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 October, 2003

TRANSALTA CORPORATION

(Translation of registrant's name into English)

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

(Address of principal executive offices)

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

Form 20-F____ Form 40-F X

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

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

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

Evaluation of Disclosure Controls and Procedures

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

EXHIBITS

Exhibit 1	Press release dated October 23, 2003.
Exhibit 2	Quarterly report for the three-month period ended September 30, 2003, which includes Management's Discussion and Analysis and consolidated financials statements.
Exhibit 3	Sarbanes-Oxley Act - Section 302 - certification of Stephen G. Snyder
Exhibit 4	Sarbanes-Oxley Act - Section 302 - certification of Ian Bourne
Exhibit 5	Sarbanes-Oxley Act - 906 - certification of Stephen G. Snyder
Exhibit 6	Sarbanes-Oxley Act - 906 - certification of Ian Bourne

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: October 23, 2003

TransAlta announces third quarter results

CALGARY, Alberta (Oct. 23, 2003) - TransAlta Corporation (TSX: TA; NYSE: TAC) today announced earnings from continuing operations for third quarter 2003 of $118.4 million ($0.62 per common share), up from $70.3 million ($0.42 per share) in third quarter 2002. Earnings included $145.8 million ($0.76 per share) of after-tax gains related to the sale of the coal-fired Sheerness Generating Station, which closed on July 31, 2003 and a $55.4 million after-tax ($0.29 per share) asset impairment charge related to turbines. Earnings from continuing operations for the nine months ended Sept. 30, 2003 were $190.4 million ($1.04 per share), compared to $128.8 million ($0.76 per share) for the same period in 2002, while net earnings for the same periods were $190.4 million ($1.04 per share) and $251.6 million ($1.48 per share), respectively.

Financial results for the quarter reflect increased maintenance at the Alberta thermal plants, the addition of several new power plants and lower hydro production.

"Our focus in 2003 and 2004 is to improve the performance of our assets," said Steve Snyder, TransAlta's president and CEO. "As a result, we have been and will continue to increase expenditures related to life cycle maintenance while we limit capacity growth. These productivity investments will better position the company for long-term financial results."

Production was 13,687 gigawatt-hours (GWh), up 16 per cent (1,937 GWh) due to CE Generation and the new power plant additions, partially offset by increased maintenance at the Alberta thermal plants and lower water levels for the hydro plants. Plant availability was 88.8 per cent, down from 89.4 per cent in third quarter 2002, mainly due to planned maintenance.

Cash generated from operating activities was $147.0 million, compared to cash used in operating activities of $14.2 million in third quarter 2002. This increase was mainly due to the settlement of a disputed ancillary services revenue issue with the Balancing Pool of Alberta in 2002 ($49.9 million), and to the timing of cash tax obligations ($55.6 million).

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.

- more -

In third quarter 2003, TransAlta:

Began commercial operation of the 259-megawatt (MW) combined-cycle gas-fired Chihuahua III power plant in Mexico on Sept. 9, 2003.
Closed the sale of its 50 per cent interest in the two-unit, 756-MW coal-fired Sheerness Generating Station to TransAlta Cogeneration, L.P., which is owned 50.01 per cent by TransAlta and 49.99 per cent by TransAlta Power, L.P., on July 31, 2003.
Renewed and increased its committed corporate credit facility to $1.5 billion from $1.2 billion. The increased size of the facility provides TransAlta with more flexibility to manage its credit and liquidity requirements and maintain a strong financial position.

TransAlta is Canada's largest non-regulated power generation and wholesale marketing company. 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.

- 30 -

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

Q3:2003

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 and nine months ended Sept. 30, 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.

Earnings before interest, taxes and non-controlling interests (EBIT) is shown because each business segment assumes responsibility for its operating results measured to EBIT and it is a widely accepted measure of financial performance used by some analysts and investors to analyze and compare companies on the basis of operating performance. EBIT 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 EBIT is not necessarily comparable to a similarly titled measure of another company. EBIT is reconciled to net earnings applicable to common shareholders below:

:P1

			Unaudited				Unaudited
		3 months ended Sept. 30				9 months ended Sept. 30
		2003		2002¹		2003		2002¹

EBIT	$	210.2	$	123.3	$	432.9	$	276.0
Other expense		(2.2)		(1.5)		(2.2)		(0.9)
Foreign exchange gain (loss)		1.0		(1.0)		(6.7)		0.3
Net interest expense		(47.9)		(20.9)		(132.2)		(58.7)

Earnings from continuing operations before income taxes and
non-controlling interests		161.1		99.9		291.8		216.7
Income tax expense		29.7		20.5		64.5		57.2
Non-controlling interests		7.2		3.6		19.8		14.5

Earnings from continuing operations		124.2		75.8		207.5		145.0
Earnings from discontinued operations		-		-		-		12.8
Gain on disposal of discontinued operations		-		-		-		110.0

Net earnings		124.2		75.8		207.5		267.8
Preferred securities distributions, net of tax		5.8		5.5		17.1		16.2

Net earnings applicable to common shareholders	$	118.4	$	70.3	$	190.4	$	251.6

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

3 months ended Sept. 30				2003				2002 ⁴

Availability				88.8%				89.4%
Production (GWh)				13,687				11,750
Electricity trading volumes (GWh) ¹				23,604				31,176
Gas trading volumes (million GJ)				70.1				31.1


			Per common				Per common
		Amount		share		Amount		share

Revenues	$	630.0			$	450.3

Earnings from continuing operations ²	$	118.4	$	0.62	$	70.3	$	0.42

Net earnings applicable to common shareholders	$	118.4	$	0.62	$	70.3	$	0.42


Cash flow from (used in) operating activities	$	147.0			$	(14.2)



9 months ended Sept. 30				2003				2002 ⁴

Availability				90.3%				88.4%
Production (GWh)				39,243				34,638
Electricity trading volumes (GWh) ¹				68,023				68,211
Gas trading volumes (million GJ)				164.4				113.8


			Per common				Per common
		Amount		share		Amount		share

Revenues	$	1,787.2			$	1,206.3

Earnings from continuing operations ²	$	190.4	$	1.04	$	128.8	$	0.76
Earnings from discontinued operations ³		-		-		12.8		0.07
Gain on disposal of discontinued operations, net of tax ³		-		-		110.0		0.65

Net earnings applicable to common shareholders	$	190.4	$	1.04	$	251.6	$	1.48


Cash flow from operating activities	$	591.1			$	248.2

1	2002 electricity 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 which 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.

:P2

Availability decreased for the third quarter of 2003 compared to the third quarter of 2002 due to increased planned maintenance at the Alberta thermal plants. Availability increased for the nine months ended Sept. 30, 2003 compared to the same period in 2002 as a result of higher availability at the Centralia and Poplar Creek plants, partially offset by lower availability at the Alberta thermal plants due to increased planned maintenance.

Production increased in the three and nine months ended Sept. 30, 2003 due to increased production from the Centralia and Poplar Creek plants and capacity additions due to the acquisitions of CE Generation LLC (CE Gen) and Vision Quest Windelectric Inc. (Vision Quest), as well as the commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants during 2003. The increase was partially offset by increased planned maintenance at the Alberta thermal plants, lower hydro production in the third quarter of 2003 due to hydrology conditions and the decommissioning of unit three of the Wabamun plant in November 2002.

Revenues increased in the three and nine months ended Sept. 30, 2003 compared to the same periods in 2002 as a result of increased production as discussed above. This was partially offset by reduced Energy Marketing revenues in the nine months ended Sept. 30, 2003.

