TransAlta Announces 2002 Results and Declares Dividend, Part 1 of 2.

Business Editors & Energy Writers

CALGARY, Alberta--(BUSINESS WIRE)--Jan. 31, 2003

TransAlta Corporation (NYSE:TAC)(TSX:TA.TO) today announced 2002 net earnings of $189.9 million ($1.12 per share) versus $214.6 million ($1.27 per share) in 2001. This reflects a one-time gain of $120.0 million ($0.71 per share) from the sale of the Transmission business in the second quarter, partially offset by the impact from one-time events announced in the fourth quarter:

-- Purchased the remainder of Vision Quest Windelectric Inc., an Alberta-based wind power generator, for $35.5 million in cash and common shares. Vision Quest has 44 MW of wind power under operation and is currently engaged in a joint venture with ENMAX to build the 75 MW McBride project in Pincher Creek, Alberta.

-- Finalized post-closing adjustments for the sale of its Transmission operation, resulting in an additional $10.0 million ($0.06 per share) after-tax gain.

-- Completed the purchase of Australia Gas and Light's (AGL) 15 per cent interest in the 250 MW Southern Cross Energy Partnership for AUD$8.5 million.

Fourth quarter 2002 had a net loss applicable to common shareholders of $54.3 million (loss of $0.32 per share), compared to net earnings of $46.5 million ($0.27 per share) in fourth quarter 2001. The fourth quarter loss from continuing operations applicable to common shareholders was $64.3 million (loss of $0.38 per share), down from net earnings of $33.2 million ($0.19 per share) in the same quarter of the previous year.

"TransAlta's availability, production and cash flow performed very well in what continued to be difficult market conditions," said Steve Snyder, TransAlta's President and CEO. "We made some tough decisions in the quarter that we believe will benefit the company in the future, including the development of a more proactive maintenance program in Alberta."

Revenue for the fourth quarter increased by $71.1 million over the same period in 2001, reflecting increased production from the Centralia plant, increased long-term contracted prices for electricity generation and higher Energy Marketing revenues. Plant availability was 87 per cent, down from 90 per cent in fourth quarter 2001 due to the accelerated maintenance in Alberta and an unplanned Wabamun unit three outage. Production was up 966 megawatt-hours (MWh) to 12,545 MWh, due to improved availability of the Centralia plant and incremental production from new power plants, and partially offset by lost production resulting from the accelerated Alberta maintenance.

Cash from operating activities including changes in working capital was $189.5 million, compared to $131.7 million in fourth quarter 2001. This increase was mainly due to lower working capital requirements, partially offset by lower earnings.

TransAlta consolidated financial highlights

----------------------------------------------------------------------
(In millions except            3 months ended            Year ended
 per share amounts)              December 31            December 31
                              2002        2001        2002        2001
                 -----------------------------------------------------
                Amount   Per  Amount  Per   Amount   Per  Amount  Per
                        share        share          share        share
----------------------------------------------------------------------
Revenue from
 continuing
 operations(a)  $517.6        $434.4       $1,723.9     $2,319.4
----------------------------------------------------------------------
Net earnings
 (loss) from
  continuing
  operations(b) $(64.3)$(0.38)$ 33.2 $0.19 $   57.1 $0.34 $169.5 $1.00
Discontinued
 operations          -      - $ 13.3 $0.08 $   12.8 $0.07 $ 45.1 $0.27
Gain on sale    $ 10.0 $ 0.06      -     - $  120.0 $0.71      -     -
----------------------------------------------------------------------
Net earnings
 (loss)(b)      $(54.3)$(0.32)$ 46.5 $0.27 $  189.9 $1.12 $214.6 $1.27
----------------------------------------------------------------------
Cash flow from
 operating
 activities     $189.5        $131.7       $  437.7       $715.6
----------------------------------------------------------------------

    (a)Trading revenues are now being reported on a net basis

    (b)Applicable to common shareholders, net of preferred securities
distributions



TransAlta consolidated financial highlights (continued)

----------------------------------------------------------------------
                             3 months ended          Year ended
                              December 31           December 31
                            2002       2001       2002        2001
----------------------------------------------------------------------
Availability (%)            87.2       89.9       88.4        86.9
Production (GWh)          12,545     11,579     46,877      44,136
Electricity trading
 volumes (GWh)            31,786     15,121    103,076      27,619
Gas trading volumes
 (million GJ)               45.9       36.5      159.8        99.3
----------------------------------------------------------------------

Discontinued operations in 2002 and 2001 include net earnings from the Transmission operation, sold in April 2002. Results for 2001 also include the Edmonton Composter operation, sold in June 2001.

In fourth quarter 2002, TransAlta:

-- Purchased the remainder of Vision Quest Windelectric Inc., an Alberta-based wind power generator, for $35.5 million in cash and common shares. Vision Quest has 44 MW of wind power under operation and is currently engaged in a joint venture with ENMAX to build the 75 MW McBride project in Pincher Creek, Alberta.

-- Finalized post-closing adjustments for the sale of its Transmission operation, resulting in an additional $10.0 million ($0.06 per share) after-tax gain.

-- Completed the purchase of Australia Gas and Light's (AGL) 15 per cent interest in the 250 MW Southern Cross Energy Partnership for AUD$8.5 million.

TransAlta today also declared a dividend of $0.25 per share on common shares payable April 1, 2003 to shareholders of record at the close of business on March 1, 2003.

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

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

MANAGEMENT'S DISCUSSION AND ANALYSIS

This discussion and analysis should be read in conjunction with the unaudited consolidated financial statements of TransAlta Corporation (TransAlta or the corporation) as at and for the three and twelve months ended Dec. 31, 2002 and 2001, and should also be read in conjunction with the audited consolidated financial statements and Management's Discussion and Analysis contained in TransAlta's annual report for the year ended Dec. 31, 2001. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP). 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. In some cases, forward-looking statements can be identified by terms such as 'may', 'will', 'believe', 'expect', 'potential', 'enable', 'continue' or other comparable terminology. These statements are not guarantees of TransAlta's future performance and are subject to risks, uncertainties, and other important factors that could cause the corporation's actual performance to be materially different from those projected. Some of the risks, uncertainties, and factors include, but are not limited to: legislative and regulatory developments that could affect revenues, costs, the speed and degree of competition entering the market, global capital markets activity, timing and extent of changes in commodity prices, prevailing interest rates, currency exchange rates, inflation levels and general economic conditions in geographic areas where TransAlta Corporation operates, results of financing efforts, changes in counterparty risk and the impact of accounting policies issued by Canadian and United States standard setters. Given these uncertainties, the reader should not place undue reliance on these forward-looking statements.

RESULTS OF OPERATIONS

The results of operations are organized by consolidated results and by business segment. TransAlta has two business segments: Generation and Energy Marketing. A third business segment, Independent Power Projects (IPP), was combined with the Generation segment effective Jan. 1, 2002, following changes to TransAlta's organizational structure. A fourth segment, Transmission, was sold on April 29, 2002. Prior period amounts have been reclassified to reflect these changes. A corporate group provides finance, treasury, legal, human resources and other administrative support to the business segments. These overheads are allocated to the business segments if they are not directly attributable to discontinued operations.

Each business segment assumes responsibility for their operating results measured as earnings before interest, taxes and non-controlling interests (EBIT). EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with Canadian GAAP as an indicator of the corporation's performance or liquidity. TransAlta's EBIT is not necessarily comparable to a similarly titled measure of another company. EBIT is reconciled to net earnings applicable to common shareholders below:

                                 3 months ended          Year ended
                                    Dec. 31               Dec. 31
---------------------------------------------------------------------
                                2002       2001       2002       2001
---------------------------------------------------------------------
EBIT                         $ (67.0)   $  50.5    $ 197.6    $ 378.9
Other income                     1.0        1.2        0.1        1.5
Foreign exchange gain            0.9        2.9        1.2        0.8
Net interest expense           (24.0)     (12.4)     (82.7)     (88.1)
---------------------------------------------------------------------
Earnings (loss) from
 continuing operations
 before income taxes and
 non-controlling interests     (89.1)      42.2      116.2      293.1
Income tax expense (recovery)  (35.1)       0.5       18.1       89.9
Non-controlling interests        5.6        5.0       20.1       20.6
---------------------------------------------------------------------
Earnings (loss) from
 continuing operations         (59.6)      36.7       78.0      182.6
Earnings from discontinued
 operations                        -       13.3       12.8       45.1
Gain on disposal of
 discontinued operations        10.0          -      120.0          -
---------------------------------------------------------------------
Net earnings (loss)            (49.6)      50.0      210.8      227.7
Preferred securities
 distribution, net of tax        4.7        3.5       20.9       13.1
---------------------------------------------------------------------
Net earnings (loss)
 applicable to common
 shareholders                $ (54.3)   $  46.5    $ 189.9    $ 214.6
---------------------------------------------------------------------
---------------------------------------------------------------------

    HIGHLIGHTS

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


3 months ended Dec. 31                        2002              2001
---------------------------------------------------------------------
Availability                                  87.2%              89.9%
Production (GWh)                            12,545             11,579
Electricity trading
 volumes (GWh)(1)                           31,786             15,121
Gas trading volumes (million GJ)              45.9               36.5
---------------------------------------------------------------------
---------------------------------------------------------------------

