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 April, 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-________

 

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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.

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Other Matters

The company maintains a comprehensive Web site containing financial and other information. On April 24, 2003, additional information on individual power plants' historical revenues and production was added to the Web site. This information will be updated quarterly, and may be accessed by investors at www.transalta.com.

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EXHIBITS

Exhibit 1	Press release dated April 24, 2003.
Exhibit 2	Quarterly report for the three-month period ended March 31, 2003, which includes Management's Discussion and Analysis and consolidated financials statements.

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Improved performance drives strong quarter for TransAlta

CALGARY, Alberta (April 24, 2003) - TransAlta Corporation (TSX: TA; NYSE: TAC) today announced first quarter 2003 earnings from continuing operations of $48.7 million ($0.28 per common share), compared to $42.8 million ($0.25 per share) for the same period in 2002. Net earnings of $54.0 million ($0.31 per share) in first quarter 2002 included the results of the Transmission operation, sold in April 2002.

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

"Our priority in 2003 is to improve the productivity of our assets. These efforts are already having an impact," said Steve Snyder, TransAlta's president and CEO. "Our strong first quarter results reflect our ability to manage costs while we drive production to meet market demand."

"Our recent equity issue of $276 million in gross proceeds improved our already solid financial strength."

Revenue for the first quarter increased by $196.5 million over the same period in 2002, reflecting the acquisition of CE Generation, increased production, improved availability and higher electricity spot prices. Plant availability was 93.4 per cent, up from 92.5 per cent in first quarter 2002, mainly as a result of better performance at the Centralia plant. Production was up seven per cent, or 809 gigawatt-hours (GWh), to 13,004 GWh, again due to improved availability and incremental production from new power plants, and partially offset by lost production resulting from the shutdown of Wabamun unit three.

Cash from operating activities was $170.1 million, compared to $129.0 million in first quarter 2002. This increase was mainly due to an improved working capital position due to the significant final installment of 2001 income taxes paid ($109.0 million), offset by a decrease in accounts receivable.

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

TransAlta consolidated financial highlights

* In accordance with U.S. and Canadian GAAP, revenues from energy trading activities are now presented on a net basis.

** Applicable to common shareholders, net of preferred securities distributions.

 

 

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In first quarter 2003, TransAlta:

• Entered into an agreement with EPCOR to acquire a 50 per cent interest in EPCOR's Genesee Phase 3 project for approximately $395 million. TransAlta paid $157 million for costs incurred to date. The 450-megawatt (MW net) plant is currently under construction southwest of Edmonton, Alberta and is expected to be in service in early 2005.

• Completed the acquisition of a 50 per cent interest in CE Generation LLC, which holds 816 MW of operating capacity, including 326 MW of geothermal generation in California and 490 MW of gas-fired cogeneration in New York, Texas and Arizona. Two months of operation of CE Generation are included in the first quarter 2003 results.

• Successfully issued 15 million common shares for gross proceeds of $240 million. Subsequent to the first quarter, the underwriters exercised their over-allotment option for 2.25 million shares, bringing total gross proceeds to $276 million.

• Began commercial operation of the 440-MW gas-fired facility at its Sarnia Regional Cogeneration Plant located in Sarnia, Ontario. The new facility is integrated with 135 MW from the facilities TransAlta acquired last year. The 575-MW plant is supplying steam and electricity to TransAlta's host customers as well as electricity into regional wholesale markets.

• Sold its 8.82 per cent interest in the Goldfields Gas Pipeline in Australia for proceeds of AU$24.1 million (approximately $21.7 million). Closing of the transaction is subject to regulatory approval and is expected to occur in the second quarter of 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.

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For more information:

Media inquiries:

Investor inquiries:

Nadine Walz

Daniel J. Pigeon

Media Relations Specialist

Director, Investor Relations

Phone:  (403) 267-3655   

    

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

Pager: (403) 213-7041

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

Email:  media_relations@transalta.com

   

E-mail:  investor_relations@transalta.com

 

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Q1:2003

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 consolidated financial statements of TransAlta Corporation (TransAlta or the corporation) as at and for the three months ended March 31, 2003 and 2002, and should also be read in conjunction with the audited consolidated financial statements and Management's Discussion and Analysis contained in TransAlta's annual report for the year ended Dec. 31, 2002. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted.

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

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

 

 

 

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Each business segment assumes responsibility for their operating results measured as earnings before interest, taxes and non-controlling interests (EBIT). EBIT is shown because 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 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:

H I G H L I G H T S

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

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Net earnings from continuing operations for the three months ended March 31, 2003 reflect improved results from energy marketing activities, improved availability and production from the generation thermal assets and higher electricity spot prices and spark spreads (power price less cost of gas consumed), partially offset by the negative earnings impact of the Sarnia and Big Hanaford plants as well as CE Generation LLC (CE Gen).

Cash flow from operating activities for the three months ended March 31, 2003 increased $41.1 million from the first quarter of 2002. In 2002 the corporation made a major payment ($109.0 million) in respect of 2001 income taxes. In 2003 net receivables increased by approximately $60 million compared to the first quarter of 2002 as a result of strong revenues earned in the quarter.

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

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

Equity offering

On March 21, 2003, the corporation issued 15.0 million common shares for gross proceeds of $240.0 million. The offering included an option for the underwriters to purchase a further 2.25 million common shares for gross proceeds of $36.0 million, which was exercised in full on April 17, 2003 and is expected to close on April 25, 2003.

