Edgar Filing: TRANSALTA CORP

Filed By Filing Services Canada Inc. 403-717-3898

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, 2004

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 29, 2004.
Exhibit 2	Press release dated January 29, 2004.
Exhibit 3	Quarterly report for the three-month period ended December 31, 2003, which includes Management's Discussion and Analysis and consolidated financials statements.
Exhibit 4	Sarbanes-Oxley Act - Section 302 - certification of Stephen G. Snyder
Exhibit 5	Sarbanes-Oxley Act - Section 302 - certification of Ian Bourne
Exhibit 6	Sarbanes-Oxley Act - Section 906 - certification of Stephen G. Snyder
Exhibit 7	Sarbanes-Oxley Act - Section 906 - certification of Ian Bourne

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TransAlta announces fourth quarter results

CALGARY, Alberta (Jan. 29, 2004) - TransAlta Corporation (TSX: TA; NYSE: TAC) today announced net earnings for fourth quarter 2003 of $43.8 million ($0.23 per common share), up from a loss of $52.0 million ($0.31 per share) in fourth quarter 2002. Net earnings for the year ended Dec. 31, 2003 were $234.2 million ($1.26 per share), compared to $199.6 million ($1.17 per share) for the same period in 2002.

Earnings from continuing operations for fourth quarter 2003 of $43.8 million ($0.23 per common share), up from a loss of $62.0 million ($0.37 per share) in fourth quarter 2002. Earnings from continuing operations for the year ended Dec. 31, 2003 were $234.2 million ($1.26 per share), compared to $66.8 million ($0.39 per share) for the same period in 2002.

Fourth quarter earnings included higher revenues and related costs from new plants. Production in the fourth quarter was 13,891 gigawatt-hours (GWh), up 10 per cent (1,311 GWh) due primarily to incremental capacity at new power plants and higher availability. Fourth quarter 2002 included asset impairment charges of $0.57 per share after-tax.

Cash generated from operating activities for the quarter was $165.4 million, compared to cash from operating activities of $189.5 million in fourth quarter 2002. 2003 cash flows reflect higher earnings in the quarter offset by increased working capital requirements.

"The full year results were strong. In 2003, we strengthened the company by increasing capacity and production, improving availability and increasing cash flow," said Steve Snyder, TransAlta's president and CEO. "Expected increases in depreciation and interest as well as increased investment in plant maintenance are affecting current financial results, but position us well for the future."

Discontinued operations in 2002 include net earnings from the Transmission operation.

TransAlta consolidated financial highlights

*	In accordance with U.S. and Canadian GAAP, revenues from energy trading activities are presented on a net basis.
**	Applicable to common shareholders, net of preferred securities distributions.

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In fourth quarter 2003, TransAlta:

Renewed the $1.0 billion medium-term note facility in October.
Closed a USD$300 million senior note issue in November with the proceeds used to repay TAU debt maturing in December.
Announced new $95 million, 68-MW Summerview wind farm in southwest Alberta through Vision Quest Windelectric Inc.

TransAlta is among Canada's largest non-regulated power generation and wholesale marketing companies. We have close to $9 billion in coal-fired, gas-fired, hydro and renewable generation assets in Canada, the U.S., Mexico and Australia. With approximately 10,000 megawatts of capacity either in operation, under construction or in development, our focus is to efficiently operate our assets in order to provide our wholesale customers with a reliable, low-cost source of power.

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:

Tim Richter

Daniel J. Pigeon

Senior Media Relations Specialist

Director, Investor Relations

Phone: (403) 267-7238

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

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TransAlta declares dividend

CALGARY, Alberta (Jan. 29, 2004) - TransAlta Corporation (TSX: TA; NYSE: TAC) announced today it declared a dividend of $0.25 per share on common shares payable April 1, 2004 to shareholders of record at the close of business March 1, 2004.

All currency is expressed in Canadian dollars except where noted.

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For more information:

Media inquiries:

Investor inquiries:

Tim Richter

Daniel J. Pigeon

Senior Media Relations Specialist

Director, Investor Relations

Phone: (403) 267-7238

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

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Q4:2003

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 interim consolidated financial statements of TransAlta Corporation (TransAlta or the corporation) as at and for the three months and year ended Dec. 31, 2003 and 2002, 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, 2002. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (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

Management's Discussion and Analysis (MD&A) 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 operates; results of financing efforts; changes in counterparty risk; and the impact of accounting standards issued by Canadian and U.S. 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 segment, Transmission, was sold on April 29, 2002. TransAlta's segments are supported by a corporate group that provides finance, treasury, legal, human resources and other administrative support. These corporate group overheads are allocated to the business segments if they are not directly attributable to discontinued operations.

Each business segment assumes responsibility for its operating results measured to operating income. Operating income is not defined under GAAP and should not be considered in isolation or as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP as an indicator of the corporation's financial performance or liquidity. TransAlta's operating income is not necessarily comparable to a similarly titled measure of another company. Operating income is reconciled to net earnings applicable to common shareholders on the next page:

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		3 months ended Dec. 31				Year ended Dec. 31
		2003		2002¹		2003		2002¹
Operating income (loss)	$	128.7	$	(63.4)	$	561.6	$	212.6
Other income (expense)		(1.0)		1.0		(3.2)		0.1
Foreign exchange gain (loss)		2.0		0.9		(4.7)		1.2
Net interest expense		(51.7)		(24.0)		(183.9)		(82.7)
Earnings (loss) from continuing operations before income taxes
and non-controlling interests		78.0		(85.5)		369.8		131.2
Income tax expense (recovery)		13.9		(33.8)		78.4		23.4
Non-controlling interests		14.4		5.6		34.2		20.1
Earnings (loss) from continuing operations		49.7		(57.3)		257.2		87.7
Earnings from discontinued operations		-		-		-		12.8
Gain on disposal of discontinued operations		-		10.0		-		120.0
Net earnings (loss)		49.7		(47.3)		257.2		220.5
Preferred securities distributions, net of tax		5.9		4.7		23.0		20.9
Net earnings (loss) applicable to common shareholders	$	43.8	$	(52.0)	$	234.2	$	199.6

1	TransAlta adopted the new accounting standard for asset retirement obligations on Jan. 1, 2003. The standard was adopted retroactively with restatement of prior periods. See Note 1 to the unaudited interim consolidated financial statements for further discussion.

H I G H L I G H T S

In the fourth quarter of 2003, TransAlta achieved higher revenues and gross margins compared to the same period in 2002 as a result of increased production and plant availability. This was partially offset by interest and depreciation costs resulting from the acquisition of a 50 per cent interest in CE Generation LLC (CE Gen) and the addition of new plants. Operating income increased as a result of the items above and the effect of the asset impairment and equipment cancellation charges in 2002. Cash flow from operating activities in the fourth quarter of 2003 was lower than the fourth quarter of 2002 due to increased working capital requirements partially offset by an improvement in operations.

TransAlta made significant additions to its asset base and generating capacity in late 2002 and 2003. The corporation purchased the remainder of Vision Quest Windelectric Inc. (Vision Quest) in December 2002 and a 50 per cent interest in CE Gen in January 2003. TransAlta completed the construction of the Sarnia, Chihuahua and Campeche plants in the first three quarters of 2003. These projects added 1,367 megawatts (MW) of net operating capacity, of which approximately 75 per cent is covered through long-term contracts. Throughout 2003, TransAlta took steps to maintain the strength of its balance sheet. The sales of the Sheerness Generating Station (Sheerness), the Calgary head office building, the Goldfields pipeline and the Seebe land, as well as the issuance of common shares and long-term debt were substantially directed to repaying the debt that was incurred to expand capacity.

For the year ended 2003, the additional capacity resulted in increased production and higher gross margin compared to 2002. This was substantially offset by higher planned maintenance on existing plants and higher interest and depreciation costs from the new capacity additions. Low spark spreads (power price less cost of gas consumed) in the Pacific Northwest and Ontario prevented the Centralia Gas and Sarnia plants from selling sufficient merchant volumes to have a positive contribution to earnings, but they did generate positive operating cash flows. A $33.3 million spreadsheet error, discussed in Significant Events in this MD&A, contributed to Energy Marketing's operating loss of $15.5 million for the year ended Dec. 31, 2003. Cash flow from operations was higher than in 2002 due to higher earnings and lower working capital requirements.

In the following MD&A, the impact of foreign exchange fluctuations on foreign currency transactions and balances is discussed with the relevant income statement and balance sheet items. While individual balance sheet line items will be impacted by foreign exchange fluctuations, the net impact of the individual items is reflected in the cumulative translation account on the consolidated balance sheet.

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The following table depicts key financial results and statistical operating data:

3 months ended Dec. 31				2003				2002⁴
Availability				91.7%				90.1%
Production (GWh)				13,891				12,580
Electricity trading volumes (GWh)¹				21,810				24,663
Gas trading volumes (million GJ)¹				105.8				48.2

			Per common				Per common
		Amount		share		Amount		share
Gross margin	$	353.2			$	300.3
Earnings (loss) from continuing operations²	$	43.8	$	0.23	$	(62.0)	$	(0.37)
Gain on disposal of discontinued operations, net of tax³		-		-		10.0		0.06
Net earnings (loss) applicable to common shareholders	$	43.8	$	0.23	$	(52.0)	$	(0.31)

Cash flow from operating activities	$	165.4			$	189.5

Year ended Dec. 31				2003				2002⁴
Availability				90.6%				88.4%
Production (GWh)				53,134				47,172
Electricity trading volumes (GWh)¹				89,833				92,874
Gas trading volumes (million GJ)¹				270.2				162.0

			Per common				Per common
		Amount		share		Amount		share
Gross margin	$	1,356.1			$	1,059.3
Earnings from continuing operations²	$	234.2	$	1.26	$	66.8	$	0.39
Earnings from discontinued operations³		-		-		12.8		0.07
Gain on disposal of discontinued operations, net of tax³		-		-		120.0		0.71
Net earnings applicable to common shareholders	$	234.2	$	1.26	$	199.6	$	1.17

Cash flow from operating activities	$	756.5			$	437.7

1	2002 electricity and gas trading volumes have been restated to conform with current reporting practices and standards.
2	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.
3	Discontinued operations consist of the Transmission operation that was sold on April 29, 2002.
4	TransAlta adopted the new standard for asset retirement obligations on Jan. 1, 2003. The standard was adopted retroactively with restatement of prior periods. See Note 1 to the unaudited interim consolidated financial statements for further discussion.

Availability for the fourth quarter of 2003 was higher than the fourth quarter of 2002 due to lower unplanned outages and a higher proportion of gas-fired plant capacity. Availability increased for the year ended Dec. 31, 2003 compared to the same period in 2002 as a result of significantly fewer planned outages at the Centralia plant and the mix of coal- and gas-fired plants, partially offset by higher planned maintenance in Alberta.

Production increased in the three months ended Dec. 31, 2003 due to capacity additions from the acquisitions of a 50 per cent interest in CE Gen and the remainder of Vision Quest, as well as the commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants during 2003. Production increased in the year ended Dec. 31, 2003 for the reasons discussed above and higher production from the Centralia and Poplar Creek plants. The increase was partially offset by the decommis-sioning of unit three of the Wabamun plant in November 2002.

Gross margins increased in the three months ended Dec. 31, 2003 compared to the same period in 2002 as a result of increased production and availability. Gross margins increased for the year ended Dec. 31, 2003 due to the reasons discussed above and the $38.9 million Wabamun arbitration decision which was recorded as a reduction to revenues in 2002.

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In the three months and year ending Dec. 31, 2003, operating income increased by $192.1 million and $349.0 million, respectively, compared to the same periods in 2002.