In the third quarter of 2003, EBIT increased by $86.9 million compared to the same period in 2002. The increase reflects the $191.5 million gain on sale of the Sheerness Generating Station (Sheerness), partially offset by an $84.7 million asset impairment charge related to turbines and a net decrease of $19.9 million from operations primarily due to increased planned maintenance at the Alberta thermal plants and the lower hydro production. The blackout in the Northeastern U.S. and Eastern Canada had minimal impact on the reported results. The same factors resulted in the increase in EBIT for the nine months ended Sept. 30, 2003.

Earnings from continuing operations for the three and nine month periods ended Sept. 30, 2003 includes the $145.8 million after-tax gain related to the sale of the Sheerness plant as well as the $55.4 million after-tax turbine impairment. Net interest expense increased due to CE Gen, as well as decreased capitalized interest upon the completion of the Big Hanaford, Sarnia, Campeche and Chihuahua plants. In the nine months ended Sept. 30, 2002, net earnings applicable to common shareholders included the gain on sale of the Transmission operation.

Cash flow from operating activities for the three months ended Sept. 30, 2003 was $147.0 million compared to cash flow used in operating activities of $14.2 million in the third quarter of 2002. Cash flow in 2002 reflects the settlement of a disputed ancillary services revenue issue with the Balancing Pool of Alberta ($49.9 million) and the timing of cash tax obligations ($55.6 million). For the nine months ended Sept. 30, 2003, cash flow from operating activities was $591.1 million compared to $248.2 million for the first three quarters of 2002. The increase is primarily due to the reasons discussed above as well as the collection of commodity tax receivables in the U.S. and Mexico (US$79.0 million) in the second quarter of 2003 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 third quarter report to shareholders in voluntary compliance with the requirements of Section 302 of the Sarbanes-Oxley Act.

:P3

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

3 months ended Sept. 30, 2003 and 2002

Sale of Sheerness Generating Station

On July 31, 2003, TransAlta completed the sale of its 50 per cent interest in the two-unit, 756-megawatt (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. The warrants, when exercised, are exchangeable for one TransAlta Power unit at any time until Aug. 3, 2004. As a result of the unit issuance, TransAlta's ownership interest in TransAlta Power at Sept. 30, 2003 is approximately 25 per cent. 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.

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 (pre-tax) was recognized in earnings. In addition, the management agreements between TransAlta and TransAlta Power and TA Cogen were amended to remove the mechanism for the deferral of the 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 removal of these terms, TransAlta received $1.0 million from TransAlta Power and $5.0 million from TA Cogen.

As a result of the sale, TransAlta realized a pre-tax gain on sale of $191.5 million ($145.8 million after-tax), which includes the realization of the $119 million 1998 deferred gain. TransAlta expects to recognize approximately $68 million of further pre-tax 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.

Asset impairment charges

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 fully recovered. As a result, TransAlta has recorded a pre-tax $84.7 million impairment charge ($55.4 million after-tax) in the third quarter of 2003 to write down the turbines to fair value.

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.

Nine months ended Sept. 30, 2003 and 2002

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 pre-tax loss of $33.3 million ($20.0 million after-tax) in May 2003.

:P4

Equity offering

In the first quarter of 2003, the corporation issued 15.0 million common shares for gross proceeds of $240.0 million. The underwriters exercised an option to purchase a further 2.25 million shares for gross proceeds of $36.0 million on April 17, 2003.

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 Sept. 30, 2003 is included in the Generation segment.

In the first quarter of 2003, TransAlta and EPCOR Utilities Inc. (EPCOR) announced an agreement whereby TransAlta acquired a 50 per cent interest in EPCOR's Genesee 3 project for an estimated $395 million. The 450 MW addition to the existing Genesee Generating Station is currently under construction southwest of Edmonton, Alberta.

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).

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 Power Purchase Arrangements (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.

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 to reflect agreed working capital adjustments and actual amounts paid and received.

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 (pre-tax), which was recorded as a reduction of revenue.

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

Effective Jan. 1, 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 the first nine months of 2003.

:P5

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 Sept. 30, 2003, Generation had 8,846 MW of gross generating capacity in operation (8,322 MW net ownership interest) and 225 MW under construction.

TransAlta added 1,367 MW of net generating capacity in the first nine months of 2003. The corporation commissioned two plants in Mexico: the 259 MW Chihuahua plant on Sept. 9, 2003 and the 252 MW Campeche plant in May 2003. During the first half of 2003, the McBride Lake wind generation project was completed, resulting in 75 MW of capacity of which TransAlta has a 50 per cent interest through its ownership of Vision Quest. The Sarnia plant was commissioned in March 2003, resulting in 440 MW of generating capacity in addition to the existing 135 MW. TransAlta also acquired a 50 per cent interest in CE Gen in January 2003. TransAlta's net ownership in CE Gen's 13 geothermal and gas-fired plants is 378 MW (408 MW gross). This increase in net generating capacity was partially offset by the sale of TransAlta's 50 per cent interest in the 756 MW Sheerness Generating Station to TA Cogen on July 31, 2003.

For the three and nine months ended Sept. 30, 2003, availability was 88.8 per cent and 90.3 per cent, respectively, compared to 89.4 per cent and 88.4 per cent, respectively, in the comparable periods of 2002. The decrease in the third quarter is due to higher planned maintenance at the Alberta thermal plants. The increase in the first three quarters is due to higher availability at the Centralia and Poplar Creek plants, partially offset by lower availability at the Alberta thermal plants due to increased planned maintenance.

The results of the Generation segment are as follows:

			2003					2002 ¹
3 months ended Sept. 30		Total	Per MWh			Total		Per MWh

Revenues	$	613.6	$	44.83	$	431.8	$	36.74
Fuel and purchased power		(278.5)		(20.35)		(163.5)		(13.91)

Gross margin		335.1		24.48		268.3		22.83
Operating expenses:
Operations, maintenance and administration		134.8		9.84		76.9		6.54
Depreciation and amortization		85.7		6.26		54.2		4.61
Taxes, other than income taxes		5.8		0.43		5.9		0.50
Gain on sale of Sheerness Generating Station		(191.5)		(13.99)		-		-
Asset impairment charges		84.7		6.19		-		-

EBIT before corporate allocations		215.6		15.75		131.3		11.18
Corporate allocations		(14.5)		(1.06)		(18.7)		(1.59)

EBIT	$	201.1	$	14.69	$	112.6	$	9.59


				2003				2002 ¹
9 months ended Sept. 30		Total	Per MWh			Total		Per MWh

Revenues	$	1,787.3	$	45.54	$	1,175.2	$	33.92
Fuel and purchased power		(784.3)		(19.98)		(447.3)		(12.91)

Gross margin		1,003.0		25.56		727.9		21.01
Operating expenses:
Operations, maintenance and administration		361.3		9.20		231.0		6.67
Depreciation and amortization		233.8		5.96		156.9		4.53
Taxes, other than income taxes		17.5		0.45		19.7		0.57
Gain on sale of Sheerness Generating Station		(191.5)		(4.88)		-		-
Asset impairment charges		84.7		2.16		-		-
Prior period regulatory decision		-		-		3.3		0.09

EBIT before corporate allocations		497.2		12.67		317.0		9.15
Corporate allocations		(46.8)		(1.19)		(52.5)		(1.52)

EBIT	$	450.4	$	11.48	$	264.5	$	7.63

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 financial statements for further discussion.

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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 Power Purchase Arrangements (PPAs) are long-term arrangements that apply to the previously regulated Alberta generation plants. All of TransAlta's Alberta coal-fired and hydroelectric facilities operate under PPAs. Under the terms of a PPA, a single customer has the rights to the entire production of a plant or unit for the length of the PPA.

PPAs established 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 would be 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. These targeted amounts are met by TransAlta 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 cogeneration plants and have between one and four customers per plant. Revenues are derived from payments for capacity and the production of electrical energy and steam.

