TransAlta Corporation
TSX : TA
NYSE : TAC

TransAlta Corporation

October 20, 2005 09:00 ET

Strong operational performance boosts TransAlta's third quarter results

CALGARY, ALBERTA--(CCNMatthews - Oct. 20, 2005) - TransAlta Corporation (TSX:TA) (NYSE:TAC) :

Third Quarter Highlights:

- Earnings of $0.27 per share compared to $0.18 per share in 2004

- Generated cash flow from operations of $148.5 million

- Higher generation margins, strong operational performance contribute to results

TransAlta Corporation (TSX:TA) (NYSE:TAC) today announced net earnings of $52.1 million ($0.27 per share), compared to $35.8 million ($0.18 per share) for the third quarter 2004. Included in the 2005 third quarter net earnings is a $13.0 million ($0.07 per share) income tax recovery related to prior periods. Cash generated from operating activities for the quarter was $148.5 million, compared to $142.6 million for the comparable quarter in 2004.

"Our operations performed well, increasing both availability and production and allowing us to capture some improving market opportunities," said Steve Snyder, TransAlta president and CEO.

For the nine months ended September 30, 2005, net earnings were $128.6 million or $0.66 per share compared to $108.1 million or $0.56 per share the year prior. Cash flow from operations was $407.5 million for the nine months ending September 30, 2005 versus $415.3 million for the same period in 2004. Capital expenditures during the first nine months of 2005 were $221.9 million compared to $268.1 million for the first nine months of 2004. Net debt was also reduced by $200.4 million at September 30, 2005.



TransAlta consolidated financial highlights

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3 months ended September 30
(In millions except 2005 2004
per share amounts) ----------------------------------------
Amount Per share Amount Per share
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Revenue $ 722.9 $ 678.2
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Net earnings from continuing
operations $ 52.1 $ 0.27 $ 35.8 $ 0.18
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Gain on disposal of
discontinued operation,
net of tax - - - -
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Net earnings $ 52.1 $ 0.27 $ 35.8 $ 0.18
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Comparable earnings(a) $ 39.1 $ 0.20 $ 33.8 $ 0.17
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Cash flow from operating
activities $ 148.5 $ 142.6
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9 months ended September 30
(In millions except 2005 2004
per share amounts) ----------------------------------------
Amount Per share Amount Per share
---------------------------------------------------------------------
Revenue $2,028.4 $1,926.1
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Net earnings from continuing
operations $ 128.6 $ 0.66 $ 98.5 $ 0.51
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Gain on disposal of
discontinued operation,
net of tax - - $ 9.6 $ 0.05
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Net earnings $ 128.6 $ 0.66 $ 108.1 $ 0.56
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Comparable earnings(a) $ 115.6 $ 0.59 $ 97.7 $ 0.51
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Cash flow from operating
activities $ 407.5 $ 415.3
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3 months ended 9 months ended
September 30 September 30
2005 2004 2005 2004
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Availability (%) 89.8 88.0 89.1 88.8
Production (GWh) 13,172 12,685 38,402 38,146
Electricity trading volumes
(GWh) 31,163 25,280 72,516 61,269
Gas trading volumes
(million GJ) 143.7 130.8 298.5 313.7
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(a) Presenting earnings on a comparable basis from period to period provides management with the ability to evaluate earnings trends more readily in comparison with prior periods' results. An explanation of this non-GAAP financial measure can be found on page 16 of the MD&A.

In the third quarter 2005, TransAlta:

- Signed a long-term major maintenance strategic partnership with Alstom Canada.

- Successfully returned to service its 279 megawatt Wabamun unit four plant after a forced shut down of the facility due to the CN train derailment and resulting oil spill into Lake Wabamun, Alberta.

TransAlta will be re-filing its 2004 consolidated financial statements for the sole purpose of restating Note 26 - U.S. GAAP. There was no impact on results reported under Canadian GAAP. Details on the U.S. GAAP restatement can be found on page 15 of the MD&A.

TransAlta is a power generation and wholesale marketing company focused on creating long-term shareholder value. We maintain a low-risk profile for investors by operating a highly contracted portfolio of assets in Canada, the U.S., Mexico and Australia. Our focus is to efficiently operate our coal-fired, gas-fired, hydro and renewable facilities in order to provide our customers with a reliable, low-cost source of power. For more than 90 years, we've been a responsible operator and a proud contributor to the communities where we work and live.

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

This management's discussion and analysis (MD&A) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See page 18 for additional information.

This MD&A should be read in conjunction with the unaudited interim consolidated financial statements of TransAlta Corporation (TransAlta or the corporation) as at and for the three and nine months ended Sept. 30, 2005 and 2004, and should also be read in conjunction with the audited consolidated financial statements and MD&A contained in TransAlta's annual report for the year ended Dec. 31, 2004. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. This MD&A is dated Oct. 19, 2005. Additional information respecting TransAlta, including its annual information form, is available on SEDAR at www.sedar.com.

RESULTS OF OPERATIONS

The results of operations are presented on a consolidated basis and by business segment. TransAlta has two business segments: Generation and Energy Marketing. TransAlta's segments are supported by a corporate group that provides finance, treasury, legal, human resources and other administrative support. These corporate group overheads are allocated to the business segments.

In this MD&A, the impact of foreign exchange fluctuations on foreign currency transactions and balances is discussed with the relevant income statement and balance sheet items. While individual balance sheet line items will be impacted by foreign exchange fluctuations, the net impact of the translation of individual items is reflected in the cumulative translation account on the consolidated balance sheet.

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



3 months 9 months
ended Sept. 30 ended Sept. 30
2005 2004(1) 2005 2004(1)
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Availability (%) 89.8 88.0 89.1 88.8
Production (GWh) 13,172 12,685 38,402 38,146
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Revenue $ 722.9 $ 678.2 $2,028.4 $1,926.1
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Gross margin(2) $ 372.8 $ 353.6 $1,075.4 $1,023.9
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Operating income(2) $ 119.8 $ 113.6 $ 346.8 $ 320.6
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Earnings from continuing
operations $ 52.1 $ 35.8 $ 128.6 $ 98.5
Gain on disposal of
discontinued operations,
net of tax - - - 9.6
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Net earnings $ 52.1 $ 35.8 $ 128.6 $ 108.1
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Basic earnings per
common share:
Earnings from continuing
operations $ 0.27 $ 0.18 $ 0.66 $ 0.51
Gain on disposal of
discontinued operations,
net of tax - - - 0.05
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Net earnings $ 0.27 $ 0.18 $ 0.66 $ 0.56
Diluted earnings per
common share:
Earnings from continuing
operations $ 0.27 $ 0.18 $ 0.65 $ 0.51
Gain on disposal of
discontinued operations,
net of tax - - - 0.05
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Net earnings $ 0.27 $ 0.18 $ 0.65 $ 0.56
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Cash flow from
operating activities $148.5 $ 142.6 $ 407.5 415.3
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(1) TransAlta adopted the standard for variable interest entities
on Jan. 1, 2005. See Note 1 to the unaudited interim consolidated
financial statements for further discussion. Prior periods have
been restated.

(2) Gross margin and operating income are not defined under GAAP.
Refer to the non-GAAP measures section on page 16 of this MD&A
for a further discussion of operating income, including a
reconciliation to net earnings.



NET EARNINGS

Net earnings for the three months ended Sept. 30, 2005 increased by $16.3 million compared to the same period in 2004. The key factors responsible for this increase are listed below in the reconciliation of operating income:



Net earnings for the 3 months ended Sept. 30, 2004 $ 35.8
Increased Generation gross margins 27.2
Reduced planned maintenance costs,
offset by lost earnings due to planned outages 3.2
Lower Energy Marketing gross margins (4.5)
Increase in operational and administrative costs (19.4)
Decreased depreciation 2.3
Lower income tax expense 6.9
2004 gain on sale of TransAlta Power partnership units (3.1)
Other 3.7
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Net earnings for the 3 months ended Sept. 30, 2005 $ 52.1
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Production for the third quarter increased by 487 gigawatt hours (GWh) from the same period in 2004 as a result of increased production due to lower unplanned outages at the Alberta Thermal plants of 313 GWh, incremental production from the addition of Genesee 3 of 424 GWh, offset by the decommissioning of units one and two of the Wabamun plant of 206 GWh and the outage at unit four of the Wabamun plant of 208 GWh.

The improvement in Generation gross margins resulted from lower unplanned outages in Alberta and higher gross margins on merchant production as well as incremental production from Genesee 3. These gains were offset by production losses incurred at the Wabamun plant related to the oil spill at Lake Wabamun. The gross margin impact of planned maintenance was comparable to the same period last year.

Gross margins for long-term contracts and CE Generation LLC (CE Gen) were essentially flat with the same quarter last year.

Energy Marketing's gross margin of $9.4 million was down $4.5 million from the same quarter last year. Strong margins during the hot summer months in eastern markets were offset by volatility during the unusual hurricane season.

Third quarter operations, maintenance and administrative (OM&A) costs increased by $12.6 million compared to the same period in 2004. This increase was the result of the addition of Genesee 3, higher compensation costs due to the impact of the increased value of TransAlta common shares on long-term compensation costs and other plant operating costs. These increases were partially offset by a reduction in planned maintenance expenses of $6.8 million.

Depreciation was down $2.3 million in the quarter primarily due to reduced production at various gas plants.

Net interest expense declined $1.3 million due to reduced debt balances. In the quarter, $110.2 million of debt was retired.

Income taxes decreased by $6.9 million due to a tax recovery of $13.0 million in the third quarter of 2005. After adjusting for this recovery, the effective tax rate for the quarter was 31.3 per cent.



CASH FLOW

Cash flow from operating activities increased by $5.9 million for the three months ended Sept. 30, 2005 as compared to the same period in 2004. The key factors responsible for this increase are listed below in the reconciliation of cash flow from operating activities:



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Cash flow from operating activities for
3 months ended Sept. 30, 2004 $ 142.6
Increased net earnings 16.3
Asset retirement obligations costs settled (5.5)
Changes in other non-cash items (15.1)
Changes in non-cash working capital 10.2
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Cash flow from operating activities for
3 months ended Sept. 30, 2005 $ 148.5
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Cash flow from operating activities of $148.5 million increased $5.9 million as compared to the third quarter of 2004 mainly due to higher earnings. Capital expenditures in the quarter were $77.0 million compared to $100.4 million in the third quarter last year. Net debt retirement in the quarter, including both short- and long-term debt, was $110.2 million compared to $44.3 million in the same period in 2004.

