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 March, 2002

TRANSALTA CORPORATION

(Translation of registrant's name into English)

110-12th 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-________

EXHIBITS

Exhibit 1 Management's discussion and analysis for the year ended December 31, 2001.
Exhibit 2 Audited consolidated financial statements for the year ended December 31, 2001.




Exhibit 1

MANAGEMENT'S DISCUSSION AND ANALYSIS

This discussion and analysis should be read in conjunction with the consolidated financial statements and Auditors' Report included in the Annual Report. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The effect of significant differences between Canadian and United States GAAP have been disclosed in Note 26 to the consolidated financial statements. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted.

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements, including statements regarding the business and anticipated financial performance of TransAlta Corporation ("TransAlta" or the "corporation"). 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 Corporation operates, results of financing efforts, changes in counterparty risk and the impact of accounting policies issued by Canadian and United States standard setters. See additional discussion below under Risk Factors and Risk Management.

OVERVIEW

TransAlta is Canada's largest non-regulated electric generation and marketing company. The corporation's strategy is to generate growth, create shareholder value, and maintain a strong balance sheet. Earnings growth will be achieved through development projects and acquisitions, with a focus on diversifying geographically and by fuel source, with a goal of increasing earnings by 10 to 15 per cent per year and increasing generating capacity by 1,000 megawatts (MW) each year. In addition, continued focus on operational improvements will maximize generation availability and ensure TransAlta remains competitive as a low-cost producer of power.

This review of TransAlta's 2001 financial results is organized by consolidated results and by business segment. At Dec. 31, 2001, TransAlta had three business segments supported by a corporate group: Generation, Independent Power Projects and Energy Marketing. 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 Alberta Distribution and Retail (D&R) and New Zealand operations were reclassified as discontinued operations on Dec. 31, 1999.

Each business segment assumes responsibility for its operating results measured as earnings before interest, taxes and non-controlling interests (EBIT). EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with 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 periods have been restated to conform to the current year's presentation.

KEY HIGHLIGHTS:

SUMMARY OF RESULTS

<table>
2001 2000 1999
Production (GWh) 44,136 40,644 33,677
Electricity trading volumes (GWh) 19,200 9,500 5,400
Gas trading volumes (millions of GJ) 216 136 214
Per common Per common Per common
Amount share Amount share Amount share
Revenues 1 $ 4,927.1 $2,802.5 $ 1,123.0
Earnings from continuing operations 2 $ 169.5 $ 1.00 $ 133.6 $ 0.79 $ 48.7 $ 0.29
Discontinued operations 3 45.1 0.27 89.1 0.53 101.7 0.60
Earnings applicable to common shareholders $ 214.6 $ 1.27 $ 222.7 $ 1.32 $ 150.4 $ 0.89
Gains on disposal of discontinued operations 3 - - 266.8 1.58 19.7 0.11
Extraordinary item 4 - - (209.7) (1.24) - -
Net earnings applicable to common shareholders $ 214.6 $ 1.27 $ 279.8 $ 1.66 $ 170.1 $ 1.00
Cash flow from operating activities $ 715.6 $ 198.7 $ 426.2
1 Gross revenues from continuing operations.
2 Continuing operations include the Generation, IPP and Energy Marketing businesses plus corporate costs not directly attributable to discontinued operations, and are net of preferred securities distributions.
3 Discontinued operations include the New Zealand operations, the Alberta D&R operation, Edmonton Composter and the Transmission operation. The New Zealand operations, Alberta D&R operation and the Edmonton Composter were disposed of on Mar. 31, 2000, Aug. 31, 2000 and June 29, 2001 respectively. An agreement to sell the Transmission operation was entered on July 4, 2001 and the transaction is expected to close in the first half of 2002.
4 Extraordinary item arose from the recognition of previously unrecorded future income taxes and a write-down of capital assets related to Alberta Generation due to a change in accounting policy as a result of deregulation of the electric generation industry in Alberta commencing on Jan. 1, 2001.




</table>

For the year ended Dec. 31, 2001, total electricity production was 44,136 gigawatt hours (GWh) compared to 40,644 GWh in 2000 and 33,677 GWh in 1999. Incremental production in 2001 compared to 2000 came from the Centralia plant (2,785 GWh) acquired in May 2000 and the Poplar Creek plant (2,491 GWh), which commenced commercial operations in January 2001, offset by lower hydro production (240 GWh) and lost production from the sale of the 265 MW Mildred Lake and the 45 MW Fort Nelson plants (1,713 GWh). Increased production in 2000 compared to 1999 was primarily a result of the acquisition of the Centralia plant in May 2000 and a full year of production from the Fort Nelson, Fort Saskatchewan and Meridian plants, which commenced commercial operations in 1999.

As the Energy Marketing segment acts as a principal, takes title to commodities purchased for resale and assumes the risks and rewards of ownership, Energy Marketing revenues are now reported on a gross basis in accordance with Canadian GAAP. Certain Generation revenues have also been similarly reclassified. Prior period amounts have been restated.

Revenues increased by 76 per cent to $4,927.1 million compared to $2,802.5 million in 2000 and increased by 150 per cent to $2,802.5 million in 2000 compared to $1,123.0 million in 1999. The increase in 2001 over 2000 was primarily a result of high prices in the first half of 2001, incremental production from the May 2000 acquisition of the Centralia plant, higher revenue from the Alberta plants, increased trading revenues in Energy Marketing and incremental revenues from the Poplar Creek and Pierce Power plants offset by the sale of the Mildred Lake and Fort Nelson plants. The increase in revenues in 2000 over 1999 was due primarily to the acquisition of the Centralia plant, increased trading activity in Energy Marketing and a full year of production from the Fort Nelson, Fort Saskatchewan and Meridian plants, which commenced operations in 1999.

Net earnings from continuing operations applicable to common shareholders for the year ended Dec. 31, 2001 were $169.5 million ($1.00 per common share - EPS) compared to $133.6 million in 2000 ($0.79 EPS) and $48.7 million in 1999 ($0.29 EPS). The increase in 2001 over 2000 was primarily a result of increased earnings from the Alberta thermal and hydro plants, earnings from the Poplar Creek and Pierce Power plants, gains on dispositions from the sale of the Fort Nelson plant and half of the corporation's interest in the Fort Saskatchewan plant and increased returns from energy trading activities. These increases were partially offset by the impact of unplanned outages at the Centralia plant and the net loss on power purchased in the first half of 2001 for delivery in the second half as a hedge against higher expected outage rates at the Centralia plant. The increase in 2000 over 1999 is mainly a result of higher earnings from non-regulated operations and improved performance in energy trading activities offset by higher net interest expense resulting from higher debt levels.

Cash flow from operating activities after changes in non-cash working capital was $715.6 million in 2001 compared to $198.7 million in 2000 and $426.2 million in 1999. Cash flow before working capital changes of $624.5 million in 2001 was consistent with 2000. In 2000, significantly increased working capital requirements resulted from deferred accounts receivable related to the sale of the discontinued Alberta D&R operation and increased trade receivables related to Centralia production and Energy Marketing activities.

OUTLOOK

The key factors affecting financial results for 2002 will be the availability of and production from generating assets, the pricing applicable to non-contracted production and the costs of production. The significantly lower electricity prices which existed in the latter half of 2001 are expected to continue throughout 2002. To achieve earnings growth, the corporation's focus will be to increase the efficiency and availability of generating assets and continue the reduction of operating and administrative costs. Energy Marketing will maximize pricing opportunities for non-contracted production and will seek to offset lower prices and price volatility by increasing trading volumes in existing and new geographic areas.

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.

TransAlta's goal is to increase electricity generation capacity to 15,000 MW by 2005. The corporation expects growth to be achieved through the acquisition of existing assets and the development of new projects. Under current economic conditions, opportunities to acquire existing generating assets in North America are expected to become more likely than has been the case for the last two years. Acquisition of existing assets will provide TransAlta with immediate generating capacity and returns while the development and construction of new projects will enable the corporation to build efficient plants that capitalize on expected growth in demand beyond 2004. Additional growth will also come from increasing capacity through upgrades of existing assets.

Relative to our peer group, a strong year-end balance sheet, high-quality credit ratings, increasing cash flow from operations and a strong dividend (see discussion under Liquidity and Capital Resources) will allow TransAlta ready access to capital markets at competitive rates to fund growth and to finance operational improvements and preventive maintenance.

Achieving the above goals will be dependent upon, but not limited to, risks and uncertainties such as commodity prices, currency exchange rates, interest rates and capital market activity. Further, the effects of competition, the regulatory environment and general economic conditions may impact the outcome. See discussion under Risk Factors and Risk Management.

SIGNIFICANT ONE-TIME ITEMS

These consolidated financial results include the following significant one-time items:

Gains on Disposal of Discontinued Operations

Effective Dec. 31, 2000, the corporation adopted a plan to divest its composter facility in Edmonton, Alberta, Canada, which commenced commercial operations in August 2000. In the fourth quarter of 2000, the corporation recorded a write-down on the carrying value of the assets of $17.9 million ($0.10 - EPS) net of income tax recoveries of $13.8 million. On June 29, 2001, the facility was sold for cash proceeds of $97.0 million. No gain or loss resulted from the sale.

On Aug. 31, 2000, TransAlta completed the disposition of its Alberta D&R business for proceeds of $857.3 million and recorded an after-tax gain of $262.4 million ($1.55 EPS). At Dec. 31, 2001, $723.6 million of these proceeds had been received. The remaining balance, primarily related to deferral accounts, is expected to be received by the end of 2003 as mandated by the Alberta Energy and Utilities Board (EUB).

On March 31, 2000, TransAlta closed the sale and completed the disposition of its investment in TransAlta New Zealand Limited for total proceeds of NZ$832.5 million (approximately Cdn$605 million) and recorded an after-tax gain of $22.3 million ($0.13 EPS).

Prior Period Regulatory Decisions

In December 2001, the EUB ruled that the Wabamun unit four outage qualified for relief under the Temporary Suspension Regulation (TSR) and ordered that TransAlta would receive $11.0 million ($7.0 million after-tax) to compensate the corporation for obligation payments incurred in 2000 as a result of the outage.

In September 2000, TransAlta received a negotiated settlement of $17.8 million ($9.9 million after-tax) under the TSR to compensate the corporation for obligation payments incurred as a result of Alberta Generation production outages occurring in 1999 and 2000. Approximately $13.5 million ($7.4 million after-tax) related to 1999 and $4.3 million ($2.5 million after-tax) related to the first quarter of 2000.

In February 2000, the EUB announced an amendment to its Phase I decision (1999 Final Decision) concerning a 1999 revenue requirement issue that partially offset the effect of its original decision rendered in 1999. The positive impact of the 1999 Final Decision increased earnings by $30.6 million ($16.4 million after-tax) and was recorded in the first quarter of 2000. Included in this amount was a reduction in earnings of approximately $0.8 million related to the discontinued Alberta D&R operation.

Extraordinary Item

On Dec. 31, 2000, TransAlta discontinued regulatory accounting and commenced the application of Canadian GAAP for non-regulated businesses for its Alberta Generation operations, following final confirmation of deregulation of the electricity generation industry in Alberta beginning on Jan. 1, 2001. As a result of the discontinuance of regulatory accounting, the corporation recorded an extraordinary non-cash after-tax charge of $209.7 million ($1.24 EPS). Of this amount, $189.9 million resulted from the recognition of future income tax liabilities that the corporation was previously exempted from recording due to the regulatory environment.

NEW ACCOUNTING STANDARDS

Effective Jan. 1, 2001, the corporation retroactively adopted the new Canadian accounting standard for calculating diluted earnings per share. The impact of the change on current and prior period diluted earnings per share was not material.

<table>

SEGMENTED BUSINESS RESULTS

GENERATION: Consists of coal and hydro plants and related mining operations in Alberta, Canada and Washington State, U.S., with a total generating capacity of 5,890 megawatts
Production (GWh) Revenue EBIT
Year ended 1999 28,717 $ 569.4 $ 182.0
1999 regulatory decisions received in 2000 - - 44.1
Acquisition of Centralia plant 6,267 585.3 137.1
Wabamun unit four outage (391) (18.0) (18.0)
Decrease in hydro energy output (476) (13.4) (13.0)
Overall improvement in thermal availability 251 7.1 5.6
Other - 29.5 (11.1)
Year ended 2000 34,368 $ 1,159.9 $ 326.7
1999 regulatory decisions received in 2000 - - (44.1)
Wabamun unit four TSR settlement for 2000 - - 11.0
Higher returns and incentives under PPAs - 208.3 208.3
Increased hydro ancillary services - 53.0 53.0
Decrease in hydro energy output (240) (17.9) (17.7)
Acquisition of Centralia plant 2,785 155.0 47.3
Unplanned Centralia outages - 95.7 (245.5)
Centralia hedge losses, expired in 2001 - 11.8 (124.2)
Other (6) 52.1 (8.7)
Year ended 2001 36,907 $ 1,717.9 $ 206.1
2001 2000 1999
Revenue per MWh 1 $ 46.55 $ 33.75 $ 19.83




</table>

RESULTS

Generation's production was 36,907 GWh in 2001, 34,368 GWh in 2000 and 28,717 GWh in 1999. The increase from 2000 to 2001 is primarily a result of a full year of production from the Centralia plant (2,785 GWh) acquired in May 2000, offset by decreased hydro production (240 GWh) due to lower than average snowpack in 2001. The increase from 1999 to 2000 is primarily a result of the acquisition of the Centralia plant.

For the year ended Dec. 31, 2001, Generation achieved an availability rate of 84.7 per cent. The availability rate was 85.9 per cent in 2000 and 87.4 per cent in 1999. Results for 2001 were negatively impacted by unplanned outages at the Centralia plant and the Wabamun unit four outage. The 2000 results were negatively impacted by the Wabamun unit four outage.

Total net revenue increased by $558.0 million in 2001 to $1,717.9 million compared to $1,159.9 million in 2000. The increase is primarily a result of increased revenues from the Power Purchase Arrangements (PPAs) (Note 1), which commenced on Jan. 1, 2001, incentives for exceeding availability targets set out in the PPAs, a full year of production from the Centralia plant, additional revenue from hydro ancillary services, and increased sales from power purchases in excess of those required to meet contracted obligations. In 2000, Generation revenues increased to $1,159.9 million compared to $569.4 million in 1999. The increase is attributable primarily to the acquisition of the Centralia plant in May 2000.

Revenue per megawatt hour (MWh) increased to $46.55 per MWh from $33.75 per MWh in 2000 primarily as a result of increased revenues under the PPAs and increased electricity prices compared to 2000. The increase in 2000 over 1999 to $33.75 per MWh from $19.83 per MWh was primarily a result of the acquisition of the Centralia plant, which received higher contracted and spot prices than in Alberta.

Generation's EBIT was $206.1 million in 2001 compared to $326.7 million in 2000, a decrease of $120.6 million or 37 per cent. Higher returns and incentives under the PPAs and increased hydro ancillary services provided additional EBIT, but were offset by losses from the Centralia plant due to unplanned outages. In addition, losses of US$77.7 million (approximately Cdn$124 Million) were incurred in the second half of the year as a result of power purchased in the first half of the year as a hedge against higher expected outage rates at Centralia. These contracts were entered into when the market indicated that power prices were going to continue to escalate. Instead, the implementation of price caps and the reduction in economic activity resulted in a significant drop in market prices. These contracts expired at the end of 2001. The increase in EBIT in 2000 compared to 1999 was primarily a result of the acquisition of the Centralia plant.

OUTLOOK

In 2002, improved availability and production is expected to offset the impact of lower spot prices for non-contracted production. Generation will focus on improving the availability and cost efficiency of its coal-fired facilities, in particular, the need to continue to build on the improved fourth quarter 2001 performance at the Centralia plant. A nine-week outage is scheduled at the Centralia plant for the second quarter of 2002 to increase the plant capacity and install the second scrubber as part of the environmental obligations that were assumed when the plant was purchased. The scrubbers will be fully operational by the last quarter of 2002.

Electricity prices are expected to continue at their current low levels throughout 2002. At the end of 2001, the last contracts in respect of the Centralia plant to purchase power at out-of-market prices expired. A large proportion of Generation's output is contracted for 2002 (93.7 per cent) with a corresponding lower amount subject to spot prices. Energy Marketing's expertise will be utilized to maximize the pricing opportunities available for this non-contracted production.

In 2002, capital expenditures will be approximately $450 million, consisting primarily of completion of the installation of scrubbers and capacity upgrades at the Centralia plant and the 248 MW gas-fired Big Hanaford plant, which is expected to commence commercial operations in the third quarter of 2002.

The arbitration of TransAlta's claim of force majeure for the Wabamun unit four outage concluded in early January 2002 and a decision is expected in the second quarter of 2002. TransAlta continues to be confident in its position that the outage, which occurred in mid-2000 and carried over into 2001, qualifies as a force majeure event under the PPAs. No amount has been accrued for this potential liability as neither the outcome nor the amount was reasonable 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 $90 million.

In February 2002, the EUB approved the previously announced 900 MW expansion of the Keephills plant. The corporation will now complete 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.

TransAlta continues to evaluate generation opportunities that fit its operating capabilities and risk profile to grow its business in Canada, the U.S. and Mexico.

INDEPENDENT POWER PROJECTS (IPP): Builds, owns and/or operates independent power projects in Canada, the U.S., Mexico and Australia, with a total generating capacity of 1,512 megawatts, for the sale of electric and thermal energy under long-term commercial contracts and in spot markets.
<table>


Production (GWh) Revenue EBIT
Year ended 1999 4,960 $ 270.6 $ 34.8
Full year of production from Western Canada plants 1,422 57.4 12.2
Poplar Creek operations and maintenance contract - 14.8 2.4
Decreased Mildred Lake power plant earnings (114) 11.3 (4.3)
Improved limited partnership operations - 7.6 3.0
Other 8 0.6 (8.2)
Year ended 2000 6,276 $ 362.3 $ 39.9
Commencement of operations at Poplar Creek plant 2,491 84.9 25.8
Disposal of Mildred Lake and Fort Nelson plants (1,713) (86.6) 0.3
Disposal of Fort Saskatchewan plant to TA Cogen - - 6.2
Incremental revenue from Pierce Power plant 22 124.0 5.2
Acquisition of Binghamton plant 27 4.0 (0.5)
Improved limited partnership operations 77 3.8 1.5
Increased recoverable gas costs - 14.4 -
Other 49 7.7 (12.8)
Year ended 2001 7,229 $ 514.5 $ 65.6
2001 2000 1999
Revenue per MWh1 $ 54.02 $ 57.73 $ 54.56
1 Defined as segment revenues, net of Pierce Power revenue, divided by production.

</table>

RESULTS

For the year ended Dec. 31, 2001, electricity production was 7,229 GWh compared to 6,276 GWh in 2000 and 4,960 GWh in 1999. In 2001, increased production of 2,491 GWh from the Poplar Creek plant was offset by lost production of 1,713 GWh from the sale of the Mildred Lake and Fort Nelson plants. The Pierce Power plant, which comprises a lease of portable generating units for a period of 14 months, commenced commercial operations in August 2001 and added 22 GWh of incremental production for the period. Steam production in 2001 was 3.8 million tonnes compared to 10.3 million tonnes in 2000 and 8.3 million tonnes in 1999. The decrease in 2001 was primarily a result of the disposal of the Mildred Lake plant. Availability was 96.3 per cent in 2001, 96.1 per cent in 2000 and 97.8 per cent in 1999.

Revenues increased by $152.2 million in 2001 to $514.5 million compared to $362.3 million in 2000. The increase was primarily a result of the commencement of commercial operations of the 360 MW Poplar Creek plant in January 2001 and incremental revenue from the 154 MW Pierce Power plant. The sale of the 265 MW Mildred Lake and the 45 MW Fort Nelson plants in January 2001 and August 2001 respectively, partially offset these increases. A full year of operations from the Fort Nelson, Fort Saskatchewan and Meridian plants contributed the majority of the $91.7 million increase in revenues in 2000 to $362.3 million from $270.6 million in 1999.

As a result of market conditions, TransAlta realized its investment in the 154 MW Pierce Power plant in September 2001, resulting in EBIT of $5.7 million. Revenue hedges were realized resulting in revenues of $121.8 million, offset by a $116.1 million reduction of the carrying values of the assets and the recognition of anticipated future fixed costs. As a result of the decision, the Pierce Power plant now operates as a peaker plant that generates power when prices are sufficient to cover variable costs.

Revenue per MWh was $54.02 in 2001 compared to $57.73 in 2000 and $54.56 in 1999. The decrease in 2001 reflects the lower priced output from the Poplar Creek plant. In 2000, the increase was due to the commencement of the operations and maintenance contract at the Poplar Creek plant, which increased revenue without a corresponding increase in production.

On Jan. 31, 2001, the 265 MW Mildred Lake plant was sold for proceeds of $60.3 million plus a receivable of $4.7 million, which approximated its book value. On Aug. 21, 2001, the 45 MW gas-fired Fort Nelson power plant was sold for proceeds of $44.1 million. A gain of $1.3 million was recorded on the disposal. These assets did not meet corporate financial targets and were sold to allow the reinvestment of cash into growth projects.

On September 30, 2001, the 60 per cent interest in the 120 MW Fort Saskatchewan gas-fired cogeneration facility was sold to TransAlta Cogeneration, L.P. (TA Cogen), a limited partnership owned 50.01 per cent by TransAlta and 49.99 per cent by TransAlta Power, L.P. (TransAlta Power), a publicly owned entity. Net proceeds to the corporation of $35.0 million and a gain of $6.2 million on the 30 per cent interest effectively sold to the minority interests in TA Cogen were realized. This sale provided the opportunity to retain control and operation of the asset through a management agreement with TA Cogen, realize a portion of the inherent value of the plant and provide cash for future growth initiatives.