                             Amount   Per common   Amount   Per common
                                         share                 share
---------------------------------------------------------------------
Revenues(2)                $  517.6              $  434.4
---------------------------------------------------------------------
Net earnings (loss) from
 continuing operations(3)     (64.3)      (0.38)     33.2        0.19
Earnings from
 discontinued operations(4)       -           -      13.3        0.08
Gain on disposal of
 discontinued operations,
 net of tax(4)                 10.0        0.06         -           -
---------------------------------------------------------------------
Net earnings (loss)
 applicable to common
 shareholders               $ (54.3)    $ (0.32)  $  46.5     $  0.27
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash flow from operating
 activities                 $ 189.5               $ 131.7
---------------------------------------------------------------------
---------------------------------------------------------------------


Year ended Dec. 31                           2002               2001
---------------------------------------------------------------
Availability                                 88.4%               86.9%
Production (GWh)                           46,877              44,136
Electricity trading
 volumes (GWh)(1)                         103,076              27,619
Gas trading volumes (million GJ)            159.8                99.3
---------------------------------------------------------------
---------------------------------------------------------------

                             Amount   Per common   Amount   Per common
                                        share                 share
---------------------------------------------------------------------
Revenues(2)                $1,723.9              $2,319.4
---------------------------------------------------------------------
Net earnings from
 continuing operations(3)      57.1        0.34     169.5        1.00
Earnings from
 discontinued operations(4)    12.8        0.07      45.1        0.27
Gain on disposal of
 discontinued operations,
 net of tax(4)                120.0        0.71         -           -
---------------------------------------------------------------------
Net earnings applicable
 to common shareholders    $  189.9     $  1.12  $  214.6     $  1.27
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash flow from operating
 activities                $  437.7              $  715.6
---------------------------------------------------------------------
---------------------------------------------------------------------

    (1) 2001 electricity trading volumes have been restated to conform
with current reporting practices and standards.

    (2) From continuing operations. In accordance with changes to U.S.
and Canadian GAAP, revenues from energy trading activities are now
presented on a net basis. Prior period amounts have been reclassified
to reflect this change.

    (3) Continuing operations include the Generation and Energy
Marketing segments plus corporate costs not directly attributable to
discontinued operations, and are net of preferred securities
distributions.

    (4) Discontinued operations include the Transmission operation and
the Edmonton Composter operation. The Transmission operation was sold
on April 29, 2002 and the Edmonton Composter was sold on June 29,
2001.

Net earnings from continuing operations for the three months ended Dec. 31, 2002 reflect the provision for the decommissioning of the Wabamun facility ($110.0 million pre-tax), cancellation fees on turbine contracts ($42.5 million pre-tax), and the impact of the accelerated Alberta thermal plant maintenance schedule ($27.7 million pre-tax), which are described in greater detail below. These costs were partially offset by higher contracted prices and lower purchased power costs. Net earnings from continuing operations for the year ended Dec. 31, 2002 were also influenced by the utilization and recognition of previously unrecognized tax losses ($11.2 million), the negative impact of the Wabamun unit four arbitration decision ($38.9 million plus interest of $2.7 million, pre-tax) and a prior period regulatory decision ($3.3 million pre-tax) described below. Net earnings attributable to common shareholders include the $120.0 million ($0.71 per common share) after-tax gain on disposal of the Transmission operation, which was sold on April 29, 2002.

Cash flow from operating activities for the three months ended Dec. 31, 2002 increased $57.8 million from the fourth quarter of 2001 due primarily to the non-cash impact of the asset impairment and equipment cancellation charges and lower working capital requirements offset by lower earnings. For the year ended Dec. 31, 2002, cash flow from operating activities was $277.9 million lower than in 2001 due to lower earnings, the impact of the collection in 2001 of accounts receivable relating to the Alberta Power Pool ($170.0 million) upon implementation of deregulation on Jan. 1, 2001, the payment in 2002 to the Alberta Power Pool relating to the ancillary services revenue settlement ($49.9 million) and the final installment of 2001 income taxes paid in the first quarter of 2002 ($109.0 million).

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

SIGNIFICANT ONE-TIME ITEMS

Purchase of Vision Quest Windelectric Inc.

On Dec. 6, 2002, the corporation purchased the remaining interest in Vision Quest Windelectric Inc. (Vision Quest) for cash of $21.3 million plus a previous loan of $19.8 million and $14.2 million in common shares. This transaction increased the corporation's total investment in the wind power company to $68.8 million. Included in the purchase price was $27.2 million of goodwill. Vision Quest owns and operates 67 wind turbine power plants with 44 megawatts (MW) of capacity with a further 37.5 MW under construction and a substantial resource base available for further expansion. The purchase of Vision Quest reflects TransAlta's goal to increase the portion of total generation from renewable energy by 2010. Vision Quest's financial results for the period after acquisition ($0.6 million EBIT) are included in corporate results for segmented reporting purposes (Note 13).

Decommissioning of Wabamun plant

After a detailed unit-by-unit engineering assessment, a review of environmental issues and a review of short- and long-term market forecasts, the corporation decided to implement a phased decommissioning of its 569 MW coal-fired Wabamun facility. The power purchase arrangement (PPA) for the plant expires at the end of 2003. The 147 MW unit three was removed from service on Nov. 29, 2002 after an unplanned outage, as it was not considered economical to return the unit to service. The corporation plans to retire units one and two (69 MW and 67 MW, respectively) in 2004 and unit four (286 MW) in 2010 when its operating licence expires. As a result of this decision, the corporation recognized a pre-tax impairment charge of $110.0 million in the fourth quarter of 2002.

Turbine order cancellation

After examining expected market conditions and potential greenfield development opportunities against the corporation's risk profile, the corporation concluded that the likelihood of using all of the natural gas turbines in its pre-purchased turbine program was unlikely. The corporation therefore cancelled orders for four turbines and as a result recorded a pre-tax cancellation charge of $42.5 million for contract termination costs in the fourth quarter of 2002. The costs consist solely of progress payments made to date.

Ancillary services revenue settlement

In July 2002, a dispute with the Balancing Pool of Alberta in respect of the allocation of hydro ancillary services revenue under the Hydro PPAs was resolved. TransAlta repaid $49.9 million it had received in advance from the Balancing Pool.

The settlement had no earnings impact as the corporation had not previously recognized this amount as revenue.

Refinancing of foreign operations

TransAlta restructured the financing of certain foreign operations and as a result, the company was able to record the benefit of previously unrecognized foreign tax loss carryforward balances. This restructuring contributed $11.2 million to earnings in the third quarter of 2002.

Wabamun arbitration decision

On May 23, 2002, the corporation received the arbitrators' decision with respect to the 10-month outage at Wabamun unit four, which resulted from fatigue cracks within the waterwall tubing of its boiler. The arbitrators confirmed in their ruling that the outage qualified as a force majeure event, but also ruled that the corporation should have returned the unit to service more quickly. As a result of this decision, the corporation was required to pay $38.9 million plus interest of $2.7 million, all pre-tax. The payment was recorded as a reduction to revenue.

Gain on disposal of discontinued operations

On April 29, 2002, TransAlta's Transmission operation was sold for proceeds of $820.7 million, of which $818.0 million has been collected. The proceeds excluded $31.7 million in accounts receivable, which were retained and subsequently collected, and $4.4 million in accounts payable. The disposal resulted in a gain on sale of $120.0 million ($0.71 per common share), net of income taxes of $32.9 million. The previously reported gain included a number of estimates, therefore the gain was adjusted in the fourth quarter of 2002 to reflect agreed working capital adjustments and actual amounts paid and received.

Prior period regulatory decision

On April 16, 2002, the Alberta Energy and Utilities Board (EUB) rendered a negative decision of $3.3 million pre-tax with respect to TransAlta's hydro bidding strategy in 2000.

NEW ACCOUNTING STANDARDS

Effective Jan. 1, 2002, the corporation prospectively adopted the new Canadian Institute of Chartered Accountants (CICA) standard for goodwill and other intangibles. Under the new standard, goodwill and certain intangibles are no longer subject to amortization, but are instead tested for impairment at least annually. The adoption of this standard resulted in the reclassification of $29.3 million from acquired intangibles to goodwill, which will no longer be subject to amortization under the new standard. There was no impairment of goodwill upon adoption of this standard, nor was there an impairment at Dec. 31, 2002.

On Jan. 1, 2002, the corporation retroactively adopted the new CICA standard for stock-based compensation. The new standard requires that stock-based payments to non-employees, direct awards of stock and awards that call for settlement in cash or other assets be accounted for using the fair value method of accounting. The fair value method is encouraged for other stock-based compensation plans, but other methods of accounting, such as the intrinsic value method, are permitted. Under the fair value method, compensation expense is measured at the grant date and recognized over the service period. Under the intrinsic value method, compensation expense is determined as the difference between the market price of the underlying stock and the exercise price of the equity instrument granted. If the intrinsic value method is used, disclosure is made of earnings and per share amounts as if the fair value method had been used. The corporation has elected to use the intrinsic value method of accounting for its fixed stock option plans and its performance stock option plan. Accordingly, no compensation cost has been recognized for these plans. Had the fair value method been used, reported basic and diluted earnings per common share would have been reduced by $0.01 and $0.02 per common share for the three and twelve months ended Dec. 31, 2002,respectively (2001 - $nil and $0.01 per common share, respectively). Effective Jan. 1, 2003, TransAlta has elected to account for stock-based compensation in accordance with the fair value method and will expense stock-based compensation in respect of stock options granted after that date.