At Sept. 30, 2005, TransAlta's total debt (including non-recourse debt) to invested capital ratio was 44.5 per cent (40.8 per cent excluding non-recourse debt). This represents a slight improvement from the Dec. 31, 2004 ratio of 46.6 per cent.

DISCUSSION OF SEGMENTED RESULTS

GENERATION: Owns and operates hydro, wind, geothermal, gas- and coal-fired plants and related mining operations in Canada, the U.S., and Australia. At Sept. 30, 2005, Generation had 8,339 megawatts (MW) of gross generating capacity in operation (7,935 MW net ownership interest). Generation's revenues are derived from the availability and production of electricity and steam as well as ancillary services such as system support (see the detailed discussion of the four revenue streams in our annual report for the year ended Dec. 31, 2004).

SIGNIFICANT EVENTS

Wabamun outage

On Aug. 3, 2005, a Canadian National Railway Company (CN Rail) train derailment resulted in an oil spill into Lake Wabamun, Alberta, which forced TransAlta to shut down the 279 MW Wabamun unit four. The plant resumed full operations on Sept. 11, 2005. TransAlta estimates that it lost $15 million - $18 million of operating income during the outage and plans to seek damages from those responsible.

Summerview Wind Farm

Late in the third quarter of 2004, the Summerview Wind Farm began commercial production. The 68 MW wind farm is operated by a division of TransAlta, Vision Quest Windelectric.

Commissioning of the Genesee 3 Generating Facility

On March 1, 2005, TransAlta and EPCOR Utilities Inc. jointly commissioned the 450 MW Genesee 3 Generating Facility. TransAlta has a net ownership interest in 225 MW of the facility.

The results of the Generation segment are as follows:



2005 2004
---------------------------------------------------------------------

3 months ended Sept. 30 Total Per MWh Total Per MWh
---------------------------------------------------------------------
Revenues $ 668.2 $ 50.73 $ 604.4 $ 47.65
Fuel and purchased power (304.8) (23.14) (264.7) (20.87)
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Gross margin 363.4 27.59 339.7 26.78
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Operations, maintenance and
administration 138.7 10.53 134.7 10.62
Depreciation and amortization 83.0 6.30 84.9 6.69
Taxes, other than income taxes 5.1 0.39 5.5 0.43
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Operating expenses 226.8 17.22 225.1 17.74
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Gain on sale of TransAlta
Power partnership units - - 3.1 0.24
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Operating income before
corporate allocations 136.6 10.37 117.7 9.28
Corporate allocations 19.8 1.50 14.1 1.11
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Operating income $ 116.8 $ 8.87 $ 103.6 $ 8.17
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Production (GWh) 13,172 12,685
Availability (%) 89.8% 88.0%
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2005 2004
---------------------------------------------------------------------

9 months ended Sept. 30 Total Per MWh Total Per MWh
---------------------------------------------------------------------
Revenues $ 1,846.0 $ 48.07 $ 1,742.4 $ 45.68
Fuel and purchased power (817.8) (21.30) (761.8) (19.97)
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Gross margin 1,028.2 26.77 980.6 25.71
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Operations, maintenance
and administration 379.8 9.89 367.1 9.62
Depreciation and amortization 258.0 6.72 256.6 6.73
Taxes, other than income taxes 16.5 0.43 17.6 0.46
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Operating expenses 654.3 17.04 641.3 16.81
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Gain on sale of TransAlta
Power partnership units - - 24.2 0.63
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Operating income before
corporate allocations 373.9 9.73 363.5 9.53
Corporate allocations 56.4 1.47 50.5 1.32
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Operating income $ 317.5 $ 8.26 $ 313.0 $ 8.21
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Production (GWh) 38,402 38,146
Availability (%) 89.1% 88.8%
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Market prices and heat rates

Gas and coal-fired facilities that have exposure to market fluctuations in energy commodity prices represent four per cent and 28 per cent of TransAlta's total generating production, respectively. The corporation closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various physical and financial instruments to hedge its assets and operations from such price risk.



Average Spot Electricity Prices
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Q3 2004 Q3 2005 YTD 2004 YTD 2005
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Alberta System Market
Price (Cdn$/MWh) $ 54.33 $ 66.71 $ 54.43 $ 54.50
Mid-Columbia Price
(US$/MWh) $ 44.29 $ 62.94 $ 41.25 $ 49.90
Ontario Market Price
(Cdn$/MWh) $ 46.18 $ 85.92 $ 49.70 $ 67.38
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Average Spark Spreads (1)
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Q3 2004 Q3 2005 YTD 2004 YTD 2005
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Alberta System Market
Price vs. AECO (Cdn$/MWh) $ 10.81 $ 1.99 $ 8.66 $ -0.24
Mid-Columbia Price
vs. Sumas (US$/MWh) $ 10.37 $ 9.10 $ 6.32 $ 4.55
Ontario Market Price
vs. Dawn (Cdn$/MWh) $ -5.77 $ 6.77 $ -5.61 $ 1.35
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(1) For a 7,000 Btu/KWh heat rate plant.


Spot electricity prices in Alberta and the Pacific Northwest were higher in the third quarter of 2005 compared to the same period in 2004, largely due to higher gas prices. In Ontario, higher gas prices combined with especially warm weather resulted in significantly higher third quarter 2005 electricity spot prices compared to the same period in 2004. Spark spreads in Alberta and the Pacific Northwest decreased in the third quarter of 2005 relative to the same period in 2004 where weak demand combined with higher gas prices to reduce spark spreads.

Availability

Availability for the three and nine months ended Sept. 30, 2005 increased to 89.8 per cent and 89.1 per cent from 88.0 per cent and 88.8 per cent, respectively, compared to the same periods in 2004 due to lower unplanned outages at the Alberta Thermal plants, partially offset by increased planned and unplanned outages at various gas facilities. The shutdown at unit four of the Wabamun plant did not impact availability for the third quarter.

Production

Production for the three and nine months ended Sept. 30, 2005 increased by 487 GWh as compared to the same periods in 2004 due to lower unplanned outages at the Alberta Thermal plants (313 GWh and 144 GWh), incremental production from the addition of Genesee 3 (424 GWh and 943 GWh) offset by the decommissioning of units one and two of the Wabamun plant (206 GWh and 622 GWh) in December 2004, and the outage at unit four of the Wabamun plant (208 GWh).

Revenue

Revenue increased by $63.8 million for the three months ended Sept. 30, 2005 as compared to the same period in 2004 due to increased production at the Alberta Thermal plants as a result of lower unplanned outages ($17.2 million), incremental revenues from the addition of Genesee 3 ($27.2 million), higher revenues from the Sarnia plant ($26.4 million), improved pricing at Centralia Coal ($12.8 million) and increased hydro production due to lower reservoir levels in 2004 and higher pricing ($6.5 million). Revenues were partially offset by the decommissioning of units one and two of the Wabamun plant ($11.1 million) and the outage at unit four of the Wabamun plant ($10.2 million).

Revenue increased by $103.6 million for the nine months ended Sept. 30, 2005 as compared to the same period in 2004 due to increased production at the Alberta Thermal plants as a result of lower unplanned outages ($6.8 million), incremental revenues from the addition of Genesee 3 ($57.5 million), higher revenues from the Sarnia plant ($30.0 million), improved pricing at Centralia Coal ($25.9 million), increased hydro production due to lower reservoir levels in 2004 and higher pricing ($22.7 million) offset by the decommissioning of units one and two of the Wabamun plant ($33.6 million) and the outage at unit four of the Wabamun plant ($10.2 million).

Fuel and purchased power

Fuel and purchased power increased by $40.1 million for the three months ended Sept. 30, 2005 as compared to the same period in 2004 due to incremental costs from Genesee 3 ($8.3 million), higher gas costs at the Sarnia plants ($26.1 million) and higher coal costs and replacement power prices at Centralia Coal ($8.1 million). These costs were partially offset by the decommissioning of units one and two of the Wabamun plant ($4.2 million) and the outage at unit four of the Wabamun plant ($3.0 million).

Fuel and purchased power increased by $56.0 million for the nine months ended Sept. 30, 2005 as compared to the same period in 2004 due to incremental costs from Genesee 3 ($17.5 million), higher gas costs at the Sarnia plant ($20.7 million), higher costs at Centralia Coal ($27.1 million) mainly due to increased coal costs, offset by the decommissioning of units one and two of the Wabamun plant ($13.4 million).

Operations, maintenance and administration expense

In the three and nine months ended Sept. 30, 2005, OM&A expense increased by $4.0 million and $12.7 million compared to the same periods in 2004 primarily due to incremental expenses from the addition of Genesee 3 of $2.2 million and $3.7 million, respectively and an increase in operating expenditures at several plants.

Planned maintenance

The table below shows the amount of planned maintenance capitalized and expensed in the three and nine months ended Sept. 30, 2005 and 2004, excluding CE Gen:




Coal Gas and Hydro Total
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3 months ended Sept. 30 2005 2004 2005 2004 2005 2004
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Capitalized $ 24.5 $ 20.5 $ 7.2 $ 1.7 $ 31.7 $ 22.2
Expensed 22.7 31.2 2.1 0.4 24.8 31.6
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$ 47.2 $ 51.7 $ 9.3 $ 2.1 $ 56.5 $ 53.8
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GWh lost 600 612 94 23 694 635
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Coal Gas and Hydro Total
---------------------------------------------------------------------
9 months ended Sept. 30 2005 2004 2005 2004 2005 2004
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Capitalized $ 53.9 $ 60.1 $ 34.0 $ 7.2 $ 87.9 $ 67.3
Expensed 53.2 64.7 3.7 3.2 56.9 67.9
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$107.1 $124.8 $ 37.7 $ 10.4 $144.8 $135.2
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GWh lost 1,788 1,831 461 135 2,249 1,966
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In the three and nine months ended Sept. 30, 2005, there were 694 GWh and 2,249 GWh of production lost due to planned maintenance compared to 635 GWh and 1,966 GWh lost for planned maintenance in the three and nine months ended Sept. 30, 2004. During the third quarter of 2005, incremental outages in the gas fleet contributed 71 GWh of lost production over the same period in 2004. Lost production in the coal fleet remained consistent between periods. During the first nine months of 2005, incremental outages in the gas fleet contributed to 326 GWh of lost production in 2005 compared to the same period in 2004. Lost production from the coal fleet was 43 GWh lower in the first nine months of 2005 as compared to the same period in 2004, driven primarily by improvements in durations on certain outages in 2005.