Purchase of 50 per cent interest in CE Generation LLC

On Jan. 29, 2003, the corporation purchased a 50 per cent interest in CE Gen for cash of US$240 million (Cdn$366.6 million), which included working capital of US$39.9 million (Cdn$60.8 million) and restricted cash of US$37.9 million (Cdn$57.9 million). GE Gen had non-recourse debt of US$939.4 million (Cdn$1,434.8 million) at the time of the acquisition. Refer to Note 2 of the consolidated financial statements for the complete purchase price allocation. MidAmerican Energy Holdings Company holds the other 50 per cent interest in CE Gen. Through its subsidiaries, CE Gen is engaged primarily in the development, ownership and operation of independent power production facilities in the United States using geothermal and natural gas resources. CE Gen has 13 facilities with an aggregate operating capacity of 816 megawatts (MW).

TransAlta's net ownership in these assets is 378 MW (408 MW gross). TransAlta's share of CE Gen's results for the period of ownership from Jan. 29, 2003 to March 31, 2003 is included in the Generation segment.

Purchase of 50 per cent interest in Genesee 3

On Jan. 13, 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. On the same date, TransAlta paid EPCOR $157.0 million of the $395 million for TransAlta's share of project costs incurred to date. The 450 MW addition to the existing Genesee Generating Station is currently under construction southwest of Edmonton, Alberta. The two corporations will own and share costs for Genesee 3 equally. EPCOR will continue to manage the project's construction and will operate the plant upon commercial operation in early 2005. Both parties will independently dispatch and market their share of the electrical output from the unit through the Alberta Power Pool. Included in the arrangement is an option, expiring Dec. 31, 2005, for EPCOR to purchase a 50 per cent interest in TransAlta's Centennial 1 project. EPCOR also has the option to purchase a 50 per cent interest in TransAlta's Sarnia plant, which may be exercised between January 2003 and March 2004.

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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. Under the new standard, the corporation now 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 related asset. 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 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 quarter 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 March 31, 2003 Generation had 8,270 MW of gross generating capacity in operation (7,973 MW net ownership interest) and 763 MW under construction.

As previously discussed, TransAlta acquired a 50 per cent interest in CE Gen on Jan. 29, 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 on March 27, 2003, resulting in 440 MW of generating capacity in addition to the existing 135 MW. Also during the first quarter, 22 MW of capacity was commissioned at the McBride Lake project of which TransAlta has a 50 per cent interest through its ownership of Vision Quest Windelectric Inc. (Vision Quest).

Availability for the first quarter of 2003 was 93.4 per cent compared to 92.5 per cent in the first quarter of 2002. The increase is primarily a result of improved performance at the Centralia plant. Increased planned maintenance outages at the Alberta thermal plants was offset by a reduction in forced outages as a result of the accelerated maintenance performed during the fourth quarter of 2002.

The results of the Generation segment are as follows:

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Generation's revenues are derived from the production of electricity and steam as well as ancillary services such as system support. Revenues are subject to seasonal variations: 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 generally span the estimated remaining useful life of the contracted plants; all of which were previously regulated. 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.

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 20 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 on either the spot and short-term (less than one year) forward markets, including the results of short-term asset-backed trading, or via contracts that are between one and 10 years in duration (typically three to seven years).

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 2003. All three facilities have gas supply contracts in place for the duration of the electricity sales contracts.

															Fuel &
						Fuel &									Purchased				Gross
3 months ended	Production					Purchased				Gross			Revenue		Power				Margin
March 31, 2003	(GWh)			Revenue		Power				Margin			per MWh		per MWh				per MWh
Alberta PPAs	6,904		$	182.9		$	46.0		$	136.9		$	26.49		$	6.66		$	19.83
Long-term contracts	1,715			148.6			97.5			51.1			86.65			56.85			29.80
Merchant	3,889			217.0			106.5			110.5			55.79			27.38			28.41
CE Gen	496			57.0			16.1			40.9			114.92			32.46			82.46
TOTAL	13,004		$	605.5		$	266.1		$	339.4		$	46.56		$	20.46		$	26.10

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In the first quarter of 2003, production from Alberta PPA plants was 256 gigawatt hours (GWh) lower than the first quarter of 2002 as a result of the decommissioning of unit three of the Wabamun plant in November, 2002.

Revenues increased slightly to $26.49 per megawatt hour (MWh) from $25.74 per MWh due to contractual escalation in the PPAs. All of the coal used for production under Alberta PPAs are from coal reserves owned by TransAlta. This allows the corporation to control the cost of coal and results in relatively fixed coal costs. Fuel and purchased power increased to $6.66 per MWh from $5.63 per MWh in 2002 as a result of escalating mine operating costs, which are factored into pricing formulas in the PPAs, and increased natural gas prices.

Long-term contracts

In the first quarter of 2003, production levels increased 229 GWh, primarily as a result of incremental production from the purchase of the existing operational assets at the Sarnia plant and the acquisition of Vision Quest in December 2002.

Revenues increased to $86.65 per MWh compared to $55.18 per MWh due in part to $33.6 million of incremental steam revenues earned from the Sarnia plant. Steam revenue has no production volumes associated with it. Revenue also increased as a result of increased natural gas prices. At certain plants, increased natural gas prices flow through to customers and are therefore recovered through increased revenues. Fuel and purchased power was $56.85 per MWh compared to $22.41 per MWh in 2002 primarily as a result of higher natural gas market prices and the cost of the gas used for steam production.

Merchant production

In the three months ended March 31, 2003, merchant production was 3,889 MWh, of which 2,550 MWh was contracted. In the first quarter of 2002 merchant production was 3,551 MWh of which 2,305 MWh was contracted. The increase in contracted production is due to increased availability and production from the Centralia plant. Non-contracted production increased as a result of incremental production from the Big Hanaford plant, offset by lower excess production at the Alberta thermal plants due to the decommissioning of Wabamun unit three.

 

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As shown in the above graphs, electricity spot prices in the Alberta and Pacific Northwest markets increased in the first quarter of 2003 compared to the same period in 2002. This was the result of increased natural gas prices and increased demand. The Ontario market was regulated until June 2002, therefore comparative data is not meaningful. While spark spreads in Alberta increased, they remained constant and depressed in the Pacific Northwest and depressed in Ontario. 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.