In January 2001, TransAlta acquired a 55 MW gas-fired plant in Binghamton, New York for US$9.0 million. TransAlta owns and operates 100 per cent of the facility, the corporation's first power plant acquisition in the northeastern U.S. The plant is a peaker plant, which will operate to provide electricity to the New York power pool during periods of high demand.

EBIT increased by $25.7 million to $65.6 million in 2001. EBIT from the Poplar Creek plant, gains realized on the sale of the Fort Saskatchewan and Fort Nelson plants, and EBIT from the Pierce Power plant were partially offset by increased administration expenses due to the expansion of operations and plant construction activities. EBIT increased by $5.1 million to $39.9 million in 2000 from $34.8 million in 1999 as the EBIT contributed by the full year of operations from the plants in Western Canada was partially offset by higher allocated corporate overheads.

OUTLOOK

At existing plants, continued focus on the maximization of revenues under the contracts and enhancing availability and operating cost efficiency will be the main focus for 2002. Significant construction activity will continue throughout 2002. Completion of the 650 MW Sarnia facility is expected in the fourth quarter of 2002, with commercial operations commencing in the first quarter of 2003.

Exposure to volatility in electricity prices is substantially mitigated through fixed 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 certain of these contracts and the existence of price caps in certain natural gas supply contracts. At the end of 2001, approximately 83 per cent of the output was contracted and the corporation will continue to focus on the maximization of revenues from these contracts. For non-contracted sales, exposure to electricity and gas price volatility is significantly mitigated by the correlation between natural gas and electricity prices.

In 2002, approximately $640 million will be spent on the continued construction of existing projects and approximately $60 million will be spent on the pre-purchase of turbines. Of this amount, $230 million relates to the completion of the Sarnia plant, while the ongoing construction of the Campeche and Chihuahua plants in Mexico will utilize $105 million and $205 million, respectively. The 252 MW Campeche plant is scheduled for completion in the first quarter of 2003. Completion of the 259 MW Chihuahua plant is expected in the second quarter of 2003.

TransAlta continues to actively seek to acquire or build high quality gas-fired projects throughout Canada, the U.S. and Mexico. In the U.S., the focus is on selected areas, specifically the Northeast, Pacific Northwest and contiguous states. In Mexico, TransAlta plans to bid on additional high-quality projects of size and scope similar to the Campeche and Chihuahua plants being placed for bid by the Comision Federal de Electricidad, the state-owned utility.

<table>

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.
Trading volumes
Transmission (GWh) Revenue EBIT
Year ended 1999 5,400 $ 283.0 $ (3.5)
Increased trading activity 4,100 1,034.8 100.9
Provision for California receivables - (37.5) (37.5)
Amortization of acquired intangibles - - (10.0)
Increased operations and maintenance expenses - - (5.3)
Other - - (2.3)
Year ended 2000 9,500 $1,280.3 $ 42.3
Increased trading activity 9,700 1,414.4 83.7
Increased operating costs - - (2.6)
One-time costs associated with MEGA acquisition - - (13.9)
Other - - (2.3)
Year ended 2001 19,200 $ 2,694.7 $107.2
</table>




RESULTS

As the Energy Marketing segment acts as a principal, takes title to commodities purchased for resale and assumes the risks and rewards of ownership, Energy Marketing revenues are now reported on a gross basis in accordance with Canadian GAAP. Prior period amounts have been restated.

The increase in Energy Marketing's trading volumes, particularly in the Pacific Northwest region, where market volatility and prices remained high for the first five months of 2001, resulted in a significant increase in trading revenues and margins in both 2001 and 2000. Lower economic activity and price caps implemented by the United States Federal Energy Regulatory Commission (FERC) in the Western System Coordinating Council (WSCC) region of the U.S. in June 2001 resulted in a significant decrease in market volatility and lowered prices to more historic levels in the second half of 2001.

Energy Marketing's net margin was $161.0 million in 2001 compared to $77.8 million in 2000 and $11.0 million in 1999 as a result of increased trading volumes and margins. Volumes of power traded increased to 19,200 GWh in 2001 from 9,500 GWh in 2000 and 5,400 GWh in 1999. Volumes of gas traded were 215.5 million gigajoules (GJ) in 2001 compared to 135.7 GJ in 2000 and 213.5 GJ in 1999.

In 2001, Energy Marketing commenced a fixed transmission trading strategy in the Pacific Northwest which significantly increased net margin. This strategy involves committing to make fixed payments for the right, but not the obligation, to use electricity transmission. Net margin is realized through trading around price differentials at points along the transmission capacity.

TransAlta acquired the remaining 50 per cent of Merchant Energy Group of the Americas (MEGA) in June 2001 for cash consideration of US$0.3 million (Cdn$0.4 million). The initial 50 per cent of MEGA was purchased in June 2000 for cash consideration of US$12.5 million (Cdn$18.6 million). Subsequent to the acquisition, one-time costs of $13.9 million were incurred, comprised primarily of severance of $3.9 million and long-term employment incentives in the amount of $8.5 million. TransAlta will continue to utilize MEGA as a platform on which to expand trading activities into eastern U.S. regions. The results of MEGA's operations are therefore included in the Energy Marketing business segment. Previously, the results had been included in the IPP business segment. Prior period revenues and EBIT in both segments have been restated to reflect this change. In September 2001, the MEGA operations were amalgamated with TransAlta Energy Marketing (U.S.) Inc., a subsidiary of TransAlta Energy Corporation (TransAlta Energy).

Energy Marketing's EBIT increased by $64.9 million to $107.2 million in 2001 from $42.3 million in 2000 primarily as a result of increased trading volumes and margins, offset by $13.9 million of one-time costs discussed above and increased operating costs. Energy Marketing's EBIT for the year ended Dec. 31, 2000 increased by $45.8 million over 1999 from a loss of $3.5 million to EBIT of $42.3 million, primarily as a result of increased trading activities.

At Dec. 31, 2001, accounts receivable, net of allowances for liquidity and potential market clawback issues decreased to $700.8 million (2000 - $1,030.0 million). Accounts payable decreased to $642.7 million (2000 - $951.6 million). These reductions are mainly due to decreases in market prices of electricity and natural gas.

At Dec. 31, 2000, TransAlta provided for US$28.8 million of accounts receivable out of a total of US$66.2 million related to the California market. The provision will be reversed when the corporation has confidence in the ultimate collection of the amounts owing and that it will not have to make any repayment of such amounts as a result of retroactive changes to trading regulations from those under which TransAlta completed its trades with California entities. At Dec. 31, 2001, US$12.9 million had been received and no associated provision amounts were reversed.

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



OUTLOOK

Electricity and gas prices, volatility and liquidity are expected to decrease in 2002. As a result, Energy Marketing's margins are expected to decrease in 2002 compared to 2001, but will be partially offset by increases in trading volumes in existing and new markets. However, overall net margins and EBIT are expected to decline.

Energy Marketing will continue to concentrate on buying and selling electricity and gas in the short-term (i.e. real time) markets. The electricity trades involve matching buyers and sellers, arranging for transmission capacity and scheduling movement of the commodity. This type of trading does not involve long-term contracts and therefore value at risk (VAR) and volatility related to fair value accounting is very low. During 2002, Energy Marketing anticipates increased activities associated with expansion into eastern North American markets. Additional volume will allow improved productivity while not compromising trading controls and discipline.

Energy Marketing will focus on improving returns and managing higher activity levels related to existing generating assets.

<table>

1. NET INTEREST EXPENSE, FOREIGN EXCHANGE AND OTHER
2001 2000 1999
Interest expense $ 112.3 $ 115.2 $ 80.6
Interest income (24.2) (23.8) (15.1)
Foreign exchange gains (0.8) (0.1) (1.7)
Other expense (income) (1.5) 1.1 -
$ 85.8 $ 92.4 $ 63.8
Year ended 1999 $ 63.8
Increased debt levels 9.1
Increased capitalized interest and AFUDC1 (21.3)
Higher effective interest rates 5.6
Decreased allocations to discontinued operations 39.9
Other (4.7)
Year ended 2000 $ 92.4
Increased debt levels, net of interest on Alberta D&R deferral accounts 5.4
Increased capitalized interest and AFUDC1 (8.5)
Lower effective interest rates (14.6)
Decreased allocations to discontinued operations 15.3
Other (4.2)
Year ended 2001 $ 85.8
1 Allowance for funds used during construction.

</table> 

RESULTS

Net interest expense (net of interest income, capitalized interest and AFUDC and amounts allocated to discontinued operations) decreased to $88.1 million in 2001 from $91.4 million in 2000. Following an EUB regulatory decision, interest income of $3.0 million was recognized as receivable on the deferral accounts of the discontinued Alberta D&R operation related to prior periods. Higher debt levels resulting from the acquisition of the Centralia plant, the commencement of commercial operations at the Poplar Creek plant and increased capital expenditures were offset by the proceeds on the disposal of the Alberta D&R operation, increased capitalized interest and lower interest rates.

The increase in net interest expense from 1999 to 2000 resulted from higher debt levels from the acquisition of the Centralia plant (offset by the proceeds on disposal of the New Zealand operations) and higher effective interest rates, offset by increased capitalized interest as a result of increased capital expenditures.

OUTLOOK

Net interest expense is expected to increase due to the commencement of operations at the Big Hanaford plant and higher expected interest rates. Interest capitalized during 2002 will relate to construction activity on the Sarnia, Campeche and Chihuahua projects, as well as the completion of the installation of scrubbers at the Centralia plant.

<table>

PREFERRED SECURITIES DISTRIBUTIONS
2001 2000 1999
Preferred securities distributions, net of tax $ 13.1 $ 12.8 $ 5.2




</table>

RESULTS

In 2001, preferred securities distributions, net of tax, increased slightly as a result of the issuance of $175.0 million of 7.75 per cent preferred securities in November 2001. In 2000, distributions exceeded those in 1999 as the preferred securities that were issued in April and December 1999 were outstanding for the entire year.

OUTLOOK

Preferred securities distributions will increase in 2002 due to the $175.0 million issuance in November 2001.

INCOME TAXES
<table>
2001 2000 1999
Income taxes $ 89.9 $ 128.5 $ 64.7
Effective tax rate 30.7% 40.6% 43.3%




</table>

RESULTS

Income taxes are net of amounts directly related to discontinued operations. Income taxes decreased by $38.6 million in 2001 compared to 2000 mainly due to the decrease in 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 30.7 per cent in 2001 from 40.6 per cent in 2000 primarily due to the reduction in Canadian tax rates, lower non-deductible items and an increase in the manufacturing and processing tax credit. In 2000, income taxes increased to $128.5 million from $64.7 million in 1999 as a result of increased pre-tax earnings. The lower effective tax rate in 2000 was due primarily to higher earnings from lower tax rate jurisdictions.

OUTLOOK

Income taxes are expected to increase in 2002 due to higher pre-tax earnings.

<table>

NON-CONTROLLING INTERESTS
2001 2000 1999
Non-controlling interests $ 20.6 $ 41.6 $ 30.9




</table> RESULTS

Non-controlling interests' share of TransAlta's consolidated earnings from continuing operations after income taxes decreased by $21.0 million in 2001 to $20.6 million compared to $41.6 million in 2000 due primarily to the minority interest portion of the fair value liability of a natural gas swap between TA Cogen and the corporation entered into in December 2000 which was charged to income in 2000. The swap transaction provides TA Cogen with fixed price gas for both the Mississauga and Ottawa plants until Dec. 31, 2005. The swap was entered into by TransAlta to stabilize cash distributions of the limited partnership for five years at levels consistent with previous years. Increased earnings from TransAlta Power's 49.99 per cent limited partnership interest in TA Cogen were offset by the redemption of the 4.0 per cent to 7.7 per cent Series and 8.4 per cent Series of preferred shares of TransAlta Utilities Corporation in September 2001 and March 2000, respectively.

Non-controlling interests increased by $10.7 million in 2000 over 1999 as TransAlta Power's interest in TA Cogen increased by $20.3 million, due primarily to the minority interest portion of the fair value liability of the natural gas swap discussed above. The charge resulting from the swap transaction was partially offset by lower subsidiary preferred share dividends as a result of the redemption of the preferred shares discussed above.

<table> OUTLOOK

No significant changes in non-controlling interests are expected in 2002.

DISCONTINUED OPERATIONS
Date Sold 2001 2000 1999
Transmission - earnings from operations n/a $ 44.4 $ 44.3 $ 48.3
Edmonton Composter - earnings from operations June 29, 2001 0.7 0.7 -
- write-down of carrying value - (17.9) -
Alberta D&R - earnings from operations Aug. 31, 2000 - 33.3 21.8
- gain on disposition - 262.4 -
New Zealand - earnings from operations Mar. 31, 2000 - 10.8 31.6
- gain on disposition - 22.3 -
Argentina 1 - gain on disposition Dec. 20, 1999 - - 19.7
$ 45.1 $ 355.9 $ 121.4
1 1999 amount includes $12.4 million reversal of a provision resulting from the expiry of an unutilized standby credit facility.




</table> TRANSMISSION

RESULTS

TransAlta entered into an agreement on July 4, 2001 to sell its Transmission operation for cash proceeds of approximately $850 million, which will result in an estimated after-tax gain of approximately $100 million. TransAlta will record Transmission's results as discontinued operations until closing, expected in the first half of 2002 following regulatory approval.

The discontinued Transmission operation after-tax earnings remained consistent at $44.4 million for the year ended Dec. 31, 2001, $44.3 million in 2000 and $48.3 million in 1999.

EDMONTON COMPOSTER

RESULTS

Effective Dec. 31, 2000, the corporation adopted a formal plan to pursue divestiture opportunities related to its composter facility in Edmonton, Alberta, which commenced commercial operations in August 2000. In the fourth quarter of 2000, the corporation recorded an after-tax write-down of the carrying value of the assets of $17.9 million ($0.10 EPS). On June 29, 2001, the facility was sold for cash proceeds of $97.0 million, which approximated its book value. After-tax earnings from the discontinued operation were $0.7 million (2000 - $0.7 million) prior to its disposal in the second quarter of 2001.

ALBERTA DISTRIBUTION AND RETAIL

RESULTS

Earnings from the discontinued D&R operation in Alberta included the effect of regulatory decisions relating to prior years consisting of a $5.3 million negative impact in 1999 due to the Phase II decision regarding rates for 1997 and 1996 and the Final Decision which reduced 2000 earnings by $0.8 million. Excluding the impact of these decisions, earnings from the discontinued Alberta D&R operation increased despite the partial year until its disposition in 2000, primarily due to higher distribution volumes and increased sales to higher rate customers in 2000. This business was sold on Aug. 31, 2000 for net proceeds of $857.3 million and an after-tax gain on disposition of $262.4 million ($1.55 EPS).

NEW ZEALAND

RESULTS

Earnings from discontinued operations in New Zealand decreased by $20.8 million mainly due to the partial year in 2000 and the inclusion of an after-tax gain on sale of $18.1 million ($0.11 EPS) of the gas distribution business in 1999 earnings. The New Zealand business operations were sold on March 31, 2000 for total proceeds of NZ$832.5 million (approximately Cdn$605 million) and an after-tax gain on disposition of $22.3 million ($0.13 EPS).

<table>

CONSOLIDATED BALANCE SHEETS

The following chart outlines significant changes in the consolidated balance sheets between Dec. 31, 2000 and Dec. 31, 2001:
Summary of Significant Changes Increase/
(in millions of Canadian dollars) (Decrease) Explanation
Cash 8.2 Refer to Consolidated Statements of Cash Flows.
Accounts receivable (334.0) As a result of the FERC decision to implement price caps in the WSCC region of the U.S. and lower economic activity, Energy Marketing activity and related accounts receivable were reduced significantly.
Investments (190.7) New Zealand dollar deposit offset against New Zealand dollar long-term debt under right of offset agreement, offset by acquistions of $9.4 million in 2001.
Capital assets 847.0 Capital expenditures and construction activity during the period offset by depreciation and the sale of the Edmonton Composter and the plants at Mildred Lake and Fort Nelson.
Other assets (29.9) Relates primarily to decrease in fair value of balance sheet hedges of U.S. dollar amounts resulting from depreciation of the Canadian dollar relative to the U.S. dollar.
Short-term debt 64.5 Repayment of current portion of long-term debt.
Accounts payable and accrued liabilities (321.8) As a result of the FERC decision to implement price caps in the WSCC region of the U.S. and lower economic activity, Energy Marketing activity and related accounts payable were reduced significantly, offset by increased accounts payable related to assets under construction.
Long-term debt (including current portion) 309.7 Issuance of debentures, increased credit facility at Campeche net of commercial paper repayments and New Zealand right of offset agreement discussed above.
Deferred credits and other long-term liabilities 71.4 Relates primarily to increased site restoration provision and decrease in fair value of balance sheet hedges.
Non-controlling interests (94.0) Redemption of preferred shares of a subsidiary in September 2001 offset by sale of interest in the Fort Saskatchewan plant to TA Cogen.
Preferred securities 160.6 Issuance of $175.0 million of preferred securities in November 2001, net of issue costs and related tax benefits.
Shareholders' equity 32.3 Net earnings offset by dividends and net buyback of common shares.




</table>

LIQUIDITY AND CAPITAL RESOURCES

TransAlta Corporation raises substantially all external capital to be invested in the various business units and affiliated or subsidiary companies as required. This strategy allows TransAlta to gain access to sufficient capital at the lowest overall cost to finance its growth strategy and to provide corporate flexibility. Historically, external financing has been obtained from borrowings under credit facilities, proceeds from the disposal of non-core assets, the issuance of debt, preferred securities and equity. Internally, capital is also raised through operations. A summary of cash flows is as follows:

<table>
2001 2000 1999
Cash, beginning of year $ 53.8 $ 75.3 $ 155.2
Cash provided by (used in):
Operating activities 715.6 198.7 426.2
Investing activities (1,076.9) (205.0) (988.8)
Financing activities 368.7 (2.7) 488.3
Translation of foreign currency cash 0.8 (12.5) (5.6)
Cash, end of year $ 62.0 $ 53.8 $ 75.3




</table>

TransAlta increased its cash balance by $8.2 million in 2001 compared to a decrease of $21.5 million in 2000 and a decrease of $79.9 million in 1999. Significant changes were as follows: OPERATING ACTIVITIES Operating activities after changes in non-cash working capital provided cash of $715.6 million in 2001 compared to $198.7 million in 2000 and $426.2 million in 1999. Cash flow before working capital changes of $624.5 million in 2001 was consistent with 2000. In 2000, significantly increased working capital requirements resulted from deferred accounts receivable related to the sale of the discontinued Alberta D&R operation and increased trade receivables related to Centralia production and Energy Marketing activities.

INVESTING ACTIVITIES Investing activities used cash of $1,076.9 million in 2001 compared to cash used of $205.0 million in 2000 and $988.8 million in 1999.

In 2001, additions to capital assets totalled $1,246.5 million. Of this amount, $680.7 million related to Generation, and consisted primarily of the installation of scrubbers at the Centralia plant and the continued construction of the Big Hanaford gas-fired combined-cycle plant in Centralia, Washington. Capital expenditures of $466.9 million in IPP were comprised primarily of construction activities at the Sarnia, Campeche and Chihuahua plants. Acquisitions of $9.8 million were primarily made in companies involved in wind power and distributed generation.

Cash proceeds on the sale of capital assets in 2001 totalled $236.6 million, comprised primarily of proceeds from the sale of the Edmonton Composter of $97.0 million, the sale of the Mildred Lake plant for proceeds of $60.3 million, the sale of the Fort Nelson plant for proceeds of $44.1 million and proceeds from the sale of half of our interest in the Fort Saskatchewan plant of $35.0 million.

In 2000, capital expenditures of $795.0 million consisted of Generation expenditures of $247.8 million related primarily to the construction of scrubbers at the Centralia plant, the replacement of tubing at the Wabamun plant and capital maintenance at other Alberta plants. IPP expenditures of $381.0 million consisted primarily of the continued construction of the Poplar Creek plant. Cash used for acquisitions totalled $880.1 million, consisting primarily of the acquisition of the Centralia plant for $868.7 million and the acquisition of MEGA for $18.6 million, net of cash acquired of $7.2 million.

Cash provided by disposals in 2000 was $1,367.0 million. Of this, $723.6 million related to the disposal of the Alberta D&R operation and NZ$832.5 million (approximately Cdn$605 million) related to the disposal of the New Zealand operations in 2000.

In 1999, additions to capital assets were $644.9 million, consisting primarily of IPP expenditures including the Fort Nelson, Fort Saskatchewan, Poplar Creek, and Lloydminster generation projects, and the construction of the Edmonton Composter facility. Acquisitions in 1999 consisted of $186.7 million to acquire an 85 per cent interest in generating capacity of 250 MW in Western Australia and $160.9 million for the discontinued New Zealand operation. 1999 proceeds from disposals included cash received from the sale of capital assets to TransAlta Power and the sale of New Zealand's gas distribution business.

In 2000, restricted investments of $86.8 million matured. In 1999, restricted bank deposits of $224.8 million were offset by restricted investment maturities of $80.3 million as well as the final instalment of $118.4 million of proceeds on the sale of capital assets to TransAlta Power in 1998.

In 2001, cash used for long-term receivables relates primarily to an amount paid under an emissions reduction program which will be returned if emissions from the Centralia plant are reduced to a certain level by 2004.

FINANCING ACTIVITIES Financing activities provided cash of $368.7 million in 2001 compared to cash used of $2.7 million in 2000 and cash provided of $488.3 million in 1999. In 2001, cash used for the $122.1 million redemption of preferred shares of a subsidiary, cash dividends of $149.6 million, net redemption of common shares of $30.3 million, distributions to non-controlling interests of $26.3 million and net distributions on preferred securities of $23.4 million were offset by an increase in short-term debt of $61.9 million, a net increase of $497.2 million in long-term debt and the net proceeds of $169.4 million from the issuance of preferred securities. The net addition to long-term debt and the proceeds from the preferred securities issuance were used to finance the significant capital expenditures during the year.