Merchant revenue is derived from the sale of production only, with multiple customers per plant. Production is sold via: 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. Two gas-fired facilities (115 MW) sell their output under fixed-price contracts ranging from 15 to 30 years in length, with expiration dates of 2009 and 2024. The third gas-fired facility (100 MW) sells its output under a fixed-price contract that expires in 2005. All three facilities have gas supply arrangements in place for the duration of the electricity sales contracts.

Fuel &

Purchased

Gross

3 months ended

Production

Purchased

Gross

Revenue

Power

Margin

Sept. 30, 2003

(GWh)

Revenue

Power

Margin

per MWh

Alberta PPAs

7,012

166.6

46.2

120.4

23.76

6.59

17.17

Long-term contracts

2,307

167.9

101.9

66.0

72.78

44.17

28.61

Merchant

3,583

180.5

105.3

75.2

50.38

29.39

20.99

CE Gen

785

98.6

25.1

73.5

125.60

31.97

93.63

TOTAL

13,687

613.6

278.5

335.1

44.83

20.35

24.48

Fuel &

Purchased

Gross

3 months ended

Production

Purchased

Gross

Revenue

Power

Margin

Sept. 30, 2002

(GWh)

Revenue

Power

Margin

per MWh

Alberta PPAs

7,483

186.8

52.7

134.1

24.96

7.04

17.92

Long-term contracts

1,496

75.1

29.1

46.0

50.20

19.45

30.75

Merchant ¹

2,771

169.9

81.7

88.2

51.56

24.80

26.76

TOTAL

11,750

431.8

163.5

268.3

36.74

13.91

22.83

:P7

										Fuel &
				Fuel &						Purchased			Gross
9 months ended	Production			Purchased			Gross		Revenue	Power			Margin
Sept. 30, 2003	(GWh)		Revenue	Power			Margin		per MWh		per MWh		per MWh

Alberta PPAs	21,188	$	566.3	$	142.3	$	424.0	$	26.73	$	6.72	$	20.01
Long-term contracts	5,868		463.0		286.2		176.8		78.90		48.77		30.13
Merchant	10,171		513.1		290.9		222.2		50.45		28.60		21.85
CE Gen	2,016		244.9		64.9		180.0		121.48		32.19		89.29

TOTAL	39,243	$	1,787.3	$	784.3	$	1,003.0	$	45.54	$	19.98	$	25.56


											Fuel &
					Fuel &					Purchased			Gross
9 months ended	Production			Purchased			Gross		Revenue		Power		Margin
Sept. 30, 2002	(GWh)		Revenue		Power		Margin		per MWh		per MWh		per MWh

Alberta PPAs	22,752	$	586.3	$	132.7	$	453.6	$	25.77	$	5.83	$	19.94
Long-term contracts	4,387		239.4		95.5		143.9		54.57		21.77		32.80
Merchant ¹	7,499		388.4		219.1		169.3		47.19		26.62		20.57
Wabamun arbitration decision	-		(38.9)		-		(38.9)		-		-		-

TOTAL	34,638	$	1,175.2	$	447.3	$	727.9	$	33.92	$	12.91	$	21.01

1	Revenue per MWh and fuel and purchased power per MWh includes actual production volumes and economic dispatch volumes purchased (524 GWh and 731 GWh for the three and nine months ended Sept. 30, 2002, respectively).

Alberta PPAs

In the three and nine months ended Sept. 30, 2003, production decreased by 471 gigawatt hours (GWh) and 1,564 GWh, respectively as a result of increased planned maintenance at the Alberta thermal plants and the decommissioning of unit three of the Wabamun plant in November 2002.

For the three months ended Sept. 30, 2003, revenues decreased by $1.20 per megawatt hour (MWh) compared to the same period in 2002. The decrease is due to increased planned maintenance, which reduced availability, offset by the revenue escalators inherent in the PPAs. In the third quarter of 2002, TransAlta earned incentive revenue as availability was above the targeted amount in the PPAs. Fuel and purchased power for the third quarter decreased by $0.45 per MWh compared to the same period in 2002 due to the timing of planned maintenance at the coal mines which was higher in 2002. The majority of the coal used for production under Alberta PPAs are from coal reserves owned by TransAlta.

For the nine months ended Sept. 30, 2003, revenues increased by $0.96 per MWh compared to the first three quarters of 2002 due to incentives earned as availability exceeded the PPA targets and the impact of the revenue escalators in the PPAs. Fuel and purchased power increased by $0.89 per MWh compared to the same period in 2002 as a result of increased natural gas and power prices and higher planned maintenance costs at the coal mines in 2003.

Long-term contracts

Production increased by 811 GWh for the third quarter of 2003 and by 1,481 GWh for the nine months ended Sept. 30, 2003 compared to the same periods in 2002. The increase is primarily a result of incremental production from the Sarnia plant, the acquisition of Vision Quest and the commencement of commercial operations at the Campeche and Chihuahua plants.

Revenues increased by $22.58 per MWh and $24.33 per MWh in the three and nine months ended Sept. 30, 2003, respectively. The increase is due in part to $21.2 million ($9.19 per MWh) and $76.0 million ($12.95 per MWh) of incremental steam revenues earned from the Sarnia plant in the three and nine months ended Sept. 30, 2003, respectively. Revenues also increased as a result of increased natural gas prices. At certain plants, increased natural gas prices flow through to customers and are therefore recovered through increased revenues. Fuel and purchased power increased by $24.72 per MWh and $27.00 per MWh in the three and nine months ended Sept. 30, 2003. The increase is primarily a result of higher natural gas market prices and the cost of the gas used for steam production.

:P8

Gross margin per MWh decreased by $2.14 per MWh and $2.67 per MWh in the three and nine months ended Sept. 30, 2003, respectively due to the commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants, which have lower gross margins than existing contracted plants.

Merchant production

In the third quarter of 2003, merchant production was 3,583 GWh, of which 2,562 GWh was contracted under short- to medium-term contracts. In the third quarter of 2002, merchant production was 2,771 GWh, of which 2,010 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. The increase in production in the third quarter of 2003 reflects the economic dispatch decisions made in 2002 (524 GWh), as well as increased production from the Sarnia and Big Hanaford plants, partially offset by lower hydro production. For the nine months ended Sept. 30, 2003, merchant production was 10,171 GWh, of which 8,293 GWh was contracted. In the first three quarters of 2002, merchant production was 7,499 GWh, of which 6,250 GWh was contracted. The increases are the result of the reasons discussed above, including 731 GWh of economic dispatch.

As shown in the above graphs, electricity spot prices in Alberta and the Pacific Northwest were significantly higher in the third quarter of 2003 compared to the same period in 2002. This was the result of lower than normal hydro production in the Pacific Northwest and increased natural gas prices. The Ontario market was regulated until May 2002, and remains partially regulated. Spark spreads (power price less cost of gas consumed) in both Alberta and the Pacific Northwest increased in the third quarter of 2003 compared to the same period in 2002, as electricity prices increased more than natural gas prices. Ontario spark spreads were negative in the third quarter of 2003 due to a combination of low electricity prices relative to high 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 overcapacity in a specific market or other generation fuel sources available in a market such as hydro or nuclear power.

For the three months ended Sept. 30, 2003, merchant revenues decreased by $1.18 per MWh compared to the third quarter of 2002. The decrease was due to lower production at the hydro facilities, partially offset by increased electricity spot prices. For the nine months ended Sept. 30, 2003, merchant revenues increased by $3.26 per MWh compared to the same period in 2002. The increase is the result of higher electricity spot prices and higher hydro ancillary services prices. For the three and nine months ended Sept. 30, 2003, fuel and purchased power increased by $4.59 per MWh and $1.98 per MWh, respectively as a result of increased natural gas prices.

