Filed By Filing Services Canada Inc. 403-717-3898

FORM 6-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16
of the Securities Exchange Act of 1934

For the month of March, 2003

TRANSALTA CORPORATION

(Translation of registrant's name into English)


110-12th Avenue S.W., Box 1900, Station “M”, Calgary, Alberta, T2P 2M1

(Address of principal executive offices)

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

Form 20-F____   Form 40-F    X     

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes .....  No ..X...

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

 







Evaluation of Disclosure Controls and Procedures

TransAlta has designed disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the Chief Executive Officer and Chief Financial Officer by others within the Company, including its consolidated subsidiaries, on a regular basis, in particular during the period in which its Current Report on Form 6-K relating to financial results for the year ended December 31, 2002 are being prepared. The Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the disclosure controls and procedures as of a date within 90 days of the date of this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded, as of that evaluation date, that the Company's disclosure controls and procedures were effective to ensure that material information relating to the Company, including its consolidated subsidiaries, was made known to them by others within those entities during the period in which this report was being prepared. There have been no significant changes in the internal controls or in other factors that could significantly affect internal controls subsequent to the date of the most recent evaluation by the Chief Executive Officer and Chief Financial Officer, including any corrective action with regard to significant deficiencies and material weaknesses.






 

Exhibit 1

2002 Management's Discussion and Analysis and consolidated financial statements for the period ended December 31, 2002.






 

MANAGEMENT'S DISCUSSION AND ANALYSIS


This discussion and analysis should be read in conjunction with the consolidated financial statements and Auditors' Report included in this Annual Report.  The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP).  The effect of significant differences between Canadian and U.S. GAAP has been disclosed in Note 27 to the consolidated financial statements.  All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted.


FORWARD-LOOKING STATEMENTS


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


OVERVIEW


This review of TransAlta's 2002 financial results is 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.  TransAlta's Transmission, Alberta Distribution and Retail (D&R), and New Zealand operations were sold on April 29, 2002, Aug. 31, 2000 and March 31, 2000, respectively.  Prior period amounts have been reclassified to reflect these changes.  Generation and Energy Marketing are supported by a corporate group that provides finance, treasury, legal, human resources and other administrative support.  These corporate group overheads are allocated to the business segments if they are not directly attributable to discontinued operations.


Each business segment assumes responsibility for its operating results measured as earnings before interest, taxes and non-controlling interests (EBIT).  EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with Canadian GAAP as an indicator of the corporation's performance or liquidity.  TransAlta's EBIT is not necessarily comparable to a similarly titled measure of another company.  EBIT has been calculated on a consistent basis for the three years ended Dec. 31, 2002 and is reconciled to net earnings applicable to common shareholders below:

 



Year ended Dec. 31

       

2002

2001

2000

EBIT

       

 $      197.6

 $          378.9

 $          408.9

Other income (expense)

       

              0.1

                    1.5

                   (1.1)

Foreign exchange gain

       

              1.2

                   0.8

                    0.1

Net interest expense

       

         (82.7)

               (88.1)

               (91.4)

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

          116.2

               293.1

               316.5

Income tax expense

       

            18.1

                89.9

               128.5

Non-controlling interests

       

            20.1

                20.6

                 41.6

Earnings from continuing operations

       

           78.0

               182.6

               146.4

Earnings from discontinued operations

   

            12.8

                 45.1

                 89.1

Gain on disposal of discontinued operations

   

          120.0

                 -  

              266.8

Extraordinary item

   

                -  

                 -  

            (209.7)

Net earnings

       

          210.8

         227.7

              292.6

Preferred securities distribution, net of tax

       

           20.9

           13.1

                 12.8

Net earnings applicable to common shareholders

 $      189.9

 $      214.6

 $          279.8



Some of the corporation's accounting policies require management to make estimates or assumptions that in some cases may relate to matters that are inherently uncertain.  Critical accounting policies and estimates for TransAlta include: revenue recognition; valuation and useful life of property, plant and equipment; valuation of goodwill; income taxes; and employee future benefits.  See additional discussion under Critical Accounting Policies and Estimates in this MD&A.


TransAlta now measures capacity as net maximum capacity (see glossary for definition of this and other key terms) compared to nameplate capacity which had been previously used.  The change was made to better reflect the actual capacities of assets and to be more consistent with industry standards.  Capacity figures represent capacity owned and in operation unless otherwise stated.  Prior years have been adjusted to reflect the new method of measurement.


STRATEGY AND KEY PERFORMANCE INDICATORS


Strategy

The corporation's strategy is to maintain a strong balance sheet, run its existing assets efficiently and carefully manage the risk profile while methodically growing capacity.  As discussed in the letter to shareholders, TransAlta has identified 11 goals to implement this strategy.


1.

Maintain investment grade credit ratings.  TransAlta is focused on maintaining a strong balance sheet and investment grade credit ratings while maintaining the dividend.  At Dec. 31, 2002, TransAlta's debt to invested capital ratio was 50.9 per cent, the corporation's credit rating was BBB+ and the 2002 annual dividend was $1.00 per common share.


2.

Steadily increase earnings per share.  For the year ended Dec. 31, 2002, TransAlta earned $1.12 per common share compared to $1.27 in 2001.   Earnings were lower due to lower market prices and increased maintenance costs.  The gain on sale related to the Transmission business was offset by an arbitration decision related to the Wabamun power purchase arrangement (PPA), an impairment charge related to the Wabamun plant and turbine cancellation charges.  TransAlta expects to achieve average earnings growth of five to 10 per cent per annum in the medium term.  However, 2003 earnings will be impacted as a result of TransAlta accelerating maintenance at Alberta thermal plants in order to have assets operating at high availability rates in the future.

 


 


3.

Increase generation capacity.  In 2002, TransAlta increased capacity by 200 megawatts (MW).  In 2003, the Sarnia, Campeche and Chihuahua plants, as well as the McBride Lake joint venture project are forecast to be completed, increasing capacity by an additional 989 MW.  In addition, the January 2003 acquisition of a 50 per cent interest in CE Generation LLC (CE Gen) increased capacity by an additional 378 MW.  Due to this acquisition and the 50 per cent acquisition of Genesee 3, TransAlta reached 9,726 MW of owned capacity in operation, under construction or approved for development in January 2003.  While TransAlta continues to explore strategic acquisitions to grow generating capacity, such growth will only be undertaken to the extent that it is affordable and supported by the balance sheet.  As a result, the corporation expects that it will take longer than 2005 to increase capacity to 15,000 MW.


 

2002

2001

2000

Owned Capacity in Operation (MW)

7,144

6,944

6,761


4.

Increase overall plant availability to 90 per cent.  Availability is a key performance indicator for TransAlta.  The corporation has approximately 90 per cent of its output under long-term contracts ; therefore , availability is critical to meeting these contracted quantities.  Availability is also essential to producing electricity for sale at spot market prices.  Overall plant availability for the year ended Dec. 31, 2002 was 88.4 per cent compared to 86.9 per cent in 2001.



 

2002

2001

2000

Availability

88.4

86.9

87.8



5.

Reduce overhead and variable costs by $150 million.  As of Dec. 31, 2002, the corporation identified $137.0 million in cost reductions related to coal extraction, variable operating costs and overhead costs compared to those incurred during 2001.  


6.

Diversify by market and fuel type.  To minimize risk, TransAlta's long-term goal is to ensure no more than 30 per cent of the corporation's generating capacity is in one fuel source or market.  During 2002 TransAlta increased gas-fired capacity by a net 263 MW, renewable capacity by 44 MW, capacity in the U.S. by a net 126 MW and capacity in Australia by 34 MW.  All of the 989 MW forecast to be completed in 2003 are fuelled by gas or renewables and 511 MW are outside of Canada.  The 50 per cent acquisition of CE Gen in 2003 increased capacity from renewables by 163 MW and gas-fired assets by 215 MW, all within the U.S.


Owned and operated capacity by fuel source at Dec. 31, 2002 (MW)

Coal

4,966

70%

Gas

1,333

19%

Hydro

801

11%

Renewable

44

1%




Owned and operated capacity by location at Dec. 31, 2002 (MW)

Canada

5,165

72%

U.S.

1,699

24%

Australia

280

4%



7.

Minimum of 75 per cent of production under long-term contracts.  Long-term contracts minimize TransAlta's exposure to market fluctuations.  Maintaining a portion of production to be sold at market rates allows the corporation to capitalize on favourable market prices when available and reduces the risk of production shortfalls.  In 2002, 90 per cent of the corporation's production was under long-term contracts.  Of the new capacity scheduled for completion in 2003, the Mexican plants and McBride Lake joint venture are 100 per cent contracted and Sarnia is approximately 50 per cent contracted.


 

2002

2001

2000

Contracted production (%)

90

92

96


8.

10 per cent of capacity from renewable energy sources by 2010.  TransAlta is committed to reducing emissions while increasing production.  A key factor in this strategy is increasing production from renewable energy sources.  The acquisitions of Vision Quest Windelectric Inc. (Vision Quest) in December 2002 and a 50 per cent interest in CE Gen in January 2003 are part of TransAlta's commitment to sustainable development.


9.

Continue to capitalize on alliances.  TransAlta has strategic alliances with EPCOR Utilities Inc. (EPCOR), ENMAX Corporation (ENMAX) and MidAmerican Energy Holdings Company (MidAmerican).  The EPCOR alliance provided the opportunity to acquire a 50 per cent ownership in the 450 MW Genesee 3 project.  The ENMAX partnership in the McBride Lake wind project provides the economic support to expand TransAlta's renewable energy business.  MidAmerican owns the other 50 per cent interest in CE Gen.


10.

  Use Energy Marketing to manage the corporation's asset risk.  Energy Marketing acts to maximize margins from electricity, minimize the cost of natural gas used to generate electricity and reduce the risk to the corporation from unplanned outages by acquiring replacement power at the lowest possible price.  During 2002, TransAlta sold uncontracted electricity at greater than market index prices and purchased electricity to meet contract obligations when it was more economic to buy rather than produce electricity.


11.

  Reach zero net emissions from Canadian thermal plants by 2024.  In 2002 TransAlta added additional gas and renewable capacity in Canada while reducing capacity at the coal-fired Wabamun facility.  In addition, the purchase of offset credits and continued focus on technology will position the corporation to manage the future requirements of the Kyoto Protocol.


Key Performance Indicators

 


 

For the Generation segment, key performance indicators (KPIs) include availability, production, fuel and operating costs, and pricing applicable to non-contracted production.  For the Energy Marketing segment, KPIs include trading volumes, margins and value at risk (VAR), which is a measure to manage earnings exposure from trading activities not related to TransAlta's assets.  Each of these KPIs is discussed in greater detail in Segmented Business Results in this MD&A.  KPIs for the corporate segment include the debt  to invested capital ratio and credit ratings.  These KPIs are discussed under Liquidity and Capital Resources.



MARKET TRENDS


Average Monthly Electricity Prices

 

 Mid-Columbia Price (US$/MWh)

Alberta System Market Price (Cdn$/MWh)

January 2000

 $            25.40

46.46

February 2000

             26.25

47.07

March 2000

             27.36

77.19

April 2000

             23.38

93.68

May 2000

             50.02

51.66

June 2000

           131.26

106.73

July 2000

             98.08

124.11

August 2000

           166.06

202.09

September 2000

           114.73

176.28

October 2000

             96.71

253.28

November 2000

           161.29

227.73

December 2000

         524.65

188.91

January 2001

         261.46

131.22

February 2001

         275.22

116.75

March 2001

         260.71

97.23

April 2001

          289.74

114.82

May 2001

          223.45

88.34

June 2001

            62.00

63.59

July 2001

            53.04

53.47

August 2001

            39.71

52.37

September 2001

            22.72

29.93

October 2001

            24.49

43.94

November 2001

           22.36

33.31

December 2001

           24.24

33.61

January 2002

            17.38

                28.44

February 2002

            19.45

                22.37

March 2002

           32.32

                 55.14

April 2002

            19.44

                45.04

May 2002

            19.02

                40.44

June 2002

              7.51

                46.23

July 2002

              9.91

                45.70

August 2002

            17.90

                32.03

September 2002

           24.59

                 24.61

October 2002

            24.49

                44.33

November 2002

            22.36

                69.07

December 2002

            24.24

                70.88



 

Changes in the price of electricity can have a significant influence on TransAlta's financial performance.  Fluctuating supply and demand resulted in high market volatility and high prices for electricity in late 2000 and early 2001.  In the last half of 2001, additional capacity was brought to market and adverse economic conditions reduced demand; this combination resulted in lower volatility and prices throughout 2002, as shown in the chart above.  Electricity price levels in Alberta and the Pacific Northwest are expected to be slightly higher in 2003 compared to 2002 due to higher natural gas prices and reduced hydro production as a result of lower snow pack.


Electricity prices generally increase as a result of higher natural gas prices.  This benefits TransAlta's coal-fired facilities by increasing margins on merchant output.  However, in the short term increased natural gas prices can also reduce spark spreads (the difference between the price of natural gas consumed to produce power and the selling price of electricity).  As illustrated in the chart below, spark spreads were reduced in 2002 at TransAlta's merchant gas-fired facilities.  The increases in electricity prices are not completely correlated to the increase in natural gas prices due to generation overcapacity in the market.  The majority of the corporation's gas costs have been hedged or flow through to customers under the terms of agreements ; however , approximately 10 per cent of total production is subject to market prices for electricity and/or spark spread risk.


Average Monthly Spark Spreads1 ($/MWh)

 

Mid-Columbia Price vs. Sumas (US$)

 

Alberta System Market Price vs. AECO (Cdn$)

January 2000

9.56

 

25.58

February 2000

9.66

 

24.15

March 2000

9.23

 

51.17

April 2000

3.75

 

65.83

May 2000

27.61

 

19.59

June 2000

101.87

 

69.00

July 2000

73.89

 

90.61

August 2000

140.54

 

168.83

September 2000

81.55

 

129.99

October 2000

62.39

 

205.94

November 2000

87.50

 

174.84

December 2000

398.39

 

102.59

January 2001

202.81

 

51.99

February 2001

232.90

 

58.81

March 2001

220.96

 

42.99

April 2001

252.12

 

60.76

May 2001

195.12

 

46.63

June 2001

40.09

 

29.93

July 2001

37.03

 

28.64

August 2001

22.29

 

25.61

September 2001

11.00

 

11.53

October 2001

9.94

 

21.58

November 2001

7.42

 

10.49

December 2001

7.47

 

9.20

January 2002

4.43

 

6.44

February 2002

5.94

 

0.09

March 2002

13.99

 

24.66

April 2002

(0.93)

 

13.60

May 2002

0.18

 

10.72

June 2002

(6.67)

 

24.03

July 2002

0.68

 

11.23

August 2002

3.17

 

9.98

September 2002

5.23

 

16.25

October 2002

4.78

 

7.25

November 2002

5.64

 

30.74

December 2002

7.92

 

27.82

1 For a 7,000 Btu/KWh heat rate plant.




Since the bankruptcy of Enron and reduction of credit worthiness of other market participants, liquidity in the medium- and longer-term energy trading markets has decreased considerably.  Activity levels in the short-term market have increased.  Margins in the energy trading business have significantly declined relative to 2000 and 2001 as a result of lower prices and more efficient markets.