In 2000, cash used for the $158.4 million of dividends paid on common shares, $146.8 million redemption of preferred shares of a subsidiary, dividends and distributions to non-controlling interests of $42.8 million, and net redemption of common shares of $19.3 million were offset by an increase of $255.7 million in short-term debt, and net issuances of $126.2 million in long-term debt. In 1999, cash was provided by net short-term and long-term debt issuances of $453.7 million, and the net proceeds of $294.8 million from the issuance of preferred securities, offset by $164.7 million in common share dividends. The cash was used to finance the significant investments in non-regulated assets.

The following debenture issuances occurred in 2001:

<table>
Maturity Rate Amount
Debentures 2006 6.05% $ 250.0
Debentures 2011 6.90% 225.0
$ 475.0




In 2001, TransAlta repaid the following senior secured debt of TransAlta Utilities Corporation:
Maturity Rate Amount
Debentures 2001 9.00% $ 75.0




Under the terms of the Normal Course Issuer Bid (NCIB), the corporation purchased for cancellation 2.0 million (2000 - 1.6 million; 1999 ­1.0 million) common shares at an average price of $23.93 (2000 - $15.25; 1999 - $18.94).

TransAlta's dividends per common share were $1.00 in 2001, 2000 and 1999. </table>

CREDIT FACILITIES TransAlta Corporation raises capital in the Canadian markets. At Dec. 31, 2001, the following credit facilities were in place:

The $1.5 billion Medium-Term Note program of TransAlta Corporation expires in September 2003. A total of $1,065.0 million had been issued under the facility prior to its renewal on Sept. 26, 2001. TransAlta Corporation also issued $175.0 million of 7.75 per cent preferred securities on November 29, 2001. It is the corporation's expectation that future financing requirements, including financing requirements in foreign jurisdictions, will be met primarily through raising capital at the TransAlta Corporation level. In addition to the above facilities, project financing of US$133.6 million has been raised for the Campeche project in Mexico.

CASH REQUIREMENTS Future cash requirements include additions to capital assets, acquisitions, as well as refinancing of short-term debt and maturing senior debt. In 2002, cash will be provided from operations as well as new debt, preferred securities or equity issuances. The following table provides an estimate of 2002 expenditures, refinancing requirements and the related sources of funding: 

<table>
Capital expenditures $ 1,190.0
Refinancing requirements 100.0
Total cash requirements $ 1,290.0
Cash from operations, net of dividends $ 300.0
Proceeds from disposal of Transmission operation 850.0
Issue of senior debt, preferred securities,
sale of non-core assets, or equity issuances. 140.0
Total cash sources $ 1,290.0




</table>

Cash requirements arise primarily from growth and capital maintenance requirements of Generation assets, acquisitions, refinancing long-term debt maturities, and general working capital requirements. Historically, acquisitions and new investments have initially been financed with short-term debt and subsequently refinanced with an appropriate mix of common equity, cash flow from operations, long-term debt and preferred securities, depending on prevailing market conditions.

In 2002, capital expenditures are necessary to maintain and improve the output from existing facilities to meet certain emission reduction commitments, to conclude the construction of the Big Hanaford gas-fired plant and the Sarnia plant and to continue the construction of the Campeche and Chihuahua plants in Mexico.

In addition, it is expected that approximately $250 million of short-term debt outstanding at Dec. 31, 2001 will be refinanced as long-term debt during 2002. Short-term liquidity is provided through cash flow from operations and the use of the $600 million commercial paper program and $1.2 billion syndicated credit facility. At Dec. 31, 2001, there was $464.4 million of commercial paper on issue, $330.0 million of bankers acceptances and $113.1 million letters of credit utilized from the $1.2 billion credit facility, resulting in approximately $892.5 million of short-term funds available.

On Jan. 16, 2001, the corporation issued $250 million of Medium-Term Notes at an interest rate of 6.05 per cent repayable in five years. On May 1, 2001, the corporation issued $225 million of Medium-Term Notes at an interest rate of 6.9 per cent repayable in ten years. The proceeds were used to repay short-term debt.

Long-term funding is provided through the maintenance of high-quality credit ratings and a carefully managed capital structure, which together create a strong balance sheet and ready access to capital markets at competitive rates. The corporation's objective is to manage the maturities of the various securities on issue such that no more than 15 per cent of the total outstanding securities mature in any one year.

The corporation's targets are to maintain its credit ratings at current levels and to maintain a capital structure of 50 per cent debt to total capitalization. The corporation's capital structure consisted of the following components at Dec. 31, 2001 and 2000:

<table>
2001 2000
Debt, net of cash and interest-earning investments $ 2,986.3 52% $ 2,421.9 48%
Preferred securities 452.6 8% 292.0 6%
Other non-controlling interests 281.0 5% 253.4 5%
Preferred shares of a subsidiary - - 121.6 2%
Common shareholders' equity 1,989.7 35% 1,957.4 39%
$ 5,709.6 100% $ 5,046.3 100%












Key financial ratios were as follows:
2001 2000 1999
Cash flow to interest1 4.9x 4.6x 4.0x
Cash flow to total debt2 23% 26% 21%
Total debt to total capitalization3 53% 50% 46%
1 Cash flow from operations before changes in working capital and gross interest expense divided by gross interest expense.
2 Cash flow from operations before changes in working capital divided by two-year average of total debt.
3 Total debt divided by the sum of total debt, non-controlling interests, preferred securities and common shareholders' equity.






Contractual repayments of long-term debt, commitments under operating leases, commitments to purchase turbines and commitments under mining agreements are as follows:
Total 2002 2003 2004 2005 2006 2007 and thereafter
Long-term debt1 $ 2,511.1 $ 104.3 $ 355.6 $ 136.3 $ 237.3 $ 354.2 $ 1,323.4
Operating leases $ 15.1 4.7 4.7 1.6 1.1 1.0 2.0
Turbine purchase commitments $ 262.9 58.7 118.1 79.9 6.2 - -
Mining agreements $ 250.0 10.9 10.9 10.9 10.9 10.9 195.5
Total contractual cash obligations $ 3,039.1 $ 178.6 $ 489.3 $ 228.7 $ 255.5 $ 366.1 $ 1,520.9
1 Includes capital lease obligations.

</table>

The corporation has also entered into a number of long-term gas purchase contracts, transportation and transmission agreements, royalty and right-of-way agreements in the normal course of operations.



Other commercial commitments are as follows:

<table>
Amount of commitment expiration per period
Total 2002 2003 2004 2005 2006 2007 and thereafter
Letters of credit $ 261.3 $ 261.3 $ - $ - $ - $ - $ -
Guarantees1 $ 1,113.6 380.9 457.1 37.0 43.2 20.0 175.4
Total commercial commitments $ 1,374.9 $ 642.2 $ 457.1 $ 37.0 $ 43.2 $ 20.0 $ 175.4
1 Represents obligations existing under guarantees issued for subsidiaries of TransAlta Corporation. Guarantee limits are $1,729.4 million.




</table>

At Dec. 31, 2001, the credit ratings for the corporation's various securities and TransAlta Power's units as determined by the Dominion Bond Rating Service (DBRS), Standard & Poor's (S&P) and Moody's rating services are as follows:

<table>
S&P DBRS Moody's
TransAlta Corporation
Issuer rating BBB+ A3
Commercial paper R1 (low)
Senior unsecured debentures BBB+ A (low)
Preferred securities BBB- Pfd-2 (low) y
TransAlta Utilities Corporation
Issuer rating BBB+
Secured debt A- A
TransAlta Power, L.P.* SR-1
* Non-controlling partner in TransAlta's subsidiary, TransAlta Cogeneration, L.P.

</table>

OFF-BALANCE SHEET ARRANGEMENTS The United States Securities and Exchange Commission (SEC) requires disclosure of all off-balance sheet arrangements such as relationships or arrangements with unconsolidated entities, structured finance entities or special purpose entities that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. The corporation has no such off-balance sheet arrangements.

RELATED PARTY TRANSACTIONS

As disclosed in Notes 5 and 22 to the consolidated financial statements, the corporation sold its 60 per cent interest in its Fort Saskatchewan plant to TA Cogen, a limited partnership owned 50.01 per cent by the corporation and 49.99 per cent by TransAlta Power, a publicly owned entity. Total cash consideration to the corporation was $35.0 million in respect of the 30 per cent interest effectively sold to the minority interest in TA Cogen. The corporation recorded a gain of $6.2 million, $5.0 million after-tax. The business purpose of the arrangement was to realize a portion of the inherent value of the plant and provide cash for future growth initiatives while retaining control and operation of the asset through a management agreement with TA Cogen. The exchange amount was determined based on an estimate of the future net cash flows of the plant and approved by the independent directors of TA Cogen. There are no ongoing contractual commitments or arrangements resulting from this sale apart from the provision of operational and management services under normal commercial terms.

In 1998, the corporation sold a 49.99 per cent interest in three Ontario cogeneration plants held by TA Cogen to TransAlta Power. The corporation is obligated to purchase all of TransAlta Power's interest in TA Cogen on Dec. 31, 2018 at the fair market value on that date. Accordingly, the gain of $160.3 million is being deferred and amortized on a straight-line basis over the period to Dec. 31, 2018. The business purpose of the arrangement was to realize the inherent value of the plants in order to provide cash for future growth initiatives while retaining control and operation of the assets. The exchange amount was determined based on the fair value of the plants at the time of the transaction and approved by the independent directors of TA Cogen.

In 2000, TA Cogen entered into a fixed-for-floating gas swap transaction with TransAlta Energy, a wholly-owned subsidiary of the corporation, for a five year and one month period starting Dec. 1, 2000. The business purpose of the swap was to provide TA Cogen with fixed price gas for two of its plants over the period of the swap to stabilize cash distributions. The floating prices associated with the plants' long-term fuel supply agreements were transferred to TransAlta Energy's account. The notional gas volume in the transaction was the total delivered fuel for both facilities. As consideration and in negotiation, TA Cogen transferred the right to incremental revenues associated with curtailed electrical production and subsequent higher revenue gas sales to TransAlta Energy. The exchange amount was determined based on the fair value of the contract when it was entered and approved by the independent directors of TA Cogen.

ENERGY TRADING ACTIVITIES

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. Transmission contracts outstanding at Dec. 31, 2001 had a fair value of $nil. Realized and unrealized changes in the fair value of energy trading contracts in 2001, exclusive of hedging transactions (Note 20), were $154.7 million and $6.3 million, respectively. There were no changes in valuation techniques during the year.

Maturities of energy trading contracts, exclusive of hedging transactions, existing at Dec. 31, 2001 over each of the next five years and thereafter is as follows:

<table>
Fair value of contracts at period end
Source of fair value Total 2002 2003 2004 2005 2006 2007 and thereafter
Prices actively quoted $ 31.3 $ 26.5 $ 2.0 $ 0.8 $ 0.8 $ 0.8 $ 0.4
Prices based on models or other valuation methods - - - - - - -
$ 31.3 $ 26.5 $ 2.0 $ 0.8 $ 0.8 $ 0.8 $ 0.4




</table>

RISK FACTORS AND RISK MANAGEMENT

TransAlta utilizes a multi-level risk management oversight structure to manage the corporation's various risk and energy trading exposures.

The Audit and Environment (A&E) Committee of the Board of Directors oversees corporate-wide risk management through review of TransAlta's overall business risks. The Chief Financial Officer reports to the A&E Committee and is responsible for ensuring compliance with TransAlta's financial and commodity risk exposure management policies. These policies include limits on exposures (commodity prices, currency, credit and interest rates), reporting practices and other procedures necessary for the corporation to manage and control its financial and commodity exposures. The Exposure Management (EM) Committee is chaired by the Chief Financial Officer and is comprised of the Directors of Financial Operations for each business unit, the Vice President and Treasurer, Vice President and Comptroller, Director of Internal Audit, Vice President of TransAlta Energy Marketing and the Manager of Treasury Operations. The EM Committee is responsible for the review, monitoring and reporting on compliance of these financial and commodity risk exposure management policies.

The following addresses some risk factors, but not all, that could affect TransAlta's future results.

COMMODITY PRICE RISK The corporation has exposure to movements in selected commodity prices including electricity and natural gas in both its electricity generation and proprietary trading businesses. A significant portion of the coal used in electricity generation is from coal reserves owned by TransAlta, thereby limiting the corporation's exposure to fluctuations in the market price of coal.

Electricity generation is exposed to price fluctuations of electricity sold to the market and natural gas used in generating electricity. In addition to the PPAs, the corporation has entered into a variety of short- and long-term contracts to limit its exposure to short-term price movements and maximize overall revenues. At Dec. 31, 2001, 91.7 per cent of total output was at contractually fixed prices, 71.0 per cent of TransAlta's cost of gas used in generating electricity was fixed or passed through to customers and 100.0 per cent of the corporation's purchased coal costs were fixed. In the event of an unplanned plant outage or other similar event, however, the corporation is exposed to electricity prices on purchases of electricity from the market to fulfill its supply obligations under these short- and long-term contracts. The corporation actively mitigates this exposure through continued and proper maintenance of its electricity generating plants, force majeure clauses negotiated in the contracts, trading activities and insurance.

The corporation's proprietary trading of gas and electricity is strictly controlled and limited and is managed through the use of Value at Risk methodologies.

CURRENCY RATE EXPOSURE The corporation has exposure to various currencies as a result of its investments and operations in foreign jurisdictions and the acquisition of equipment and services from foreign suppliers. The corporation has exposures primarily to the United States, Australian and Swiss currencies. These exposures are managed through the use of a variety of hedging instruments including cross-currency interest rate swaps and forward sales contracts. At Dec. 31, 2001, the corporation had hedged approximately 98 per cent of its currency rate exposures on a pre-tax basis.

Translation gains and losses related to the carrying value of the corporation's foreign operations are deferred and included in the cumulative translation account in shareholders' equity. At Dec. 31, 2001, the balance in this account was a loss of $19.5 million (including a $6.0 million tax effect on hedging losses) compared to a $19.8 million loss at the end of 2000.

CREDIT RISK The corporation actively manages its exposure to credit risk by assessing the ability of counterparties to fulfill their obligations under the related contracts prior to entering into such contracts. The corporation sets strict credit limits for each counterparty and the mix of counterparties based on their credit ratings and halts trading activities with a counterparty if the limits are exceeded. TransAlta is not exposed to credit risk for Alberta Generation PPAs under the terms of these contracts.

The corporation has a concentration of credit risk relating to its long-term receivable of $173.3 million from UtiliCorp Networks Canada arising from the sale of the discontinued Alberta D&R operation. At Dec. 31, 2000, TransAlta had accounts receivable of US$66.2 million related to the California market. At Dec. 31, 2001, US$53.3 million remains outstanding, for which a provision of US$28.8 million remains. The provision will be reversed when the corporation has confidence in the ultimate collection of the amounts owing and that it will not have to make any repayment of such amounts. At Dec. 31, 2001, TransAlta's exposure to credit risk resulting from the bankruptcy of Enron Corporation was $1.3 million and appropriate provisions have been made.

The maximum credit exposure to any one customer, including the fair value of open trading positions, is $98.4 million. Of this amount, approximately $47 million is secured by a letter of credit.

INTEREST RATE EXPOSURE The corporation has exposure to movements in interest rates and manages this exposure by maintaining a limit on the amount of debt subject to floating interest rates. At Dec. 31, 2001, approximately 35 per cent of the corporation's total debt portfolio was subject to movements in floating interest rates through a combination of floating rate debt and interest rate swaps.

OPERATIONAL RISK The corporation's plants have exposure to operational risks such as fatigue cracks in boilers, corrosion in boiler tubing and other issues that can lead to outages. A comprehensive plant maintenance program and regular turnarounds reduce this exposure. Force majeure clauses in the PPAs and insurance further mitigate this exposure.

Approximately 57 per cent of the corporation's labour force is covered under collective bargaining agreements. The agreements of approximately 33 per cent of this unionized labour force are being negotiated during 2002. Management does not anticipate any significant issues in the renegotiations of these agreements.

ENVIRONMENTAL, HEALTH AND SAFETY RISK TransAlta's approach is to continually improve the management of operation risks in the areas of environment, health and safety while developing mechanisms to manage future risks. These programs are integrated into the operations and management systems of the company. They are designed to mitigate the potential competitive risks to its fossil-fuelled generation plants from future changes in public policy. This could include changes to environmental controls, regulatory regimes, taxes or charges, to meet due diligence requirements and to enhance environmental performance through implementing systems and standards such as ISO 14001. Contractual provisions in the Alberta PPAs substantially cover TransAlta for risks related to potential changes in law. TransAlta's environmental strategy addresses the following key areas: reducing net emissions; participating in provincial, federal and international policy development; contributing to research and development; purchasing renewable energy; and testing market-based approaches that deliver real environmental benefits, such as the trading of emission reduction credits. In 2001, as part of its climate change strategy, TransAlta continued to invest in Vision Quest Windelectric Inc., a company that utilizes wind-based technology to generate electricity and made substantial investments in technology upgrades at the Centralia plant to significantly improve environmental performance by reducing emissions. In 2001, TransAlta again exceeded its voluntary goal to reduce its net greenhouse gas emissions in Canada to 1990 levels. All TransAlta facilities undergo compliance and management system integrity audits on a cycle determined by facility performance, on average, once every three years. The Dow Jones Sustainability Index has again recognized TransAlta as one of the world's best utility companies in terms of environmental, health and safety performance, and TransAlta has also been recognized on the FTSE4 (Financial Times Stock Exchange) Good Global Index, a London-based sustainability index.

REGULATORY AND POLITICAL RISK TransAlta's transmission business remains exposed to the regulatory risks associated with delays in receipt of regulatory decisions. Regulatory and political risks also exist in other jurisdictions in which TransAlta operates. TransAlta manages these risks by working with regulators and other stakeholders to attempt to resolve issues as fairly and expeditiously as possible.

WEATHER-RELATED BUSINESS RISKS In early 1998, severe ice storms cut off electricity for weeks to millions of residents in Quebec and Ontario. The nature of the ice storm was particularly severe and widespread. This type of storm, although extremely unusual, is an ongoing risk for electric companies. This risk is mitigated through force majeure clauses in the Alberta PPAs and power sales contracts and access to multiple transmission lines.

CORPORATE STRUCTURE The corporation conducts a significant amount of business through subsidiaries and partnerships. The corporation's ability to meet and service debt obligations is dependent upon the results of operations of its subsidiaries and the payment of funds by such subsidiaries to the corporation in the form of distributions, loans, dividends or otherwise. In addition, TransAlta's subsidiaries may be subject to statutory or contractual restrictions which limit their ability to distribute cash to the ultimate shareholder, TransAlta Corporation.

GENERAL ECONOMIC CONDITIONS Changes in general economic conditions impact product demand, revenue, operating costs, timing and extent of capital expenditures, the net recoverable value of property, plant and equipment, results of financing efforts, credit risk and counterparty risk.

INCOME TAXES The corporation's operations are complex, and the computation of the provision for income taxes involves tax interpretations, regulations and legislation that are continually changing. The corporation's tax filings are subject to audit by taxation authorities. The outcome of some audits may increase the tax liability of the corporation. Management believes that it has adequately provided for income taxes based on all information currently available.

LEGAL CONTINGENCIES The corporation, through generation and transmission of services and products, is occasionally named as a defendant in various claims and legal action. The nature of these claims is usually related to personal injury, environmental issues and pricing. Exposure to these claims is mitigated through levels of insurance coverage considered appropriate by management. Except as disclosed in note 24 to the consolidated financial statements, the corporation does not expect the outcome of the claims or potential claims to have a materially adverse effect on the corporation as a whole.

OTHER CONTINGENCIES The corporation maintains a level of insurance coverage deemed appropriate by management and for matters for which insurance coverage can be maintained. There have been no significant changes to TransAlta's insurance coverage during 2001 except for the discontinuance of coverage for terrorist acts.

SENSITIVITY ANALYSIS The following table shows the effect on net earnings and cash flows of changes in certain key variables. The analysis is based on business conditions and production volumes in 2001. Each separate item in the sensitivity assumes the others are held constant. While these sensitivities are applicable to the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitude of changes.

<table>
Approximate change
Factor Change Cash flow Earnings (after-tax)
Electricity price $1.00/MWh $ 2.0 $ 2.0
Exchange rate (US$ per Cdn$) US$0.01 0.2 0.2
Interest rate 1.0% 2.1 2.1




</table>

EMPLOYEE FUTURE BENEFITS

TransAlta has a registered pension plan with defined benefit and defined contribution options and a supplemental defined benefit plan covering substantially all employees of the corporation, its domestic subsidiaries and specific named employees working internationally. The defined benefit plan option of the registered pension plan ceased for new employees on June 30, 1998. The defined benefit plan had a net accounting surplus of $16.8 million at Dec. 31, 2001. TransAlta does not expect to make any contributions to its plans in the near term, and will use the surplus in the registered defined benefit plan to pay benefits under both the registered defined contribution and the supplemental defined benefit options. Using the assumptions outlined in Note 19 to the consolidated financial statements, management estimates that the surplus will be consumed in approximately nine years of benefit payments.

EMPLOYEE SHARE OWNERSHIP

TransAlta employs a variety of stock based compensation plans to align employee and corporate objectives. In 2001, the corporation expanded enrolment in the corporation's common share option program to include all Canadian and United States employees of the corporation. At Dec. 31, 2001, 2.8 million options to purchase the corporation's common stock were outstanding with 0.7 million exercisable at the reporting date.