CE Gen

In the third quarter of 2003, CE Gen produced 785 GWh of electricity. Revenue was $125.60 per MWh and fuel and purchased power was $31.97 per MWh. From Jan. 29, 2003 to Sept. 30, 2003, production was 2,016 GWh, revenue was $121.48 per MWh and fuel and purchased power was $32.19 per MWh.

:P9

Operations, maintenance and administration expense

In the third quarter of 2003, total planned maintenance outage days were consistent with the same period in 2002 but were focused on maintenance at the Alberta thermal plants compared to gas plants in 2002. The result was proportionately higher operations, maintenance and administration (OM&A) expensed versus capitalized.

In the third quarter of 2003, OM&A expenses increased by $57.9 million ($3.30 per MWh) over the same period in 2002. Excluding the impact of the CE Gen acquisition, OM&A costs increased by $38.8 million ($2.43 per MWh) due to the addition of the Sarnia plant, the two Mexican plants and the increased planned maintenance costs at the Alberta thermal plants.

The table below shows the amount of planned maintenance capitalized and expensed for the three and nine month periods ended Sept. 30, 2003 and 2002, excluding CE Gen.

	3 months ended Sept. 30		9 months ended Sept. 30
Planned maintenance expenditures	2003	2002	2003	2002

Capitalized	6.9	17.9	30.8	92.2
Expensed	27.0	6.1	64.9	26.9

	33.9	24.0	95.7	119.1

The increase in maintenance expense was due to the nature of the planned maintenance at the Alberta thermal plants. Planned maintenance in 2003 involved repairing asset components rather than replacing them whereas maintenance in 2002 was predominantly outside Alberta and involved more replacement components.

For the nine months ended Sept. 30, 2003, OM&A increased by $130.3 million ($2.53 per MWh) compared to the same period in 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 as discussed above.

OM&A costs for CE Gen were $19.1 million ($24.33 per MWh) in the third quarter of 2003 and $52.5 million ($26.04 per MWh) for the first nine months of 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. The decrease in CE Gen OM&A in the third quarter is primarily due to the seasonality of maintenance activities.

Depreciation and amortization

Depreciation and amortization increased by $31.5 million ($1.65 per MWh) in the third quarter of 2003 and $76.9 million ($1.43 per MWh) for the first nine months of 2003 compared to the same periods in 2002. In the third quarter, $22.1 million of the increase is the result of the CE Gen acquisition. In the nine months ended Sept. 30, 2003, $59.7 million of the increase is the result of the CE Gen acquisition. The remaining increase is due to incremental depreciation from the commissioning of the Big Hanaford, Sarnia, Campeche and Chihuahua plants, as well as the acquisition of Vision Quest, partially offset by the decommissioning of Wabamun unit three in 2002.

Taxes other than income taxes

For the three and nine months ended Sept. 30, 2003, taxes other than income taxes were consistent with the same periods in 2002.

:P10

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

Energy Marketing 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, natural gas and transmission needs on behalf of Generation. TransAlta generates approximately one quarter of its electricity using gas-fired turbines. Therefore, the corporation's natural physical commodity position is "short" gas and "long" power. The contracts used have fixed or variable pricing provisions and are settled with physical delivery. Accrual accounting is used under both Canadian and U.S. GAAP and the results of these contracts, as well as the costs to execute them, are included in Generation's segmented results.

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 commodities produced and consumed by 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. The results of these contracts, as well as the costs to execute them are included in Generation's segmented results.

Energy Marketing also uses commodity derivatives to manage risk, earn trading revenue and gain market information. This portfolio consists of physical and financial derivative instruments including forwards, swaps, futures and options in various commodities. Under FASB Statement 133 these activities 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 this portfolio are recognized in income in the period they occur.

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

	3 months ended Sept. 30		9 months ended Sept. 30
Electricity (GWh)	2003	2002	2003	2002

Physical	14,498	20,722	41,992	45,801
Financial	9,106	10,454	26,031	22,410

	23,604	31,176	68,023	68,211


	3 months ended Sept. 30		9 months ended Sept. 30
Gas (million GJ)	2003	2002	2003	2002

Physical	25.7	29.4	75.0	74.1
Financial	44.4	1.7	89.4	39.7

	70.1	31.1	164.4	113.8

Electricity volumes in the third quarter of 2003 were lower than the same period in 2002 due to the closure of the Annapolis office and a decline in market opportunities. Electricity volumes in the nine months ended Sept. 30, 2003 remained consistent with the same period of 2002. The increase in gas volumes relates to the increased use of heat rate contracts, which involve a gas component, to manage power positions. TransAlta's trading activities are mainly short-term transactions, thereby limiting risk and maintaining low working capital requirements.

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. All transmission contracts are accounted for in accordance with FASB EITF 02-03. The fair value of financial transmission contracts is based upon statistical analysis of historical data. 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 (liabilities) for the period.

:P11

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		12.6		-		12.6
Changes in values attributable to market price and other market changes		(1.1)		-		(1.1)
Contracts realized, amortized or settled during the period		9.5		(1.6)		7.9
Changes in values attributable to changes in valuation techniques and assumptions		-		-		-

Net price risk management assets outstanding at Sept. 30, 2003	$	13.5	$	-	$	13.5


			Sept. 30,		Dec. 31,
Balance Sheet			2003			2002

Price risk management assets
Current			$	105.5	$	157.8
Long-term				71.9		60.7
Price risk management liabilities
Current				(99.7)		(173.8)
Long-term				(64.2)		(50.6)

Net price risk management assets (liabilities) outstanding			$	13.5	$	(5.9)

Energy Marketing's trading positions at Sept. 30, 2003 were as follows:

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

Electricity	MWh	16,602.2	16,295.8	36
Natural gas	GJ	44,952.7	33,154.0	27

The corporation's electrical transmission contracts trading position was 14.7 million MWh at Sept. 30, 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.

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

												2008 and
		2003		2004		2005		2006		2007		thereafter		Total

Prices actively quoted	$	5.0	$	7.4	$	3.1	$	2.1	$	1.5	$	-	$	19.1
Prices based on models		(5.1)		(0.5)		-		-		-		-		(5.6)

	$	(0.1)	$	6.9	$	3.1	$	2.1	$	1.5	$	-	$	13.5

In accordance with EITF 02-03, physical transmission is now accounted for under accrual accounting. As of Sept. 30, 2003, TransAlta had recorded $4.6 million on the balance sheet as prepaid transmission related to these contracts. The maximum term of these contracts is 15 months.

Based on the above positions, contracts and changes in market prices, Energy Marketing's results are as follows:

		3 months ended Sept. 30				9 months ended Sept. 30
		2003		2002		2003		2002

Net trading revenues (losses)	$	16.4	$	18.5	$	(0.1)	$	31.1
Operations, maintenance and administration		4.7		5.0		9.1		11.5
Depreciation and amortization		0.8		0.6		2.4		2.0
Taxes other than income taxes		-		0.1		-		0.1

EBIT before corporate allocations		10.9		12.8		(11.6)		17.5
Corporate allocations		(1.8)		(2.1)		(5.9)		(6.0)

EBIT	$	9.1	$	10.7	$	(17.5)	$	11.5

:P12

Net trading revenues decreased by $2.1 million for the third quarter of 2003 and $31.2 million for the first nine months of 2003 compared to the same periods in 2002. During the third quarter of 2003, Energy Marketing consolidated its trading activities in Calgary. As a result, fewer volumes were transacted and settled. This was partially offset by higher western market prices than in the comparable period of 2002. For the nine months ended Sept. 30, 2003, the decrease in revenues, compared to the same period in 2002, is due to the error on TCC bids that occurred in the second quarter of 2003.