SUMMARY OF RESULTS

   

2002

 

2001

 

2000

 
               

Availability (%)

       88.4

 

      86.9

 

      87.8

 

Production (GWh)

   46,877

 

  44,136

 

  40,644

 

Electricity trading volumes (GWh)

 103,076

 

  27,619

 

    9,500

 

Gas trading volumes (million GJ)

     159.8

 

      99.3

 

    135.7

 
               
     

Per common

 

Per common

 

Per common

   

Amount

share

Amount

share

Amount

share

Revenues 1

$1,723.9

 

$2,319.4

 

$1,671.1

 
               

Earnings from continuing operations 2

 $    57.1

 $  0.34

 $ 169.5

 $   1.00

 $ 133.6

 $   0.79

Discontinued operations 3

       12.8

     0.07

      45.1

      0.27

      89.1

      0.53

 Earnings applicable to common shareholders

 $    69.9

 $  0.41

 $ 214.6

 $   1.27

 $ 222.7

 $   1.32

Gains on disposal of discontinued operations 3

      120.0

       0.71

             -

             -

      266.8

        1.58

Extraordinary item 4

             -

           -

           -

           -

 (209.7)

 (1.24)

 Net earnings applicable to common shareholders

 $  189.9

 $  1.12

 $ 214.6

 $   1.27

 $ 279.8

 $   1.66

 Cash flow from operating activities

 $  437.7

 

 $ 715.6

 

 $ 198.7

 
               

1

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

2

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

   3

Discontinued operations include the New Zealand operations, the Alberta D&R operation, the Edmonton Composter and the Transmission operation which were disposed of on March 31, 2000, Aug. 31, 2000, June 29, 2001 and April 29, 2002, respectively.

4

Extraordinary item arose from the recognition of previously unrecorded future income taxes and a write-down of property, plant and equipment related to Alberta Generation due to a change in accounting policy as a result of deregulation of the electric generation industry in Alberta commencing on Jan. 1, 2001.


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 adopted a policy that all gains and losses on energy trading contracts not related to generation assets be shown as the net effect of sales less cost of purchased commodity 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.

 



Revenues

2002

2001

2000

Generation

 $1,674.9

 $2,158.4

 $1,593.3

Energy Marketing

 49.0

  161.0

   77.8

 

 $1,723.9

 $2,319.4

 $1,671.1


Revenues decreased by $595.5 million in 2002 compared to 2001.  The decrease is attributable to lower electricity market prices and lower margins on Energy Marketing activities, partially offset by improved availability and production.  The $648.3 million  increase in 2001 revenues compared to 2000 was primarily a result of high market prices in the first half of 2001, a full year of production from the Centralia plant and increased trading revenues in Energy Marketing.


Net earnings from continuing operations applicable to common shareholders decreased by $112.4 million in 2002 compared to 2001.  The decrease was primarily due to lower revenues, the Wabamun plant impairment charge (described below), the cancellation of turbines ordered (described below), and the impact of the accelerated Alberta thermal plant maintenance schedule, partially offset by reduced purchased power requirements.  The $35.9 million increase in 2001 over 2000 was primarily a result of increased earnings from Generation, gains on disposition from the sales of the Fort Nelson and the Fort Saskatchewan plants and increased returns from Energy Marketing activities.  These increases were partially offset by the impact of unplanned outages at the Centralia plant.


Cash flow from operating activities was $277.9 million lower in 2002 compared to 2001. The decrease was due to lower earnings, the impact of the collection in 2001 of accounts receivable relating to the Alberta Power Pool upon implementation of deregulation on Jan. 1, 2001 ($170.0 million), the payment in 2002 to the Alberta Power Pool relating to the ancillary services revenue settlement ($49.9 million), described below, and the final installment of 2001 income taxes paid in the first quarter of 2002 ($109.0 million).  In 2000, significantly increased working capital requirements resulted from deferred accounts receivable related to the sale of the discontinued Alberta D&R operation and increased trade receivables related to Centralia production and Energy Marketing activities.

 

SIGNIFICANT ONE-TIME ITEMS


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


Purchase of Vision Quest

On Dec. 6, 2002 the corporation purchased the remaining interest in 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 MW of capacity and has a substantial resource base available for further expansion.  Vision Quest and ENMAX each own a 50 per cent interest in the McBride Lake joint venture project with 75 MW under construction.  Vision Quest's financial results for the period after acquisition ($0.6 million EBIT) are included in corporate results for segmented reporting purposes.

 



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 four-unit 537 MW coal-fired Wabamun facility.   The PPA for the plant expires at the end of 2003.  The 139 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 (62 MW and 57 MW respectively) in 2004 and unit four (279 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 it could not use all its pre-purchased natural gas turbines.  The corporation therefore cancelled orders for four turbines and as a result has recorded a pre-tax cancellation charge of $42.5 million for contract termination costs in 2002.  The costs consisted solely of progress payments made to date.  The remaining five turbines will be used in development projects.


Refinancing of foreign operations

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


Ancillary services revenue settlement

In July 2002, a dispute with the Balancing Pool of Alberta in respect of the allocation of hydro ancillary services deferred revenue under the PPAs was resolved.  TransAlta repaid $49.9 million received in advance from the Balancing Pool.  The settlement had no earnings impact as the corporation had not previously recognized the amount as revenue.


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 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.


Gains 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 $36.2 million.

 


 

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


On Aug. 31, 2000, TransAlta completed the disposition of its Alberta D&R operation for proceeds of $857.3 million and recorded an after-tax gain of $262.4 million ($1.55 per common share).  In 2002, the outstanding amount due from Aquila Networks Canada (formerly UtiliCorp Networks Canada) relating to the sale of the D&R operation was collected in full.


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


Prior period regulatory decisions

Financial results for 2000, 2001 and 2002 were affected by Alberta Energy and Utilities Board (EUB) decisions related to other reporting periods.  The impact of such regulatory decisions is recorded when the effect of such decisions is known, without adjustment to the financial statements of prior periods.


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


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


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


In February 2000, the EUB announced an amendment to its Phase I decision concerning a 1999 revenue requirement issue.  The amendment resulted in TransAlta recognizing $30.6 million of pre-tax earnings.


Pierce Power

In September 2001, TransAlta reassessed its investment in the 154 MW Pierce Power plant as a result of weak economic conditions.  Revenue hedges that were no longer expected to be effective were unwound and realized, resulting in the recognition of $121.8 million in revenue, partially offset by a write-down in the carrying amount of property, plant and equipment of $66.5 million and $52.3 million recognized in anticipated future plant operating costs.  The plant remained available for production until it was decommissioned in September 2002.  At Dec. 31, 2002, all accrued amounts had been realized.

 



Extraordinary item

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


NEW ACCOUNTING STANDARDS


On Jan. 1, 2002, the corporation retroactively adopted the new Canadian Institute of Chartered Accountants (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, the impact would be as disclosed in Note 16.  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.


Effective Jan. 1, 2002, the corporation prospectively adopted the new CICA standard for goodwill and other intangibles.  The new standards require business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting.  It also specifies that 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 is no longer 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.


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.



 

In November 2001, the CICA released an accounting guideline on hedging relationships, which specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges.  The guideline also identifies situations where hedge accounting is to be discontinued.  The guideline is effective for years beginning on or after July 1, 2003.  TransAlta has adopted the guideline effective Jan. 1, 2002 and met the criteria for all hedging relationships with the exception of written swaptions, which are ineffective under the guideline.  Hedge accounting was discontinued for the written swaptions in accordance with the guideline.  The impact on earnings for the year ended Dec. 31, 2002 was a decrease of $2.0 million after tax.


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 pre-tax, 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 adopted a policy that all gains and losses on energy trading contracts not related to generation assets 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.



OUTLOOK


To achieve earnings growth, the corporation's focus will be to increase the efficiency and availability of generating assets, continue to improve productivity in operating, maintenance and administrative (OM&A) costs and add generating capacity.  Energy Marketing will focus on maximizing pricing opportunities for non-contracted production from Generation and taking advantage of short-term market opportunities within pre-established risk limits.


Generation

The key factors affecting Generation's financial results for 2003 continue to be the megawatt capacity in production, the availability of and production from facilities, the pricing applicable to non-contracted production and the costs of production.


Grow capacity

Generating capacity in 2003 will be higher than in 2002 due to completion of the 252 MW Campeche plant, the 259 MW Chihuahua plant and the 75 MW McBride Lake joint venture which are scheduled to commence commercial operations in the first, third and fourth quarters of 2003, respectively.  In connection with the construction of the Sarnia Regional Cogeneration Plant, TransAlta purchased 190 MW of existing operational assets during 2002 and subsequently decommissioned 55 MW.  Construction of an additional 440 MW at Sarnia is expected to be completed in the first quarter of 2003 to provide 575 MW of ongoing generating capacity.  The purchase of a 50 per cent interest in CE Gen in January 2003 will add another 378 MW of capacity.  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.  Additional maintenance in Alberta will be offset by increased availability at Centralia.



At Dec. 31, 2002, assets under construction totalled $1,206.8 million and was comprised of the Sarnia, Campeche and Chihuahua plants.  When these plants are commissioned, depreciation expense will be charged to operations.  Depreciation on the above plants as well as the Big Hanaford plant is expected to be approximately $58 million in 2003.


Power prices

Electricity spot prices in 2003 are expected to be slightly higher than in 2002 for the Alberta and Pacific Northwest markets due to higher natural gas prices and reduced hydro production as a result of lower snow pack.  However, spark spreads are expected to compress due to excess generation capacity and the proportionately higher increase in the cost of natural gas as a result of high gas field decline rates, stagnant drilling activity and an increasing storage deficit.  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 megawatt hour (MWh).  Wholesale market prices have not been directly impacted by this decision, however liquidity in the Ontario market has declined.  As a result, future revenues for merchant capacity at the Sarnia plant may be affected.


Exposure to volatility in electricity prices is substantially mitigated through long-term electricity sales contracts at fixed prices.  Exposure to volatility in gas prices is substantially mitigated by the flow-through of the costs of natural gas to customers in some of these contracts and the existence of price caps in certain natural gas supply contracts.  For 2003, approximately 85 per cent of output is contracted, a significant portion of which relates to the Alberta PPAs which are capacity related based on achieving agreed availability rates.  The corporation will continue to focus on maximizing availability under these contracts.


Improving efficiency

Generation is continuing its focus on reducing coal costs and ongoing OM&A expenses.  Areas for reductions were identified and have been, and continue to be, implemented.  The benefits of these initiatives were partially realized in 2002, and are expected to become fully apparent in 2003 and beyond.  There will be more planned maintenance expenses incurred at the Alberta thermal plants in 2003 than in 2002.


Energy Marketing

Short-term and real-time markets are expected to continue to be active.  Energy Marketing will continue to concentrate on buying and selling electricity and gas in these markets.  The electricity trades involve matching buyers and sellers, arranging for transmission capacity and scheduling movement of the commodity.  This type of trading does not involve long-term contracts and therefore VAR and volatility related to fair value accounting is low.


In 2003, Energy Marketing is expected to achieve comparable results to 2002 based on similar levels of activity.



 

Capital expenditures and acquisitions

In 2003, capital expenditures will be approximately $830 million, of which approximately $275 million will be spent on the Genesee 3 project, described below, approximately $170 million will be spent to complete the two Mexican plants, $60 million will be spent on other growth projects and approximately $325 million will be spent on maintenance and productivity expenditures as a result of planned outages and preventative maintenance.  Financing for these expenditures is expected to come from a combination of cash flow from operations, monetization of selected assets, the issuance of common shares and the issuance of debt.  For further information on financing, see discussion under Liquidity and Capital Resources in this MD&A.


On Jan. 13, 2003, TransAlta and EPCOR announced an agreement for TransAlta to acquire a 50 per cent interest in EPCOR's Genesee 3 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 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 1 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 addition, on Jan. 24, 2003, the corporation announced the acquisition of a 50 per cent interest in 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 non-recourse debt of approximately US$500.0 million (approximately Cdn$762 million).  CE Gen, through its subsidiaries, is primarily engaged in the development, ownership and operation of independent power production facilities in the U.S. using geothermal resources and natural gas as fuel. CE Gen has 13 facilities with an aggregate operating capacity of 756 MW.  The transaction closed on Jan. 29, 2003.


In February 2002, the EUB approved the previously announced Centennial project, which is a 900 MW merchant expansion at the Keephills site.  The first phase one of the project (Centennial 1) 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 Centennial 1 will be made by TransAlta.


Equity Issuance

On March 14, 2003, the corporation filed a short-form prospectus for the issuance of 12.0 million common shares for gross proceeds of $192.0 million.  The underwriters also exercised an option for an additional 3.0 million common shares for gross proceeds of $48.0 million.  The offering includes a second option for the underwriters to purchase a further 2.25 million common shares for $36.0 million, exercisable until April 18, 2003.  The transaction is expected to close on March 21, 2003.


Environmental

On Dec. 16, 2002, the Canadian government ratified the Kyoto Protocol.  The Kyoto Protocol is not expected to have an impact on TransAlta's U.S., Mexican or Australian operations.  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 of 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 development of clean coal technology and the purchase of offset credits.  The acquisition of Vision Quest and its prospects for further developments have resulted in additional amounts of zero-emissions facilities consistent with TransAlta's strategy.  Since 1990, TransAlta's worldwide emissions intensity (the amount of carbon dioxide ( CO2 ) emitted per MWh produced) decreased by 20 per cent.

 



Achieving the above goals will be dependent upon, but not limited to,  certain risks and uncertainties.  For further discussion, see Risk Factors and Risk Management in this MD&A.



SEGMENTED BUSINESS RESULTS

GENERATION Owns and operates hydro-, gas-, and coal-fired plants and related mining operations in Canada, the U.S., Mexico and Australia.  At Dec. 31, 2002 Generation had 7,100 MW of generating capacity in operation and 951 MW under construction.  Generation's results do not include results from wind-powered assets.  Key performance indicators for Generation include availability, production and natural gas and electricity market prices.


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 completion of an upgrade at Centralia (32 MW) the commissioning of the Big Hanaford plant (248 MW), the previously described purchase of existing operational assets at the Sarnia plant (135 MW) and the purchase of the remaining interest in the Southern Cross facility (34 MW).  This is offset by the decommissioning of the Pierce Power plant (154 MW) and Wabamun unit three (139 MW).


The results of the Generation segment are as follows:


Year ended Dec. 31

 

2002

 

2001

 

2000

 
   

 Total

 Per MWh

 Total

Per MWh

 Total

Per MWh

Revenues

 

 $1,673.9

 $      35.71

 $ 2,158.4

 $      48.90

 $1,593.3

 $  39.20

Fuel and purchased power

 

   (703.6)

      (15.01)

  (1,230.6)

       (27.88)

   (741.2)

   (18.24)

Gross margin

 

970.3

          20.70

       927.8

         21.02

     852.1

     20.96

Operating expenses:

             

Operations, maintenance and administration

 

       346.3

           7.39

       290.6

           6.58

     260.1

       6.40

Depreciation and amortization

 

      196.3

           4.19

      156.5

           3.55

     167.7

       4.12

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

       23.9

       0.59

Prior period regulatory decisions

 

           3.3

            0.07

      (11.0)

        (0.25)

     (44.1)

     (1.09)

EBIT before corporate allocations

 

       244.6

           5.22

       354.2

          8.03

    444.5

     10.94

Corporate allocations

 

     (70.6)

        (1.51)

     (82.5)

        (1.87)

    (77.9)

     (1.92)

EBIT  

 

 $   174.0

 $         3.71

 $    271.7

 $        6.16

 $  366.6

 $    9.02




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.  For the year ended Dec. 31, 2002, long-term contracts covered 90 per cent of total production (2001 - 92 per cent; 2000 - 96 per cent) with the remaining production subject to market pricing.