	3 months ended		Year ended
Operating income (loss) Dec. 31, 2002	$	(63.4)	$	212.6
Higher Generation gross margins		59.4		295.6
Wabamun arbitration decision		-		38.9
Lower Energy Marketing gross margins		(6.5)		(37.7)
Increased operations, maintenance and administration		(3.0)		(133.3)
Increased depreciation		(24.5)		(101.4)
Gain on sale of Sheerness		-		191.5
Gain on sale of TransAlta Power partnership units		15.2		15.2
Wabamun impairment		110.0		110.0
Equipment cancellation charge		42.5		42.5
Turbine impairment		-		(84.7)
Other		(1.0)		12.4
Operating income Dec. 31, 2003	$	128.7	$	561.6

Earnings from continuing operations, net of preferred share distributions, for the three months ended Dec. 31, 2003 were $43.8 million ($0.23 per common share) compared to a loss of $62.0 million ($0.37 per common share) in the same period in 2002. For the fourth quarter of 2003, earnings from continuing operations, net of preferred share distributions, includes the $9.9 million after-tax dilution gain on the sale of TransAlta Power partnership units, the $3.6 million after-tax Binghamton impairment and the $4.1 million after-tax write down of long-term investments. Earnings from continuing operations, net of preferred share distributions, for the fourth quarter of 2002 include the $27.6 million after-tax turbine order cancellation charge and the $71.5 million after-tax Wabamun impairment charge.

Earnings from continuing operations, net of preferred share distributions, for the year ended Dec. 31, 2003 were $234.2 million ($1.26 per common share), compared to $66.8 million ($0.39 per common share) for the same period in 2002. In the year ended Dec. 31, 2003, earnings from continuing operations, net of preferred share distributions, includes the items discussed above, the $145.8 million after-tax gain on the sale of Sheerness and the $55.4 million after-tax turbine impairment charge. Earnings from continuing operations, net of preferred share distributions, for the year ended Dec. 31, 2002 include the items discussed above, the $11.2 million after-tax gain from refinancing of foreign operations and the $25.2 million after-tax charge for the Wabamun arbitration decision.

Net earnings applicable to common shareholders for the three months and year ended Dec. 31, 2002 included the $10.0 million and $120.0 million, respectively, after-tax gain on sale of the Transmission operation. In the fourth quarter of 2002, the gain was adjusted to reflect agreed working capital adjustments and actual amounts paid and received.

Cash flow from operating activities for the three months ended Dec. 31, 2003 was $165.4 million compared to $189.5 million in the fourth quarter of 2002. 2003 cash flows reflect higher earnings in the quarter offset by increased working capital requirements. For the year ended Dec. 31, 2003, cash flow from operating activities was $756.5 million compared to $437.7 million for 2002. The increase is primarily due to higher earnings and the collection of commodity tax receivables in the U.S. and Mexico (US$79.0 million) in the second quarter of 2003, the settlement of a disputed ancillary services revenue issue with the Balancing Pool of Alberta ($49.9 million), the timing of cash tax obligations ($55.6 million) in the third quarter of 2002, and the final instalment of 2001 income taxes paid in the first quarter of 2002 ($109.0 million).

The corporation's financial reporting procedures and practices have enabled the certification of TransAlta's fourth quarter report to shareholders in voluntary compliance with the requirements of Section 302 of the Sarbanes-Oxley Act.

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S I G N I F I C A N T E V E N T S

All gains and losses discussed below are presented as pre-tax (after-tax) amounts.

3 months ended Dec. 31, 2003 and 2002

Impairment charge

The corporation performed an annual review of its property, plant and equipment. As a result of this review, TransAlta recorded a $5.6 million ($3.6 million) impairment charge on the Binghamton plant in the fourth quarter of 2003. The Binghamton plant is a peaker plant that sells electricity to the New York area at spot market rates when such prices exceed its marginal operating costs. Due to generation overcapacity in the Northeastern U.S. and transmission constraints, TransAlta does not expect the plant to operate on a regular basis or at prices that would justify its current book value. The impairment charge reduces the Binghamton plant's book value to fair value.

Investment write down

On an annual basis, TransAlta reviews the valuation of its long-term equity investments. As a result of this review, in the fourth quarter of 2003, the corporation recorded a $6.2 million ($4.1 million) charge to recognize an other than temporary decline in fair value. The charge is included in corporate operations, maintenance and administration (OM&A) expenses.

Sale of Seebe land

On Dec. 31, 2003, TransAlta sold 539 acres of undeveloped land at Seebe, Alberta for $11.0 million. The corporation recognized a gain on sale of $10.5 million ($8.6 million).

Purchase of Vision Quest

In the fourth quarter of 2002, TransAlta purchased the remaining interest in Vision Quest. The transaction increased the corporation's total investment in the wind power company to $68.8 million. Vision Quest operates 124 wind turbines with 119 MW of gross generating capacity in operation (82 MW net ownership interest). Vision Quest's financial results are included in Generation's results for segmented reporting purposes.

Decommissioning of Wabamun plant

In the fourth quarter of 2002, TransAlta decided to implement a phased decommissioning of the Wabamun facility by removing the 139-MW unit three from service. As a result of this decision to decommission unit three and the upcoming retirements of units one and two, the corporation recognized an impairment charge of $110.0 million ($71.5 million) in the fourth quarter of 2002. The corporation plans to retire units one and two (62 MW and 57 MW, respectively) in 2004 and unit four (279 MW) in 2010 when its operating license expires. The power purchase arrangement (PPA) for the plant expired on Dec. 31, 2003 and 2004 production will be sold on the spot market.

Turbine order cancellation

In the fourth quarter of 2002, the corporation cancelled orders for four turbines and recorded a cancellation charge of $42.5 million ($27.6 million) for contract termination costs. The costs consisted solely of progress payments made to date.

Events occurring in the nine months ended Sept. 30, 2003 and 2002

Sale of Sheerness

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and 17.75 million partnership units to TransAlta for gross proceeds of $165.1 million. As a result of the unit issuance, TransAlta's ownership interest in TransAlta Power on July 31, 2003 was approximately 26 per cent. The warrants, when exercised, are exchangeable for one TransAlta Power unit at any time until Aug. 3, 2004. As the warrants are exercised, TransAlta will sell TransAlta Power units back to TransAlta Power for $9.30 per unit, reducing its ownership interest in TransAlta Power to its original 0.01 per cent and increasing cash proceeds by a further $165.1 million assuming all the warrants are exercised. As a result of the exercising of warrants and the subsequent sale of TransAlta Power units back to TransAlta Power, TransAlta's ownership interest in TransAlta Power was approximately 19 per cent at Dec. 31, 2003.

In connection with the sale, the obligation for TransAlta to purchase all of TransAlta Power's interest in TA Cogen on Dec. 31, 2018 that arose on the sale of power generation assets to TA Cogen in 1998 has been eliminated; therefore, the deferred gain of approximately $119 million ($99 million) related to this sale was recognized in earnings in 2003. In addition, the management agreements between TransAlta, TransAlta Power and TA Cogen were amended to remove the mechanism for the deferral of management fees and remove the obligation for TransAlta Power and TA Cogen to pay management fees to TransAlta in the future. As consideration for the amendments, TransAlta received $1.0 million from TransAlta Power and $5.0 million from TA Cogen.

As a result of the sale, in the third quarter of 2003, TransAlta realized a gain on sale of $191.5 million ($145.8 million), which includes the realization of the 1998 deferred gain (approximately $119 million). In the fourth quarter, TransAlta recognized $15.2 million ($9.9 million) of gains on the sale of TransAlta Power units. TransAlta expects to recognize approximately $53 million ($34 million) of further gains on the assumption that the warrants are fully exercised and TransAlta's effective interest in TransAlta Power is reduced to its original 0.01 per cent.

Proceeds from the sale of Sheerness were used to repay debt.

Asset impairment charges

Following a strategic review and after examining expected unfavourable market conditions, the corporation concluded that the book value of its turbine inventory was unlikely to be fully recovered. As a result, TransAlta recorded an $84.7 million impairment charge ($55.4 million) in the third quarter of 2003 to write down the turbines to fair value.

Energy Marketing loss on transmission congestion contracts

TransAlta submitted an erroneous bid to the New York Independent System Operator (New York ISO) for May 2003 transmission congestion contracts (TCCs). The New York ISO manages New York's electricity transmission system and TCCs are financial contracts. TransAlta's computer spreadsheet contained mismatched bids for TCCs due to a clerical error and resulted in TransAlta purchasing more contracts at higher prices than intended. The erroneous bid resulted in a loss of $33.3 million ($20.0 million) in May 2003.

Sale of head office building

On May 9, 2003, TransAlta sold the Calgary head office building for $65.8 million, which approximated book value. TransAlta is leasing the property back for a term of 20 years.

Sale of Goldfields gas pipeline

On April 30, 2003, TransAlta sold its 8.82 per cent interest in the Goldfields gas pipeline for proceeds of AUD$24.1 million (Cdn$21.6 million) which approximated book value.

Equity offering

In March and April of 2003, the corporation issued a total of 17.25 million common shares for gross proceeds of $276.0 million. Proceeds were used to repay debt.

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Acquisitions

In the first quarter of 2003, the corporation purchased a 50 per cent interest in CE Gen. Note 2 of the unaudited interim consolidated financial statements discloses details of the transaction. TransAlta's share of CE Gen's results for the period of ownership from Jan. 29, 2003 to Dec. 31, 2003 is included in the Generation segment.

In the first quarter of 2003, TransAlta acquired a 50 per cent interest in EPCOR Utilities Inc.'s (EPCOR) Genesee 3 project for an estimated $395 million of which $281.8 million has been incurred at Dec. 31, 2003. The 450 MW addition to the existing Genesee Generating Station is currently under construction southwest of Edmonton, Alberta.

Refinancing of foreign operations

During the third quarter of 2002, TransAlta restructured the financing of certain of its foreign operations. As a result, the corporation 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.

Ancillary services revenue settlement

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

Wabamun arbitration decision

In May 2002, the corporation received the arbitrators' decision with respect to the Wabamun outage. As a result of the decision, the corporation was required to pay $38.9 million ($25.2 million), which was recorded as a reduction of revenue.

Gain on disposal of discontinued operations

In April 2002, TransAlta's Transmission operation was sold for proceeds of $820.7 million. The disposal resulted in an after-tax gain on sale of $110.0 million ($0.65 per common share). The gain of $110.0 million included a number of estimates. In the fourth quarter of 2002, the gain was adjusted to $120.0 million ($0.71 per common share) to reflect agreed working capital adjustments and actual amounts paid and received.

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

TransAlta has determined that real-time physical trading, an activity within the Energy Marketing segment that is done on behalf of TransAlta owned assets, meets the definition of a non-derivative contract held for delivery and therefore is reported gross in compliance with Emerging Issues Task Force (EITF) 03-11. Prior periods have been restated.

Effective Jan. 1, 2003, TransAlta early adopted the new Canadian Institute of Chartered Accountants standard for accounting for asset retirement obligations. The effect of this change in accounting policy was recorded retroactively with restatement of prior periods. The impact of the adoption of the new standard is disclosed in Note 1 to the unaudited interim consolidated financial statements.

Effective Jan. 1, 2003, TransAlta 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. No stock options were granted in 2003.

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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, wind, geothermal, gas- and coal-fired plants and related mining operations in Canada, the U.S., Mexico and Australia. At Dec. 31, 2003, Generation had 8,846 MW of gross generating capacity in operation (8,322 MW net ownership interest) and 293 MW under construction.

TransAlta added 1,367 MW of net generating capacity in 2003. In January 2003, TransAlta acquired a 50 per cent interest in CE Gen. TransAlta's net ownership in CE Gen's 13 geothermal and gas-fired plants is 378 MW. The Sarnia plant was commissioned in March 2003, adding 440 MW of generating capacity to the existing 135 MW that was acquired in 2002. In May 2003, TransAlta commissioned the 252-MW Campeche plant. The McBride Lake wind generation project was completed in June 2003, resulting in 75 MW of capacity of which TransAlta has a 50 per cent interest through its ownership of Vision Quest. In September 2003, the 259-MW Chihuahua plant was commissioned. On Dec. 16, 2003, TransAlta announced the new 68-MW Summerview Wind Farm project scheduled for completion in the third quarter of 2004.