OM&A costs for the third quarter of 2003 included $1.1 million of severance and exit costs incurred as a result of the closure of the Annapolis office. A further $0.3 million is expected to be incurred in the fourth quarter of 2003. OM&A for the first nine months of 2003 was lower than the same period in 2002 as a result of lower incentive compensation costs.

Depreciation and amortization for the three and nine months ended Sept. 30, 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 in California, 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 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 behaviour. Based on the information provided by TransAlta, FERC staff filed a Motion to Dismiss with respect to TransAlta in the two show cause proceedings. A number of parties have filed objections to the Motions to Dismiss TransAlta. 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.

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 Sept. 30				9 months ended Sept. 30
		2003		2002		2003		2002

Gross interest expense	$	56.9	$	44.8	$	175.9	$	126.2
Interest income		(0.6)		(1.0)		(3.1)		(7.0)
Interest allocated to discontinued operations		-		-		-		(2.4)
Capitalized interest		(8.4)		(22.9)		(40.6)		(58.1)

Net interest expense		47.9		20.9		132.2		58.7
Other expense		2.2		1.5		2.2		0.9
Foreign exchange loss (gain)		(1.0)		1.0		6.7		(0.3)
Non-controlling interests		7.2		3.6		19.8		14.5
Preferred securities distributions, net of tax		5.8		5.5		17.1		16.2

	$	62.1	$	32.5	$	178.0	$	90.0

:P13

Net interest expense increased by $27.0 million and by $73.5 million in the three and nine months ended Sept. 30, 2003, respectively, compared to the same periods of 2002. The increase is primarily due to approximately $5 million a month of interest expense incurred as a result of the CE Gen acquisition and lower capitalized interest. The decrease in capitalized interest from 2002 is a result of the completion of the Big Hanaford, Campeche, Sarnia and Chihuahua plants, partially offset by the Genesee 3 plant.

The foreign exchange loss in 2003 relates primarily to a reduction in the value of a commodity tax receivable in Mexico associated with equipment purchases and was the result of the weakening of the Mexican peso relative to the U.S. dollar. The receivable was collected in the second quarter of 2003.

The increase in earnings attributable to non-controlling interests in the three and nine months ended Sept. 30, 2003 compared to the same periods in 2002 is attributable to the 25 per cent non-controlling interest in CE Gen's Saranac facility and the sale of Sheerness to TA Cogen.

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

I N C O M E T A X E S

		3 months ended Sept. 30				9 months ended Sept. 30
		2003		2002		2003		2002

Income tax expense Effective tax rate	$	29.7	$	20.5	$	64.5	$	57.2
Effective tax rate		18.4%		20.5%		22.1%		26.4%

For the three and nine months ended Sept. 30, 2003, income tax expense increased by $9.2 million and $7.3 million, respectively, compared to the same periods in 2002. The increase is due primarily to the tax effect of the sale of the Sheerness plant ($45.7 million), partially offset by the tax effect of the asset impairment charges ($29.3 million). In 2002 the refinancing of foreign operations reduced income tax expense as $11.2 million of previously unrecognized foreign loss carryforward balances were recognized. The 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 charge. The effective tax rate in 2002 reflects the benefit of the refinanc-ing of foreign operations in the third quarter. For the remainder of 2003, the annualized tax rate is expected to be between 25 and 30 per cent.

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 nine months ended Sept. 30, 2002. The disposal resulted in an after-tax gain of $110.0 million ($0.65 per common share). The gain of $110.0 million included a number of estimates and in the fourth quarter of 2002 was adjusted to $120.0 million to reflect agreed working capital adjustments and actual amounts paid and received.

:P14

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 Sept. 30, 2003:

	Increase/
	(Decrease)		Explanation

Cash and cash equivalents	$	(28.0)	Refer to Consolidated Statements of Cash Flows.
Accounts receivable		(85.7)	Decrease due to collection of commodity tax receivables in Mexico and
			the U.S., offset by the purchase of CE Gen.
Investments		(21.1)	Sale of the Goldfields gas pipeline.
Long-term receivables		49.1	Increase due to the acquisition of CE Gen.
Property, plant and equipment, net of
accumulated depreciation		818.8	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		94.4	Acquisition of CE Gen in January 2003.
Other assets		87.7	Increase in mark-to-market valuation of cross-currency swaps.
Short-term debt		(190.6)	Repayment of short-term debt with proceeds from the Sheerness
			transaction.
Long-term debt (including current portion)		(73.1)	Net borrowings during the year, more than offset by repayments and the
			effect of the strengthening Canadian dollar relative to the U.S.
			dollar on U.S. dollar debt.
Non-recourse long-term debt
(including current portion)		606.3	Debt acquired on the acquisition of CE Gen.
Deferred credits and other long-term liabilities		(146.7)	Recognition of the deferred gain as a result of the Sheerness
			transaction, asset retirement obligations settled in the period and the
			increase in mark-to-market valuation of cross-currency swaps.
Future income tax liabilities
(including current portion)		249.3	Increase primarily due to the acquisition of CE Gen.
Non-controlling interests		183.6	Acquisition of CE Gen and increase in non-controlling interest in TA
			Cogen due to the Sheerness transaction.
Shareholders' equity		359.7	Net earnings and common share offering, partially offset by dividends
			and net redemption of common shares.

:P15

:P16

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

The corporation increased its committed bank credit facility to $1.5 billion from $1.2 billion in July 2003 and maintained the $500.0 million of uncommitted credit facilities. The corporation is in the process of renewing its $1.0 billion medium-term note facility and it is expected to be finalized on Oct. 24, 2003. TransAlta has a credit rating of BBB high with a negative trend, by Dominion Bond Rating Service, which is currently under review. On Aug. 1, 2003, Moody's downgraded TransAlta's credit rating to Baa2 with a negative outlook and removed the corporation from credit watch. Previously, in May 2003, Standard and Poor's downgraded TransAlta's credit rating to BBB- (stable) and removed the corporation from credit watch. The downgrades did not trigger early repayment under any of the corporation's debt agreements; however they resulted in decreased credit limits granted by TransAlta's trading counterparties thereby requiring the corporation to increase collateral by approximately $19.8 million.

At Sept. 30, 2003, TransAlta's total debt (including non-recourse debt) to invested capital ratio was 48.9 per cent (43.7 per cent excluding non-recourse debt). This represents a decrease from the Dec. 31, 2002 ratio of 50.4 per cent as a result of lower debt levels resulting from the equity offering completed in March 2003 and the sale of the office building, the Goldfields gas pipeline and the Sheerness Generating Station, partially offset by the CE Gen acquisition and the Genesee 3 project.

As discussed previously, TransAlta sold its 50 per cent interest in the Sheerness plant on July 31, 2003 for proceeds of $630.0 million, which was comprised of $149.9 million in cash, $315.0 million in TA Cogen units and $165.1 million in TransAlta Power units. Cash proceeds were used to repay short-term debt.

In the first half of 2003, the corporation issued 17.25 million common shares for gross proceeds of $276.0 million.

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. The lease is accounted for as an operating lease and proceeds from the sale were used to repay short-term debt.

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). The proceeds approximated book value and were used to repay short-term debt.

O U T L O O K

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

Capacity and availability

Generating capacity is expected to remain at the current level for the last quarter of 2003. For the remainder of 2003, only one major maintenance outage is planned at an Alberta thermal plant. As a result, availability for the remainder of 2003 is expected to be similar to the first half of the year. Production is expected to increase in the fourth quarter of the year due to the increased availability as well as the increased capacity that occurred in the third quarter.