The existing contracts have remaining terms ranging from one to 22 years.  At Dec. 31, 2002, contracted production, as a percentage of potential production from existing assets and assets currently under construction, over the next five years is as shown below.


 

2003

2004

2005

2006

2007

Contracted output (%)

85

79

79

73

69


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.  


Generation also derives revenue from the provision of ancillary services and the sale of steam .  A breakdown of revenues and average pricing applicable to contract and merchant production is presented in the following table:


Year ended Dec. 31

 

2002

 

2001

 

2000

 
   

Revenue

Per MWh

Revenue

Per MWh

Revenue

Per MWh

Contract

 

 $      1,448.2

 $     33.26

 $   1,374.1

 $                                     33.23

 $                    1,195.7

 $                        30.47

Merchant

 

              171.0

        51.64

681.2

      142.91

       347.1

   246.27

Ancillary services and other

 

                93.6

                -   

103.1

              -   

         50.5

           -   

Wabamun arbitration decision

 

             (38.9)

                -   

              -   

               -   

              -   

           -   

   

 $      1,673.9

 $     35.71

 $   2,158.4

 $     48.90

 $   1,593.3

 $  39.20



A reconciliation between production, revenue and EBIT for the years ended Dec. 31, 2001 and 2002 is presented below:


 

Production (GWh)

Revenue

EBIT

Year ended Dec. 31, 2000

   40,644

 $1,593.3

 $366.6

1999 regulatory decisions received in 2000

           -   

            -   

  (44.1)

Wabamun unit four TSR settlement for 2000

           -   

            -   

    11.0

Higher returns and incentives under PPAs

           -   

     208.3

  208.3

Increased hydro ancillary services

           -   

       53.0

    53.0

Decrease in hydro energy output

       (240)

     (17.9)

  (17.7)

Acquisition of Centralia plant

     2,785

    155.0

    47.3

Unplanned Centralia outages

           -   

       95.7

(245.5)

Centralia hedge losses, expired in 2001

           -   

       11.8

(124.2)

Commencement of operations at Poplar Creek plant

2,491

       84.9

    25.8

Disposal of Mildred Lake, Fort Nelson and Fort Saskatchewan plants

    (1,713)

     (86.6)

        6.5

Monetization of Pierce Power plant

-

     121.8

      3.0

Other

169

(60.9)

(18.3)

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 purchase 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 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 a pre-tax 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 pre-tax contract termination charge.  In September 2001, TransAlta reassessed its investment in the 154 MW Pierce Power plant as a result of weak economic conditions.  Revenue hedges that were expected to be effective were unwound and realized, resulting in the recognition of $121.8 million in revenue, partially 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 was undertaken in order to improve reliability and increase availability in the future.  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, excluding interest that was recorded as a reduction of revenue in the second quarter of 2002.


As discussed in Significant One-Time Items, the following prior period regulatory decisions impacted revenues in 2002, 2001 and 2000: the EUB rendered a negative decision of $3.3 million pre-tax with respect to TransAlta's hydro bidding, which was recorded in 2002; the EUB ruled that the Wabamun unit four outage qualified for relief under the TSR and ordered that TransAlta receive $11.0 million (pre-tax) in 2001; TransAlta received a negotiated settlement of $17.8 million (pre-tax) under the TSR in 2000; and the EUB announced an amendment to its Phase I decision (1999 Final Decision) that increased pre-tax earnings by $30.6 million in 2000.


For 2002, Generation achieved an availability rate of 88.4 per cent compared to 86.9 per cent in 2001.  The increase is the 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 unit three 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 2001, availability was negatively impacted by unplanned outages at the Centralia plant and the Wabamun unit four outage.  In 2000, availability was negatively impacted by the Wabamun unit four outage.


 

2002

2001

2000

Annual electricity production (GWh)

46,877

44,136

40,644


Generation's production increased by 2,741 gigawatt hours (GWh) in 2002 compared to 2001.  The increase is the result of incremental production from the Sarnia and Big Hanaford plants, increased production from the Centralia plant, the return to service of Wabamun unit four, as well as increased thermal production and availability.  This was partially offset by lost production resulting from accelerated Alberta thermal plant maintenance and economic dispatch decisions.


Production in 2001 increased over 2000 primarily as a result of a full year of production from the Centralia plant, which was acquired in May 2000, and increased production from the Poplar Creek plant which commenced commercial operations in January 2001.  This was partially offset by decreased hydro production and lost production due to the sale of the Mildred Lake and Fort Nelson plants.



 

2002

2001

2000

Revenue ($/MWh)

35.71

  48.90

 39.20


Revenue in 2002 decreased by $484.5 million ($13.19 per MWh) compared to 2001.  Adjusted for the Wabamun arbitration and Pierce Power one-time items in 2002 and 2001 respectively, 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.


In 2001 compared to 2000, increased revenues were realized from the Alberta PPAs, increased production from a full year of production from the Centralia and Poplar Creek plants, partially offset by the sale of the Mildred Lake and the Fort Nelson plants.


Fuel and purchased power decreased to $703.6 million ($15.01 per MWh) in 2002 from $1,230.6 million ($27.88 per MWh) in 2001 and $741.2 million ($18.24 per MWh) in 2000.  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.



   

2002

2001

2000

Fuel

 

 $               671.5

 $               635.7

 $               550.6

Purchased Power

 

 $                 32.1

 $               594.9

 $               190.6

Total

 

 $               703.6

 $            1,230.6

 $               741.2



In 2002, purchased power declined significantly to $32.1 million from $594.9 million in 2001 and $190.6 million in 2000.  The majority of the purchased power for 2002 was due to the economic dispatch decisions discussed earlier.  In the year ended Dec. 31, 2001, 2,707 GWh of electricity were purchased totalling $594.9 million.  Pre-tax losses as a result of these purchases were US$77.7 million (approximately Cdn$124 million) in 2001.  The purchased power in 2001 and 2000 was the result of unplanned outages at Centralia.


Fuel costs, excluding purchased power, consist primarily of coal and natural gas costs.  Total fuel costs, excluding purchased power, were $671.5 million ($14.32 per MWh) in 2002 compared to $635.7 million ($14.40 per MWh) in 2001 and $550.6 million ($13.55 per MWh) in 2000.  TransAlta's average fuel costs per MWh are shown below:


   

2002

 

2001

 

2000

Coal

 

 $         11.70

 

 $        12.34

 

 $        12.18

Gas

 

 $         27.86

 

 $        26.16

 

 $        23.95

Average fuel costs, excluding purchased power

 

 $         14.32

 

 $        14.40

 

 $        13.55


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 five per cent in 2002 compared to 2001.  Fuel costs, excluding purchased power, on a per MWh basis, decreased in 2002 as a result of the decrease in coal costs, partially offset by increased natural gas costs.  The increase in gas costs was due to higher natural gas market prices at the Big Hanaford plant, higher gas prices and heat rates at the Sarnia plant, and increased transportation costs.  For contracted plants, a portion of the gas cost has 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.


Coal costs per MWh in 2001 were similar to 2000 while the increased gas costs per MWh in 2001 compared to 2000 reflect ed higher natural gas market prices.


In 2002, OM&A expenses increased by $55.7 million ($0.81 per MWh) over 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, partially offset by cost reduction initiatives.  OM&A in 2001 increased by $30.5 million ($0.18 per MWh) compared to 2000 as a result of the increased maintenance at the Centralia plant.


Depreciation and amortization increased by $39.8 million ($0.64 per MWh) in 2002 compared to 2001.  The increase is a result of the addition of the Big Hanaford plant and increased capital projects at the thermal plants, including the scrubber project at Centralia.  Depreciation and amortization decreased by $11.2 million ($0.57 per MWh) in 2001 over 2000 due to the sale of the Mildred Lake, Fort Nelson and Fort Saskatchewan plants, partially offset by a full year of operations at the Centralia plant and the commissioning of the Poplar Creek plant.



 

The increase in taxes other than income taxes in 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 provide critical market knowledge to help identify growth opportunities and support corporate investment decisions.  Key performance indicators for Energy Marketing include trading volumes, margins and VAR.


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


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


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


The results of Energy Marketing are as follows:


Year ended Dec. 31

2002

2001

2000

Gross revenues

 $       3,703.8

 $       2,694.7

 $          1,280.3

Trading purchases

         (3,654.8)

         (2,533.7)

           (1,202.5)

Net revenues

               49.0

             161.0

77.8

Operations, maintenance and administration

               15.1

               36.2

19.0

Depreciation and amortization

                 2.5

               11.0

9.4

Taxes, other than income taxes

                 0.1

                   -   

-

EBIT before corporate allocations

               31.3

             113.8

49.4

Corporate allocations

                (8.3)

                (6.6)

(7.1)

EBIT

 $            23.0

 $          107.2

 $               42.3



The gross physical and financial settled sales transactions are as follows:


Electricity (GWh)

 

Year ended Dec. 31

2002

2001

2000

Physical

           63,015

           18,504

6,365

Financial

           40,061

             9,115

3,135

 

         103,076

           27,619

9,500

       

Gas (million GJ)

 

Year ended Dec. 31

2002

2001

2000

Physical

               96.2

               30.6

42.1

Financial

               63.6

               68.7

93.6

 

             159.8

               99.3

135.7




Gross trading sales volumes increased by 75,457 GWh of electricity and 60.5 million gigajoules (GJ) of gas in 2002 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 while TransAlta's activity levels in the short-term market increased.  TransAlta's trading activity comprised mainly short-term transactions, the majority of which were settled within 90 days thereby limiting risk and maintaining low working capital requirements.  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.


The increased electricity trading volumes in 2001 compared to 2000 were in response to high market volatility and prices in the Pacific Northwest for the first five months of 2001.



   

2002

2001

2000

Net revenues

 

 $                   49.0

 $                 161.0

 $                   77.8


Net revenues decreased by $112.0 million in 2002 due to significantly lower market prices and margins compared to 2001, particularly in the Pacific Northwest.  As expected, increased market liquidity and pricing efficiencies in the short-term market in 2002 resulted in margins on individual trades being reduced.  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.  Net revenues in 2000 were lower than in 2001 for the reasons discussed above.



   

2002

2001

2000

OM&A

 

 $                  15.1

 $                  36.2

 $                  19.0


OM&A expense 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 EBIT as well as 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.  Expenses were higher in 2001 than in 2000 due to the one-time costs relating to the MEGA acquisition and higher incentive compensation.


Depreciation and amortization decreased by $8.5 million in 2002 compared to 2001.  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.  Depreciation and amortization in 2001 was higher than in 2000 as a result of the increased goodwill resulting from the MEGA acquisition.

 



VAR is a measure to manage earnings exposure for Energy Marketing activities.  The average daily VAR level in 2002 was approximately $2.6 million compared to $1.2 million in 2001.  See additional discussion under commodity price risk in Risk Factors and Risk Management.


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 during 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:


 

2003

2004

2005

2006

2007

2008 and 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 these claims.


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.  The net amount has been reclassified to long term, as collection is no longer expected in 2003, although ultimate collection of the net receivable 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.



 

TransAlta acquired the remaining 50 per cent of MEGA in June 2001 for cash consideration of US$0.3 million (Cdn$0.4 million). The initial 50 per cent of MEGA was purchased in June 2000 for cash consideration of US$12.5 million (Cdn$18.6 million).  Subsequent to the acquisition, one-time costs of $13.9 million were incurred, comprised primarily of severance of $3.9 million and long-term employment incentives in the amount of $8.5 million.  TransAlta continues to use MEGA as a platform on which to expand trading activities into eastern U.S. regions.  MEGA has been amalgamated with TransAlta Energy Marketing U.S. Inc., a subsidiary of TransAlta Energy Corporation (TransAlta Energy) and is therefore included in the Energy Marketing business segment.



NET INTEREST EXPENSE, OTHER EXPENSE AND FOREIGN EXCHANGE

             

Year ended Dec. 31

   

2002

 

2001

2000

             

Gross interest expense

 

 $   172.9

 

 $ 170.3

 $      180.0

Interest income

   

(8.7)

 

(24.2)

(23.8)

Capitalized interest

   

      (79.1)

 

    (48.3)

         (39.8)

Allocated to discontinued operations

 

         (2.4)

 

      (9.7)

         (25.0)

Net interest expense

   

82.7

 

88.1

91.4

Other expense (income)

 

         (0.1)

 

      (1.5)

            1.1

Foreign exchange gains

 

         (1.2)

 

      (0.8)

          (0.1)

     

 $      81.4

 

 $   85.8

 $        92.4

             

Year ended 2000

         

 $        92.4

Increased debt levels, net of interest on Alberta D&R deferral accounts

            5.4

Increased capitalized interest

       

          (8.5)

Lower effective interest rates

       

         (14.6)

Decreased allocations to discontinued operations

     

          15.3

Other

         

          (4.2)

Year ended 2001

         

 $        85.8

Increased debt levels, net of interest on Alberta D&R deferral accounts

          22.2

Increased capitalized interest

       

         (30.8)

Lower effective interest rates

       

          (3.2)

Decreased allocations to discontinued operations

     

            7.3

Other

         

            0.1

Year ended 2002

         

 $         81.4



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

 



Net interest expense decreased by $5.4 million in 2002 as a result of an overall decline in short-term interest rates and higher capitalized interest, partially offset by a higher proportion of debt subject to long-term interest rates and receipt of the $180.3 million interest-bearing receivable from Aquila Networks Canada that arose from the sale of the Alberta D&R operation.  


Net interest expense decreased by $3.3 million in 2001 compared to 2000.  Higher debt levels resulting from the acquisition of the Centralia plant, the commencement of commercial operations at the Poplar Creek plant and increased capital expenditures were offset by the proceeds on the disposal of the Alberta D&R operation, increased capitalized interest and lower interest rates.

OUTLOOK

Net interest expense is expected to increase due to the decreased capitalized interest on assets under construction as the Big Hanaford plant commenced commercial operations in August 2002, and the Sarnia, Campeche and Chihuahua plants will commence commercial operations in 2003.  During 2002, the corporation capitalized interest of $79.1 million as a result of the significant construction activity during the year.  Upon completion of these plants, interest will no longer be capitalized.  Incremental interest expense in respect of these plants in 2003 will be approximately $80 million.  Net interest expense will also increase due to the acquisition funding for CE Gen plus the interest related to approximately US$500 million of assumed non-recourse debt.  Capitalized interest for 2003 will relate to the construction of the Genesee 3 project and the remaining construction on the Sarnia, Campeche and Chihuahua plants.

PREFERRED SECURITIES DISTRIBUTIONS

Year ended Dec. 31

2002

2001

2000

Preferred securities distributions, net of tax

 $  20.9

 $  13.1

 $  12.8


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

OUTLOOK

2003 preferred securities distributions are expected to be similar to 2002 levels, assuming no change in principal amounts outstanding.