Merchant revenues of $55.79 per MWh in the first quarter of 2003 increased from $43.51 per MWh in the first quarter of 2002, as 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 US dollar. Fuel and purchased power was $27.38 per MWh compared to $26.56 per MWh in 2002 reflecting increased natural gas prices partially offset by lower mine operating costs and lower purchased power requirements due to higher availability at the Centralia plant.

CE Gen

From Jan. 29, 2003 to March 31, 2003, CE Gen produced 496 GWh of electricity. Revenue was $114.92 per MWh and fuel and purchased power was $32.46 per MWh resulting in an average gross margin of $82.46 per MWh.

Operations, maintenance and administration expense

In the first quarter of 2003, operations, maintenance and administration (OM&A) expenses increased by $46.5 million ($3.21 per MWh) over the same period in 2002. Excluding the impact of the CE Gen acquisition, OM&A costs increased by $26.7 million ($1.69 per MWh). The increase reflects the impact of increased planned long-term maintenance at the Alberta thermal plants and incremental costs relating to the Big Hanaford plant and existing Sarnia assets currently in operation. The execution of the corporation's long-term maintenance strategy focuses on performing specific planned maintenance which generally involves higher capital and operating expenditures rather than less expensive short-term repairs. As a result, maintenance expenditures will be higher in the initial stages of the plan execution, but are expected to decline over time. OM&A costs for CE Gen in the first quarter of 2003 were $19.8 million ($39.92 per MWh). The relatively high costs per MWh at the geothermal generation facilities result from the requirement to process and refine the geothermal resources before they can be used for the generation of electricity.

Depreciation and amortization

Depreciation and amortization increased by $17.4 million or $1.08 per MWh in the first quarter of 2003 compared to the same period in 2002. $17.2 million of the increase is the result of the CE Gen acquisition of which $4.7 million related to plant and equipment and $12.5 million related to the amortization of power purchase agreements. Incremental depreciation from the Big Hanaford and Sarnia plants was offset by the decommissioning of the Wabamun unit three in 2002.

Taxes other than income taxes

For the first quarter of 2003, taxes other than income taxes, were consistent with the first quarter of 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 segment results.

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Energy Marketing also uses energy derivatives, including physical and financial swaps, forwards 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 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 March 31		2003		2002
Net trading revenues	$	10.7	$	(1.1)
Operations, maintenance and administration		2.1		2.6
Depreciation and amortization		0.8		0.7
EBIT before corporate allocations		7.8		(4.4)
Corporate allocations		(2.4)		(2.1)
EBIT	$	5.4	$	(6.5)

Net revenues increased by $11.8 million for the first quarter of 2003. In the corresponding period for 2002, Energy Marketing incurred losses on certain trading positions as a result of unanticipated increases in the prices of gas and electricity.

OM&A and depreciation and amortization expenses were consistent with the first quarter of 2002.

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

Electricity (GWh)
3 months ended March 31	2003	2002
Physical	14,027	8,667
Financial	9,261	6,795
	23,288	15,462
Gas (million GJ)
3 months ended March 31	2003	2002
Physical	29.5	11.8
Financial	23.4	37.9
	52.9	49.7

Gross trading sales volumes during the first quarter of 2003 increased by 7,826 GWh of electricity to 23,288 GWh and increased by 3.2 million gigajoules (GJ) of gas to 52.9 million GJ compared to the same period in 2002. The increase in electricity volumes 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 volumes in pure gas trading. These volumes are generally consistent with activity in the second half of 2002. TransAlta's trading activities are mainly short-term transactions, the majority of which are settled within four months 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. Physical transmission contracts are now accounted for on an accrual basis in accordance with changes in Canadian and U.S. GAAP. Previously these contracts were valued using quoted market prices and a spread option valuation model.

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The following table illustrates movements in the values of the corporation's price risk management assets (liabilities) during the three months ended March 31, 2003:

The corporation's electrical transmission contracts trading position was 29.9 million MWh at March 31, 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 2002, TransAlta responded to a number of inquiries from various U.S. State and Federal bodies regarding trading activities in California and states in the Pacific Northwest during 2000 and 2001. TransAlta believes it operated in accordance with all applicable laws, rules, regulations and tariffs. 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. FERC did not, however, name TransAlta in its findings and it remains unclear what refunds TransAlta will be required to make. As a result, 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

 

Net interest expense increased by $15.5 million in the three months ended March 31, 2003 compared to the same period of 2002. The increase was primarily due to higher debt levels resulting from the CE Gen and Genesee 3 acquisitions and continued construction activity. The increase in capitalized interest is a result of the increased amounts under construction related to the Mexico and Sarnia plants, as well as expenditures related to the Genesee 3 and McBride Lake projects, offset by interest no longer capitalized on the Big Hanaford plant.

The foreign exchange loss in 2003 relates to a reduction in the value of a goods and services 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 increase in earnings attributable to non-controlling interests in the first quarter of 2003 compared to 2002 is attributable to the 25 per cent non-controlling interest in CE Gen's Saranac facility, offset by decreased quarterly 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

Income tax expense increased by $3.9 million due to increased earnings in the first quarter of 2003 compared to 2002. The effective income tax rate, expressed as a percentage of earnings from continuing operations before income taxes and non-controlling interests, is marginally higher than 2002 as a result of a higher proportion of earnings in higher tax rate jurisdictions.

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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 $11.2 million in the first quarter of 2002.