:P17

Power prices

Electricity spot prices for the remainder of the year are generally expected to be comparable to or higher than those in the third quarter of 2003 in all markets due to natural gas prices and seasonal factors such as lower hydro production and colder weather.

Exposure to volatility in electricity prices 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 the remainder of 2003, approximately 89 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 the maximization of revenues from these contracts. For merchant plants, spark spreads for the remainder of the year are expected to be similar to those experienced in the first nine months of 2003.

Costs of production

OM&A costs per MWh fluctuate by quarter and are dependent on the timing and nature of maintenance activities. Excluding CE Gen, fourth quarter OM&A per MWh is expected to be lower than experienced in the first nine months of 2003. CE Gen OM&A per MWh for the remainder of the year is expected to be consistent with the first quarter of 2003.

Energy Marketing

Short-term and real-time markets are expected to continue to be active. 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 expenditures

Capital expenditures for 2003 are expected to be approximately $675 million to $700 million, excluding the acquisition of a 50 per cent interest in CE Gen.

:P18

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)
		Unaudited				Unaudited
		3 months ended Sept. 30				9 months ended Sept. 30
		2003		2002		2003		2002

				(Restated,				(Restated,
				Note 1)				Note 1)
Revenues	$	630.0	$	450.3	$	1,787.2	$	1,206.3
Fuel and purchased power		(278.5)		(163.5)		(784.3)		(447.3)

Gross margin		351.5		286.8		1,002.9		759.0

Operating expenses
Operations, maintenance and administration		153.2		98.4		412.7		285.4
Depreciation and amortization		89.1		59.1		246.6		174.5
Taxes, other than income taxes		5.8		6.0		17.5		19.8
Gain on sale of Sheerness Generating Station (Note 2)		(191.5)		-		(191.5)		-
Asset impairment charges (Note 6)		84.7		-		84.7		-

		141.3		163.5		570.0		479.7

Operating income		210.2		123.3		432.9		279.3
Other expense		(2.2)		(1.5)		(2.2)		(0.9)
Foreign exchange gain (loss)		1.0		(1.0)		(6.7)		0.3
Net interest expense		(47.9)		(20.9)		(132.2)		(58.7)

Earnings from continuing operations before regulatory
decisions, income taxes and non-controlling interests		161.1		99.9		291.8		220.0
Prior period regulatory decision (Note 11)		-		-		-		(3.3)

Earnings from continuing operations before income taxes
and non-controlling interests		161.1		99.9		291.8		216.7
Income tax expense		29.7		20.5		64.5		57.2
Non-controlling interests		7.2		3.6		19.8		14.5

Earnings from continuing operations		124.2		75.8		207.5		145.0
Earnings from discontinued operations, net of tax (Note 3)		-		-		-		12.8
Gain on disposal of discontinued operations, net of tax (Note 3)		-		-		-		110.0

Net earnings		124.2		75.8		207.5		267.8
Preferred securities distributions, net of tax		5.8		5.5		17.1		16.2

Net earnings applicable to common shareholders	$	118.4	$	70.3	$	190.4	$	251.6

Common share dividends		(47.4)		(42.1)		(137.3)		(126.7)
Adjustment arising from normal course issuer bid		-		(4.1)		-		(27.0)
Retained earnings
Opening balance		866.8		954.9		884.7		881.1

Closing balance	$	937.8	$	979.0	$	937.8	$	979.0


Weighted average common shares outstanding in the period		189.8		169.2		183.6		169.5


Basic earnings per share
Continuing operations	$	0.62	$	0.42	$	1.04	$	0.76
Earnings from discontinued operations		-		-		-		0.07

Net earnings from operations		0.62		0.42		1.04		0.83
Gain on disposal of discontinued operations, net of tax		-		-		-		0.65
Net earnings	$	0.62	$	0.42	$	1.04	$	1.48


Diluted earnings per share
Earnings from continuing operations	$	0.62	$	0.42	$	1.04	$	0.76
Earnings from discontinued operations		-		-		-		0.07

Net earnings from operations		0.62		0.42		1.04		0.83
Gain on disposal of discontinued operations, net of tax		-		-		-		0.65

Net earnings	$	0.62	$	0.42	$	1.04	$	1.48


See accompanying notes.

:P19

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)
		Unaudited				Unaudited
		3 months ended Sept. 30				9 months ended Sept. 30
		2003		2002		2003		2002

				(Restated,				(Restated,
Operating activities				Note 1)				Note 1)
Net earnings	$	124.2	$	75.8	$	207.5	$	267.8
Depreciation and amortization (Note 12)		100.8		66.2		271.2		206.5
Loss (gain) on sale of assets (Note 2)		(189.0)		0.3		(189.4)		3.3
Future income taxes		21.2		(34.4)		23.0		(16.6)
Non-controlling interests		7.2		3.6		19.8		14.5
Site restoration costs incurred		(19.1)		(9.0)		(22.6)		(12.1)
Site restoration accretion		5.2		5.7		17.3		17.1
Unrealized loss (gain) from energy marketing activities		(8.5)		3.3		(19.4)		24.8
Foreign exchange loss (gain)		(1.0)		1.0		6.7		(0.3)
Asset impairment charge (Note 6)		84.7		-		84.7		-
Gain on disposal of Transmission operation		-		-		-		(110.0)
Other non-cash items		(0.4)		(5.6)		1.1		(3.5)

		125.3		106.9		399.9		391.5
Change in non-cash operating working capital balances		21.7		(121.1)		191.2		(143.3)

Cash flow from (used in) operating activities		147.0		(14.2)		591.1		248.2

Investing activities
Additions to property, plant and equipment		(99.1)		(182.2)		(505.0)		(751.2)
Acquisitions (Note 2)		-		-		(323.4)		-
Proceeds on sale of discontinued operations (Note 3)		-		-		-		818.0
Proceeds on sale of long-term investments		-		-		21.6		-
Proceeds on sale of property, plant and equipment		149.9		-		215.7		-
Long-term receivables		(0.7)		136.0		-		170.7
Investments		-		(0.5)		-		(6.1)
Restricted cash (Note 2)		(9.2)		-		38.2		-
Deferred charges and other		24.6		(0.6)		23.8		(6.6)

Cash flow from (used in) investing activities		65.5		(47.3)		(529.1)		224.8

Financing activities
Net increase (decrease) in short-term debt		(208.3)		1.4		(188.3)		(536.4)
Issuance of long-term debt		-		92.1		149.1		612.5
Repayment of long-term debt		(9.4)		(3.5)		(129.9)		(306.3)
Dividends on common shares		(64.2)		(28.3)		(122.6)		(86.0)
Net proceeds on issuance of common shares (Note 8)		-		0.2		265.0		1.8
Redemption of common shares		-		(16.5)		-		(49.9)
Distributions on preferred securities		(8.9)		(9.1)		(26.5)		(26.7)
Distributions to subsidiary's non-controlling limited partner		(13.7)		(6.5)		(26.5)		(19.0)
Deferred financing charges and other		(3.9)		(2.3)		(4.0)		(7.6)

Cash flow from (used in) financing activities		(308.4)		27.5		(83.7)		(417.6)

Cash flow from (used in) operating, investing and financing activities		(95.9)		(34.0)		(21.7)		55.4
Effect of translation on foreign currency cash		12.5		4.1		(6.3)		3.2

Increase (decrease) in cash and cash equivalents		(83.4)		(29.9)		(28.0)		58.6
Cash and cash equivalents, beginning of period		198.7		150.5		143.3		62.0

Cash and cash equivalents, end of period	$	115.3	$	120.6	$	115.3	$	120.6


See accompanying notes.