INCOME TAXES

Year ended Dec. 31

 

 

2002

2001

2000

Income taxes

     

 $  18.1

 $    89.9

 $  128.5

Effective tax rate (%)

 

 

      15.6

       30.7

       40.6


Income taxes decreased by $71.8 million for the year ended Dec. 31, 2002 due to lower pre-tax earnings as well as the impact of the Wabamun impairment charge 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 during the year 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.


The decrease in the effective tax rate in 2001 compared to 2000 reflects the reduction in Canadian tax rates, lower non-deductible items, and an increase in the manufacturing and processing tax credit.

OUTLOOK

Income taxes are expected to increase in 2003 due to higher pre-tax earnings from operations.  Assuming a similar geographic distribution of earnings and no material changes in tax rates, the corporation anticipates an effective tax rate for 2003 of approximately 30 per cent.


NON-CONTROLLING INTERESTS

Year ended Dec. 31

 

2002

2001

2000

Earnings attributable to non-controlling interests

 

 $  20.1

 $  20.6

 $   41.6


The decrease in earnings attributable to non-controlling interests in 2002 compared to 2001 reflects the redemption of the preferred shares of TransAlta Utilities Corporation (TransAlta Utilities) for $121.6 million in September 2001, resulting in lower subsidiary preferred share dividends, partially offset by increased earnings from the 49.99 per cent non-controlling interest in TransAlta Cogeneration, L.P. (TA Cogen) due to the addition of the Fort Saskatchewan plant in 2001.


The decrease in 2001 compared to 2000 is due primarily to the minority interest portion of the fair value liability of a natural gas swap between TA Cogen and the corporation entered into in December 2000 which was charged to income in 2000.  The swap transaction provides TA Cogen with fixed price gas for both the Mississauga and Ottawa plants until Dec. 31, 2005.  The swap was entered into by TransAlta to stabilize cash distributions of the limited partnership for five years at levels consistent with previous years.  Increased earnings from TransAlta Power, L.P.'s (TransAlta Power) 49.99 per cent limited partnership interest in TA Cogen were offset by the redemption of the 4.0 per cent to 7.7 per cent Series and 8.4 per cent Series of preferred shares of TransAlta Utilities Corporation in September 2001 and March 2000, respectively.


OUTLOOK



No significant changes in non-controlling interests are expected in 2003 assuming current investment levels.


DISCONTINUED OPERATIONS

 

 

Date Sold

2002

2001

2000

Transmission

- earnings from operations

April 29, 2002

 $     12.8

 $     44.4

 $   44.3

 

- gain on disposition

 

      120.0

           -   

          -   

Edmonton Composter

- earnings from operations

June 29, 2001

            -   

          0.7

        0.7

 

- write-down of carrying value

 

            -   

            -   

     (17.9)

Alberta D&R  

- earnings from operations

Aug. 31, 2000

            -   

            -   

      33.3

 

- gain on disposition

 

            -   

            -   

    262.4

New Zealand

- earnings from operations

March 31, 2000

            -   

            -   

      10.8

 

- gain on disposition

 

            -   

            -   

      22.3

 

 

 

 $    132.8

 $      45.1

 $    355.9


TRANSMISSION

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).


EDMONTON COMPOSTER

As discussed in Significant One-Time Items, TransAlta sold its Edmonton Composter facility for proceeds of $97.0 million, which approximated its book value.

 

ALBERTA DISTRIBUTION AND RETAIL

As discussed in Significant One-Time Items, TransAlta sold its Alberta D&R operation in August 2000 for net proceeds of $857.3 million and an after-tax gain on sale of $262.4 million ($1.55 per common share).


NEW ZEALAND

As discussed in Significant One-Time Items, the New Zealand business operations were sold in March 2000 for proceeds of NZ$832.5 million (approximately Cdn$605 million) and an after-tax gain on sale of $22.3 million ($0.13 per common share).






 

CONSOLIDATED BALANCE SHEETS

The following chart outlines significant changes in the consolidated balance sheets between Dec. 31, 2002 and Dec. 31, 2001:

Summary of Significant Changes

Increase/

 

(in millions of Canadian dollars)

(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 receivables related to Pierce Power hedges ($82.0 million), reclassification of California receivables to long-term (US$24.2 million) and  collection of the receivable related to 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 Networks Canada relating to the sale of the discontinued Alberta D&R operation ($180.3 million) and reclass of  sulphur tax abatement ($60.9 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 are expected to be recovered in future years.

Other assets

29.5

Long-term prepayments related to the Sarnia plant, 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, offset by capital expenditures.

Accounts payable and accrued liabilities

(155.3)

Decrease due to lower capital expenditures.

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 $100.0 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 TA Cogen 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.



LIQUIDITY AND CAPITAL RESOURCES

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


Year ended Dec. 31

2002

2001

2000

       

Cash, beginning of year

 $    62.0

 $     53.8

 $     75.3

Cash flow from (used in):

     

  Operating activities

437.7

715.6

198.7

  Investing activities

(36.2)

(1,076.9)

(205.0)

  Financing activities

(320.9)

368.7

(2.7)

Translation of foreign currency cash

0.7

0.8

(12.5)

       

Cash, end of year

 $  143.3

 $     62.0

 $     53.8


TransAlta increased its cash balance by $81.3 million in 2002 compared to an increase of $8.2 million in 2001 and a decrease of $21.5 million in 2000.  Significant changes were as follows:

OPERATING ACTIVITIES Operating activities after changes in non-cash working capital provided cash of $437.7 million in 2002 compared to $715.6 million in 2001 and $198.7 million in 2000.

The decrease in 2002 was a result of the impact of the Wabamun arbitration and prior period regulatory decisions, 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 installment of 2001 income taxes paid in the first quarter of 2002 ($109.0 million).  In 2000, significantly increased working capital requirements resulted from deferred accounts receivable related to the sale of the discontinued Alberta D&R operation and increased trade receivables related to Centralia production and Energy Marketing activities.

INVESTING ACTIVITIES Investing activities used cash of $36.2 million in 2002 compared to $1,076.9 million in 2001 and $205.0 million in 2000.

In 2002, additions to capital assets totalled $945.8 million and consisted primarily of the completion of the Big Hanaford plant and continued construction of the Sarnia, Campeche and Chihuahua plants.  Acquisitions of $40.1 million consisted of the purchase of the remaining interests in Vision Quest and Southern Cross Energy.


 

In 2001, capital expenditures of $1,246.5 million related primarily to the installation of the scrubber at the Centralia plant and the continued construction activities at the Big Hanaford, Sarnia, Campeche and Chihuahua plants.

In 2000, capital expenditures of $795.0 million consisted primarily of continued construction of the Poplar Creek plant, the construction of the scrubber at the Centralia plant and capital maintenance at the Alberta plants.  Cash used for acquisitions totalled $880.1 million, consisting primarily of the acquisition of the Centralia plant for $868.7 million and the acquisition of MEGA for $18.6 million, net of cash acquired of $7.2 million.

Cash provided by disposals and the sale of capital assets in 2002 totalled $820.3 million comprised primarily of proceeds from the sale of the discontinued Transmission operation in April 2002.  Proceeds were used to repay short- and long-term debt.

Cash provided by disposals and the sale of capital assets in 2001 was $236.6 million comprised primarily of proceeds of $97.0 million from the sale of the Edmonton Composter, $60.3 million from the sale of the Mildred Lake plant, $44.1 million from the sale of the Fort Nelson plant and $35.0 million from the sale of half of the corporation's interest in the Fort Saskatchewan plant.

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

In August 2002, long-term receivables in the amount of $180.3 million due from Aquila Networks Canada that arose from the sale of the Alberta D&R operation were collected in full.

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

In 2000, restricted investments of $86.8 million matured.

FINANCING ACTIVITIES Financing activities used cash of $320.9 million compared to providing cash of $368.7 million in 2001 and $2.7 million used in 2000.

In 2002, the issuance of US$300.0 million in senior notes was more than offset by the net repayment of short-term debt ($247.1 million), repayment of long-term debt ($454.5 million), cash dividends ($115.5 million), and the net redemption of common shares ($48.1 million).  

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


 

In 2000, cash used for the $158.4 million of dividends paid on common shares, $146.8 million redemption of preferred shares of a subsidiary, dividends and distributions to non-controlling interests of $42.8 million, and net redemption of common shares of $19.3 million was offset by an increase of $255.7 million in short-term debt, and net issuances of $126.2 million in long-term debt.

In 2002, TransAlta repaid the following senior secured debt of TransAlta Utilities Corporation:


 

Maturity

Rate

Amount

Debentures


2002

8.70%

 $      100.0


In 2002, under the terms of the Normal Course Issuer Bid, the corporation purchased for cancellation 2.0 million (2001 - 2.0 million; 2000 - 1.6 million) common shares at an average price of $20.40 (2001 - $23.93; 2000 - $15.25).


TransAlta's dividends per common share were $1.00 in 2002, 2001 and 2000.

FINANCING ARRANGEMENTS TransAlta Corporation raises capital in the Canadian and U.S. markets.  TransAlta has the following financing arrangements in place:

TransAlta Corporation issued $175.0 million of 7.75 per cent preferred securities on Nov. 29, 2001.  It is the corporation's expectation that future financing requirements, including financing requirements in foreign jurisdictions, will be met primarily through raising capital at the TransAlta Corporation level.  In addition to the above facilities, non-recourse project financing of US$133.6 million has been arranged for the Campeche project.

 


 

CASH REQUIREMENTS In 2003, cash will be provided from operations as well as a combination of new debt, preferred securities, equity and/or the sale of non-core assets.  Future cash requirements include additions to capital assets, acquisitions, as well as dividend payments and refinancing of short-term and maturing senior debt.


In 2003, capital expenditures are necessary to maintain and improve the output from existing facilities ($325 million), fund the Genesee 3 project ($275 million), complete the construction of the Campeche and Chihuahua plants ($170 million) and fund other growth projects ($60 million).  The acquisition of CE Gen will initially be financed with short-term debt and subsequently refinanced with a combination of cash flow from operations, long-term debt, preferred securities and equity.  In addition, $355.4 million of existing debt is required to be refinanced during 2003.


Short-term liquidity is provided through cash flow from operations and utilization of various credit facilities.  At Dec. 31, 2002, there were approximately $1 billion of funds available under credit facilities.  Cash provided by operations in 2002 was $437.7 million.


In January 2001, the corporation issued $250.0 million of medium-term notes at an interest rate of 6.05 per cent repayable in five years.  In May 2001, the corporation issued $225.0 million of medium term notes at an interest rate of 6.90 per cent repayable in 10 years.  The proceeds were used to repay short-term debt.


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


The corporation's targets are to maintain its credit ratings at strong investment grade levels and maintain a capital structure of 50 per cent debt to total capitalization.  The corporation's capital structure consisted of the following components at Dec. 31, 2002, 2001 and 2000:


   

2002

2001

2000

Debt to invested capital (%)

50.9

52.3

48.0



 

2002

   

2001

   

2000

 
                 

Debt, net of cash and interest-earning investments

 $ 2,853.3

51%

 

 $2,986.3

52%

 

 $2,421.9

48%

Preferred securities

       451.7

8%

 

    452.6

8%

 

    292.0

6%

Other non-controlling interests

       263.0

5%

 

     281.0

5%

 

     253.4

5%

Preferred shares of a subsidiary

               -  

-

 

 -

-

 

     121.6

2%

Common shareholders' equity

    2,039.6

36%

 

  1,989.7

35%

 

1,957.4

39%

 

 $ 5,607.6

100%

 

 $ 5,709.6

100%

 

 $5,046.3

100%


With the purchase of 50 per cent interests in CE Gen and Genesee 3, the debt to invested capital ratio has increased since Dec. 31, 2002.  It is TransAlta's intention to return to a 50 per cent debt to invested capital ratio through utilizing cash from operations, the sale of selected assets and the issuance of common shares.

Additional key financial ratios were as follows:

 


 

 

2002

2001

2000

 
         

Cash flow to interest1

 3.8x

 4.8x

 4.4x

 

Cash flow to total debt2

18%

25%

26%

 
         

1  Cash flow from operations before changes in working capital and gross interest expense divided by gross interest expense.

2  Cash flow from operations before changes in working capital divided by two-year average of total debt.



Contractual repayments of long-term debt, commitments under operating leases, turbine purchase commitments and commitments under mining agreements are as follows:


 

2003

2004

2005

2006

2007

2008 and thereafter

Total

Long-term debt1

 $       355.4

 $  146.9

 $  247.4

 $  364.4

 $    15.7

 $ 1,576.8

 $ 2,706.6

Operating leases

             6.7

        5.7

        5.5

        4.4

        3.2

        26.7

        52.2

Turbine purchase commitments

             6.2

       46.0

        1.2

         -   

         -   

           -   

        53.4

Mining agreements

           20.0

       20.0

       20.0

       20.0

       20.0

       357.5

       457.5

Total contractual cash obligations

 $       388.3

 $  218.6

 $  274.1

 $  388.8

 $    38.9

 $ 1,961.0

 $ 3,269.7

1 Includes capital lease obligations.

         


In addition, the corporation has entered into a number of long-term power sales, gas purchase and transportation agreements in the normal course of operations as hedges of its operations.


In the normal course of operations, TransAlta and certain of its subsidiaries enter into agreements to provide financial or performance assurances to third parties.  This includes guarantees, letters of credit and surety bonds which are entered into to support or enhance creditworthiness in order to facilitate the extension of sufficient credit for Energy Marketing trading activities, treasury hedging, Generation construction projects, equipment purchases and mine reclamation obligations.


At Dec. 31, 2002, the corporation had $161.7 million, US$144.4 million and 35.2 million pesos in letters of credit outstanding.  The letters of credit were issued to counterparties that have credit exposure to certain subsidiaries.  If a subsidiary does not pay amounts due under the covered contract, the counterparty may present its claim for payment to the financial institution, which in turn will request payment from the corporation.   Any amounts owed by the corporation's subsidiaries are reflected in the consolidated balance sheet.  All letters of credit expire in 2003.


At Dec. 31, 2002, the corporation issued a surety bond in the amount of US$156.7 million in support of future site reclamation liabilities at the Centralia mine.  A provision for reclamation liabilities is included in the deferred credits and other long-term liabilities (Note 12).  The surety bond expires in 2005.


TransAlta also guaranteed payments for its subsidiaries involved in hedging and trading activities.  These guarantees are provided to counterparties in order to facilitate physical and financial transactions in various derivatives.  To the extent liabilities exist for trading activities, they are included in the consolidated balance sheet.  To the extent liabilities exist for hedging activities, they are disclosed in Note 20.  The limit under these guarantees at Dec. 31, 2002 for trading and hedging activities was $1.9 billion.  In addition, the corporation has a number of unlimited guarantees.  The exposure at Dec. 31, 2002 under these guarantees was approximately $475 million.  Certain contracts contain provisions that may require collateral to be provided if certain triggers in the contract are met such as fluctuations in commodity prices or creditworthiness.  In the absence of any credit limits granted by TransAlta's counterparties, TransAlta's maximum collateral requirements would have been $492.0 million at Dec. 31, 2002 if the corporation's credit ratings were below investment grade.  Collateral available was approximately $1 billion.  See discussion under liquidity risk in Risk Factors and Risk Management.



 

TransAlta provided guarantees to counterparties for obligations of various subsidiaries for performance and payment of obligations.  In the event of the subsidiaries' inability to meet the obligations, TransAlta would be obligated to make such payments.  To the extent obligations existed under these guarantees at Dec. 31, 2002, they are included in accounts payable and accrued liabilities.  The limit under these guarantees at Dec. 31, 2002 was $693.8 million.  