Under the terms of the Performance Share Ownership Plan (PSOP), certain employees receive awards which, after three years, make them eligible to receive a set number of common shares or cash equivalent plus dividends thereon based upon the performance of the corporation relative to a selected group of publicly traded companies. On Dec. 31, 2001, the plan was modified so that after three years, once PSOP eligibility has been determined, 50 per cent of the shares may be released to the participant, while the remaining 50 per cent will be held in trust for one additional year. The first PSOP maturity occurred in 2000 with 120,101 common shares issued at $14.15 per share. In 2001, 83,077 common shares were issued at $22.00 per share. At Dec. 31, 2001, there were 1.0 million PSOP awards outstanding.

Under the terms of the Employee Share Purchase Plan, the corporation will extend an interest-free loan to employees of up to 30 per cent of the employee's base salary for the purchase of common shares of the corporation from the open market. The loan is repaid over a three-year period by the employee through payroll deductions unless the shares are sold, at which point the loan becomes due on demand. At Dec. 31, 2001, 0.3 million shares had been purchased by employees under this program.

CHANGES IN ACCOUNTING STANDARDS

During 2001, the Canadian Institute of Chartered Accountants (CICA) and the Financial Accounting Standards Board (FASB) in the U.S. issued new standards regarding business combinations and goodwill and other intangible assets. The new standards require business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting. It also specifies the types of acquired intangible assets that are required to be recognized and reported separately from goodwill. In addition, goodwill and certain intangibles will no longer be amortized, but instead will be tested for impairment at least annually. The new recommendations are to be applied in fiscal years beginning after Dec. 15, 2001, with early adoption permitted in certain circumstances. The corporation adopted the recommendations effective Jan. 1, 2002, which resulted in the reclassification of $29.3 million from acquired intangibles relating to the acquisition of MEGA, to goodwill, which will not be subject to amortization. There was no impairment of this goodwill upon adoption. Amortization of this amount was approximately $7.7 million in 2001 (2000 - $3.6 million; 1999 - $nil).

In September 2001, the CICA issued a new Canadian standard on stock-based compensation that harmonizes Canadian and U.S. GAAP. The new standard requires that stock-based payments, 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-based 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, disclosure is made of earnings and per share amounts as if the fair value method had been used. The new standard is to be applied in fiscal years beginning on or after Jan. 1, 2002. The corporation has elected to use the intrinsic value method. The impact would be as disclosed in Note 26.

In November 2001, the CICA issued an accounting guideline on hedging relationships. The new guideline establishes certain conditions where hedge accounting may be applied. It is effective for years beginning on or after July 1, 2002. The corporation expects all criteria to be met for all hedging relationships with the exception of written swaptions, which are ineffective under the guideline. Hedge accounting will be discontinued for the written swaptions in accordance with the guideline. The impact on earnings at Dec. 31, 2001 was a decrease of approximately $0.4 million after-tax.

In December 2001, the CICA amended its standard on foreign currency translation. The changes, effective Jan. 1, 2002, 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 had been amortized over the life of the related item. As TransAlta designates long-term foreign currency denominated monetary items as hedges of net investments in foreign operations, the unamortized balance of deferred gains or losses at Dec. 31, 2001 was $nil (2000 - $nil).

In August 2001, the 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. The new standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. Upon adoption, the corporation will recognize an increase in liabilities under U.S. GAAP in the amount of approximately $470 million with a corresponding increase in capital assets under U.S. GAAP.

In October 2001, the FASB issued Statement 144, Impairment and Disposal of Long-Lived Assets, which requires that all long-lived assets, including discontinued operations, be measured at the lower of carrying amount or fair value less costs to sell. Discontinued operations are no longer measured at net realizable value and will no longer include provisions for operating losses that have not yet occurred. Further, discontinued operations have been broadened to include components that can be distinguished from the rest of the entity. The new standard is effective for fiscal years beginning after Dec. 14, 2001, with earlier application encouraged. The corporation does not expect impairment of any long-lived assets upon adoption, and no provision for losses have been made for the discontinued Transmission operation, the sale of which is expected to close in the first half of 2002.

SELECTED QUARTERLY FINANCIAL INFORMATION

<table>
(Unaudited; in millions of Canadian dollars except per share amounts)
2001 Quarters First Second Third Fourth Total
Total revenues $ 1,446.4 $ 1,552.8 $ 969.2 $ 958.7 $ 4,927.1
Earnings from continuing operations1 55.9 47.0 33.4 33.2 169.5
Net earnings1 67.6 59.1 41.4 46.5 214.6
Basic earnings (loss) per common share: -
Continuing operations 0.33 0.28 0.20 0.19 1.00
Net earnings 0.40 0.35 0.25 0.27 1.27
Diluted earnings (loss) per common share:
Continuing operations 0.32 0.27 0.20 0.19 0.98
Net earnings 0.39 0.34 0.25 0.27 1.25
2000 Quarters First Second Third Fourth Total
Total revenues $ 359.0 $ 535.0 $ 720.0 $1188.5 $2,802.5
Earnings from continuing operations1 44.2 30.0 22.1 37.3 133.6
Net earnings1 93.1 50.7 316.1 (180.1) 279.8
Basic earnings (loss) per common share:
Continuing operations 0.26 0.18 0.13 0.22 0.79
Net earnings 0.55 0.30 1.87 (1.06) 1.66
Diluted earnings (loss) per common share:
Continuing operations 0.25 0.18 0.12 0.22 0.77
Net earnings 0.55 0.30 1.84 (1.06) 1.63
1 Applicable to common shareholders, net of preferred securities distributions.

</table>









































Exhibit 2

TransAlta Corporation

Consolidated Financial Statements

Years ended Dec. 31, 2001, 2000 and 1999

MANAGEMENT'S RESPONSIBILITY

In management's opinion, the accompanying consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of appropriately selected Canadian generally accepted accounting principles and policies consistently applied and summarized in the consolidated financial statements. Since a precise determination of many assets and liabilities is dependent upon future events, the preparation of periodic financial statements necessarily involves the use of estimates and approximations. These have been made using careful judgment and with all information available up to Feb. 1, 2002. Management is responsible for all information in the annual report. Financial operating data in the report are consistent, where applicable, with the consolidated financial statements.

To meet its responsibility for reliable and accurate financial statements, management has established systems of internal control which are designed to provide reasonable assurance that financial information is relevant, reliable and accurate, and that assets are safeguarded and transactions are executed in accordance with management's authorization. These systems are monitored by management and by internal auditors. In addition, the internal auditors perform appropriate tests and related audit procedures.

The consolidated financial statements have been examined by Ernst & Young LLP, independent chartered accountants. The external auditors' responsibility is to express a professional opinion on the fairness of management's consolidated financial statements. The auditors' report outlines the scope of their examination and sets forth their opinion.

The Audit and Environment (A&E) Committee of the Board of Directors is comprised of independent directors. The audit committee meets regularly with management, the internal auditors and the external auditors to satisfy itself that each is properly discharging its responsibilities, and to review the consolidated financial statements. The A&E Committee reports its findings to the Board of Directors for consideration when approving the consolidated financial statements for issuance to the shareholders. The A&E Committee also recommends, for review by the Board of Directors and approval of shareholders, the appointment of the external auditors. The internal and external auditors have full and free access to the A&E Committee.





Stephen G. Snyder Ian A. Bourne

President & Chief Executive Officer Executive Vice-President & Chief Financial Officer

Feb. 1, 2002

AUDITORS' REPORT

TO THE SHAREHOLDERS OF TRANSALTA CORPORATION

We have audited the consolidated balance sheets of TransAlta Corporation as at Dec. 31, 2001 and 2000 and the consolidated statements of earnings and retained earnings and cash flows for each of the years in the three year period ended Dec. 31, 2001. These financial statements are the responsibility of the corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the corporation as at Dec. 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended Dec. 31, 2001 in accordance with Canadian generally accepted accounting principles.





Chartered Accountants

Calgary, Canada

Feb. 1, 2002

CONSOLIDATED STATEMENTS OF EARNINGS & RETAINED EARNINGS<table>
Years ended Dec. 31
(in millions of Canadian dollars except per share amounts) 2001 2000 1999
Revenues $ 4,927.1 $ 2,802.5 $ 1,123.0
Trading purchases (2,533.7) (1,202.5) (272.0)
Fuel and purchased power (1,288.7) (655.8) (216.6)
Gross margin 1,104.7 944.2 634.4
Operating expenses
Operations, maintenance and administration 444.5 349.9 234.8
Depreciation and amortization 273.6 205.6 164.4
Taxes, other than income taxes 18.7 23.9 21.9
736.8 579.4 421.1
Operating income 367.9 364.8 213.3
Other income (expense) 1.5 (1.1) -
Foreign exchange gains 0.8 0.1 1.7
Net interest expense (Note 11) (88.1) (91.4) (65.5)
Earnings from continuing operations before regulatory decisions,
Income taxes and non-controlling interests 282.1 272.4 149.5
Prior period regulatory decisions (Note 17) 11.0 44.1 -
Earnings from continuing operations before income taxes
and non-controlling interests 293.1 316.5 149.5
Income taxes (Note 18) 89.9 128.5 64.7
Non-controlling interests (Note 13) 20.6 41.6 30.9
Earnings from continuing operations 182.6 146.4 53.9
Earnings from discontinued operations (Notes 3 and 17) 45.1 89.1 101.7
Net gain on disposal of discontinued operations (Note 3) - 266.8 19.7
Net earnings before extraordinary item 227.7 502.3 175.3
Extraordinary item (Note 4) - (209.7) -
Net earnings 227.7 292.6 175.3
Preferred securities distributions, net of tax (Note 14) 13.1 12.8 5.2
Net earnings applicable to common shareholders $ 214.6 $ 279.8 $ 170.1
Common share dividends (168.4) (168.7) (169.5)
Adjustment arising from normal course issuer bid (Note 15) (34.8) (7.5) -
Retained earnings
Opening balance 826.9 723.3 722.7
Closing balance $ 838.3 $ 826.9 $ 723.3
Weighted average common shares outstanding in the year 168.9 168.8 169.5
Basic earnings per share
Continuing operations $ 1.00 $ 0.79 $ 0.29
Earnings from discontinued operations (Note 3) 0.27 0.53 0.60
2. Net earnings from operations 1.27 1.32 0.89
Net gain on disposal of discontinued operations (Note 3) - 1.58 0.11
Extraordinary item (Note 4) - (1.24) -
Net earnings $ 1.27 $ 1.66 $ 1.00
Diluted earnings per share (Notes 14 and 15)
Continuing operations $ 0.98 $ 0.77 $ 0.27
Net earnings $ 1.25 $ 1.63 $ 0.98
SEE ACCOMPANYING NOTES

</table>



CONSOLIDATED BALANCE SHEETS

<table>
Dec. 31
(in millions of Canadian dollars) 2001 2000
Assets
Current assets
Cash $ 62.0 $ 53.8
Accounts receivable (Note 20) 1,139.7 1,473.7
Future income tax assets (Note 18) 16.9 30.3
Income taxes receivable (Note 18) 128.3 153.9
Materials and supplies at average cost 85.5 91.3
1,432.4 1,803.0
Investments (Note 6) 37.3 228.0
Long-term receivables (Notes 7 and Note 20) 221.4 232.9
Capital assets (Notes 8 and 11)
Cost 8,813.3 7,762.1
Accumulated depreciation (2,689.2) (2,485.0)
6,124.1 5,277.1
Future income tax assets (Note 18) 15.6 9.1
Other assets (Note 9) 47.1 77.0
Total assets $ 7,877.9 $ 7,627.1
3. Liabilities and shareholders' equity
Current liabilities
Short-term debt (Note 10) $ 537.2 $ 472.7
Accounts payable and accrued liabilities (Note 20) 1,116.1 1,437.9
Income taxes payable (Note 18) - 41.4
Future income taxes (Note 18) 11.8 -
Dividends payable 42.8 44.8
Current portion of long-term debt (Note 11) 104.3 79.6
1,812.2 2,076.4
Long-term debt (Note 11) 2,406.8 2,121.8
Deferred credits and other long-term liabilities (Note 12) 526.5 455.1
Future income tax liabilities (Note 18) 409.1 349.4
Non-controlling interests (Note 13) -
Preferred shares of a subsidiary - 121.6
Other 281.0 253.4
281.0 375.0
Preferred securities (Note 14) 452.6 292.0
Common shareholders' equity
Common shares (Notes 15 and 16)
Authorized: unlimited
Issued: 168.3 million (2000 ­ 168.6 million) 1,170.9 1,150.3
Retained earnings 838.3 826.9
Cumulative translation adjustment (19.5) (19.8)
1,989.7 1,957.4
Total liabilities and shareholders' equity $ 7,877.9 $ 7,627.1
Contingencies and commitments (Notes 3, 11, 20, 23 and 24)
SEE ACCOMPANYING NOTES.

</table>

On behalf of the board:
/s/ John T. Ferguson Director /s/ John S. Lane Director








































CONSOLIDATED STATEMENTS OF CASH FLOWS <table>
Years ended Dec. 31
(in millions of Canadian dollars) 2001 2000 1999
Operating activities
Net earnings $ 227.7 $ 292.6 $ 175.3
Depreciation and amortization 325.9 321.7 325.5
Non-controlling interests 20.6 44.6 52.1
Gains on sale of assets (Notes 3 and Note 5) (5.4) (284.9) (36.0)
Write-down of discontinued Edmonton Composter (Note 3) - 17.9 -
Recovery of discontinued operation in Argentina (Note 3) - - (19.7)
Future income taxes (Note 18) 39.9 34.1 7.3
Unrealized gain (loss) from risk management activities (6.3) (24.0) 0.9
Extraordinary item (Note 4) - 209.7 -
Other non-cash items 22.1 5.2 (27.7)
624.5 616.9 477.7
Change in non-cash operating working capital balances 1 91.1 (418.2) (51.5)
Cash flow from operating activities 715.6 198.7 426.2
Investing activities
Additions to capital assets (1,246.5) (795.0) (644.9)
Acquisitions (Note 5) (9.8) (880.1) (347.6)
Proceeds on sale of capital assets (Note 5) 201.6 - 118.4
Proceeds on sale of capital assets to limited partnership (Notes 5, 12 and 22) 35.0 - -
Disposals (Notes 3 and 5) - 1,367.0 89.9
Long-term receivables (46.3) 12.1 9.1
Investments (Note 6) - (9.5) 16.3
Restricted investments - 86.8 (153.4)
Deferred charges and other (10.9) 13.7 (76.6)
Cash flow used in investing activities (1,076.9) (205.0) (988.8)
Financing activities
Net increase in short-term debt 61.9 255.7 121.5
Issuance of long-term debt 789.9 330.8 835.4
Repayment of long-term debt (292.7) (204.6) (503.2)
Proceeds on issuance of preferred securities, net of after-tax issue costs 169.4 - 294.8
Redemption of preferred shares of a subsidiary (122.1) (146.8) -
Issuance of common shares 14.1 4.6 6.0
Redemption of common shares (44.4) (23.9) (18.1)
Distributions on preferred securities (23.4) (22.1) (9.4)
Dividends on common shares (149.6) (158.4) (164.7)
Dividends to subsidiary's non-controlling preferred shareholders (8.3) (14.8) (21.1)
Dividends to subsidiary's non-controlling common shareholders - (7.0) (33.0)
Distributions to subsidiary's non-controlling limited partner (26.3) (21.0) (22.7)
Other 0.2 4.8 2.8
Cash flow from (used in) financing activities 368.7 (2.7) 488.3
Cash flow from (used in) operating, investing and financing activities 7.4 (9.0) (74.3)
Effect of translation on foreign currency cash 0.8 (12.5) (5.6)
Increase (decrease) in cash 8.2 (21.5) (79.9)
Cash at beginning of year 53.8 75.3 155.2
Cash at end of year 62.0 53.8 75.3
Interest paid 163.1 173.2 166.2
Income taxes paid 41.5 140.3 198.7
1 The change in non-cash operating working capital balances and cash flow from operating activities for the year ended December 31, 2000 includes the impact of increased deferral accounts receivable for the discontinued Alberta Distribution and Retail business operation until the date of disposal on August 31, 2000. The related proceeds from the disposal of these deferral accounts receivable, totalling $164.3, million are classified as cash provided by investing activities, of which $24.2 million was received in 2000 (Note 3).




</table>

SEE ACCOMPANYING NOTES.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1. Summary of significant accounting policies A. CONSOLIDATION AND INVESTMENTS

These consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles (GAAP). These accounting principles are different in some respects from United States generally accepted accounting principles (U.S. GAAP). The significant differences are described in Note 26.

The consolidated financial statements include the accounts of TransAlta Corporation (TransAlta or the corporation), all subsidiaries and the proportionate share of the accounts of jointly controlled corporations. TransAlta Utilities Corporation (TransAlta Utilities) and TransAlta Energy Corporation (TransAlta Energy) are the principal wholly owned operating subsidiaries.

TransAlta Utilities owns and operates electric generation and transmission facilities in the province of Alberta. TransAlta Utilities also owned and operated a distribution and retail (D&R) operation in Alberta until the operation was disposed of on Aug. 31, 2000. A purchase and sale agreement to dispose of the transmission operation was signed on July 4, 2001, and is expected to close in the first half of 2002, subject to regulatory approval. TransAlta Energy is engaged in electric and thermal energy supply, energy services and energy marketing in Canada and internationally. TransAlta Energy also owned and operated an electricity generation and retail operation in New Zealand until the operations were disposed of on March 31, 2000 (Note 3). Investments in entities that are not proportionately consolidated but over which the corporation exercises significant influence are accounted for using the equity method. Other investments are accounted for using the cost method.

B. MEASUREMENT UNCERTAINTY

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates due to factors such as fluctuations in interest rates, currency exchange rates, inflation levels and commodity prices, changes in economic conditions and legislative and regulatory changes (Notes 3, 20 and 24).

C. REGULATION TransAlta Utilities is regulated by the Alberta Energy and Utilities Board (EUB), pursuant to the Hydro and Electric Energy Act (Alberta); pursuant to Part 2 of the Public Utilities Board Act (Alberta); pursuant to the Electric Utilities Act (Alberta); and is subject to the Provincial Water Power Regulations (Alberta). These acts and regulations cover matters such as tariffs, rates, construction, operations, financing and accounting.

TransAlta Utilities accounts for transactions in accordance with applicable regulation (regulatory accounting) when three criteria are met: the rates for services or products provided to customers are established by or are subject to approval by a regulatory body; the regulated rates are designed to recover the cost of providing the services or products; and it is reasonable to assume that rates are set at levels that will recover the cost that can be charged to and collected from customers. Under regulatory accounting, the timing of TransAlta Utilities' recognition of certain assets, liabilities, revenues and expenses may differ from that otherwise expected using Canadian GAAP for non-regulated businesses.

When one of the above three criteria no longer applies to a TransAlta Utilities operation, regulatory accounting ceases and the application of Canadian GAAP for non-regulated businesses commences for that operation at the date the criteria were no longer met. Upon discontinuation of regulatory accounting, the effects of any action of regulators that had been recognized as assets and liabilities that would not have been recognized as assets or liabilities under Canadian GAAP are eliminated and future income tax liabilities or assets not recorded under regulatory accounting are recognized. The net effect of these adjustments are included in the period in which the discontinuation of regulated accounting occurs and is classified as an extraordinary item.

Commencing Jan. 1, 2001, all Alberta generating plants were deregulated and became subject to long-term Power Purchase Arrangements (PPAs) for the remaining estimated life of each plant. The PPAs set a production requirement and availability target to be supplied by each plant or unit and the price at which each megawatt-hour will be supplied to the customer. As the criteria for regulatory accounting were no longer met, Canadian GAAP for non-regulated businesses commenced on Dec. 31, 2000, in respect of the Alberta Generation operations.

D. REVENUE RECOGNITION Electrical energy revenue is recognized upon transmission to the customer. Thermal revenue is recognized upon delivery to the customer. Capacity and ancillary revenue is recognized when contractually earned. In accordance with the Canadian Institute of Chartered Accountants (CICA) recommendations, revenues are reported on a gross basis unless the corporation is acting in the capacity of an agent or a broker in which case they are recognized net of purchases. The Energy Marketing segment acts as a principal, taking title to the commodities purchased for resale and assumes the risks and rewards of ownership, and therefore recognizes revenue on a gross basis.

Revenues from rate-regulated operations are recognized on the accrual basis in accordance with rates and policies as set by the regulator.

Rate adjustments related to prior years are presented as unusual items.

E. DISCONTINUED OPERATIONS The results of discontinued operations are presented on a one-line basis in the consolidated statements of earnings. Interest expense, direct corporate overheads and income taxes are allocated to discontinued operations. General corporate overheads are not allocated to discontinued operations.

F. CAPITAL ASSETS AND FUTURE SITE RESTORATION COSTS Capital assets are carried at cost, which includes direct internal labour and allocated overheads. Regulated operations capitalize an allowance for funds used during construction (AFUDC) at the cost of capital including the cost of equity related to property under construction. AFUDC is a non-cash income item that will be charged and recovered in rates to customers over the service life of the assets, commencing with their inclusion in the rate base.

Interest is capitalized for non-regulated plants under construction, and is included in the capital cost of the related property. Depreciation on non-regulated gas generation plants is provided on a unit-of-production basis based upon estimated production over the asset's useful life. No provision for future site restoration costs for gas generation plants is recorded, as management estimates the costs of restoration will be offset completely by the salvage values of the related plant. Depreciation on non-regulated coal generation plants is provided for on a straight-line basis over the useful life of the asset. Future site restoration costs for non-regulated coal plants are provided for in depreciation and amortization expense on a straight-line basis over the life of the asset. Non-regulated transmission, distribution and retail systems and customer base intangibles are depreciated using the straight-line method over the useful life of the asset.