In the three and nine months ended Sept. 30, 2005, capitalized maintenance costs increased by $9.5 million and $20.6 million, respectively, compared to the same period in 2004 due to incremental outages in the gas fleet in the third quarter of 2005 as compared to the third quarter of 2004. Expensed maintenance costs in the three and nine months ended Sept. 30, 2005 decreased from the same periods in 2004 for the same reasons above.

Generation's production volumes, electricity and steam production revenues and fuel and purchased power costs are presented below:



Fuel &
3 months ended Production Purchased Gross
Sept. 30, 2005 (GWh) Revenue Power Margin
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Alberta PPAs 6,435 $ 171.5 $ 49.3 $ 122.2
Long-term contracts 1,700 147.7 91.9 55.8
Merchant 4,222 266.8 145.3 121.5
CE Gen 815 82.2 18.3 63.9
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TOTAL 13,172 $ 668.2 $ 304.8 $ 363.4
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Fuel &
Purchased Gross
Revenue Power per Margin per
3 months ended Sept. 30, 2005 per MWh MWh MWh
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Alberta PPAs $ 26.65 $ 7.66 $ 18.99
Long-term contracts 86.88 54.06 32.82
Merchant 63.19 34.41 28.78
CE Gen 100.86 22.45 78.41
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TOTAL $ 50.73 $ 23.14 $ 27.59
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Fuel &
3 months ended Production Purchased Gross
Sept. 30, 2004 (GWh) Revenue Power Margin
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Alberta PPAs 6,025 $ 156.1 $ 45.4 $ 110.7
Long-term contracts 1,693 134.7 78.8 55.9
Merchant 4,162 227.3 121.3 106.0
CE Gen 805 86.3 19.2 67.1
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TOTAL 12,685 $ 604.4 $ 264.7 $ 339.7
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Fuel &
Purchased Gross
Revenue Power per Margin per
3 months ended Sept. 30, 2004 per MWh MWh MWh
---------------------------------------------------------------------
Alberta PPAs $ 25.91 $ 7.54 $ 18.37
Long-term contracts 79.56 46.54 33.02
Merchant 54.61 29.14 25.47
CE Gen 107.20 23.85 83.35
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TOTAL $ 47.65 $ 20.87 $ 26.78
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Fuel &
9 months ended Production Purchased Gross
Sept. 30, 2005 (GWh) Revenue Power Margin
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Alberta PPAs 19,074 $ 510.6 $ 142.3 $ 368.3
Long-term contracts 5,273 459.7 268.8 190.9
Merchant 11,886 654.5 355.3 299.2
CE Gen 2,169 221.2 51.4 169.8
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TOTAL 38,402 $1,846.0 $ 817.8 $1,028.2
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Fuel &
Purchased Gross
Revenue Power per Margin per
9 months ended Sept. 30, 2005 per MWh MWh MWh
---------------------------------------------------------------------
Alberta PPAs $ 26.77 $ 7.46 $ 19.31
Long-term contracts 87.18 50.98 36.20
Merchant 55.06 29.89 25.17
CE Gen 101.98 23.70 78.28
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TOTAL $ 48.07 $ 21.30 $ 26.77
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Fuel &
9 months ended Production Purchased Gross
Sept. 30, 2004 (GWh) Revenue Power Margin
---------------------------------------------------------------------
Alberta PPAs 19,401 $ 516.8 $ 140.1 $ 376.7
Long-term contracts 5,302 426.1 253.8 172.3
Merchant 11,397 580.4 316.7 263.7
CE Gen 2,046 219.1 51.2 167.9
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TOTAL 38,146 $1,742.4 $ 761.8 $ 980.6
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Fuel &
Purchased Gross
Revenue Power Margin per
9 months ended Sept. 30, 2004 per MWh MWh MWh
---------------------------------------------------------------------
Alberta PPAs $ 26.64 $ 7.22 $ 19.42
Long-term contracts 80.37 47.87 32.50
Merchant 50.93 27.79 23.14
CE Gen 107.09 25.02 82.07
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TOTAL $ 45.68 $ 19.97 $ 25.71
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Alberta PPAs

Under the Power Purchase Arrangements (PPAs), the corporation earns monthly capacity revenues, which are designed to recover fixed costs and provide a return on capital for the plants and mines. The corporation also earns energy payments for the recovery of predetermined variable costs of producing energy, an incentive/penalty for achieving above/below the targeted availability and an excess energy payment for power production above committed capacity.

Production for the three months ended Sept. 30, 2005 increased by 410 GWh compared to the same period in 2004 primarily due to lower unplanned outages at the Alberta Thermal plants (296 GWh).

Production for the nine months ended Sept. 30, 2005 decreased by 327 GWh compared to the same period in 2004 primarily due to increased planned maintenance at the Alberta Thermal plants (351 GWh), excess production in 2004 (71 GWh), offset by lower unplanned outages at the Alberta Thermal plants (135 GWh).

Revenues for the three months ended Sept. 30, 2005 increased by $15.4 million compared to the same period in 2004 primarily due to increased production at the Alberta Thermal plants as a result of lower unplanned outages ($16.3 million), partially offset by higher pricing during planned maintenance outages ($3.6 million). Revenues for the nine months ended Sept. 30, 2005 decreased by $6.2 million compared to the same period in 2004 primarily due to increased planned maintenance at the Alberta Thermal plants ($19.3 million), offset by increased production at the Alberta Thermal plants as a result of lower unplanned outages ($6.5 million) and contract escalations ($3.0 million).

Revenues per megawatt hour (MWh) for the three and nine months ended Sept. 30, 2005 increased by $0.74 per MWh and $0.13 per MWh, respectively, compared to the same period in 2004, primarily as a result of increased incentive payments resulting from the lower unplanned outages.

Fuel and purchased power costs for the three months ended Sept. 30, 2005 were $3.9 million ($0.12 per MWh) higher than the comparable period in 2004 primarily due to fewer unplanned outages and a slight increase in cost of coal due to overburden removal. Fuel and purchased power costs for the nine months ended Sept. 30, 2005 were $2.2 million ($0.24 per MWh) higher than the comparable period in 2004 due to the reasons mentioned above.

Long-term contracts

Long term contracts are similar to PPAs. TransAlta defines a long-term contract as having an original term between 10 and 25 years. Long-term contracts are typically for gas-fired cogeneration plants and have between one and four customers per plant. Revenues are derived from payments for capacity and/or the production of electrical energy and steam.

In the three and nine months ended Sept. 30, 2005, production subject to long-term contracts remained consistent with the same periods in 2004.

For the three months ended Sept. 30, 2005, revenues increased by $13.0 million ($7.32 per MWh), primarily due to improved steam and electricity pricing at the Sarnia plant ($10.9 million). For the nine months ended Sept. 30, 2005, revenues increased by $33.6 million ($6.81 per MWh) primarily due to improved steam and electricity pricing at the Sarnia plant ($18.7 million) and revised contracting at the other gas plants ($11.0 million).

Fuel and purchased power costs increased by $13.1 million ($7.52 per MWh) and $15.0 million ($3.11 per MWh) for the three and nine months ended Sept. 30, 2005 compared to the same periods in 2004 due to higher gas prices.

Merchant

Merchant revenue is derived from the sale of production only, with multiple customers per plant. Production is sold via: medium-term contract sales (typically three to seven years); short-term asset-backed trading; and spot or short-term (less than one year) forward markets.

In the third quarter of 2005, merchant production was 4,222 GWh, of which 1,934 GWh was contracted under short- to medium-term contracts. In the third quarter of 2004, merchant production was 4,162 GWh, of which 1,879 GWh was contracted. The increase in production was primarily due to the addition of Genesee 3 (424 GWh) offset by the decommissioning of two units of the Wabamun plant (206 GWh) and the outage at unit four of the Wabamun plant (208 GWh).

In the nine months ended Sept. 30, 2005, merchant production was 11,886 GWh, of which 5,058 GWh was contracted under short- to medium-term contracts. In the nine months ended Sept. 30, 2004, merchant production was 11,397 GWh, of which 4,809 GWh was contracted. The increase in production was primarily due to the addition of Genesee 3 (943 GWh), fewer GWh lost to planned maintenance at Alberta merchant plants (388 GWh) and increased hydro production due to lower reservoir levels in 2004 and higher pricing (324 GWh), partially offset by the decommissioning of units one and two of the Wabamun plant (622 GWh), lower production from Poplar Creek (276 GWh) due to the lower market heat rate and planned maintenance and the outage at unit four of the Wabamun plant (208 GWh).

For the three months ended Sept. 30, 2005, merchant revenues increased by $39.5 million while fuel and purchased power increased by $24.0 million resulting in a gross margin increase of $15.5 million ($3.31 per MWh) compared to the same period in 2004. The gross margin increase is due to the addition of Genesee 3 ($18.9 million), increased hydro production due to lower reservoir levels in 2004 and higher pricing ($5.6 million), partially offset by the outage at unit four of the Wabamun plant ($7.2 million) and the decommissioning of units one and two of the Wabamun plant ($6.9 million). At Centralia Coal, margins are up $4.8 million primarily due to an increase in spot prices partially offset by an increase in coal costs and replacement power prices.

For the nine months ended Sept. 30, 2005, merchant revenues increased by $74.1 million while fuel and purchased power increased by $38.6 million resulting in a gross margin increase of $35.5 million ($2.03 per MWh) compared to the same period in 2004. The gross margin increase is due to the addition of Genesee 3 ($40.0 million), lower planned maintenance at the Alberta merchant plants ($16.2 million), increased hydro production due to lower reservoir levels in 2004 and higher pricing ($24.3 million), partially offset by the decommissioning of units one and two of the Wabamun plant ($20.2 million), the outage at unit four of the Wabamun plant ($7.2 million) and lower margins at Poplar Creek due to a decline in market heat rate ($14.2 million). At Centralia Coal, margins have decreased $1.2 million primarily due to increased cost of coal offset by higher prices.

CE Gen

TransAlta's share of CE Gen production for the three and nine months ended Sept. 30, 2005, increased by 10 GWh and 123 GWh, respectively, when compared to the same periods in 2004 primarily due to increased production at the Power Resources facilities and Imperial Valley.

