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

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.

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

On April 18, 2002, TransAlta Corporation announced its first quarter 2002 results. A copy of the company's press release and the report for the quarter ended March 31, 2002 are attached as Exhibits 1 and 2, respectively.

In addition, on April 18, 2002, the company conducted its quarterly earnings conference call. During that call, the information contained in exhibit 99-1 was discussed and the company made the following additional announcements.

The company is making good progress on cost reduction targets and made headway in the quarter on both fuel and overhead costs. About $80 to $90 million of the previously announced $150 million target has been identified and the company expects to see the impact of these changes in the run rate in the second half of the year.

The company reiterated that a 10% increase in earnings from operations for 2002 is achievable if an economic recovery and an upturn in prices occur in the second half of the year.

Operations, maintenance and administration costs for the year are expected to be below last year's Cdn$7.77/MWh.

Debt to capitalization was 53.8% for the quarter and is expected to decrease to 45% following the closing of the Transmission sale, expected on April 29. This is well below the company's target of 50%.

The overall availability rate for the year is expected to be 89-90%, with availability lower in the second and third quarters and higher in the fourth quarter of the year.

EXHIBITS

Exhibit 1	Press Release dated April 18, 2002.
Exhibit 2	Quarterly report for the three-month period ended March 31, 2002, which includes Management's Discussion and Analysis and consolidated financials statements.

CALGARY, Alberta (April 18, 2002) TransAlta Corporation (TSE: TA; NYSE: TAC) today announced first quarter 2002 earnings from continuing operations of $40.2 million ($0.24 per share), compared to $55.9 million ($0.33 per share) for the same period in 2001. Operating cash flow excluding working capital changes improved from $137.3 million in the first quarter of 2001 to $171.3 million. Financial results reflect improved plant operating performance, offset by lower power prices and Energy Marketing results.

"Our power plant operating performance was strong, with availability levels and production output up. Excellent progress was also made in reducing costs and operating cash flow," said Steve Snyder, TransAlta's president and CEO. "Energy Marketing results were disappointing, as they encountered difficult market conditions compared to last year."

Net earnings for the quarter, including discontinued operations, were $51.4 million ($0.30 per share) compared to 2001 earnings of $67.6 million ($0.40 per share). Cash flow from operating activities, including changes in working capital was $129.0 million, compared to $388.7 million in first quarter 2001.

Discontinued operations in both years include net earnings from the Transmission operation; results for 2001 also include the Edmonton Composter operation.

Received regulatory approval for the sale of the majority of its regulated Alberta transmission business to AltaLink. The transaction, which was announced in July 2001, is anticipated to close April 29 and generate proceeds of approximately $850 million, for an after-tax gain of approximately $100 million ($0.59 per share).

Received regulatory approval for the company's proposed 900-megawatt expansion to its existing Keephills facility. TransAlta is updating its feasibility study factoring in the impact of various market and environmental factors included in the regulatory approval. The company expects to announce its plans in second half 2002.

Announced a normal course issuer bid to repurchase up to three million shares for cancellation beginning Feb. 21, 2002. To date, 105,000 shares have been purchased on the TSE under the new program. TransAlta purchased for cancellation 2,156,100 of its common shares through a previously announced normal course issuer bid that expired in February 2002.

Announced that the Canadian Clean Power Coalition (CCPC), of which it is a member, will research, develop, construct and operate a full-scale demonstration plant by 2007 to test the technical, environmental and economic viability of new clean coal technology for retrofit onto an existing coal plant.

In order to improve plant performance and fulfill environmental obligations, the second of two scrubbers is being installed at the Centralia plant. The planned outage of Unit 1, which began April 15 and will last approximately nine weeks, includes a turbine upgrade and scheduled maintenance. This outage was built into sales contracts and earnings forecasts. Once complete, it will increase total plant capacity to 1404 MW, up from 1340 MW when purchased in May 2000.

The force majeure decision related to TransAlta's Wabamun outage is currently in binding arbitration, with a decision expected in first half 2002. The 300 MW Wabamun four unit was shut down in August 2000 due to cracks in its boiler tubing and returned to service in June 2001. Under the force majeure article of the Power Purchase Arrangement, TransAlta believes that the company should not be obligated to repay the cost of obtaining an alternative source of electricity during the period of repair and therefore no specific amount has been provided for potential obligations.

In fourth quarter 2000, TransAlta made a provision of US$29 million against US$58 million owing from the California Independent System Operator and the California Power Exchange. No change has been made to the provision due to continuing uncertainty in California.

TransAlta Corporation is Canada's largest non-regulated electric generation and marketing company, with more than $8 billion in assets and 9,000 megawatts of capacity either in operation or under construction. As one of North America's lowest-cost operators, our growth is focused on developing coal- and gas-fired generation in Canada, the U.S. and Mexico.