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

The following chart outlines significant changes in the consolidated balance sheet from Dec. 31, 2002 to March 31, 2003:

	Increase/
	(Decrease)			Explanation
Cash and cash equivalents	$	(25.5)		Refer to Consolidated Statements of Cash Flows.
Accounts receivable and other		137.9		Increase due to the acquisition of CE Gen as well as
				increased revenues.
Restricted cash		56.7		Restricted cash was acquired in conjunction with the CE
				Gen acquisition, and is comprised of debt service funds that
				are legally restricted.
Long-term receivables		85.0		Increase due to the acquisition of CE Gen.
Property, plant and equipment,		1,098.5		Acquisition of CE Gen and Genesee 3 as well as capital
net of accumulated depreciation				expenditures and construction activity during the period,
				parially offset by depreciation.
Goodwill		121.7		Acquisition of CE Gen in January 2003.
Net price risk management assets and liabilities		24.8		New trading contracts entered into during the first quarter of
(current and long-term)				2003.
Other assets		21.7		Increase in mark-to-market valuation of cross-currency interest
				rate swaps.
Short-term debt		102.8		Increased short-term debt to partially finance the acquisitions
				of CE Gen and Genesee 3 during the period.
Accounts payable and accrued liabilities		102.0		Increase due to the acquisition of CE Gen as well as increased
				capital expenditures in the quarter.
Long-term debt (including current		95.4		Increase primarily due to the acquisition of CE Gen.
portion)
Non-recourse long-term debt		693.1		Debt acquired on the acquistion of CE Gen.
(including current portion)
Future income tax liabilities		204.2		Increase primarily due to the acquisition of CE Gen.
(including current portion)
Non-controlling interests		44.5		Acquisition of CE GEN and decreased non-controlling interest
				in TA Cogen as a result of distributions in excess of net
				income.
Shareholders' equity		251.7		Net earnings and common share offering, partially offset by
				dividends and net redemption of common shares.

:P11

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

 

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 252 MW Campeche and 259 MW Chihuahua plants in Mexico which are scheduled to commence commercial operations in the second and third quarters of 2003, respectively. The McBride Lake Joint Venture has a further 53 MW under construction that is scheduled to commence commercial operations in the second quarter of 2003. Availability for the remainder of 2003 is expected to be slightly lower than the first quarter of 2003 due to planned maintenance. Production is expected to increase throughout the remainder of the year due to the increased capacity.

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Power prices

Electricity spot prices for the remainder of the year are generally expected to be lower than those in the first quarter in all markets primarily due to lower natural gas prices and seasonal factors such as increased hydro production.

Exposure to volatility in electricity prices is substantially mitigated through firm-price long-term electricity sales contracts. Exposure to volatility in gas prices is substantially mitigated by the flow-through of the costs of natural gas to customers in some of these contracts and the existence of price caps in certain natural gas supply contracts. For 2003, approximately 85 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.

Cost of production

Fuel and purchased power costs are expected to decrease per MWh from those experienced in the first quarter of 2003 due to lower natural gas prices. OM&A costs per MWh fluctuate by quarter and are dependent on the timing of maintenance activities. Excluding CE Gen, OM&A costs per MWh is expected to be consistent with that experienced in 2002 on an annual basis. CE Gen OM&A per MWh is expected to decline for the remainder of the year due to the timing of maintenance activities.

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.

For the remainder of 2003, Energy Marketing is expected to achieve comparable results to 2002.

Capital expenditures

Capital expenditures are expected to be in line with the $830 million forecasted for the year, which includes approximately $325 million for maintenance capital expenditures. This excludes the acquisition of CE Gen.

:P13

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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
		3 months ended March 31
		2003		2002
				(Restated,
				Note 1)
Revenues	$	616.2	$	419.7
Fuel and purchased power		(266.1)		(167.9)
Gross margin		350.1		251.8
Operating expenses
Operations, maintenance and administration		137.7		87.4
Depreciation and amortization		74.4		58.1
Taxes, other than income taxes		6.1		7.0
		218.2		152.5
Operating income		131.9		99.3
Other expense		(0.2)		(2.1)
Foreign exchange gain (loss)		(7.5)		0.6
Net interest expense		(34.7)		(19.2)
Earnings from continuing operations before income taxes
and non-controlling interests		89.5		78.6
Income tax expense		27.8		23.9
Non-controlling interests		7.5		6.4
Earnings from continuing operations		54.2		48.3
Earnings from discontinued operations (Note 3)		-		11.2
Net earnings		54.2		59.5
Preferred securities distributions, net of tax		5.5		5.5
Net earnings applicable to common shareholders	$	48.7	$	54.0
Common share dividends		(42.6)		(42.2)
Adjustment arising from normal course issuer bid		-		(4.5)
Retained earnings
Opening balance		884.7		881.1
Closing balance	$	890.8	$	888.4
Weighted average common shares outstanding in the period		172.4		169.0
Basic earnings per share
Continuing operations	$	0.28	$	0.25
Earnings from discontinued operations		-		0.06
Net earnings	$	0.28	$	0.31
Diluted earnings per share
Earnings from continuing operations	$	0.28	$	0.23
Earnings from discontinued operations		-		0.06
Net earnings	$	0.28	$	0.29
See accompanying notes.