The corporation does not provide for the removal costs associated with its hydroelectric generating facilities as the costs are not reasonably estimated because of the long service life of these assets. With either maintenance efforts or rebuilding, the water control structures are assumed to be required for the foreseeable future, and therefore no amounts have been provided for site restoration costs for these facilities. Estimated costs to reclaim mining properties are provided for primarily on a unit-of-production basis. Customer contributions to the corporation for new service connections are recorded as a reduction to the cost of property. Regulated operations provide for depreciation on a straight-line basis using various rates as approved by the EUB, based on depreciation studies prepared by the corporation. Changes to depreciation rates requested by the EUB are accounted for on a prospective basis. Depreciation rates reflect estimated service lives and estimated future removal and site restoration costs less salvage values.

Major maintenance costs are deferred and amortized on a straight-line basis over the estimated benefit period of such maintenance.

Acquired intangibles are amortized on a straight-line basis over five years. The recoverability of acquired intangibles is assessed, if indications of impairment are present, based on estimated undiscounted future cash flows. Commencing Jan. 1, 2002, acquired intangibles will be reclassified to goodwill, which will not be subject to amortization, but will instead be assessed for impairment at least annually.

G. OTHER ASSETS

The deferred license fees consist primarily of an Australian land license which is being amortized over the useful life of the power station assets which are situated thereon.

Financing costs for the issuance of long-term debt, preferred shares and preferred securities are amortized to earnings on a straight-line basis over the term of the related issue.

Costs incurred by the corporation to develop potential capital assets or investments, inclusive of internal labour, are included in operating expenses until construction of a plant commences or acquisition of an investment has been completed, at which time the costs are included in capital assets or investments.

H. INCOME TAXES

The corporation uses the liability method of accounting for income taxes for its non-rate-regulated operations. Under the liability method, income taxes are recognized for the differences between financial statement carrying values and the respective income tax basis of assets and liabilities (temporary differences), and for the carry forward of unused tax losses and income tax reductions. Future income tax assets and liabilities are measured using income tax rates expected to apply in the years in which temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities of a change in tax rates is included in income in the period that the change is substantively enacted. Future income tax assets are evaluated and if realization is not considered 'more likely than not', a valuation allowance is provided.

TransAlta's rate-regulated operations use the income tax accounting policies as prescribed by the EUB. Rate-regulated enterprises need not recognize future income taxes to the extent that future income taxes are expected to be included in the rates charged to and recovered from future customers.

I. EMPLOYEE FUTURE BENEFITS The corporation accrues its obligations under employee benefit plans and the related costs, net of plan assets. The cost of pensions and other post-employment and post-retirement benefits earned by employees is actuarially determined using the projected benefit method pro-rated on services and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. For the purpose of calculating the expected return on plan assets, those assets are valued at fair value. The discount rate used to calculate the interest cost on the accrued benefit obligation is the long-term market rate at the balance sheet date. Past service costs from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment (EARSL). The excess of the net cumulative unamortized actuarial gain or loss over 10 per cent of the greater of the accrued benefit obligation and the fair value of plan assets is amortized over the average remaining service period of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and settlement of obligations, the curtailment is accounted for prior to the settlement. Transition obligations and assets arising from the prospective adoption of new accounting standards are amortized over EARSL.

J. FOREIGN CURRENCY TRANSLATION The corporation's self-sustaining foreign operations are translated using the current rate method. Translation gains and losses are deferred and included in the cumulative translation adjustment (CTA) account in shareholders' equity. Transactions denominated in foreign currencies are translated at the exchange rate on the transaction date. Foreign currency denominated monetary assets and liabilities are translated at exchange rates in effect on the balance sheet date. The resulting exchange gains and losses on these items are included in net earnings, except for unrealized exchange gains or losses arising on translation of long-term debt not designated as a hedge of foreign operations, which are deferred and amortized over the remaining life of the debt on a straight-line basis. Gains and losses arising on translation of long-term debt designated as a hedge of self-sustaining foreign operations are deferred and included in CTA in shareholders' equity on a net of tax basis.

Commencing Jan. 1, 2002, gains and losses on the translation of long-term debt not designated as a hedge of foreign operations will no longer be deferred and amortized, but will be included in income in the period in which the translation gain or loss occurs.

K. DERIVATIVES AND FINANCIAL INSTRUMENTS The corporation utilizes derivative financial instruments and derivative commodity instruments (collectively, derivatives) and other financial instruments to manage its exposure to changes in foreign currency exchange rates, interest rates and energy prices. Gains and losses relating to derivatives that are designated as hedges are deferred and recognized in the same period and financial statement category as the related items hedged. To be accounted for as a hedge, a derivative must be designated by management as a hedge and be effective. Hedge effectiveness for cash flow hedges is achieved if the derivative's cash flows substantially offset the cash flows of the hedged item and the timing of the cash flows is similar. Hedge effectiveness for fair value hedges is achieved if changes in the fair value of the derivative substantially offsets changes in the fair value of the item hedged. If a derivative that has been accorded hedge accounting is settled early, the termination gain or loss is deferred and recognized when the gain or loss on the item hedged is recognized. Premiums paid or received with respect to hedging derivatives are deferred and amortized to earnings over the term of the hedge. Derivatives used in trading activities are carried at fair value. Realized and unrealized changes in fair value are recognized in earnings in the period in which the changes occur. The estimated fair value of a derivative generally reflects the estimated amount that the corporation would receive or pay to terminate the contract at the balance sheet date. The estimated fair value of long-term debt is based on quoted market prices where available, or where not available, with reference to market prices for similar issues. The carrying amounts of other balance sheet financial assets and financial liabilities approximate their fair values.

L. STOCK-BASED COMPENSATION PLANS The corporation has three types of stock-based compensation plans comprised of two stock option-based plans and a Performance Share Ownership Plan (PSOP), described in Note 16. For stock option-based plans, no compensation expense is recognized when stock options or, upon exercise, stock is issued to employees. Stock grants under the PSOP are accrued in corporate operating, maintenance and administration expense as earned to the balance sheet date, based upon the percentile ranking of the total shareholder return of the corporation's common shares in comparison to the total shareholder returns of a selected group of publicly traded companies. If stock options or stock are repurchased from employees, the excess of the consideration paid over the carrying amount of the stock option or stock cancelled is charged to retained earnings.

M. EARNINGS PER SHARE (EPS) Effective Jan. 1, 2001, the corporation retroactively adopted the CICA standard requiring the use of the treasury stock method rather than the imputed earnings method in calculating diluted earnings per share. The impact of this change on current and prior period diluted earnings per share was not material. Prior period amounts have been restated to comply with the new standard. Supplemental diluted earnings per share information disclosed in Note 14 is calculated assuming settlement of the equity component of the preferred securities by issuance of the corporation's common shares.

2. Segment disclosures

A. DESCRIPTION OF REPORTABLE SEGMENTS

The corporation has three reportable segments, each supported by a corporate group: Generation, Independent Power Projects (IPP) and Energy Marketing. A fourth business segment, Transmission, has been reclassified as a discontinued operation following the announcement of the agreement to dispose of the segment on July 4, 2001. The Alberta D&R operation was reclassified as a discontinued operation on Dec. 31, 1999. The New Zealand segment was also reclassified as a discontinued operation on Dec. 31, 1999 (Note 3). The business segments are strategic business units that offer different products and services, and each is managed separately. Each business unit assumes responsibility for its operating results measured as earnings before interest, taxes and non-controlling interests (EBIT). EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with 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. Corporate overheads that are not directly attributable to discontinued operations are allocated to the business segments.

The Generation segment operates in Alberta, Canada, and Washington State, U.S. Commencing Jan. 1, 2001, the Alberta generating plants are no longer subject to rate regulation and earn revenues based on long-term PPAs for the remaining life of each plant or unit. The PPAs set a production requirement and availability target to be supplied by each plant or unit and the price at which each megawatt hour will be supplied to the customer. Previously, the Alberta generating plants were regulated by the EUB and the transactions were facilitated through third-party intermediaries, namely the Power Pool of Alberta (Power Pool), ESBI Alberta Ltd. and the independent transmission administrator (TA). The electrical production of these plants was sold to the Power Pool. Legislation provided for the sale of all power for use in Alberta to the Power Pool for resale at a bid price which matches demand with supply. Prices were determined through regulation and were based on a rate of return on assets and the recovery of costs. Revenues were net of payments to small power producers (SPP). The Alberta Generation operation also earned ancillary revenue for providing system stability services to the TA and paid ancillary access charges to the TA. In Washington State, revenue earned from the Centralia plant and mining operation acquired in May 2000 (Note 5) is not subject to rate regulation. The plant sells its production primarily to the Pacific Northwest market. Generation expenses include Energy Marketing's intersegment charge for energy marketing and financial risk management services in the amount of $4.7 million (2000 - $5.7 million; 1999 - $2.5 million). Generation expenses also include Transmission's intersegment charge in the amount of $0.4 million (2000 - $0.7 million; 1999 - $0.9 million).

The IPP segment builds, owns and operates independent power projects in Canada, the U.S., Australia and Mexico for the sale of electric and thermal energy. The majority of electricity production is sold under long-term commercial contracts with the remainder sold in spot markets. Thermal energy is sold under long-term contracts. Expenses include Energy Marketing's intersegment charges for energy marketing and financial risk management services in the amount of $2.7 million (2000 - $1.4 million; 1999 - $1.4 million). The amount of engineering, procurement and construction service (EPC) charges from Transmission capitalized to capital assets under construction was $0.7 million (2000 - $3.6 million; 1999 ­ $24.7 million).

The Energy Marketing segment derives revenue from the wholesale trading of electricity and other energy-related commodities and derivatives. Expenses are net of intersegment charges to the Generation and IPP segments for the provision of energy marketing and financial risk management services in the amount of $7.4 million (2000 - $7.1 million; 1999 - $3.9 million), and to the discontinued Alberta D&R operation in the amount of $nil (2000 - $1.0 million; 1999 ­ $1.6 million).

The accounting policies of the segments are the same as those described in Note 1. Intersegment transactions are accounted for on a cost recovery basis which approximates market rates.

B. REPORTED SEGMENT PROFIT OR LOSS AND SEGMENT ASSETS

<table>
I. Earnings information
Energy
Year ended Dec. 31, 2001 Generation IPP 4. Marketing Corporate Total
Revenues $ 1,717.9 $ 514.5 $ 2,694.7 $ - $ 4,927.1
Trading purchases - - (2,533.7) - (2,533.7)
Fuel and purchased power (1,093.9) (194.8) - - (1,288.7)
Gross margin 624.0 319.7 161.0 - 1,104.7
Operations, maintenance and administration 215.5 127.4 36.2 65.4 444.5
Depreciation and amortization 136.6 102.3 11.0 23.7 273.6
Taxes, other than income taxes 15.3 3.4 - - 18.7
Prior period regulatory decisions (11.0) - - - (11.0)
EBIT before corporate allocations 267.6 86.6 113.8 (89.1) 378.9
Corporate allocations 61.5 21.0 6.6 (89.1) -
EBIT $ 206.1 $ 65.6 $ 107.2 $ - 378.9
Other income 1.5
Foreign exchange gain 0.8
Net interest expense (88.1)
Earnings from continuing operations before income taxes and non-controlling interests $ 293.1
Energy
Year ended Dec. 31, 2000 Generation IPP Marketing Corporate Total
Revenues $ 1,159.9 $ 362.3 $ 1,280.3 $ - $ 2,802.5
Trading purchases - - (1,202.5) - (1,202.5)
Fuel and purchased power (504.9) (150.9) - - (655.8)
Gross margin 655.0 211.4 77.8 - 944.2
Operations, maintenance and administration 166.0 94.1 19.0 70.8 349.9
Depreciation and amortization 126.7 55.3 9.4 14.2 205.6
Taxes, other than income taxes 22.2 1.7 - - 23.9
Prior period regulatory decisions (44.1) - - - (44.1)
EBIT before corporate allocations 384.2 60.3 49.4 (85.0) 408.9
Corporate allocations 57.5 20.4 7.1 (85.0) -
EBIT $ 326.7 $ 39.9 $ 42.3 $ - 408.9
Other expense (1.1)
Foreign exchange gain 0.1
Net interest expense (91.4)
Earnings from continuing operations before income taxes and non-controlling interests $ 316.5
Energy
Year ended Dec. 31, 1999 Generation IPP Marketing Corporate Total
Revenues $ 569.4 $ 270.6 $ 283.0 $ - $ 1,123.0
Trading purchases - - (272.0) - (272.0)
Fuel and purchased power (124.0) (92.6) - - (216.6)
Gross margin 445.4 178.0 11.0 - 634.4
Operations, maintenance and administration 99.5 81.7 8.1 45.5 234.8
Depreciation and amortization 101.7 45.9 1.3 15.5 164.4
Taxes, other than income taxes 20.5 1.4 - - 21.9
EBIT before corporate allocations 223.7 49.0 1.6 (61.0) 213.3
Corporate allocations 41.7 14.2 5.1 (61.0) -
EBIT $ 182.0 $ 34.8 $ (3.5) $ - 213.3
Foreign exchange gain 1.7
Net interest expense (65.5)
Earnings from continuing operations before income taxes and non-controlling interests $ 149.5






II. Selected Balance Sheet Information
Energy Discontinued
Dec. 31, 2001 Generation IPP Marketing Corporate Operations Total
Segment assets $ 3,894.8 $ 1,968.1 $ 729.1 $ 609.0 $ 676.9 $ 7,877.9
Segment accounts payable and accrued liabilities $ 202.7 $ 153.7 $ 642.7 $ 101.5 $ 15.5 $ 1,116.1
Dec. 31, 2000
Segment assets $ 3,275.0 $ 1,745.3 $ 1,033.1 $ 774.7 $ 799.0 $ 7,627.1
Segment accounts payable and accrued liabilities $ 155.1 $ 269.4 $ 951.6 $ 45.8 $ 16.0 $ 1,437.9






III. Selected Cash Flow Information
Year ended Dec. 31, 2001 5.

6.Generation

IPP		 Energy

Marketing

 Corporate Discontinued

Operations

 Total
Capital expenditures $ 680.7 $ 466.9 $ 43.8 $ 15.1 $ 40.0 $ 1,246.5
Acquisitions $ - $ 9.4 $ 0.4 $ - $ - $ 9.8
Year ended Dec. 31, 2000
Capital expenditures $ 247.8 $ 381.0 $ 27.2 $ 14.7 $ 124.3 $ 795.0
Acquisitions $ 868.7 $ - $ 11.4 $ - $ - $ 880.1
Year ended Dec. 31, 1999
Capital expenditures $ 109.1 $ 285.6 $ 0.6 $ 25.1 $ 224.5 $ 644.9
Acquisitions $ - $ 186.7 $ - $ - $ 160.9 $ 347.6






lV. Reconciliations





<table>

l. Depreciation and amortization expense (D&A) per statement of cash flows
Year ended Dec. 31 2001 2000 1999
D&A expense for reportable segments $ 273.6 $ 205.6 $ 164.4
Discontinued operations 46.5 108.6 158.0
Other 5.8 7.5 3.1
$ 325.9 $ 321.7 $ 325.5




</table>

C. GEOGRAPHIC INFORMATION

<table>
I. Revenues
2001 2000 1999
Canada $ 3,723.2 $ 2,151.2 $ 1,066.2
Australia 61.5 54.9 56.8
U.S. 1,142.4 596.4 -
4,927.1 2,802.5 1,123.0


Revenues are attributable to countries based on the location of customers. The Mexican plants have not yet commenced commercial operations and therefore no revenues are being generated.
II. Capital assets
2001 2000
Canada $ 3,145.3 $ 3,962.0
Australia 264.5 192.3
U.S. 2,451.0 1,122.8
Mexico 263.3 -
6,124.1 5,277.1




</table>

3. Discontinued operations

7. A. TRANSMISSION

On July 4, 2001, the corporation signed a purchase and sale agreement for the disposal of its Transmission operations for cash proceeds of approximately $850 million. The sale is expected to close in the first half of 2002, subject to regulatory approval.

B. EDMONTON COMPOSTER

Effective Dec. 31, 2000, the corporation adopted a plan to divest its composter facility in Edmonton, Alberta, Canada, which commenced commercial operations in August 2000. In the fourth quarter of 2000, the corporation recorded a write-down of the carrying value of the assets of $17.9 million ($0.10 per common share) net of income tax recoveries of $13.8 million. On June 29, 2001, the facility was sold for cash proceeds of $97.0 million. No gain or loss resulted from the disposal.

C. ALBERTA DISTRIBUTION AND RETAIL (D&R) OPERATION

Effective Dec. 31, 1999, the corporation adopted a plan to divest its Alberta D&R operation. This operation was sold on Aug. 31, 2000 for proceeds of $857.3 million and an after-tax gain on disposal of $262.4 million ($1.55 per common share) net of income tax recoveries of $137.9 million. By Dec. 31, 2001, $723.6 million of the proceeds had been received. The remaining balance, primarily related to deferral accounts as approved by the EUB, is expected to be received by the end of 2003.

As per the terms of the disposition agreement, TransAlta will share the benefit or burden of future regulatory decisions affecting the Alberta D&R pre-disposition operation. No amount has been accrued in the consolidated financial statements as no amount was reasonably determinable at the reporting date.

D. NEW ZEALAND

Effective Dec. 31, 1999, the corporation adopted a plan to divest its New Zealand operations. On March 31, 2000, TransAlta sold its interest in its discontinued New Zealand operations for total proceeds of NZ$832.5 million (approximately Cdn$605 million) resulting in an after-tax gain on disposal of $22.3 million ($0.13 per common share) net of income taxes of $43.1 million.

8. E. ARGENTINA

Effective Dec. 31, 1998, the corporation adopted a plan to pursue divestiture opportunities relating to its investment in Argentina. A provision resulting from the expiry of an unutilized US$9.3 million standby credit facility was reversed in 1999 giving rise to income of $12.4 million ($0.07 per common share). In December 1999, the corporation sold its interest in Argentina for total proceeds and gain on sale of $7.3 million ($0.04 per common share).

F. STATEMENTS OF EARNINGS

The statements of earnings amounts applicable to discontinued operations are as follows. Interest is allocated to discontinued operations based on the ratio of assets to be discontinued, net of directly attributable debt, to the total assets of the entity, net of debt that can be directly attributed to the discontinued operation or to particular continuing operations of the corporation.

<table>
Edmonton
Year ended December 31, 2001 Transmission Composter Total
Revenues $ 171.1 $ 6.6 $ 177.7
Operating expenses 84.6 5.4 90.0
Operating income 86.5 1.2 87.7
Net interest expense (9.7) - (9.7)
Earnings before income taxes and non-controlling interests 76.8 1.2 78.0
Income taxes (32.4) (0.5) (32.9)
Earnings subsequent to measurement date 44.4 0.7 45.1
Earnings from discontinued operations 1 $ 44.4 $ 0.7 $ 45.1
1 Transmission earnings include $23.4 million of earnings prior to the measurement date, net of taxes of $16.8 million.
Edmonton
Year ended December 31, 2000 Transmission Composter D&R New Zealand Total
Revenues $ 178.2 $ 6.3 $ 180.2 $ 148.8 $ 513.5
Operating expenses 83.6 4.1 103.3 125.8 316.8
Operating income 94.6 2.2 76.9 23.0 196.7
Net interest expense (9.4) (1.0) (10.2) (4.4) (25.0)
Earnings before income taxes and non-controlling interests 85.2 1.2 66.7 18.6 171.7
Income taxes (40.9) (0.5) (33.4) (4.7) (79.5)
Non-controlling interests - - - (3.1) (3.1)
Earnings subsequent to (Transmission & Edmonton Composter - prior to) measurement date 44.3 0.7 33.3 10.8 89.1
Gain on disposal (write-down of carrying value) - (17.9) 262.4 22.3 266.8
Earnings from discontinued operations $ 44.3 $ (17.2) $ 295.7 $ 33.1 $ 355.9
Year ended December 31, 1999 Transmission D&R New Zealand Argentina Total
Revenues $ 189.6 $ 211.2 $ 789.0 $ 23.7 $ 1,213.5
Operating expenses 87.6 144.4 746.2 9.0 987.2
Operating income 102.0 66.8 42.8 14.7 226.3
Gain on sale of assets - - 35.2 - 35.2
Other income (expense) 0.7 - - - 0.7
Rate adjustment - 1996 and 1997 (Note 17) - (9.6) - - (9.6)
Net interest expense (13.6) (15.1) (20.5) (15.7) (64.9)
Earnings before income taxes and non-controlling interests 89.1 42.1 57.5 (1.0) 187.7
Income taxes (40.8) (20.3) (1.6) (2.1) (64.8)
Non-controlling interests - - (24.3) 3.1 (21.2)
Earnings prior to (Argentina - subsequent to) measurement date 48.3 21.8 31.6 - 101.7
Gain on disposal (write-down of carrying value) - - - 19.7 19.7
Earnings from discontinued operations $ 48.3 $ 21.8 $ 31.6 $ 19.7 $ 121.4




</table>

G. BALANCE SHEETS

At Dec. 31, 2001, all of the corporation's discontinued operations had been sold except for those of the Transmission operation. Balance sheet amounts were as follows:

<table>
2001 2000
Edmonton
Transmission Transmission Composter Total
Current assets $ 36.1 $ 52.6 $ 2.4 $ 55.0
Capital assets 637.5 622.3 119.7 742.0
Other assets 3.3 2.0 - 2.0
Current liabilities (15.5) (12.1) (3.9) (16.0)
Net assets $ 661.4 $ 664.8 $ 118.2 $ 783.0




</table>

4. Extraordinary item

In December 2000, the corporation discontinued regulatory accounting and commenced the application of Canadian GAAP for its Alberta Generation operations, consistent with deregulation of the electricity generation industry in Alberta beginning on Jan. 1, 2001.