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

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

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

This report contains forward-looking statements, including statements regarding the business and anticipated financial performance of TransAlta. These statements involve known and unknown risks and relate to future events, future financial performance and projected business results. 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 forward-looking statements are subject to a number of uncertainties that may cause actual results to differ materially from those contemplated in the forward-looking statements. Some of the factors that could cause such differences include 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 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 United States standard setters.

The results of operations are organized by consolidated results and by business segments. TransAlta has two business segments: Generation and Energy Marketing. A third business segment, Independent Power Projects (IPP), was combined with the Generation segment effective Jan. 1, 2002, following changes to TransAlta's organizational structure. A fourth business segment, Transmission, was reclassified as a discontinued operation following the announcement on July 4, 2001 of the agreement to dispose of the business. The corporate group provides finance, treasury, legal, human resources and other administrative services to the business segments. The business segments assume responsibility for their operating results measured as earnings before interest, taxes and non-controlling interests (EBIT). EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with Canadian GAAP as an indicator of the corporation's performance or liquidity. TransAlta's EBIT is not necessarily comparable to a similarly titled measure of another company. EBIT can be determined from the consolidated statements of earnings by adding prior period regulatory decisions to operating income.

Corporate overheads that are not directly attributable to discontinued operations are allocated to the business segments. Prior period amounts have been restated.

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

Net earnings from continuing operations in the first quarter of 2002 compared to the first quarter of 2001 reflect increased production and availability offset by lower pricing and reduced energy marketing results. Cash flow before changes in non-cash working capital and unrealized energy marketing gains and losses was comparable to the same period in 2001.

GENERATION: Owns and operates coal-, hydro- and gas-fired plants and related mining operations, with a total generating capacity of 7,402 MW.

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

2002

2001

RESULTS Generation's annual revenues are derived from the production of electricity, of which approximately 90 per cent are based upon contracted prices, including capacity payments, and approximately 10 per cent are subject to market pricing and from the provision of other ancillary services such as steam and system support. The percentage allocations are subject to seasonal variations.

Revenues received under long-term contractual arrangements are not subject to major fluctuations in the spot price for electricity. These contracts covered approximately 91 per cent of production in the first quarter of 2002 (2001 - 88 per cent) at an average price of $34.70 per megawatt hour (MWh) (2001 - $33.20 per MWh) and have remaining terms ranging from one to 23 years. The remaining nine per cent of first quarter of 2002 production (2001 12 per cent) was subject to market pricing at an average price of $34.48 per MWh (2001 - $212.09 per MWh).

Availability for the first quarter of 2002 was 92.5 per cent compared to 88.0 per cent in the first quarter of 2001. The increase is primarily a result of improved performance at the Centralia and Poplar Creek plants and the return to service of Wabamun unit four. Generation's production increased to 11,614 GWh from 11,240 GWh in the same period of 2001, reflecting the increased availability at the above plants. Timing of maintenance in the first quarter of 2002 as well as lower hydro production partially offset these production gains.

As shown in the above table, for the first quarter of 2002, spot prices and spark spreads (sales price less cost of fuel) in both Alberta and the Pacific Northwest markets declined substantially compared to the same period of 2001. These price declines were driven by a return to a more rational market. Within this market, prices were softer due to reduced demand as a result of lower economic activity, an unseasonably warm January and February 2002, additional generating capacity added to these markets and lower gas prices.

As a result of the factors discussed above, revenue for the first three months of 2002 decreased by $234.5 million or 36 per cent from the same period of 2001 to $420.8 million from $655.3 million. Correspondingly, total revenue per MWh decreased to $36.23 per MWh in the first quarter of 2002 compared to $58.30 per MWh in the same period of 2001.

Fuel and purchased power decreased by 58 per cent to $173.8 million ($14.96 per MWh) from $411.4 million ($36.60 per MWh). Purchased power is the cost incurred to acquire electricity from the market to fulfill contracted commitments during planned and unplanned outages. Any electricity not required to fulfill these commitments is sold back into the market at spot prices. In the first quarter of 2001, lower availability at the Centralia plant resulted in the purchase of 516 GWh of electricity totaling $242.4 million. Of this amount, $152.7 million (340 GWh at an average price of $447.94 per MWh) was used to fulfill delivery commitments and $89.7 million (175 GWh at an average price of $511.51 per MWh) was not required and sold back into the spot market. In 2002, improved availability and lower market prices resulted in a reduction in purchased power costs to $5.6 million (192 GWh at an average price of $29.40 per MWh).

Fuel costs, excluding purchased power, were $168.2 million ($14.48 per MWh) in the first quarter of 2002, compared to $169.0 million ($15.04 per MWh) in 2001, reflecting higher production ($5.5 million) that was more than offset by lower transmission charges, cost reduction initiatives and decreased natural gas prices ($6.3 million).