In the three and nine months ended Sept. 30, 2005, revenues decreased by $6.34 per MWh and $5.11 per MWh, respectively, compared to the same periods in 2004 primarily due to strengthening of the Canadian dollar compared to the U.S. dollar. In the three months ended Sept. 30, 2005, fuel costs decreased by $1.40 per MWh, primarily due to the reason noted above. For the nine months ended Sept. 30, 2005, fuel costs decreased by $1.32 per MWh, primarily due to strengthening of the Canadian dollar compared to the U.S. dollar, partially offset by increased gas prices.

ENERGY MARKETING: Derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives not supported by TransAlta owned generation assets. Energy Marketing also utilizes contracts of various durations for the forward sales of electricity and purchases of natural gas and transmission capacity to effectively manage available generating capacity and fuel and transmission needs on behalf of Generation. These results are included in the Generation segment. Operating expenses are net of the inter-segment charges for provision of these energy marketing, financial risk management, commercial, portfolio, and regulatory management services.

Energy Marketing uses commodity derivatives to manage risk associated with our generation assets, earn trading revenue and gain market intelligence. The portfolio consists of physical and financial derivative instruments including forwards, swaps, futures and options in various commodities. Power and gas trading activities are focused on capturing opportunities based on expected trends in electricity, natural gas prices or market heat rates. Trading activities related to market heat rates involve both a gas and an electricity component. During periods in which the trading is focused on market heat rates, the gas trading volumes will usually be higher to manage the heat rate as compared to trading volumes when the opportunities are focused solely on gas or electricity trends. These contracts meet the definition of trading activities and have been accounted for using fair values for both Canadian and U.S. GAAP. Changes in the fair values of the portfolio are recognized in income in the period they occur.

The results of the Energy Marketing segment are as follows:



3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------

Revenues $ 54.7 $ 73.8 $ 182.4 $ 183.7
Trading purchases (45.3) (59.9) (135.2) (140.4)
---------------------------------------------------------------------
Gross margin 9.4 13.9 47.2 43.3
---------------------------------------------------------------------
Operations, maintenance and
administration 3.0 1.6 8.2 5.0
Depreciation and amortization 0.5 0.6 1.3 1.5
---------------------------------------------------------------------
Operating expenses 3.5 2.2 9.5 6.5
---------------------------------------------------------------------
Prior period regulatory decision - - - 22.9
---------------------------------------------------------------------
Operating income before corporate
allocations 5.9 11.7 37.7 13.9
Corporate allocations 2.9 1.7 8.4 6.3
---------------------------------------------------------------------
Operating income $ 3.0 $ 10.0 $ 29.3 $ 7.6
---------------------------------------------------------------------
---------------------------------------------------------------------


Revenues include all power and gas trading activities which are recorded net, in addition to gross revenues related to energy trading contracts settled in real-time physical markets. For the three months ended Sept. 30, 2005, real-time physical power purchases decreased by $14.6 million relative to the same period in 2004 due to TransAlta's decision to exit an energy services agreement effective April 2005. In the three months ended Sept. 30, 2005, gross margin decreased by $4.5 million compared to the same period in 2004 when market heat rates fell due to the effects of an unusual 2005 hurricane season, partially offset by better performance in electricity trading in the Eastern markets.

For the nine months ended Sept. 30, 2005, real-time physical power purchases decreased by $5.2 million relative to the same period in 2004 due to the termination of an energy services agreement in April 2005, partially offset by increased real-time physical power purchases. In the nine months ended Sept. 30, 2005 gross margin increased by $3.9 million compared to the same period in 2004 due to strong second quarter results in electricity trading in 2005.

OM&A costs for the three and nine months ended Sept. 30, 2005 have increased by $1.4 million and $3.2 million, respectively, relative to the same periods in 2004 due to an increase in staff and higher compensation expenses. OM&A is net of Energy Marketing's inter-segment charge for management services in the amount of $6.5 million (2004 - $6.5 million) for the three months ended Sept. 30, 2005, and $19.5 million (2004 - $19.5 million) for the nine months ended Sept. 30, 2005.

TransAlta's fixed price trading positions were as follows:



Electricity Natural Gas
Units (000s) (MWh) (GJ)
---------------------------------------------------------------------

Fixed price payor, notional amounts,
Sept. 30, 2005 24,151 39,587
Fixed price payor, notional amounts,
Dec. 31, 2004 14,138 35,222

Fixed price receiver, notional amounts,
Sept. 30, 2005 27,042 34,718
Fixed price receiver, notional amounts,
Dec. 31, 2004 15,854 29,721

Maximum term in months, Sept. 30, 2005 39 25
Maximum term in months, Dec. 31, 2004 48 34
---------------------------------------------------------------------
---------------------------------------------------------------------


Power trading strategies consist of shorter-term physical and financial trades in regions where TransAlta has assets and the markets that interconnect with those regions. TransAlta's proprietary trading activities are derived from both changes in electricity prices and market heat rates. Trading activities related to market heat rates involve both an electricity and a gas component therefore the level of trading in market heat rates will influence the level of trading in gas volumes.

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



3 months 9 months
Electricity (GWh) ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Physical 11,707 19,515 33,721 46,854
Financial 19,456 5,765 38,795 14,415
---------------------------------------------------------------------
31,163 25,280 72,516 61,269
---------------------------------------------------------------------
---------------------------------------------------------------------

3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
Gas (million GJ) 2005 2004 2005 2004
---------------------------------------------------------------------
Physical 22.7 39.3 64.9 88.9
Financial 121.0 91.5 233.6 224.7
---------------------------------------------------------------------
143.7 130.8 298.5 313.6
---------------------------------------------------------------------
---------------------------------------------------------------------



Total electricity volumes in the three and nine months ended Sept. 30, 2005 are above the same periods in 2004 due to opportunities created from increasing liquidity in some markets.

The fluctuations in gas volumes for the three and nine months ended Sept. 30, 2005 are related to changes in trading opportunities associated with changes in market heat rates. During the three months ended Sept. 30, 2005, a higher proportion of the trading activities were related to market heat rates and therefore increased the volume of gas trading.

The corporation's electrical transmission contracts net trading position of 11.8 million MWh at Sept. 30, 2005 is higher than the net trading position of 4.4 million MWh at Dec. 31, 2004, primarily due to additional purchases of electrical transmission contracts.

PRICE RISK MANAGEMENT

The following tables show the balance sheet classifications for price risk management assets and liabilities, as well as the changes in the fair value of the net price risk management assets for the period:



Sept. 30 Dec. 31
Balance Sheet 2005 2004
---------------------------------------------------------------------
Price risk management assets
Current $ 249.1 $ 61.4
Long-term 38.9 32.5
Price risk management liabilities
Current (230.3) (49.9)
Long-term (36.7) (28.5)
---------------------------------------------------------------------
Net price risk management assets outstanding $ 21.0 $ 15.5
---------------------------------------------------------------------
---------------------------------------------------------------------


Change in fair value of net assets Fair value
---------------------------------------------------------------------
Net price risk management assets
outstanding at Dec. 31, 2004 $ 15.5
Contracts realized, amortized or
settled during the period (16.7)
Changes in values attributable to
market price and other market changes 6.1
New contracts entered into during
the current calendar year 16.1
---------------------------------------------------------------------
Net price risk management assets
outstanding at Sept. 30, 2005 $ 21.0
---------------------------------------------------------------------
---------------------------------------------------------------------


The net price risk management assets and liabilities increased by $5.5 million compared to Dec. 31, 2004 due to an increase in the volumes of power contracts outstanding and an increase in market prices.

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



2010 and
2005 2006 2007 2008 2009 thereafter Total
---------------------------------------------------------------------
Prices actively quoted $ 2.1 $ 5.3 $ 1.2 $ 1.6 $ 0.6 $ 0.3 $11.1
Prices based on models 7.3 2.6 - - - - 9.9
---------------------------------------------------------------------
$ 9.4 $ 7.9 $ 1.2 $ 1.6 $ 0.6 $ 0.3 $21.0
---------------------------------------------------------------------
---------------------------------------------------------------------


TransAlta's proprietary trading activities are mainly short-term transactions under 24 months in duration, thereby limiting credit risk and maintaining low working capital requirements. Transactions extending past 2006 are Generation asset-backed contracts that do not qualify for hedge accounting and have a low risk profile.



NET INTEREST EXPENSE

3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Interest on recourse and
non-recourse debt $ 48.3 $ 47.4 $ 141.2 $ 150.8
Interest on preferred securities 3.4 9.2 13.1 27.6
Interest income (2.7) (0.8) (2.7) (1.7)
Capitalized interest - (5.5) (3.4) (15.3)
---------------------------------------------------------------------
Net interest expense $ 49.0 $ 50.3 $ 148.2 $ 161.4
---------------------------------------------------------------------
---------------------------------------------------------------------


Net interest expense in the three and nine months ended Sept. 30, 2005 was $1.3 million lower and $13.2 million lower, respectively, than the same periods in 2004 due to decreased debt levels, the strengthening of the Canadian dollar as compared to the U.S. dollar, and decreased interest on the preferred securities as a result of the redemption of $300.0 million of preferred securities in the first quarter of 2005, partially offset by a reduction in capitalized interest.

NON-CONTROLLING INTERESTS

The earnings attributable to non-controlling interests in the three and nine months ended Sept. 30, 2005 increased from $12.3 million to $13.0 million and from $31.3 million to $37.2 million, respectively, compared to the same periods in 2004 as a result of the sale of the Meridian Cogeneration Facility to TransAlta Cogeneration, L.P. (TA Cogen) in the fourth quarter of 2004.



EQUITY INCOME

3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Equity (loss) income $ (2.1) $ (1.8) $ 0.1 $ (4.2)
---------------------------------------------------------------------
---------------------------------------------------------------------


Equity income represents the results from the wholly owned subsidiaries that hold TransAlta's interests in the Campeche and Chihuahua plants.

For the three months ended Sept. 30, 2005, the equity loss remained consistent with the prior year. For the nine months ended Sept. 30, 2005, equity income increased by $4.3 million as compared to the same period in 2004 due to higher capacity payments due to improved availability at the Chihuahua plant.