As a result of the discontinuance of regulatory accounting, the corporation recorded an extraordinary non-cash after-tax charge of $209.7 million ($1.24 per share) comprised of the following:

<table>
Write-off of regulatory accounts $ 2.5
Write-down of net carrying values of capital assets 17.3
Recognition of previously unrecognized future income tax liabilities 189.9
209.7




</table>

5. Acquisitions and disposals - continuing operations A. GENERATION In May 2000, TransAlta purchased a power plant and the adjacent mining operations in Centralia, Washington, for cash consideration of US$582.7 million (Cdn$868.7 million). This acquisition was accounted for using the purchase method. This purchase included plant assets of $847.1 million, mine assets of $145.1 million, working capital of $65.7 million, estimated future site restoration liabilities of $168.8 million, future income tax liabilities of $5.8 million, accrued employee future liabilities of $7.5 million and other liabilities totaling $7.1 million.



B. IPP - Canada

In January 2001, the corporation sold its 265 MW Mildred Lake plant to Syncrude's Joint Venture owners for cash proceeds of $60.3 million plus a receivable in the amount of $4.7 million, which approximated its book value. Of the receivable amount, $2.3 million remains outstanding at Dec. 31, 2001 (Note 7).

In August 2001, the corporation sold its 45 MW Fort Nelson gas-fired facility for cash proceeds of $44.1 million. The gain on disposition was $1.3 million after-tax. The book value of the assets was $42.8 million.

In September 2001, the corporation sold its 60 per cent interest in its Fort Saskatchewan cogeneration facility to TransAlta Cogeneration, L.P. (TA Cogen), a limited partnership owned 50.01 per cent by the corporation and 49.99 per cent by TransAlta Power, L.P. (TransAlta Power), a publicly owned entity. Total cash consideration to the corporation was $35.0 million in respect of the 30 per cent interest effectively sold to the minority interest in TA Cogen. The corporation recorded a gain of $6.2 million, $5.0 million after-tax. The effective book value of the assets transferred to TA Cogen was $57.6 million, with $28.8 million representing TransAlta Power's 49.99 per cent interest in the assets.

C. IPP ­ Australia

In 1999, the corporation increased its interest in a gas transmission pipeline in Western Australia from 6.3 per cent to 8.8 per cent for consideration of $14.1 million. A subsequent return of capital in 1999 provided cash of $30.4 million.

Also in 1999, the corporation acquired an 85 per cent interest in four gas-fired power generating stations and transmission lines in Western Australia for cash consideration of $186.7 million, net of cash acquired of $2.3 million. Total assets acquired amounted to $222.3 million, $220.0 million of which related to capital assets. Non-controlling interest assumed was $33.3 million.

D. ENERGY MARKETING

In June 2000, the corporation purchased a 50 per cent interest in Merchant Energy Group of the Americas (MEGA) for cash consideration of US$12.5 million (Cdn$18.6 million). In June 2001, the corporation purchased the remaining 50 per cent of MEGA for cash consideration of US$0.3 million (Cdn$0.4 million) plus Cdn$13.9 million in one-time costs relating to the acquisition consisting primarily of severance of $3.9 million and long-term employment incentives in the amount of $8.5 million. MEGA specialized in the commercial management of power generation assets in the U.S. and will provide additional market knowledge and capability to enable the acquisition and development of power facilities in the U.S. and will serve as a platform on which to expand trading activities into the eastern U.S. regions. As such, the results of MEGA's operations have been included in the Energy Marketing business segment. Previously they had been recorded in the IPP business segment. Prior period amounts have been restated to reflect this change. In September 2001, the MEGA operations were amalgamated with TransAlta Energy Marketing (U.S.) Inc., a subsidiary of TransAlta Energy.

The purchase of the initial 50 per cent in 2000 included cash of $7.2 million, a negative working capital balance of $8.8 million, capital and intangible assets of $33.6 million, and future income tax liabilities of $32.0 million. The purchase of the remaining 50 per cent in June 2001 was comprised of negative working capital of $7.7 million, capital and intangible assets of $14.2 million and a future tax liability of $6.1 million.

6. Investments

<table>
2001 2000
Investment in Australian gas transmission pipeline $ 19.2 $ 20.2
Investment in wind power generation 10.0 8.5
Investment in distributed generation companies 7.9 -
Restricted bank deposits - 198.4
Other 0.2 0.9
$ 37.3 $ 228.0




</table>

Restricted bank deposits in 2000 consisted of NZ$298.8 million at an average fixed interest rate of 6.6 per cent with maturity in 2004. The deposits have been pledged as collateral for the New Zealand bank facility (Note 11). In 2001, the corporation entered into an offset agreement with the lender to legally offset these balances.

7. Long-term receivables

<table>
2001 2000
Due from UtiliCorp Networks Canada (Note 3) $ 173.3 $ 136.0
Sulphur tax abatement 45.0 -
Deferral accounts receivable - 77.9
Due from Syncrude Canada Ltd. 2.3 27.3
Other 0.8 4.7
221.4 245.9
Less current portion included in accounts receivable - 13.0
$ 221.4 $ 232.9




</table>

The amount due from UtiliCorp Networks Canada arose from the sale of the discontinued Alberta D&R operation and includes interest at a rate determined by the EUB with repayment expected to be completed by 2003.

The sulphur tax abatement represents an incentive to coal-fired thermal electric generators in Washington State, U.S. to construct air pollution control facilities. Final certification of meeting the initial rolling 12-month emission requirements is required by Feb. 28, 2004.

The deferral accounts receivable related to the Generation segment and was settled in 2001.

The long-term receivable from Syncrude Canada Ltd. is unsecured, non-interest bearing and repayable in equal monthly amounts through March 2003. The majority of this receivable was collected in 2001 when the corporation sold its Mildred Lake plant to Syncrude's Joint Venture owners (Note 5).

8. Capital assets

<table>
2001 2000


Depreciation

Accumulated		 Net book

#

Accumulated

Net Book
Rates Cost depreciation value Cost depreciation Value
and amortization and amortization
Mining property & equipment 3.9% - 20% $ 589.7 $ 264.2 $ 325.5 $ 786.5 $ 280.2 $ 506.3
Thermal generation 3.1% - 10% 3,496.3 964.8 2,531.5 2,757.4 874.8 1,882.6
Thermal environmental equipment 3.8% - 10% 425.2 223.7 201.5 436.7 239.6 197.1
Gas generation 3.1% - 5% 1,241.7 185.1 1,056.6 1,002.2 169.7 832.5
Hydro generation 2.8% - 5% 321.3 162.7 158.6 311.4 82.1 229.3
Transmission systems 2.0% - 20% 1,401.8 778.4 623.4 1,344.6 731.1 613.5
Other 2.4% - 33% 249.6 110.3 139.3 325.3 107.5 217.8
Assets under construction None 1,087.7 - 1,087.7 798.0 - 798.0
$8,813.3 $ 2,689.2 $6,124.1 $7,762.1 $ 2,485.0 $5,277.1




</table>

The corporation capitalized AFUDC of $1.0 million (2000 - $3.6 million; 1999 - $3.4 million) and interest during construction of $47.3 million (2000 - $36.2 million; 1999 - $15.1 million) to assets under construction. Included in other capital assets are acquired intangibles with a net book value of $29.3 million (2000 - $24.2 million). In September 2001, a $66.5 million reduction in carrying value of IPP gas generation assets related to the Pierce Power plant was taken in conjunction with the realization of revenue hedges. The amount is included in depreciation and amortization expense.

9. Other assets

<table>
  2001 2000
Deferred license fees $ 23.9 $ 25.2
Cross-currency interest rate swaps (Note 20) - 23.4
Deferred financing costs 10.6 10.0
Foreign currency forward contracts (Note 20) 8.7 6.9
Deferred regulatory hearing costs 2.8 6.2
Deferred project development costs 1.1 5.3
  $ 47.1 $ 77.0






</table>

10. Short-term debt

<table>
2001 2001 2000 2000
Outstanding Interest1 Outstanding Interest1
Commercial paper $ 207.2 2.4% $ 258.4 5.7%
Bank debt 330.0 3.5% 214.3 5.8%
$ 537.2 $ 472.7


</table>

1 Interest is an average rate weighted by principal amounts outstanding before the effect of hedging.

The bank debt consists of bankers' acceptances in the amount of $312.1 million and LIBOR-based loans in the amount of $17.9 million, and have no fixed terms of repayment.

11. Long-term debt

A. AMOUNTS OUTSTANDING

<table>
2001 2001 2000 2000
Outstanding Interest rate1 Outstanding Interest rate1
Debentures, due 2002 to 20332 $ 1,963.4 7.0% $ 1,563.4 7.1%
Commercial paper3 257.2 2.3% 300.0 6.0%
Bank credit facility - Campeche, US$127 million4 200.5 2.9% 28.8 7.5%
Notes payable - Windsor plant, due 2002 to 20145 65.3 7.4% 68.2 7.4%
Preferred securities, due 2048 to 20506 13.8 7.8% 8.6 7.7%
Capital lease obligation, due 2004 7 10.9 9.4% 9.2 9.4%
Bank credit facilities - New Zealand, due 2004 8 - - 198.4 6.9%
Other9 - - 24.8 8.0%
2,511.1 2,201.4
Less current portion 104.3 79.6
$ 2,406.8 $ 2,121.8

</table>

1 Interest is an average rate weighted by principal amounts outstanding before the effect of hedging.

2 DEBENTURES: The debentures bear interest at fixed rates. A floating charge on the property and assets of TransAlta Utilities has been provided as collateral for $898.4 million of the debentures as at Dec. 31, 2001. The interest rate on $425.0 million of the 2001 amount has been converted to floating rates using receive fixed interest rate swaps maturing in 2003 to 2011. Debentures of $100.0 million maturing in 2023 and $50.0 million maturing in 2033 are redeemable at the option of the holder in 2008 and 2009, respectively. Another debenture of $150.0 million maturing in 2005 is extendable until 2030 at the option of the holder.

3 COMMERCIAL PAPER: Amounts outstanding at Dec. 31, 2001 include US$162.8 million of commercial paper. Under the terms of TransAlta's credit facility, the corporation has the ability and intent to maintain these commercial paper borrowings beyond one year. The corporation has designated US$162.8 million as a long-term hedge of its net investment in U.S. operations (Note 20).

4 BANK CREDIT FACILITY ­ CAMPECHE: In December 2000, the corporation established a US$133.6 million 16-year credit facility for the financing of the construction of an IPP power plant in Campeche, Mexico. The outstanding borrowing totals US$127.0 million with an interest rate of LIBOR plus 0.875 per cent during construction and LIBOR plus 2.25 per cent upon completion of the construction, increasing to LIBOR plus 3.25 per cent by 2016. Upon completion of construction in March 2003, 70 per cent of the facility will be converted to a fixed rate of 7.4 per cent with a forward starting swap (Note 20). During construction, the corporation has provided a guarantee to the lenders for the completion of the plant. Upon completion of the construction, the facility is secured by the Campeche plant.

5 NOTES PAYABLE - WINDSOR PLANT: The Windsor plant notes payable bear interest at fixed rates and are recourse to the corporation through a standby letter of credit.

6 PREFERRED SECURITIES: The debt component amount of the preferred securities (Note 14) represents the present value of the principal amount of $475.0 million due in 2048 and 2050. Interest accretion at the coupon rate is included in interest expense.

7 CAPITAL LEASE OBLIGATION: Certain coal mining capital assets have been provided as collateral. The obligation bears interest at a fixed rate.

8 BANK CREDIT FACILITY - NEW ZEALAND: The corporation has a fully drawn fixed interest rate bank facility of NZ$298.8 million, with restricted investments pledged as collateral. Subsequent to Dec. 31, 2000, the credit facility was offset with New Zealand bank deposits (Note 6).

9 OTHER: Other long-term debt was paid in full in August 2001.

B. PRINCIPAL REPAYMENTS

Principal repayments over each of the next five years and thereafter are as follows:

<table>
2002 $ 104.3
2003 355.6
2004 136.3
2005 237.3
2006 354.2
2007 and thereafter 1,323.4
$ 2,511.1




</table>



C. INTEREST EXPENSE

Interest expense on long-term debt was $150.3 million (2000 - $165.7 million; 1999 - $154.2 million), of which $140.6 million (2000 - $140.7 million; 1999 - $89.3 million) relates to continuing operations.

D. LETTERS OF CREDIT AND GUARANTEES

At Dec. 31, 2001, the corporation had $155.9 million and US$66.6 million in letters of credit outstanding. In addition, the corporation has issued various performance guarantees in the amount of $1,113.6 million in support of Energy Marketing trading, Treasury hedging, and IPP and Generation project activities. The corporation has also issued two surety bonds, one for $0.5 million to secure trading with counterparties and another for US$156.7 million in support of future site reclamation liabilities associated with the Centralia mining operation.

12. Deferred credits and other long-term liabilities

<table>
2001 2000
Future site restoration costs $ 339.8 $ 283.4
Unamortized gain on sale of capital assets to limited partnership 131.3 139.0
Cross-currency interest rate swaps (Note 20) 36.9 -
Fair value of swap transaction with limited partnership (Note 22) 13.3 19.0
Deferred revenues and other 5.2 13.7
$ 526.5 $ 455.1




</table>

The unamortized gain on sale of capital assets to limited partnership relates to the gain on disposal of a 49.99 per cent interest in Ontario cogeneration assets held by TA Cogen to TransAlta Power, a publicly owned entity, in 1998. The corporation is obligated to purchase all of TransAlta Power's interest in TA Cogen on Dec. 31, 2018, at the fair market value at that date. Accordingly, the gain of $160.3 million is being deferred and amortized on a straight-line basis over the period to Dec. 31, 2018. Amortization of the gain in the amount of $7.7 million (2000 - $7.7 million; 1999 - $7.8 million) is presented within depreciation and amortization expense in the statements of earnings.

13. Non-controlling interests

A. STATEMENTS OF EARNINGS

<table>
2001 2000 1999
TransAlta Power's limited partnership interest in TA Cogen (Note 22) $ 14.7 $ 29.4 $ 9.1
Dividend requirements on preferred shares of a subsidiary 6.1 11.7 21.1
Other common shareholders' interests (0.2) 0.5 0.7
$ 20.6 $ 41.6 $ 30.9




</table>

B. PREFERRED SHARES OF A SUBSIDIARY

<table>
2001 2000
4.0% - 7.7% Series $ - $ 121.6




</table>

On Sept. 10, 2001, the remaining series of preferred shares were redeemed for $121.6 million plus a premium of $0.5 million. In March 2000, the 8.4 per cent Series were redeemed for $146.1 million.

C. BALANCE SHEETS - OTHER NON-CONTROLLING INTERESTS

<table>
2001 2000
TransAlta Power's limited partnership interest in TA Cogen $ 271.9 $ 244.8
Other common shareholders' interests 9.1 8.6
$ 281.0 $ 253.4




</table>

14. Preferred securities

<table>
Maturity Call date Coupon 2001 2000
2048 2004 7.50% $ 165.8 $ 169.5
2048 2004 8.15% 119.5 122.5
2050 2006 7.75% 167.3 -
$ 452.6 $ 292.0






</table>

In November 2001, the corporation issued preferred securities for net proceeds of $171.9 million (net of issue costs and related tax benefits). The corporation may redeem the preferred securities in whole or in part on or after 2006 at a redemption price equal to 100 per cent of the principal amount of the preferred securities plus accrued and unpaid distributions thereon to the date of such redemption.

In 1999, the corporation issued preferred securities for net proceeds of $294.8 million (net of issue costs and related tax benefits). The corporation may redeem the preferred securities in whole or in part on or after 2004 at a redemption price equal to 100 per cent of the principal amount of the preferred securities plus accrued and unpaid distributions thereon to the date of such redemption. In 1999, the corporation monetized a portion of this redemption feature by writing pay fixed swaptions exercisable in 2004, having a notional amount of $75.0 million and a weighted average interest rate of 6.1 per cent. In return, the corporation received a premium of $2.0 million, which is being amortized to income over the life of the swaptions. At Dec. 31, 2001, the swaptions had a fair value liability of $1.3 million (2000 - $2.4 million).

The preferred securities are subordinated and unsecured. The corporation may elect to defer coupon payments on the preferred securities and settle deferred coupon payments in either cash or common shares of the corporation. As a result, the preferred securities are classified into their respective debt (Note 11) and equity components. The above equity component amounts represent the present value of future coupon payments.

Supplemental diluted earnings per share for 2001 from continuing operations and net earnings were $0.94 (2000 - $0.78; 1999 - $0.27) and $1.18 (2000 - $1.58; 1999 - $0.91), respectively.

15. Common shares

A. ISSUED AND OUTSTANDING

The corporation is authorized to issue an unlimited number of voting common shares without nominal or par value.

<table>
2001 2000 1999
Common shares (millions) Amount Common shares (millions) Amount Common shares (millions) Amount
Issued and outstanding, beginning of year 168.6 $ 1,150.3 169.2 $ 1,145.9 169.6 $ 1,144.4
Repurchased by the corporation (2.0) (14.1) (1.6) (10.6) (1.0) (6.2)
Issued under dividend reinvestment and share purchase plan 0.9 19.1 0.7 10.4 0.4 4.8
Issued for cash under stock option plans 0.7 13.8 0.2 2.9 0.2 2.9
Issued under Performance Share Ownership Plan 0.1 1.8 0.1 1.7 - -
168.3 $ 1,170.9 168.6 $ 1,150.3 169.2 $ 1,145.9






</table>

In 2001, the corporation purchased for cancellation, under its normal course issuer bid, 2,043,100 common shares (2000 ­ 1,567,100; 1999 ­ 955,600) in the amount of $48.9 million (2000 - $23.9 million; 1999 - $18.1 million). The $34.8 million (2000 - $7.5 million) excess of the repurchase price over the average net book value was charged to retained earnings. In 2000 and 1999, the excess of the repurchase price over the average net book value was charged first to contributed surplus and the remainder was charged to retained earnings. Under the terms of the normal course issuer bid program, the corporation is allowed to purchase for cancellation up to three million of its common shares.

B. SHAREHOLDER RIGHTS PLAN

The primary objective of the shareholder rights plan is to provide the corporation's board of directors sufficient time to explore and develop alternatives for maximizing shareholder value if a takeover bid is made for the corporation and to provide every shareholder with an equal opportunity to participate in such a bid.

When an acquiring shareholder acquires 20 per cent or more of the outstanding common shares of the corporation and that shareholder does not make a bid for all of the common shares outstanding, each shareholder other than the acquiring shareholder may receive one right for each common share owned. Each right will entitle the holder to acquire an additional $160 worth of common shares for $80.

C. DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN

Under the terms of the dividend reinvestment and share purchase plan, participants are able to purchase additional common shares in lieu of receiving dividends. Common shares will be issued from treasury or will be purchased on the open market. In 2001, 0.9 million (2000 ­ 0.7 million; 1999 ­ 0.4 million) common shares were purchased under this program for $19.1 million (2000 - $10.4 million; 1999 - $4.8 million).

D. DILUTED EARNINGS PER SHARE

Diluted earnings per share has been calculated after giving rise to the dilutive effect of the exercise of stock options, which would increase the weighted average number of common shares outstanding by nil (2000 ­nil, 1999 -0.1 million). The dilutive impact of PSOP would result in an increase in after-tax compensation expense of $2.7 million (2000 - $3.9 million, 1999 - $2.8 million), and an increase in the weighted average number of common shares outstanding of 0.4 million (2000 -0.3 million, 1999 -0.2 million). Supplementary diluted earnings per share includes the dilutive effects of the conversion of outstanding preferred securities, after the consideration of potential dilutive effects of the stock options and PSOP. The dilutive effect of the preferred securities includes an increase in after-tax earnings of $13.1 million (2000 - $12.8 million, 1999 - $5.2 million) and an increase to the weighted average common shares outstanding of 21.4 million (2000 - 13.2 million, 1999 -20.6 million).



16. Stock-based compensation plans

At Dec. 31, 2001, the corporation had three types of stock-based compensation plans and an employee share purchase plan.

The corporation is authorized to grant employees options to purchase up to an aggregate of 13.0 million common shares at prices based on the market price of the shares as determined on the date of the grant. The corporation has reserved 13.0 million common shares for issue.

A. FIXED STOCK OPTION PLANS

I. MANAGEMENT PLAN: The granting of options under this fixed stock option plan was discontinued in 1997. Options were granted under this plan to certain eligible employees. The options could not be exercised until one year after grant and thereafter at an amount not exceeding 20 per cent of the grant per year on a cumulative basis until the sixth year, after which the entire grant may be exercised until the tenth year, which is the expiry date.

II. CANADIAN EMPLOYEE PLAN: This plan came into effect in 2000 and was offered to all full-time and part-time employees in Canada at or below the level of manager. Options granted under this plan may not be exercised until one year after grant and thereafter at an amount not exceeding 25 per cent of the grant per year on a cumulative basis until the fifth year, after which the entire grant may be exercised until the tenth year, which is the expiry date.

III. Alberta D&R PLAN: This plan came into effect in 2000 and was offered to all full-time and part-time employees employed by the Alberta D&R business segment. Options granted under this plan could not be exercised until the date of the closing of the Alberta D&R sale, after which the entire grant could be exercised until the third year, which is the expiry date.

IV. U.S. PLAN: This plan came into effect in 2001 and was offered to all full-time and part-time employees in the U.S. at or below the level of manager. Options granted under this plan may not be exercised until May 2002 at an amount not exceeding 25 per cent of the grant per year on a cumulative basis until the fifth year, after which the entire grant may be exercised until the tenth year, which is the expiry date.

