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 July, 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 July 24, 2003.
Exhibit 2	Quarterly report for the three-month period ended June 30, 2003, which includes Management's Discussion and Analysis and consolidated financials statements.
Exhibit 3	Signatures
Exhibit 4	Certifications

TransAlta achieves solid second quarter results

CALGARY, Alberta (July 24, 2003) - TransAlta Corporation (TSX: TA; NYSE: TAC) today announced second quarter 2003 earnings from continuing operations of $23.3 million ($0.12 per common share), compared to $15.7 million ($0.09 per share) for the same period in 2002. Net earnings of $127.3 million ($0.75 per share) in second quarter 2002 included the gain on sale from the Transmission operation ($0.65 per share), sold in April 2002.

Financial results reflect strong plant operating performance, higher electricity spot prices and the addition of several new power plants, offset by a loss from energy marketing activities.

"We had another strong operational quarter with good performance from our new plants," said Steve Snyder, TransAlta's president and CEO. "In addition, our acquisition of U.S.-based CE Generation is achieving all of our targets."

Revenue for the second quarter increased by $204.7 million over the same period in 2002, reflecting the acquisition of CE Generation, increased production, improved availability and higher electricity spot prices, partially offset by the US$24.0 million (Cdn$33.3 million) loss related to an error in Energy Marketing announced on June 3, 2003. Second quarter 2002 revenues were net of the $38.9 million Wabamun arbitration decision. Plant availability was 88.7 per cent, up from 83.4 per cent in second quarter 2002, mainly as a result of the Centralia plant. Production was up 18 per cent, or 1,967 gigawatt-hours (GWh), to 12,658 GWh, due to improved availability and incremental production from new power plants exceeding reductions resulting from the shutdown of Wabamun unit three.

Cash from operating activities was $274.0 million, compared to $133.4 million in second quarter 2002. This increase was mainly due to improved operating results and reduced working capital.

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

TransAlta consolidated financial highlights

- more -

In second quarter 2003, TransAlta:

Began commercial operation of the 252-megawatt (MW) combined-cycle gas- and diesel-fueled Campeche power plant located in the Mexican state of Campeche in the Yucatan Peninsula on May 29, 2003.
Began commercial operation of the 114-wind turbine, 75-MW wind-fired McBride Lake Wind Farm located near Fort Macleod, Alberta on June 21, 2003. McBride is a joint venture of TransAlta subsidiary Vision Quest Windelectric Inc. and ENMAX Corporation.
Sold its head office building in Calgary, Alberta to Forum Leasehold Partners Inc. for $66 million. TransAlta has leased back the property for a term of 20 years.
Issued additional equity pursuant to the underwriters for the TransAlta equity offering that closed on March 21, 2003 exercising their over-allotment option to acquire an additional 2.25 million common shares at the offering price of $16.00 per share. As a result of the option being exercised, a total of 17.25 million common shares were issued for total gross proceeds of $276 million.
Announced its intention to sell 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. TransAlta expects to realize net proceeds of $315.0 million from the sale, resulting in a gain on sale of $55 million after tax. The transaction is expected to close on July 31, 2003.

Subsequent to the second quarter, TransAlta:

Renewed and increased its committed corporate credit facility to $1.5 billion. The increased size of the new facility provides TransAlta with more flexibility to manage its credit and liquidity requirements and maintain a strong financial position.
Decided to consolidate its trading functions in Calgary in order to increase operating efficiency and decrease costs. As a result of the decision, its Annapolis, Maryland trading office will be closed by Dec. 31, 2003.

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:

Nadine Walz

Daniel J. Pigeon

Senior Media Relations Specialist

Director, Investor Relations

Phone: (403) 267-3655

Phone: 1-800-387-3598 in Canada and U.S.

Pager: (403) 213-7041

Phone: (403) 267-2520 Fax (403) 267-2590

Email: media_relations@transalta.com

E-mail: investor_relations@transalta.com

Exhibits

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Q2:2003

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 six months ended June 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 policies 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 their operating results measured as earnings 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:

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			Unaudited				Unaudited
		3 months ended June 30				6 months ended June 30
		2003		2002¹		2003		2002¹

EBIT	$	90.8	$	53.4	$	222.7	$	152.7
Other income		0.2		2.7		-		0.6
Foreign exchange gain (loss)		(0.2)		0.7		(7.7)		1.3
Net interest expense		(49.6)		(18.6)		(84.3)		(37.8)

Earnings from continuing operations before income taxes
and non-controlling interests		41.2		38.2		130.7		116.8
Income tax expense		7.0		12.8		34.8		36.7
Non-controlling interests		5.1		4.5		12.6		10.9

Earnings from continuing operations		29.1		20.9		83.3		69.2
Earnings from discontinued operations		-		1.6		-		12.8
Gain on disposal of discontinued operations		-		110.0		-		110.0

Net earnings		29.1		132.5		83.3		192.0
Preferred securities distributions, net of tax		5.8		5.2		11.3		10.7

Net earnings applicable to common shareholders	$	23.3	$	127.3	$	72.0	$	181.3

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 June 30				2003				2002⁾⁵

Availability				88.7%				83.4%
Production (GWh)				12,658				10,691
Electricity trading volumes (GWh)¹				21,131				20,699
Gas trading volumes (million GJ)				41.5				32.7


			Per common				Per common
		Amount		share		Amount		share

Revenues²	$	541.0			$	336.3

Net earnings from continuing operations³	$	23.3	$	0.12	$	15.7	$	0.09
Earnings from discontinued operations⁴		-		-		1.6		0.01
Gain on disposal of discontinued operations, net of tax⁴		-		-		110.0		0.65

Net earnings applicable to common shareholders	$	23.3	$	0.12	$	127.3	$	0.75


Cash flow from operating activities	$	274.0			$	133.4



6 months ended June 30				2003				2002⁾⁵

Availability				91.0%				88.0%
Production (GWh)				25,662				22,888
Electricity trading volumes (GWh)¹				44,419				37,035
Gas trading volumes (million GJ)				94.4				82.7

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			Per common				Per common
		Amount	share			Amount	share

Revenues²	$	1,157.2			$	756.0

Net earnings from continuing operations³	$	72.0	$	0.40	$	58.5	$	0.34
Earnings from discontinued operations⁴		-		-		12.8		0.07
Gain on disposal of discontinued operations, net of tax⁴		-		-		110.0		0.65

Net earnings applicable to common shareholders	$	72.0	$	0.40	$	181.3	$	1.06


Cash flow from operating activities	$	444.1			$	262.4

1	2002 electricity trading volumes have been restated to conform with current reporting practices and standards.
2	From continuing operations. In accordance with changes to U.S. and Canadian GAAP, revenues from energy trading activities are now presented on a net basis. Prior period amounts have been reclassified to reflect this change.
3	Continuing operations include the Generation and Energy Marketing segments plus corporate costs not directly attributable to discontinued operations, and are net of preferred securities distributions.
4	Discontinued operations include the Transmission operation which was sold on April 29, 2002.
5	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.

Net earnings from continuing operations for the three and six months ended June 30, 2003 compared to the same periods in 2002 reflect improved availability and production from Centralia, the acquisition of CE Generation LLC (CE Gen) as well as higher electricity spot prices, partially offset by energy marketing activities.

Cash flow from operating activities for the three months ended June 30, 2003 was $274.0 million compared to $133.4 million in the second quarter of 2002. The increase is primarily due to higher earnings as well as the collection of commodity tax receivables in the U.S. and Mexico (US$79.0 million). For the six months ended June 30, 2003, cash flow from operating activities was $444.1 million compared to $262.4 million for the first half of 2002. The increase is primarily due to collection of the commodity tax receivables discussed above as well as the final instalment of 2001 income taxes paid in the first quarter of 2002 ($109.0 million), partially offset by the collection of the Transmission receivables ($32.0 million) retained by the corporation on its disposition in 2002.

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

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

Sale of Sheerness Generating Station

On June 16, 2003, TransAlta announced the intention to sell its 50 per cent interest in the two-unit, 756-megawatt (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. (TransAlta Power). TransAlta expects to realize net proceeds of $315.0 million from the sale, resulting in a gain on sale of approximately $55 million after-tax, subject to the exercise of the warrants discussed below. The transaction is expected to close on July 31, 2003.

Concurrent with the sale, TransAlta Power will issue 17.75 million units to the public, each with one warrant attached, for gross proceeds of $165.1 million, and 17.75 million units to TransAlta for gross proceeds of $165.1 million. The warrants are exercisable for one unit at any time until 12 months after the closing of the sale. Depending on the timing of the warrant exercise, the gain may vary.