:P14

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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
					3 months ended March 31
					2003		2002
						(Restated,
Operating activities							Note 1)
Net earnings				$	54.2	$	60.9
Depreciation and amortization					80.9		75.1
Loss (gain) on sale of property, plant and equipment					(0.5)		2.8
Future income taxes					7.9		3.1
Non-controlling interests					7.5		6.4
Site restoration costs incurred					(1.5)		(3.6)
Site restoration accretion					5.2		5.7
Unrealized loss from energy marketing activities					2.0		31.4
Foreign exchange loss (gain)					7.5		(0.6)
Other non-cash items					1.4		(7.3)
					164.6		173.9
Change in non-cash operating working capital balances					5.5		(44.9)
Cash flow from operating activities					170.1		129.0
Investing activities
Additions to property, plant and equipment					(292.9)		(269.3)
Acquisitions (Note 2)					(323.4)		-
Long-term receivables					0.4		4.3
Long-term investments					-		(2.9)
Deferred charges and other					1.3		(4.8)
Cash flow used in investing activities					(614.6)		(272.7)
Financing activities
Net increase in short-term debt					103.0		214.6
Issuance of long-term debt					133.1		30.9
Repayment of long-term debt					(1.1)		(1.2)
Dividends on common shares					(30.1)		(28.2)
Net proceeds on issuance of common shares (Note 7)					232.0		0.9
Redemption of common shares					-		(14.0)
Distributions on preferred securities					(8.9)		(9.2)
Distributions to subsidiary's non-controlling limited partner					(7.6)		(6.3)
Deferred financing charges and other					(0.2)		-
Cash flow from financing activities					420.2		187.5
Cash flow from operating, investing and financing activities					(24.3)		43.8
Effect of translation on foreign currency cash					(1.2)		(5.5)
Increase (decrease) in cash and cash equivalents					(25.5)		38.3
Cash and cash equivalents, beginning of period					143.3		62.0
Cash and cash equivalents, end of period				$	117.8	$	100.3
See accompanying notes.

:P15

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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)
				March 31,			Dec. 31,
				2003			2002
				Unaudited			Audited*
							(Restated,
ASSETS							Note 1)
Current assets
Cash and cash equivalents				$	117.8	$	143.3
Accounts receivable and other					606.3		468.4
Price risk management assets (Note 4)					142.3		157.8
Future income tax assets					20.2		18.7
Income taxes receivable					107.8		111.5
Materials and supplies					114.3		112.7
					1,108.7		1,012.4
Restricted cash (Note 2)					56.7		-
Investments (Note 5)					32.4		32.2
Long-term receivables (Note 6)					124.9		39.9
Property, plant and equipment
Cost					9,299.6		8,120.3
Accumulated depreciation					(2,170.7)		(2,089.9)
					7,128.9		6,030.4
Goodwill (Note 2)					178.2		56.5
Future income tax assets					61.5		72.2
Price risk management assets (Note 4)					47.4		60.7
Other assets					132.3		110.6
Total assets				$	8,871.0	$	7,414.9
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt				$	392.8	$	290.0
Accounts payable and accrued liabilities					574.2		472.2
Price risk management liabilities (Note 4)					132.7		173.8
Income taxes payable					13.3		-
Future income tax liabilities					19.0		17.1
Dividends payable					43.3		42.9
Current portion of long-term debt					363.3		355.4
Current portion of long-term debt - non-recourse (Note 2)					63.5		-
					1,602.1		1,351.4
Long-term debt					2,438.7		2,351.2
Long-term debt - non-recourse (Note 2)					629.6		-
Deferred credits and other long-term liabilities					455.3		452.8
Future income tax liabilities					604.4		402.1
Price risk management liabilities (Note 4)					38.1		50.6
Non-controlling interests					307.5		263.0
Preferred securities					451.5		451.7
Common shareholders' equity
Common shares (Note 7)					1,475.2		1,226.2
Retained earnings					890.8		884.7
Cumulative translation adjustment					(22.2)		(18.8)
					2,343.8		2,092.1
Total liabilities and shareholders' equity				$	8,871.0	$	7,414.9
Commitments and contingencies (Notes 5, 6 and 8)
See accompanying notes.

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

:P16

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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):

Balance sheets:	Dec. 31, 2002
Asset retirement asset	$	97.3
Accumulated depreciation on asset retirement asset		27.3
Property, plant and equipment		(101.9)
Accumulated depreciation		(27.2)
Asset retirement obligations, included in deferred credits and other long-term liabilities		(87.4)
Long-term future income tax liabilities		30.2
Opening retained earnings		42.8
	3 months ended
Statements of earnings:	March 31, 2002
Site restoration accrual, included in fuel and purchased power	$	(9.6)
Depreciation and amortization expense		0.3
Depreciation and amortization expense, included in fuel and purchased power		(0.4)
Accretion expense, included in depreciation and amortization expense		5.7
Current income tax expense		1.4
Net earnings applicable to common shareholders	$	2.6

:P17

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

Balance Jan. 1, 2002	$	232.2
Liabilities incurred in period		28.5
Liabilities settled in period		(14.5)
Accretion expense		18.7
Revisions in estimated cash flows		-
Balance Jan. 1, 2003		264.9
Liabilities incurred in period		4.0
Liabilities settled in period		(1.6)
Accretion expense		5.2
Acquisition of CE Gen		5.8
Revisions in estimated cash flows		-
Balance, March 31, 2003	$	278.3

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 quarter of 2003.

Previously, the intrinsic 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 March 31		2003		2002
Reported net earnings applicable to common shareholders	$	48.7	$	54.0
Compensation expense		0.6		0.7
Pro forma net earnings applicable to common shareholders	$	48.1	$	53.3
Reported basic earnings per share	$	0.28	$	0.31
Compensation expense per share		-		-
Pro forma basic earnings per share	$	0.28	$	0.31
Reported diluted earnings per share	$	0.28	$	0.29
Compensation expense per share		-		-
Pro forma diluted earnings per share	$	0.28	$	0.29

The accounting treatment for the corporation's performance share ownership plan remains unchanged. Under this plan, compensation expense recognized in the three months ended March 31, 2003 was $2.1 million (2002 - $2.2 million). Compensation expense is included in operations, maintenance and administration expense in the statements of earnings.

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 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-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.

:P18

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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) for US$240.0 million of cash (Cdn$366.6 million). The acquisition was accounted for using the purchase method of accounting. CE Gen is controlled jointly by TransAlta and MidAmerican Energy Holdings Company (MidAmerican). As such, the financial results of CE Gen subsequent to the acquisition date are proportionately consolidated with those of TransAlta, and are included in the Generation segment.