Operations, maintenance and administration (OM&A) expense increased by 14 per cent to $71.6 million ($6.16 per MWh) in the first quarter of 2002 from $62.7 million ($5.58 per MWh) in the first quarter of 2001 primarily as a result of the timing of expenditures related to additional major maintenance in the quarter compared to the same quarter in the previous year and higher business development activity to support growth initiatives. The cost reduction initiatives identified in the fourth quarter of 2001 were being implemented during the first quarter of 2002. The benefits of these initiatives should begin to be realized during the second half of the year and beyond.

Depreciation and amortization increased by 18 per cent to $50.1 million ($4.31 per MWh) from $42.5 million ($3.78 per MWh) as a result of 2001 capital expenditures.

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

Trading volumes during the quarter increased to 21,200 MWh of electricity traded in 2002 compared to 3,490 MWh in 2001 and increased to 59.8 million gigajoules (GJ) of gas traded in 2002 compared to 12.9 million GJ in 2001. The increases are a result of increased real-time and term trading activities.

Revenues decreased by $88.7 million to $646.6 million in the first quarter of 2002 compared to $735.3 million in the first quarter of 2001 as increased trading volumes were more than offset by lower market prices.

Gross margin decreased to a loss of $1.1 million for the first three months of 2002 compared to income of $51.2 million for the same period of 2001 due to significantly lower market prices and reduced market liquidity, particularly in the Pacific Northwest. In the first quarter of 2001, the average market price in the Pacific Northwest was US$264 per MWh (approximately Cdn$419 per MWh) compared to US$25 per MWh (approximately Cdn$40 per MWh) in the first quarter of 2002. The 2001 prices were influenced by the process of deregulation in California exacerbated by a drought in the Pacific Northwest and historically high natural gas prices.

Market liquidity has been adversely affected by the collapse of Enron Corporation, the industry's largest trader, concerns about the credit quality of the major marketers and the loss of confidence of wholesale customers. While the market for shorter-term transactions has continued to function reasonably well, the liquidity in the medium- and longer-term transactional markets has declined significantly during the quarter. In February and March 2002, the escalation of unrest in the Middle East and harsh winter weather in March 2002, drove natural gas prices significantly above fundamental support levels and previous market predictions, however natural gas prices remained lower than in the first quarter of 2001. TransAlta had anticipated first quarter electricity price deterioration, however electricity prices followed escalating natural gas prices and certain of TransAlta's trading positions for late 2002 and early 2003 were adversely affected. The lack of liquidity in the medium- to longer-term markets due to Enron's collapse made it difficult to exit these positions at minimal cost. However, TransAlta's financial and risk management controls, including stop-loss provisions, functioned as designed and minimized the extent of losses incurred and were effective in preventing further losses. As a result of the significantly diminished liquidity in the medium- to longer-term markets, TransAlta will continue to have a low level of activity in these markets until liquidity returns.

OM&A expense for the Energy Marketing segment decreased to $2.6 million in the first three months of 2002 compared to $4.4 million in the same period of 2001 due primarily to decreased salaries and incentives.

Depreciation and amortization decreased to $0.7 million from $1.6 million in the prior period, as goodwill arising from previous acquisitions, previously recorded as acquired intangibles, is no longer being amortized in accordance with this new accounting standard issued by the Canadian Institute of Chartered Accountants.

With the exception of transmission contracts, the fair value of all energy trading activities is based on quoted market prices. The fair value of transmission contracts is based on quoted market prices and a spread option valuation model. In the first quarter of 2002, realized and unrealized changes in the fair value of energy trading contracts, exclusive of hedging transactions, were income of $27.7 million and a loss of $28.8 million, respectively.

Valuations of energy trading contracts existing at March 31, 2002, exclusive of hedging transactions, maturing over each of the next five calendar years and thereafter are as follows:

Energy Marketing's trading receivables and payables include invoiced amounts for settled transactions (realized) and the fair value of unsettled transactions (unrealized), based on current market prices.

NET INTEREST EXPENSE, FOREIGN EXCHANGE, OTHER EXPENSE, NON-CONTROLLING INTERESTS AND PREFERRED SECURITIES DISTRIBUTIONS

Net interest expense (net of interest income, capitalized interest, and amounts allocated to discontinued operations) decreased to $19.2 million in the first three months of 2002 compared to $33.9 million in the comparable period of 2001. This resulted from the impact of lower short-term interest rates on a higher portion of debt, interest income of $3.3 million earned on the deferred accounts receivable related to the discontinued Alberta Distribution and Retail operation and interest earned on the $11.0 million Temporary Suspension Regulation recorded in the fourth quarter of 2001. Increased debt was used to fund capital expenditures and increased assets under construction, and the related interest was capitalized.

The decrease in earnings attributable to non-controlling interests reflects the redemption of the preferred shares of TransAlta Utilities Corporation for $121.6 million in September 2001, resulting in lower subsidiary preferred share dividends, partially offset by increased earnings from the 49.99% non-controlling interest in TransAlta Cogeneration, L.P. due to the addition of the Fort Saskatchewan plant in the third quarter of 2001.