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

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purchasing more contracts at higher prices than intended. The erroneous bid resulted in a $33.3 million (US$24.0 million) pre-tax loss in May 2003, which was taxed at the statutory rate of 40 per cent.

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.

Purchase of 50 per cent interest in CE Generation LLC

In the first quarter of 2003, the corporation purchased a 50 per cent interest in CE Gen. Refer to Note 2 of the unaudited interim consolidated financial statements for further discussion. TransAlta's share of CE Gen's results for the period of ownership from Jan. 29, 2003 to June 30, 2003 is included in the Generation segment.

Purchase of 50 per cent interest in Genesee 3

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.

Gain on disposal of discontinued operations

In April 2002, TransAlta's Transmission operation was sold for proceeds of $820.7 million. At June 30, 2002, the disposal resulted in an after-tax gain on sale of $110.0 million ($0.65 per common share). In the fourth quarter of 2002, the gain was adjusted to $120.0 million ($0.71 per common share) to reflect agreed working capital adjustments and actual amounts paid and received.

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 (CICA) 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 half of 2003.

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 June 30, 2003, Generation had 8,586 MW of gross generating capacity in operation (8,252 MW net ownership interest) and 484 MW under construction.

As previously discussed, TransAlta 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). TransAlta's Sarnia plant was commissioned in March 2003, resulting in 440 MW of generating capacity in addition to the existing 135 MW. On May 27, 2003 TransAlta

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commissioned the 252 MW Campeche, Mexico plant. Also 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 Windelectric Inc. (Vision Quest).

Availability for the three and six months ending June 30, 2003 was 88.7 per cent and 91.0 per cent, respectively, compared to 83.4 per cent and 88.0 per cent in the comparable periods of 2002. The increase is primarily a result of lower planned maintenance at the Centralia plant in 2003 partially offset by increased planned maintenance at the Alberta thermal plants.

The results of the Generation segment are as follows:
			2003					2002
3 months ended June 30		Total	Per MWh			Total		Per MWh

Revenues	$	568.2	$	44.89	$	322.6	$	30.17
Fuel and purchased power		(239.7)		(18.94)		(115.9)		(10.84)

Gross margin		328.5		25.95		206.7		19.33
Operating expenses:
Operations, maintenance and administration		108.4		8.56		82.5		7.72
Depreciation and amortization		78.8		6.22		50.8		4.75
Taxes, other than income taxes		5.6		0.45		6.8		0.63
Prior period regulatory decision		-		-		3.3		0.31

EBIT before corporate allocations		135.7		10.72		63.3		5.92
Corporate allocations		(12.9)		(1.02)		(17.2)		(1.61)

EBIT	$	122.8	$	9.70	$	46.1	$	4.31


				2003				2002
6 months ended June 30		Total	Per MWh			Total		Per MWh

Revenues	$	1,173.7	$	45.74	$	743.4	$	32.48
Fuel and purchased power		(505.8)		(19.71)		(283.8)		(12.40)

Gross margin		667.9		26.03		459.6		20.08
Operating expenses:
Operations, maintenance and administration		226.5		8.83		154.1		6.73
Depreciation and amortization		148.1		5.77		102.7		4.49
Taxes, other than income taxes		11.7		0.46		13.8		0.60
Prior period regulatory decision		-		-		3.3		0.14

EBIT before corporate allocations		281.6		10.97		185.7		8.12
Corporate allocations		(32.3)		(1.26)		(33.8)		(1.48)

EBIT	$	249.3	$	9.71	$	151.9	$	6.64

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: during the summer months, warmer temperatures result in less efficient fuel conversion rates (higher heat rates), and increased hydro production from spring run-off results in lower electricity prices. 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 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.

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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 a contract for production between 10 and 25 years. Long-term contracts are typically for gas-fueled co-generation 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 the third quarter of 2003. All three facilities have gas supply contracts in place for the duration of the electricity sales contracts.

Fuel &

Purchased

Gross

3 months ended

Production

Purchased

Gross

Revenue

Power

Margin

June 30, 2003

(GWh)

Revenue

Power

Margin

per MWh

Alberta PPAs

7,020

179.8

46.6

133.2

25.61

6.64

18.97

Long-term contracts

1,846

146.5

86.8

59.7

79.36

47.02

32.34

Merchant

2,951

152.6

82.6

70.0

51.71

27.99

23.72

CE Gen

841

89.3

23.7

65.6

106.18

28.18

78.00

TOTAL

12,658

568.2

239.7

328.5

44.89

18.94

25.95

Fuel &

Purchased

Gross

3 months ended

Production

Purchased

Gross

Revenue

Power

Margin

June 30, 2002

(GWh)

Revenue

Power

Margin

per MWh

Alberta PPAs	7,404	$	191.9	$	32.0	$	159.9	$	25.92	$	4.32	$	21.60
Long-term contracts	1,405		82.3		33.1		49.2		58.58		23.56		35.02
Merchant	1,882		87.3		50.8		36.5		46.39		26.99		19.40
Wabamun arbitration
decision	-		(38.9)		-		(38.9)		-		-		-

TOTAL	10,691	$	322.6	$	115.9	$	206.7	$	30.17	$	10.84	$	19.33

Fuel &

Purchased

Gross

6 months ended

Production

Purchased

Gross

Revenue

Power

Margin

June 30, 2003

(GWh)

Revenue

Power

Margin

per MWh

Alberta PPAs

13,924

362.7

92.6

270.1

26.05

6.65

19.40

Long-term contracts

3,561

295.1

184.3

110.8

82.87

51.76

31.11

Merchant

6,840

369.6

189.1

180.5

54.04

27.65

26.39

CE Gen

1,337

146.3

39.8

106.5

109.42

29.77

79.65

TOTAL

25,662

1,173.7

505.8

667.9

45.74

19.71

26.03

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											Fuel &
					Fuel &						Purchased		Gross
6 months ended	Production				Purchased		Gross		Revenue		Power		Margin
June 30, 2002	(GWh)		Revenue		Power		Margin		per MWh		per MWh		per MWh


Alberta PPAs	14,564	$	376.2	$	72.3	$	303.9	$	25.83	$	4.96	$	20.87
Long-term contracts	2,891		164.3		66.4		97.9		56.83		22.97		33.86
Merchant	5,433		241.8		145.1		96.7		44.51		26.71		17.80
Wabamun
arbitration decision	-		(38.9)		-		(38.9)		-		-		-

TOTAL	22,888	$	743.4	$	283.8	$	459.6	$	32.48	$	12.40	$	20.08

Alberta PPAs

In the three and six months ended June 30, 2003, production from Alberta PPA plants decreased by 384 gigawatt hours (GWh) and 640 GWh, respectively, compared to the same periods in 2002. The decrease is a result of the increased planned maintenance outages in 2003 as well as the decommissioning of unit three of the Wabamun plant in November 2002.

For the three months ended June 30, 2003 revenues of $25.61 per megawatt hour (MWh) were consistent with $25.92 per MWh in the second quarter of 2002, which excludes the impact of the Wabamun arbitration decision. Fuel and purchased power for the second quarter increased to $6.64 per MWh from $4.32 per MWh in the second quarter of 2002 primarily as a result of increased natural gas prices as well as increased power costs and planned maintenance costs at the coal mines in 2003.

For the six months ended June 30, 2003, revenues increased to $26.05 per MWh from $25.83 per MWh in 2002. The increase is due to the net effect of contractual escalation in the PPAs. Fuel and purchased power increased to $6.65 per MWh from $4.96 per MWh for the reasons discussed above.

Long-term contracts

Production increased by 441 GWh for the second quarter of 2003 and by 670 GWh for the six months ended June 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 in December 2002 and the completion of the Campeche plant in May 2003.

Revenues increased by $20.78 per MWh and $26.04 per MWh in the three and six months ended June 30, 2003, respectively. The increase is due in part to $21.2 million and $54.8 million of incremental steam revenues earned from the Sarnia plant in the three and six months ended June 30, 2003, respectively. Steam revenue has no MWh production volumes associated with it. Revenues also increased as a result of increased natural gas prices. Fuel and purchased power increased by $23.46 per MWh and $28.79 per MWh in the three and six months ended June 30, 2003. The increase is primarily a result of higher natural gas market prices and the cost of the gas used for steam production. At certain plants, increased natural gas prices flow through to customers and are therefore recovered through increased revenues.