:P20


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)
	Unaudited			Audited*
	Sept. 30			Dec. 31
		2003		2002

				(Restated,
ASSETS					Note 1)
Current assets
Cash and cash equivalents	$	115.3	$		143.3
Accounts receivable		333.3			419.0
Prepaid expenses		58.0			49.4
Price risk management assets (Note 4)		105.5			157.8
Future income tax assets		17.0			18.7
Income taxes receivable		110.3			111.5
Inventory		49.2			48.9

		788.6			948.6

Restricted cash		17.6			-
Investments (Note 5)		11.1			32.2
Long-term receivables (Note 7)		89.0			39.9
Property, plant and equipment
Cost		9,184.2		8,184.1
Accumulated depreciation		(2,271.2)		(2,089.9)

		6,913.0		6,094.2
Goodwill		150.9			56.5
Future income tax assets		92.6			72.2
Price risk management assets (Note 4)		71.9			60.7
Other assets		198.3			110.6

Total assets	$	8,333.0	$	7,414.9


LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	$	99.4	$		290.0
Accounts payable and accrued liabilities		489.7			472.2
Price risk management liabilities (Note 4)		99.7			173.8
Income taxes payable		-			-
Future income tax liabilities		24.8			17.1
Dividends payable		16.2			42.9
Current portion of long-term debt		363.5			355.4
Current portion of long-term debt - non-recourse		51.9			-

		1,145.2		1,351.4

Long-term debt		2,270.0		2,351.2
Long-term debt - non-recourse		554.4			-
Deferred credits and other long-term liabilities		306.1			452.8
Future income tax liabilities		643.7			402.1
Price risk management liabilities (Note 4)		64.2			50.6
Non-controlling interests		446.6			263.0
Preferred securities		451.0			451.7
Common shareholders' equity
Common shares (Note 8)		1,540.1		1,226.2
Retained earnings		937.8			884.7
Cumulative translation adjustment		(26.1)			(18.8)

		2,451.8		2,092.1

Total liabilities and shareholders' equity	$	8,333.0	$	7,414.9


Contingencies and commitments (Notes 7 and 9)

See accompanying notes.

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

:P21

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 in nature 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 and accounting for non-derivatives used in trading activities.

Asset retirement obligations

Effective Jan. 1, 2003, TransAlta early adopted the new 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 effect of the adoption 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		9 months ended			12 months ended
	Sept. 30, 2002		Sept. 30, 2002		Dec. 31, 2002

Statements of earnings:
Site restoration accrual, included in fuel and purchased power	$	(9.5)	$	(28.6)	$	(38.0)
Depreciation and amortization expense		0.3		0.9		1.2
Depreciation and amortization expense, included in fuel and purchased power		(0.2)		(0.8)		(1.0)
Accretion expense, included in depreciation and amortization expense		5.7		17.1		22.8
Current income tax expense		1.3		4.0		5.3

Net earnings applicable to common shareholders	$	2.4	$	7.4	$	9.7

:P22

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		(22.6)
Accretion expense		17.3
Acquisition of CE Gen		5.2
Change in foreign exchange rates		(15.8)

Balance, Sept. 30, 2003	$	258.3

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 the first nine months of 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 Sept. 30				9 months ended Sept. 30
		2003		2002		2003		2002

				(Restated,				(Restated,
				Note 1)				Note 1)
Reported net earnings applicable to common shareholders	$	118.4	$	70.3	$	190.4	$	251.6
Compensation expense		0.6		1.0		1.9		2.7

Pro forma net earnings applicable to common shareholders	$	117.8	$	69.3	$	188.5	$	248.9


Reported basic earnings per share	$	0.62	$	0.42	$	1.04	$	1.48
Compensation expense per share		-		0.01		0.01		0.02

Pro forma basic earnings per share	$	0.62	$	0.41	$	1.03	$	1.46


Reported diluted earnings per share	$	0.62	$	0.42	$	1.04	$	1.48
Compensation expense per share		-		0.01		0.01		0.02

Pro forma diluted earnings per share	$	0.62	$	0.41	$	1.03	$	1.46


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.

:P23

2 . A C Q U I S I T I O N S A N D D I S P O S A L S - C O N T I N U I N G O P E R A T I O N S

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 July 31, 2003, TransAlta completed the sale of its 50 per cent interest in the two-unit, 756-megawatt (MW) coal-fired Sheerness Generating Station (Sheerness) 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. The warrants, when exercised, are exchangeable for one TransAlta Power unit at any time until Aug. 3, 2004. As a result of the unit issuance, TransAlta's ownership interest in TransAlta Power at Sept. 30, 2003 is approximately 25 per cent. 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 nil and increasing cash proceeds by $165.1 million assuming all the warrants are exercised.

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 (pre-tax) was taken into earnings. In addition, the management agreements between TransAlta and TransAlta Power and TA Cogen were amended to remove the mechanism for the deferral of the 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 removal of these terms, TransAlta received $1.0 million from TransAlta Power and $5.0 million from TA Cogen.

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 as operating lease.

:P24

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, of which $818.0 million was collected in the second quarter of 2002 and the remaining amount was collected in the fourth quarter of 2002.

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

Sept. 30, 2002	3 months ended		9 months 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		-		110.0

Earnings from discontinued operations	$	-	$	122.8

The gain of $110.0 million included a number of estimates. In the fourth quarter of 2002, the gain was adjusted without restatement to $120.0 million to reflect agreed working capital adjustments and actual amounts paid and received.

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 FASB EITF 02-03.

The following table illustrates movements in the fair value of the corporation's price risk management assets (liabilities) during the nine months ended Sept. 30, 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		12.6		-		12.6
Changes in values attributable to market price and other market changes		(1.1)		-		(1.1)
Contracts realized, amortized or settled during the period		9.5		(1.6)		7.9
Changes in values attributable to changes in valuation techniques and assumptions		-		-		-

Net price risk management assets outstanding at Sept. 30, 2003	$	13.5	$	-	$	13.5

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

												2008 and
		2003		2004		2005		2006		2007		thereafter		Total

Prices actively quoted	$	5.0	$	7.4	$	3.1	$	2.1	$	1.5	$	-	$	19.1
Prices based on models		(5.1)		(0.5)		-		-		-		-		(5.6)

	$	(0.1)	$	6.9	$	3.1	$	2.1	$	1.5	$	-	$	13.5

:P25

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

Balance Sheet	Sept. 30, 2003		Dec. 31, 2002


Price risk management assets
Current	$	105.5	$	157.8
Long-term		71.9		60.7
Price risk management liabilities
Current		(99.7)		(173.8)
Long-term		(64.2)		(50.6)

Net price risk management assets (liabilities) outstanding	$	13.5	$	(5.9)

The corporation's trading positions at Sept. 30, 2003 were as follows:

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

Electricity	MWh	16,602.2	16,295.8	36
Natural gas	GJ	44,952.7	33,154.0	27

The corporation's electrical transmission contracts trading position was 14.7 million megawatt hours (MWh) at Sept. 30, 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. The maximum term of the contracts outstanding at Sept. 30, 2003 was 15 months.

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.

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

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

8 . 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 Sept. 30, 2003, the corporation had 189.8 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).

:P26

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 the first nine months of 2003.

9 . 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 in which TransAlta's U.S. subsidiaries were named. These orders require 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 staff filed a Motion to Dismiss with respect to TransAlta in the two show cause proceedings. A number of parties have filed objections to the Motions to Dismiss TransAlta. 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.

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.

In December 2002, two class action lawsuits were initiated on behalf of all persons and businesses in the states of Oregon and Washington in respect of alleged unlawful practices in the purchase and sale of wholesale energy. Both class actions have been dismissed.