TransAlta guaranteed the debt of $269.4 million at Dec. 31, 2002 for the Windsor and Campeche plants.  The debt is recorded on TransAlta's consolidated balance sheets.  The subsidiaries are required to comply with certain financial covenants as specified in the debt agreements.  In the event of default, TransAlta would be obligated to pay the principal and any related interest.  Currently, the subsidiaries are in compliance with all covenants, and management does not estimate any difficulties in continuing to maintain compliance.  The US$133.6 million of debt related to the Campeche plant will become non-recourse to the corporation upon commencement of commercial operations, which is expected to occur in the first quarter of 2003, and the achievement of certain performance tests, which is expected to occur in the second half of 2003.


 At Dec. 31, 2002, the credit ratings for the corporation's various securities and TransAlta Power's units as determined by Standard & Poor's (S&P), the Dominion Bond Rating Service (DBRS) and Moody's rating services were as follows:


Credit Ratings

     
 

S&P

DBRS

Moody's

TransAlta Corporation

     

Issuer rating

BBB+

 

Baa 1

Commercial paper

 

R1 (low)

 

Senior unsecured debentures

BBB+

BBB (high)

(P) Baa 1

Preferred securities / stock

BBB-

Pfd-3 (high) y

(P) Baa 3

TransAlta Utilities Corporation

     

Issuer rating

BBB+

   

Secured debt

A-

A (low)

 

TransAlta Power, L.P.*

SR-1

   

* Non-controlling partner in TransAlta's subsidiary, TransAlta Cogen

 



In May 2002, Moody's downgraded TransAlta Corporation's issuer rating from A3 and assigned prospective ratings of (P) Baa 1 and (P) Baa 3 to the corporation's senior unsecured debt and first preferred shares, respectively, under the corporation's US$1.0 billion shelf registration.  In December 2002, DBRS downgraded TransAlta Corporation's credit ratings on senior unsecured debentures and preferred securities from A (low) and Pfd (low) y, respectively; and TransAlta Utilities' credit ratings on secured debentures from A.  The downgrades reflect weak economic performance in the markets in which TransAlta operates.  The downgrades do not trigger early repayment under the terms of any of the debt agreements.

In January 2003, Moody's placed TransAlta Corporation's rating under review for possible downgrade; S&P placed both ratings of TransAlta Corporation and TransAlta Utilities on credit watch; and DBRS changed their rating trend for both TransAlta Corporation and TransAlta Utilities from stable to negative.  S&P affirmed the SR-1 stability rating for TransAlta Power on Jan. 15, 2003.  

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

Under Canadian GAAP, most derivatives used in hedging relationships are not recorded on the balance sheet (Note 1(O)).  Gains or losses during the term of the hedge are deferred and recognized in earnings in the same period and financial statement caption as the hedged exposure (settlement accounting).  The fair values of these derivatives are disclosed in Note 20 to the consolidated financial statements.  The corporation also enters into long-term electricity purchase and sale, gas purchase and transportation agreements in the normal course of operations.  These contracts are not recorded on the balance sheet under Canadian GAAP.  Under U.S. GAAP, certain of these contracts meet the definition of a derivative, and would require mark-to-market accounting, but are eligible for the normal purchase and sale exemption under the Financial Accounting Standards Board (FASB) Statement 133.  This exemption is available as electricity cannot be stored in significant quantities and due to the requirement for electricity generators to maintain sufficient capacity to meet customers' demands, and is also available for physically settled commodity contracts if certain criteria are met.


Information regarding guarantees has been disclosed in the Liquidity and Capital Resources section.

RELATED PARTY TRANSACTIONS

For the period November 2002 to November 2007, TA Cogen entered into a transportation swap transaction with a wholly owned subsidiary of TransAlta Corporation.  The business purpose of the transportation swap was to provide TA Cogen with the delivery of fixed-price gas without being exposed to escalating costs of pipeline transportation for two of its plants over the period of the swap.  This stabilizes cash distributions in TA Cogen and thereby preserves the value of the limited partnership as a financing vehicle of TransAlta Corporation.  The notional gas volume in the transaction was the total delivered fuel for both facilities.  Exchange amounts are based on the market value of the contract.  TransAlta entered into an offsetting contract with an external third party.


 

In 2001, the corporation sold its 60 per cent interest in its Fort Saskatchewan plant to TA Cogen.  Total cash consideration to the corporation was $35.0 million in respect of the 30 per cent interest effectively sold to the minority interest in TA Cogen.  The corporation recorded a pre-tax gain of $6.2 million.  The business purpose of the arrangement was to realize a portion of the inherent value of the plant and provide cash for future growth initiatives while retaining control and operation of the asset through a management agreement with TA Cogen.  The exchange amount was determined based on an estimate of the future net cash flows of the plant and approved by the independent directors of TA Cogen.  There are no ongoing contractual commitments or arrangements resulting from this sale apart from the provision of operational and management services under normal commercial terms.

In 2000, TA Cogen entered into a fixed-for-floating gas swap transaction with TransAlta Energy, for a 61-month period starting Dec. 1, 2000.  The business purpose of the swap was to provide TA Cogen with fixed-price gas for two of its plants over the period of the swap to stabilize cash distributions.  The floating prices associated with the plants' long-term fuel supply agreements were transferred to TransAlta Energy's account.  The notional gas volume in the transaction was the total delivered fuel for both facilities.  As consideration and in negotiation, TA Cogen transferred the right to incremental revenues associated with curtailed electrical production and subsequent higher revenue gas sales to TransAlta Energy.  Exchange amounts were based on the fair value of the contract and approved by the independent directors of TA Cogen.

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

RISK FACTORS AND RISK MANAGEMENT

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


The Audit and Environment (A&E) Committee of the Board of Directors oversees corporate-wide risk management through review of TransAlta's overall business risks.  The Chief Financial Officer (CFO) reports to the A&E Committee and is responsible for ensuring compliance with TransAlta's financial and commodity risk exposure management policies.  These policies include limits on exposures (commodity prices, currency, credit and interest rates), reporting practices and other procedures necessary for the corporation to manage and control its financial and commodity exposures.



 

The Exposure Management (EM) Committee is chaired by the CFO and is comprised of the Directors of Financial Operations for each business unit, the Vice-President and Treasurer, Vice-President and Comptroller, Director of Internal Audit, Vice-President of TransAlta Energy Marketing and the Manager of Treasury Operations.  The EM Committee is responsible for the review, monitoring and reporting on compliance of these financial and commodity risk exposure management policies.  


The following addresses some, but not all, risk factors that could affect TransAlta's future results.  A discussion of critical estimates made in the application of accounting policies is provided in the Critical Accounting Policies and Estimates section that follows.


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


Electricity generation is exposed to price fluctuations of electricity sold to the market and natural gas used in generating electricity.  In addition to the PPAs, the corporation has entered into a variety of short- and long-term contracts to limit its exposure to short-term price movements and maximize overall revenues.  In 2002, 90 per cent (2001 - 92 per cent) of total output was at contractually fixed prices, 62 per cent (2001 - 68 per cent) of TransAlta's cost of gas used in generating electricity was contractually fixed or passed through to customers and 100 per cent (2001 - 100 per cent) of the corporation's purchased coal costs were contractually fixed.  In the event of an unplanned plant outage or other similar event, however, the corporation is exposed to electricity prices on purchases of electricity from the market to fulfill its supply obligations under these short- and long-term contracts.  The corporation actively mitigates this exposure through continued and proper maintenance of its electricity generating plants, force majeure clauses negotiated in the contracts, trading activities and insurance.


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


VAR is the primary measure used to manage Energy Marketing's exposure to market risk resulting from trading activities.  VAR is monitored on a daily basis, and is used to determine the potential change in the value of the corporation's marketing portfolio over a three-day period within a 95 per cent confidence level resulting from normal market fluctuations.  Stress tests are performed weekly on earnings and VAR to measure the potential effects of various market events that could impact earnings, including substantial fluctuations in commodity prices, volatility of those prices, and relationships between markets.  


The corporation estimates VAR using the historical variance/covariance approach.  Currently, there is no uniform energy industry methodology for estimating VAR.  An inherent limitation of historical variance/covariance VAR is that historical information used in the estimate may not be indicative of future market risk.  



An emerging view of VAR is to look at the number on a 99 per cent confidence interval over a 10-day holding period.  For comparison purposes, the following table provides this average daily VAR of the corporation's marketing portfolio for 2002 and 2001:


   

2002

2001

10-day average VAR - 99 per cent confidence level

$6.6

$3.2



CURRENCY RATE EXPOSURE The corporation has exposure to various currencies as a result of its investments and operations in foreign jurisdictions and the acquisition of equipment and services from foreign suppliers. The corporation has exposures primarily to the U.S. and Australian currencies. These exposures are managed through the use of a variety of hedging instruments including cross-currency interest rate swaps and foreign currency forward sales contracts.  At Dec. 31, 2002, the corporation had hedged approximately 94 per cent (2001 - 98 per cent) of its currency rate exposures on a pre-tax basis.


Translation gains and losses related to the carrying value of the corporation's foreign operations are deferred and included in the cumulative translation account in shareholders' equity. At Dec. 31, 2002, the balance in this account was a loss of $18.8 million compared to a $19.5 million loss at the end of 2001.


CREDIT RISK The corporation actively manages its exposure to credit risk by assessing the ability of counterparties to fulfill their obligations under the related contracts prior to entering into such contracts.  The corporation sets strict credit limits for each counterparty and the mix of counterparties based on their credit ratings and halts trading activities with a counterparty if the limits are exceeded.  


TransAlta is exposed to minimal credit risk for Alberta Generation PPAs because under the terms of these arrangements all receivables are guaranteed by the Alberta government.


A summary of the corporation's credit risk exposure for its trading operations at Dec. 31, 2002, including asset-backed trading is provided below:


Rating

 

Exposure Before Credit Collateral

Credit Collateral

Net Exposure

Number of Counterparties Greater than 10%

Net Exposure of Counterparties Greater than 10%

Investment grade

 

 $      111.4

 

 $            -   

 

 $    111.4

 

 $                   -   

 

 $                     -   

Non-investment grade

 

           14.9

 

           7.4

 

          7.5

 

                     -   

 

                        -   

No external rating, internally rated - investment grade

                     20.6

 

                     0.6

 

                  20.0

 

                                   -   

 

                                   -   

   

 $      146.9

 

 $        8.0

 

 $    138.9

 

 $                   -   

 

 $                     -   



In the fourth quarter of 2000, TransAlta recorded a provision of US$28.8 million against US$58.0 million owing from the California Power Exchange Corp. and the California Independent System Operator.  During 2001, approximately US$5.0 million was collected.  No change has been made to the provision due to the continuing uncertainty in California.  Ultimate collection of the net receivable is expected.  

 



The maximum credit exposure to any one customer, excluding the California Independent System Operator and California Power Exchange Corp. discussed above, and including the fair value of open trading positions, is $26.1 million receivable from Ontario Hydro.


LIQUIDITY RISK TransAlta is exposed to funding liquidity risk under certain electricity and natural gas purchase and sale contracts entered into for the purposes of hedging or proprietary trading.  Funding liquidity risk relates to TransAlta's ability to meet margin and collateral requirements of these contracts.  The terms and conditions of these contracts require TransAlta to provide collateral when the fair value of these contracts is both negative (out-of-the-money) and in excess of any credit limits granted by TransAlta's counterparties.  The fair value of these contracts change due to changes in commodity prices and foreign exchange rates.  These contracts are out-of-the-money in these circumstances: (i) for purchase agreements, when forward commodity prices are less than contracted prices; and (ii) for sales agreements, when forward commodity prices exceed contracted prices.    Downgrades in TransAlta's creditworthiness may decrease the credit limits granted by TransAlta's counterparties.


In the absence of any credit limits granted by TransAlta's counterparties, TransAlta's maximum collateral requirements would have been $492.0 million at Dec. 31, 2002 if the corporation's credit ratings were below investment grade.  Collateral available was approximately $1 billion.


INTEREST RATE EXPOSURE The corporation has exposure to movements in interest rates and manages this exposure by maintaining a limit on the amount of debt subject to floating interest rates. At Dec. 31, 2002, approximately 25 per cent of the corporation's total debt portfolio was subject to movements in floating interest rates through a combination of floating rate debt and interest rate swaps.


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


Approximately 54 per cent of the corporation's labour force is covered under collective bargaining agreements.  The agreements of approximately 56 per cent of this unionized labour force are being negotiated during 2003.  Management does not anticipate any significant issues in the renegotiations of these agreements.


The construction and development of generating facilities and acquisition activities are subject to various environmental, engineering, and construction risks relating to cost-overruns, delays and performance.  The corporation attempts to minimize these risks by performing detailed analysis of project economics prior to construction or acquisition and by securing favourable power sales agreements.


The corporation's fuel supply and fuel costs for gas-fired plants are managed with short-, medium- and long-term gas supply contracts, gas hedging transactions, and contractual agreements that provide for the flow-through of gas costs.  The corporation believes adequate supplies of natural gas at reasonable prices will be available for plants when existing supply contracts expire.

 


 


ENVIRONMENTAL, HEALTH AND SAFETY RISK TransAlta's approach is to continually improve the management of operational risks in the areas of environment, health and safety while developing mechanisms to manage future risks.  These programs are integrated into the operations and management systems of the company and are designed to mitigate the potential competitive risks to its fossil-fuelled generation plants from future changes in public policy.  TransAlta's programs may include changes to environmental controls, regulatory regimes, taxes or charges to meet due diligence requirements and to enhance environmental performance through implementing systems and standards such as ISO 14001.


TransAlta's environmental strategy addresses the following key areas: reducing net emissions; participating in provincial, federal and international policy development; contributing to research and development; investing in renewable energy; and testing market-based approaches that deliver real environmental benefits, such as the trading of emission reduction credits.


TransAlta strives to maintain compliance with all environmental, health and safety regulations relating to its operations and facilities.  If regulations were to change however, the operational and financial impact on all plants would need to be assessed.  Outcomes may include, but are not limited to: increased compliance, maintenance or capital costs; plant impairment charges; or the decommissioning of certain facilities.


On Dec. 16, 2002, the Canadian government ratified the Kyoto Protocol.  TransAlta is not able to estimate the full impact the ratification will have on its business, as the government has not yet established an implementation plan.  However, the PPAs for TransAlta's coal-fired plants in Alberta contain 'Change of 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.  In 2002, as part of this strategy, TransAlta purchased the remaining interest in Vision Quest, a company that uses wind-based technology to generate electricity.  TransAlta also made substantial investments in technology upgrades at the Centralia plant to significantly improve environmental performance by reducing emissions.


All TransAlta facilities undergo compliance and management system integrity audits on a cycle determined by facility performance, which on average, is once every three years.  The Dow Jones Sustainability Indexes have again recognized TransAlta as one of the world's best utility companies in terms of environmental, health and safety performance, and TransAlta has also been recognized on the FTSE4 (Financial Times Stock Exchange) Good Global Index, a London-based sustainability index.


REGULATORY AND POLITICAL RISK Regulatory and political risks exist in the jurisdictions in which TransAlta operates.  TransAlta manages these risks by working with regulators and other stakeholders to attempt to resolve issues as fairly and expeditiously as possible.  Legislation was passed in Ontario in late 2002 capping retail market prices at $43 per MWh.  Wholesale market prices have not been directly impacted by this decision; however, liquidity has decreased in the Ontario market as a result.