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

The CICA has amended its standard on the recognition, measurement, and disclosure of the impairment of long-lived assets. This standard is effective April 1, 2003 and requires that an impairment loss be recognized when the carrying amount of a long-lived asset exceeds the sum of the undiscounted cash flows expected from its use and eventual disposition. The impairment loss is measured as the amount that the long-lived asset's carrying value exceeds its fair value. TransAlta early adopted this standard in the fourth quarter of 2002. In accordance with the standard, the impairment calculation for the Wabamun plant resulted in the recognition of an impairment charge of $110.0 million, which is included in asset impairment and equipment cancellation charges.

In the third quarter of 2002, in response to changes in accounting standards in the U.S. with respect to energy trading activities, the corporation has adopted a policy that all gains and losses on energy trading contracts be shown net in the statement of earnings. Consistent with these recommendations, the corporation has chosen to disclose the gross transaction volumes for those energy trading contracts that are physically settled.

DISCUSSION OF SEGMENTED RESULTS

GENERATION: Owns and operates hydro-, gas-, and coal-fired plants and related mining operations, with a total generating capacity of 7,516 MW.

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

Available capacity increased during the year as a result of the scrubber installation at Centralia (32 MW), an upgrade at Sundance unit six (42 MW), and the commissioning of the Big Hanaford plant (248 MW) offset by the decommissioning of Wabamun unit three (147 MW) in the fourth quarter. In connection with the construction of the Sarnia Regional Cogeneration plant, TransAlta purchased existing operational assets during the fourth quarter with a current generating capacity of 135 MW plus 55 MW of backup capacity for $30.2 million. Construction of an additional 440 MW is expected to be completed in the first quarter of 2003.

The results of the Generation segment are as follows:

                                    2002                  2001
3 months ended Dec. 31         Total    Per MWh      Total    Per MWh
---------------------------------------------------------------------
Revenues                    $  498.7   $  39.75   $  431.8   $  37.29
Fuel and purchased power      (226.9)    (18.09)    (246.4)    (21.28)
---------------------------------------------------------------------
Gross margin                   271.8      21.66      185.4      16.01
Operating expenses:
Operations, maintenance
 and administration            115.3       9.19       68.7       5.93
Depreciation and
 amortization                   57.4       4.58       41.4       3.58
Asset impairment and
 equipment cancellation
 charges                       152.5      12.16        2.7       0.23
Taxes, other than income
 taxes                           7.6       0.60        4.6       0.40
Prior period regulatory
 decision                          -          -      (11.0)     (0.95)
---------------------------------------------------------------------
EBIT before corporate
 allocations                   (61.0)     (4.87)      79.0       6.82
Corporate allocations          (18.1)     (1.44)     (23.6)     (2.04)
---------------------------------------------------------------------
EBIT                        $  (79.1)  $  (6.31)  $   55.4   $   4.78
---------------------------------------------------------------------
---------------------------------------------------------------------

                                    2002                  2001
Year ended Dec. 31             Total    Per MWh      Total    Per MWh
---------------------------------------------------------------------
Revenues                    $1,673.9   $  35.71   $2,158.4   $  48.90
Fuel and purchased power      (703.6)    (15.01)  (1,230.6)    (27.88)
---------------------------------------------------------------------
Gross margin                   970.3      20.70      927.8      21.02
Operating expenses:
Operations, maintenance
 and administration            346.3       7.39      290.6       6.58
Depreciation and
 amortization                  196.3       4.19      156.5       3.55
Asset impairment and
 equipment cancellation
 charges                       152.5       3.25      118.8       2.69
Taxes, other than income
 taxes                          27.3       0.58       18.7       0.42
Prior period regulatory
 decision                        3.3       0.07     (11.0)     (0.25)
---------------------------------------------------------------------
EBIT before corporate
 allocations                   244.6       5.22      354.2       8.03
Corporate allocations          (70.6)     (1.51)     (82.5)     (1.87)
---------------------------------------------------------------------
EBIT                        $  174.0   $   3.71   $  271.7   $   6.16
---------------------------------------------------------------------
---------------------------------------------------------------------

Generation's revenues are derived from the production of electricity, of which, on an annualized basis, approximately 90 per cent are based upon contracted prices, including capacity payments, and approximately 10 per cent are subject to market pricing. Revenues received under long-term contractual arrangements are not subject to major fluctuations in the spot price for electricity. In the fourth quarter of 2002, long-term contracts covered 91 per cent of production (2001 - 94 per cent) with the remaining nine per cent (2001 - six per cent) subject to market pricing. For the year ended Dec. 31, 2002, long-term contracts covered 90 per cent of total production (2001 - 92 per cent) with the remaining 10 per cent (2001 - eight per cent) subject to market pricing.

The existing contracts have remaining terms ranging from one to 22 years. Contracted production, as a percentage of existing production and forecasted production from assets currently under construction, over the next five years are as follows:

                       2003   2004   2005   2006   2007
-------------------------------------------------------
Contracted output        88%    87%    87%    86%    85%
-------------------------------------------------------
-------------------------------------------------------

Generation also derives revenue from the provision of ancillary services such as steam and system support. Revenues are subject to seasonal variations: during the summer months, warmer temperatures result in less efficient fuel conversion rates (higher heat rates), and increased hydro production from spring run-off results in lower electricity prices. A breakdown of revenues and average pricing applicable to each category is summarized in the following table:

3 months ended Dec. 31              2002                  2001
                             Revenue    Per MWh    Revenue    Per MWh
---------------------------------------------------------------------
Contract                    $  405.3  $   34.53   $  373.8  $   33.96
Merchant                        54.8      62.78       48.7      46.47
Ancillary services and
 other                          38.6          -        9.3          -
---------------------------------------------------------------------
                            $  498.7  $   39.75   $  431.8  $   37.29
---------------------------------------------------------------------
---------------------------------------------------------------------

Year ended Dec. 31                  2002                 2001
                             Revenue    Per MWh    Revenue    Per MWh
---------------------------------------------------------------------
Contract                    $1,448.2  $   33.26   $1,374.1  $   33.23
Merchant                       171.0      51.64      681.2     142.91
Ancillary services and
 other                          93.6          -      103.1          -
Wabamun arbitration
 decision                      (38.9)         -          -          -
---------------------------------------------------------------------
                            $1,673.9      35.71   $2,158.4  $   48.90
---------------------------------------------------------------------
---------------------------------------------------------------------


   A reconciliation between production, revenue and EBIT for the
fourth quarter and year ended Dec. 31, 2002 compared to the same
periods in 2001 is presented below:

                                      Production
                                            (GWh)   Revenue      EBIT
---------------------------------------------------------------------
3 months ended Dec. 31, 2001              11,579   $  431.8  $   55.4
Increased production                         868       32.4      23.5
New gas plants in service (Sarnia
 and Big Hanaford)                           388       39.9     (11.7)
Accelerated Alberta thermal
 plant maintenance                          (290)     (10.6)    (27.7)
Wabamun impairment and equipment
 cancellation charges                          -          -    (152.5)
Higher market prices                           -        5.3       5.3
Lower purchased power requirements             -          -      66.8
Increased operations, maintenance and
 administration expense                        -          -     (24.9)
Increased depreciation                         -          -     (11.2)
Wabamun unit four TSR settlement
 for 2000                                      -          -     (11.0)
Other                                          -       (0.1)      8.9
---------------------------------------------------------------------
3 months ended Dec. 31, 2002              12,545   $  498.7  $  (79.1)
---------------------------------------------------------------------
---------------------------------------------------------------------

                                      Production
                                            (GWh)   Revenue      EBIT
---------------------------------------------------------------------
Year ended Dec. 31, 2001                  44,136   $2,158.4  $  271.7
Net improved availability and
 production                                2,538       91.1      53.5
New gas plants in service (Sarnia
 and Big Hanaford)                           493       40.2     (13.1)
Accelerated Alberta thermal plant
 maintenance                                (290)     (10.6)    (27.7)
Wabamun impairment and equipment
 cancellation charges                          -          -    (152.5)
Lower market prices                            -     (441.9)   (441.9)
Lower purchased power requirements             -          -     562.8
Wabamun arbitration decision                   -      (38.9)    (38.9)
Impact of the Pierce Power plant
 monetization in 2001                          -     (121.8)     (3.0)
Increased operations, maintenance and
 administration expense                        -          -     (33.0)
Increased depreciation                         -          -     (34.6)
Lower fuel costs per megawatt hour             -          -      39.4
Wabamun unit four TSR settlement
 for 2000 and prior period
 regulatory decision                           -          -     (14.3)
Other                                          -       (2.6)      5.6
---------------------------------------------------------------------
Year ended Dec. 31, 2002                  46,877   $1,673.9  $  174.0
---------------------------------------------------------------------
---------------------------------------------------------------------

As discussed in significant one-time items, the corporation recognized an impairment charge of $110.0 million relating to the Wabamun plant, as the carrying value was determined to be in excess of fair value. TransAlta also cancelled the order for four natural gas turbines resulting in a $42.5 million contract termination charge. In September 2001, TransAlta monetized its investment in the 154 MW Pierce Power plant as a result of weak economic conditions. Revenue hedges were realized resulting in the recognition of revenue of $121.8 million, offset by an asset impairment charge of $66.5 million and a recognition of anticipated future operating costs of $52.3 million.