INCOME TAXES

3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Income tax expense $ 4.8 $ 11.7 $ 34.6 $ 22.8
Effective tax rate (%) 8.4 24.6 21.2 18.8
---------------------------------------------------------------------
---------------------------------------------------------------------


During the third quarter of 2005, income tax expense was reduced by $13.0 million due to a recovery related to the timing of the taxability of certain revenues. After adjusting for this recovery, the effective tax rate for the third quarter, expressed as a percentage of earnings before income taxes, of 31.3 per cent was higher than the same period in 2004 primarily due to withholding taxes on inter-company interest payments and higher incremental earnings.

The effective income tax rate in the first nine months of 2005 was higher compared to the same period in 2004, primarily due to the higher incremental earnings. The first nine months of 2004 included a benefit of the reduced Alberta corporate income tax rate applied to TransAlta's future tax liabilities and a favourable settlement of a tax dispute with New Zealand Inland Revenue relating to the 1999 taxation year of NZ$8.0 million (Cdn$6.8 million). During the third quarter of 2005, there was a recovery of $13.0 million recorded as a reduction in income tax expense, as discussed above.

The effective tax rate for the nine months ended Sept. 30, 2005, after adjusting for changes in tax rates and recoveries, of 29.2 per cent is comparable to the same period in 2004.



FINANCIAL POSITION

The following chart outlines significant changes in the consolidated
balance sheet from Dec. 31, 2004 to Sept. 30, 2005:

Increase/
(Decrease) Explanation
---------------------------------------------------------------------
Cash and cash equivalents $ (45.2) Refer to Consolidated Statements
of Cash Flows.

Accounts receivable 120.3 Increased Energy Marketing
trading and increased Generation
activity due to timing and
incremental Genesee 3.

Price risk management 187.7 Increase in the volumes of power
assets (current) contracts receivable and an
increase in prices.

Property, plant and (129.7) Increase due to capital
equipment, net of additions of $222 million,
accumulated depreciation offset by depreciation of
($291 million) and a change in
foreign exchange rate of
($101 million).

Intangible assets (39.1) Amortization of the CE Gen sales
contracts and change in foreign
exchange rates.

Other assets (including (303.2) Decrease due to scheduled
current portion) maturities of net investment
hedge contracts.

Short-term debt 141.1 Issuances of short-term debt.

Accounts payable and 98.5 Increased Energy Marketing
accrued liabilities trading, increased major
maintenance due to timing, and
increased interest due to timing
of payments.

Price risk management 180.4 Increase in the volumes of power
liabilities (current) contracts payable and an
increase in prices.

Recourse long-term debt (329.1) Redemption of preferred
(including current securities.
portion)

Non-recourse long-term (58.5) Repayment of long-term debt.
debt (including current
portion)

Deferred credits and other (251.8) Decrease due to scheduled
long-term liabilities maturities of net investment
(including current portion) hedge contracts.
---------------------------------------------------------------------


STATEMENTS OF CASH FLOWS

3 months ended Sept. 30 2005 2004 Explanation
---------------------------------------------------------------------
Cash and cash equivalents, $ 58.3 $ 106.3
beginning of period

Provided by (used in):

Operating activities 148.5 142.6 Increased earnings and
lower working capital
requirements.

Investing activities 27.7 (18.2) Capital expenditures of
$77.0 million, offset by
foreign exchange gains on
net investment hedges of
$79.9 million and a
decrease in the equity
investment of $31.8
million.

In 2004, capital
expenditures of $100.4
million relating
primarily to the
construction of the
Summerview Wind Farm, the
Genesee 3 project, and
planned maintenance,
offset by a decrease in
the equity investment of
$21.2 million and foreign
exchange gains on net
investment hedges of
$48.1 million.

Financing activities (180.4) (105.6) Net repayment of
short-term debt of $92.0
million, net repayment of
long-term borrowings of
$18.2 million, cash
dividends on common
shares of $61.2 million
and non-controlling
interest distributions
of $17.8 million.

In 2004, net repayment of
$35.4 million of
short-term debt, cash
dividends on common
shares of $32.6 million
and non-controlling
interest distributions of
$31.9 million.

Translation of foreign 1.9 -
currency cash
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash and cash equivalents, $ 56.0 $ 125.1
end of period
---------------------------------------------------------------------
---------------------------------------------------------------------


9 months ended Sept. 30 2005 2004 Explanation
---------------------------------------------------------------------
Cash and cash equivalents, $ 101.2 $ 123.8
beginning of period

Provided by (used in):

Operating activities 407.5 415.3 Increased earnings offset
by higher working capital
requirements.

Investing activities (126.9) (73.5) Capital expenditures of
$221.9 million, offset by
foreign exchange gains on
net investment hedges of
$83.2 million and a
decrease in equity
investment of $14.9
million.

In 2004, capital
expenditures of $268.1
million relating
primarily to the
construction of the
Summerview Wind Farm, the
Genesee 3 project, and
major maintenance,
partially offset by
proceeds from the
exercise of TransAlta
Power warrants ($61.7
million) and the
collection of the $90.8
million Zinc Recovery
long-term receivable.

Financing activities (324.0) (340.5) Net issuance of
short-term debt of $139.7
million and common share
issuances of $13.4
million were used to
partially fund
the redemption of
preferred securities of
$300.0 million, repayment
of long-term borrowings
of $40.1 million,
non-controlling interest
distributions of $53.4
million and dividend
payments of $96.8
million.

In 2004, net repayment of
short-term debt of $72.9
million, net repayment of
long-term debt of $135.1
million, cash dividends
on common shares of
$102.6 million, and
non-controlling interest
distributions of $33.5
million.

Translation of foreign (1.8) -
currency cash
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash and cash equivalents, $ 56.0 $ 125.1
end of period
---------------------------------------------------------------------
---------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Liquidity risk arises from the ability of TransAlta to meet general funding needs, engage in trading and hedging activities and manage the assets, liabilities and capital structure of the company. Liquidity risk is managed to maintain sufficient liquid financial resources to fund obligations as they become due in the most cost effective manner.

The corporation's liquidity needs are met through a variety of sources, including: cash generated from operations, short-term borrowings against our credit facilities and commercial paper program and long-term debt issued under the corporation's U.S. shelf registrations and Canadian Medium Term Note program. TransAlta's primary uses of funds are operational expenses, capital expenditures, dividends, distributions to non-controlling limited partners and interest and principal payments on debt securities.

The corporation has a $1.5 billion committed syndicated credit facility and approximately $332.3 million of uncommitted credit facilities. In April 2005, the $1.5 billion committed credit facility was extended and committed for a three year term. The amount available to the corporation, subject to customary borrowing conditions, is the total amount of the facilities less direct borrowings, commercial paper outstanding and letters of credit issued.

At Sept. 30, 2005, the corporation had $834.8 million available under these credit facilities ($1.35 billion at Dec. 31, 2004)to support future trading and hedging activities.

The corporation has obligations to issue letters of credit to secure potential liabilities to certain parties including those related to potential environmental obligations, trading activities, hedging activities and purchase obligations. As at Sept. 30, 2005, the corporation had issued letters of credit totaling $821.4 million ($447.3 million as at Dec. 31, 2004). The increase is due to additional contracts to sell power out of Centralia and an increase in electricity spot prices in the Pacific Northwest.

TransAlta expects that its ability to generate adequate cash flow from operations in the short term and the long term, and, when needed, to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since Dec. 31, 2004.

Funds generated from operations

Funds generated from operations were $148.5 million and $407.5 million for the three and nine months ended Sept. 30, 2005, respectively, compared with $142.6 million and $415.3 million for the same periods in 2004. Cash provided by operating activities increased due to higher net earnings in the third quarter of 2005 as compared to 2004.

Working capital requirements at Sept. 30, 2005 increased to $444.7 million as compared to $325.1 million at Dec. 31, 2004 due to a higher revenue receivable balance related to higher prices.

Investing activities

In the three and nine months ended Sept. 30, 2005, TransAlta spent $77.0 million and $221.9 million, respectively, on capital expenditures. In the three and nine months ended Sept. 30, 2004, TransAlta spent $100.4 million and $268.1 million, respectively, on capital expenditures. Capital expenditures for the third quarter of 2005 were $23.4 million lower than 2004 because in the third quarter of 2004, there were capital expenditures related to the construction of Genesee 3 and the Summerview Wind Farm.

For the three and nine months ended Sept. 30, 2005, the corporation realized $79.9 million and $83.2 million from foreign exchange gains on net investment hedges of foreign subsidiaries compared to $48.1 million and $10.2 million realized in the same period in 2004.

Financing activities

Cash used in financing activities during the quarter was $180.4 million, an increase of $74.8 million over the same quarter for 2004. This was mainly due to an increase in repayment of short- and long-term debt.

In the three months ended Sept. 30, 2005, TransAlta had an overall net debt repayment (which includes both short- and long-term debt) of $110.2 million compared to $44.3 million in the same period in 2004. In the nine months ended Sept. 30, 2005, TransAlta had an overall net repayment of debt of $200.4 million compared to $205.3 million in the same period in 2004. The majority of the total decrease in debt for the first nine months of 2005 is related to the redemption of $300.0 million of preferred securities.

Guarantee contracts

TransAlta has provided guarantees of subsidiaries' obligations that secure those subsidiaries obligations to third parties under various contracts. The guarantees generally have limits as to the amount of the guarantees however the corporation also has a number of unlimited guarantees. These guarantees fall into three categories including those related to trading activities, those related to hedging activities (hedging of the sale of electricity from production from our power plants and hedging of our interest rate and foreign exchange exposures) and those related to performance and payment obligations. To the extent potential liabilities related to these guarantees exist for trading activities, they are included in accounts payable and accrued liabilities and price risk management liabilities. To the extent potential liabilities exist related to those guarantees for hedging activities, they are not recognized on the consolidated balance sheet. To the extent liabilities exist under these guarantees for payment and performance obligations, they are included in accounts payable and accrued liabilities.

The total guarantees provided related to trading and hedging activities amount to approximately $1.5 billion at Sept.30, 2005(Dec. 31, 2004 - $1.6 billion). The net liability at Sept. 30, 2005, under these guarantees, was $601.9 million as compared to $345.2 million at Dec. 31, 2004. The increase is due to additional contracts to sell power out of Centralia and an increase in electricity spot prices in the Pacific Northwest.

The total guarantees related to payment and performance obligations at Sept. 30, 2005 was $653.3 million (Dec. 31, 2004 - $662.5 million).