The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition. Due to the timing of the purchase, it was impractical to finalize the allocation process without causing undue delay in issuing the financial statements for the period in which the combination occurred. Therefore, the allocations in the purchase equation may be adjusted when the process is completed during the second quarter of 2003.

Net assets acquired at assigned values:
Working capital, including cash of $43.2 million	$	61.0
Restricted cash		57.9
Current income tax receivable		2.4
Property, plant and equipment		1,025.1
Goodwill		125.8
Note receivable		90.0
Non-recourse long-term debt, including current portion		(717.4)
Deferred credits and other long-term liabilities		(17.6)
Future income tax liability		(216.0)
Non-controlling interests		(44.6)
Total	$	366.6
Consideration:
Cash	$	366.6

The restricted cash is comprised of debt service funds which are legally restricted, and require the maintenance of specific minimum balances equal to the next debt service payment, and amounts restricted for capital and maintenance expenditures.

The non-recourse debt consists of project financing debt, debt securities and senior secured bonds. The related assets have been pledged as security for the project financing debt. Maturity dates range from 2004 to 2008, and interest rates range from LIBOR plus 1.25 per cent to 8.31 per cent. The debt securities are non-recourse, have maturity dates ranging from 2005 to 2018 and interest rates ranging from 7.37 per cent to 8.30 per cent. A portion of the repayment of these debt securities has been guaranteed by MidAmerican and is included in notes receivable, with associated interest. The senior secured bonds are also non-recourse to the corporation, bear interest at 7.42 per cent, and are due in 2018.

On Dec. 6, 2002, the corporation completed a step acquisition of Vision Quest Windelectric Inc. (Vision Quest). The purchase price was finalized in the first quarter of 2003, and did not change from that presented in the 2002 audited consolidated financial statements.

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.

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

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3 months ended March 31		2003		2002
Revenues	$	-	$	41.5
Operating expenses		-		(20.5)
Operating income		-		21.0
Net interest expense		-		(1.7)
Earnings before income taxes		-		19.3
Income taxes		-		(8.1)
Earnings from discontinued operations	$	-	$	11.2

At March 31, 2003 and Dec. 31, 2002 all of the corporation's discontinued operations had been sold.

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. Physical transmission contracts are now accounted for on an accrual basis in accordance with changes in Canadian and U.S. GAAP. Previously these contracts were valued using quoted market prices and a spread option valuation model.

The following table illustrates movements in the fair value of the corporation's price risk management assets (liabilities) during the three months ended March 31, 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		15.5		9.0		24.5
Changes in values attributable to market price and other market changes		(2.0)		-		(2.0)
Contracts realized, amortized or settled during the period		4.0		(1.7)		2.3
Net price risk management assets outstanding at March 31, 2003	$	10.0	$	8.9	$	18.9

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

											2008 and
		2003		2004		2005		2006		2007	thereafter			Total
Prices actively quoted	$	1.1	$	4.2	$	3.2	$	2.1	$	1.5	$	-	$	12.1
Prices based on models		(2.8)		0.7		-		-		-		-		(2.1)
	$	(1.7)	$	4.9	$	3.2	$	2.1	$	1.5	$	-	$	10.0
Electrical transmission
rights (accrual)		6.7		2.2		-		-		-		-		8.9
	$	5.0	$	7.1	$	3.2	$	2.1	$	1.5	$	-	$	18.9
The corporation's trading positions were as follows:
Trading positions				Fixed price payor				Fixed price receiver					Maximum term
3 months ended March 31, 2003		Units (000s)		notional amounts				notional amounts					in months
Electricity			MWh			23,835.5				23,618.6				42
Natural gas			GJ			63,522.5				75,041.0				33

The corporation's electrical transmission contracts trading position was 29.9 million MWh at March 31, 2003 compared to 18.1 million MWh at Dec. 31, 2002.

:P20

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5 . I N V E S T M E N T S

On March 4, 2003, the corporation agreed to sell its 8.82 per cent interest in the Goldfields Gas Pipeline for proceeds of AU$24.1 million (approximately Cdn$21.7 million), which approximates book value. The transaction is expected to close on April 30, 2003.

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

On Dec. 12, 2002, a U.S. Federal Energy Regulatory Commission (FERC) Administrative Law Judge issued proposed findings of fact that TransAlta be entitled to receive approximately US$44.0 million for electricity sales to California. On March 26, 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. Until a final ruling is made with respect to these issues, TransAlta will maintain the provision for these receivables.

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 March 31, 2003, the corporation had 185.7 million (Dec. 31, 2002 - 169.8 million) common shares issued and outstanding plus outstanding employee stock options to purchase an additional 3.2 million shares (Dec. 31, 2002 - 3.0 million).

On March 21, 2003, the corporation issued 15.0 million common shares for gross proceeds of $240.0 million, net of 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, which was exercised April 17, 2003 and is expected to close on April 25, 2003.

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 quarter of 2003.

8 . C O N T I N G E N C I E S

On May 8, 2002, FERC requested that 150 sellers of wholesale electricity and ancillary services to the California electricity market, including TransAlta, respond to questions regarding their trading strategies in California during 2000 and 2001. On March 26, 2003 FERC issued its ruling on this investigation;TransAlta was cleared of any wrongdoing.

On Nov. 20, 2002, FERC issued an order permitting parties to conduct discovery into market manipulation by various sellers during the western power crisis of 2000 and 2001. Following such discovery, parties submitted directly to FERC additional evidence and proposed new and/or modified findings of fact. TransAlta received and responded to several rounds of discovery requests from various parties in California and the Pacific Northwest. FERC has not yet ruled on the manipulation allegations made by and against various parties on March 3, 2003 at the end of the 100-day discovery process. No impact is anticipated, as TransAlta is not aware of any allegations made directly against it and does not expect to be implicated in manipulation findings, if any.