As a result of the corporation's forward view of the electricity market and its positive experience with improvements at the Centralia plant, the corporation accelerated its Alberta thermal plant maintenance schedule. This is being undertaken in order to improve reliability and increase availability when the economy turns around and electricity demand increases. This decision resulted in lower revenues and increased maintenance costs ($27.7 million pre-tax) in the fourth quarter of 2002.

As discussed in significant one-time items, the Wabamun arbitration decision resulted in a $38.9 million pre-tax payment that was recorded as a reduction of revenue in the second quarter of 2002.

As discussed in significant one-time items, the EUB rendered a negative decision of $3.3 million pre-tax with respect to TransAlta's hydro bidding strategy in 2000, which was recorded in 2002 as a prior period regulatory decision.

Availability for the fourth quarter of 2002 was 87.2 per cent compared to 89.9 per cent in 2001, reflecting decreased availability at the Alberta thermal plants due to the accelerated maintenance schedule and the unplanned Wabamun unit three outage discussed previously. Availability for the year ended Dec. 31, 2002 was 88.4 per cent compared to 86.9 per cent in 2001 as a result of improved operational performance at the thermal and gas plants, partially offset by the accelerated maintenance at the Alberta thermal plants and the Wabamun outage. At various times during 2002, when the market price of electricity was lower than the variable costs of production at certain plants, the corporation reduced production at these plants, and purchased electricity from the market to fulfill contractual obligations (economic dispatch). During these periods of economic dispatch, the affected plants were available to generate the electricity if required.

In the three months ended Dec. 31, 2002, production increased by 966 GWh compared to the same period in 2001 as a result of incremental production from the Sarnia and Big Hanaford plants and increased production from the Centralia plant, offset by lost production resulting from accelerated Alberta thermal plant maintenance. There was no economic dispatch in the fourth quarter of 2002. In the year ended Dec. 31, 2002, total production increased by 2,741 GWh compared to 2001. This increase was the result of the items discussed above and the return to service of Wabamun unit four as well as increased thermal production and availability, partially offset by 731 GWh decreased production resulting from economic dispatch decisions.

As shown in the above graphs, electricity spot prices in the fourth quarter of 2002 in both the Alberta and Pacific Northwest markets increased compared to the same period in 2001; however on an annual basis, electricity spot prices were lower in 2002 than in 2001. In the fourth quarter, spark spreads (power price less cost of gas consumed) increased in the Alberta market and decreased in the Pacific Northwest market. For the year ended Dec. 31, 2002, spark spreads decreased in both the Alberta and Pacific Northwest markets. Within these markets, prices were softer in 2002 due to reduced demand as a result of lower economic activity, increased hydro production and additional generating capacity added to these markets.

Generation's revenue for the fourth quarter of 2002 increased by $66.9 million ($2.46 per MWh) compared to the same period in 2001. The increase is due to higher production, higher ancillary services revenue, increased long-term contracted prices and higher electricity spot prices. The increase in contracted prices is due to higher gas prices, which are recovered under the terms of certain contracts. Revenue for the year ended Dec. 31, 2002 decreased by $484.5 million ($13.19 per MWh) compared to 2001. Adjusted for the Wabamun arbitration and Pierce Power decisions, revenue was $1,712.8 million ($36.54 per MWh) in 2002 compared to $2,036.6 million ($46.14 per MWh) in 2001. The decline in revenue in 2002 reflects lower electricity spot prices, partially offset by improved production and availability.

Fuel and purchased power decreased by $19.5 million ($3.19 per MWh) in the fourth quarter of 2002 and by $527.0 million ($12.87 per MWh) for the year ended Dec. 31, 2002. Purchased power is the cost incurred to acquire electricity from the market to fulfill contracted commitments during planned and unplanned outages. Any electricity not required to fulfill these commitments is sold back into the market at spot prices.

Purchased power declined significantly in the fourth quarter and the year ended Dec. 31, 2002 to $5.1 million and $32.1 million, respectively (2001 - $71.9 million and $594.9 million). The purchased power in the fourth quarter was the result of planned outages, while the majority of the purchased power requirement for the remainder of 2002 was due to the economic dispatch decisions discussed earlier. Due to high market power prices in the fourth quarter of 2002, no economic dispatch occurred in the quarter. In the fourth quarter of 2001, expected lower availability at the Centralia plant resulted in the purchase of 551 GWh of electricity, totalling $71.9 million. In the year ended Dec. 31, 2001, 2,707 GWh of electricity was purchased totalling $594.9 million. Pre-tax losses as a result of these purchases in the three and twelve months ended Dec. 31, 2001 were US$28.0 million (approximately Cdn$47 million) and US$77.7 million (approximately Cdn$124 million), respectively.

Fuel costs, excluding purchased power, consist primarily of coal and natural gas costs. Total fuel costs, excluding purchased power, were $221.8 million ($17.68 per MWh) in the fourth quarter of 2002 compared to $174.5 million ($15.07 per MWh) in 2001. For the year ended Dec. 31, 2002, coal and natural gas costs totalled $671.5 million ($14.32 per MWh) compared to $635.7 million ($14.40 per MWh) in 2001. TransAlta's average fuel costs per MWh are shown below:

                        3 Months ended Dec. 31     Year ended Dec. 31
                             2002         2001     2002          2001
---------------------------------------------------------------------
Coal                     $  12.40     $  13.91  $ 11.70      $  12.34
Gas                      $  40.51     $  21.87  $ 27.86      $  26.16
---------------------------------------------------------------------
Average fuel costs,
 excluding  purchased
 power                   $  17.68     $  15.07  $ 14.32      $  14.40
---------------------------------------------------------------------

TransAlta is subject to fluctuations in natural gas and coal costs, however the majority of the coal used in generation is from coal reserves owned by TransAlta. This allows the corporation to control the cost of coal. As a result of cost reduction programs, TransAlta reduced coal costs by 11 per cent in the fourth quarter of 2002 and five per cent for the year ended Dec. 31, 2002 compared to the same periods in 2001. The fourth quarter increase in fuel costs per MWh, excluding purchased power, is attributable to the 85 per cent increase in natural gas costs, partially offset by the decrease in coal costs. The increase in gas costs is due to higher natural gas market prices at the Big Hanaford plant and higher gas prices and heat rates at the Sarnia plant. For contracted plants, a portion of the gas costs have been hedged by the corporation, and in some cases, the corporation has hedged plants' spark spreads. In certain contracted plants the gas cost is a flow through to the customer and is not hedged by the corporation, therefore TransAlta is still subject to fluctuations in gas prices, but the increased gas costs are recovered through increased revenues. Gas costs for electricity to be sold in spot markets are matched to power sales and hedged accordingly. Fuel costs, excluding purchased power, on a per MWh basis, decreased for the year ended Dec. 31, 2002 as a result of the decrease in coal costs, partially offset by increased natural gas costs as discussed above.

In the fourth quarter of 2002, operations, maintenance and administration (OM&A) expenses increased by $46.6 million ($3.26 per MWh) over the same period in 2001. The increase represents the impact of the accelerated maintenance at the Alberta thermal plants, the commissioning of the Sarnia and Big Hanaford plants, increased business development costs, inventory obsolescence costs and increased project management costs related to plants under construction. For the year ended Dec. 31, 2002, OM&A increased by $55.7 million ($0.81 per MWh) from 2001. This reflects the impact of the items discussed above and increased insurance premiums partially offset by cost reduction initiatives.

Depreciation and amortization increased by $16.0 million ($1.00 per MWh) for the fourth quarter of 2002 and $39.8 million ($0.64 per MWh) for the year ended Dec. 31, 2002 compared to the same periods in 2001. The increase is the result of the addition of the Big Hanaford plant and increased capital projects at thermal plants.

The increase in taxes other than income taxes in the three and twelve months ended Dec. 31, 2002 relates to higher property tax assessments by local municipalities on the majority of the corporation's plants.