Merchant production

In the second quarter of 2003, merchant production was 2,951 GWh, of which 1,328 GWh was contracted. In the second quarter of 2002, merchant production was 1,882 GWh, of which 1,024 GWh was contracted. The increase in production is due to increased availability and production from the Centralia and Big Hanaford plants, offset by lower excess production at the Alberta thermal plants due to lower availability. For the six months ended June 30, 2003, merchant production was 6,840 GWh, of which 3,878 GWh was contracted. In the first half of 2002, merchant production was 5,433 GWh, of which 3,329 GWh was contracted. The increases are the result of the reasons discussed above.

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As shown in the above graphs, electricity spot prices in the Alberta and Pacific Northwest markets increased for both the three and six months ended June 30, 2003 compared to the same periods 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, therefore comparative data is not meaningful. Spark spreads (power price less cost of gas consumed) in Alberta decreased significantly in the second quarter of 2003 compared to the same period in 2002, as gas prices increased significantly. Spark spreads remained constant and depressed in the Pacific Northwest. Ontario spark spreads were generally depressed during the first half of 2003. 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 and six months ended June 30, 2003, merchant revenues increased by $5.32 per MWh and $9.53 per MWh compared to the same periods in 2002. The increases are the result of higher electricity spot prices and higher hydro ancillary services prices, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. Fuel and purchased power increased $1.00 per MWh and $0.94 per MWh for the three and six months ended June 30, 2003, respectively. The increase reflects increased natural gas prices and a change in the fuel mix for the quarter. Merchant production at Alberta thermal plants decreased while merchant production at Centralia increased.

CE Gen

In the second quarter of 2003, CE Gen produced 841 GWh of electricity. Revenue was $106.18 per MWh and fuel and purchased power was $28.18 per MWh. From Jan. 29, 2003 to June 30, 2003, revenue was $109.42 per MWh and fuel and purchased power was $29.77 per MWh. The decrease in revenue and fuel and purchased power is primarily due to the strengthening of the Canadian dollar versus the U.S. dollar.

Operations, maintenance and administration expense

In the second quarter of 2003, operations, maintenance and administration (OM&A) expenses increased by $25.9 million ($0.84 per MWh) over the same period in 2002. Excluding the impact of the CE Gen acquisition, OM&A costs increased by $12.3 million ($0.30 per MWh). The increase reflects the incremental impact of the Sarnia and Campeche plants, as well as the effect of increased planned long-term maintenance at the Alberta thermal plants. These increases were partially offset by the adjustment of a pension over-accrual and a decrease in expected performance share ownership plan payouts due to market conditions. In 2002, the majority of the Centralia maintenance costs were capitalized. The execution of the corporation's long-term maintenance strategy focuses on performing specific planned maintenance that generally involves higher capital and operating expenditures rather than less expensive short-term repairs. OM&A costs for CE Gen were $13.6 million ($16.17 per MWh) in the second quarter of 2003 and $33.4 million ($24.98 per MWh) for the first half 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 is due to the seasonality of maintenance activities.

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For the first half of 2003, OM&A increased by $72.4 million ($2.10 per MWh) compared to the same period in 2002, primarily due to the CE Gen acquisition, the commencement of commercial operations of the Sarnia and Campeche plants and increased planned long-term maintenance, primarily at the Alberta thermal plants.

Depreciation and amortization

Depreciation and amortization increased by $28.0 million ($1.47 per MWh) in the second quarter of 2003 and $45.4 million ($1.28 per MWh) for the first six months of 2003 compared to the same periods in 2002. In the second quarter, $20.8 million of the increase is the result of the CE Gen acquisition. In the six months ending June 30, 2003, $37.7 million of the increase is the result of the CE Gen acquisition. The remaining increase is due to incremental depreciation from the Big Hanaford, Sarnia, Vision Quest and Campeche plants, partially offset by the decommissioning of Wabamun unit three in 2002.

Taxes other than income taxes

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

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

Energy Marketing operates on behalf of Generation to sell electricity produced, purchase natural gas not covered by long-term contracts, establish long-term contracts for the sale of electricity and the purchase of natural gas, and purchase and sell transmission capacity to transmit electricity. The results of these arrangements and the costs to execute them are included in Generation's segmented results.

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

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

The results of Energy Marketing are as follows:

		3 months ended June 30				6 months ended June 30
		2003		2002		2003		2002

Net trading revenues (losses)	$	(27.2)	$	13.7	$	(16.5)	$	12.6
Operations, maintenance and administration		2.3		3.9		4.4		6.5
Depreciation and amortization		0.8		0.7		1.6		1.4

EBIT before corporate allocations		(30.3)		9.1		(22.5)		4.7
Corporate allocations		(1.7)		(1.8)		(4.1)		(3.9)

EBIT	$	(32.0)	$	7.3	$	(26.6)	$	0.8

Net trading revenues decreased by $40.9 million for the second quarter of 2003 and $29.1 million for the first half of 2003 compared to the same periods in 2002. During the second quarter, Energy Marketing realized a $33.3 million (US$24.0 million) pre-tax loss on TCCs in the New York area. The loss was due to an erroneous bid made for May TCCs. The bid resulted in TransAlta being awarded more TCCs for May than the corporation intended to acquire and at prices that did not match the intended bids. Other trading activities generated net revenue of $6.1 million, comprised of $8.4 million of trading gains partially offset by a $2.3 million adjustment to conform with FASB Emerging Issues Task Force (EITF) 02-03.

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After an extensive review of trading operations, TransAlta made the decision to consolidate its trading functions in Calgary in order to increase operating efficiency and decrease costs. As a result of this decision, the Annapolis trading office will be closed. Energy Marketing has $29.3 million of goodwill originating from the purchase of the Annapolis operations in 2000 and 2001. The Annapolis operations were acquired as a building block to support North American generation growth plans and gain insight into the eastern market. TransAlta will continue to participate in energy marketing activities in North America and as a result no goodwill impairment was considered necessary due to the consolidation of trading activities.

OM&A costs for the second quarter of 2003 include $0.4 million of severance costs incurred as a result of the closure of the Annapolis office. A further $1.4 million of severance and closure costs will be recorded over the remainder of 2003 as they are incurred. OM&A for the first half of 2003 was consistent with the first six months of 2002.

For the three and six months ended June 30, 2003, depreciation and amortization expense was consistent with the same periods in 2002.

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

	3 months ended June 30		6 months ended June 30
Electricity (GWh)	2003	2002	2003	2002

Physical	13,467	13,290	27,494	25,079
Financial	7,664	7,409	16,925	11,956

	21,131	20,699	44,419	37,035



	3 months ended June 30		6 months ended June 30
Gas (million GJ)	2003	2002	2003	2002

Physical	19.8	29.2	49.3	44.7
Financial	21.7	3.5	45.1	38.0

	41.5	32.7	94.4	82.7

Electricity volumes in the second quarter of 2003 were consistent with the same period in 2002. The increase in electricity volumes in the six months ended June 30, 2003 relates mainly to higher activity in the eastern North American markets. The increase in gas volumes relates to increased use of heat rate contracts, which involve a gas component, in western North America, partially offset by lower activity in proprietary gas trading. These volumes are generally consistent with activity in the second half of 2002. 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 mark-to-market basis. With the exception of transmission contracts, the fair value of all energy trading activities is based on quoted market prices. The fair value of financial transmission contracts is based upon statistical analysis of historical data. All transmission contracts are accounted for in accordance with FASB EITF 02-03.

The following table illustrates movements in the values of the corporation's price risk management assets (liabilities) during the six months ended June 30, 2003:

	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		6.5		9.0		15.5
Changes in values attributable to market price and other market changes		(20.6)		-		(20.6)
Contracts realized, amortized or settled during the period		26.6		(5.0)		21.6
Changes in values attributable to changes in valuation techniques and assumptions		-		-		-

Net price risk management assets outstanding at June 30, 2003	$	5.0	$	5.6	$	10.6

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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	$	2.0	$	4.2	$	3.1	$	2.1	$	1.5	$	-	$	12.9
Prices based on
models		(7.9)		-		-		-		-		-		(7.9)

	$	(5.9)	$	4.2	$	3.1	$	2.1	$	1.5	$	-	$	5.0
Electrical transmission
rights (accrual)		3.5		2.1		-		-		-		-		5.6

	$	(2.4)	$	6.3	$	3.1	$	2.1	$	1.5	$	-	$	10.6

The carrying and fair value of price risk management assets and liabilities included on the balance sheet are as follows:

					June 30,		Dec. 31,
					2003		2002

Price risk management assets
Current				$	159.1	$	157.8
Long-term					44.0		60.7
Price risk management liabilities
Current					(156.4)		(173.8)
Long-term					(36.1)		(50.6)

				$	10.6	$	(5.9)


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

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

Electricity	MWh	25,784.9	25,912.7				39
Natural gas	GJ	67,034.0	69,545.1				30

The corporation's electrical transmission contracts trading position was 27.3 million MWh at June 30, 2003 compared to 18.1 million MWh at Dec. 31, 2002. The increase relates to the timing of the transactions, as the majority are entered into in the first quarter each year.