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.

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

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 as a whole.

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9 . R E L A T E D  P A R T Y  T R A N S A C T I O N S

CE Gen has entered into contracts with related parties to provide administrative and maintenance services.

1 0 .. 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 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 interest (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 statement of earnings by deducting earnings and gains from discontinued operations, other income (expense) and foreign exchange gains (losses) and adding net interest expense, income taxes and non-controlling interests to net earnings applicable to common shareholders.

I. Earnings information
										Unaudited
				Energy
3 months ended March 31, 2003	Generation			Marketing			Corporate				Totals
Revenues	$	605.5		$	10.7		$	-		$	616.2
Fuel and purchased power		(266.1)			-			-			(266.1)
Gross margin		339.4			10.7			-			350.1
Operations, maintenance and administration		118.1			2.1			17.5			137.7
Depreciation and amortization		69.3			0.8			4.3			74.4
Taxes, other than income taxes		6.1			-			-			6.1
EBIT before corporate allocations		145.9			7.8			(21.8)			131.9
Corporate allocations		(19.4)			(2.4)			21.8			-
EBIT	$	126.5		$	5.4		$	-			131.9
Other expense											(0.2)
Foreign exchange loss											(7.5)
Net interest expense											(34.7)
Earnings from continuing operations before income taxes and non-controlling interests										$	89.5
										Unaudited
				Energy
3 months ended March 31, 2002	Generation			Marketing			Corporate				Totals
Revenues	$	420.8		$	(1.1)		$	-		$	419.7
Fuel and purchased power		(167.9)			-			-			(167.9)
Gross margin		252.9			(1.1)			-			251.8
Operations, maintenance and administration		71.6			2.6			13.2			87.4
Depreciation and amortization		51.9			0.7			5.5			58.1
Taxes, other than income taxes		7.0			-			-			7.0
EBIT before corporate allocations		122.4			(4.4)			(18.7)			99.3
Corporate allocations		(16.6)			(2.1)			18.7			-
EBIT	$	105.8		$	(6.5)		$	-			99.3
Other expense											(2.1)
Foreign exchange gain											0.6
Net interest expense											(19.2)
Earnings from continuing operations before income taxes and non-controlling interests										$	78.6

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II. Selected balance sheet information
						Energy
March 31, 2003			Generation			Marketing			Corporate					Total
Goodwill			$	148.9		$	29.3		$	-		$		178.2
Total segment assets			$	7,905.5		$	327.8		$	637.7		$	8,871.0
							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
III. Selected cash flow information
				Energy					Discontinued
3 months ended March 31, 2003	Generation		Marketing			Corporate			Operations					Total
Capital expenditures	$	289.8	$	2.1		$	1.0		$	-		$		292.9
Acquisitions	$	323.4	$	-		$	-		$	-		$		323.4
				Energy					Discontinued
3 months ended March 31, 2002	Generation		Marketing			Corporate			Operations					Total
Capital expenditures	$	253.0	$	1.3		$	1.7		$	13.3		$		269.3
IV. Reconciliation
Depreciation and amortization expense (D&A) per statement of cash flows
3 months ended March 31										2003				2002
D&A expense for reportable segments									$	74.4		$		58.1
Mining equipment depreciation, included in fuel and purchased power										10.1				10.1
Site restoration accretion, included in D&A expense										(5.2)				(5.7)
Discontinued operations										-				11.7
Other										1.6				0.9
									$	80.9		$		75.1

1 2 .. 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:

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A . E A R N I N G S  A N D  E P S
3 months ended March 31		Reconciling items							2003			2002
Earnings from continuing operations - Canadian GAAP								$	54.2		$	48.3
Effect of asset retirement obligations adoption - Canadian GAAP		(XI)							-			(2.6)
Derivatives and hedging activities, net of tax		(I)							2.7			2.4
Start-up costs, net of tax		(II)							(0.2)			(2.2)
Preferred securities distributions, net of tax		(III)							(5.5)			(5.5)
Amortization of debt extinguishment, net of tax		(IV)							0.3			0.2
Amortization of pension transition adjustment		(VI)							(1.4)			(1.2)
Earnings from continuing operations - U.S. GAAP									50.1			39.4
Earnings from discontinued operations - Canadian and U.S. GAAP									-			11.2
Net earnings before change in accounting principle - U.S. GAAP									50.1			50.6
Cumulative effect of change in accounting principle, net of tax		(XI)							52.5			-
Net income - U.S. GAAP								$	102.6		$	50.6
Foreign currency cumulative translation adjustment		(I), (VIII)							(19.7)			(2.7)
Net gain (loss) on derivative instruments		(I), (VIII)							(16.0)			6.9
Comprehensive income - U.S. GAAP								$	66.9		$	54.8
Basic EPS - U.S. GAAP
Earnings from continuing operations								$	0.29		$	0.24
Cumulative effect of change in accounting principle									0.31			-
Earnings from discontinued operations									-			0.06
Net earnings								$	0.60		$	0.30
Diluted EPS - U.S. GAAP
Earnings from continuing operations								$	0.29		$	0.22
Cumulative effect of change in accounting principle									0.31			-
Earnings from discontinued operations									-			0.06
Net earnings								$	0.60		$	0.28
B . B A L A N C E  S H E E T  I N F O R M A T I O N
	Reconciling	Canadian			March 31, 2003			Canadian			Dec. 31, 2002
	items		GAAP		U.S. GAAP				GAAP		U.S. GAAP
Assets
Current derivative assets	(I)		$                 -		$	9.8		$	-		$	8.3
Accounts receivable	(IX)		748.6			745.9			626.2			624.7
Income taxes receivable	(I), (II), (IV)		107.8			115.7			111.5			120.7
Investments	(X)		32.4			274.9			32.2			271.9
Property, plant and equipment, net	(II)		7,128.9			7,136.8			6,030.4			6,048.2
Long-term derivative asset	(I)		-			47.9			-			53.3
Other assets	(I), (II), (III)		132.3			69.8			110.6			57.4
Liabilities
Accounts payable and accrued liabilities	(VI)		707.0			673.9			646.0			610.5
Current derivative liability	(I)		-			17.9			-			27.6
Long-term debt	(I), (III), (X)		3,068.3			3,803.3			2,351.2			3,087.6
Deferred credits and other long-term liabilities	(I), (IV)		455.5			479.8			452.8			614.3
Long-term derivative liabilities	(I)		-			146.6			-			133.1
Future or deferred income tax liability	(I), (II), (III), (IV), (V), (VI)		604.4			552.4			402.1			308.9
Equity
Preferred securities	(III)		451.5			-			451.7			-
Common shares	(IX)		1,475.2			1,472.5			1,226.2			1,224.7
Retained earnings	(I), (II), (IV), (V), (VI)		890.8			894.9			884.7			786.5
Cumulative translation adjustment	(I), (VIII)		(22.2)			-			(18.8)			-
Accumulated other comprehensive income	(I), (VIII)		-			(159.4)			-			(123.7)