For the three months ended Dec. 31, 2003, availability was 91.7 per cent compared to 90.1 per cent in the same period in 2002 due to the addition of the new plants and higher availability at the Alberta thermal plants as a result of lower unplanned outages. For the year ended Dec. 31, 2003 availability was 90.6 per cent compared to 88.4 per cent in 2002. The increase is due to higher availability at the Centralia and Poplar Creek plants and the addition of the new plants.

The results of the Generation segment are as follows:

				2003				2002¹
3 months ended Dec. 31		Total		Per MWh		Total		Per MWh
Revenues	$	624.9	$	44.99	$	499.7	$	39.72
Fuel and purchased power		(283.1)		(20.38)		(217.3)		(17.27)
Gross margin		341.8		24.61		282.4		22.45
Operating expenses:
Operations, maintenance and administration		118.7		8.55		115.7		9.20
Depreciation and amortization		87.8		6.32		63.4		5.04
Taxes, other than income taxes		5.6		0.41		7.6		0.60
Gain on sale of TransAlta Power partnership units		(15.2)		(1.09)		-		-
Gain on sale of Seebe land		(10.5)		(0.76)		-		-
Asset impairment charges		5.6		0.40		152.5		12.12
Operating income (loss) before corporate allocations		149.8		10.78		(56.8)		(4.51)
Corporate allocations		(23.1)		(1.66)		(18.1)		(1.44)
Operating income (loss)	$	126.7	$	9.12	$	(74.9)	$	(5.95)

1	TransAlta adopted the new accounting standard for asset retirement obligations on Jan.1, 2003. The standard was adopted retroactively with restatement of prior periods. See Note 1 to the unaudited interim consolidated financial statements for further discussion.

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				2003				2002¹
Year ended Dec. 31		Total		Per MWh		Total		Per MWh
Revenues	$	2,412.2	$	45.40	$	1,674.9	$	35.51
Fuel and purchased power		(1,067.4)		(20.09)		(664.6)		(14.09)
Gross margin		1,344.8		25.31		1,010.3		21.42
Operating expenses:
Operations, maintenance and administration		480.0		9.03		346.7		7.35
Depreciation and amortization		321.6		6.05		220.3		4.67
Taxes, other than income taxes		23.1		0.44		27.3		0.58
Gain on sale of Sheerness Generating Station		(191.5)		(3.60)		-		-
Gain on sale of TransAlta Power partnership units		(15.2)		(0.29)		-		-
Gain on sale of Seebe land		(10.5)		(0.20)		-		-
Asset impairment charges		90.3		1.70		152.5		3.23
Prior period regulatory decision		-		-		3.3		0.07
Operating income before corporate allocations		647.0		12.18		260.2		5.52
Corporate allocations		(69.9)		(1.32)		(70.6)		(1.50)
Operating income	$	577.1	$	10.86	$	189.6	$	4.02

1	TransAlta adopted the new accounting standard for asset retirement obligations on Jan.1, 2003. The standard was adopted retroactively with restatement of prior periods. See Note 1 to the unaudited interim consolidated financial statements for further discussion.

Generation's revenues are derived from the production of electricity and steam as well as ancillary services such as system support. Revenues are subject to seasonal variations. TransAlta's electricity and steam production revenues are generated from the following revenue streams:

Alberta PPAs are long-term arrangements that apply to all of TransAlta's Alberta coal-fired and hydroelectric facilities (previously regulated) whereby a single customer has the rights to the entire production of a plant or unit. PPAs establish committed capacity and electrical energy generation requirements and availability targets to be achieved by each coal-fired plant, energy and ancillary services obligations for the hydroelectric plants, and the pricing formula at which capacity and power is supplied. The corporation bears the risk or retains the benefit of volume variances (except for those arising from events considered to be force majeure, in the case of the coal-fired plants), and any change in costs required to maintain and operate the facilities. The corporation's hydroelectric facilities are not contracted on a facility-by-facility basis, rather facilities are aggregated in a single Alberta PPA which provides for energy and ancillary services obligations based on hourly targets. TransAlta meets these targeted amounts through physical delivery or third party purchases.

Long-term contracts are similar to PPAs. TransAlta defines a long-term contract as being between 10 and 25 years. Long-term contracts are typically for gas-fueled plants with one to four customers per plant. Revenues are derived from payments for capacity and the production of electrical energy and steam. Long-term contracts may or may not involve the purchasing of natural gas as the fuel source.

Merchant revenue is derived from the sale of production only, with multiple customers per plant. Production is sold through medium-term contract sales (typically three to seven years), short-term asset-backed trading and spot or short-term (less than one year) forward markets.

CE Gen earns revenues from 10 geothermal plants (163 MW) and three gas-fired facilities (215 MW). Eight of the geothermal plants sell their output under long-term contracts expiring between 2016 and 2035. One facility is partially contracted while the remaining facility sells its output on the spot market but has an option to sell output under a 35-year contract based on market prices. The three gas-fired facilities sell their output under fixed-price contracts ranging from two to 30 years in length, with expiration dates of 2005, 2009 and 2024. All three facilities have gas supply arrangements in place for the duration of the electricity sales contracts.

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										Fuel &
				Fuel &						Purchased			Gross
3 months ended	Production			Purchased			Gross		Revenue	Power			Margin
Dec. 31, 2003	(GWh)		Revenue	Power			Margin		per MWh		per MWh		per MWh
Alberta PPAs	7,107	$	180.4	$	49.4	$	131.0	$	25.38	$	6.95	$	18.43
Long-term contracts	2,670		203.3		122.1		81.2		76.14		45.73		30.41
Merchant	3,512		177.1		96.1		81.0		50.43		27.36		23.06
CE Gen	602		64.1		15.5		48.6		106.48		25.75		80.73
TOTAL	13,891	$	624.9	$	283.1	$	341.8	$	44.99	$	20.38	$	24.61

											Fuel &
					Fuel &						Purchased		Gross
3 months ended	Production			Purchased			Gross		Revenue		Power		Margin
Dec. 31, 2002	(GWh)		Revenue		Power		Margin		per MWh		per MWh		per MWh
Alberta PPAs	7,040	$	175.3	$	42.7	$	132.6	$	24.90	$	6.07	$	18.84
Long-term contracts	1,816		125.4		70.4		55.0		69.05		38.77		30.29
Merchant	3,724		199.0		104.2		94.8		53.44		27.98		25.46
TOTAL	12,580	$	499.7	$	217.3	$	282.4	$	39.72	$	17.27	$	22.45

											Fuel &
					Fuel &					Purchased			Gross
Year ended	Production			Purchased			Gross		Revenue		Power		Margin
Dec. 31, 2003	(GWh)		Revenue		Power		Margin		per MWh		per MWh		per MWh
Alberta PPAs	28,295	$	746.7	$	191.7	$	555.0	$	26.39	$	6.78	$	19.61
Long-term contracts	8,538		666.3		408.3		258.0		78.04		47.82		30.22
Merchant	13,683		690.2		387.0		303.2		50.44		28.28		22.16
CE Gen	2,618		309.0		80.4		228.6		118.03		30.71		87.32
TOTAL	53,134	$	2,412.2	$	1,067.4	$	1,344.8	$	45.40	$	20.09	$	25.31

											Fuel &
					Fuel &						Purchased		Gross
Year ended	Production			Purchased			Gross		Revenue		Power		Margin
Dec. 31, 2002	(GWh)		Revenue		Power		Margin		per MWh		per MWh		per MWh
Alberta PPAs	29,792	$	761.6	$	175.4	$	586.2	$	25.56	$	5.89	$	19.68
Long-term contracts	6,157		364.8		165.9		198.9		59.25		26.94		32.30
Merchant ¹	11,223		587.4		323.3		264.1		49.14		27.05		22.09
Wabamun arbitration
decision	-		(38.9)		-		(38.9)		-		-		-
TOTAL	47,172	$	1,674.9	$	664.6	$	1,010.3	$	35.51	$	14.09	$	21.42

1 Revenue per MWh and fuel and purchased power per MWh includes actual production volumes and economic dispatch volumes purchased (731 GWh).

Alberta PPAs

In the fourth quarter of 2003, production was consistent with the same period in 2002 as reduced unplanned outages in 2003 offset the decommissioning of unit three of the Wabamun plant in 2002. Planned outages in the fourth quarter of 2003 were consistent with the fourth quarter of 2002. For the year ended Dec. 31, 2003, production decreased by 1,497 gigawatt hours (GWh) due to the decommissioning of unit three of the Wabamun plant in November 2002.

For the three months and year ended Dec. 31, 2003, revenues increased by $0.48 per megawatt hour (MWh) and $0.83 per MWh, respectively, compared to the same periods in 2002 due to incentives earned from exceeding the availability targets in the PPAs. Fuel and purchased power for the three months and year ended Dec. 31, 2003 increased by $0.88 per MWh and $0.89 per MWh respectively, compared to the same periods in 2002 due to increased energy prices and higher planned maintenance costs at the coal mines in 2003. Substantially all of the coal used for production under Alberta PPAs is from coal reserves owned by TransAlta.

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Long-term contracts

Production increased by 854 GWh for the fourth quarter of 2003 and by 2,381 GWh for the year ended Dec. 31, 2003 compared to the same periods in 2002. The increase is primarily the result of incremental production from the Sarnia plant, Vision Quest and the commencement of commercial operations at the Campeche and Chihuahua plants.

Revenues increased by $7.09 per MWh and $18.79 per MWh in the three months and year ended Dec. 31, 2003, respectively, over the same periods in 2002. The increase is due in part to $26.9 million ($10.07 per MWh) and $102.9 million ($12.05 per MWh) of incremental steam revenues earned from the Sarnia plant in the three months and year ended Dec. 31, 2003, respectively. Revenues also increased as a result of higher natural gas prices. At certain plants, natural gas prices flow through to customers and are therefore recovered through revenues. Fuel and purchased power increased by $6.96 per MWh and $20.88 per MWh in the three months and year ended Dec. 31, 2003 primarily due to higher heat rates at Sarnia, higher natural gas market prices and the cost of the gas used for steam production.

Gross margins increased by $0.12 per MWh in the three months ended Dec. 31, 2003 compared to the same period in 2002 due to the higher steam revenues at the Sarnia plant, partially offset by higher natural gas prices and the commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants, which have lower gross margins than existing contracted plants. Gross margins decreased by $2.08 per MWh for the year ended Dec. 31, 2003 due to higher natural gas prices and the commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants.

Merchant production

1 For a 7,000 Btu/KWh heat rate plant.

As shown in the above graphs, electricity spot prices in Alberta and Ontario were lower in the fourth quarter of 2003 compared to the same period in 2002. Warm weather and excess capacity contributed to the decrease. In the Pacific Northwest, electricity spot prices were higher than in the fourth quarter of 2002 due to increased natural gas prices. On an annual basis, 2003 electricity spot prices increased in all three areas over 2002 prices. The Ontario market was regulated until May 2002, and remains partially regulated. Spark spreads in all three areas decreased in the fourth quarter of 2003 compared to the same period in 2002, due to a combination of lower electricity prices and higher natural gas prices. Electricity prices generally increase as a result of increased natural gas prices; however, they may not be completely correlated due to the existence of generation overcapac-ity in a specific market or other generation fuel sources in that market such as hydro or nuclear power. For the year ended Dec. 31, 2003, spark spreads increased in both Alberta and the Pacific Northwest markets, but decreased in Ontario.

In the fourth quarter of 2003, merchant production was 3,512 GWh, of which 2,556 GWh was contracted under short- to medium-term contracts. In the fourth quarter of 2002, merchant production was 3,724 GWh, of which 2,681 GWh was contracted. The decreased production was due to unplanned outages at the Centralia plant in November 2003. For the year ended Dec. 31, 2003, merchant production was 13,683 GWh, of which 8,997 GWh was contracted. In 2002, merchant production was 11,223 GWh, of which 8,020 GWh was contracted. At certain times during the second and third quarters of 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). The increase in production in

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2003 reflects increased production from the Sarnia, Centralia and Centralia Gas plants as well as the 731 GWh of economic dispatch that occurred in 2002.