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 0 .. 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 office and consolidate all trading activities in Calgary. The decision is expected to increase operating efficiencies and reduce costs. The total amount of involuntary termination, which vested over three months, was $0.7 million. Of this amount, $0.4 million was recognized in the second quarter and $0.3 million was recognized in the third quarter. The amounts are included in operations, maintenance and administration expense for the Energy Marketing segment.

Costs of $0.8 million were incurred in the third 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 $0.3 million will be incurred in the fourth quarter related to these costs. The office is expected to be closed by Dec. 31, 2003.

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1 1 .. 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 2000.

1 2 .. 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 Windelectric Inc. (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 as earnings before interest, taxes and non-controlling interests (EBIT). EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP as an indicator of the corporation's performance or liquidity. TransAlta's EBIT is not necessarily comparable to a similarly titled measure of another company. EBIT can be determined from the consolidated statements of earnings by deducting earnings and gains on disposal of discontinued operations, other income (expense) and foreign exchange gains (losses) and adding net interest expense, income taxes and non-controlling interests to net earnings applicable to common shareholders.

I. Earnings information
							Unaudited

			Energy
3 months ended Sept. 30, 2003	Generation		Marketing		Corporate			Total

Revenues	$	613.6	$	16.4	$	-	$	630.0
Fuel and purchased power		(278.5)		-		-		(278.5)

Gross margin		335.1		16.4		-		351.5
Operations, maintenance and administration		134.8		4.7		13.7		153.2
Depreciation and amortization		85.7		0.8		2.6		89.1
Taxes, other than income taxes		5.8		-		-		5.8
Gain on sale of Sheerness Generating Station		(191.5)		-		-		(191.5)
Asset impairment charges (Note 6)		84.7		-		-		84.7

EBIT before corporate allocations		215.6		10.9		(16.3)		210.2
Corporate allocations		(14.5)		(1.8)		16.3		-

EBIT	$	201.1	$	9.1	$	-		210.2

Other expense								(2.2)
Foreign exchange gain								1.0
Net interest expense								(47.9)

Earnings from continuing operations before income taxes and non-controlling interests							$	161.1


							Unaudited

				Energy
3 months ended Sept. 30, 2002	Generation		Marketing		Corporate			Total

Revenues	$	431.8	$	18.5	$	-	$	450.3
Fuel and purchased power		(163.5)		-		-		(163.5)

Gross margin		268.3		18.5		-		286.8
Operations, maintenance and administration		76.9		5.0		16.5		98.4
Depreciation and amortization		54.2		0.6		4.3		59.1
Taxes, other than income taxes		5.9		0.1		-		6.0

EBIT before corporate allocations		131.3		12.8		(20.8)		123.3
Corporate allocations		(18.7)		(2.1)		20.8		-

EBIT	$	112.6	$	10.7	$	-		123.3

Other expense								(1.5)
Foreign exchange loss								(1.0)
Net interest expense								(20.9)

Earnings from continuing operations before income taxes and non-controlling interests							$	99.9

:P28


							Unaudited

			Energy
9 months ended Sept. 30, 2003	Generation		Marketing		Corporate			Total

Revenues	$	1,787.3	$	(0.1)	$	-	$	1,787.2
Fuel and purchased power		(784.3)		-		-		(784.3)

Gross margin		1,003.0		(0.1)		-		1,002.9
Operations, maintenance and administration		361.3		9.1		42.3		412.7
Depreciation and amortization		233.8		2.4		10.4		246.6
Taxes, other than income taxes		17.5		-		-		17.5
Gain on sale of Sheerness Generating Station		(191.5)		-		-		(191.5)
Asset impairment charges (Note 6)		84.7		-		-		84.7

EBIT before corporate allocations		497.2		(11.6)		(52.7)		432.9
Corporate allocations		(46.8)		(5.9)		52.7		-

EBIT	$	450.4	$	(17.5)	$	-		432.9

Other expense								(2.2)
Foreign exchange loss								(6.7)
Net interest expense								(132.2)

Earnings from continuing operations before income taxes and non-controlling interests							$	291.8


							Unaudited

				Energy
9 months ended Sept. 30, 2002	Generation		Marketing		Corporate			Total

Revenues	$	1,175.2	$	31.1	$	-	$	1,206.3
Fuel and purchased power		(447.3)		-		-		(447.3)

Gross margin		727.9		31.1		-		759.0
Operations, maintenance and administration		231.0		11.5		42.9		285.4
Depreciation and amortization		156.9		2.0		15.6		174.5
Taxes, other than income taxes		19.7		0.1		-		19.8
Prior period regulatory decisions		3.3		-		-		3.3

EBIT before corporate allocations		317.0		17.5		(58.5)		276.0
Corporate allocations		(52.5)		(6.0)		58.5		-

EBIT	$	264.5	$	11.5	$	-		276.0

Other expense								(0.9)
Foreign exchange gain								0.3
Net interest expense								(58.7)

Earnings from continuing operations before income taxes and non-controlling interests							$	216.7


II. Selected balance sheet information
				Energy
Sept. 30, 2003	Generation		Marketing		Corporate			Total

Goodwill		121.6		29.3		-	$	150.9
Total segment assets	$	7,650.4	$	236.7	$	445.9	$	8,330.0


Dec. 31, 2002

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

:P29

III. Selected cash flow information
			Energy				Discontinued
3 months ended Sept. 30, 2003	Generation		Marketing		Corporate		Operations			Total

Capital expenditures	$	96.9	$	0.1	$	2.1	$	-	$	99.1

3 months ended Sept. 30, 2002

Capital expenditures	$	179.0	$	0.4	$	2.8	$	-	$	182.2

9 months ended Sept. 30, 2003

Capital expenditures	$	498.3	$	0.7	$	6.0	$	-	$	505.0
Acquisitions	$	323.4	$	-	$	-	$	-	$	323.4

9 months ended Sept. 30, 2002

Capital expenditures	$	718.3	$	2.1	$	9.0	$	21.8	$	751.2

IV. Reconciliation
Depreciation and amortization expense (D&A) per statement of cash flows
				3 months ended Sept. 30				9 months ended Sept. 30
				2003		2002		2003		2002

D&A expense for reportable segments			$	89.1	$	59.1	$	246.6	$	174.5
Mining equipment depreciation, included in fuel and purchased power				10.7		9.0		31.4		29.5
Site restoration accretion, included in D&A expense				(5.2)		(5.7)		(17.3)		(17.1)
Discontinued operations				-		-		-		15.6
Other				6.2		3.8		10.5		4.0

			$	100.8	$	66.2	$	271.2	$	206.5



1 3 . 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.

:P30


S U P P L E M E N T A L I N F O R M A T I O N
(Annualized)		Sept. 30, 2003		Dec. 31, 2002

Closing market price		$	18.35	$		17.11
Price range (last 12 months)
	High	$	19.55	$	23.95
	Low	$	15.36	$	16.69
Debt/invested capital (including non recourse debt)			48.9%		50.4%
Debt/invested capital (excluding non recourse debt)			43.7%		50.4%
Return on common shareholders' equity			5.6%			3.9%
Return on invested capital			6.0%			4.2%
Book value per share		$	12.92	$	12.43
Cash dividends per share		$	1.00	$		1.00
Price/earnings ratio (times)			27.0			46.0
Dividend payout ratio			139.9%		212.3%
Interest coverage (times)			1.7			1.5
Interest coverage including preferred securities (times)			1.4			1.2
Dividend coverage (times)			4.2			2.5
Dividend yield			5.4%			4.6%



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).

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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

WEB SITE

www.cibcmellon.com

For more information:

Media inquiries:

Tim Richter,

Senior Media Relations Specialist

PHONE

403.267.7238

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