In 2000, TransAlta made a provision of US$28.8 million against US$58.0 million receivable from the California Independent System Operator and the California Power Exchange. During 2001, US$5.0 million was collected. No change has been made to the provision due to the continuing uncertainty in California. The net amount is reported as a long-term receivable, as collection is not expected in 2003, although ultimate collection of the net receivable is expected.

In March 2003, the Federal Energy Regulatory Commission (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. 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 is responding to these FERC show cause orders and requests for information. It remains unclear what refunds or payments, if any, TransAlta may be required to make pursuant to these orders and therefore the corporation has not adjusted the amount receivable or the provision.

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N E T I N T E R E S T E X P E N S E , O T H E R E X P E N S E , F O R E I G N E X C H A N G E ,

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

		3 months ended June 30				6 months ended June 30
		2003		2002		2003		2002

Gross interest expense	$	61.7	$	43.5	$	119.0	$	81.4
Interest income		(0.8)		(2.6)		(2.5)		(6.0)
Interest allocated to discontinued operations		-		(0.7)		-		(2.4)
Capitalized interest		(11.3)		(21.6)		(32.2)		(35.2)

Net interest expense		49.6		18.6		84.3		37.8
Other income		(0.2)		(2.7)		-		(0.6)
Foreign exchange loss (gain)		0.2		(0.7)		7.7		(1.3)
Non-controlling interests		5.1		4.5		12.6		10.9
Preferred securities distributions, net of tax		5.8		5.2		11.3		10.7

	$	60.5	$	24.9	$	115.9	$	57.5

Net interest expense increased by $31.0 million and by $46.5 million in the three and six months ended June 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, increased debt levels relating to the Genesee 3 acquisition and lower capitalized interest. The decrease in capitalized interest from 2002 is a result of the completion of the Big Hanaford, Campeche and Sarnia plants. Capitalized interest of $11.3 million in the second quarter of 2003, represents interest incurred relating to the Chihuahua, Genesee 3 and McBride Lake projects, as well as the Campeche project prior to completion.

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

The increase in earnings attributable to non-controlling interests in the three and six months ended June 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, offset by decreased earnings relating to the 49.99 per cent non-controlling interest in TransAlta Cogeneration, L.P.

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

I N C O M E T A X E S

For the three and six months ended June 30, 2003, income tax expense decreased by $5.8 million and $1.9 million, respectively, compared to the same periods in 2002. The decrease is due to higher earnings in lower tax rate jurisdictions and the Energy Marketing TCC loss being recognized at the marginal rate (40 per cent). The effective income tax rate, expressed as a percentage of earnings from continuing operations before income taxes and non-controlling interests, is lower than in 2002 as a result of the above reasons. In 2003, the annualized tax rate is now expected to be 26 to 30 per cent as a result of the TCC loss, earnings mix, the sale of the Sheerness plant and the effect of international financing structures.

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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 $1.6 million and $12.8 million in the three and six months ended June 30, 2002. At June 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. 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.

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

On May 29, 2003, Standard and Poor's downgraded TransAlta's credit rating to BBB- (stable) and removed the corporation from credit watch. The downgrade did not trigger early repayment under any of the corporation's debt agreements; however it resulted in decreased credit limits granted by TransAlta's trading counterparties thereby requiring the corporation to increase collateral by approximately $17 million. The corporation increased its committed bank credit facility to $1.5 billion in July 2003 and maintained the $500.0 million of uncommitted credit facilities. TransAlta has a credit rating of Baa1 and BBB high by Moody's and Dominion Bond Rating Service, respectively. These ratings are currently under review.

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.

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.

At June 30, 2003, TransAlta's total debt (including non-recourse debt) to invested capital ratio was 52.0 per cent (46.9 per cent excluding non-recourse debt). This represents an increase from the Dec. 31, 2002 ratio of 50.4 per cent as a result of increased debt levels resulting from the CE Gen acquisition and the Genesee 3 project, partially offset by the equity offering completed in March 2003 and the sale of the office building and the Goldfields gas pipeline.

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 will increase during the remainder of 2003 due to the completion of the 259 MW Chihuahua plant in Mexico that is scheduled to commence commercial operations in August 2003. This will be partially offset by the sale of the 50 per cent interest in the Sheerness plant, discussed previously. Availability for the remainder of 2003 is expected to be slightly higher than the first half of 2003 due to lower planned maintenance. Production is expected to increase throughout the remainder of the year due to the increased capacity and availability.

Power prices

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

Exposure to volatility in electricity prices is substantially mitigated through firm-price, long-term electricity sales contracts. Exposure to volatility in gas prices is substantially mitigated by the flow-through of the costs of natural gas to customers in some of these contracts and the existence of price caps in certain natural gas supply contracts. For 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 agreed availability rates. The corporation will continue to focus on the maximization of revenues from these contracts.

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Costs of production

OM&A costs per MWh fluctuate by quarter and are dependent on the timing of maintenance activities. Excluding CE Gen, OM&A per MWh is expected to be consistent with that experienced in 2002 on an annual basis. CE Gen OM&A per MWh for the remainder of the year is expected to be consistent with the first half 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 (VAR) and volatility related to fair value accounting is relatively low.

The costs of consolidating trading operations in Calgary will be offset by cost savings in the remainder of the year.

Capital expenditures

Capital expenditures for 2003 are expected to be approximately $700 million, excluding the acquisition of CE Gen. This is $130 million lower than previously forecasted for the year due to cost reduction activities and the cancellation or deferral of projects.

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

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

(in millions of Canadian dollars except per share amounts)


		Unaudited				Unaudited
		3 months ended June 30				6 months ended June 30
		2003		2002		2003		2002

				(Restated,				(Restated,
				Note 1)				Note 1)
Revenues	$	541.0	$	336.3	$	1,157.2	$	756.0
Fuel and purchased power		(239.7)		(115.9)		(505.8)		(283.8)

Gross margin		301.3		220.4		651.4		472.2

Operating expenses
Operations, maintenance and administration		121.8		99.6		259.5		187.0
Depreciation and amortization		83.1		57.3		157.5		115.4
Taxes, other than income taxes		5.6		6.8		11.7		13.8

		210.5		163.7		428.7		316.2

Operating income		90.8		56.7		222.7		156.0
Other income		0.2		2.7		-		0.6
Foreign exchange gain (loss)		(0.2)		0.7		(7.7)		1.3
Net interest expense		(49.6)		(18.6)		(84.3)		(37.8)

Earnings from continuing operations before regulatory
decisions, income taxes and non-controlling interests		41.2		41.5		130.7		120.1
Prior period regulatory decisions (Note 10)		-		(3.3)		-		(3.3)

Earnings from continuing operations before income taxes
and non-controlling interests		41.2		38.2		130.7		116.8
Income tax expense		7.0		12.8		34.8		36.7
Non-controlling interests		5.1		4.5		12.6		10.9

Earnings from continuing operations		29.1		20.9		83.3		69.2
Earnings from discontinued operations (Note 3)		-		1.6		-		12.8
Gain on disposal of discontinued operations (Note 3)		-		110.0		-		110.0

Net earnings		29.1		132.5		83.3		192.0
Preferred securities distributions, net of tax		5.8		5.2		11.3		10.7

Net earnings applicable to common shareholders	$	23.3	$	127.3	$	72.0	$	181.3

Common share dividends		(47.3)		(42.4)		(89.9)		(84.6)
Adjustment arising from normal course issuer bid		-		(18.4)		-		(22.9)
Retained earnings
Opening balance		890.8		881.1		884.7		838.3

Closing balance	$	866.8	$	947.6	$	866.8	$	912.1


Weighted average common shares outstanding in the period		188.3		169.2		180.4		169.7


Basic earnings per share
Continuing operations	$	0.12	$	0.09	$	0.40	$	0.34
Earnings from discontinued operations		-		0.01		-		0.07

Net earnings from operations		0.12		0.10		0.40		0.41
Gain on disposal of discontinued operations, net of tax		-		0.65		-		0.65

Net earnings	$	0.12	$	0.75	$	0.40	$	1.06


Diluted earnings per share
Earnings from continuing operations	$	0.12	$	0.08	$	0.40	$	0.33
Earnings from discontinued operations		-		0.01		-		0.07

Net earnings from operations		0.12		0.09		0.40		0.40
Gain on disposal of discontinued operations, net of tax		-		0.65		-		0.65

Net earnings	$	0.12	$	0.74	$	0.40	$	1.05


See accompanying notes.