For the three months ended Dec. 31, 2003, merchant revenues decreased by $3.01 per MWh compared to the fourth quarter of 2002. The decrease was due to the strengthening of the Canadian dollar compared to the U.S. dollar and lower production at the hydro facilities. For the year ended Dec. 31, 2003, merchant revenues increased by $1.30 per MWh compared to the same period in 2002 as a result of higher electricity spot prices. For the three months ended Dec. 31, 2003, fuel and purchased power decreased by $0.62 per MWh due to the strengthening of the Canadian dollar compared to the U.S. dollar. For the year ended Dec. 31, 2003, fuel and purchased power increased by $1.23 per MWh as a result of increased natural gas prices.

For the three months ended Dec. 31, 2003, gross margins decreased by $2.40 per MWh compared to the fourth quarter of 2002 as a result of increased natural gas costs and the strengthening of the Canadian dollar compared to the U.S. dollar. For the year ended Dec. 31, 2003, gross margins increased by $0.07 per MWh due to increased power prices substantially offset by increased natural gas costs and the strengthening of the Canadian dollar compared to the U.S. dollar.

CE Gen

In the fourth quarter of 2003, CE Gen produced 602 GWh of electricity. Revenue was $106.48 per MWh and fuel and purchased power was $25.75 per MWh. From Jan. 29, 2003 to Dec. 31, 2003, production was 2,618 GWh, revenue was $118.03 per MWh and fuel and purchased power was $30.71 per MWh.

Operations, maintenance and administration expense

In the fourth quarter of 2003, OM&A expenses decreased by $0.65 per MWh over the same period in 2002. Excluding the impact of the CE Gen acquisition, OM&A costs decreased by $9.8 million ($1.20 per MWh) due to decreased planned and unplanned maintenance spending at the Alberta thermal plants. In the quarter, planned outage days at Alberta thermal were similar to the prior year, however the maintenance performed in 2003 was of a different type.

For the year ended Dec. 31, 2003, OM&A increased by $133.3 million ($1.68 per MWh) compared to 2002. The increase is due to the CE Gen acquisition, commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants and increased planned maintenance at the Alberta thermal plants.

The table below shows the amount of planned maintenance capitalized and expensed in the three months and year ended Dec. 31, 2003 and 2002, excluding CE Gen.

	3 months ended Dec. 31		Year ended Dec. 31
Planned maintenance expenditures	2003	2002	2003	2002
Capitalized	4.4	9.9	35.2	102.1
Expensed	12.4	19.3	77.3	46.2
	16.8	29.2	112.5	148.3

In the three months and year ended Dec. 31, 2003, planned maintenance was focused on repairing the assets rather than more capital intensive repairs which would result in the plants not being available for a longer period of time. In the fourth quarter of 2002, the increased planned maintenance was due to TransAlta accelerating the Alberta thermal maintenance schedule.

OM&A costs for CE Gen were $12.8 million ($21.26 per MWh) in the fourth quarter of 2003 and $65.3 million ($24.94 per MWh) for the year ended Dec. 31, 2003. The relatively high costs per MWh at the geothermal generation facilities result from the requirement to process and refine the geothermal resources before they can be used for the generation of electricity.

Depreciation and amortization

Depreciation and amortization increased by $24.4 million ($1.28 per MWh) in the fourth quarter of 2003 compared to the same period in 2002 of which $24.1 million is the result of the CE Gen acquisition. The remaining increase is due to incremental depreciation from the commissioning of the Sarnia, Campeche and Chihuahua plants substantially offset by the decommissioning

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of Wabamun unit three and the strengthening of the Canadian dollar compared to the U.S. dollar. Depreciation and amortization increased by $101.3 million ($1.38 per MWh) for the year ended Dec. 31, 2003 compared to 2002 of which $83.8 million is the result of the CE Gen acquisition. The remaining increase is due to the reasons discussed above.

Taxes other than income taxes

For the three months and year ended Dec. 31, 2003, taxes other than income taxes were consistent with the same periods in 2002.

ENERGY MARKETING: Derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives not supported by TransAlta owned generation assets. Energy Marketing also utilizes contracts of various durations for the forward sales of electricity and purchases of natural gas and transmission capacity to effectively manage available generating capacity and fuel and transmission needs on behalf of Generation. These results are included in the Generation segment.

TransAlta is exposed to market fluctuations in energy commodity prices related to its generation activities. The corporation closely monitors the risks associated with these commodity price changes on its future operations and where appropriate uses various physical and financial instruments to hedge the value of its assets and operations from such price risk. These contracts are designated as effective hedge positions of future cash flows or fair values of the output and production of its owned assets. Under Canadian GAAP, settlement accounting is used for hedging. Under U.S. GAAP, hedging activities are accounted for in accordance with the Financial Accounting Standards Board (FASB) Statement 133.

Energy Marketing also uses commodity derivatives to manage risk, earn trading revenue and gain market information. The portfolio consists of physical and financial derivative instruments including, forwards, swaps, futures, and options in various commodities. These contracts meet the definition of trading activities and have been accounted for using fair values for both Canadian and U.S. GAAP. Changes in the fair values of the portfolio are recognized in income in the period they occur.

The EITF has reached a consensus on EITF 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes." EITF 03-11 gives guidance on whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. TransAlta has concluded that real-time physical trading meets the definition of non-derivative contracts held for delivery and therefore is reported gross in compliance with EITF 03-11.

TransAlta's price risk management assets and liabilities represent the value of unsettled (unrealized) proprietary trading transactions accounted for on a fair value, mark-to-market basis. With the exception of transmission contracts, the fair value of all energy trading activities is based on quoted market prices. The fair value of financial transmission contracts is based upon statistical analysis of historical data. All transmission contracts are accounted for in accordance with EITF 02-03. The following charts show the balance sheet classifications for price risk management assets and liabilities as well as the changes in the fair value of the net assets for the period.

Balance Sheet	Dec. 31, 2003		Dec. 31, 2002
Price risk management assets
Current	$	77.1	$	157.8
Long-term		71.9		60.7
Price risk management liabilities
Current		(71.2)		(173.8)
Long-term		(65.1)		(50.6)
Net price risk management assets (liabilities) outstanding	$	12.7	$	(5.9)

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Change in fair value of net assets (liabilities)	Fair value			Accrual		Total

Net price risk management assets (liabilities) outstanding at Dec. 31, 2002	$	(7.5)	$	1.6	$	(5.9)
New contracts entered into during the period		13.1		-		13.1
Changes in values attributable to market price and other market changes		0.7		-		0.7
Contracts realized, amortized or settled during the period		6.4		(1.6)		4.8
Changes in values attributable to changes in valuation techniques and assumptions		-		-		-
Net price risk management assets outstanding at Dec. 31, 2003	$	12.7	$	-	$	12.7

The net price risk management assets and liabilities increased by $18.6 million compared to Dec. 31, 2002 due to a decrease in liabilities as a result of the decision to exit from the New York TCC market as well as higher gas prices compared to 2002.

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

												2009 and
		2004		2005		2006		2007		2008		thereafter		Total
Prices actively quoted	$	4.0	$	3.1	$	2.1	$	1.5	$	-	$	-	$	10.7
Prices based on models		2.0		-		-		-		-		-		2.0
	$	6.0	$	3.1	$	2.1	$	1.5	$	-	$	-	$	12.7

In accordance with EITF 02-03, physical transmission is now accounted for under accrual accounting. At Dec. 31, 2003 TransAlta recorded $1.5 million on the balance sheet as prepaid transmission related to these contracts. Physical transmission is widely used in the California and Ontario markets. The maximum term of these contracts is 12 months.

Energy Marketing's fixed trading positions at Dec. 31, 2003 were as follows:

		Fixed price payor	Fixed price receiver	Maximum term
	Units (000s)	notional amounts	notional amounts	in months
Electricity	MWh	13,872.6	4,106.8	33
Natural gas	GJ	37,805.3	56,308.8	24

The corporation's electrical transmission contracts trading position was 7.4 million MWh at Dec. 31, 2003 compared to 18.1 million MWh at Dec. 31, 2002. This decrease in trading position relates to TransAlta's systematic withdrawal from the New York TCC market and increased focus on asset backed trading.

Gross physical and financial settled sales of proprietary trading transactions are as follows:

	3 months ended Dec. 31		Year ended Dec. 31
Electricity (GWh)	2003	2002	2003	2002
Physical	13,514	15,288	55,506	61,089
Financial	8,296	9,375	34,327	31,785
	21,810	24,663	89,833	92,874

	3 months ended Dec. 31		Year ended Dec. 31
Gas (million GJ)	2003	2002	2003	2002
Physical	25.1	27.4	100.1	101.5
Financial	80.7	20.8	170.1	60.5
	105.8	48.2	270.2	162.0

Electricity volumes in the three months and year ended Dec. 31, 2003 were lower than the same periods in 2002 due to the consolidation of the Annapolis trading office. Power trading strategies consist of shorter term physical and financial trades in regions where TransAlta has assets and the markets that interconnect with those regions. The increase in gas volumes relates to the increased use of heat rate contracts, which involve a gas component, to manage power price risk. Gas trading, independent of power trading strategies, continues to be a small part of the risk taken in the marketplace. TransAlta's trading activities are mainly short-term transactions, thereby limiting credit risk and maintaining low working capital requirements.

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Based on the above volumes, contracts and changes in market prices, the results of Energy Marketing are as follows:

		3 months ended Dec. 31				Year ended Dec. 31
		2003		2002		2003		2002
Revenues	$	30.5	$	32.0	$	96.4	$	140.0
Trading purchases		(19.1)		(14.1)		(85.1)		(91.0)
Gross margin		11.4		17.9		11.3		49.0
Operations, maintenance and administration		5.8		3.6		14.9		15.1
Depreciation and amortization		0.7		0.5		3.1		2.5
Taxes other than income taxes		-		-		-		0.1
Operating income (loss) before corporate allocations		4.9		13.8		(6.7)		31.3
Corporate allocations		(2.9)		(2.3)		(8.8)		(8.3)
Operating income (loss)	$	2.0	$	11.5	$	(15.5)	$	23.0

Gross margins decreased by $6.5 million for the fourth quarter of 2003 and $37.7 million for the year ended Dec. 31, 2003 compared to the same periods in 2002. During the third quarter of 2003, Energy Marketing re-evaluated trading strategies and consolidated the Annapolis trading office in Calgary. The closure of the Annapolis office and changing market opportunities in Alberta resulted in fewer volumes being traded and settled in the fourth quarter of 2003 as compared to 2002. For the year ended Dec. 31, 2003 the decrease in revenues is mainly due to a $33.3 million clerical error made on TCCs that occurred in the second quarter of 2003.

OM&A costs for the fourth quarter of 2003 include $1.1 million of amounts expensed relating to the closure of the Annapolis office. OM&A for the year ended Dec. 31, 2003 was consistent with the prior year.

Depreciation and amortization for the three months and year ended Dec. 31, 2003 was consistent with the same periods in 2002.

TransAlta has a US$53.0 million receivable relating to energy sales in California between Jan. 1, 2000 and June 20, 2001. On Dec. 12, 2002, a U.S. Federal Energy Regulatory Commission (FERC) Administrative Law Judge issued proposed findings of fact that recommended TransAlta refund US$9.2 million for electricity sales made to the California Independent System Operator, which would reduce the receivable to US$43.8 million. In March 2003, FERC proposed further adjustments in respect of power and gas prices, which could result in further adjustments to the amount to be received by TransAlta. As a result, TransAlta has a provision of US$28.8 million to account for potential refund liabilities and will maintain this provision until a final ruling is made by FERC with respect to these issues.

In March 2003, FERC completed its investigation of natural gas and power markets and indicated that the total industry refunds for price overcharges will be higher than originally anticipated.