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

INCOME TAXES

3 months ended March 31	2002	2001
Income taxes	$ 22.5	$ 53.0
Effective tax rate	30.2%	44.6%

Income taxes decreased to $22.5 million in the first quarter of 2002 compared to $53.0 million for the same period in 2001, reflecting decreased pre-tax earnings. The effective income tax rate, expressed as a percentage of earnings from continuing operations before income taxes and non-controlling interests, decreased to 30.2 per cent from 44.6 per cent due to lower earnings from higher tax rate jurisdictions, lower Federal and Alberta tax rates and as a result of the corporation's financing structures, the benefits of which do not fluctuate with earnings.

DISCONTINUED OPERATIONS

3 months ended March 31	2002	2001
Transmission operation	$ 11.2	$ 11.4
Edmonton Composter operation	-	0.3
	$ 11.2	$ 11.7

TransAlta entered into an agreement on July 4, 2001 to sell its Transmission operation for proceeds of approximately $850 million, which will result in an after-tax gain of approximately $100 million. Regulatory approval of the sale was received on March 28, 2002, and the transaction is expected to close on April 29, 2002.

The discontinued Transmission operation contributed after-tax earnings of $11.2 million in the first three months of 2002 consistent with after-tax earnings of $11.4 million in the first three months of 2001.

In June 2001, TransAlta sold its Edmonton Composter for proceeds of $97.0 million, which approximated its book value. After-tax earnings from the discontinued operation were $0.3 million for the three months ended March 31, 2001.

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

On April 16, 2002, the Alberta Energy and Utilities Board (EUB) rendered a negative decision of $2.5 million after-tax with respect to TransAlta's hydro bidding strategy in 2000. The impact of regulatory decisions is recorded when the effect of such decisions is known, without adjustment to the financial statements of prior periods. Consequently, the adjustment will be recorded in the second quarter of 2002.

The key factors affecting the financial results for 2002 continue to be the availability of and production from generating assets, the pricing applicable to non-contracted production, the costs of production and the volume and gross margin applicable to energy marketing activities.

Availability and production for the second quarter will be negatively impacted by scheduled maintenance and a nine-week scheduled outage at one of the Centralia units to increase the plant capacity and install the second scrubber as part of the environmental obligations that were assumed when the plant was purchased. Availability and production for the third quarter will also be reduced due to scheduled maintenance, and the fourth quarter is expected to be similar to the first quarter. Additional production is expected from the 248 MW gas-fired Big Hanaford and 650 MW Sarnia plants, which are scheduled to commence commercial operations in the third quarter of 2002 and by the first quarter of 2003, respectively.

Electricity spot prices are expected to increase from the levels experienced in the first quarter of 2002. The extent of the recovery of electricity prices will be dependent on the price of natural gas and the level of increased demand due to an anticipated economic recovery which is forecasted for the second half of 2002.

TransAlta is continuing its focus on reducing fuel and OM&A expenses. The areas for reductions were identified in the fourth quarter of 2001, and are currently being implemented. The results of these initiatives are expected to become apparent in the second half of the year and beyond.

Energy Marketing trading volumes are expected to continue at the level experienced in the first quarter of 2002. Gross margins on trading activities are expected to recover due to lower activity in the medium- and longer-term markets in reaction to the reduced liquidity in these markets. However, they are not expected to recover to the levels experienced in 2001.

Assets under construction at March 31, 2002 totaled $1,276.9 million and consisted primarily of the Big Hanaford and Sarnia plants discussed above and the 252 MW Campeche and 259 MW Chihuahua plants, which are scheduled to commence commercial operations in the first and third quarter of 2003, respectively.

In February 2002, the EUB approved the previously announced 900 MW expansion of the Keephills plant. TransAlta is now updating the project feasibility study factoring in the impact of Alberta's transmission constraints, environmental conditions placed on the approval by the EUB and market conditions is. The corporation expects to announce its plans in the second half of the year.

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 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 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 CORPORATION
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS
(in millions of Canadian dollars except per share amounts)
							Unaudited
							3 months ended March 31

	2002	2001
Revenues	$ 1,067.4	$ 1,390.6
Trading purchases	(647.7)	(684.1)
Fuel and purchased power	(173.8)	(411.4)
Gross margin	245.9	295.1
Operating expenses
Operations, maintenance and administration	87.4	84.3
Depreciation and amortization	56.3	49.8
Taxes, other than income taxes	7.0	7.5
	150.7	141.6
Operating income	95.2	153.5
Other expense	(2.0)	(1.5)
Foreign exchange gain	0.6	0.7
Net interest expense	(19.2)	(33.9)
Earnings from continuing operations before income taxes
and non-controlling interests	74.6	118.8
Income taxes	22.5	53.0
Non-controlling interests	6.4	6.8
Earnings from continuing operations	45.7	59.0
Earnings from discontinued operations (Note 2)	11.2	11.7
Net earnings	56.9	70.7
Preferred securities distributions, net of tax	5.5	3.1
Net earnings applicable to common shareholders	$ 51.4	$ 67.6