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

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

(in millions of Canadian dollars)


		Unaudited				Unaudited
		3 months ended June 30				6 months ended June 30
		2003		2002		2003		2002

				(Restated,				(Restated,
				Note 1)				Note 1)
Operating activities
Net earnings	$	29.1	$	132.5	$	83.3	$	192.0
Depreciation and amortization		89.5		65.2		170.4		140.3
Loss (gain) on sale of assets		0.1		0.2		(0.4)		3.0
Future income taxes		(6.1)		14.7		1.8		17.8
Non-controlling interests		5.1		4.5		12.6		10.9
Site restoration costs incurred		(2.0)		(1.4)		(3.5)		(3.1)
Site restoration accretion		6.9		5.7		12.1		11.4
Unrealized loss (gain) from energy marketing activities		18.6		(1.8)		20.6		29.6
Foreign exchange loss (gain)		0.2		(0.7)		7.7		(1.3)
Gain on disposal of Transmission operation		-		(110.0)		-		(110.0)
Other non-cash items		0.1		9.9		1.5		2.1

		141.5		118.8		306.1		292.7
Change in non-cash operating working capital balances		132.5		14.6		138.0		(30.3)

Cash flow from operating activities		274.0		133.4		444.1		262.4

Investing activities
Additions to property, plant and equipment		(113.0)		(299.7)		(405.9)		(569.0)
Acquisitions (Note 2)		-		-		(323.4)		-
Proceeds on sale of discontinued operations (Note 3)		-		818.0		-		818.0
Proceeds on sale of long-term investments		21.6		-		21.6		-
Proceeds on sale of property, plant and equipment		65.8		-		65.8		-
Long-term receivables		0.3		30.4		0.7		34.7
Acquisition of long-term investments		-		(2.7)		-		(5.6)
Recovery of restricted cash (Note 2)		47.4		-		47.4		-
Deferred charges and other		(2.1)		(1.2)		(0.8)		(6.0)

Cash flow from (used in) investing activities		20.0		544.8		(594.6)		272.1

Financing activities
Net increase (decrease) in short-term debt		(83.0)		(752.4)		20.0		(537.8)
Issuance of long-term debt		16.0		489.5		149.1		520.4
Repayment of long-term debt		(119.4)		(301.6)		(120.5)		(302.8)
Dividends on common shares		(28.3)		(29.5)		(58.4)		(57.7)
Net proceeds on issuance of common shares (Note 7)		33.0		0.7		265.0		1.6
Redemption of common shares		-		(19.4)		-		(33.4)
Distributions on preferred securities		(8.7)		(8.4)		(17.6)		(17.6)
Distributions to subsidiary's non-controlling limited partner		(5.2)		(6.2)		(12.8)		(12.5)
Deferred financing charges and other		0.1		(5.3)		(0.1)		(5.3)

Cash flow from (used in) financing activities		(195.5)		(632.6)		224.7		(445.1)

Cash flow from operating, investing and financing activities		98.5		45.6		74.2		89.4
Effect of translation on foreign currency cash		(17.6)		4.6		(18.8)		(0.9)

Increase in cash and cash equivalents		80.9		50.2		55.4		88.5
Cash and cash equivalents, beginning of period		117.8		100.3		143.3		62.0

Cash and cash equivalents, end of period	$	198.7	$	150.5	$	198.7	$	150.5


See accompanying notes.

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

C O N S O L I D A T E D B A L A N C E S H E E T S

(in millions of Canadian dollars)

	Unaudited			Audited*
	June 30			Dec. 31
		2003		2002

				(Restated,
				Note 1)
ASSETS
Current assets
Cash and cash equivalents	$	198.7	$	143.3
Accounts receivable		331.2		419.0
Prepaid expenses		73.9		49.4
Price risk management assets (Note 4)		159.1		157.8
Future income tax assets		16.4		18.7
Income taxes receivable		105.6		111.5
Inventory		47.6		48.9

		932.5		948.6

Restricted cash (Note 2)		10.5		-
Investments (Note 5)		11.1		32.2
Long-term receivables (Note 6)		115.4		39.9
Property, plant and equipment
Cost		9,105.7		8,184.1
Accumulated depreciation		(2,185.6)		(2,089.9)

		6,920.1		6,094.2
Goodwill (Note 2)		149.7		56.5
Future income tax assets		82.5		72.2
Price risk management assets (Note 4)		44.0		60.7
Other assets		192.5		110.6

Total assets	$	8,458.3	$	7,414.9


LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	$	310.2	$	290.0
Accounts payable and accrued liabilities		484.2		472.2
Price risk management liabilities (Note 4)		156.4		173.8
Income taxes payable		7.3		-
Future income tax liabilities		19.0		17.1
Dividends payable		47.9		42.9
Current portion of long-term debt		362.8		355.4
Current portion of long-term debt - non-recourse (Note 2)		56.7		-

		1,444.5		1,351.4

Long-term debt		2,285.1		2,351.2
Long-term debt - non-recourse (Note 2)		566.7		-
Deferred credits and other long-term liabilities		411.2		452.8
Future income tax liabilities		604.7		402.1
Price risk management liabilities (Note 4)		36.1		50.6
Non-controlling interests		296.9		263.0

Preferred securities		451.2		451.7
Common shareholders' equity
Common shares (Note 7)		1,524.9		1,226.2
Retained earnings		866.8		884.7
Cumulative translation adjustment		(29.8)		(18.8)

		2,361.9		2,092.1

Total liabilities and shareholders' equity	$	8,458.3	$	7,414.9

Contingencies and commitments (Notes 6 and 8)

See accompanying notes.

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

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

( U N A U D I T E D )

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

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

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

TransAlta's results are seasonal 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 a 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 the 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

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June 30, 2002	3 months ended		6 months ended

Statements of earnings:
Site restoration accrual, included in fuel and purchased power	$	(9.5)		$	(19.1)
Depreciation and amortization expense		0.3				0.6
Depreciation and amortization expense, included in fuel and purchased power		(0.2)				(0.6)
Accretion expense, included in depreciation and amortization expense		5.7				11.4
Current income tax expense		1.3				2.7

Net earnings applicable to common shareholders	$	2.4		$		5.0


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
Revisions in estimated cash flows						-

Balance, Dec. 31, 2002				$	264.9
Liabilities incurred in period						4.8
Liabilities settled in period						(3.5)
Accretion expense						12.1
Acquisition of CE Gen						5.2
Change in foreign exchange rates						(9.7)
Revisions in estimated cash flows						-

Balance, June 30, 2003				$	273.8

TransAlta estimates the undiscounted amount of cash flow required to settle the asset retirement obligation is approximately $1.2 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 half 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 June 30				6 months ended June 30
		2003		2002		2003		2002

				(Restated,				(Restated,
				Note 1)				Note 1)
Reported net earnings applicable to common shareholders	$	23.3	$	127.3	$	72.0	$	181.3
Compensation expense		0.6		1.0		1.3		1.7

Pro forma net earnings applicable to common shareholders	$	22.7	$	126.3	$	70.7	$	179.6


Reported basic earnings per share	$	0.12	$	0.75	$	0.40	$	1.06
Compensation expense per share		-		0.01		0.01		0.01

Pro forma basic earnings per share	$	0.12	$	0.74	$	0.39	$	1.05


Reported diluted earnings per share	$	0.12	$	0.74	$	0.40	$	1.05
Compensation expense per share		-		0.01		0.01		0.01

Pro forma diluted earnings per share	$	0.12	$	0.73	$	0.39	$	1.04

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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.

2 . A C Q U I S I 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. Working capital adjustments and a reduction in deferred credits and other liabilities resulted in a $0.7 million decrease in working capital, a $17.6 million decrease in deferred credits and other long-term liabilities related to asset retirement obligations and a corresponding $16.9 million decrease in goodwill.