In June 2003, FERC issued two show cause orders, the Partnership Gaming Order and the Gaming Practices Order, in which TransAlta's U.S. subsidiaries were named. These orders required TransAlta to justify certain trading activities in California between Jan. 1, 2000 and June 20, 2001. In response to FERC's show cause orders, TransAlta confirmed that it did not engage in gaming behavior. Based on the information provided by TransAlta, FERC Trial Staff filed a Motion to Dismiss with respect to TransAlta in the two show cause proceedings. On Jan. 22, 2004, FERC granted the Trial Staff's motion to dismiss TransAlta from both the Partnership Gaming Order and the Gaming Practices Order. FERC found that TransAlta did not engage in prohibited gaming practices.

As the result of another June 2003 FERC order, the FERC Office of Market Oversight and Investigations instituted an investigation into bidding behaviour in the California markets between May 1, 2000 and Oct. 2, 2000 and made information requests of TransAlta's U.S. energy marketing subsidiaries. TransAlta filed its response to this investigation on July 24, 2003. TransAlta's investigations revealed no significant bidding behaviours outlined in the FERC request for information. Based on TransAlta's responses, it is unlikely that TransAlta will be required to make any refunds or payments pursuant to these orders.

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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
		2003		2002		2003		2002
Gross interest expense	$	58.2	$	46.7	$	234.1	$	172.9
Interest income		(1.9)		(1.7)		(5.0)		(8.7)
Interest allocated to discontinued operations		-		-		-		(2.4)
Capitalized interest		(4.6)		(21.0)		(45.2)		(79.1)
Net interest expense		51.7		24.0		183.9		82.7
Other expense (income)		1.0		(1.0)		3.2		(0.1)
Foreign exchange loss (gain)		(2.0)		(0.9)		4.7		(1.2)
Non-controlling interests		14.4		5.6		34.2		20.1
Preferred securities distributions, net of tax		5.9		4.7		23.0		20.9
Total	$	71.0	$	32.4	$	249.0	$	122.4

For the three months and year ended Dec. 31, 2003, net interest expense increased by $27.7 million and by $101.2 million, respectively, compared to the same periods of 2002. The increase is primarily due to lower capitalized interest and approximately $5 million a month of interest expense incurred as a result of the CE Gen acquisition. The decrease in capitalized interest from 2002 is a result of the completion of the Sarnia, Centralia Gas, Campeche and Chihuahua plants, partially offset by the Genesee 3 project.

The increase in earnings attributable to non-controlling interests in the three months and year ended Dec. 31, 2003 compared to the same periods in 2002 is attributable to the sale of Sheerness to TA Cogen and the 25 per cent non-controlling interest in CE Gen's Saranac facility.

Preferred securities distributions, net of tax, are consistent with 2002.

I N C O M E T A X E S

		3 months ended Dec. 31				Year ended Dec. 31
		2003		2002		2003		2002
Income tax expense (recovery)	$	13.9	$	(33.8)	$	78.4	$	23.4
Effective tax rate		17.8%		39.5%		21.2%		17.8%

For the three months ended Dec. 31, 2003, income tax expense of $13.9 million was recorded compared to an income tax recovery of $33.8 million for the same period of 2002. The recovery and high effective tax rate reflects the impact of the asset impairment charge incurred in the fourth quarter of 2002. Income taxes increased by $55.0 million for the year ended Dec. 31, 2003 due to increased earnings in 2003. The 2003 effective income tax rate, expressed as a percentage of earnings from continuing operations before income taxes and non-controlling interests, reflects the impact of the taxation of the sale of the Sheerness plant, the recognition of the deferred gain and the impairment charges. The effective tax rate in 2002 reflects the benefit of the refinancing of foreign operations in the fourth quarter.

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

The discontinued Transmission operation, which was sold in April 2002, generated after-tax earnings of $12.8 million in the year ended Dec. 31, 2002. The disposal resulted in an after-tax gain of $120.0 million ($0.71 per common share).

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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, 2002 to Dec. 31, 2003:

	Increase/
	(Decrease)		Explanation
Cash and cash equivalents	$	11.7	Refer to Consolidated Statements of Cash Flows.
Investments		(27.2)	Sale of the Goldfields gas pipeline and write down to recognize a loss in
			value other than a temporary decline.
Long-term receivables		80.2	Increase due to the acquisition of CE Gen.
Property, plant and equipment,
net of accumulated depreciation		309.5	Acquisition of CE Gen and Genesee 3 as well as capital expenditures
			and construction activity during the period, partially offset by depreciation,
			the turbine write down and the effect of the strengthening Canadian dollar
			relative to the U.S. dollar.
Goodwill		93.1	Increase due to the acquisition of CE Gen.
Intangible assets		459.0	Increase due to the acquisition of CE Gen offset by depreciation.
Future income tax assets
(including current portion)		43.8	Increase in unused tax losses that are expected to be recovered in future
			years.
Other assets		103.7	Increase in mark-to-market valuation of cross-currency swaps.
Short-term debt		(170.2)	Repayment of short-term debt.
Accounts payable and accrued liabilities		75.0	Increase due to the acquisition of CE Gen.
Long-term debt (including current portion)		(124.0)	Repayments and a reduction of approximately $108 million due to the
			effect of the strengthening Canadian dollar relative to the U.S. dollar on
			U.S. dollar debt, partially offset by new borrowings during the year.
Non-recourse long-term debt
(including current portion)		579.5	Debt acquired on the acquisition of CE Gen, net of principal repayments.
Deferred credits and other long-term liabilities		(93.5)	Primarily due to the recognition of the deferred gain as a result of the
			Sheerness transaction and an increase in mark-to-market valuation of
			cross-currency swaps of $15.3 million.
Future income tax liabilities
(including current portion)		272.1	Increase primarily due to the $186.4 million from the acquisition of
			CE Gen. The remaining is the result of Canadian and U.S. operations.
Non-controlling interests		214.9	$43.8 million from the acquisition of CE Gen, $149.9 million increase in
			non-controlling interest in TA Cogen due to the Sheerness transaction
			and cash distributions of approximately $25 million.
Shareholders' equity		368.5	Net earnings, common share offering, and re-investment of dividends
			partially offset by dividends paid.

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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 :

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L I Q U I D I T Y A N D C A P I T A L R E S O U R C E S

In 2003, TransAlta spent $879.1 million on capital expenditures and acquisitions and repaid net short- and long-term recourse debt of $226.7 million, compared to $985.9 million of capital expenditures and acquisitions and $90.3 million net repayment of debt in 2002. In 2003, these cash expenditures were funded by cash flow from operations, $226.7 million of proceeds from the sale of capital assets, $21.6 million from the sale of the Goldfields pipeline and $265.0 million of net proceeds from the issuance of shares. In 2002 the expenditures were funded by cash flow from operations and the $818.0 million proceeds from the sale of the Transmission operation. Including the non-recourse debt held by CE Gen, TransAlta's short- and long-term debt balance on Dec. 31, 2003 increased by $285.3 million compared to Dec. 31, 2002.

In October 2003, the corporation renewed its $1.0 billion medium-term note shelf registration. The corporation also increased its committed bank credit facility to $1.5 billion from $1.2 billion in July 2003 to meet increasing liquidity requirements. The corporation maintained approximately $400 million of uncommitted credit facilities. At Dec. 31, 2003, the corporation had approximately $1.5 billion of credit available from its committed and uncommitted credit facilities.

On Nov. 25, 2003 TransAlta issued US$300.0 million of 10-year senior notes at an interest rate of 5.75 per cent. The issuance was required to refinance bonds that matured in 2003. This brings the utilization on the US$1.0 billion shelf registration to US$600.0 million. TransAlta intends to renew the registration for a further two year term and increase the registration's available facility to US$1.0 billion.

At Dec. 31, 2003, TransAlta's total debt (including non-recourse debt) to invested capital ratio was 47.9 per cent (42.8 per cent excluding non-recourse debt). This represents an improvement from the Dec. 31, 2002 ratio of 50.4 per cent.

On Nov. 4, 2003, Dominion Bond Rating Service assigned TransAlta a credit rating of BBB with a negative trend. On Aug. 1, 2003, Moody's assigned TransAlta a credit rating of Baa2 with a negative outlook and removed the corporation from credit watch. Previously, in May 2003, Standard and Poor's assigned TransAlta a credit rating of BBB- (stable) and removed the corporation from credit watch. These ratings, which are lower than previously assigned, did not have a significant impact on TransAlta's operations or ability to raise capital.

O U T L O O K

The key factors affecting the financial results for 2004 continue to be the megawatt capacity in place, the availability of and production from generating assets, the margins applicable to non-contracted production, the costs of production, and the volumes traded and margins achieved on Energy Marketing activities.

Production and availability

In 2004, production is expected to increase due to the capacity additions that occurred throughout 2003 partially offset by increased planned maintenance. Availability for 2004 is expected to be similar to 2003. Generating capacity is expected to decrease due to the decommissioning of units one and two (62 MW and 57 MW, respectively) of the Wabamun plant in 2004 partially offset by the expected completion of the 68-MW Summerview Wind Farm project in the third quarter of 2004. The Genesee 3 project is expected to be completed in the first quarter of 2005.

If the plants do not meet the availability or production targets specified in the PPAs contracts then the corporation must either compensate the purchaser for the loss in the availability of production or suffer a reduction in electrical or capacity payments. Consequently, an extended outage could have a material adverse effect on the business, financial condition, results of operations, or cash flows of the corporation.

Production and gross margins from the merchant gas plants are subject to the changes in spark spreads discussed in the following section. TransAlta has not entered into fixed commodity agreements for gas for these merchant plants as gas will be purchased coincident with spot market spark spreads being adequate to produce and sell electricity.

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Power prices

Electricity spot prices in 2004 are expected to be lower than in 2003 for the Alberta and Pacific Northwest markets due to a reduction in natural gas prices from early 2003 levels, increased system wide reserve margins and higher hydro production. In Ontario, electricity spot prices are also expected to be lower in 2004 than in 2003 due to overcapacity from the recommis-sioning of nuclear power facilities. Spark spreads are expected to be comparable to or higher than 2003 as natural gas prices are expected to decrease more than power prices.

Exposure to volatility in electricity prices and spark spreads is substantially mitigated through firm-price, long-term electricity sales contracts. Exposure to volatility in gas prices is partially 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 2004, approximately 85 per cent of output is contracted, a significant portion of which relates to the Alberta PPAs, which are based on achieving specified availability rates. The corporation will continue to focus on maximizing revenues from these contracts.

Costs of production

Fluctuations in the cost of coal are minimized through ownership of reserves in Alberta and Central Washington. OM&A costs per MWh fluctuate by quarter and are dependent on the timing and nature of maintenance activities. OM&A per MWh in 2004 is expected to be consistent with 2003.

Energy Marketing

Short-term and real-time markets are expected to be similar to the last quarter of 2003. Energy Marketing will continue to concentrate on buying and selling electricity, gas and electrical transmission contracts in these markets. This type of trading does not involve long-term contracts and therefore value at risk and volatility related to fair value accounting is relatively low.

Capital and maintenance expenditures

Capital expenditures for 2004 are expected to be approximately $400 million to $425 million of which approximately $160 million will be spent on renewable growth projects and the Genesee 3 project. The remainder will be spent on planned and preventative maintenance, including CE Gen. TransAlta expects to increase planned maintenance expenditures in 2004 as there will be more replacement than repair work conducted. Financing for these expenditures is expected to come from a combination of cash from operations and the exercising of TransAlta Power warrants related to the sale of Sheerness.

Exposure to fluctuations in foreign currencies

TransAlta will continue to offset foreign denominated assets with foreign denominated liabilities. TransAlta also has foreign currency expenses, primarily interest charges, offsetting foreign currency revenues. This strategy minimizes the impact on TransAlta of the recent appreciation in the Canadian dollar against the U.S. dollar.