Common share dividends	(42.2)	(42.2)
Adjustment arising from normal course issuer bid	(4.5)	(1.6)
Retained earnings
Opening balance	838.3	826.9
Closing balance	$ 843.0	$ 850.7
Weighted average common shares outstanding in the period	169.0	168.6

Basic earnings per share
Continuing operations	$ 0.24	$ 0.33
Earnings from discontinued operations	0.06	0.07
Net earnings	$ 0.30	$ 0.40

Diluted earnings per share
Earnings from continuing operations	$ 0.22	$ 0.32
Net earnings	$ 0.28	$ 0.39

See accompanying notes.

TRANSALTA CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions of Canadian dollars)
	Unaudited
	3 months ended March 31
	2002	2001
Operating activities
Net earnings	$ 56.9	$ 70.7
Depreciation and amortization	70.9	65.6
Non-controlling interests	6.4	6.8
Loss on sale of assets	2.8	1.0
Future income taxes	3.1	(11.2)
Unrealized loss (gain) from energy marketing activities	28.8	(0.5)
Other non-cash items	2.4	4.9
	171.3	137.3
Change in non-cash operating working capital balances	(42.3)	251.4
Cash flow from operating activities	129.0	388.7
Investing activities
Additions to capital assets	(269.3)	(161.4)
Disposal	-	60.3
Long-term receivables	4.3	-
Long-term investments	(2.9)	-
Other	(4.8)	-
Cash flow used in investing activities	(272.7)	(101.1)
Financing activities
Net increase (decrease) in short-term debt	214.6	(279.1)
Issuance of long-term debt	30.9	304.0
Repayment of long-term debt	(1.2)	(271.3)
Issuance of common shares	0.9	2.9
Redemption of common shares	(14.0)	(2.1)
Distributions on preferred securities	(9.2)	(5.9)
Dividends on common shares	(28.2)	(40.0)
Dividends to subsidiary's non-controlling preferred shareholders	-	(2.3)
Distributions to subsidiary's non-controlling limited partner	(6.3)	(5.9)
Cash flow from (used in) financing activities	187.5	(299.7)
Cash flow from (used in) operating, investing and financing	43.8	(12.1)
Effect of translation on foreign currency cash	(5.5)	6.8
Increase (decrease) in cash	38.3	(5.3)
Cash at beginning of period	62.0	53.8
Cash at end of period	$ 100.3	$ 48.5

See accompanying notes.

TRANSALTA CORPORATION
CONSOLIDATED BALANCE SHEET
(in millions of Canadian dollars)	March 31	Dec. 31
	2002	2001
	(Unaudited)	(Audited*)
ASSETS
Current assets
Cash	$ 100.3	$ 62.0
Accounts receivable	351.2	438.9
Trading accounts receivable (Note 3)	656.5	700.8
Future income tax assets	16.7	16.9
Income taxes receivable	230.5	128.3
Materials and supplies at average cost	71.5	85.5
	1,426.7	1,432.4
Investments (Note 4)	40.2	37.3
Long-term receivables	220.1	221.4
Capital assets (Note 2)
Cost	9,016.6	8,766.7
Accumulated depreciation		(2,671.9)
	6,280.5	6,094.8
Goodwill	29.3	29.3
Future income tax assets	15.5	15.6
Other assets	54.0	47.1
Total assets	$ 8,066.3	$ 7,877.9

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	$ 752.2	$ 537.2
Accounts payable and accrued liabilities (Note 4)	426.1	473.4
Trading accounts payable	599.8	642.7
Future income taxes	11.7	11.8
Dividends payable	42.8	42.8
Current portion of long-term debt	104.4	104.3
	1,937.0	1,812.2
Long-term debt	2,437.2	2,406.8
Deferred credits and other long-term	536.4	526.5
Future income tax liabilities	412.8	409.1
Non-controlling interests	281.6	281.0
Preferred securities	452.3	452.6
Common shareholders' equity
Common shares (Note 5)	1,185.4	1,170.9
Retained earnings	843.0	838.3
Cumulative translation adjustment	(19.4)	(19.5)
	2,009.0	1,989.7
Total liabilities and shareholders' equity	$ 8,066.3	$ 7,877.9
Contingency (Note 6)
See accompanying notes.
* Derived from the audited Dec. 31, 2001 consolidated financial statements.