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 values of the 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.

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

On 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 statement of earnings.

June 30, 2002	3 months ended		6 months ended

Revenues	$	14.3	$	55.8
Operating expenses		(10.3)		(30.8)

Operating income		4.0		25.0
Net interest expense		(0.7)		(2.4)

Earnings before income taxes		3.3		22.6
Income taxes		1.7		9.8

Earnings before gain on disposal		1.6		12.8
Gain on disposal		110.0		110.0

Earnings from discontinued operations	$	111.6	$	122.8

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.

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 six months ended June 30, 2003:

	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		6.5		9.0		15.5
Changes in values attributable to market price and other market changes		(20.6)		-		(20.6)
Contracts realized, amortized or settled during the period		26.6		(5.0)		21.6
Changes in values attributable to changes in valuation techniques and assumptions		-		-		-

Net price risk management assets outstanding at June 30, 2003	$	5.0	$	5.6	$	10.6

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	$	2.0	$	4.2	$	3.1	$	2.1	$	1.5	$	-	$	12.9
Prices based on
models		(7.9)		-		-		-		-		-		(7.9)

	$	(5.9)	$	4.2	$	3.1	$	2.1	$	1.5	$	-	$	5.0
Electrical transmission
rights (accrual)		3.5		2.1		-		-		-		-		5.6

	$	(2.4)	$	6.3	$	3.1	$	2.1	$	1.5	$	-	$	10.6

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The carrying value and fair value of price risk management assets and liabilities included on the balance sheet are as follows:

					June 30,		Dec. 31,
					2003		2002

Price risk management assets
Current				$	159.1	$	157.8
Long-term					44.0		60.7
Price risk management liabilities
Current					(156.4)		(173.8)
Long-term					(36.1)		(50.6)

				$	10.6	$	(5.9)


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

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

Electricity	MWh	25,784.9	25,912.7				39
Natural gas	GJ	67,034.0	69,545.1				30

The corporation's electrical transmission contracts trading position was 27.3 million MWh at June 30, 2003 compared to 18.1 million MWh at Dec. 31, 2002. The maximum term of the contracts outstanding at June 30, 2003 was 18 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 . L O N G - T E R M R E C E I V A B L E S

TransAlta has a US$53.0 million receivable relating to energy sales in California. On Dec. 12, 2002, a U.S. Federal Energy Regulatory Commission (FERC) Administrative Law Judge issued proposed findings of fact that TransAlta be entitled to receive approximately US$44 million for electricity sales in California. 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. 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. TransAlta has a provision of US$28.8 million against the receivable and will maintain this provision until a final ruling is made with respect to these issues. For further discussion, see Note 8.

7 . 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 June 30, 2003, the corporation had 188.9 million (Dec. 31, 2002 - 169.8 million) common shares issued and outstanding plus outstanding employee stock options to purchase an additional 3.2 million shares (Dec. 31, 2002 - 3.2 million).

In March of 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 half of 2003.

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8 . 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. 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 is responding to these FERC show cause orders and requests for information. It remains unclear what refunds or payments, if any, TransAlta may be required to make 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 outcome of this appeal is unknown 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.

9 . 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 costs expected to be incurred, which vest over three months, are expected to be $0.7 million. Of this amount, $0.4 million was recognized in the second quarter of 2003, and is included in operations, maintenance and administration expense for the Energy Marketing segment.

Additional costs of $1.1 million are expected to be incurred in connection with the closure of the office, including $0.5 million for relocation, $0.5 million for the impairment of assets in the Annapolis office and $0.1 million for other related costs. As of June 30, 2003, no amounts have been incurred or recognized in respect of these closure costs. The office is expected to be closed by Dec. 31, 2003.

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

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.

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

Effective Jan. 1, 2003, the results of Vision Quest are included in the Generation segment. Prior period amounts have been reclassified. The results of CE Gen are also included in the Generation segment from the date of purchase (Jan. 29, 2003).

Each business segment assumes responsibility for its operating results measured 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 from discontinued operations, other income (expense) and foreign exchange gains (losses) and adding net interest expense, prior period regulatory decisions, income taxes and non-controlling interests to net earnings applicable to common shareholders.

I. Earnings information
							Unaudited

			Energy
3 months ended June 30, 2003	Generation		Marketing		Corporate			Total

Revenues	$	568.2	$	(27.2)	$	-	$	541.0
Fuel and purchased power		(239.7)		-		-		(239.7)

Gross margin		328.5		(27.2)		-		301.3
Operations, maintenance and administration		108.4		2.3		11.1		121.8
Depreciation and amortization		78.8		0.8		3.5		83.1
Taxes, other than income taxes		5.6		-		-		5.6

EBIT before corporate allocations		135.7		(30.3)		(14.6)		90.8
Corporate allocations		(12.9)		(1.7)		14.6		-

EBIT	$	122.8	$	(32.0)	$	-		90.8

Other income								0.2
Foreign exchange loss								(0.2)
Net interest expense								(49.6)

Earnings from continuing operations before income taxes and non-controlling interests							$	41.2


							Unaudited

				Energy
3 months ended June 30, 2002	Generation		Marketing		Corporate			Total

Revenues	$	322.6	$	13.7	$	-	$	336.3
Fuel and purchased power		(115.9)		-		-		(115.9)

Gross margin		206.7		13.7		-		220.4
Operations, maintenance and administration		82.5		3.9		13.2		99.6
Depreciation and amortization		50.8		0.7		5.8		57.3
Taxes, other than income taxes		6.8		-		-		6.8
Prior period regulatory decisions		3.3		-		-		3.3

EBIT before corporate allocations		63.3		9.1		(19.0)		53.4
Corporate allocations		(17.2)		(1.8)		19.0		-

EBIT	$	46.1	$	7.3	$	-		53.4

Other income								2.7
Foreign exchange gain								0.7
Net interest expense								(18.6)

Earnings from continuing operations before income taxes and non-controlling interests							$	38.2

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							Unaudited

			Energy
6 months ended June 30, 2003	Generation		Marketing		Corporate			Total

Revenues	$	1,173.7	$	(16.5)	$	-	$	1,157.2
Fuel and purchased power		(505.8)		-		-		(505.8)

Gross margin		667.9		(16.5)		-		651.4
Operations, maintenance and administration		226.5		4.4		28.6		259.5
Depreciation and amortization		148.1		1.6		7.8		157.5
Taxes, other than income taxes		11.7		-		-		11.7

EBIT before corporate allocations		281.6		(22.5)		(36.4)		222.7
Corporate allocations		(32.3)		(4.1)		36.4		-

EBIT	$	249.3	$	(26.6)	$	-		222.7

Other income								-
Foreign exchange loss								(7.7)
Net interest expense								(84.3)

Earnings from continuing operations before income taxes and non-controlling interests							$	130.7


							Unaudited

				Energy
6 months ended June 30, 2002	Generation		Marketing		Corporate			Total

Revenues	$	743.4	$	12.6	$	-	$	756.0
Fuel and purchased power		(283.8)		-		-		(283.8)

Gross margin		459.6		12.6		-		472.2
Operations, maintenance and administration		154.1		6.5		26.4		187.0
Depreciation and amortization		102.7		1.4		11.3		115.4
Taxes, other than income taxes		13.8		-		-		13.8
Prior period regulatory decisions		3.3		-		-		3.3

EBIT before corporate allocations		185.7		4.7		(37.7)		152.7
Corporate allocations		(33.8)		(3.9)		37.7		-

EBIT	$	151.9	$	0.8	$	-		152.7

Other income								0.6
Foreign exchange gain								1.3
Net interest expense								(37.8)

Earnings from continuing operations before income taxes and non-controlling interests							$	116.8


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

Goodwill	$	120.4	$	29.3	$	-	$	149.7
Total segment assets	$	7,554.1	$	296.6	$	607.6	$	8,458.3


				Energy
Dec. 31, 2002	Generation		Marketing		Corporate			Total

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

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

Capital expenditures	$	108.7	$	1.4	$	2.9	$	-	$	113.0


				Energy			Discontinued
3 months ended June 30, 2002	Generation		Marketing		Corporate		Operations			Total

Capital expenditures	$	286.3	$	0.4	$	4.5	$	8.5	$	299.7


				Energy			Discontinued
6 months ended June 30, 2003	Generation		Marketing		Corporate		Operations			Total

Capital expenditures	$	398.5	$	3.5	$	3.9	$	-	$	405.9
Acquisitions	$	323.4	$	-	$	-	$	-	$	323.4