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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 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 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.

The corporation's cash flow hedges resulted in a net gain of $nil related to the ineffective portion of its hedging instruments as well as the portion of the hedging instrument excluded from the assessment of hedge effectiveness.

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 amortized over five years, the term of the hedged debt.

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 OCI over 10 years, the term of the hedged debt.

Over the next 12 months, the corporation estimates that $13.6 million of net losses that arose from cash flow hedges will be reclassified from OCI to net earnings. The corporation also estimates that $4.3 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 months ended March 31, 2003, the corporation recognized a net after-tax loss of $19.7 million (2002 - $2.7 million) on its net investment hedges, included in OCI.

The corporation recognized income of $nil (2002 - $nil), 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-market accounting.

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(v) Other Hedging Activities

The corporation recognized pre-tax income of $3.4 million (2002 - $nil) 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.

IV. Debt extinguishment

Under U.S. GAAP, the premium on redemption of long-term debt related to the limited partnership transaction was recorded as an extraordinary loss 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:

	March 31,			Dec. 31,
	2003			2002
Future income tax liability (net) under Canadian GAAP	$	(541.7)	$	(328.3)
Derivatives		67.5		48.8
Start-up costs		(2.3)		(2.3)
Preferred securities		(6.1)		(6.2)
Debt extinguishment		9.1		9.7
Employee future benefits		(16.2)		(17.2)
	$	(489.7)	$	(295.5)
Comprised of the following:
	March 31,			Dec. 31,
		2003		2002
Current deferred income tax assets	$	20.2	$	18.7
Long-term deferred income tax assets		61.5		72.2
Current deferred income tax liabilities		(19.0)		(17.1)
Long-term deferred income tax liabilities		(552.4)		(369.3)
	$	(489.7)	$	(295.5)
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.

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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.

VIII. Other comprehensive income
The changes in the components of OCI were as follows:
3 months ended March 31		2003		2002
Net gain (loss) on derivative instruments:
Unrealized gains (losses), net of taxes of $12.4 million (2002 - $0.4 million)	$	(16.9)	$	5.9
Reclassification adjustment for losses included in net income, net of taxes of $0.6 million (2002 - $6.3 million)		0.9		1.0
Net gain (loss) on derivative instruments		(16.0)		6.9
Translation adjustments		(19.7)		(2.7)
Other comprehensive income (loss)	$	(35.7)	$	4.2
The components of AOCI were:
	March 31,			Dec. 31,
		2003		2002
Net loss on derivative instruments	$	(96.0)	$	(80.0)
Registered pension alternate minimum liability		(1.7)		(1.7)
Translation adjustments		(61.7)		(42.0)
Accumulated other comprehensive loss	$	(159.4)	$	(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 March 31, 2003 was $1.5 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.

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. Had the change in accounting principle been applied retroactively, basic and diluted earnings per share for the three months ended March 31, 2002 would have been $0.31 and $0.29 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			March 31, 2003		Dec. 31, 2002
Closing market price			$	15.80	$	17.11
Price range (last 12 months)
		High	$	23.95	$	23.95
		Low	$	15.36	$	16.69
Debt/invested capital (including non-recourse debt)				54.5%		50.4%
Debt/invested capital (excluding non-recourse debt)				49.3%		50.4%
Return on common shareholders' equity				3.4%		3.9%
Return on invested capital				3.8%		4.2%
Book value per share			$	12.62	$	12.43
Cash dividends per share			$	1.00	$	1.00
Price/earnings ratio (times)				36.8		46.0
Dividend payout ratio				228.0%		212.3%
Interest coverage (times)				1.3		1.5
Interest coverage including preferred securities (times)				1.1		1.2
Dividend coverage (times)				2.7		2.5
Dividend yield				6.3%		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 -	A standard unit for measuring the quantity of heat energy required to heat one pound of water
	one degree 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.
Spark spread -	A measure of gross margin per MW, sales price less cost of fuel.

 

 

TransAlta Corporaton 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

F O R M O R E I N F O R M A T I O N :   Media inquiries: Nadine Walz, 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

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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: April 24, 2003

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CERTIFICATIONS

I, Stephen G. Snyder, certify that:

1.

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

2.

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;

3.

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;

4.

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;

5.

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

6.

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:

March 24, 2003

/s/ Stephen G. Snyder

Stephen G. Snyder

President and Chief Executive Officer

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I, Ian Bourne, certify that:

1.

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

2.

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;

3.

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;

4.

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;

5.

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

6.

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: March 24, 2003

/s/ Ian Bourne

Ian Bourne

Executive Vice President and

Chief Financial Officer