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

Effective Jan. 1, 2002, the corporation adopted the new Canadian Institute of Chartered Accountants (CICA) standard for goodwill and other intangibles. Under the new standard, goodwill and certain intangibles are no longer subject to amortization, but are instead tested for impairment at least annually. The adoption of this standard resulted in the reclassification of $29.3 million from acquired intangibles to goodwill, which will not be subject to amortization. There was no impairment of goodwill upon adoption of this standard.

Net income and earnings per share for the three months ended March 31, 2001 adjusted to exclude the amortization the above amount is as follows:

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

The estimated fair value of stock options issued during the quarter was determined using the binomial model using the following weighted average assumptions, resulting in a weighted-average fair value of $4.25 per option (2001 - $4.35):

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

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

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

On July 4, 2001, the corporation signed a purchase and sale agreement for the disposal of its Transmission operation for proceeds of approximately $850 million. Regulatory approval was received on March 28, 2002, and the transaction is expected to close on April 29, 2002.

On June 29, 2001, the corporation's composter facility in Edmonton, Alberta was sold for cash proceeds of $97.0 million.

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

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

The realized and unrealized components of trading accounts receivable and accounts payable are as follows:

In January 2002, an additional $2.9 million was invested in a wind power generation company. This investment is accounted for using the equity method.

TransAlta Corporation is authorized to issue an unlimited number of voting common shares without nominal or par value. At March 31, 2002, the corporation had 168.7 million (Dec. 31, 2001 168.3 million) common shares issued and outstanding plus outstanding employee stock options to purchase an additional 3.8 million shares (Dec. 31, 2001 2.8 million).

In February 2002, TransAlta announced a normal course issuer bid to repurchase up to 3.0 million common shares for cancellation.

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

Since Jan. 1, 2001, the unit has been subject to the terms of a power purchase arrangement (PPA). Under the PPA's force majeure article, the corporation is not obligated to supply electricity during the period of repair, subject to confirmation by the administrator of the PPAs. Should such confirmation not occur, the corporation would be obligated to pay a penalty equal to the cost of obtaining an alternative source of electricity to fulfill its PPA supply obligations during the affected period. No specific amount has been accrued in these financial statements for this potential liability as the outcome was not determinable at the reporting date. Should the force majeure decision not be in TransAlta's favour, it could have a maximum pre-tax impact of approximately $90 million.

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

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

I. Earnings information
	Unaudited
3 months ended March 31, 2002	Generation	Energy Marketing	Corporate	Totals
Revenues	$ 420.8	$ 646.6	$ -	$ 1,067.4
Trading purchases	-	(647.7)	-	(647.7)
Fuel and purchased power		-	-
Gross margin	247.0	(1.1)	-	245.9
Operations, maintenance and	71.6	2.6	13.2	87.4
Depreciation and amortization	50.1	0.7	5.5	56.3
Taxes, other than income taxes	7.0	-	-	7.0
EBIT before corporate allocations	118.3	(4.4)		95.2
Corporate allocations	16.6	2.1		-
EBIT	$ 101.7	$ (6.5)	-	95.2
Other expense				(2.0)
Foreign exchange gain				0.6
Net interest expense
Earnings from continuing operations before income taxes and non-controlling interests				$ 74.6

	Unaudited
3 months ended March 31, 2001	Generation	Energy Marketing	Corporate	Totals
Revenues	$ 655.3	$ 735.3	$ -	$1,390.6
Trading purchases	-	(684.1)	-	(684.1)
Fuel and purchased power	(411.4)	-	-	(411.4)
Gross margin	243.9	51.2	-	295.1
Operations, maintenance and administration	62.7	4.4
Depreciation and amortization	42.5	1.6
Taxes, other than income taxes	7.5	-	-	7.5
EBIT before corporate allocations	131.2	45.2	(22.9)
Corporate allocations	21.0	1.9	(22.9)	-
EBIT	$ 110.2	$ 43.3	$ -	153.5
Other expense				(1.5)
Foreign exchange gain
Net interest expense				(33.9)
Earnings from continuing operations before income taxes and non-controlling interests				$ 118.8

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.

3 months ended March 31	2002		2001
Availability	92.5%		88.0%
Production (GWh)	11,614		11,240
Electricity trading volumes (MWh)	21,200		3,490
Gas trading volumes (million GJ)	59.8		12.9

(in millions of Canadian dollars except per share amounts)	Amount	Per common share	Amount	Per common share
Revenues¹	^{$ 1,067.4}		$ 1,390.6
Net earnings from continuing operations²	^{$ 40.2}	$ 0.24	$ 55.9	$ 0.33
Discontinued operations³	^11.2	0.06	11.7	0.07
Net earnings applicable to common shareholders	$ 51.4	$ 0.30	$ 67.6	$ 0.40
Cash flow from operating activities	$ 129.0		$ 388.7
¹ From continuing operations.
² Continuing operations include the Generation and Energy Marketing segments plus corporate costs not directly attributable to discontinued operations, and are net of preferred securities distributions.
³ Discontinued operations include the Transmission operation and the Edmonton Composter operation. An agreement to sell the Transmission operation was entered into on July 4, 2001, with the transaction expected to close April 29, 2002. The Edmonton Composter was sold on June 29, 2001.