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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 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*
		2003		2002	2003			2002
				(Restated,				(Restated,
				Note 1)				Note 1)
Revenues	$	655.4	$	531.7	$	2,508.6	$	1,814.9
Trading purchases		(19.1)		(14.1)		(85.1)		(91.0)
Fuel and purchased power		(283.1)		(217.3)		(1,067.4)		(664.6)
Gross margin		353.2		300.3		1,356.1		1,059.3
Operating expenses
Operations, maintenance and administration		146.6		135.1		559.3		420.5
Depreciation and amortization (Note 13)		92.4		68.5		339.0		243.0
Taxes, other than income taxes		5.6		7.6		23.1		27.4
Gain on sale of Sheerness Generating Station (Note 2)		-		-		(191.5)		-
Gain on sale of TransAlta Power partnership units (Note 2)		(15.2)		-		(15.2)		-
Gain on land sale (Note 2)		(10.5)		-		(10.5)		-
Asset impairment charges (Note 6)		5.6		152.5		90.3		152.5
Prior period regulatory decision (Note 12)		-		-		-		3.3
		224.5		363.7		794.5		846.7
Operating income (loss)		128.7		(63.4)		561.6		212.6
Other income (expense)		(1.0)		1.0		(3.2)		0.1
Foreign exchange gain (loss)		2.0		0.9		(4.7)		1.2
Net interest expense		(51.7)		(24.0)		(183.9)		(82.7)
Earnings (loss) from continuing operations before income taxes
and non-controlling interests		78.0		(85.5)		369.8		131.2
Income tax expense (recovery)		13.9		(33.8)		78.4		23.4
Non-controlling interests		14.4		5.6		34.2		20.1
Earnings (loss) from continuing operations		49.7		(57.3)		257.2		87.7
Earnings from discontinued operations, net of tax (Note 3)		-		-		-		12.8
Gain on disposal of discontinued operations, net of tax (Note 3)		-		10.0		-		120.0
Net earnings (loss)		49.7		(47.3)		257.2		220.5
Preferred securities distributions, net of tax		5.9		4.7		23.0		20.9
Net earnings (loss) applicable to common shareholders	$	43.8	$	(52.0)	$	234.2	$	199.6

Common share dividends		(47.7)		(42.3)		(185.0)		(169.0)
Adjustment arising from normal course issuer bid		-		-		-		(27.0)
Retained earnings
Opening balance		937.8		979.0		884.7		881.1
Closing balance	$	933.9	$	884.7	$	933.9	$	884.7

Weighted average common shares outstanding in the period		190.6		169.3		185.3		169.6

Basic earnings (loss) per share
Earnings (loss) from continuing operations	$	0.23	$	(0.37)	$	1.26	$	0.39
Earnings from discontinued operations		-		-		-		0.07
Net earnings (loss) from operations		0.23		(0.37)		1.26		0.46
Gain on disposal of discontinued operations, net of tax		-		0.06		-		0.71
Net earnings (loss)	$	0.23	$	(0.31)	$	1.26	$	1.17

Diluted earnings per share
Earnings (loss) from continuing operations	$	0.23	$	(0.37)	$	1.26	$	0.39
Earnings from discontinued operations		-		-		-		0.07
Net earnings (loss) from operations		0.23		(0.37)		1.26		0.46
Gain on disposal of discontinued operations, net of tax		-		0.06		-		0.71
Net earnings (loss)	$	0.23	$	(0.31)	$	1.26	$	1.17

See accompanying notes.
* Derived from the audited Dec. 31, 2002 consolidated financial statements.

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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 O F C A S H F L O W S
(in millions of Canadian dollars)
		3 months ended Dec. 31				Year ended Dec. 31
		Unaudited			Unaudited			Audited*
		2003		2002	2003			2002
				(Restated,				(Restated,
				Note 1)				Note 1)
Operating activities
Net earnings	$	49.7	$	(47.3)	$	257.2	$	220.5
Depreciation and amortization (Note 13)		106.9		70.3		378.1		276.8
Loss (gain) on sale of assets (Note 2)		(10.5)		12.3		(202.0)		15.6
Dilution gain on sale of TransAlta Power units (Note 2)		(15.2)		-		(15.2)		-
Write down of investments (Note 5)		6.2		-		6.2		-
Future income taxes		4.4		(43.8)		27.4		(60.4)
Non-controlling interests		14.4		5.6		34.2		20.1
Site restoration costs incurred		(3.9)		(2.4)		(26.5)		(14.5)
Site restoration accretion		4.7		1.6		22.0		18.7
Unrealized loss (gain) from energy marketing activities		0.8		6.9		(18.6)		31.7
Foreign exchange loss (gain)		(2.0)		(0.9)		4.7		(1.2)
Asset impairment charge (Note 6)		5.6		152.5		90.3		152.5
Gain on sale of discontinued operations (Note 3)		-		(10.0)		-		(120.0)
Other non-cash items		2.1		(11.7)		3.2		(15.2)
		163.2		133.1		561.0		524.6
Change in non-cash operating working capital balances		2.2		56.4		195.5		(86.9)
Cash flow from operating activities		165.4		189.5		756.5		437.7
Investing activities
Additions to property, plant and equipment		(50.7)		(194.6)		(555.7)		(945.8)
Acquisitions (Note 2)		-		(40.1)		(323.4)		(40.1)
Proceeds on sale of discontinued operations(Note 3)		-		-		-		818.0
Proceeds on sale of long-term investments (Note 5)		-		-		21.6		-
Proceeds on sale of property, plant and equipment (Note 2)		11.0		2.3		226.7		2.3
Long-term receivables		-		(5.4)		-		165.3
Investments		-		-		-		(6.1)
Proceeds on sale of TransAlta Power partnership units (Note 2)		37.2		-		37.2		-
Restricted cash (Note 2)		8.5		-		46.7		-
Deferred charges and other		(12.0)		(23.2)		11.8		(29.8)
Cash flow used in investing activities		(6.0)		(261.0)		(535.1)		(36.2)
Financing activities
Net increase (decrease) in short-term debt		20.2		289.3		(170.2)		(247.1)
Issuance of long-term debt		395.5		-		544.6		611.3
Repayment of long-term debt		(473.3)		(149.4)		(601.1)		(454.5)
Dividends on common shares		(35.7)		(29.5)		(158.3)		(115.5)
Net proceeds on issuance of common shares (Note 9)		-		-		265.0		1.8
Redemption of common shares		-		-		-		(49.9)
Distributions on preferred securities		(9.0)		(8.2)		(35.5)		(34.9)
Distributions to subsidiary's non-controlling limited partner		(12.4)		(5.5)		(38.9)		(24.5)
Deferred financing charges and other		(2.6)		-		(6.6)		(7.6)
Cash flow from (used in) financing activities		(117.3)		96.7		(201.0)		(320.9)
Cash flow from operating, investing and financing activities		42.1		25.2		20.4		80.6
Effect of translation on foreign currency cash		(2.4)		(2.5)		(8.7)		0.7
Increase in cash and cash equivalents		39.7		22.7		11.7		81.3
Cash and cash equivalents, beginning of period		115.3		120.6		143.3		62.0
Cash and cash equivalents, end of period	$	155.0	$	143.3	$	155.0	$	143.3

See accompanying notes.

* Derived from the audited Dec. 31, 2002 consolidated financial statements.

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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 S H E E T S
(in millions of Canadian dollars)
	Dec. 31			Dec. 31
	2003			2002
	Unaudited			Audited*
				(Restated,
				Note 1)
ASSETS
Current assets
Cash and cash equivalents	$	155.0	$	143.3
Accounts receivable		410.2		419.0
Prepaid expenses		53.8		49.4
Price risk management assets (Note 4)		77.1		157.8
Future income tax assets		29.4		18.7
Income taxes receivable		108.9		111.5
Inventory		47.0		48.9
		881.4		948.6
Restricted cash		9.9		-
Investments (Note 5)		5.0		32.2
Long-term receivables (Note 7)		120.1		39.9
Property, plant and equipment
Cost		8,858.5		8,074.1
Accumulated depreciation		(2,541.6)		(2,066.7)
		6,316.9		6,007.4
Goodwill		149.6		56.5
Intangible assets (Note 8)		545.8		86.8
Future income tax assets		105.3		72.2
Price risk management assets (Note 4)		71.9		60.7
Other assets		214.3		110.6
Total assets	$	8,420.2	$	7,414.9

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	$	119.8	$	290.0
Accounts payable and accrued liabilities		547.2		472.2
Price risk management liabilities (Note 4)		71.2		173.8
Future income tax liabilities		4.6		17.1
Dividends payable		14.9		42.9
Current portion of long-term debt		138.5		355.4
Current portion of long-term debt - non-recourse		45.3		-
		941.5		1,351.4
Long-term debt		2,444.1		2,351.2
Long-term debt - non-recourse		534.2		-
Deferred credits and other long-term liabilities		359.3		452.8
Future income tax liabilities		686.7		402.1
Price risk management liabilities (Note 4)		65.1		50.6
Non-controlling interests		477.9		263.0
Preferred securities		450.8		451.7
Common shareholders' equity
Common shares (Note 9)		1,555.7		1,226.2
Contributed surplus		-		-
Retained earnings		933.9		884.7
Cumulative translation adjustment		(29.0)		(18.8)
		2,460.6		2,092.1
Total liabilities and shareholders' equity	$	8,420.2	$	7,414.9

Commitments and contingencies (Notes 7 and 10) See accompanying notes.

* Derived from the audited Dec. 31, 2002 consolidated financial statements.

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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.

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

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 asset retirement obligations, stock-based compensation, accounting for non-derivatives used in trading activities and accounting for derivatives not held for trading.

Asset retirement obligations

Effective Jan. 1, 2003, TransAlta early adopted the new Canadian Institute of Chartered Accountants (CICA) standard for accounting for asset retirement obligations. Under the new standard, the corporation recognizes asset retirement obligations in the period in which they are incurred if a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted over the estimated time period until settlement of the obligation and the asset is depreciated over the estimated useful life of the asset. Previously, future site restoration costs for coal and hydro plants were recognized over the estimated life of the plant on a straight-line basis. Reclamation costs for mining assets were recognized on a unit-of-production basis. No provision for future site restoration for gas generation plants had been recognized as the costs of restoration were expected to be offset by the salvage value of the related plant.

TransAlta recorded an asset retirement obligation for all generating facilities, as it is legally required to remove the facilities at the end of their useful lives and restore the plant sites to their original condition. For hydro facilities, the corporation is required to remove the generating equipment, but is not legally required to remove the structures. The asset retirement liabilities are recognized when the asset retirement obligation is incurred. Asset retirement liabilities for coal mines are incurred over time, as new areas are mined, and a portion of the liability is settled over time as areas are reclaimed prior to final pit reclamation.

The effect of this change in accounting policy was recorded retroactively with restatement of prior periods. The impact of the change in policy for the three months and year ended Dec. 31, 2003 was not material to the consolidated financial statements. The effect of the adoption on prior periods is presented below as increases (decreases):

			Dec. 31, 2002

Balance sheets:
Asset retirement asset, included in property, plant and equipment			$	97.3
Accumulated depreciation on asset retirement asset				27.3
Property, plant and equipment				(101.9)
Accumulated depreciation				(27.2)
Asset retirement obligations, included in deferred credits and other long-term liabilities				(87.4)
Long-term future income tax liabilities				30.2
Opening retained earnings				42.8


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

Statements of earnings:
Site restoration accrual, included in fuel and purchased power	$	(9.4)	$	(38.0)
Depreciation and amortization expense		0.3		1.2
Depreciation and amortization expense, included in fuel and purchased power		(0.2)		(1.0)
Accretion expense, included in depreciation and amortization expense		5.7		22.8
Current income tax expense		1.3		5.3

Net earnings applicable to common shareholders	$	2.3	$	9.7

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A reconciliation between the opening and closing asset retirement obligation balances is provided below:

Balance, Jan. 1, 2002	$	232.2
Liabilities incurred in period		28.5
Liabilities settled in period		(14.5)
Accretion expense		18.7

Balance, Dec. 31, 2002	$	264.9
Liabilities incurred in period		9.3
Liabilities settled in period		(26.5)
Accretion expense		22.0
Acquisition of CE Gen		5.2
Change in foreign exchange rates		(16.7)

Balance, Dec. 31, 2003	$	258.2

TransAlta estimates the undiscounted amount of cash flow required to settle the asset retirement obligation is approximately $1.5 billion, which will be incurred between 2007 and 2082. The majority of the costs will be incurred between 2030 and 2035. A discount rate of eight per cent was used to calculate the carrying value of the asset retirement obligation. No assets have been legally restricted for settlement of the liability.