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

The results of Energy Marketing are as follows:

                         3 months ended Dec. 31    Year ended Dec. 31
                                 2002      2001       2002       2001
---------------------------------------------------------------------
Gross revenues                $ 992.4   $ 526.9  $ 3,703.8  $ 2,694.7
Trading purchases              (974.5)   (524.3)  (3,654.8)  (2,533.7)
---------------------------------------------------------------------
Net revenues                     17.9       2.6       49.0      161.0
Operations, maintenance
 and administration               3.6       1.6       15.1       36.2
Depreciation and amortization     0.5       4.0        2.5       11.0
Taxes, other than income
 taxes                              -         -        0.1          -
---------------------------------------------------------------------
EBIT before corporate
 allocations                     13.8      (3.0)      31.3      113.8
Corporate allocations            (2.3)     (1.9)      (8.3)      (6.6)
---------------------------------------------------------------------
EBIT                           $ 11.5    $ (4.9)    $ 23.0    $ 107.2
---------------------------------------------------------------------
---------------------------------------------------------------------

    Gross physical and financial settled sales transactions are as
follows:

                         3 months ended Dec. 31    Year ended Dec. 31
Electricity (GWh)                2002      2001       2002       2001
---------------------------------------------------------------------
Physical                       18,619    10,131     63,015     18,504
Financial                      13,167     4,990     40,061      9,115
---------------------------------------------------------------------
                               31,786    15,121    103,076     27,619
---------------------------------------------------------------------
---------------------------------------------------------------------

                         3 months ended Dec. 31    Year ended Dec. 31
Gas (million GJ)                 2002      2001       2002       2001
---------------------------------------------------------------------
Physical                         26.5      12.2       96.2       30.6
Financial                        19.4      24.3       63.6       68.7
---------------------------------------------------------------------
                                 45.9      36.5      159.8       99.3
---------------------------------------------------------------------
---------------------------------------------------------------------

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

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

Gross trading sales volumes during the fourth quarter of 2002 increased by 16,665 GWh of electricity and by 9.4 million gigajoules (GJ) of gas compared to 2001. In the year ended Dec. 31, 2002, trading volumes increased by 75,457 GWh of electricity and 60.5 million GJ of gas compared to 2001. Liquidity in the medium- to long-term markets remained low and as a result, Energy Marketing continued to have a low level of activity in these markets. Coincidently, activity levels in the short-term market increased. As expected, increased market liquidity and pricing efficiencies resulted in margins on individual trades being reduced. TransAlta's trading activity comprised mainly short-term transactions, the majority of which were settled within ninety days thereby limiting risk and maintaining low working capital requirements. Value at risk levels throughout 2002 were consistent with 2001 levels. The increase in gas trading volumes relates to the settlement of trading positions offset in early 2002 when the gas trading book was closed. In addition, the trading of heat rate swaps, which include a gas element and are therefore presented as settled gas transactions, increased in 2002.

Gross sales increased by $465.5 million in the three months ended Dec. 31 and increased by $1,009.1 million for the year ended Dec. 31, 2002 compared to 2001. Increased electricity trading volumes in 2002 more than offset lower market prices and the reduced gas trading activities in the first and second quarters of 2002.

Net revenues increased by $15.3 million for the fourth quarter of 2002 as a result of increased trading activity and higher percentage margins. Net revenues decreased by $112.0 million for the year ended Dec. 31, 2002 due to significantly lower market prices and margins compared to 2001, particularly in the Pacific Northwest. The 2001 Pacific Northwest prices were influenced by the process of deregulation in California, exacerbated by a drought in the Pacific Northwest and historically high natural gas prices.

In the fourth quarter of 2002, OM&A expense increased by $2.0 million due primarily to higher incentive compensation recognized during the quarter. Incentive compensation is based on net revenues which increased in the quarter, as discussed above. OM&A decreased by $21.1 million for the year ended Dec. 31, 2002 due to lower annual incentive compensation resulting from lower annual net revenue and one-time costs associated with the acquisition of the remaining 50 per cent of Merchant Energy Group of the Americas, Inc. (MEGA) in June 2001.

Depreciation and amortization decreased by $3.5 million in the fourth quarter of 2002 and by $8.5 million for the year ended Dec. 31, 2002. The decrease is due to $29.3 million of goodwill arising from the acquisition of MEGA, previously recorded as acquired intangibles, which is no longer being amortized. This treatment is in accordance with the new accounting standard issued by the CICA. There was no impairment of goodwill upon adoption of the standard on Jan. 1, 2002, nor was there an impairment at Dec. 31, 2002.

Energy Marketing's price risk management assets and liabilities represent the fair value of unsettled (unrealized) trading transactions. With the exception of transmission contracts, the fair value of all energy trading activities is based on quoted market prices. The fair value of physical transmission contracts is based on quoted market prices and a spread option valuation model. The fair value of financial transmission contracts is based upon statistical analysis of historical data.

The following table illustrates movements in the fair value of the corporation's price risk management assets (liabilities) during the twelve months ended Dec. 31, 2002:

---------------------------------------------------------------------
Fair value of net price risk management assets
 outstanding at Dec. 31, 2001                                  $ 25.8
Fair value of new contracts entered into during
 the period                                                      (2.7)
Changes in fair values attributable to market price
 and other market changes                                         7.6
Contracts realized or settled during the period                 (36.6)
Changes in fair values attributable to changes in
 valuation techniques and assumptions                               -
---------------------------------------------------------------------
Fair value of net price risk management liabilities
 outstanding at Dec. 31, 2002                                  $ (5.9)
---------------------------------------------------------------------
---------------------------------------------------------------------


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

                                                              2008 and
                   2003   2004   2005   2006   2007 thereafter Total
--------------------------------------------------------------------
Prices actively
 quoted         $ (17.6) $ 3.3  $ 3.2  $ 2.1  $ 1.5     $ -    $(7.5)

Prices based
 on models          1.6      -      -      -      -       -      1.6
--------------------------------------------------------------------
Asset
 (liability)    $ (16.0) $ 3.3  $ 3.2  $ 2.1  $ 1.5     $ -    $(5.9)
--------------------------------------------------------------------
--------------------------------------------------------------------

In 2002, TransAlta responded to a number of inquiries from various U.S. State and Federal bodies regarding trading activities in California and states in the Pacific Northwest during 2000 and 2001. TransAlta believes it operated in accordance with all applicable laws, rules, regulations and tariffs. No significant developments have occurred on these issues as a result of TransAlta's responses.

In the fourth quarter of 2002, two class action lawsuits on behalf of all persons and businesses in the states of Oregon and Washington were initiated in respect of alleged unlawful practices in the purchase and sale of wholesale energy. TransAlta believes these are without merit and will vigorously defend its actions.

In 2000, TransAlta made a provision of US$28.8 million against US$58.0 million owing from the California Independent System Operator and the California Power Exchange. During 2001, US$5.0 million was collected. No change has been made to the provision due to the continuing uncertainty in California. The amount has been reclassified to long-term, as collection is no longer expected in 2003, although ultimate collection is still expected. On Dec. 12, 2002, a U.S. Federal Energy Regulatory Commission (FERC) Administrative Law Judge proposed that TransAlta receive approximately US$44.0 million, however FERC has indicated that further adjustments in respect of power and gas prices may occur, which could result in further alterations of the amount TransAlta is to receive. As a result, TransAlta has not adjusted the amount receivable or the provision.

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

                      3 months ended Dec. 31       Year ended Dec. 31
                            2002        2001         2002        2001
----------------------------------------------------------------------
Gross interest expense    $ 46.7      $ 42.4      $ 172.9     $ 170.3
Interest income             (1.7)       (8.7)        (8.7)      (24.2)
Interest allocated to
 discontinued operations       -        (0.6)        (2.4)       (9.7)
Capitalized interest       (21.0)      (20.7)       (79.1)      (48.3)
----------------------------------------------------------------------
Net interest expense        24.0        12.4         82.7        88.1
Other income                (1.0)       (1.2)        (0.1)       (1.5)
Foreign exchange gain       (0.9)       (2.9)        (1.2)       (0.8)
Non-controlling interests    5.6         5.0         20.1        20.6
Preferred securities
 distributions, net of tax   4.7         3.5         20.9        13.1
----------------------------------------------------------------------
                          $ 32.4      $ 16.8      $ 122.4     $ 119.5
----------------------------------------------------------------------
----------------------------------------------------------------------

On June 20, 2002, the corporation issued US$300.0 million of senior notes under a US$1.0 billion shelf prospectus filed May 14, 2002. The proceeds of the issuance were used to repay short-term debt and U.S. denominated commercial paper. The notes are unsecured and bear interest at 6.75 per cent and mature on July 15, 2012.

Net interest expense increased by $11.6 million in the three months ended Dec. 31, 2002 compared to the same period of 2001. The increase was primarily due to a higher proportion of debt subject to long-term interest rates and lower interest income due to the receipt of the $180.3 million receivable from Aquila Networks Canada (formerly UtiliCorp Networks Canada) that arose from the sale of the Alberta Distribution and Retail (D&R) operation. Net interest expense decreased by $5.4 million for the year ended Dec. 31, 2002 as a result of an overall decline in average debt levels and higher capitalized interest, offset by a higher proportion of debt subject to long-term interest rates and receipt of the interest-bearing receivable from Aquila Networks Canada.

The increase in earnings attributable to non-controlling interests in the fourth quarter of 2002 compared to 2001 is attributable to increased quarterly earnings relating to the 49.99 per cent non-controlling interest in TransAlta Cogeneration, L.P. The decrease for the year ended Dec. 31, 2002 compared to 2001 is the result of the redemption of the preferred shares of TransAlta Utilities Corporation for $121.6 million in September 2001, resulting in lower subsidiary preferred share dividends, offset by higher earnings from TransAlta Cogeneration, L.P.

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

INCOME TAXES

                            3 months ended Dec. 31 Year ended Dec. 31
                            2002          2001     2002          2001
---------------------------------------------------------------------
Income tax expense
 (recovery)            $   (35.1)     $    0.5  $  18.1      $   89.9
Effective tax rate          39.4%          1.2%    15.6%         30.7%
---------------------------------------------------------------------

An income tax recovery of $35.1 million was recorded for the three months ended Dec. 31, 2002, compared to income tax expense of $0.5 million for the same period in 2001. The recovery reflects the loss incurred in the current quarter. Income taxes decreased by $71.8 million for the year ended Dec. 31, 2002 due to lower earnings and the impact of the Wabamun decommissioning and the turbine cancellation charges, which were recognized at the marginal rate. The decrease also reflects the benefit of previously unrecognized tax losses that were recognized in the third quarter of 2002 as it became more likely than not that they would be utilized. The effective income tax rate, expressed as a percentage of earnings from continuing operations before income taxes and non-controlling interests, decreased to 15.6 per cent in 2002 from 30.7 per cent in 2001. The effective tax rate in 2002 reflects the impact of the issues discussed above. Due to lower earnings in the three months ended Dec. 31, 2001, the 1.2 per cent effective rate reflects the impact of the financing arrangements of TransAlta's foreign operations. The benefits of these arrangements do not vary with earnings.