On Oct. 19, 2005, the corporation had approximately 198.4 million common shares outstanding.

OUTLOOK

The key factors affecting the financial results for the remainder of 2005 are the megawatt capacity in place, the availability of and production from generating assets, the margins applicable to non-contracted production, the costs of production, and the volumes traded and margins achieved on Energy Marketing activities.

Production and availability

Production and availability are expected to be higher for the remainder of 2005 as a result of less planned maintenance.

Power prices

Electricity spot prices for the remainder of 2005 are anticipated to be higher than those in the third quarter in all markets with expectations for higher gas prices and stronger seasonal power demand. As a result of hedging, realized prices for the remainder of 2005 are expected to be consistent with the third quarter. Spark spreads are expected to be comparable to or lower than those seen in the third quarter in all markets as gas prices are expected to increase more than power prices.

Exposure to volatility in electricity prices and spark spreads is substantially mitigated through firm-price, long-term electricity sales contracts and hedging arrangements. For 2005, approximately 90 per cent of output is contracted, of which a significant portion relates to the Alberta PPAs. For the fourth quarter of 2005, approximately 55 per cent of merchant Alberta and 89 per cent of merchant Pacific Northwest exposure is hedged and TransAlta continues to lock in power prices as liquidity permits.

Fuel costs

Mining coal is subject to cost increases due to inflation and diesel commodity prices, which the corporation seeks to mitigate through diesel hedges. Seasonal variations in coal mining are minimized through the application of standard costing.

The coal mines continue to be exposed to rising costs due to increasing diesel costs, higher amounts of overburden being removed and mining operations moving further away from the power plants.

Exposure on gas costs for facilities under long-term sales contracts are minimized through long-term gas purchase contracts or corresponding offsets within revenues. Merchant gas facilities are exposed to the changes in spark spreads discussed in the power prices section. TransAlta has not entered into fixed gas commodity agreements for merchant gas plants as supply will be purchased coincident with electricity sales opportunities.

Operations, maintenance and administration costs

OM&A costs per MWh fluctuate by quarter and are dependent on the timing and nature of maintenance activities. OM&A costs per MWh for the fourth quarter of 2005 are expected to decrease as compared to the third quarter due to increased production and reduced planned maintenance.

Capital expenditures

Capital expenditures for 2005 are expected to be approximately $335 million to $350 million of which approximately $140 million will be spent on planned maintenance (excluding CE Gen), $80 million will be spent on the Alberta and Centralia mines and approximately $45 million on growth to complete the Genesee 3 project and to expand capacity in Australia, of which $38 million has been spent in the first nine months of 2005. The remainder will be spent at CE Gen and on productivity related investments. Financing for these expenditures is expected to be provided by cash flow from operations.

Planned maintenance

During 2005, TransAlta expects to spend between $205 million and $220 million on planned maintenance as outlined in the following table (excluding CE Gen):



Gas and
Coal Hydro Total
-----------------------------------------------------------
Capitalized $ 65-70 $ 65-70 $130-140
Expensed 65-70 10 75-80
-----------------------------------------------------------
$130-140 $ 75-80 $205-220
-----------------------------------------------------------
-----------------------------------------------------------

GWh lost 2,300 600 2,900
-----------------------------------------------------------
-----------------------------------------------------------



TransAlta expects to lose approximately 2,900 GWh of production due to planned maintenance during 2005 of which 2,249 GWh were lost in the first nine months of 2005.

Energy marketing

TransAlta will continue to manage its risk profile utilizing value at risk and other measures.

Exposure to fluctuations in foreign currencies

TransAlta's strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. dollar by offsetting foreign denominated assets with foreign denominated liabilities. TransAlta also has foreign currency expenses, primarily interest charges, that offset foreign currency revenues.

Net interest expense

Net interest expense for the remainder of the year is expected to decline slightly compared to the previous three quarters of 2005 as a result of a lower aggregate amount of debt.

Liquidity and capital resources

With the increased volatility in power and gas markets, market trading opportunities are expected to increase, which can potentially cause a strain on liquidity. To mitigate this liquidity risk, we continue to monitor the credit markets and our internally generated cash flow to determine any liquidity requirements.

NEW ACCOUNTING STANDARDS

Effective Jan. 1, 2005, TransAlta adopted the CICA Accounting Guideline 15 "Consolidation of Variable Interest Entities". The standard provides direction for applying consolidation principles to certain entities that are subject to control on a basis other than ownership of voting interests. The adoption of this guideline resulted in the deconsolidation of the wholly owned subsidiaries that hold the Campeche and Chihuahua plants. For further information, see Note 1 to our consolidated financial statements.

U.S. GAAP RESTATEMENT

Effective Sept. 30, 2005, the corporation restated Note 26 to its 2004 consolidated financial statements to recognize a difference in the treatment under U.S. generally accepted accounting principles (U.S. GAAP) of a gain arising on the disposition of certain generation assets to TA Cogen in 1998.

In 1998, the corporation transferred assets to its subsidiary TA Cogen. TransAlta Power, L.P. (TA Power) concurrently subscribed to a minority interest in TA Cogen. The fair value paid by TA Cogen for the assets exceeded their historical carrying values and the corporation recognized a portion of this difference, to the extent it was funded by TA Power's investment in TA Cogen, as a gain. As TA Power also held an option to resell their interest in TA Cogen to the corporation in 2018, this gain was initially deferred and amortized over a 30 year period for both Canadian and U.S. GAAP. In July 2003, TA Power's option to resell these TA Cogen units was eliminated and the unamortized balance of the gain was recognized in income.

The corporation has recently determined that pursuant to U.S. Securities and Exchange Commission Staff Accounting Bulletin No. 51, TA Power's option to potentially resell TA Cogen units to the corporation should have caused the gain, net of its related tax effects, to be characterized as contributed surplus in 1998. This U.S. accounting rule is not consistent with applicable accounting guidance in Canada. As a result, under U.S. GAAP, there would have been no amortization of the gain into income in the period from 1998 to 2002 and no recognition of the unamortized balance of the gain in July 2003. The impact on previously reported income amounts under U.S. GAAP is as follows:



2004 2003 2002
---------------------------------------------------------------------
Decrease in:
Earnings from continuing operations $ - $ 102.7 $ 6.3
Net earnings $ - $ 102.7 $ 6.3
Net earnings per share in accordance
with U.S. GAAP
Continuing operations $ - $ 0.56 $ 0.04
Discontinued operations $ - $ - $ -
Basic $ - $ 0.56 $ 0.04
Diluted $ - $ 0.56 $ 0.04
---------------------------------------------------------------------
---------------------------------------------------------------------


The impact on previously reported balance sheet amounts for U.S. GAAP
purposes is as follows:

2004 2003
---------------------------------------------------------------------
Increase (decrease) in:
Contributed surplus $ 133.0 $ 133.0
Retained earnings $ (133.0) $ (133.0)
---------------------------------------------------------------------
---------------------------------------------------------------------


The correction had no impact on the accumulated shareholders' equity at Dec. 31, 2004 and Dec. 31, 2003 for U.S. GAAP purposes.

TransAlta's restated 2004 audited consolidated financial statements will be available in Canada on SEDAR at www.sedar.com and in the U.S. on EDGAR at www.sec.gov under TransAlta Corporation and are available on the company's website at www.transalta.com.

PRIOR PERIOD REGULATORY DECISION

The U.S. Federal Energy Regulatory Commission (FERC) has provided TransAlta with an opportunity to petition for relief from refund obligations. To be successful in such a petition for relief, TransAlta will be required to demonstrate that, as a result of the refund methodology, it has suffered operating losses in respect of California transactions during the refund period. On Aug. 8, 2005, FERC issued an order detailing the methodology for a petition for relief from refund obligations. TransAlta prepared a petition for relief from the refund obligation and filed it with FERC. The California Independent System Operator (CAISO) and California Power Exchange (CALPX) have reviewed and commented on our petition and TransAlta replied to the CAISO and CALPX comments on Oct. 17, 2005. While the outcome of this filing cannot be determined at this time, any such relief would be accounted for only at the time that it is obtained from FERC.

The impact of prior period regulatory decisions relating to prior reporting periods are recorded when the effect of such decisions are known, without adjustment to the financial statements of prior periods.

NON-GAAP MEASURES

TransAlta evaluates its performance and the performance of its business segments using a variety of measures. Those discussed below are not defined under GAAP and therefore should not be considered in isolation or as an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP as an indicator of the corporation's financial performance or liquidity. These measures are not necessarily comparable to a similarly titled measure of another company.

Each business unit assumes responsibility for its operating results measured to gross margin and operating income. Operating income is a measure of financial performance used by TransAlta's analysts and investors to analyze and compare companies on the basis of operating performance.

Operating income provides management with a measurement of operating performance which is readily comparable from period to period.

Gross margin and operating income are reconciled to net earnings below:



3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004(1) 2005 2004(1)
---------------------------------------------------------------------
Gross margin $ 372.8 $ 353.6 $ 1,075.4 $ 1,023.9
Operating expenses (253.0) (243.1) (728.6) (704.6)
---------------------------------------------------------------------
119.8 110.5 346.8 319.3
Gain on sale of TransAlta
Power partnership units - 3.1 - 24.2
Prior period regulatory decision - - - (22.9)
---------------------------------------------------------------------
Operating income 119.8 113.6 346.8 320.6
Foreign exchange gain (loss) 1.2 (1.7) 1.7 (2.4)
Net interest expense (49.0) (50.3) (148.2) (161.4)
Equity income (loss) (2.1) (1.8) 0.1 (4.2)
---------------------------------------------------------------------
Earnings before non-controlling
interests and income taxes 69.9 59.8 200.4 152.6
Non-controlling interests 13.0 12.3 37.2 31.3
---------------------------------------------------------------------
Earnings before income taxes 56.9 47.5 163.2 121.3
Income tax expense 4.8 11.7 34.6 22.8
---------------------------------------------------------------------
Earnings from continuing
operations 52.1 35.8 128.6 98.5
Gain on disposal of discontinued
operations, net of tax - - - 9.6
---------------------------------------------------------------------
Net earnings $ 52.1 $ 35.8 $ 128.6 $ 108.1
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) TransAlta adopted the standard for variable interest entities on
Jan. 1, 2005. See Note 1 to the unaudited interim consolidated
financial statements for further discussion. Prior periods have
been restated.