				Energy			Discontinued
6 months ended June 30, 2002	Generation		Marketing		Corporate		Operations			Total

Capital expenditures	$	539.3	$	1.7	$	6.2	$	21.8	$	569.0


IV. Reconciliation
				3 months ended June 30				6 months ended June 30
Depreciation and amortization expense (D&A) per statement of cash flows				2003		2002		2003		2002

D&A expense for reportable segments			$	83.1	$	57.3	$	157.5	$	115.4
Mining equipment depreciation, included in fuel and purchased power				3.4		9.0		13.5		19.1
Site restoration accretion, included in D&A expense				(6.9)		(5.7)		(12.1)		(11.4)
Discontinued operations				-		3.9		-		15.6
Other				9.9		0.7		11.5		1.6

			$	89.5	$	65.2	$	170.4	$	140.3



1 2 . S U B S E Q U E N T E V E N T

On June 16, 2003, TransAlta announced its intention to sell its 50 per cent interest in the two-unit, 756 MW coal-fired Sheerness Generating Station to TransAlta Cogeneration, L.P. (TA Cogen). TA Cogen is owned 50.01 per cent by TransAlta and 49.99 per cent by TransAlta Power, L.P. (TransAlta Power). Total consideration to the corporation is expected to be $630.0 million, comprised of $315.0 million in cash, and 38.8 million units of TA Cogen at an effective issue price of $8.12. The gain on sale will be approximately $55 million. Both the cash receipt and gain on sale are subject to the exercise of the warrants discussed below. The unitholders of TransAlta Power approved the transaction on July 18, 2003, and the sale is expected to close on July 31, 2003.

Concurrent with the sale, TransAlta Power will issue to the public 17.75 million partnership units at a price of $9.30 each. Each unit has one warrant attached. TransAlta Power will also issue 17.75 million partnership units to TransAlta at a per unit price of $9.30. TransAlta Power will also subscribe to 38.8 million units of TA Cogen at a unit price of $8.12. The warrants can be exercised for one partnership unit, and are exercisable any time until 12 months after closing of the sale. The partnership units purchased by TransAlta will be sold back to TransAlta Power as the warrants are exercised. As a result, TransAlta will own approximately 26 per cent of TransAlta Power until the warrants are exercised in full, at which time TransAlta will return to its original ownership interest in TransAlta Power. As a result, TransAlta will own, directly and indirectly, approximately 63 per cent of TA Cogen immediately after the sale, prior to the exercise of the warrants. In addition to the approximately $55 million gain upon closing of the transaction, additional gains will be recognized as the warrants are exercised and TransAlta's effective interest in TransAlta Power is reduced.

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

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of approximately $119 million (pre-tax) will be taken into earnings. In addition, the management agreements between TransAlta and TransAlta Power and TA Cogen will be 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 will receive $1.0 million from TransAlta Power and $5.0 million from TA Cogen.

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.

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

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

A . E A R N I N G S A N D E P S
	Reconciling		3 months ended June 30				6 months ended June 30
	items		2003		2002		2003		2002

Earnings from continuing operations - Canadian GAAP		$	29.1	$	20.9	$	83.3	$	69.2
Effect of asset retirement obligations
adoption - Canadian GAAP	(XI)		-		(2.4)		-		(5.0)
Derivatives and hedging activities, net of tax	(I)		(6.8)		0.8		(4.1)		3.2
Start-up costs, net of tax	(II)		(1.2)		(1.1)		(1.4)		(3.3)
Preferred securities distributions, net of tax	(III)		(5.8)		(5.2)		(11.3)		(10.7)
Effect of debt extinguishment, net of tax	(IV)		0.1		0.2		0.4		0.4
Amortization of pension transition adjustment	(VI)		(1.5)		(1.0)		(2.9)		(2.2)

Earnings from continuing operations - U.S. GAAP			13.9		12.2		64.0		51.6
Earnings from discontinued
operations - Canadian and U.S. GAAP			-		1.6		-		12.8
Net gain on disposal of discontinued
operations - Canadian and U.S. GAAP			-		110.0		-		110.0

Net earnings before change in
accounting principle - U.S. GAAP			13.9		123.8		64.0		174.4
Cumulative effect of change in accounting principle,
net of tax	(XI)		-		-		52.5		-

Net income - U.S. GAAP		$	13.9	$	123.8	$	116.5	$	174.4
Foreign currency cumulative translation adjustment	(I), (VIII)		8.7		(16.9)		(11.0)		(19.6)
Net loss on derivative instruments	(I), (VIII)		(9.9)		(11.4)		(25.9)		(4.5)

Comprehensive income - U.S. GAAP		$	12.7	$	95.5	$	79.6	$	150.3


Basic EPS - U.S. GAAP
Earnings from continuing operations		$	0.07	$	0.07	$	0.35	$	0.30
Earnings from discontinued operations			-		0.01		-		0.08
Net gain on disposal of discontinued operations			-		0.65		-		0.65
Cumulative effect of change in accounting principle			-		-		0.29		-

Net earnings		$	0.07	$	0.73	$	0.64	$	1.03


Diluted EPS - U.S. GAAP
Earnings from continuing operations		$	0.07	$	0.07	$	0.35	$	0.30
Earnings from discontinued operations			-		0.01		-		0.08
Net gain on disposal of discontinued operations			-		0.65		-		0.65
Cumulative effect of change in accounting principle			-		-		0.29		-

Net earnings		$	0.07	$	0.73	$	0.64	$	1.03

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B . B A L A N C E S H E E T I N F O R M A T I O N

(Audited)

Reconciling

Canadian

June 30, 2003

Canadian

Dec. 31 2002

items

GAAP

U.S. GAAP

GAAP

U.S. GAAP

Assets

Current derivative assets

(I)

11.2

8.3

Accounts receivable

(IX)

331.2

329.6

419.0

417.5

Income taxes receivable

(I), (II), (IV)

105.6

117.0

111.5

120.7

Investments

(X)

11.1

183.2

32.2

271.9

Property, plant and equipment, net

(II)

6,920.1

6,926.1

6,094.2

6,043.5

Long-term derivative asset

(I)

104.8

53.3

Other assets

(I), (II), (III)

192.5

68.2

110.6

57.4

Liabilities

Accounts payable and accrued liabilities

(VI)

484.2

453.5

472.2

436.7

Income taxes payable

(IX)

7.3

5.8

Current derivative liability

(I)

17.3

27.6

Long-term debt

(I), (III), (X)

2,851.8

3,528.6

2,351.2

3,087.6

Deferred credits and other long-term liabilities

(I), (IV)

411.2

431.5

452.8

526.9

Long-term derivative liabilities

(I)

118.1

133.1

Future or deferred income tax liability

(I), (II), (III), (IV), (V), (VI)

604.7

557.1

402.1

339.1

Non-controlling interest

(II)

296.9

293.0

263.0

Equity

Preferred securities

(III)

451.2

451.7

Common shares

(IX)

1,524.9

1,523.3

1,226.2

1,224.7

Retained earnings

(I), (II), (IV), (V), (VI)

866.8

865.6

884.7

786.5

Cumulative translation adjustment

(I), (VIII)

(29.8)

(18.8)

Accumulated other comprehensive income

(I), (VIII)

(160.6)

(123.7)

C . R E C O N C I L I N G I T E M S

I. Derivatives and hedging activities

(i) Fair Value Hedging Strategy

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

The corporation's fair value hedges resulted in a net gain of $nil in the three and six months ended June 30, 2003 and 2002 related to the ineffective portion of its hedging instruments (inclusive of the time value of money) as well as the portion of the hedging instrument excluded from the assessment of hedge effectiveness.

(ii) Cash Flow Hedging Strategy

The corporation uses forward starting swaps, treasury locks and spread locks to hedge the interest rates of anticipated issuances of debt to protect the corporation against increases in interest rates prior to the date of issuance, and uses forward sales contracts, swaps and futures contracts to hedge generation production to protect the corporation against fluctuations in commodity prices and exchange rates. The maximum term of cash flow hedges of anticipated transactions is 11 years.

In the three and six months ended June 30, 2003 the corporation's cash flow hedges resulted in a net loss of $0.4 million (2002 - $0.2 million) related to the ineffective portion of its hedging instruments, and a net gain of $nil (2002 - $0.2 million) related to the portion of the hedging instrument excluded from the assessment of hedge effectiveness.