International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the respective country.  This risk is mitigated through the use of non-recourse financing and political risk insurance.



 

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


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


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


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


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


OTHER CONTINGENCIES The corporation maintains a level of insurance coverage deemed appropriate by management and for matters for which insurance coverage can be maintained.  There were no significant changes to TransAlta's insurance coverage during 2002 except for the discontinuance of coverage for terrorist acts, which is no longer available from insurance providers.


SENSITIVITY ANALYSIS The following table shows the effect on net earnings and cash flows of changes in certain key variables.  The analysis is based on business conditions and production volumes in 2002.  Each separate item in the sensitivity assumes the others are held constant.  While these sensitivities are applicable to the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances, or for greater magnitude of changes.

 



     

Approximate impact

Factor

Change

 

Cash flow

 

Earnings (after-tax)

           

Electricity price

$1.00/MWh

 

 $    2.9

 

 $      2.9

Natural gas price

$0.1/mmBtu

 

 (0.7)

 

 (0.7)

Availability

1%

 

       8.9

 

         8.9

Production

1%

 

       7.7

 

         7.7

Exchange rate (US$ per Cdn$)

US$0.01

 

        -   

 

          -   

Interest rate

1%

 

       2.5

 

         2.5


The impact of a $1.00 per MWh change in electricity prices has minimal impact on cash flow and after-tax earnings as approximately 90 per cent of output is fixed under long-term contracts.  A change in natural gas prices also has minimal impact as 62 per cent of gas costs have been contractually fixed or flow through to customers under terms of agreements.  


A one per cent change in availability has a greater impact on cash flow and after-tax earnings than a one per cent change in production because a change in availability impacts both production levels attainable and capacity payments received for achieving specific availability levels as defined in PPAs.  A change in production affects actual output levels and corresponding revenues.


TransAlta's hedging strategies have minimized the impact of changes in exchange rates and interest rates as the corporation's net investments in foreign operations have been hedged and interest rates on approximately 75 per cent of TransAlta's debt have been fixed.


CRITICAL ACCOUNTING POLICIES AND ESTIMATES


The selection and application of accounting policies is an important process that has developed as TransAlta's business activities have evolved and as accounting rules have changed.  Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment relative to the circumstances existing in the corporation's business.  Every effort is made to comply with all applicable rules on or before the effective date, and TransAlta believes the proper implementation and consistent application of accounting rules is critical.  However, not all situations are specifically addressed in the accounting literature.  In these cases, the corporation's best judgment is used to adopt a policy for accounting for these situations.  This is accomplished by analogizing to similar situations and the accounting guidelines governing them, and consultation with the corporation's independent auditors about the appropriate interpretation and application of these policies.  Each of the critical accounting policies involve s complex situations and a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact the corporation's financial statements.


TransAlta's significant accounting policies are described in Note 1 to the consolidated financial statements.  The most critical of these policies are those related to revenue recognition, property, plant and equipment, goodwill, income taxes and employee future benefits (Notes 1(D), (G), (H), (L) and (M), respectively).  Each policy involves a number of estimates and assumptions to be made by management about matters that are highly uncertain at the time the estimate is made.  Different estimates, with respect to key variables the corporation used for the calculations, or changes to estimates could potentially have a material impact on TransAlta's financial position or results of operations.  These critical accounting estimates are described below.

 



Management has discussed the development and selection of these critical accounting estimates with the A&E committee and the corporation's independent auditors.  The A&E committee has reviewed and approved the corporation's disclosure relating to critical accounting estimates in this MD&A.


Tables are provided in the following discussion to reflect the sensitivities associated with changes in key assumptions used in the estimates.  The tables reflect an increase or decrease in the percentage or other factor for each assumption.  The inverse of each change is expected to have a similar opposite impact.  Each separate item in the sensitivity assumes all other factors remain constant.


Revenue recognition


The majority of the corporation's revenues are derived from the sale of physical power and from Energy Marketing and risk management activities.  Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components:  fixed capacity payments for being available, energy payments for generation of electricity, availability payments or penalties for exceeding or not meeting availability targets, excess energy payments for power generation above committed capacity and ancillary services.  Each is recognized upon output, delivery, or satisfaction of specific targets, as specified by contractual terms.  Revenues from non-contracted capacity are comprised of energy payments for each MWh produced at market prices, and is recognized upon delivery or output to the customer.  


Trading activities use derivatives such as physical and financial swaps, forward sales contracts, futures contracts and options, which are used to earn trading revenues and to gain market information.  Under Canadian GAAP, these derivatives are accounted for using fair value accounting and are presented on a net basis in the statements of earnings.  The initial recognition of fair value and subsequent changes in fair value affect reported earnings in the period the change occurs.  The fair values of those instruments that remain open at the balance sheet date represent unrealized gains or losses and are presented on the balance sheets as price risk management assets and liabilities.  Non-derivative contracts entered into subsequent to the rescission of EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, are accounted for using the accrual method.  Prior to the rescission, mark-to-model accounting was used for non-derivative contracts.


The determination of the fair value of energy trading contracts and derivative instruments is complex and relies on judgments concerning future prices, volatility and liquidity, among other factors.  Some derivatives have quoted market prices from the New York Mercantile Exchange , or over-the-counter quotes are available from brokers.  However, some derivatives are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available.  These derivatives require the use of internal valuation techniques or models (mark-to-model accounting).  



 

Mark-to-model accounting is currently used for physical and financial forward contracts and option contracts on transmission and transmission congestion, other than transmission rights acquired to sell production from TransAlta plants, and physical transmission rights used by the Energy Marketing segment.  Changes in fair value of derivatives subsequent to inception are recorded on the balance sheet as price risk management assets or liabilities with the offset recorded in revenues.  The values can be favourable or unfavourable, and depending on current market conditions, values can fluctuate significantly, with the effect of changes being recorded through earnings in the period of the change.  Modelling techniques require the corporation to model future prices, price correlation, market volatility, liquidity and other forecasted market intelligence as well as the use of mathematical extrapolation techniques.  Where appropriate, the estimates used to derive fair value reflect the potential impact for uncertainties in the modelling process, the potential impact of liquidating the corporation's position in an orderly manner over a reasonable period of time under present market conditions and operational risk.  TransAlta validates its mark-to-model results by comparing against settled data.  The amounts reported in the financial statements may change as estimates are revised to reflect actual results or new information, changes in market conditions or other factors, many of which are beyond the control of the corporation, and may be material.  


Key variables used in the models are uncertain.  The estimated value of these contracts at Dec. 31, 2002 using mark-to-model methodology was $1.6 million.  Sensitivities of the valuation, which would have been recorded in earnings in the current period, are as follows:


Assumption

Change in assumption

Impact on pre-tax earnings

Change in volatility

1%

$                -

Change in commodity price

1%

0.1


There have been no significant changes to the modelling techniques in the past three years.



Valuation of property, plant and equipment


In the fourth quarter of 2002, TransAlta adopted the CICA's new impairment standard, which harmonizes Canadian standards with the U.S. standard.  These standards require the corporation to determine whether the net carrying amount of property, plant and equipment (PP&E) is recoverable from future cash flows.  Factors which could indicate that an impairment exists include significant underperformance relative to historical or projected future operating results, significant changes in the manner or use of the assets, the strategy for the corporation's overall business and significant negative industry or economic trends.  In some cases, these events are clear.  However, in many cases, a clearly identifiable event indicating possible impairment does not occur.  Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired.  This can be further complicated in situations where TransAlta is not the operator of the project.  Events can occur in these situations that may not be known until a date subsequent to their occurrence.  



 

The corporation's businesses, the market and business environment are continually monitored, and judgments and assessments are made to determine whether an event has occurred that indicates possible impairment.  If such an event has occurred, an estimate is made of the future undiscounted cash flows from the asset.  If the total of the undiscounted future cash flows, excluding financing charges, is less than the carrying amount of the asset, an asset impairment must be recognized in the financial statements.  The amount of the impairment recognized is calculated by subtracting the fair value of the asset from the carrying value of the asset.  Fair value is the amount at which an item could be bought or sold in a current transaction between willing parties, and is best estimated by calculating the net present value of future expected cash flows related to the asset.  Both the identification of events that may trigger an impairment and the estimates of future cash flows and the fair value of the asset require considerable judgment.


PP&E makes up 81 per cent of the corporation's assets, of which 96 per cent relate to the Generation segment.  Plants are reviewed for impairment when conditions of impairment exist.  Unit three of the Wabamun plant experienced an unplanned outage in the fourth quarter of 2002.  The significant amount of capital required to return the unit to service and the pending expiration of the PPA indicated that an impairment may exist, therefore this plant was reviewed for impairment.  The corporation determined that the undiscounted sum of the expected future cash flows from the Wabamun plant was less than the carrying value of the asset, therefore an impairment charge of $110.0 million pre-tax was recognized in the fourth quarter of 2002.  The Big Hanaford and Sarnia plants are primarily merchant plants.  As spark spreads have declined significantly in each of the plants' respective markets, an impairment test was performed for each of the plants.  For both plants, the corporation determined that the undiscounted sum of the expected future cash flows exceeded the carrying values, so no impairment charges were recognized.  No other plants showed indications of impairment.  


The assessment of asset impairment requires management to make significant assumptions about future sales prices, cost of sales, production and fuel consumed over the life of the plants (up to 30 years), retirement costs and discount rates.  In addition, when impairment tests are performed, the estimated useful lives of the plants are reassessed, with any change accounted for prospectively.  


In estimating future cash flows of the plants, the corporation used estimates based on contracted and future market prices based on expected market supply and demand in the region in which the plant operates, anticipated production levels, planned and unplanned outages, and transmission capacity or constraints for the remaining life of the plant.  Actual results can, and often do, differ from the estimates, and can have either a positive or negative impact on the estimate of the impairment charge, and may be material.  


Estimates of future cash flows for the Wabamun plant reflect sustained historical availability and production levels throughout 2003, except for unit three, which was decommissioned in the fourth quarter of 2002.  In 2004, units one and two are assumed to be retired while unit four is assumed to operate until 2010 at availability levels reflective of historical capability and age-related outage factors.  Revenues between 2004 and 2010 assume market-based pricing.  Fuel and plant operating costs reflect operating levels.  Sensitivities for the major assumptions are as follows:



   

Assumption

Change in assumption (%)

Impact on impairment charge (pre-tax)

Electricity prices

10

$       19.0

Fuel prices

10

$         4.0

Volumes produced

3

$       12.0

Discount rate

3

$         6.0



Undiscounted future cash flows for the Sarnia and Big Hanaford plants are calculated based on the corporation's forward view of spark spreads at Dec. 31, 2002, which are expected to compress in the near term, and to recover in the medium to long term.  Because the plants only operate when spark spreads are above certain levels to recover variable costs, fluctuations in electricity prices and natural gas prices will also affect production levels.  Therefore, the calculation of sensitivities of changes in these variables, with all other variables remaining constant, will not produce a meaningful result.  


At Dec. 31, 2002, the carrying values of the Sarnia and Big Hanaford plants were $473.3 million and $307.7 million, respectively.  


Useful life of Property, Plant and Equipment


A significant amount of the corporation's assets are PP&E related to the corporation's generating and mining activities (79 per cent).  PP&E is depreciated over its estimated useful life.  The estimated useful lives were determined based on current facts and past experience, and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand and the potential for technological obsolescence.  Major components of plants are depreciated over their own useful lives.  A component is a tangible asset that can be separately identified as an asset, and is expected to provide a benefit of greater than one year.  


Depreciation and amortization expense was $256.1 million in 2002, of which $37.1 million relates to mining equipment, and is included in fuel and purchased power.


The rates used are reviewed on an ongoing basis to ensure they continue to be appropriate, and are also reviewed in conjunction with impairment testing, as discussed above.  


A five per cent change in the estimated useful life of depreciable assets will result in a change of $13.3 million in depreciation and amortization expense.


Valuation of goodwill


The corporation evaluates goodwill for impairment at least annually, or more frequently if indicators of impairment exist.  If the carrying value of a reporting unit including goodwill exceeds the reporting unit's fair value, any excess represents the impairment loss.  


Goodwill was recorded on the acquisition of MEGA, completed in 2001, and on the acquisition of Vision Quest, completed in 2002 (Note 5).  At Dec. 31, 2002, this goodwill had a total carrying value of $56.5 million.  Additional goodwill will be recorded as a result of the January 2003 acquisition of CE Gen (Note 26).



 

The corporation reviewed the $29.3 million of goodwill related to the MEGA acquisition on initial adoption of the new goodwill standard on Jan. 1, 2002, and in the fourth quarter of 2002 in connection with the corporation's annual impairment test.  To test for impairment, the fair value of the reporting unit to which the goodwill relates, the Energy Marketing segment, was compared to the carrying value of the reporting unit.  The corporation determined that the fair value of the Energy Marketing segment, based on historical cash flows and estimates of future cash flows, exceeded its carrying value, therefore no impairment charge was recorded upon initial adoption or when the annual impairment test was performed.  


The fair value determination of the Energy Marketing segment is susceptible to change from period to period as management is required to make assumptions about future cash flows, trading volumes, margins and operating costs.  Future cash flow estimates for the Energy Marketing segment assume that future margins in the Energy Marketing segment remain consistent with 2002, therefore there is no impairment issue.  Had the assumption been made that future margins decline by 10 per cent from current levels, there would not have been any impairment of goodwill. To the extent goodwill is impaired, the impairment charge would impact earnings in the period of the charge, but would not have a material impact on liquidity and capital resources as the corporation would be within its debt covenants.  


Goodwill will be tested annually for impairment in the fourth quarter of each year, or earlier if indicators of impairment exist.  


Income taxes


In accordance with Canadian GAAP, the corporation uses the liability method of accounting for future income taxes and provides future income taxes for all significant income tax temporary differences.  The Canadian standard is substantially the same as the U.S. standard.


Preparation of the consolidated financial statements requires an estimate of income taxes in each of the jurisdictions in which the corporation operates.  The process involves an estimate of the corporation's actual current tax exposure and an assessment of temporary differences resulting from differing treatment of items, such as depreciation and amortization, for tax and accounting purposes.  These differences result in future tax assets and liabilities which are included in the corporation's consolidated balance sheet.  


An assessment must also be made to determine the likelihood that the corporation's future tax assets will be recovered from future taxable income.  To the extent that recovery is not considered likely, a valuation allowance must be determined.  Judgment is required in determining the provision for income taxes, future income tax assets and liabilities and any related valuation allowance.  To the extent a valuation allowance is created or revised, current period earnings will be affected.


Future tax assets of $90.9 million have been recorded on the consolidated balance sheet at Dec. 31, 2002.  This is comprised primarily of unrealized losses on electricity trading contracts, future site restoration costs and net operating and capital loss carryforwards.  The corporation believes there will be sufficient taxable income and capital gains that will permit the use of these deductions and carryforwards in the tax jurisdictions where they exist.  



Future tax liabilities of $389.0 million have been recorded on the consolidated balance sheet at Dec. 31, 2002.  The liability is comprised primarily of unrealized gains on electricity trading contracts and income tax deductions in excess of related depreciation of PP&E.  