Presenting earnings on a comparable basis from period to period provides management with the ability to evaluate earnings trends more readily in comparison with prior periods' results. To do so, the following items which we believe would otherwise affect the comparability of TransAlta's operating results from period to period, are excluded from net earnings: material tax adjustments, gains on sale of the Sheerness Generating Station, TA Power units, the Meridian Cogeneration Facility and land, asset impairment charges, prior period regulatory decisions, and earnings from discontinued operations, net of tax.

Earnings presented on a comparable basis from period to period is reconciled to net earnings below:



3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004(1) 2005 2004(1)
---------------------------------------------------------------------
Earnings on a comparable
basis $ 39.1 $ 33.8 $ 115.6 $ 90.9
Tax settlement on deferred
receivable 13.0 - 13.0 -
Gain on sale of TA Power
units, net of tax - 2.0 - 15.7
Prior period regulatory
decision, net of tax - - - (14.9)
Gain from discontinued
operations, net of tax - - - 9.6
New Zealand tax settlement - - - 6.8
---------------------------------------------------------------------
Net earnings $ 52.1 $ 35.8 $ 128.6 $ 108.1
---------------------------------------------------------------------
---------------------------------------------------------------------

Weighted average common
shares outstanding in
the period 196.1 193.0 196.3 192.2
---------------------------------------------------------------------
---------------------------------------------------------------------
Earnings on a comparable
basis per share $ 0.20 $ 0.17 $ 0.59 $ 0.47
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) TransAlta adopted the standard for variable interest entities on
Jan. 1, 2005. See Note 1 to the unaudited interim consolidated
financial statements for further discussion. Prior periods have
been restated.


SELECTED QUARTERLY INFORMATION (1)
(In millions of Canadian dollars except per share amounts)

Q4 2004 Q1 2005 Q2 2005 Q3 2005
---------------------------------------------------------------------
Revenue $ 660.2 $ 684.3 $ 621.2 $ 722.9
Earnings from continuing
operations 62.1 51.7 24.8 52.1
Net earnings 62.1 51.7 24.8 52.1
Basic earnings per common share:
Continuing operations 0.32 0.27 0.13 0.27
Net earnings 0.32 0.27 0.13 0.27
Diluted earnings per common share:
Continuing operations 0.32 0.26 0.13 0.27
Net earnings 0.32 0.26 0.13 0.27
---------------------------------------------------------------------
---------------------------------------------------------------------

Q4 2003 Q1 2004 Q2 2003 Q3 2004
---------------------------------------------------------------------
Revenue $ 609.1 $ 655.0 $ 592.9 $ 678.2
Earnings from continuing
operations 43.8 47.2 15.5 35.8
Net earnings 43.8 47.2 25.1 35.8
Basic earnings per common share:
Continuing operations 0.23 0.25 0.08 0.18
Net earnings 0.23 0.25 0.13 0.18
Diluted earnings per common share:
Continuing operations 0.23 0.24 0.08 0.18
Net earnings 0.23 0.24 0.13 0.18
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) TransAlta adopted the standard for variable interest entities
on Jan. 1, 2005. See Note 1 to the unaudited interim
consolidated financial statements for further discussion. Prior
periods have been restated.


TransAlta's results are partly seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are ordinarily incurred in the second and third quarters when electricity prices are expected to be lower as electricity prices generally increase in the winter months in the Canadian market. Production usually decreases in the second and third quarters in connection with increased maintenance. Margins are also typically increased in the second quarter due to the volume of hydro production resulting from spring run-off and rainfall in the Canadian and U.S. markets. TransAlta's results reflect the completion, acquisition, and disposition of plants and facilities throughout the nine months of 2004 and 2005 as described previously within this MD&A.

FORWARD-LOOKING STATEMENTS

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

CONTROLS AND PROCEDURES

As of the end of the period covered by this quarterly report, TransAlta's management, together with TransAlta's President and Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer have concluded that the disclosure controls and procedures of the company are effective.

There were no changes in TransAlta's internal control over financial reporting during the most recent fiscal quarter that have materially affected or are reasonably likely to materially affect TransAlta's internal control over financial reporting.



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

3 months ended 9 months ended
Sept. 30 Sept. 30
---------------------------------------------------------------------
Unaudited 2005 2004 2005 2004
---------------------------------------------------------------------
(Restated, (Restated,
Note 1) Note 1)
Revenues $ 722.9 $ 678.2 $ 2,028.4 $ 1,926.1
Trading purchases (45.3) (59.9) (135.2) (140.4)
Fuel and purchased power (304.8) (264.7) (817.8) (761.8)
---------------------------------------------------------------------
Gross margin 372.8 353.6 1,075.4 1,023.9
---------------------------------------------------------------------
Operations, maintenance
and administration 161.8 149.2 444.0 419.7
Depreciation and
amortization (Note 11) 86.1 88.4 268.1 267.3
Taxes, other than income
taxes 5.1 5.5 16.5 17.6
---------------------------------------------------------------------
Operating expenses 253.0 243.1 728.6 704.6
---------------------------------------------------------------------
Gain on sale of TransAlta
Power partnership units
(Note 2) - (3.1) - (24.2)
Prior period regulatory
decision (Note 4) - - - 22.9
---------------------------------------------------------------------
- (3.1) - (1.3)
---------------------------------------------------------------------
Operating income 119.8 113.6 346.8 320.6
Foreign exchange gain
(loss) 1.2 (1.7) 1.7 (2.4)
Net interest expense
(Note 5) (49.0) (50.3) (148.2) (161.4)
Equity income (loss)
(Note 1) (2.1) (1.8) 0.1 (4.2)
---------------------------------------------------------------------
Earnings before
non-controlling interests
and income taxes 69.9 59.8 200.4 152.6
Non-controlling interests 13.0 12.3 37.2 31.3
---------------------------------------------------------------------
Earnings before income
taxes 56.9 47.5 163.2 121.3
Income tax expense 4.8 11.7 34.6 22.8
---------------------------------------------------------------------
Earnings from continuing
operations 52.1 35.8 128.6 98.5
Gain on disposal of
discontinued operations,
net of tax (Note 2) - - - 9.6
---------------------------------------------------------------------
Net earnings $ 52.1 $ 35.8 $ 128.6 $ 108.1
Common share dividends (49.4) (48.2) (147.3) (144.1)
Adjustment arising from
normal course issuer
bid (Note 8) - - - (1.1)
Retained earnings
Opening balance 870.1 909.2 891.5 933.9
---------------------------------------------------------------------
Closing balance $ 872.8 $ 896.8 $ 872.8 $ 896.8
---------------------------------------------------------------------
---------------------------------------------------------------------
Weighted average common
shares outstanding in
the period 196.1 193.0 196.3 192.2
---------------------------------------------------------------------
---------------------------------------------------------------------
Basic earnings per share
Earnings from continuing
operations $ 0.27 $ 0.18 $ 0.66 $ 0.51
Earnings from
discontinued operations - - - 0.05
---------------------------------------------------------------------
Net earnings $ 0.27 $ 0.18 $ 0.66 $ 0.56
---------------------------------------------------------------------
---------------------------------------------------------------------

Diluted earnings per share
Earnings from continuing
operations $ 0.27 $ 0.18 $ 0.65 $ 0.51
Earnings from discontinued
operations - - - 0.05
---------------------------------------------------------------------
Net earnings $ 0.27 $ 0.18 $ 0.65 $ 0.56
---------------------------------------------------------------------
---------------------------------------------------------------------
See accompanying notes.


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

3 months ended 9 months ended
Sept. 30 Sept. 30
---------------------------------------------------------------------
Unaudited 2005 2004 2005 2004
---------------------------------------------------------------------
(Restated, (Restated,
Note 1) Note 1)
Operating activities
Net earnings $ 52.1 $ 35.8 $ 128.6 $ 108.1
Depreciation and
amortization (Note 11) 92.3 96.5 290.8 292.5
Non-controlling interests 13.0 12.3 37.2 31.3
Asset retirement
obligation accretion
(Note 6) 4.9 5.1 15.2 15.4
Future income taxes 11.5 12.1 11.0 1.0
Unrealized loss (gain)
from Energy Marketing
activities 7.1 4.6 (5.3) (4.8)
Asset retirement
obligation costs settled (15.6) (10.1) (21.0) (16.7)
Foreign exchange loss
(gain) (1.2) 1.7 (1.7) 2.4
Loss (gain) on sale of
assets - 1.2 - (10.9)
Equity (income) loss
(Note 1) 2.1 1.8 (0.1) 4.2
Other non-cash items (5.5) 7.1 (7.8) 3.2
Prior period regulatory
decision (Note 4) - - - 22.9
Gain on sale of TransAlta
Power partnership units
(Note 2) - (3.1) - (24.2)
---------------------------------------------------------------------
160.7 165.0 446.9 424.4
Change in non-cash
operating working
capital balances (12.2) (22.4) (39.4) (9.1)
---------------------------------------------------------------------
Cash flow from operating
activities 148.5 142.6 407.5 415.3
---------------------------------------------------------------------
Investing activities
Long-term receivables - - - 90.8
Additions to property,
plant and equipment (77.0) (100.4) (221.9) (268.1)
Proceeds on sale of
property, plant and
equipment 1.6 0.7 1.6 12.7
Proceeds on sale of
TransAlta Power
partnership units (Note 2) - 2.6 - 61.7
Equity investment 31.8 21.2 14.9 15.6
Restricted cash (9.3) 4.6 (4.7) 3.5
Realized foreign exchange
gain on net investments 79.9 48.1 83.2 10.2
Deferred charges and other 0.7 5.0 - 0.1
---------------------------------------------------------------------
Cash flow from (used in)
investing activities 27.7 (18.2) (126.9) (73.5)
---------------------------------------------------------------------
Financing activities
Increase (repayment) of
short-term debt (92.0) (35.4) 139.7 (72.9)
Repayment of long-term debt (18.2) (8.9) (40.1) (135.1)
Dividends on common shares (61.2) (32.6) (96.8) (102.6)
Issuance of long-term debt - - - 2.7
Redemption of common shares - - - (1.5)
Redemption of preferred
securities - - (300.0) -
Net proceeds on issuance of
common shares (Note 8) 5.4 2.4 13.4 2.4
Distributions to
subsidiary's
non-controlling
interests (17.8) (31.9) (53.4) (33.5)
Reduction in advance to
TransAlta Power (Note 2) 3.4 0.8 13.2 -
---------------------------------------------------------------------
Cash flow used in financing
activities (180.4) (105.6) (324.0) (340.5)
---------------------------------------------------------------------
Cash flow from (used in)
operating, investing
and financing activities (4.2) 18.8 (43.4) 1.3
Effect of translation on
foreign currency cash 1.9 - (1.8) -
---------------------------------------------------------------------
Increase (decrease) in
cash and cash equivalents (2.3) 18.8 (45.2) 1.3
Cash and cash equivalents,
beginning of period 58.3 106.3 101.2 123.8
---------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 56.0 $ 125.1 $ 56.0 $ 125.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash taxes paid $ 13.2 $ 7.6 $ 31.7 $ 24.0
Cash interest paid $ 38.7 $ 43.6 $ 136.0 $ 160.1
---------------------------------------------------------------------
---------------------------------------------------------------------
See accompanying notes.