Stock based compensation

Effective Jan. 1, 2003, the corporation elected to prospectively use the fair value method of accounting for awards granted under its fixed stock option plans and its performance stock option plan subsequent to Jan. 1, 2003. No awards were granted in 2003.

Previously, the intrinsic value method was used. The following table provides pro forma measures of net earnings and earnings per share had compensation expense been recognized for awards granted prior to 2003 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:

		3 months ended Dec. 31				Year ended Dec. 31
		2003		2002		2003		2002

				(Restated,				(Restated,
				Note 1)				Note 1)
Reported net earnings (loss) applicable to common shareholders	$	43.8	$	(52.0)	$	234.2	$	199.6
Compensation expense		0.7		1.0		2.6		3.7

Pro forma net earnings (loss) applicable to common shareholders	$	43.1	$	(53.0)	$	231.6	$	195.9


Reported basic earnings (loss) per share	$	0.23	$	(0.31)	$	1.26	$	1.17
Compensation expense per share		-		-		0.01		0.02

Pro forma basic earnings (loss) per share	$	0.23	$	(0.31)	$	1.25	$	1.15


Reported diluted earnings (loss) per share	$	0.23	$	(0.31)	$	1.26	$	1.17
Compensation expense per share		-		-		0.01		0.02

Pro forma diluted earnings (loss) per share	$	0.23	$	(0.31)	$	1.25	$	1.15


Accounting for non-derivatives used in trading activities

In October 2002, U.S. standard setters rescinded EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Non-derivative energy trading contracts are now accounted for using the accrual method. Previously, non-derivative contracts were accounted for using mark-to-market accounting. The change in policy was recorded retroactively with restatement of prior periods; however the effect on prior periods was not material to the consolidated financial statements.

Accounting for derivatives not held for trading

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2. ACQUISITIONS AND DISPOSALS - CONTINUING OPERATIONS

On Jan. 29, 2003, the corporation acquired a 50 per cent interest in CE Generation LLC (CE Gen). The purchase price allocation was finalized in the second quarter of 2003 and is presented below.

Net assets acquired at assigned values:
Working capital, including cash of $43.2 million	$	60.3
Restricted cash		57.9
Current income tax receivable		2.4
Property, plant and equipment		1,025.1
Goodwill		108.9
Note receivable		90.0
Non-recourse long-term debt, including current portion		(717.4)
Future income tax liability		(216.0)
Non-controlling interests		(44.6)

Total	$	366.6


Consideration:
Cash	$	366.6

Property, plant and equipment includes acquired intangibles in the amount of $610.5 million related to the fair value of power sale contracts acquired. The amount is being amortized over the terms of the contracts.

The amount of restricted cash acquired has been reduced subsequent to the acquisition as a result of TransAlta issuing a letter of credit in lieu of holding the restricted cash.

On May 9, 2003, TransAlta sold the Calgary head office for $65.8 million, which approximated book value. TransAlta is leasing the property back for a term of 20 years. The lease is accounted for as an operating lease.

In July 2003, TransAlta completed the sale of its 50 per cent interest in the two-unit, 756-MW coal-fired Sheerness plant to TransAlta Cogeneration, L.P. (TA Cogen) for $630.0 million. TA Cogen is owned 50.01 per cent by TransAlta and 49.99 per cent by TransAlta Power, L.P. (TransAlta Power). TransAlta received cash proceeds of $149.9 million, $315.0 million in TA Cogen units and $165.1 million in TransAlta Power units. As part of the financing and concurrent with the sale, TransAlta Power issued 17.75 million partnership units and 17.75 million warrants to the public for gross proceeds of $165.1 million, and 17.75 million partnership units to TransAlta for gross proceeds of $165.1 million. As a result of the unit issuance, TransAlta's ownership interest in TransAlta Power on July 31, 2003 was approximately 26 per cent. The warrants, when exercised, are exchangeable for one TransAlta Power unit at any time until Aug. 3, 2004. As the warrants are exercised, TransAlta will sell TransAlta Power units back to TransAlta Power for $9.30 per unit, reducing its ownership interest in TransAlta Power to its original 0.01 per cent and increasing cash proceeds by a further $165.1 million assuming all the warrants are exercised. As a result of the exercising of warrants and the subsequent sale of TransAlta Power units back to TransAlta Power, TransAlta's ownership interest in TransAlta Power was approximately 19 per cent at Dec. 31, 2003.

In connection with the sale, the obligation for TransAlta to purchase all of TransAlta Power's interest in TA Cogen on Dec. 31, 2018 that arose on the sale of power generation assets to TA Cogen in 1998 has been eliminated; therefore the deferred gain of approximately $119 million related to this sale was recognized in earnings. In addition, the management agreements between TransAlta, TransAlta Power and TA Cogen were amended to remove the mechanism for the deferral of management fees and remove the obligation for TransAlta Power and TA Cogen to pay management fees to TransAlta in the future. As consideration for the amendments, TransAlta received $1.0 million from TransAlta Power and $5.0 million from TA Cogen.

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As a result of the sale, in the third quarter of 2003, TransAlta realized a gain on sale of $191.5 million, which includes the realization of the 1998 deferred gain (approximately $119 million). In the fourth quarter TransAlta recognized $15.2 million of gains on the exercise of warrants. TransAlta expects to recognize approximately $53 million of further gains on the assumption that the warrants are fully exercised and TransAlta's effective interest in TransAlta Power is reduced to its original 0.01 per cent.

On Dec. 31, 2003, TransAlta completed the sale of 539 acres of undeveloped land at Seebe, Alberta for $11.0 million. The corporation recognized a gain on sale of $10.5 million.

In December 2002, TransAlta completed a step purchase 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 are included in Generation's segment. Vision Quest operates 124 wind turbines with 119 MW of gross generating capacity in operation (82 MW net ownership interest).

The aggregate purchase price included 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. 91,478 of the shares were issued in 2003 and 44,809 will be issued over the next two years.

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

On April 29, 2002, the corporation's Transmission operation was sold for proceeds of $820.7 million. In the fourth quarter of 2002, the gain on disposal was adjusted without restatement to $120.0 million 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 consolidated statement of earnings.

Dec. 31, 2002	3 months ended		Year ended

Revenues	$	-	$	55.8
Operating expenses		-		(30.8)

Operating income		-		25.0
Net interest expense		-		(2.4)

Earnings before income taxes		-		22.6
Income taxes		-		(9.8)

Earnings before gain on disposal		-		12.8
Gain on disposal		10.0		120.0

Earnings from discontinued operations	$	10.0	$	132.8

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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

Energy Marketing's price risk management assets and liabilities represent the value of unsettled (unrealized) proprietary trading transactions and those asset backed trading transactions accounted for on a mark-to-market basis. With the exception of transmission contracts, the fair value of all energy trading activities is based on quoted market prices. The fair value of financial transmission contracts is based upon statistical analysis of historical data. All physical transmission contracts are now accounted for on an accrual basis in accordance with EITF 02-03.

The following table illustrates movements in the fair value of the corporation's price risk management assets (liabilities) during the year ended Dec. 31, 2003:

Change in fair value of net assets (liabilities)	Fair value			Accrual		Total

Net price risk management assets (liabilities) outstanding at Dec. 31, 2002	$	(7.5)	$	1.6	$	(5.9)
New contracts entered into during the period		13.1		-		13.1
Changes in values attributable to market price and other market changes		0.7		-		0.7
Contracts realized, amortized or settled during the period		6.4		(1.6)		4.8
Changes in values attributable to changes in valuation techniques and assumptions		-		-		-

Net price risk management assets outstanding at Dec. 31, 2003	$	12.7	$	-	$	12.7

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

												2009 and
		2004		2005		2006		2007		2008		thereafter		Total
Prices actively quoted	$	4.0	$	3.1	$	2.1	$	1.5	$	-	$	-	$	10.7
Prices based on models		2.0		-		-		-		-		-		2.0
	$	6.0	$	3.1	$	2.1	$	1.5	$	-	$	-	$	12.7

The carrying and fair value of energy trading assets and liabilities included on the balance sheet are as follows:

Balance Sheet	Dec. 31, 2003		Dec. 31, 2002

Price risk management assets
Current	$	77.1	$	157.8
Long-term		71.9		60.7
Price risk management liabilities
Current		(71.2)		(173.8)
Long-term		(65.1)		(50.6)

Net price risk management assets (liabilities) outstanding	$	12.7	$	(5.9)

In accordance with EITF 02-03, physical transmission is now accounted for under accrual accounting. As of Dec. 31, 2003, TransAlta had recorded $1.5 million on the balance sheet as prepaid transmission related to these contracts. The maximum term of these contracts is 12 months.

The corporation's trading positions at Dec. 31, 2003 were as follows:

		Fixed price payor	Fixed price receiver	Maximum term
	Units (000s)	notional amounts	notional amounts	in months

Electricity	MWh	13,872.6	4,106.8	33
Natural gas	GJ	37,805.3	56,308.8	24

The corporation's electrical transmission contracts trading position was 7.4 million megawatt hours (MWh) at Dec. 31, 2003 compared to 18.1 million MWh at Dec. 31, 2002. The decrease relates to TransAlta's systematic withdrawal from the New York TCC market.

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

On April 30, 2003, the corporation sold its 8.82 per cent interest in the Goldfields Gas Pipeline for proceeds of AUD$24.1 million (Cdn$21.6 million), which approximated book value.

On an annual basis, TransAlta reviews the valuation of its long-term investments. As a result of this review, in the fourth quarter of 2003, the corporation recorded a $6.2 million charge to recognize an other than temporary decline in fair value. The charge is included in corporate operations, maintenance and administration expenses.

6 . A S S E T I M P A I R M E N T C H A R G E S

Following a strategic review and after examining expected market conditions and potential development opportunities against TransAlta's risk profile, the corporation concluded that the book value of its turbine inventory was unlikely to be recovered. As a result, TransAlta recorded an $84.7 million impairment charge in the third quarter of 2003 to write down the turbines to fair value. Fair value was based on quoted market prices.

The corporation performed an annual review of its property, plant and equipment. As a result of this review, TransAlta recorded a $5.6 million impairment charge on the Binghamton plant in the fourth quarter of 2003. The Binghamton plant is a peaker plant that sells electricity to the New York area at spot market rates when such prices exceed its marginal operating costs. Due to generation overcapacity in the Northeastern U.S. and transmission constraints, TransAlta does not expect the plant to operate on a regular basis or at prices that would justify its current book value. The impairment charge reduces the Binghamton plant's book value to fair value. Fair value was based on the present value of expected future cash flows.

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

8 . I N T A N G I B L E A S S E T S

Intangible assets consist of $487.3 million of sales contracts resulting from the CE Gen acquisition and $58.5 million of coal rights relating to TransAlta mining operations. The value of the sales contracts are amortized over the life of the contracts and the coal rights are amortized on a unit of production basis, based on the estimated mine reserve.

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, 2003, the corporation had 190.7 million (Dec. 31, 2002 - 169.8 million) common shares issued and outstanding plus outstanding employee stock options to purchase an additional 3.2 million shares (Dec. 31, 2002 - 3.2 million).

In March 2003, the corporation issued 15.0 million common shares for gross proceeds of $240.0 million, with issue costs of $8.0 million. The offering included an option for the underwriters to purchase a further 2.25 million common shares for $36.0 million. This option was exercised on April 17, 2003 with issue costs of $3.0 million.

In February 2003, TransAlta announced a normal course issuer bid to repurchase up to 3.0 million common shares for cancellation. No shares were repurchased during 2003.