DISCONTINUED OPERATIONS

                            3 months ended Dec. 31 Year ended Dec. 31
                            2002          2001     2002          2001
---------------------------------------------------------------------
Transmission operation   $     -      $   13.3  $  12.8      $   44.4
Gain on disposal of
 Transmission operation     10.0             -    120.0             -
Edmonton Composter
 operation                     -             -        -           0.7
---------------------------------------------------------------------
                         $  10.0      $   13.3  $ 132.8      $   45.1
---------------------------------------------------------------------
---------------------------------------------------------------------

As discussed in significant one-time items, TransAlta sold its Transmission operation in April 2002 for proceeds of $820.7 million. The disposal resulted in an after-tax gain on sale of $120.0 million ($0.71 per common share).

On June 29, 2001, TransAlta sold its Edmonton Composter for proceeds of $97.0 million, which approximated its book value.

FINANCIAL POSITION

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

                             Increase/
                            (Decrease)           Explanation
---------------------------------------------------------------------
Cash                                   and cash equivalents $ 81.3
                                       Refer to Consolidated
                                       Statements of Cash Flows.

Accounts receivable and
 other                       (156.9)   Decrease primarily due to
                                       collection of receivable
                                       related to monetized Pierce
                                       Power hedges ($82.0 million),
                                       reclassification of California
                                       receivables to long-term
                                       (US$24.2 million) and the sale
                                       of the Transmission business
                                       ($31.7 million).

Materials and supplies, at
 average cost                  27.2    Higher coal inventory balances
                                       as a result of second and third
                                       quarter economic dispatch
                                       decisions, increased coal
                                       production and advanced
                                       maintenance at the Alberta
                                       thermal plants.

Long-term receivables        (181.5)   Receipt of amount due from
                                       Aquila (formerly UtiliCorp)
                                       relating to the sale of the
                                       discontinued D&R operation
                                       ($180.3 million) and reclass
                                       of sulphur tax abatement
                                       ($45.0 million) to current
                                       receivables, offset by
                                       reclassification of California
                                       receivables to long-term
                                       (US$24.2 million).

Property, plant and
 equipment, net of
 accumulated depreciation     (59.7)   Capital expenditures and
                                       construction activity during
                                       the period and acquisition of
                                       Vision Quest, more than offset
                                       by depreciation, the sale of
                                       the Transmission business, the
                                       impairment charge relating to
                                       the decommissioning of the
                                       Wabamun plant and equipment
                                       cancellation charges.

Goodwill                       27.2    Acquisition of Vision Quest
                                       in December 2002.

Future income tax assets       56.6    2001 U.S. operating losses
                                       that will be recovered in
                                       future years.

Other assets                   29.5    Long-term prepayments
                                       related to the Sarnia plant
                                       and financing costs related
                                       to US$300.0 million debt
                                       issuance and financing costs
                                       related to the Mexican
                                       projects.

Short-term debt              (247.2)   Repayment with a portion of
                                       the proceeds from US$300.0
                                       million debt issuance and
                                       proceeds from disposal of
                                       the Transmission operation.

Accounts payable and
 accrued liabilities         (155.3)   Decrease due to lower
                                       capital expenditures in the
                                       quarter.

Price risk management
 liabilities (current and
 long-term)                    41.3    Decrease in margins on
                                       energy trading activities.

Long-term debt (including
 current portion)             195.5    US$300.0 million debt issuance,
                                       offset by maturity of
                                       debentures of $100 million and
                                       net decrease in long-term
                                       commercial paper repaid with
                                       proceeds on disposal of the
                                       Transmission business.

Non-controlling interests     (18.0)   Acquisition of remaining
                                       interest in Southern Cross
                                       Energy ($7.2 million) and
                                       decreased non-controlling
                                       interest in TransAlta
                                       Cogeneration, L.P. as a
                                       result of distributions
                                       in excess of net income.

Shareholders' equity           49.9    Net earnings and issuance
                                       of common shares for Vision
                                       Quest acquisition, partially
                                       offset by dividends and net
                                       redemption of common shares.
---------------------------------------------------------------------


STATEMENTS OF CASH FLOWS:


3 months ended Dec. 31        2002     2001         Explanation
---------------------------------------------------------------------
Cash and cash equivalents,
 beginning of period       $ 120.6 $   61.5
Provided by (used in):
Operating activities         189.5    131.7  Lower cash operating
                                             earnings offset by
                                             decreased working capital
                                             requirements due to
                                             collection of income
                                             taxes receivable related
                                             to U.S. operations in
                                             2001.

Investing activities        (261.0)  (366.1) In 2002, capital
                                             expenditures of $194.6
                                             million relating
                                             primarily to construction
                                             of Sarnia and the Mexico
                                             plants, acquisition of
                                             Vision Quest for $41.1
                                             million (less cash
                                             acquired of $8.2 million)
                                             and acquisition of
                                             remaining interest in
                                             Southern Cross Energy
                                            (SCE) for $7.2 million.

                                             In 2001, capital
                                             expenditures also
                                             included the installation
                                             of the scrubber at the
                                             Centralia plant and
                                             construction of the Big
                                             Hanaford plant.

Financing activities          96.7    230.9  In 2002, net increase in
                                             short-term debt, offset
                                             by $100.0 million
                                             debenture maturity, net
                                             repayment of commercial
                                             paper and cash dividends
                                             of $29.5 million.

                                             In 2001, debt issuances of
                                            $125.0 million and $169.4
                                             million proceeds on
                                             issuance of preferred
                                             securities offset by
                                             dividends of $28.7
                                             million and redemption of
                                             common shares of $14.2
                                             million.
Translation of foreign
 currency cash                (2.5)     4.0
----------------------------------------------------------------------
Cash and cash equivalents,
 end of period             $ 143.3 $   62.0
----------------------------------------------------------------------
----------------------------------------------------------------------


Year ended Dec. 31            2002     2001          Explanation
----------------------------------------------------------------------
Cash and cash equivalents,
 beginning of period       $  62.0 $   53.8
Provided by (used in):
Operating activities         437.7    715.6  Lower cash operating
                                             earnings as a result of
                                             the impact of the Wabamun
                                             arbitration and prior
                                             period regulatory
                                             decisions, offset by
                                             increased working capital
                                             requirements due to the
                                             timing of the ancillary
                                             revenue settlement ($49.9
                                             million), timing of
                                             accounts receivable
                                             relating to the Alberta
                                             Power Pool for Generation
                                             due to deregulation on
                                             Jan. 1, 2001 ($170.0
                                             million), and the final
                                             instalment of 2001
                                             income taxes paid in the
                                             first quarter of 2002
                                             ($109.0 million).

Investing activities         (36.2)(1,076.9) In 2002, proceeds on the
                                             disposal of the
                                             Transmission operation
                                             and collection of
                                             amounts receivable from
                                             Aquila (formerly
                                             UtiliCorp) related to the
                                             sale of the discontinued
                                             Alberta D&R operation in
                                             2000, offset by capital
                                             expenditures relating to
                                             the construction of the
                                             Sarnia, Big Hanaford,
                                             Campeche and Chihuahua
                                             plants, the acquisition of
                                             Vision Quest and the
                                             remaining portion of SCE
                                             as well as the
                                             installation of the
                                             scrubber at the Centralia
                                             plant during the second
                                             quarter.

                                             In 2001, capital
                                             expenditures relating
                                             primarily to the
                                             installation of the
                                             scrubber at the Centralia
                                             plant and construction of
                                             the Sarnia, Big Hanaford
                                             and Campeche plants were
                                             offset by proceeds on the
                                             disposal of the Edmonton
                                             Composter, Mildred Lake,
                                             Fort Nelson and Fort
                                             Saskatchewan plants.

Financing activities        (320.9)   368.7  In 2002, the issuance of
                                             US$300.0 million in
                                             long-term notes offset by
                                             the repayment of short-
                                             and long-term debt,
                                             payment of common share
                                             and preferred securities
                                             distributions, and
                                             repurchase of common
                                             shares.

                                             In 2001, net long-term
                                             borrowings offset by
                                             redemption of preferred
                                             shares of a subsidiary,
                                             common and preferred
                                             share dividends and
                                             repurchase of common
                                             shares.

Translation of foreign
 currency cash                 0.7      0.8
---------------------------------------------------------------------
Cash and cash equivalents,
 end of period             $ 143.3 $   62.0
---------------------------------------------------------------------

OUTLOOK

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

Generating capacity in 2003 will be higher than in 2002 due to the addition of the 575 MW Sarnia plant, which will commence commercial operations in the first quarter of 2003. 55 MW of added capacity at Sarnia is forecasted for 2005. The acquisition of Vision Quest in December 2002 added 44 MW of capacity with a further 37.5 MW scheduled to commence commercial operations in the second quarter of 2003. The 252 MW Campeche and 259 MW Chihuahua plants in Mexico are scheduled to commence commercial operations in the first and third quarters of 2003, respectively. These increases will be partially offset by the shutdown in November 2002 of unit three at the Wabamun facility (147 MW). Availability for 2003 is expected to be similar to 2002, however production is expected to be higher than in 2002 due to the increased capacity.