Revenue and gross margin (GM) analysis
3 months ended March 31	2002		2001
	Revenue	GM	Revenue	GM
Contract	$ 363.2	$ 220.7	$ 324.1	$ 30.5
Merchant	36.4	5.1	297.3	179.5
Ancillary services	21.2	21.2	33.9	33.9
	$ 420.8	$ 247.0	$ 655.3	$ 243.9

	Production (GWh)	Revenue	EBIT
3 months ended March 31, 2001	11,240	$ 655.3	$ 110.2
Lower market prices	-	(248.0)	(248.0)
Lower purchased power requirements	-	-	236.8
Net improved availability and production	374	13.5	8.0
Lower fuel costs per megawatt hour	-	-	6.3
Timing of scheduled maintenance	-	-	(3.0)
Increased depreciation from 2001 capital additions	-	-	(7.6)
Decreased corporate allocations	-	-	4.4
Other	-	-	(5.4)
3 months ended March 31, 2002	11,614	$ 420.8	$ 101.7

AVERAGE MONTHLY SPOT ELECTRICITY PRICES	3 months ended March 31
	2002	2001
Alberta System Market Price (Cdn$)	$ 35.74	$ 115.07
Mid-Columbia Price (US$)	$ 24.61	$ 265.80


SPARK SPREADS ¹
	2002	2001
Alberta System Market Price vs. AECO (Cdn$)	$ 10.78	$ 50.98
Mid-Columbia Price vs. Sumas (US$)	$ 8.04	$ 218.91

¹ For a 7,000 Btu/KWh plant

	Trading volumes
	Electricity (MWh)	Gas (million GJ)	Revenue	EBIT
3 months ended March 31, 2001	3,490	12.9	$ 735.3	$ 43.3
Decreased pricing and margins offset by increased trading activity	17,710	46.9	(88.7)	(52.3)
Decreased operating costs	-	-	-	1.8
Lower depreciation and amortization costs	-	-	-	0.9
Other	-	-	-	(0.2)
3 months ended March 31, 2002	21,200	59.8	$ 646.6	$ (6.5)

(In millions except per share amounts)	3 months ended March 31
	2002		2001
	Amount	Per share	Amount	Per share
Revenue from continuing operations	$ 1,067.4		$ 1,390.6
Net earnings from continuing operations*	$ 40.2	$ 0.24	$ 55.9	$ 0.33
Discontinued operations	$ 11.2	$ 0.06	$ 11.7	$ 0.07
Net earnings*	$ 51.4	$ 0.30	$ 67.6	$ 0.40
Cash flow from operating activities	$ 129.0		$ 388.7
	2002		2001
Availability (%)	92.5		88.0
Production (GWh)	11,614		11,240
Electricity trading volumes (MWh)	21,200		3,490
Gas trading volumes (million GJ)	59.8		12.9

3 months ended March 31	Total	Per MWh	Total	Per MWh
Revenues	$ 420.8	$ 36.23	$ 655.3	$ 58.30
Fuel and purchased power	(173.8)	(14.96)	(411.4)	(36.60)
Gross margin	247.0	21.27	243.9	21.70
Operations, maintenance and administration	71.6	6.16	62.7	5.58
Depreciation and amortization	50.1	4.31	42.5	3.78
Taxes, other than income taxes	7.0	0.60	7.5	0.67
EBIT before corporate allocations	118.3	10.20	131.2	11.67
Corporate allocations	16.6	1.43	21.0	1.87
EBIT	$ 101.7	$ 8.77	$ 110.2	$ 9.80

	2002	2003	2004	2005		2006	2007 and thereafter	Total
Prices actively quoted	$ (7.9)	$ (1.2)	$ (0.1)		$ (0.1)	$ (0.1)	$2.5	$ (6.9)
Prices based on models or other valuation methods	5.4	1.4	-		-	-	-	6.8
	$ (2.5)	$ 0.2	$ (0.1)		$ (0.1)	$ (0.1)	$2.5	$ (0.1)

	Balance		Unrealized balance
	March 31,	Dec. 31,	March 31,	Dec. 31,
	2002	2001	2002	2001
Accounts receivable	$ 656.5	$ 700.8	$ 536.6	$ 370.9
Accounts payable	$ (599.8)	$ (642.7)	$ (536.7)	$ (339.6)