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1 0 . C O N T I N G E N C I E S

In March 2003, FERC completed its investigation of natural gas and power markets and indicated that the total industry refunds for price overcharges will be higher than originally anticipated. In June 2003, FERC issued two show cause orders, the Partnership Gaming Order and the Gaming Practices Order, in which TransAlta's U.S. subsidiaries were named. These orders required TransAlta to justify certain trading activities in California between Jan. 1, 2000 and June 20, 2001. In response to FERC's show cause orders TransAlta confirmed that it did not engage in gaming behavior. Based on the information provided by TransAlta, FERC Trial Staff filed a Motion to Dismiss with respect to TransAlta in the two show cause proceedings. On Jan. 22, 2004 FERC granted the FERC Trial Staff's motion to dismiss TransAlta from both the Partnership Gaming Order and the Gaming Practices Order. FERC found that TransAlta did not engage in prohibited gaming practices.

TransAlta's investigations revealed no significant bidding behaviours outlined in the FERC request for information. Based on TransAlta's responses, it is unlikely that TransAlta will be required to make any refunds or payments pursuant to these orders.

On May 30, 2002, the California Attorney General's Office filed civil complaints in the state court of California against eight 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. The state court denied the Attorney General's complaint and granted an order to dismiss the claims against TransAlta. The Attorney General has appealed this decision. The appeal is still ongoing at this time.

CE Gen's geothermal and cogeneration facilities are qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and their contracts for the sale of electricity are subject to regulations thereunder. In order to promote open competition in the industry, legislation has been proposed in the U.S. Congress that calls for either a repeal of PURPA on a prospective basis or the significant restructuring of the regulations governing the electric industry, including sections of PURPA. Current federal legislative proposals would not abrogate, amend, or modify existing contracts with electric utilities. The ultimate outcome of any proposed legislation is unknown at this time.

The corporation is involved in various other claims and legal actions arising from the normal course of business. The corporation does not expect that the outcome of these proceedings will have a materially adverse effect on the corporation.

1 1 . E X I T A C T I V I T I E S

In June 2003, TransAlta announced its intention to close its Annapolis, MD trading office and consolidate all trading activities in Calgary. The decision is expected to increase operating efficiencies and reduce costs. Costs of $1.1 million were incurred in the fourth quarter in connection with the closure of the office, related to relocation, impairment of assets in the Annapolis office and other related costs. An additional $0.8 million was incurred in the third quarter related to these costs. The trading office was closed in October 2003.

The total amount of involuntary termination, which vested over three months, was $0.7 million; all of which was recognized prior to the fourth quarter. The amounts are included in operations, maintenance and administration expense for the Energy Marketing segment.

1 2 . 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

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

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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, 2003, the results of Vision Quest are included in the Generation segment. Prior period amounts have been reclassified. The results of CE Gen are also included in the Generation segment from the date of purchase (Jan. 29, 2003).

Each business segment assumes responsibility for its operating results measured to operating income.

I. Earnings Information
		Unaudited

				Energy
3 months ended Dec. 31, 2003	Generation			Marketing	Corporate			Total

Revenues	$	624.9	$	30.5	$	-	$	655.4
Trading purchases		-		(19.1)		-		(19.1)
Fuel and purchased power		(283.1)		-		-		(283.1)

Gross margin		341.8		11.4		-		353.2
Operations, maintenance and administration		118.7		5.8		22.1		146.6
Depreciation and amortization		87.8		0.7		3.9		92.4
Taxes, other than income taxes		5.6		-		-		5.6
Gain on sale of TransAlta Power partnership units		(15.2)		-		-		(15.2)
Gain on sale of Seebe land		(10.5)		-		-		(10.5)
Asset impairment charges		5.6		-		-		5.6

Operating income before corporate allocations		149.8		4.9		(26.0)		128.7
Corporate allocations		(23.1)		(2.9)		26.0		-

Operating income	$	126.7	$	2.0	$	-		128.7


Other expense								(1.0)
Foreign exchange gain								2.0
Net interest expense								(51.7)

Earnings from continuing operations before income taxes and non-controlling interests							$	78.0


	Unaudited

				Energy
3 months ended Dec. 31, 2002	Generation			Marketing	Corporate			Total

Revenues	$	499.7	$	32.0	$	-	$	531.7
Trading purchases		-		(14.1)		-		(14.1)
Fuel and purchased power		(217.3)		-		-		(217.3)

Gross margin		282.4		17.9		-		300.3
Operations, maintenance and administration		115.7		3.6		15.8		135.1
Depreciation and amortization		63.4		0.5		4.6		68.5
Asset impairment and equipment cancellation charges		152.5		-		-		152.5
Taxes, other than income taxes		7.6		-		-		7.6

Operating income (loss) before corporate allocations		(56.8)		13.8		(20.4)		(63.4)
Corporate allocations		(18.1)		(2.3)		20.4		-

Operating income (loss)	$	(74.9)	$	11.5	$	-		(63.4)


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

Earnings (loss) from continuing operations before income taxes and non-controlling interests							$	(85.5)

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	Unaudited

				Energy
Year ended Dec. 31, 2003	Generation			Marketing		Corporate		Total

Revenues	$	2,412.2	$	96.4	$	-	$	2,508.6
Trading purchases		-		(85.1)		-		(85.1)
Fuel and purchased power		(1,067.4)		-		-		(1,067.4)

Gross margin		1,344.8		11.3		-		1,356.1
Operations, maintenance and administration		480.0		14.9		64.4		559.3
Depreciation and amortization		321.6		3.1		14.3		339.0
Taxes, other than income taxes		23.1		-		-		23.1
Gain on sale of Sheerness Generating Station		(191.5)		-		-		(191.5)
Gain on sale of TransAlta Power partnership units		(15.2)		-		-		(15.2)
Gain on sale of Seebe land		(10.5)		-		-		(10.5)
Asset impairment charges		90.3		-		-		90.3

Operating income (loss) before corporate allocations		647.0	$	(6.7)		(78.7)		561.6
Corporate allocations		(69.9)		(8.8)		78.7		-

Operating income (loss)	$	577.1	$	(15.5)	$	-		561.6


Other expense								(3.2)
Foreign exchange loss								(4.7)
Net interest expense								(183.9)

Earnings from continuing operations before income taxes and non-controlling interests							$	369.8


	Audited

				Energy
Year ended Dec. 31, 2002	Generation			Marketing		Corporate		Total

Revenues	$	1,674.9	$	140.0	$	-	$	1,814.9
Trading purchases		-		(91.0)		-		(91.0)
Fuel and purchased power		(664.6)		-		-		(664.6)

Gross margin		1,010.3		49.0		-		1,059.3
Operations, maintenance and administration		346.7		15.1		58.7		420.5
Depreciation and amortization		220.3		2.5		20.2		243.0
Asset impairment and equipment cancellation charges		152.5		-		-		152.5
Taxes, other than income taxes		27.3		0.1		-		27.4
Prior period regulatory decisions		3.3		-		-		3.3

Operating income before corporate allocations		260.2		31.3		(78.9)		212.6
Corporate allocations		(70.6)		(8.3)		78.9		-

Operating income	$	189.6	$	23.0	$	-		212.6


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							$	131.2

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II. Selected balance sheet information
					Energy
Dec. 31, 2003			Generation		Marketing		Corporate			Total

Goodwill			$	120.3	$	29.3	$	-	$	149.6
Total segment assets			$	7,598.8	$	267.1	$	554.3	$	8,420.2


Dec. 31, 2002

Goodwill			$	27.2	$	29.3	$	-	$	56.5
Total segment assets			$	6,348.7	$	344.6	$	721.6	$	7,414.9


III. Selected cash flow information
				Energy			Discontinued
3 months ended Dec. 31, 2003	Generation		Marketing		Corporate		Operations			Total

Capital expenditures	$	44.1	$	0.1	$	6.5	$	-	$	50.7
3 months ended Dec. 31, 2002

Capital expenditures	$	190.8	$	2.1	$	1.7	$	-	$	194.6
Acquisitions	$	40.1	$	-	$	-	$	-	$	40.1

				Energy			Discontinued
Year ended Dec. 31, 2003	Generation		Marketing		Corporate		Operations			Total

Capital expenditures	$	542.4	$	0.8	$	12.5	$	-	$	555.7
Acquisitions	$	323.4	$	-	$	-	$	-	$	323.4
Year ended Dec. 31, 2002

Capital expenditures	$	909.1	$	4.2	$	10.7	$	21.8	$	945.8
Acquisitions	$	40.1	$	-	$	-	$	-	$	40.1

IV. Reconciliation
Depreciation and amortization expense (D&A) per statement of cash flows
				3 months ended Dec. 31				Year ended Dec. 31
				2003		2002		2003		2002

D&A expense for reportable segments			$	92.4	$	68.5	$	339.0	$	243.0
Mining equipment depreciation, included in fuel and purchased power				15.7		7.5		47.1		37.1
Site restoration accretion, included in D&A expense				(4.7)		(5.7)		(22.0)		(22.8)
Discontinued operations				-		-		-		15.6
Other				3.5		-		14.0		3.9

			$	106.9	$	70.3	$	378.1	$	276.8

1 4 . 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 to the current period's presentation.

:P33

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

Q U A R T E R L Y R E P O R T 2 0 0 3

S U P P L E M E N T A L I N F O R M A T I O N
(Annualized)		Dec. 31, 2003		Dec. 31, 2002

					(Restated)
Closing market price		$	18.53	$	17.11
Price range (last 12 months)
	High	$	19.55	$	23.95
	Low	$	15.36	$	16.69
Debt/invested capital (including non-recourse debt)			47.9%		50.4%
Debt/invested capital (excluding non-recourse debt)			42.8%		50.4%
Return on common shareholders' equity			10.3%		3.9%
Return on invested capital			9.1%		4.2%
Book value per share		$	12.90	$	12.32
Cash dividends per share		$	1.00	$	1.00
Price/earnings ratio (times)			14.7		37.2
Dividend payout ratio			79.0%		212.3%
Interest coverage (times)			2.4		1.5
Interest coverage including preferred securities (times)			2.1		1.2
Dividend coverage (times)			4.0		2.5
Dividend yield			5.4%		5.8%

:P34

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

Q U A R T E R L Y R E P O R T 2 0 0 3

G L O S S A R Y O F K E Y T E R M S

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

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

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

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

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

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

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

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

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

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

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

Q U A R T E R L Y R E P O R T 2 0 0 3

TransAlta Corporation

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

Calgary, Alberta Canada T2P 2M1

PHONE

403.267.7110

WEB SITE www.transalta.com

CIBC Mellon Trust Company

P.O. Box 7010 Adelaide Street Station

Toronto, Ontario Canada M5C 2W9

toll free in North America: 1.800.387.0825

PHONE

416.643.5500 in Toronto or outside North America

FAX

416.643.5501

EMAIL inquiries@cibcmellon.com

WEB SITE www.cibcmellon.com

For more information:

Media inquiries:

Tim Richter,

Senior Media Relations Specialist

PHONE

403.267.3655

PAGER

403.213.7041

EMAIL media_relations@transalta.com

Investor inquiries:

Daniel J. Pigeon,

Director, Investor Relations

PHONE

1.800.387.3598 in Canada and United States or 403.267.2520

FAX

403.267.2590

EMAIL investor_relations@transalta.com

I, Stephen 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-15(e) and 15d-15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

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

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated: January 29, 2004

/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;

Dated: January 29, 2004

/s/ Ian Bourne

Ian Bourne

Executive Vice President

and Chief Financial Officer

Certification of Chief Executive Officer

Pursuant to 18 U.S.C. 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned officer of TransAlta Corporation (the "Company") hereby certifies, to such officer's knowledge, that:

(i) the accompanying Report of Foreign Private Issuer on Form 6-K of the Company (the "Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: January 29, 2004

/s/ Stephen G. Snyder

Stephen G. Snyder

President and Chief Executive Officer

Certification of Chief Financial Officer

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: January 29, 2004

/s/ Ian Bourne

Ian Bourne

Executive Vice President

and Chief Financial Officer

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 29, 2004