<table>
Management plan Canadian employee plan Alberta D&R plan U.S. employee plan
Number of share options (millions) Weighted average exercise prices Number of share options (millions) Weighted average exercise prices Number of share options (millions) Weighted average exercise prices Number of share options (millions) Weighted average exercise prices
Outstanding, January 1, 1999 1.0 $ 14.07 - - - - - -
Granted - - - - - - - -
Exercised (0.2) 13.76 - - - - - -
Cancelled or expired - - - - - - - -
Outstanding, December 31, 1999 0.8 $ 14.13 $ - $ - $ - $ - $ - $ -
Granted - - 0.7 14.20 0.1 14.20 - -
Exercised (0.2) 13.37 - - - - - -
Cancelled or expired - - (0.1) 14.20 - - - -
Outstanding, December 31, 2000 0.6 $ 14.37 0.6 $ 14.20 0.1 $ 14.20 $ - $ -
Granted - - 0.9 26.96 - - 0.8 22.41
Exercised (0.4) 14.08 (0.1) 14.22 - - - -
Cancelled or expired - - (0.1) 21.32 - - - -
Outstanding, December 31, 2001 0.2 $ 14.84 1.3 $ 22.27 0.1 $ 14.20 0.8 $ 22.41




</table>

<table>
Options outstanding Options exercisable
Range of exercise prices Number outstanding at December 31, 2001 (millions) Weighted-average remaining contractual life (years) Weighted-average exercise price Number exercisable at December 31, 2001 (millions) Weighted-average exercise price
$13.12 - $14.16 0.1 2.5 $ 13.85 0.1 $ 13.85
$14.17 - $18.00 0.7 6.8 14.40 0.2 14.71
$18.01 - $23.05 0.9 9.9 22.36 - -
$23.06 - $27.70 0.7 9.3 27.70 - -
$13.12 - $27.70 2.4 8.7 $ 21.55 0.3 $ 14.66






</table>

B. PERFORMANCE STOCK OPTION PLAN

In 1999, the corporation expanded enrolment in the share option program to include all domestic employees of the corporation by issuing stock options with an expiry date of 2009 and vesting dependent upon achieving certain earnings per share targets. At Dec. 31, 2001, all outstanding options vested.

<table>
2001 2000 1999
Number of share options (millions) Weighted average exercise prices Number of share options (millions) Weighted average exercise prices Number of share options (millions) Weighted average exercise prices
Outstanding at beginning of year 0.6 $ 23.05 0.9 $ 23.05 - $ -
Granted - - 0.1 14.15 1.0 23.05
Exercised (0.2) 21.27 - - - -
Cancelled or expired - - (0.4) 22.29 (0.1) 23.05
Outstanding at end of year 0.4 $ 22.31 0.6 $ 21.87 0.9 $ 23.05




</table>





<table>
Options outstanding Options exercisable
Range of exercise prices Number outstanding at December 31, 2001 (millions) Weighted-average remaining contractual life (years) Weighted-average exercise price Number exercisable at December 31, 2001 (millions) Weighted-average exercise price
$14.15 - $19.00 0.1 8.0 $ 14.15 0.1 $ 14.15
$19.01 - $23.05 0.3 7.1 23.05 0.3 23.05
$14.15 - $23.05 0.4 7.2 $ 22.31 0.4 $ 22.31




</table>



C. PERFORMANCE SHARE OWNERSHIP PLAN

Under the terms of the PSOP, which commenced in 1997, the corporation was authorized to grant to employees and directors up to an aggregate of 2.0 million common shares. The number of common shares which could be issued under both the PSOP and the share option plans, however, could not exceed 6.0 million common shares. Participants in the PSOP receive awards which, after three years, make them eligible to receive a set number of common shares or cash equivalent up to the maximum of the award amount plus any accrued dividends thereon. The actual number of common shares or cash equivalent a participant may receive is determined by the percentile ranking of the total shareholder return over three years of the corporation's common shares amongst a selected group of publicly traded companies. Until Dec. 31, 2001, where common shares are awarded, such shares were then held in trust and therefore could not be disposed of for a period of two additional years.

On Dec. 31, 2001, the plan was modified so that after three years, once the PSOP eligibility has been determined, 50 per cent of the shares may be released to the participant, while the remaining 50 per cent will be held in trust for one additional year. In addition, the number of common shares the corporation is authorized to grant under the terms of the PSOP was increased to 4.0 million common shares and the maximum number of common shares which may be issued under both the PSOP and share option plans was increased to 13.0 million common shares.

<table>
2001 2000 1999
Number of awards outstanding at beginning of year 1.0 0.9 0.6
Granted 0.4 0.5 0.3
Awarded (0.1) (0.1) -
Cancelled or expired (0.3) (0.3) -
Number of awards outstanding at end of year 1.0 1.0 0.9




</table>

In 2001, PSOP compensation expense was $4.8 million (2000 - $5.1 million expense; 1999 - $0.9 million income). The first PSOP award maturity occurred in 2000 and 120,101 common shares were issued at $14.15 per share. In 2001, 83,077 common shares were issued at $22.00 per share.



D. EMPLOYEE SHARE PURCHASE PLAN

Under the terms of the employee share purchase plan implemented in 2000, the corporation will extend an interest-free loan (up to 30 per cent of employee's base salary) to employees and allow for payroll deductions over a three-year period to repay these loans. The corporation will purchase these common shares on the open market on behalf of employees at prices based on the market price of the shares as determined on the date of purchase. Employee sales of these shares are handled in the same manner. At Dec. 31, 2001, accounts receivable from employees under the plan totalled $1.7 million (2000 - $1.6 million).

The old employee share purchase plan was terminated in 2000 and involved the issuance of up to an aggregate of 200,000 common shares at prices based on the market price of the shares as determined on the date of issue. Employees were able to obtain an interest-free loan, up to 10 per cent of their gross salary, which was repayable over a 12-month period. In 2000, 19,535 common shares were purchased under the old plan and were fully repaid in 2001.



17. Prior period regulatory decisions

A. 1997 AND 1996 RATE ADJUSTMENTS RECORDED IN 1999

The EUB Phase II decision regarding TransAlta Utilities' rates for 1997 and 1996 was received in 1999. The EUB awarded an interest refund to retail customers for payment of interest on rate refunds relating to its 1997 and 1996 rate decision. This rate adjustment reduced 1999 pre-tax earnings from the discontinued Alberta D&R operation by $9.6 million ($5.3 million after-tax).

B. FINAL 1999 DECISION RECORDED IN 2000

On Feb. 1, 2000, the EUB announced an amendment to its 1999 Phase I decision (1999 Final Decision) concerning a 1999 revenue requirement issue that partially offset the effect of its original decision rendered in 1999. The positive impact of the 1999 Final Decision increased earnings by $16.4 million after-tax and was recorded in 2000. Included in this amount was a reduction in earnings of approximately $0.8 million related to the discontinued Alberta D&R operation.

C. 2000 TEMPORARY SUSPENSION REGULATION (TSR) SETTLEMENT

In September 2000, TransAlta negotiated a settlement resulting in the receipt of $17.8 million ($9.9 million after-tax) under the TSR to compensate the corporation for obligation payments incurred as a result of Alberta Generation production outages occurring in 1999 and 2000. Approximately $13.5 million ($7.4 million after-tax) of this receipt related to 1999 outages and $4.3 million ($2.5 million after-tax) related to the first quarter of 2000.

D. 2001 TSR SETTLEMENT

In December 2001, the EUB ruled the Wabamun unit four outage qualified for relief under the TSR and ordered that TransAlta receive $11.0 million ($7.0 million after-tax) to compensate the corporation for obligation payments incurred as a result of the outage.

18. Income taxes

A. STATEMENTS OF EARNINGS

<table>

II. RATE RECONCILIATIONS
2001 2000 1999
Earnings from continuing operations before income taxes & non-controlling interests $ 293.1 $ 316.5 $ 149.5
Statutory Canadian federal and provincial income tax rate 43.31% 44.62% 44.62%
Expected taxes on income $ 126.9 $ 141.2 $ 66.7
Increase (decrease) in income taxes resulting from:
Lower effective foreign tax rates (19.0) (23.4) (6.7)
Resource allowance rate reduction (4.9) (4.7) (5.3)
TransAlta Power's share of TA Cogen's partnership income (6.2) (4.4) (4.1)
Manufacturing and processing rate reduction (7.9) (3.0) (1.0)
Non-deductible costs and other (0.1) 8.3 8.3
Large corporations tax (net of surtax) 7.1 8.3 4.5
Effect of tax rate changes (11.4) 2.6 -
Non-deductible royalties 2.3 2.1 2.3
Unrecognized future income tax assets 3.1 1.5 -
Income tax expense $ 89.9 $ 128.5 $ 64.7
Effective tax rate 30.7% 40.6% 43.3%




III. II. COMPONENTS OF INCOME TAX EXPENSE
2001 2000 1999
Current tax expense $ 47.2 $ 109.3 $ 45.2
Future income tax expense related to the origination and reversal of temporary differences 54.1 16.6 19.5
Future income tax (benefit) expense resulting from changes in tax rates or laws (11.4) 2.6 -
Income tax expense $ 89.9 $ 128.5 $ 64.7




</table>

B. BALANCE SHEETS

<table>

Significant components of the corporation's future income tax assets and liabilities are as follows:
2001 2000
Unrealized losses on electricity trading contracts $ 148.8 $ 393.9
Future site restoration costs 118.4 105.4
Net operating and capital loss carry forwards 69.3 42.0
Other deductible temporary differences 26.9 42.4
Unrealized gains on electricity trading contracts (185.7) (417.2)
Capital assets (443.8) (395.6)
Other taxable temporary differences (122.3) (80.9)
$ (388.4) $ (310.0)






Presented in the balance sheet as follows:
2001 2000
Assets - current $ 16.9 $ 30.3
- long-term 15.6 9.1
Liabilities - current (11.8) -
- long-term (409.1) (349.4)
$ (388.4) $ (310.0)




Future tax assets have not been recognized for the following items:
Expiry date 2001 2000
Unused tax losses 2016 $ 11.0 $ 8.6






The benefits (costs) of current and future income taxes credited (charged) to equity in the period are as follows:
2001 2000
Balance sheet - preferred securities issue costs $ 2.4 $ -
Statement of earnings and retained earnings - preferred securities distributions $ 11.3 $ 10.1
Cumulative translation adjustment $ (18.1) $ 12.1






C. REGULATED OPERATIONS

The following unrecognized amounts relating to the corporation's rate-regulated operations would have been recorded had these operations been non-rate-regulated:
2001 2000
Balance sheet - unrecognized future income tax assets $ 8.7 $ 21.2
2001 2000 1999
Net earnings - unrecognized future income tax recovery $ 0.8 $ 110.1 $ 7.4




</table>





19. Employee future benefits

A. DESCRIPTION

The corporation has a registered pension plan with defined benefit and defined contribution options and a supplemental defined benefit plan covering substantially all employees of the corporation, its domestic subsidiaries and specific named employees working internationally. The defined benefit option of the registered pension plan ceased for new employees on June 30, 1998. The latest actuarial valuations of the registered and supplemental pension plans were as at Aug. 31, 2000.

The corporation provides other health and dental benefits to the age of 65 for both disabled members (other post-employment benefits) and retired members (other post-retirement benefits). The latest actuarial valuation of these other plans was as at Dec. 31, 1998.

B. EXPENSE

<table>
December 31, 2001 Registered Supplemental Other Total
Current service cost $ 3.9 $ 0.8 $ 0.4 $ 5.1
Interest cost 22.1 1.7 0.9 24.7
Expected return on plan assets (28.8) - - (28.8)
Amortization of net transition obligation (asset) (9.3) 0.3 0.3 (8.7)
Defined benefit expense (income) $ (12.1) $ 2.8 $ 1.6 $ (7.7)
Defined contribution option expense of registered pension plan 9.7
Expense before capitalization 2.0
Regulatory capitalization to plant and equipment (0.1)
Net expense $ 1.9
December 31, 2000
Current service cost $ 3.2 $ 0.7 $ 0.4 $ 4.3
Interest cost 21.3 1.5 0.7 23.5
Expected return on plan assets (29.0) - - (29.0)
Curtailment as a result of other post-employment plan changes - - (2.1) (2.1)
Settlement upon sale of Alberta D&R operation (Note 3) 13.9 - (1.2) 12.7
Amortization of net transition (asset) obligation (9.5) 0.3 - (9.2)
Defined benefit (income) expense $ (0.1) $ 2.5 $ (2.2) $ 0.2
Defined contribution option expense of registered pension plan 10.2
Income before capitalization 10.4
Regulatory capitalization to plant and equipment 0.5
Net expense $ 10.9
December 31, 1999
Current service cost $ 3.0 $ 0.8 $ 0.4 $ 4.2
Interest cost 19.3 1.3 0.6 21.2
Expected return on plan assets (28.7) - - (28.7)
Amortization of net transition (asset) obligation (9.8) 0.3 0.1 (9.4)
Defined benefit (income) expense $ (16.2) $ 2.4 $ 1.1 $ (12.7)
Defined contribution option expense of registered pension plan 10.3
Income before capitalization (2.4)
Regulatory capitalization to plant and equipment 0.5
Net expense $ (1.9)






Net amount related to continuing operations for 2001 was an expense of $1.7 million (2000 ­ income of $1.9 million).

</table>

C. STATUS OF PLANS

<table>
December 31, 2001 Registered Supplemental Other Total
Fair value of plan assets $ 403.4 $ - $ - $ 403.4
Accrued benefit obligation 345.5 27.5 13.6 386.6
Funded status - plan surplus (deficit) 1 57.9 (27.5) (13.6) 16.8
Amounts not yet recognized in financial statements:
Unamortized transition obligation (asset) (84.1) 4.0 - (80.1)
Unamortized net actuarial gains 5.9 2.6 (4.4) 12.9
Total recognized in financial statements:
Accrued liability $ (20.3) $ (20.9) $ (9.2) $ (50.4)
Amortization period in years (EARSL) 11 11 15
December 31, 2000
Fair value of plan assets $ 423.5 $ - $ - $ 423.5
Accrued benefit obligation 323.8 24.6 9.1 357.5
Funded status - plan surplus (deficit) 1 99.7 (24.6) (9.1) 66.0
Amounts not yet recognized in financial statements:
Unamortized transition (asset) obligation (93.4) 4.3 0.1 (89.0)
Unamortized net actuarial gains (27.3) 1.2 0.6 (25.5)
Total recognized in financial statements:
Accrued liability $ (21.0) $ (19.1) $ (8.4) $ (48.5)
Amortization period in years (EARSL) 11 11 15


1 Management intends to utilize the surplus in the registered defined benefit option to pay contributions to the registered defined contribution option and the supplemental defined benefit plan.

</table>

D. RECONCILIATION OF PLAN ASSETS

<table>
Registered Supplemental Other Total
Fair value of plan assets on December 31, 1999 $ 417.2 $ - $ - $ 417.2
Transfers to defined contribution option (10.2) - - (10.2)
Settlement upon sale of Alberta D&R operation (Note 3) (29.5) - - (29.5)
Business combination (Note 5) 21.8 - - 21.8
Benefits paid (24.7) - - (24.7)
Actuarial return on plan assets1 48.9 - - 48.9
Fair value of plan assets at December 31, 2000 423.5 - - 423.5
Contributions 0.9 - - 0.9
Transfers to defined contribution option (9.3) - - (9.3)
Settlement upon sale of Alberta D&R operation (Note 3) 2.6 - - 2.6
Benefits paid (25.1) - - (25.1)
Effect of translation on U.S. plans 0.9 - - 0.9
Actual return on plan assets 1 9.9 - - 9.9
Fair value of plan assets at December 31, 2001 $ 403.4 $ - $ - $ 403.4




1 Net of expenses.

</table>

Plan assets include common shares of the corporation having a fair value of $0.9 million at Dec. 31, 2001 (2000 - $0.9 million). In 2001, the corporation charged the registered plan $0.1 million (2000 - $0.1 million) for administrative services provided during the year.



E. RECONCILIATION OF ACCRUED BENEFIT OBLIGATIONS

<table>
Registered Supplemental Other Total
Accrued benefit obligation as at December 31, 1999 $ 285.5 $ 19.7 $ 9.6 $ 314.8
Current service cost 3.2 0.7 0.4 4.3
Interest cost 21.3 1.5 0.7 23.5
Benefits paid (23.6) (1.1) (0.9) (25.6)
Curtailment as a result of other post-employment plan changes - - (2.1) (2.1)
Settlement upon sale of Alberta D&R operation (Note 3) (11.0) - (1.2) (12.2)
Business combination (Note 5) 28.1 - 2.4 30.5
Actuarial gains 20.3 3.8 0.2 24.3
Accrued benefit obligation as at December 31, 2000 323.8 24.6 9.1 357.5
Current service cost 3.9 0.8 0.4 5.1
Interest cost 22.1 1.7 0.9 24.7
Benefits paid (24.0) (1.2) (1.0) (26.2)
Effect of translation on U.S. plans 1.5 - 0.2 1.7
Actuarial gains 18.2 1.6 4.0 23.8
Accrued benefit obligation as at December 31, 2001 $ 345.5 $ 27.5 $ 13.6 $ 386.6




</table>

The significant actuarial assumptions adopted in measuring the corporation's accrued benefit obligations were as follows:

<table>
Dec. 31, 2001 Registered Supplemental Other
Liability discount rate 6.5% - 7.0% 6.5% 6.5% - 7.0%
Expected long-term rate of return on plan assets 7.0% - 8.5% - -
Rate of compensation increase (exclusive of promotion increases) 3.5% - 5.0% 3.5% -
Health care cost escalation - - 6.6% - 7.0% 1
Dental care cost escalation - - 3.5%
Provincial health care premium escalation - - 2.5%
Dec. 31, 2000
Liability discount rate 7.0% - 7.5% 7.0% 7.0% - 7.5%
Expected long-term rate of return on plan assets 7.0% - 8.5% - -
Rate of compensation increase (exclusive of promotion increases) 3.5% 3.5% -
Health care cost escalation - - 6.6% - 7.0%1
Dental care cost escalation - - 3.5%
Provincial health care premium escalation - - 2.5%
1 For five years and 5 per cent thereafter for Canadian plans. For U.S. plans decreasing gradually to 4.5 per cent for 2016 and remaining at that level thereafter.
</table>


20. Financial risk management

A. FOREIGN EXCHANGE RATE RISK MANAGEMENT

I . HEDGES OF FOREIGN OPERATIONS The corporation has exposure to changes in the carrying values of its foreign operations as a result of changes in foreign exchange rates. The corporation uses cross-currency interest rate swaps at fixed and floating rate terms, forward sales contracts and direct foreign currency debt to hedge these exposures. The principal component of the cross-currency interest rate swaps and direct foreign currency debt hedge a portion of the carrying value of foreign operations. Translation gains and losses related to these components are deferred and included in CTA in shareholders' equity on a net of tax basis.

The interest component of the cross-currency interest rate swaps and interest on direct foreign currency debt hedge a portion of the future earnings of the foreign operations. Settlement gains and losses are included in earnings as realized.



Details of the notional amounts of cross-currency interest rate swaps were as follows:

<table>
2001 2001 2000 2000
Amount Maturities Amount Maturities
Australian dollar hedges AU$300.0 2002 - 2010 AU$305.0 2002 - 2009
U.S. dollar hedges US$749.0 2002 - 2006 US$664.0 2002 - 2009






</table>

At Dec. 31, 2001, the fair value of the cross-currency interest rate swaps was a liability of $45.0 million (2000 - $3.6 million liability) of which a $36.9 million liability (2000 - $23.4 million asset) related to the principal component of the swaps is deferred and was recorded in deferred credits and other long-term liabilities (Note 12) (2000 - other assets (Note 9)).

In addition, the corporation has designated U.S. dollar denominated long-term debt (Note 11) in the amount of US$162.8 million (2000 - US$73.0 million) as a hedge of its net investment in U.S. operations with $1.2 million (2000 - $0.3 million) of related foreign currency losses deferred and included in CTA.

The corporation has also hedged a portion of its net investment in self-sustaining subsidiaries with forward sales contracts with notional amounts of NZ$12.5 million (2000 ­ NZ$12.5 million), US$43.3 million (2000 - US$9.0 million) and AU$nil (2000 ­ AU$19.3 million). The fair value of these contracts is a $0.1 million liability (2000 - $0.9 million liability), a $0.2 million liability (2000 - $0.5 million asset) and $nil (2000 - $0.5 million liability), respectively.

In addition, the corporation has hedged foreign currency denominated long-term intercompany loans to a self-sustaining foreign subsidiary using forward contracts with a notional amount of US$122.9 million (2000 ­ nil) and a fair value liability of $1.6 million (2000 ­ nil).

In 2000, the corporation had hedged a portion of its future earnings from foreign operations through forward sales contracts maturing in 2002 with total notional amounts of US$7.5 million. The fair value of these contracts at Dec. 31, 2000 was a $0.2 million asset.













IV. HEDGES OF FUTURE FOREIGN CURRENCY OBLIGATIONS

The corporation has hedged future foreign currency obligations through forward purchase contracts as follows: <table>
2001 2000
Currency Fair value Fair value
Currency sold purchased Amount asset (liability) Amount asset (liability)
U.S. dollars Swiss francs 22.6 Swiss francs ($0.1) 52.0 Swiss francs ($2.8)
Canadian dollars U.S. dollars US$196.6 $3.6 US$91.0 $2.1
Canadian dollars British pounds £1.8 $0.1 £4.0 $0.1




</table>

At Dec. 31, 2001, deferred foreign exchange losses of $8.7 million (2000 - $6.9 million) related to these hedges were included in other assets (Note 9).

In addition, at Dec. 31, 2000, the corporation had hedged a foreign currency denominated short-term intercompany operating loan to a self-sustaining foreign subsidiary using forward contracts with a notional amount of US$12.5 million and a fair value asset of $0.1 million.

B. INTEREST RATE RISK MANAGEMENT

I . EXISTING DEBT At Dec. 31, 2001, the corporation had fixed the interest rates on 64.8 per cent (2000 ­ 64.0 per cent) of its debt through fixed-rate borrowings.

The corporation has converted the interest rates on $425.0 million (2000 - $150.0 million) of its long-term fixed interest rate debt to floating rates through receive fixed interest rate swaps (Note 11). The total fair value of these swaps as at Dec. 31, 2001 was a $20.9 million asset (2000 - $5.3 million asset).