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In January 2001, forward starting swaps with a notional amount of $200.0 million were settled and debt was issued.The $2.6 million transitional amount in accumulated other comprehensive income (AOCI) relating to the swaps is being reclassified into income as interest expense on the debt is recognized.

In June 2002, forward starting swaps with a notional amount of US$125.0 million were settled and debt was issued, resulting in a loss of $11.2 million.The loss will be reclassified from other comprehensive income (OCI) into income as interest expense on the debt is recognized.

Over the next 12 months, the corporation estimates that $12.8 million of net losses that arose from cash flow hedges will be reclassified from OCI to net earnings.The corporation also estimates that $3.7 million of net losses on cash flow hedging instruments that arose on adoption of Statement 133 will be reclassified from AOCI to earnings.These estimates assume constant gas and power prices, interest rates and exchange rates over time; however, the actual amounts that will be reclassified will vary based on changes in these factors.Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next 12 months.

(iii) Net Investment Hedges

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

In the three and six months ended June 30, 2003, the corporation recognized a net after-tax gain of $8.7 million and a net after tax loss of $11.0 million, respectively (2002 - $16.9 million and $19.6 million losses, respectively) on its net investment hedges, included in OCI.

The corporation recognized income of $nil (2002 - $0.7 million), related to ineffectiveness of net investment hedges.

(iv) Trading Activities

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

(v) Other Hedging Activities

The corporation recognized pre-tax losses of $3.4 million and $6.8 million (2002 - $2.7 million and $1.2 million, respectively) related to hedging activities that do not qualify for hedge accounting under Statement 133.

II. Start-up costs

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

III. Preferred securities

Under U.S. GAAP, the corporation's preferred securities are considered to be entirely debt with no equity component, whereas under Canadian GAAP, these preferred securities have both a debt and equity component. Accordingly, the preferred securities distributions are classified as an expense under U.S. GAAP rather than a direct charge to retained earnings. Under U.S. GAAP, the costs associated with the issuance of the preferred securities are recorded as an asset whereas under Canadian GAAP, these costs, net of tax, are charged to preferred securities.

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IV. Debt extinguishment

Under U.S. GAAP, the premium on redemption of long-term debt related to the limited partnership transaction was recorded when incurred, whereas for Canadian GAAP the loss is amortized to earnings over the period of the limited partnership to 2018.

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

Deferred income taxes under U.S. GAAP would be as follows:
		June 30,		Dec. 31,
		2003		2002

Future income tax liability (net) under Canadian GAAP	$	(524.8)	$	(328.3)
Asset retirement obligation		-		30.2
Derivatives		61.8		48.8
Start-up costs		(2.3)		(2.3)
Preferred securities		(5.7)		(6.2)
Debt extinguishment		9.1		9.7
Employee future benefits		(15.3)		(17.2)

	$	(477.2)	$	(265.3)


Comprised of the following:
		June 30,		Dec. 31,
		2003		2002

Current deferred income tax assets	$	16.4	$	18.7
Long-term deferred income tax assets		82.5		72.2
Current deferred income tax liabilities		(19.0)		(17.1)
Long-term deferred income tax liabilities		(557.1)		(339.1)

	$	(477.2)	$	(265.3)


VI. Employee future benefits

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

As a result of the corporation's plan asset return experience for its U.S. registered pension plan, at Dec. 31, 2002, the corporation was required under U.S. GAAP to recognize an additional minimum liability. The liability was recorded as a reduction in common equity through a charge to OCI, and did not affect net income for 2002. The charge to OCI will be restored through common equity in future periods to the extent fair value of trust assets exceed the accumulated benefit obligation.

VII. Joint ventures

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

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VIII. Other comprehensive income

The changes in the components of OCI were as follows:

3 months ended June 30

6 months ended June 30

2003

2002

2003

2002

Net gain (loss) on derivative instruments:

Unrealized losses, net of taxes of $5.7 million and $18.1 million

(2002 - $8.0 million and $4.0 million)

(10.8)

(12.3)

(27.7)

(6.4)

Reclassification adjustment for gains included in net income,

net of taxes of $0.4 million and $1.0 million

(2002 - $0.6 million and $1.1 million)

0.9

0.9

1.8

1.9

Net loss on derivative instruments

(9.9)

(11.4)

(25.9)

(4.5)

Translation adjustments

8.7

(16.9)

(11.0)

(19.6)

Other comprehensive income (loss)

(1.2)

(28.3)

(36.9)

(24.1)

The components of AOCI were:

June 30,

Dec. 31,

2003

2002

Net loss on derivative instruments

(105.9)

(80.0)

Registered pension alternate minimum liability

(1.7)

(1.7)

Translation adjustments

(53.0)

(42.0)

Accumulated other comprehensive income (loss)

(160.6)

(123.7)

IX. Share capital

Under U.S. GAAP, amounts receivable for share capital should be recorded as a deduction from shareholders' equity. Under the corporation's employee share purchase plan, accounts receivable for share purchases at June 30, 2003 was $1.6 million (Dec. 31, 2002 - $1.5 million).

X. Right of offset agreement

The corporation has a New Zealand bank deposit that has been offset with a New Zealand bank facility under a right of offset agreement. The arrangement does not qualify for offsetting under U.S. GAAP.

XI. Asset retirement obligations

The Financial Accounting Standards Board (FASB) issued Statement 143, Asset Retirement Obligations, which requires asset retirement obligations to be measured at fair value and recognized when the obligation is incurred. A corresponding amount is capitalized as part of the asset's carrying amount and depreciated over the asset's useful life. Statement 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. TransAlta adopted the provisions of Statement 143 effective Jan. 1, 2003.

In accordance with Canadian GAAP, the asset retirement obligations standard was adopted retroactively with restatement of prior periods. Under U.S. GAAP, the impact of adopting Statement 143 was recognized as a cumulative effect of a change in accounting principle as of Jan. 1, 2003, the beginning of the fiscal year in which the Statement was first applied. The change resulted in an after-tax increase in net earnings of $52.5 million ($82.7 million pre-tax). Had the change in accounting principle been applied retroactively, basic and diluted earnings per share for the three months ended June 30, 2002 would have been $0.74 and $0.74 per share respectively, and basic and diluted earnings per share for the six months ended June 30, 2002 would have been $1.05 and $1.05 per share respectively.

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

Closing market price		$	17.97	$	17.11
Price range (last 12 months)
	High	$	21.15	$	23.95
	Low	$	15.36	$	16.69
Debt/invested capital (including non-recourse debt)			52.0%		50.4%
Debt/invested capital (excluding non-recourse debt)			46.9%		50.4%
Return on common shareholders' equity			3.1%		3.9%
Return on invested capital			4.6%		4.2%
Book value per share		$	12.50	$	12.43
Cash dividends per share		$	1.00	$	1.00
Price/earnings ratio (times)			46.2		46.0
Dividend payout ratio			250.4%		212.3%
Interest coverage (times)			1.3		1.5
Interest coverage including preferred securities (times)			1.1		1.2
Dividend coverage (times)			3.4		2.5
Dividend yield			5.6%		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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Q U A R T E R L Y R E P O R T 2 0 0 3

TransAlta Corporation

Box 1900, Station "M"

110 - 12th Avenue S.W.

Calgary, Alberta Canada T2P 2M1

PHONE

403.267.7110

WEB SITE

www.transalta.com

CIBC Mellon Trust Company

P.O. Box 7010 Adelaide Street Station

Toronto, Ontario Canada M5C 2W9

toll free in North America: 1.800.387.0825

PHONE

416.643.5500 in Toronto or outside North America

FAX

416.643.5501

WEB SITE

www.cibcmellon.ca

For more information:

Media inquiries:

Nadine Walz,

Senior Media Relations Specialist

PHONE

403.267.3655

PAGER

403.213.7041

EMAIL

media_relations@transalta.com

Investor inquiries:

Daniel J. Pigeon,

Director, Investor Relations

PHONE

1.800.387.3598 in Canada and United States

or 403.267.2520

FAX

403.267.2590

EMAIL

investor_relations@transalta.com

Exhibits

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: July 24, 2003

Exhibits

CERTIFICATIONS

I, Stephen G. Snyder, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:

July 23, 2003

/s/ Stephen G. Snyder

Stephen G. Snyder

President and Chief Executive Officer

Exhibits

I, Ian Bourne, certify that:

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

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

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

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

Date: July 23, 2003

/s/ Ian Bourne

Ian Bourne

Executive Vice President and Chief Financial Officer

Exhibits