Electricity spot prices in 2003 are expected to be similar to those in 2002 for the Alberta market and higher in the Pacific Northwest. However, spark spreads (the difference between electricity prices and cost of gas consumed) are expected to compress due to the proportionately higher increase in the cost of natural gas. Expected electricity demand compared to levels of supply is expected to prevent prices from materially increasing over the medium term.

Legislation was passed in Ontario in late 2002 capping retail market prices at $43 per MWh. However, wholesale market prices have not been directly impacted by this decision. Some of the legislation has not yet been clarified and as a result, revenues for merchant capacity at the Sarnia plant may be affected.

Exposure to volatility in electricity prices is substantially mitigated through firm price long-term electricity sales contracts. Exposure to volatility in gas prices is substantially mitigated by the flow-through of the costs of natural gas to customers in some of these contracts and the existence of price caps in certain natural gas supply contracts. For 2003, approximately 88 per cent of output will be contracted, a significant portion of which relates to the Alberta PPAs which are capacity related based on achieving agreed availability rates. The corporation will continue to focus on the maximization of revenues from these contracts. For non-contracted sales, the historic correlation between natural gas and electricity prices is expected to weaken in 2003, resulting in a compression of spark spreads for non-contracted plants compared to 2002.

TransAlta is continuing its focus on reducing coal costs and ongoing operating (OM&A) expenses. The areas for reductions were identified in the fourth quarter of 2001 and have been, and continue to be, implemented. The benefits of these initiatives are beginning to be realized, and are expected to become fully apparent in 2003 and beyond. However, it is expected there will be more planned maintenance in the Alberta thermal plants in 2003 than in 2002.

Energy Marketing anticipates that short-term markets will continue to be active. Liquidity in the medium- and longer-term markets continues to be low, however there is a need for the types of products offered in these markets and the corporation hopes that additional creditworthy counterparties will begin to emerge and thereby increase liquidity. The financial performance of Energy Marketing activities is expected to be similar to that achieved in 2002.

In 2003, capital expenditures will be approximately $830 million, of which approximately $275 million will be spent on the Genesee Phase three project, described below, approximately $170 million will be spent to complete the two Mexican plants, $60 million on other growth projects and approximately $325 million on maintenance and productivity expenditures as a result of the planned outages and preventative maintenance. Included in the maintenance and productivity expenditures is $25 million in respect of CE Generation LLC (CE Gen), described below. Financing for these expenditures is expected to come from a combination of cash flow from operations, monetization of selected assets, issuance of common shares and the issuance of debt. TransAlta has access to a wide variety of sources of capital including: a $1.5 billion medium-term note program; a US$1.0 billion shelf-prospectus; a $1.0 billion commercial paper program; and approximately $2.0 billion of bank credit facilities.

On Jan. 24, 2003 the corporation announced the acquisition of 50 per cent of the membership interests in CE Generation LLC (CE Gen) for US$205.0 million (approximately Cdn$312 million) plus approximately US$35.0 million of working capital (approximately Cdn$53 million) and the assumption of non-recourse debt of approximately US$500.0 million (approximately Cdn$762 million). MidAmerican Energy Holdings Company is the other 50 per cent member of CE Gen. CE Gen, through its subsidiaries, is primarily engaged in the development, ownership and operation of independent power production facilities in the United States utilizing geothermal and natural gas resources. CE Gen has 13 facilities with an aggregate operating capacity of 820 MW. The transaction closed on Jan. 29, 2003.

On Jan. 13, 2003, TransAlta and EPCOR Utilities Inc. (EPCOR) announced an agreement for TransAlta to acquire a 50 per cent interest in EPCOR's Genesee Phase three project for $395.0 million. On the same date, TransAlta paid EPCOR $157.0 million for TransAlta's share of project costs incurred to date. The 450 MW addition to the existing Genesee Generating Station is currently under construction southwest of Edmonton, Alberta. The two corporations will own and share costs for Genesee Phase 3 equally. EPCOR will continue to manage the project's construction and will operate the plant upon commercial operation in early 2005. Both parties will independently dispatch and market their share of the electrical output from the unit through the Alberta Power Pool. Included in the arrangement is an option for EPCOR to purchase a 50 per cent interest in TransAlta's Centennial one project described below. The option expires Dec. 31, 2005. EPCOR also has the option to purchase a 50 per cent interest in TransAlta's Sarnia plant, which may be exercised between January 2003 and March 2004.

In February 2002, the EUB approved the previously announced Centennial project, which is a 900 MW merchant expansion at the Keephills site. Phase one of the project is now part of the arrangement with EPCOR and the two corporations will jointly proceed with the development phase of the project. The decision to construct phase one will be made in sufficient time to ensure that the plant is operational when market conditions are appropriate. EPCOR has an option to participate in the construction and ownership of the project.

TransAlta will continue to focus on exploring strategic acquisitions and additional greenfield opportunities. Growth will only be undertaken to the extent that it is affordable and supported by the balance sheet.

On Dec. 16, 2002, the Canadian government ratified the Kyoto Protocol. The Kyoto Protocol will have no impact on TransAlta's U.S., Mexican or Australian operations as these countries have not ratified the Protocol. TransAlta is not able to estimate the full impact the Protocol will have on its Canadian operations, as the Canadian government has not yet established an implementation plan. However, the PPAs for TransAlta's coal-fired plants in Alberta contain 'Change in Law' provisions that provide an opportunity to recover compliance costs from the PPA customers. As a member of the Canadian Clean Power Coalition, TransAlta, along with its peers, is exploring other means to reduce greenhouse gas emissions, including the purchase of offset credits. The acquisition of Vision Quest and its prospects for further developments has resulted in the additional amounts of zero-emissions facilities consistent with the strategy of the corporation. Since 1990 the corporation has reduced net emissions by 18 per cent and is on track to reach zero net emissions by 2024.

TRANSALTA CORPORATION
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS
(in millions of Canadian dollars except per share amounts)

                          3 months ended Dec. 31  Year ended Dec. 31
                                    Unaudited    Unaudited  Audited(a)
                                  2002      2001      2002      2001
--------------------------------------------------------------------
Revenues                      $  517.6   $ 434.4 $ 1,723.9 $ 2,319.4
Fuel and purchased power        (226.9)   (246.4)   (703.6) (1,230.6)
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Gross margin                     290.7     188.0   1,020.3   1,088.8
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Operating expenses
Operations, maintenance and
 administration                  135.1      89.4     420.5     392.2
Depreciation and
 amortization                     62.5      51.8     219.0     191.2
Asset impairment and
 equipment cancellation
 charges (Note 6)                152.5       2.7     152.5     118.8
Taxes, other than income
 taxes                             7.6       4.6      27.4      18.7
--------------------------------------------------------------------
                                 357.7     148.5     819.4     720.9
--------------------------------------------------------------------
Operating income (loss)          (67.0)     39.5     200.9     367.9
Other income                       1.0       1.2       0.1       1.5
Foreign exchange gain              0.9       2.9       1.2       0.8
Net interest expense             (24.0)    (12.4)    (82.7)    (88.1)
--------------------------------------------------------------------
Earnings (loss) from
 continuing operations
 before regulatory
 decisions, income taxes and
 non-controlling interests       (89.1)     31.2     119.5     282.1
Prior period regulatory
 decisions (Note 10)                 -      11.0      (3.3)     11.0
--------------------------------------------------------------------
Earnings (loss) from
 continuing operations
 before income taxes
 and non-controlling
 interests                       (89.1)     42.2     116.2     293.1
Income tax expense
 (recovery)                      (35.1)      0.5      18.1      89.9
Non-controlling interests          5.6       5.0      20.1      20.6
--------------------------------------------------------------------
Earnings (loss) from
 continuing operations           (59.6)     36.7      78.0     182.6
Earnings from discontinued
 operations (Note 3)                 -      13.3      12.8      45.1
Gain on disposal of
 discontinued operations
 (Note 3)                         10.0         -     120.0         -
--------------------------------------------------------------------
Net earnings (loss)              (49.6)     50.0     210.8     227.7
Preferred securities
 distributions, net of tax         4.7       3.5      20.9      13.1
--------------------------------------------------------------------
Net earnings (loss)
 applicable to common
 shareholders                 $  (54.3)  $  46.5 $   189.9 $   214.6
Common share dividends           (42.3)    (41.7)   (169.0)   (168.4)
Adjustment arising from
 normal course issuer bid            -     (14.1)    (27.0)    (34.8)
Retained earnings
Opening balance                  928.8     847.6     838.3     826.9
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Closing balance               $  832.2   $ 838.3 $   832.2 $   838.3
--------------------------------------------------------------------
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Weighted average common
 shares outstanding in the
 period                          169.3     168.9     169.6     168.9
--------------------------------------------------------------------

Basic earnings (loss) per
 share
Continuing operations         $  (0.38)   $ 0.19 $    0.34 $    1.00
Earnings from discontinued
 operations                          -      0.08      0.07      0.27
--------------------------------------------------------------------
Net earnings (loss) from
 operations                      (0.38)     0.27      0.41      1.27
Gain on disposal of
 discontinued operations,
 net of tax                       0.06         -      0.71         -
--------------------------------------------------------------------
Net earnings (loss)           $  (0.32)   $ 0.27 $    1.12 $    1.27
--------------------------------------------------------------------
--------------------------------------------------------------------
Diluted earnings (loss) per
 share
Earnings (loss) from
 continuing operations        $  (0.38)   $ 0.19 $    0.34 $    0.98
Earnings from discontinued
 operations                          -      0.08      0.07      0.27
--------------------------------------------------------------------
Net earnings (loss) from
 operations                      (0.38)     0.27      0.41      1.25
Gain on disposal of
 discontinued operations,
 net of tax                       0.06         -      0.71         -
--------------------------------------------------------------------
Net earnings (loss)           $  (0.32)   $ 0.27 $    1.12 $    1.25
--------------------------------------------------------------------
--------------------------------------------------------------------

    See accompanying notes.