Judgment is required to assess tax interpretations, regulations and legislation, which are continually changing, to ensure liabilities are complete and to ensure assets, net of valuation allowances, are realizable.  The impact of different interpretations and applications could potentially be material.  


The corporation's tax filings are subject to audit by taxation authorities.  The outcome of some audits may increase the tax liability of the corporation, although management believes that it has adequately provided for income taxes based on all information currently available.  The outcome of the audits is not known, nor is the potential impact on the financial statements determinable.


Employee future benefits


As explained in Note 19 to the consolidated financial statements, the corporation provides post-retirement benefits to employees.  The cost of providing these benefits is dependent upon many factors which result from actual plan experience and assumptions of future experience.  


Pension costs are impacted by actual employee demographics, including age, compensation levels, employment periods, the level of contributions made to the plans and earnings on plan assets.  Changes to the provisions of the plans may also affect current and future pension costs.  Pension costs may also be significantly impacted by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.


The plan assets are comprised primarily of equity and fixed income investments.  Fluctuations in actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.  In addition, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs.  


The following chart reflects the sensitivities associated with a change in certain actuarial assumptions:  


Actuarial assumption

Change in assumption (%)

Impact on projected benefit obligation

Impact on pension cost reported in earnings

Discount rate

1

$         36.6

$         0.6

Rate of return on plan assets

1

-

3.7


The discount rate used represents high-quality fixed income securities currently available and expected to be available during the period to maturity of the pension benefits.  The corporation believes it uses a conservative approach in setting the discount rate and does not expect to make any changes to the rate in 2003.



 

The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan.  The market value of the corporation's plan assets has been affected by recent declines in equity markets.  For the year ended Dec. 31, 2002, the plan assets had a negative return of $6.7 million compared to earnings of $9.9 million in 2001 and $48.9 million in 2000.  The 2002 actuarial valuation used the same rate of return on plan assets (7.0 to 8.5 per cent) as was used in 2001 and 2000.


As a result of the corporation's plan asset return experience for its U.S. registered pension plan, at Dec. 31, 2002, the corporation was required under U.S. GAAP to recognize an additional minimum liability (Note 27).  The liability was recorded as a reduction in common equity through a charge to other comprehensive income (OCI), and did not affect net income for 2002.  The charge to OCI will be restored through common equity in future periods to the extent the fair value of the trust assets exceeds the accumulated benefit obligation.


The amount of the additional pension liability to be recognized at Dec. 31, 2002 for U.S. GAAP depended on a number of factors, including the discount rate and asset returns experienced, contributions made by the corporation and any resulting change in management's assumptions.  In addition, pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets.

 

EMPLOYEE SHARE OWNERSHIP

 

TransAlta employs a variety of stock-based compensation plans to align employee and corporate objectives.  In 2001, the corporation expanded enrolment in the corporation's common share option program to include all Canadian and U.S. employees of the corporation.  At Dec. 31, 2002, 3.2 million options to purchase the corporation's common stock were outstanding with 0.8 million exercisable at the reporting date.


Under the terms of the Performance Share Ownership Plan (PSOP), certain employees receive awards which, after three years, make them eligible to receive a set number of common shares or cash equivalent plus dividends thereon based upon the performance of the corporation relative to a selected group of publicly traded companies.  On Dec. 31, 2001, the plan was modified so that after three years, once PSOP eligibility has been determined, 50 per cent of the shares may be released to the participant, while the remaining 50 per cent will be held in trust for one additional year.  The first PSOP maturity occurred in 2000 with 120,101 common shares issued at $14.15 per share.  In 2001, 83,077 common shares were issued at $22.00 per share. In 2002, 84,578 common shares were issued at $21.60 per share.  At Dec. 31, 2002, there were 1.4 million PSOP awards outstanding.


Under the terms of the Employee Share Purchase Plan, the corporation will extend an interest-free loan to employees of up to 30 per cent of the employee's base salary for the purchase of common shares of the corporation from the open market.  The loan is repaid over a three-year period by the employee through payroll deductions unless the shares are sold, at which point the loan becomes due on demand.  At Dec. 31, 2002, 0.3 million shares had been purchased by employees under this program.

 


 

EMPLOYEE FUTURE BENEFITS


TransAlta has registered pension plans in Canada and the U.S. covering substantially all employees of the corporation, its domestic subsidiaries and specific named employees working internationally. These plans have defined benefit and defined contribution options and in Canada, there is a supplemental defined benefit plan for certain employees. The defined benefit option of the registered pension plan ceased for new employees on June 30, 1998. The latest actuarial valuations of the registered and supplemental pension plans were as at Dec. 31, 2002.  As the Canadian registered plan has a funded surplus, there is no requirement for the corporation to fund the registered plan in 2003.

The corporation provides other health and dental benefits to the age of 65 for both disabled members (other post-employment benefits) and retired members (other post-retirement benefits). The latest actuarial valuation of these other plans was as at April 30, 2002.


The supplemental pension plan is solely the obligation of the corporation.  The corporation is not obligated to fund the supplemental plan but is obligated to pay benefits under the terms of the plan as they come due.  The corporation has posted a letter of credit in the amount of $34.5 million to secure the obligations under the supplemental plan.  

SELECTED QUARTERLY FINANCIAL INFORMATION


(Unaudited; in millions of Canadian dollars except per share amounts)

 
           

2002 Quarters

First

Second

Third

Fourth

Annual

Total revenues

 $    419.7

 $    336.3

 $    450.3

 $    517.6

 $   1,723.9

Earnings (loss) from continuing operations

         45.7

         18.5

         73.4

      (59.6)

           78.0

Net earnings (loss) applicable to common shareholders

         51.4

       124.9

         67.9

        (54.3)

         189.9

Basic earnings (loss) per common share:

       

   Continuing operations

         0.24

         0.08

         0.40

      (0.38)

           0.34

   Net earnings

         0.30

         0.74

         0.40

      (0.32)

           1.12

Diluted earnings (loss) per common share:

       

   Continuing operations

         0.22

         0.07

         0.40

      (0.38)

           0.34

   Net earnings

         0.28

         0.73

         0.40

      (0.32)

           1.12

           

2001 Quarters

First

Second

Third

Fourth

Annual

Total revenues

 $    706.5

 $    605.2

 $    573.3

 $    434.4

 $   2,319.4

Earnings from continuing operations

         59.0

         50.2

         36.7

         36.7

         182.6

Net earnings applicable to common shareholders

         67.6

         59.1

         41.4

         46.5

         214.6

Basic earnings (loss) per common share:

     

   

   Continuing operations

         0.33

         0.28

         0.20

         0.19

           1.00

   Net earnings

         0.40

         0.35

         0.25

         0.27

           1.27

Diluted earnings (loss) per common share:

       

   Continuing operations

         0.32

         0.27

         0.20

         0.19

           0.98

   Net earnings

         0.39

         0.34

         0.25

         0.27

           1.25

 


TransAlta Corporation

Consolidated Financial Statements

Years ended Dec. 31, 2002, 2001 and 2000


MANAGEMENT'S RESPONSIBILITY

TransAlta's management is responsible for presentation and preparation of the annual consolidated financial statements, management's discussion and analysis (MD&A) and all other information in this annual report.  


The accompanying consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and the requirements of the Securities and Exchange Commission (SEC) in the U.S., as applicable.


The MD&A has been prepared in accordance with the requirements of securities regulators including National Instrument 44-101 of the Canadian Securities Administrators as well as Item 303 of Regulation S-K of the Securities Exchange Act, and their related published requirements.  


The consolidated financial statements and information in the MD&A necessarily include amounts based on informed judgements and estimates of the expected effects of current events and transactions with appropriate consideration for materiality.  In addition, in preparing financial information, the corporation must interpret the requirements described above, make determinations as to the relevancy of information to be included, and make estimates and assumptions that affect reported information.  The MD&A also includes information regarding the estimated impact of current transactions and events, sources of liquidity and capital resources, operating trends, risks and uncertainties.  Actual results in the future may differ materially from management's present assessment of this information because future events and circumstances may not occur as expected.


The financial information presented elsewhere in this annual report is consistent with that in the consolidated financial statements.  


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


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


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


TransAlta's Chief Executive Officer and Chief Financial Officer have certified TransAlta Corporation's annual disclosure document filed with the SEC (Form 40-F) as required by the U.S. Sarbanes-Oxley Act.  


Signed by


Stephen G. Snyder                                                                                                                                    Ian A. Bourne
President & Chief Executive Officer                                                                                                    Executive Vice-President & Chief Financial Officer

March 15, 2003




AUDITORS' REPORT

TO THE SHAREHOLDERS OF TRANSALTA CORPORATION  


We have audited the consolidated balance sheets of TransAlta Corporation as at December 31, 2002 and 2001 and the consolidated statements of earnings and retained earnings and cash flows for each of the years in the three year period ended December 31, 2002. These financial statements are the responsibility of the corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the corporation as at December 31, 2002 and 2001 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2002 in accordance with Canadian generally accepted accounting principles.  We also report that, in our opinion, these principles have been applied, except for changes in method of accounting for impairment of long-lived assets, goodwill, foreign currency translation, hedging relationships, stock-based compensation and presentation of trading activities, as described in Note 1(R) to the consolidated financial statements, on a basis consistent with that of the preceding year.  


 


Chartered Accountants
Calgary, Canada

February 1, 2003, except for Note 26, which is as of March 15, 2003




CONSOLIDATED STATEMENTS OF EARNINGS & RETAINED EARNINGS


Years ended Dec. 31

     

(in millions of Canadian dollars except per share amounts)

2002

2001

2000

Revenues

 $   1,723.9

 $    2,319.4

 $    1,671.1

Fuel and purchased power

       (703.6)

     (1,230.6)

        (741.2)

Gross margin

      1,020.3

      1,088.8

         929.9

Operating expenses

     

Operations, maintenance and administration

         420.5

         392.2

         349.9

Depreciation and amortization

         219.0

         191.2

         191.3

Asset impairment and equipment cancellation charges (Note 8)

         152.5

         118.8

              -   

Taxes, other than income taxes

           27.4

           18.7

           23.9

     

         819.4

         720.9

         565.1

Operating income

         200.9

         367.9

         364.8

Other income (expense)

             0.1

             1.5

           (1.1)

Foreign exchange gain

             1.2

             0.8

             0.1

Net interest expense

(82.7)

(88.1)

(91.4)

Earnings from continuing operations before regulatory decisions,

     

income taxes and non-controlling interests

         119.5

         282.1

         272.4

Prior period regulatory decisions (Note 17)

           (3.3)

           11.0

           44.1

Earnings from continuing operations before income taxes

     

and non-controlling interests

         116.2

         293.1

         316.5

Income tax expense (Note 18)

           18.1

           89.9

         128.5

Non-controlling interests (Note 13)

           20.1

           20.6

           41.6

Earnings from continuing operations

           78.0

         182.6

         146.4

Earnings from discontinued operations (Note 3)

           12.8

           45.1

           89.1

Gain on disposal of discontinued operations (Note 3)

         120.0

              -   

         266.8

Net earnings before extraordinary item

         210.8

         227.7

         502.3

Extraordinary item (Note 4)

              -   

              -   

        (209.7)

Net earnings

         210.8

         227.7

         292.6

Preferred securities distributions, net of tax (Note 14)

           20.9

           13.1

           12.8

Net earnings applicable to common shareholders

 $      189.9

 $      214.6

 $      279.8

Common share dividends

(169.0)

(168.4)

(168.7)

Adjustment arising from normal course issuer bid (Note 15)

(27.0)

(34.8)

(7.5)

Retained earnings

     

Opening balance

         838.3

         826.9

         723.3

Closing balance

 $      832.2

 $      838.3

 $      826.9

           

Weighted average common shares outstanding in the period

         169.6

         168.9

         168.8

           

Basic earnings per share (Notes 14 and 15)

     

Continuing operations

 $        0.34

 $        1.00

 $        0.79

Earnings from discontinued operations (Note 3)

           0.07

           0.27

           0.53

Net earnings from operations

           0.41

           1.27

           1.32

Gain on disposal of discontinued operations (Note 3)

           0.71

              -   

           1.58

Extraordinary item (Note 4)

              -   

              -   

         (1.24)

Net earnings

 $        1.12

 $        1.27

 $        1.66

           

Diluted earnings per share (Notes 14 and 15)

     

Earnings from continuing operations

 $        0.34

 $        0.98

 $        0.77

Earnings from discontinued operations (Note 3)

           0.07

           0.27

           0.53

Net earnings from operations

           0.41

           1.25

           1.30

Gain on disposal of discontinued operations (Note 3)

           0.71

              -

           1.58

Extraordinary item (Note 4)

              -   

              -   

         (1.24)

Net earnings

 $        1.12

 $        1.25

 $        1.64

   

See accompanying notes.

     

 


 

 

CONSOLIDATED BALANCE SHEETS

Dec. 31

   

(in millions of Canadian dollars)

2002

2001

Assets

   

Current assets

   

Cash and cash equivalents

 $    143.3

 $        62.0

Accounts receivable and other

       468.4

         625.3

Price risk management assets (Note 20)

       157.8

         137.6

Future income tax assets (Note 18)

          18.7

           16.9

Income taxes receivable

       111.5

         128.3

Materials and supplies at average cost

       112.7

           85.5

     

    1,012.4

      1,055.6

Investments (Note 6)

          32.2

           37.3

Long-term receivables (Note 7)

          39.9

         221.4

Property, plant and equipment (Note 8)

   

Cost

 

    8,124.9

      8,766.7

Accumulated depreciation

(2,089.8)

(2,671.9)

     

    6,035.1

      6,094.8

Goodwill (Note 5)

          56.5

           29.3

Future income tax assets (Note 18)

          72.2

           15.6

Price risk management assets (Note 20)

          60.7

           71.3

Other assets (Note 9)

       110.6

           81.1

Total assets

 $ 7,419.6

 $   7,606.4

         

Liabilities and shareholders' equity

   

Current liabilities

   

Short-term debt (Note 10)

 $    290.0

 $      537.2

Accounts payable and accrued liabilities

       472.2

         627.5

Price risk management liabilities (Note 20)

       173.8

         114.1

Future income tax liabilities (Note 18)

          17.1

           11.8

Dividends payable

          42.9

           42.8

Current portion of long-term debt (Note 11)

       355.4

         104.3

     

    1,351.4

      1,437.7

Long-term debt (Note 11)

    2,351.2

      2,406.8

Deferred credits and other long-term liabilities (Note 12)

       540.2

         560.5

Future income tax liabilities (Note 18)

       371.9

         409.1

Price risk management liabilities (Note 20)

          50.6

           69.0

Non-controlling interests (Note 13)

       263.0

         281.0

Preferred securities (Note 14)

       451.7

         452.6

Common shareholders' equity

   

Common shares (Note 15)

    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

Commitments and contingencies (Notes 23 and 24)

   

Subsequent events (Note 26)

   




On behalf of the board:

 

 

 

Signed by
John T. Ferguson
Director

Signed by
John S. Lane
Director

 


 

 

CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended Dec. 31

     

(in millions of Canadian dollars)

2002

2001

2000

           

Operating activities

     

 Net earnings

 $210.8

 $  227.7

 $    292.6

 Depreciation and amortization (Note 2)

       314.8

        312.3

       353.0

 Asset impairment and equipment cancellation charges (Note 8)

       152.5

          66.5

         17.9

 Non-controlling interests (Note 13)