	Increase/
(in millions of Canadian dollars)	(Decrease)	Explanation
Cash	$ 38.3	Refer to Consolidated Statements of Cash Flows.
Accounts receivable	(87.7)	Decrease due to timing of receipt of Generation receivables.
Trading accounts receivable	(44.3)	Increased trading volumes were more than offset by lower prices, resulting in lower outstanding accounts receivable and accounts payable balances.
Income taxes receivable	102.2	Final instalment of 2001 income taxes.
Capital assets	185.7	Capital expenditures and construction activity during the period offset by depreciation.
Short-term debt	215.0	Increased short-term borrowings financed capital expenditures during the period.
Accounts payable and accrued liabilities	(47.3)	Decrease due to the timing of expenditures.
Trading accounts payable	(42.9)	Increased trading volumes were more than offset by lower prices, resulting in lower outstanding accounts receivable and accounts payable balances.
Long-term debt (including current portion)	30.5	Increased borrowings under U.S. commercial paper facility as a hedge of U.S. operations.
Shareholders' equity	19.3	Net earnings offset by dividends and net issuance of common shares.

3 months ended March 31	2002	2001	Explanation
Cash, beginning of period	$ 62.0	$ 53.8
Cash provided by (used in):
Operating activities	129.0	388.7	Timing of accounts receivable relating to the Power Pool for Alberta Generation ($170.0 million) and the final instalment for 2001 income taxes recorded in the first quarter of 2002 ($109.0 million).
Investing activities	(272.7)	(101.1)	In 2002, capital expenditures of $269.3 million consisted primarily of construction at the Big Hanaford, Campeche, Chihuahua and Sarnia plants.
			In 2001, capital expenditures relating primarily to the installation of a scrubber at the Centralia plant and construction of the Sarnia and Campeche plants used cash of $161.4 million; proceeds on the disposal of the Mildred Lake plant provided cash of $60.3 million.
Financing activities	187.5	(299.7)	In 2002, increased short-term and long-term borrowings provided cash of $245.5 million, which was used to finance capital expenditures discussed above, distributions on preferred securities of $9.2 million, cash dividends of $28.2 million and the net repurchase of common shares of $13.1 million.
			In 2001, short-term debt repayments of $279.1 million and cash dividends of $40.0 million were offset by net long-term borrowings of $32.7 million.
Translation of foreign currency cash	(5.5)	6.8
Cash, end of period	$100.3	$ 48.5

3 months ended March 31		2001
Reported net earnings applicable to common shareholders		$ 67.6
Amortization of acquired intangibles		1.5
Adjusted net earnings applicable to common shareholders		$ 69.1

Reported basic earnings per share		$ 0.40
Amortization of acquired intangibles per share		0.01
Adjusted basic earnings per share		$ 0.41

Reported diluted earnings per share		$ 0.39
Amortization of acquired intangibles per share		0.01
Adjusted diluted earnings per share		$ 0.40

	2002	2001
Risk-free interest rate (%)	5.9	5.4
Expected hold period to exercise (years)	7.0	7.0
Volatility in the price of the corporation's shares (%)	28.3	28.2

3 months ended March 31, 2002	Transmission
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

		Edmonton
3 months ended March 31, 2001	Transmission	Composter	Total
Revenues	$ 45.4	$ 3.7	$ 49.1
Operating expenses	(22.7)	(3.1)	(25.8)
Operating income	22.7	0.6	23.3
Net interest expense	(3.0)	-	(3.0)
Earnings before income taxes	19.7	0.6	20.3
Income taxes	8.3	0.3	8.6
Earnings from discontinued operations	$ 11.4	$ 0.3	$ 11.7

	March 31, 2002	Dec. 31, 2001

Current assets	$ 22.8	$ 36.1
Capital assets	636.5	637.5
Other assets	1.3	3.3
Current liabilities
Total net assets	$ 648.8	$ 661.4

Trading accounts receivable	March 31, 2002	Dec. 31, 2001
Realized	$ 119.9	$ 329.9
Unrealized	536.6	370.9
Total	$ 656.5	$ 700.8

Trading accounts payable
Realized	$ 63.1	$ 303.1
Unrealized	536.7	339.6
Total	$ 599.8	$ 642.7

II. Selected balance sheet
		Energy		Discontinued
*March 31, 2002*	Generation	Marketing	Corporate	Operations	Total
Segment assets	$	$ 695.7	$ 732.5	$	$ 8,066.3

*Dec. 31, 2001*
Segment assets	$	$	$ 609.0	$	$ 7,877.9

III. Selected cash flow
		Energy
3 months ended March 31, 2002		Marketing	Corporate	Operations	Total
Capital expenditures	$	$	$	$ 13.3	$ 269.3

3 months ended March 31, 2001
Capital expenditures	$ 145.4	$ 0.3	$ 2.8	$ 12.9	$ 161.4

IV. Reconciliations

Depreciation and amortization expense (D&A) per statement of cash flows
*3 months ended March 31*	2002	2001
D&A expense for reportable segments	$ 56.3	$ 49.8
Discontinued operations	11.7	12.0
Other	2.9	3.8
	$ 70.9	$ 65.6