    (a) Derived from the audited Dec. 31, 2001 consolidated financial
statements.


TRANSALTA CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions of Canadian dollars)

                          3 months ended Dec. 31  Year ended Dec. 31
                                    Unaudited    Unaudited  Audited(a)
                                 2002       2001      2002      2001
--------------------------------------------------------------------
Operating activities
Net earnings                  $ (49.6)    $ 50.0   $ 210.8   $ 227.7
Depreciation and
 amortization                    79.7       82.6     314.8     312.3
Asset impairment and
 equipment cancellation
 charges                        152.5          -     152.5      66.5
Non-controlling interests         5.6        5.0      20.1      20.6
Loss (gain) on sale of
 property, plant and
 equipment                       12.3        2.1      15.6      (5.4)
Site restoration costs
 incurred                        (3.5)      (4.6)    (15.6)    (14.8)
Future income taxes
 (recovery)                     (43.8)      33.2     (60.4)     39.9
Unrealized (gain) loss from
 energy marketing activities    (10.9)       6.0      (5.9)     (6.3)
Gain on disposal of
 Transmission
 operation (Note 3)            (10.0)         -    (120.0)        -
Other non-cash items            (17.2)      (0.7)    (24.8)      9.5
--------------------------------------------------------------------
                                115.1      173.6     487.1     650.0
Change in non-cash
 operating working capital
 balances                        74.4      (41.9)    (49.4)     65.6
--------------------------------------------------------------------
Cash flow from operating
 activities                     189.5      131.7     437.7     715.6
--------------------------------------------------------------------
Investing activities
Additions to property,
 plant and equipment           (194.6)    (419.0)   (945.8) (1,246.5)
Acquisitions (Note 2)           (40.1)         -     (40.1)     (9.8)
Proceeds on sale of
 property, plant and
 equipment to Limited
 Partnership                        -       35.0         -      35.0
Disposals (Note 3)                  -          -     818.0         -
Proceeds on sale of
 property, plant and
 equipment                        2.3        0.2       2.3     201.6
Long-term receivables            (5.4)      20.3     165.3     (46.3)
Long-term investments (Note 5)      -          -      (6.1)        -
Deferred charges and other      (23.2)      (2.6)    (29.8)    (10.9)
--------------------------------------------------------------------
Cash flow used in investing
 activities                    (261.0)    (366.1)    (36.2) (1,076.9)
--------------------------------------------------------------------
Financing activities
Net increase (decrease) in
 short-term debt                289.3       (7.8)   (247.1)     61.9
Issuance of long-term debt          -      125.0     611.3     789.9
Repayment of long-term debt    (149.4)      (0.8)   (454.5)   (292.7)
Redemption of preferred
 shares of a subsidiary             -          -         -    (122.1)
Issuance of common shares           -        0.1       1.8      14.1
Redemption of common shares         -      (14.2)    (49.9)    (44.4)
Distributions on preferred
 securities                      (8.2)      (6.2)    (34.9)    (23.4)
Dividends on common shares      (29.5)     (28.7)   (115.5)   (149.6)
Net proceeds on issuance of
 preferred securities               -      169.4         -     169.4
Dividends to subsidiary's
 non-controlling preferred
 shareholders                       -          -         -      (8.3)
Distributions to
 subsidiary's
 non-controlling limited
 partner                         (5.5)      (6.0)    (24.5)    (26.3)
Deferred financing charges
 and other                          -        0.1      (7.6)      0.2
--------------------------------------------------------------------
Cash flow from (used in)
 financing activities            96.7      230.9    (320.9)    368.7
--------------------------------------------------------------------
Cash flow from (used in)
 operating, investing and
 financing activities            25.2       (3.5)     80.6       7.4
Effect of translation on
 foreign currency cash           (2.5)       4.0       0.7       0.8
--------------------------------------------------------------------
Increase in cash and cash
 equivalents                     22.7        0.5      81.3       8.2
Cash and cash equivalents,
 beginning of period            120.6       61.5      62.0      53.8
--------------------------------------------------------------------
Cash and cash equivalents,
 end of period                $ 143.3    $  62.0   $ 143.3    $ 62.0
--------------------------------------------------------------------
--------------------------------------------------------------------

    See accompanying notes.

    (a) Derived from the audited Dec. 31, 2001 consolidated financial
statements.

TRANSALTA CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions of Canadian dollars)        Dec. 31             Dec. 31
                                            2002                2001
                                       Unaudited            Audited(a)
--------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents                $ 143.3              $ 62.0
Accounts receivable and
 other                                     468.4               625.3
Price risk management
 assets (Note 4)                           157.8               137.6
Future income tax assets                    18.7                16.9
Income taxes receivable                    111.5               128.3
Materials and supplies at
 average cost                              112.7                85.5
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                                         1,012.4             1,055.6
--------------------------------------------------------------------
Investments (Note 5)                        32.2                37.3
Long-term receivables (Note 7)              39.9               221.4
Property, plant and
 equipment (Note 3)
Cost                                     8,124.9             8,766.7
Accumulated depreciation                (2,089.8)           (2,671.9)
--------------------------------------------------------------------
                                         6,035.1             6,094.8
Goodwill (Note 2)                           56.5                29.3
Future income tax assets                    72.2                15.6
Price risk management
 assets (Note 4)                            60.7                71.3
Other assets                               110.6                81.1
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Total assets                           $ 7,419.6           $ 7,606.4
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--------------------------------------------------------------------


LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt                        $   290.0           $   537.2
Accounts payable and
 accrued liabilities                       472.2               627.5
Price risk management
 liabilities (Note 4)                      173.8               114.1
Future income tax
 liabilities                                17.1                11.8
Dividends payable                           42.9                42.8
Current portion of
 long-term debt (Note 8)                   355.4               104.3
--------------------------------------------------------------------
                                         1,351.4             1,437.7
--------------------------------------------------------------------
Long-term debt (Note 8)                  2,351.2             2,406.8
Deferred credits and other
 long-term liabilities                     540.2               560.5
Future income tax
 liabilities                               371.9               409.1
Price risk management
 liabilities (Note 4)                       50.6                69.0
Non-controlling interests                  263.0               281.0

Preferred securities                       451.7               452.6
Common shareholders' equity
Common shares (Note 9)                   1,226.2             1,170.9
Retained earnings                          832.2               838.3
Cumulative translation
 adjustment                                (18.8)              (19.5)
--------------------------------------------------------------------
                                         2,039.6             1,989.7
--------------------------------------------------------------------
Total liabilities and
 shareholders' equity                  $ 7,419.6           $ 7,606.4
--------------------------------------------------------------------
--------------------------------------------------------------------

    Contingencies (Note 11)

    See accompanying notes.

    (a) Derived from the audited Dec. 31, 2001 consolidated financial
statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

1. ACCOUNTING POLICIES

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

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

Effective Jan. 1, 2002, the corporation prospectively adopted the new Canadian Institute of Chartered Accountants (CICA) standard for goodwill and other intangibles. Under the new standard, goodwill and certain intangibles are no longer subject to amortization, but are instead tested for impairment at least annually. The adoption of this standard resulted in the reclassification of $29.3 million from acquired intangibles to goodwill, which will no longer be subject to amortization under the new standard. There was no impairment of goodwill upon adoption of this standard, nor was there an impairment at Dec. 31, 2002.

Net income and earnings per share for the three and twelve months ended Dec. 31, 2001 adjusted to exclude the amortization of the above amount are as follows:

                                      3 months ended   Year ended Dec.
                                       Dec. 31, 2001       31, 2001
------------------------------------------------------------------
Reported net earnings applicable to
 common shareholders                   $     46.5      $     214.6
Amortization of acquired intangibles          2.3              7.7
------------------------------------------------------------------
Adjusted net earnings applicable to
 common shareholders                   $     48.8      $     222.3
------------------------------------------------------------------
------------------------------------------------------------------

Reported basic earnings per share      $     0.27      $      1.27
Amortization of acquired intangibles
 per share                                   0.01             0.05
------------------------------------------------------------------
Adjusted basic earnings per share      $     0.28      $      1.32
------------------------------------------------------------------
------------------------------------------------------------------

Reported diluted earnings per share    $     0.27      $      1.25
Amortization of acquired intangibles
 per share                                   0.01             0.05
------------------------------------------------------------------
Adjusted diluted earnings per share    $     0.28      $      1.30
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