         20.1

          20.6

         44.6

 Loss (gain) on sale of property, plant and equipment

         15.6

           (5.4)

     (284.9)

 Site restoration costs incurred

      (15.6)

         (14.8)

        (4.2)

 Future income taxes (recovery) (Note 18)

      (60.4)

          39.9

         34.1

 Unrealized gain from energy marketing activities (Note 20)

        (7.6)

           (6.3)

       (24.0)

 Gain on disposal of Transmission operation (Note 3)

    (120.0)

              -   

              -   

 Extraordinary item (Note 4)

             -   

              -   

        209.7

 Other non-cash items

      (23.1)

            9.5

        (26.1)

     

       487.1

        650.0

        612.7

Change in non-cash operating working capital balances

      (49.4)

          65.6

      (414.0)

 Cash flow from operating activities

       437.7

        715.6

        198.7

Investing activities

     

 Additions to property, plant and equipment

    (945.8)

    (1,246.5)

      (795.0)

 Acquisitions (Note 5)

      (40.1)

           (9.8)

      (880.1)

 Proceeds on sale of property, plant and equipment to TransAlta Cogeneration, L.P. (Note 5)

             -   

          35.0

              -   

 Disposals (Notes 3 and 5)

       818.0

          97.0

     1,367.0

 Proceeds on sale of property, plant and equipment

           2.3

        104.6

              -   

 Long-term receivables

       165.3

         (46.3)

          12.1

 Long-term investments

        (6.1)

              -   

          (9.5)

 Restricted investments

             -   

              -   

          86.8

 Deferred charges and other

      (29.8)

         (10.9)

          13.7

 Cash flow used in investing activities

      (36.2)

    (1,076.9)

      (205.0)

Financing activities

     

 Net increase (decrease) in short-term debt

    (247.1)

          61.9

        255.7

 Issuance of long-term debt

       611.3

        789.9

        330.8

 Repayment of long-term debt

    (454.5)

       (292.7)

      (204.6)

 Redemption of preferred shares of a subsidiary

             -   

       (122.1)

      (146.8)

 Issuance of common shares

           1.8

          14.1

            4.6

 Redemption of common shares

      (49.9)

         (44.4)

        (23.9)

 Distributions on preferred securities

      (34.9)

         (23.4)

        (22.1)

 Dividends on common shares

    (115.5)

       (149.6)

      (158.4)

 Net proceeds on issuance of preferred securities

             -   

        169.4

              -   

 Dividends to subsidiary's non-controlling preferred shareholders

             -   

           (8.3)

        (14.8)

 Dividends to subsidiary's non-controlling common shareholders

             -   

              -   

          (7.0)

 Distributions to subsidiary's non-controlling limited partner

      (24.5)

         (26.3)

        (21.0)

 Deferred financing charges and other

        (7.6)

            0.2

            4.8

 Cash flow from (used in) financing activities

    (320.9)

        368.7

          (2.7)

Cash flow from (used in) operating, investing and financing activities

         80.6

            7.4

         (9.0)

Effect of translation on foreign currency cash

           0.7

            0.8

       (12.5)

Increase (decrease) in cash and cash equivalents

         81.3

            8.2

       (21.5)

Cash and cash equivalents, beginning of year

         62.0

          53.8

          75.3

Cash and cash equivalents, end of year

 $143.3

 $    62.0

 $       53.8

           

Cash taxes paid

 $123.1

 $    41.5

 $     140.3

Cash interest paid

 $210.8

 $  163.1

 $     173.2

           

See accompanying notes.

     
           

1  The change in non-cash operating working capital balances and cash flow from operating activities for the year ended December 31, 2000 includes the impact of increased deferral accounts receivable for the discontinued  Alberta Distribution and Retail business operation  until the date of disposal on August 31, 2000.  The related proceeds from the disposal of these deferral accounts receivable, totalling $164.3 million are classified as cash provided by investing activities, of which $** million was received in 2002 ( 2000 - $24.2 million) (Note 3).


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1.  Summary of significant accounting policies

A.  CONSOLIDATION


These consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles (Canadian GAAP).  These accounting principles are different in some respects from United States generally accepted accounting principles (U.S. GAAP).  The significant differences are described in Note 27.  


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


TransAlta Utilities owns and operates electric generation in the province of Alberta.  TransAlta Utilities also owned and operated transmission facilities and a distribution and retail (D&R) operation in Alberta.  The Transmission operation was disposed of on April 29, 2002, and the D&R operation was disposed of on Aug. 31, 2000.  TransAlta Energy is engaged in electric and thermal energy supply, energy services and energy marketing in Canada, the U.S., Mexico and Australia.  TransAlta Energy also owned and operated an electricity generation and retail operation in New Zealand until the operations were disposed of on March 31, 2000 (Note 3).


B.  MEASUREMENT UNCERTAINTY


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


C.  REGULATION

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


D.  REVENUE RECOGNITION

The majority of the corporation's revenues are derived from the sale of physical power and from energy marketing and trading activities.  Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components:  fixed capacity payments for being available, energy payments for generation of electricity, availability payments or penalties for exceeding or not meeting availability targets, excess energy payments for power generation above committed capacity and ancillary services.  Each is recognized upon output, delivery, or satisfaction of specific targets, all as specified by contractual terms.  Revenues from non-contracted capacity are comprised of energy payments for each MWh produced at market prices, and are recognized upon delivery.


Derivatives used in trading activities include physical and financial swaps, forward sales contracts, futures contracts and options, which are used to earn trading revenues and to gain market information.  Under Canadian GAAP, these derivatives are accounted for using the fair value method of accounting and are presented on a net basis in the statements of earnings.  The initial recognition of fair value and subsequent changes in fair value affect reported earnings in the period the change occurs.  The fair values of those instruments that remain open at the balance sheet date represent unrealized gains or losses and are presented on the balance sheets as price risk management assets and liabilities.  Non-derivative contracts entered into subsequent to the rescission of EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities are accounted for using the accrual method.  Prior to the rescission of EITF 98-10, non-derivative contracts were accounted for using mark-to-model accounting.

 



Some derivatives have quoted market prices or over-the-counter quotes are available from brokers.  However some derivatives are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available, requiring the use of internal valuation techniques or models (mark-to-model accounting).  

 

Under U.S. GAAP, trading activities are accounted for in accordance with Statement 133, Accounting for Derivative Instruments and Hedging Activities, which is described in greater detail in Note 1(O).  


E.  DISCONTINUED OPERATIONS

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


F.  MATERIALS AND SUPPLIES


The corporation's materials and supplies balance includes coal, replacement parts which will be used within one year and operating supplies.  Coal is valued at the lower of cost and market.  Replacement parts are valued using the specific identification method.  


G.  PROPERTY, PLANT AND EQUIPMENT

The corporation's investment in property, plant and equipment (PP&E) is stated at original cost at the time of construction, purchase or acquisition.  Original costs include items such as materials, labour, interest and other appropriately allocated costs.  As costs are expended for new construction, the entire amount is capitalized as PP&E on the consolidated balance sheets and is subject to depreciation upon commencement of commercial operations.  The cost of routine maintenance and repairs, such as inspections and corrosion removal, and the replacement of minor parts, are charged to expense as incurred.  Certain expenditures relating to components incurred during major maintenance are capitalized and amortized over the estimated benefit period of such expenditures.  A component is a tangible portion of the asset that can be separately identified as an asset and depreciated over its own expected useful life, and is expected to provide a benefit of greater than one year.  


The estimate of the useful life of PP&E is based on current facts and past experience, and takes into consideration existing long-term sales agreements and contracts, current and forecasted demand and the potential for technological obsolescence.  The useful life is used to estimate the rate at which the PP&E is amortized.  These estimates are subject to revision in future periods based on new or additional information.  


TransAlta capitalizes interest on capital invested in projects that are under construction.  Upon commencement of plant operations, capitalized interest, as a portion of the total cost of the plant, is amortized over the estimated useful life of the plant.  


The corporation determines those debt instruments that best represent a reasonable measure of the cost of financing the assets under construction.  These debt instruments and associated interest costs are included in the calculation of the weighted average interest rate used for capitalizing interest.  


In the fourth quarter of 2002, TransAlta early adopted the new Canadian Institute of Chartered Accountants (CICA) impairment standard, which harmonizes the Canadian standard with the U.S. standard (Statement 144).  These standards require the corporation to determine whether the net carrying amount of property, plant and equipment is recoverable from future undiscounted cash flows when indicators of impairment exist.  Factors which could indicate an impairment exists include significant underperformance relative to historical or projected future operating results, significant changes in the manner or use of the assets, the strategy for the corporation's overall business and significant negative industry or economic trends.  In some cases, these events are clear.  However, in many cases, a clearly identifiable event indicating possible impairment does not occur.  Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired.  This can be further complicated where TransAlta is not the operator of the project.  Events can occur in these situations that may not be known until a later date from their occurrence.  


The corporation's businesses, the market and business environment are continually monitored, and judgements and assessments are made to determine whether an event has occurred that indicates possible impairment.  If such an event has occurred, an estimate is made of future undiscounted cash flows from the PP&E.  If the total of the undiscounted future cash flows, excluding financing charges, is less than the carrying amount of the PP&E, an asset impairment must be recognized in the financial statements.  The amount of the impairment to be recognized is calculated by subtracting the fair value of the asset from the carrying value of the asset.  Fair value is the amount at which an item could be bought or sold in a current transaction between willing parties, and is best estimated by calculating the present value of expected future cash flows related to the asset.


The application of the standard in the fourth quarter of 2002 resulted in the recognition of a pre-tax impairment loss of $110.0 million related to the Wabamun plant (Note 8).


H.  GOODWILL


Goodwill is the cost of an acquisition less the fair value of the net assets of an acquired business.  Prior to Jan. 1, 2002, TransAlta amortized goodwill on a straight-line basis over the useful life of the acquired assets.  Effective Jan. 1, 2002, the corporation prospectively adopted the new CICA standard for goodwill and other intangibles.  The new standard requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting.  It also specifies that goodwill and certain intangibles are no longer subject to amortization, but are instead tested for impairment at least annually, or more frequently if an analysis of events and circumstances indicate that a possible impairment issue may arise earlier.  These events could include a significant change in financial position of the reporting unit to which the goodwill relates or significant negative industry or economic trends.  


The adoption of the new standard resulted in the reclassification of $29.3 million from acquired intangibles to goodwill, which is no longer subject to amortization under the new standard.  There was no impairment of goodwill upon adoption of this standard.  Net earnings and earnings per share for the years ended Dec. 31, 2001 and 2000 adjusted to exclude the amortization of the above amount are as follows:

 

Year ended Dec. 31

2001

2000

Reported net earnings applicable to common shareholders

   $            214.6

 $               279.8

Amortization of acquired intangibles

                    7.7

                      9.4

Adjusted net earnings applicable to common shareholders

   $            222.3

 $               289.2

     

Reported basic earnings per share

 $                1.27

 $                 1.66

Amortization of acquired intangibles per share

                   0.05

                    0.06

Adjusted basic earnings per share

 $                1.32

 $                 1.72

     

Reported diluted earnings per share

 $                1.25

 $                 1.64

Amortization of acquired intangibles per share

                   0.05

                    0.06

Adjusted diluted earnings per share

 $                1.30

 $                 1.70



I.  FUTURE SITE RESTORATION COSTS


Future site restoration costs for coal plants are included in fuel and purchased power expense on a straight-line basis over the life of the asset.  Estimated costs to reclaim mining properties are amortized primarily on a unit-of-production basis.  


No provision for future site restoration for gas generation plants is recorded as management estimates the costs of restoration will be offset by the salvage values of the related plant.


The corporation does not provide for the removal costs associated with its hydroelectric generating structures as the costs are not reasonably estimated because of the long service life of these assets.  With either maintenance efforts or rebuilding, the water control structures are assumed to be required for the foreseeable future and therefore, no amounts have been provided for site restoration costs for these facilities. Provisions are made for removal of hydro generating equipment.  


J.  INVESTMENTS


Investments in shares of companies over which the corporation exercises significant influence are accounted for using the equity method.  Other investments are carried at cost.  If there is other than a temporary decline in value of the investment, it is written down to net realizable value.


K.  OTHER ASSETS

Deferred license fees and deferred contract costs are amortized on a straight-line basis over the useful life of the related assets or long-term contracts.  


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

 


 


Other costs capitalized on the balance sheet include business development costs, which includes external, direct and incremental costs which are necessary for completion of a potential acquisition or construction project.  Business development costs are included in operating expenses until construction of a plant or acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable and that efforts will result in future value to the corporation, at which time the future costs are included in PP&E or investments.  The appropriateness of the carrying value of these costs is evaluated each reporting period, and unrecoverable amounts of capitalized costs for projects no longer probable of occurring are charged to expense in the current period.  


L.  INCOME TAXES


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


Under U.S. GAAP, a difference arises as a result of the requirement for income tax balances to reflect currently legislated tax rates rather than substantively enacted tax rates.


M.  EMPLOYEE FUTURE BENEFITS

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


N.  FOREIGN CURRENCY TRANSLATION

The corporation's self-sustaining foreign operations are translated using the current rate method. Translation gains and losses are deferred and included in the cumulative translation adjustment (CTA) account in shareholders' equity.


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 CTA, a separate component of shareholders' equity, therefore this amendment has no impact on TransAlta.


Transactions denominated in foreign currencies are translated at the exchange rate on the transaction date. Foreign currency denominated monetary and non-monetary assets and liabilities are translated at exchange rates in effect on the balance sheet date. The resulting exchange gains and losses on these items are included in net earnings. Gains and losses arising on translation of long-term debt designated as a hedge of self-sustaining foreign operations are deferred and included in CTA in shareholders' equity on a net of tax basis.


O.  DERIVATIVES AND FINANCIAL INSTRUMENTS

In November 2001, the CICA released an accounting guideline on hedging relationships, which specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges.  The guideline also identifies situations where hedge accounting is to be discontinued.  The guideline is effective for years beginning on or after July 1, 2003.  TransAlta has early adopted the guideline effective Jan. 1, 2002 and met the criteria for all hedging relationships with the exception of written swaptions, which are ineffective under the guideline.  Hedge accounting was discontinued for the written swaptions in accordance with the guideline.  The impact on earnings for the year ended Dec. 31, 2002 was a decrease of $2.0 million after-tax.


Derivatives used in trading activities are described in Note 1(D).  

 


 


Physical and financial swaps, forward sales contracts, futures contracts and options are used to hedge the corporation's exposure to fluctuations in electricity and natural gas prices.  Under Canadian GAAP, if hedging criteria are met (described below), gains and losses on these derivatives are deferred and recognized in earnings in the same period and financial statement caption as the hedged exposure (settlement accounting).  The derivatives are not recorded on the balance sheet.


Cross-currency interest rate swaps, foreign currency forward sales contracts and foreign currency long-term debt are used to hedge exposure to changes in the carrying values of the corporation's net investments in foreign operations as a result of changes in foreign exchange rates.  Under Canadian GAAP, gains and losses on the principal component of the cross-currency interest rate swaps as well as gains and losses on the forward sales contracts and foreign currency long-term debt are deferred and included in CTA, a separate component of shareholders' equity, on a net of tax basis.  The principal component of the cross-currency interest rate swaps is deferred and recorded in other assets (Note 9) or deferred credits and other long-term liabilities (Note 12) as appropriate.  The forward sales c