The fair value of the corporation's fixed interest long-term debt changes as interest rates change, with details as follows:

<table>
2001 2001 2000 2000
Carrying amount Fair value Carrying amount Fair value
Long-term debt - recourse $ 2,511.1 $ 2,527.7 $ 2,201.4 $ 2,205.0




</table>

II. ANTICIPATED FUTURE DEBT ISSUANCES The corporation uses forward starting interest rate swaps, treasury locks and spread locks to hedge its interest payments on anticipated future debt issuances. As at Dec. 31, 2001, the total notional principal amounts were $nil (2000 - $200.0 million) and US$338.5 million (2000 ­ US$93.5 million), having total fair value liabilities of $nil (2000 - $2.6 million) and $8.3 million (2000 - $6.2 million), respectively, and maturities from 2002 to 2016.

C. ENERGY COMMODITIES PRICE RISK MANAGEMENT

I . TRADING ACTIVITIES The corporation markets energy derivatives, including physical and financial swaps, forwards and options, to gain market information, optimize returns from assets and to earn trading revenues. At Dec. 31, 2001, details of the corporation's trading positions were as follows:

<table>
Fixed price payor Fixed price receiver Maximum term
Units (000's) notional amounts notional amounts In months
Electricity Megawatt-hours (MWh) 13,893.7 13,931.5 60
Natural gas gigajoules (GJ) 189,947.4 140,952.3 60
Crude oil barrels (BBLS) 325.0 25.0 12
Electrical transmission rights MWh 871.6 - 9

</table>

The carrying and fair value of energy commodity trading assets included in accounts receivable was $370.9 million (2000 - $1,150.3 million). The carrying and fair value of energy commodity liabilities included in accounts payable was $339.6 million (2000 - $1,110.3 million).

II. HEDGING ACTIVITIES The corporation uses energy derivatives, including physical and financial swaps, forwards and options, to manage its exposure to changes in electricity and natural gas prices. At Dec. 31, 2001, details of the corporation's hedging position were as follows:

<table>
Floating price payor notional amount Floating price receiver notional amount Maximum term
in months
Heat rate swaps 1,515.6 MWh 8,790.5 GJ 82
Diesel swap (millions of litres) 16.1 16.1 12
Commodity hedges 219 MWh 1,270.2 GJ 12




</table>

The fair value of these swaps total an asset of $2.2 million (2000 -$54.8 million liability).

In addition, the corporation has entered into a number of long-term gas purchase and transportation agreements in the normal course of business to hedge its long-term electricity sales contracts. D. CREDIT RISK MANAGEMENT The corporation actively manages its exposure to credit risk by assessing the ability of counterparties to fulfill their obligations under the related contracts prior to entering into such contracts. For Energy Marketing, the corporation sets strict credit limits for each counterparty and halts trading activities with the counterparty if the limits are exceeded. The corporation makes detailed assessments of the credit quality of all counterparties and, where appropriate, obtains corporate guarantees and/or letters of credit to support the ultimate collection of these receivables. TransAlta is not exposed to credit risk for Alberta Generation PPAs under the terms of these contracts.

The corporation has a concentration of credit risk relating to its long-term receivable of $173.3 million from UtiliCorp Networks Canada arising from the sale of the discontinued Alberta D&R operation. At Dec. 31, 2000, the corporation had US$66.2 million of receivables outstanding related to sales to the California market. US$12.9 million of this amount was received during 2001, however, ultimate collection of the remaining balance remains uncertain. As a result, the provision of US$28.8 million established in 2000 remains in place. At Dec. 31, 2001, TransAlta's exposure to credit risk resulting from the bankruptcy of Enron Corporation was $1.3 million and appropriate provisions have been made.

The maximum credit exposure to any one customer, including the fair value of open trading positions, is $98.4 million. Approximately $47 million of this exposure is secured by a letter of credit.

21. Joint ventures

Summarized information on the results of operations, financial position and cash flows relating to the corporation's pro-rata interests in its continuing jointly controlled corporations was as follows:

<table>
2001 2000 1999
Results of operations
Revenues $ 90.5 $ 112.2 $ 22.2
Expenses (74.2) (95.7) (19.1)
Proportionate share of net earnings $ 16.3 $ 16.5 $ 3.1
Cash flows
Cash flow from operations $ 13.0 $ 18.0 $ 8.9
Cash flow to investing activities (8.3) (17.8) (102.0)
Cash flow from (to) from financing activities (8.3) (35.0) 92.3
Proportionate share of changes in cash $ (3.6) $ (34.8) $ (0.8)
Financial position
Current assets $ 140.2 $ 69.7
Long-term assets 172.8 185.4
Current liabilities (144.4) (48.3)
Long-term liabilities - (56.4)
Proportionate share of net assets $ 168.6 $ 150.4


</table>

22. Related party transactions

In September 2001, the corporation sold its 60 per cent interest in its Fort Saskatchewan plant to TA Cogen for an after-tax gain of $5.0 million (Note 5).

In November 2000, TA Cogen entered into a fixed-for-floating gas swap transaction with TransAlta Energy for a five-year and one-month period starting Dec. 1, 2000. As described in Note 12, TA Cogen is owned 49.99 per cent by TransAlta Power, a publicly-owned limited partnership with the remaining 50.01 per cent owned by TransAlta Energy, which also operates and maintains TA Cogen's three combined-cycle power plants in Ontario and a plant in Fort Saskatchewan. The swap transaction provided TA Cogen with fixed price gas for both the Mississauga and Ottawa plants over the five-year period. The floating prices associated with the Mississauga and Ottawa Cogen plants' long-term fuel supply agreements were transferred to TransAlta Energy's account. The notional gas volume in the transaction was the total delivered fuel for both facilities. As consideration and in negotiation, TA Cogen transferred the right to incremental revenues associated with curtailed electrical production and subsequent higher revenue gas sales. At Dec. 31, 2001, the portion of the contract related to the minority interest had a fair value liability of $13.3 million (2000 - $19.0 million liability) and was included as a charge to non-controlling interests.

23. Commitments

A significant portion of the corporation's electricity and thermal sales revenues are subject to long-term contracts and arrangements. In Generation, commencing Jan. 1, 2001, Alberta Generation assets became subject to long-term PPAs for the remaining life of each plant or unit. These PPAs set a production requirement and availability target to be supplied by each plant or unit and the price at which each megawatt-hour will be supplied to the customer. A significant portion of Generation's Centralia plant production is subject to short to medium-term energy sales contracts. In addition, most of the corporation's energy sales from its IPP plants are also subject to medium to long-term energy sales contracts.

The corporation has entered into a number of long-term gas purchase agreements, transportation and transmission agreements, royalty and right-of-way agreements in the normal course of operations. In addition, the corporation has committed to purchase turbines for a total purchase price of $262.9 million, has entered into a number of operating lease agreements and commitments under mining agreements. Approximate future payments under these turbines commitments and operating lease agreements are as follows:

<table>
Operating leases Turbines Mining agreements Total
2002 $ 4.7 $ 58.7 $ 10.9 $ 74.3
2003 4.7 118.1 10.9 133.7
2004 1.6 79.9 10.9 92.4
2005 1.1 6.2 10.9 18.2
2006 1.0 - 10.9 11.9
2007 and thereafter 2.0 - 195.5 197.5
$ 15.1 $ 262.9 $ 250.0 $ 528.0




</table>

24. Other contingencies

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.

Commencing Jan. 1, 2001, the unit is subject to the terms of a 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 amount has been accrued in these financial statements for this potential liability as neither the outcome nor amount was 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 $90.0 million dollars.

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 material adverse effect on the corporation as a whole.

25. Comparative figures

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



26. U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

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

<table>

A. EARNINGS AND EPS
Reconciling items 2001 2000 1999
Earnings from continuing operations - Canadian GAAP $ 182.6 $ 146.4 $ 53.9
Derivatives and hedging activities, net of tax (I) 20.0 (4.2) (15.6)
Start-up costs, net of tax (II) 3.6 10.5 (5.7)
Preferred security distributions, net of tax (III) (13.1) (12.8) (5.2)
Amortization of debt extinguishment, net of tax (IV) 0.8 0.8 0.8
Income taxes - rate change adjustment (V) 20.0 2.6 -
Amortization of pension transition adjustment (VI) (4.5) - -
Earnings from continuing operations - U.S. GAAP $ 209.4 $ 143.3 $ 28.2
Earnings from discontinued operations - Canadian and U.S. GAAP $ 45.1 $ 89.1 $ 101.7
Net gain on disposal of discontinued operations - Canadian and U.S. GAAP $ - $ 266.8 $ 19.7
Net earnings before extraordinary items and change in accounting principle - U.S. GAAP $ 254.5 $ 499.2 $ 149.6
Extraordinary loss - Canadian GAAP - 209.7 -
Income taxes - rate change adjustment (V) - 22.6 -
Employee future benefits (VI) - (30.3) -
Extraordinary loss - U.S. GAAP $ - $ 202.0 $ -
Net earnings before change in accounting principle - U.S. GAAP $ 254.5 $297.2 $ 149.6
Cumulative effect of change in accounting principle, net of taxes of $0.1 (I) 0.2 - $ -
Net income - U.S. GAAP $ 254.7 $ 297.2 $149.6
Cumulative effect of change in accounting principle, net of taxes of $25.9 (I), (VIII) (38.5) - -
Foreign currency cumulative translation adjustment (I), (VIII) (5.4) 19.6 $ (25.9)
Net gain on derivative instruments (I), (VIII) 10.0 - -
Comprehensive income - U.S. GAAP $ 220.8 $ 316.8 $ 123.7
Basic EPS - U.S. GAAP
Earnings from continuing operations $ 1.24 $ 0.85 $ 0.17
Earnings from discontinued operations 0.27 0.53 0.60
Net gain on disposal of discontinued operations - 1.58 0.11
Extraordinary loss - (1.20) -
Cumulative effect of change in accounting principle - - -
Net earnings $ 1.51 $ 1.76 $ 0.88
Diluted EPS - U.S. GAAP
Earnings from continuing operations $ 1.22 $ 0.82 $ 0.15
Cumulative effect of change in accounting principle $ - $ - $ -
Net earnings $ 1.49 $ 1.73 $ 0.87




</table>

B. Balance Sheet INFORMATION

<table>
2001 2001 2000 2000
Reconciling items Canadian GAAP U.S. GAAP Canadian GAAP U.S. GAAP
Assets
Current derivative assets (I) $ - $ 58.5 $ - $ -
Future or deferred income tax assets - current (V) $ 16.9 $ 25.6 $ 30.3 $ 8.7
Income taxes receivable (I), (II), (VI) $ 128.3 $ 136.9 $ 153.9 $ 153.9
Investments (X) $ 37.3 $ 227.8 $ 228.0 $ 228.0
Capital assets, net (II) $ 6,124.1 $ 6,140.2 $ 5,277.1 $ 5,287.2
Regulatory rate-making liability (V) $ - $ (8.7) $ - $ (22.3)
Long-term derivative asset (I) $ - $ 54.1 $ - $ -
Other assets (I), (II), (III), (VI) $ 47.1 $ 18.3 $ 77.0 $ 50.7
Liabilities
Accounts payable and accrued liabilities (VI) $ 1,116.1 $ 1,069.3 $ 1,437.9 $ 1,394.8
Current derivative liability (I) $ - $ 21.5 $ - $ -
Long-term debt (I), (III), (X) $ 2,406.8 $ 3,080.2 $ 2,121.8 $ 2,413.2
Deferred credits and other long-term liabilities (I), (IV) $ 526.5 $ 498.7 $ 455.1 $ 478.1
Firm commitments (I) $ - $ 3.6 $ - $ -
Long-term derivative liabilities (I) $ - $ 134.3 $ - $ -
Future or deferred income tax liability (I), (II), (III), (IV), (V), (VI) $ 409.1 $ 416.6 $ 349.4 $ 330.0
Equity
Preferred securities (III) $ 452.6 $ - $ 292.0 $ -
Common shares (IX) $ 1,170.9 $ 1,169.2 $ 1,150.3 $1,148.7
Retained earnings (I), (II), (IV), (V), (VI) $ 838.3 $ 858.4 $ 826.9 $ 806.9
Cumulative translation adjustment (I), (VIII) $ (19.5) $ - $ (19.8) $ -
Accumulated other comprehensive income (I), (VIII) $ - $ (53.7) $ - $ (19.8)




</table>

V. C. RECONCILING ITEMS

I. Derivatives and hedging activities

On Jan. 1, 2001, the corporation adopted Statement 133, Accounting for Derivative Instruments and Hedging Activities. The new statement requires all derivative instruments to be recorded on the balance sheet at fair value, with changes in fair value recognized in earnings in the period of change. If the derivative is designated and qualifies as a fair value hedge, the changes in fair value of the derivative and the hedged item attributable to the hedged risk are recognized in earnings in the period the change occurs. If the derivative is designated and qualifies as a cash flow hedge, the effective portion of changes in the fair value of the derivative are recorded in other comprehensive income (OCI) and are recognized in earnings as the hedged item affects earnings. The ineffective portion of changes in fair value of cash flow hedges is recognized in earnings. If the derivative is designated and qualifies as a hedge of a net investment in a foreign currency, the effective portion of changes in fair value are recorded OCI as part of the CTA and the ineffective portion is recognized in earnings.

The adoption of Statement 133 on Jan. 1, 2001 resulted in the recognition of additional derivative assets with a fair value of $1.6 million, firm commitment assets with a fair value of $0.6 million, additional derivative liabilities with a fair value of $88.6 million, a $0.3 million ($0.2 million after-tax) credit to income as the cumulative effect of a change in accounting principle and a charge of $64.4 million ($38.5 million after-tax) to OCI as the cumulative effect of a change in accounting principle.

(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 $0.2 million ($0.1 million after-tax) related to the ineffective portion of its hedging instruments (inclusive of the time value of money) and a net gain of $nil related to 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. These instruments will protect the corporation against increases in interest rates prior to the date of issuance. The maximum term of cash flow hedges of anticipated transactions is 13 years.

The corporation's cash flow hedges resulted in a net gain of $nil related to the ineffective portion of its hedging instruments, and a net gain of $nil related to the portion of the hedging instrument excluded from the assessment of hedge effectiveness. Over the next twelve months, the corporation expects to reclassify approximately $3.7 million of net losses on cash flow hedging instruments from accumulated other comprehensive income (AOCI) to earnings.

(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 United States, Australia and Barbados. Realized and unrealized gains and losses from these hedges are included in CTA included in OCI, with the related amounts due to or from counterparties included in other assets, long-term debt and other liabilities.



The corporation recognized $0.2 million of net gains on its net investment hedges, included CTA, related to its forward sales contracts.

(iv) TRADING ACTIVITIES As disclosed in Note 20, the corporation markets energy derivatives to gain market information, optimize returns from assets and to earn trading revenues. These derivatives are recorded on the balance sheet at fair value under both Canadian and U.S. GAAP.

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 capital assets 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 security 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. The fair value of the preferred securities at Dec. 31, 2001 was $485.5 million (2000 ­ $315.4 million).

IV. Debt extinguishment

Under U.S. GAAP, the premium on redemption of long-term debt related to the limited partnership transaction is 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. Canadian and U.S. GAAP require accounting for income taxes using the liability method of tax allocation; however, two significant differences remain between Canadian and U.S. GAAP:

(i) Canadian GAAP requires that future income tax balances be adjusted to reflect substantively enacted rates rather than currently legislated tax rates under U.S. GAAP. As a result of this difference, a $20.0 million (2000 - $2.6 million; 1999 - $nil) adjustment to earnings from continuing operations is required; and

(ii) Under Canadian GAAP, rate-regulated operations need not recognize future income taxes to the extent that future income taxes are expected to be included in the rates charged to and recovered from customers. For these operations, U.S. GAAP requires that the corporation record deferred income tax assets or liabilities for its rate-regulated operations. As these amounts are recoverable or payable through future revenues, a corresponding regulatory rate-making asset or liability is recorded for U.S. GAAP purposes.

Deferred income taxes under U.S. GAAP would be as follows:

<table>
2001 2000 1999
Future income tax liability (net) under Canadian GAAP $ (388.4) $ (310.0) $ (72.3)
Rate-regulated operations deferred income taxes 8.7 21.2 (51.2)
Other U.S. GAAP adjustments, net (27.5) (3.4) 25.5
Difference related to rate change adjustment 20.0 (20.0) -
$ (387.2) $ (312.2) $ (98.0)
Comprised of the following:
2001 2000 1999
Current deferred income tax assets $ 25.6 $ 8.7 $ 1.0
Long-term deferred income tax assets 15.6 9.1 6.1
Current deferred income tax liabilities (11.8) - -
Long-term deferred income tax liabilities (416.6) (330.0) (105.1)
$ (387.2) $ (312.2) $ (98.0)




</table>

VI. Employee future benefits

US 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 and is amortized over ten years. The difference between US GAAP and Canadian GAAP for the corporation's regulated operations has no effect on net earnings and retained earnings, as any difference from the allowed method of recovery is recognized as a regulatory rate-making liability refundable through regulation. As indicated in Note 4, the corporation discontinued regulatory accounting and commenced the application of Canadian GAAP consistent with the deregulation of the electricity generation industry in Alberta beginning Jan. 1, 2001.

<table>

Sensitivity to changes in assumed health care cost trend rates are as follows:
One percentage One percentage
point increase point decrease
Effect on total service and interest costs 0.1 (0.1)
Effect on post-retirement benefit obligation 0.6 (0.6)




</table>

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 US 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:

<table>
2001 2000 1999
Cumulative effect of accounting change, net of taxes of ($25.9) million $ (38.5) $ - $ -
Net gain on derivative instruments:
Unrealized gains, net of taxes of $0.4 million 0.5 - -
Reclassification adjustment for losses included in net income, net of taxes of $6.3 million 9.5 - -
Net gain on derivative instruments 10.0 - -
Translation adjustments (5.4) 19.6 (26.3)
Other comprehensive income (loss) $ (33.9) $ 19.6 $ (26.3)
The components of accumulated other comprehensive income were:
2001 2000
Net loss on derivative instruments $ (28.5) $ -
Translation adjustments (25.2) (19.8)
Accumulated other comprehensive income (loss) $ (53.7) $ (19.8)

</table>

IX. SHARE CAPITAL Under US GAAP, amounts receivable for share capital should be recorded as a deduction from shareholder's equity. Under the corporation's employee share purchase plan, accounts receivable for share purchases at Dec. 31, 2001 was $1.7 million (2000 - $1.6 million).

X. RIGHT OF OFFSET AGREEMENT As disclosed in Notes 6 and 11, the corporation has a New Zealand bank deposit that has been offset with a New Zealand bank facility. The arrangement does not qualify for offsetting under U.S. GAAP.

D. stock option plans

The corporation has elected to account for stock compensation in accordance with the Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees.

No amount of compensation expense has been recognized in the financial statements for stock options granted to employees and directors. The following table provides pro forma measures of net income and net income per common share in accordance with US GAAP had stock options been recognized as compensation expense based on the estimated fair value of the options on the grant date in accordance with Statement 123, Accounting for Stock-Based Compensation.

<table>
2001 2001 2000 2000 1999 1999
As Pro As Pro As Pro
reported forma Reported forma reported forma
Net earnings $ 254.7 $ 252.7 $ 297.2 $ 296.9 $ 149.6 $ 149.1
EPS $ 1.51 $ 1.50 $ 1.76 $ 1.76 $ 0.88 $ 0.88




</table>

Stock options granted in 2001 had an estimated weighted-average fair value of $4.35 per option (2000 - $1.86; 1999 ­ $3.07). All options issued by the corporation permit the holder to purchase one common share of the corporation at the stated exercise price.

The estimated fair value of stock options issued was determined using the binomial model using the following weighted average assumptions:

<table>
2001 2000 1999
Risk-free interest rate (%) 5.4 5.4 4.8
Expected hold period to exercise (years) 7.0 7.0 7.0
Volatility in the price of the corporation's shares (%) 28.2 19.6 16.4




</table>

Future dividend payments were assumed in estimating the fair value of the options.

E. Changes in accounting standards

In June 2001, the Financial Accounting Standards Board (FASB) issued Statement 141, Business Combinations, and Statement 142, Goodwill and Other Intangible Assets. Statement 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting. It also specifies the types of acquired intangible assets that are required to be recognized and reported separately from goodwill. Statement 142 requires that goodwill and certain intangibles no longer be amortized, but instead be tested for impairment at least annually. Statement 142 is required to be applied in fiscal years beginning after Dec. 15, 2001, with early application permitted in certain circumstances. On Jan. 1, 2002, the corporation reclassified $29.3 million from acquired intangibles resulting from the acquisition of MEGA, to goodwill, which will not be subject to amortization. There was no impairment of this goodwill upon adoption. Amortization of this amount was approximately $7.7 million in 2001 (2000 - $3.6 million; 1999 - $nil).

In August 2001, the 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. Upon adoption, the corporation will recognize an increase in liabilities in the amount of approximately $470 million with a corresponding increase in capital assets.

In October 2001, the FASB issued Statement 144, Impairment and Disposal of Long-Lived Assets, which requires that all long-lived assets, including discontinued operations, be measured at the lower of carrying amount or fair value less costs to sell. Discontinued operations are no longer measured at net realizable value and will no longer include provisions for operating losses that have not yet occurred. Further, discontinued operations have been broadened to include components that can be distinguished from the rest of the entity. Statement 144 is effective for fiscal years beginning after Dec. 14, 2001, with earlier application encouraged. The corporation does not expect impairment of any long-lived assets upon adoption, and no provision for losses has been made for the discontinued Transmission operation, which is expected to be sold in the first half of 2002.













































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/ Rodger Conner

(Signature)

Rodger Conner, Corporate Secretary

Date: March 1, 2002