TRANSALTA CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions of Canadian dollars)

Sept. 30 Dec. 31
Unaudited 2005 2004 (1)
---------------------------------------------------------------------
(Restated,
Note 1)
ASSETS
Current assets
Cash and cash equivalents $ 56.0 $ 101.2
Accounts receivable 567.3 447.0
Prepaid expenses 70.5 52.3
Price risk management assets (Note 3) 249.1 61.4
Future income tax assets 22.7 21.5
Income taxes receivable 62.2 60.1
Inventory 46.8 39.9
Current portion of other assets 12.5 296.4
---------------------------------------------------------------------
1,087.1 1,079.8
---------------------------------------------------------------------
Restricted cash 13.6 8.9
Investments (Note 1) 406.6 402.5
Property, plant and equipment
Cost 8,334.3 8,295.4
Accumulated depreciation (2,761.4) (2,592.8)
---------------------------------------------------------------------
5,572.9 5,702.6
Goodwill 138.4 142.2
Intangible assets 353.2 392.3
Future income tax assets 144.0 132.0
Price risk management assets (Note 3) 38.9 32.5
Other assets 186.7 206.0
---------------------------------------------------------------------
Total assets $ 7,941.4 $ 8,098.8
---------------------------------------------------------------------
---------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt $ 175.5 $ 34.4
Accounts payable and accrued liabilities 561.0 462.5
Price risk management liabilities (Note 3) 230.3 49.9
Income taxes payable - 6.1
Future income tax liabilities 17.0 11.1
Dividends payable 21.0 19.3
Deferred credits and other current
liabilities 3.1 241.5
Current portion of long-term debt
- recourse (Note 5) 487.5 530.5
Current portion of long-term debt
- non-recourse (Note 5) 36.4 49.6
---------------------------------------------------------------------
1,531.8 1,404.9
---------------------------------------------------------------------
Long-term debt - recourse (Note 5) 1,653.7 1,939.8
Long-term debt - non-recourse (Note 5) 336.0 381.3
Preferred securities (Note 5) 175.0 175.0
Deferred credits and other long-term
liabilities (Note 6) 384.4 397.8
Future income tax liabilities 737.9 703.9
Price risk management liabilities (Note 3) 36.7 28.5
Non-controlling interests 597.3 616.4
Common shareholders' equity
Common shares (Note 8) 1,675.0 1,611.9
Retained earnings 872.8 891.5
Cumulative translation adjustment (59.2) (52.2)
---------------------------------------------------------------------
2,488.6 2,451.2
---------------------------------------------------------------------
Total liabilities and shareholders' equity $ 7,941.4 $ 8,098.8
---------------------------------------------------------------------
---------------------------------------------------------------------
Contingencies (Note 4 and 9)
Commitments (Notes 10 and 12)
See accompanying notes.

(1) Derived from the audited Dec. 31, 2004 consolidated financial
statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

1. ACCOUNTING POLICIES

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

These unaudited interim financial statements reflect all adjustments (consisting of normal recurring adjustments and accruals) that are, in the opinion of management, necessary for a fair presentation of the results for the interim period.

TransAlta's results are partly seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are ordinarily incurred in the second and third quarters when electricity prices are expected to be lower as electricity prices generally increase in the winter months in the Canadian market. Margins are also typically increased in the second quarter due to increased hydro production resulting from spring run-off and rainfall in the Canadian and U.S. markets.

These unaudited interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) using the same accounting policies as those used in the corporation's most recent annual consolidated financial statements, except for variable interest entities, as explained below.

Change in accounting policies

Effective Jan. 1, 2005, TransAlta adopted the Canadian Institute of Chartered Accountants (CICA) Accounting Guideline 15 "Consolidation of Variable Interest Entities" (VIE). The guideline establishes that a VIE is to be consolidated by the primary beneficiary based upon the determination of who will receive the majority of a VIE's expected losses, expected residual returns, or both, rather than solely based on the voting interests. Variable interests are ownership interests or contractual relationships that enable the holder to share in the financial risks and rewards resulting from the activities of a VIE.

The accounting guideline specifies that an entity is a VIE if either of the following criteria are met:

1. total equity invested is insufficient to finance the entity without additional subordinated financial support; or

2. the holders of the equity investment, as a group,

i) do not have the right to make decisions about an entity's activities that have a significant effect on the success of the entity; or

ii) are protected either directly or indirectly from variability in cash flows from the entity; or

iii) do not have the right to all of the residual returns of the entity.

The corporation has considered the provisions of the guideline for all subsidiaries and their related power purchase, power sale or tolling agreements. Factors considered in the analysis include the duration of the agreements, how capacity and energy payments are determined, source of payment terms for fuel, as well as responsibility and payment for operating and maintenance expenses.

As a result of this review, the corporation determined that the wholly owned subsidiary that holds TransAlta's interest in the Campeche power plant is considered a VIE as the equity invested was not sufficient to finance the entity without additional subordinated financial support. The corporation then determined that the power sale contract with the Comision Federal de Electridad (CFE) insulates the corporation from significant variability in the fuel costs and related cash flows from the entity. Therefore, TransAlta is not the primary beneficiary of the VIE and does not consolidate the entity. Accordingly, the subsidiary owning the Campeche plant is presented as an equity investment and the results from operations are presented as equity income on the consolidated income statement. There was no impact to net earnings as a result of adoption of this accounting guideline.

On adoption of the accounting guideline in the first quarter of 2005, the wholly owned subsidiary that holds TransAlta's interest in the Chihuahua power plant was not considered a VIE as the equity invested in the subsidiary was considered to be sufficient to finance the entity without additional subordinated financial support. However, during the second quarter of 2005, the corporation determined that the entity should also be considered a VIE as the power sale contract with the CFE indirectly protects TransAlta from the variability in the fuel costs and related cash flows from the entity. Therefore the entity is a VIE and as TransAlta is not the primary beneficiary of the VIE, it does not consolidate the entity. Accordingly, the subsidiary owning the Chihuahua plant is presented as an equity investment and the results from operations of the plant are presented as equity income on the consolidated income statement. There was no impact to net earnings as a result of adoption of this interpretation. The presentation of the results from operations for the first quarter of 2005 have been restated to conform with current presentation.

The following is summary information about the subsidiaries holding the Campeche and Chihuahua plants:



Campeche Chihuahua
---------------------------------------------------------------------
Total assets $ 274.7 $ 310.2
Total liabilities $ 182.1 $ 18.3
Ownership interest and maximum exposure
to loss $ 91.6 $ 312.2
Capacity (MW) 252 259
Production (GWh) (nine months ended
Sept. 30, 2005) 1,301 938
---------------------------------------------------------------------


2. DISPOSALS

On Dec. 1, 2004, TransAlta completed the sale of its 50 per cent interest in the 220 megawatt (MW) Meridian Cogeneration Facility located in Lloydminster, Saskatchewan to TransAlta Cogeneration, L.P. (TA Cogen), owned 50.01 per cent by TransAlta and 49.99 per cent by TransAlta Power, L.P. (TA Power), for its fair value of $110.0 million. TA Cogen financed the acquisition through the use of $50.0 million of cash on hand, by the issuance of $30.0 million of units to each of TransAlta Energy Corporation (TEC) and TA Power and by an advance to TEC for $30.0 million. The advance outstanding at Sept. 30, 2005 was $6.5 million and is included in accounts receivable.

On July 31, 2003, TransAlta completed the sale of its 50 per cent interest in the two-unit 756 MW coal-fired Sheerness Generating Station to TA Cogen. As part of the financing, and concurrent with the sale, TA Power issued 17.75 million partnership units and 17.75 million warrants to the public, and 17.75 million partnership units to TransAlta. As a result of the unit issuance, TransAlta's ownership interest in TA Power on July 31, 2003 was approximately 26 per cent. Each warrant, when exercised, was exchangeable for one TA Power unit at any time until Aug. 3, 2004. As the warrants were exercised, TransAlta sold TA Power units back to TA Power for $9.30 per unit, reducing its ownership interest in TA Power and increasing cash proceeds. As a result of exercising warrants and the subsequent sale of TA Power units by the corporation, TransAlta's ownership interest in TA Power was reduced to 0.01 per cent held by TransAlta Power Ltd., the general partner of TA Power, as at Sept. 30, 2005.

For the three and nine months ended Sept. 30, 2004, TransAlta recognized $3.1 million and $24.2 million respectively of dilution gains on the exercise of warrants.

In June 2004, a settlement was reached to finalize the sale of the Transmission operations. In April 2002, TransAlta's Transmission operations were sold for proceeds of $820.7 million. The disposal resulted in an after-tax gain on sale of $120.0 million that was recorded in the second and fourth quarters of 2002. During the second quarter of 2004, final working capital adjustments were made to reflect post-closing adjustments and other provisions related to closing costs, which resulted in an additional $9.6 million after-tax gain, bringing the final gain on the sale of the Transmission operations to $129.6 million.

3. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES

Energy Marketing's price risk management assets and liabilities represent the value of unsettled (unrealized) proprietary trading transactions and those asset-backed trading transactions accounted for on a fair value basis. With the exception of financial transmission contracts and gas/power spread options, the fair value of all energy trading activities is based on quoted market prices. The fair value of financial transmission contracts and the spread options are based upon statistical analysis of historical data as well as forward market data and forward market volatilities. All physical transmission contracts are accounted for on an accrual basis in accordance with the U.S. Financial Accounting Standards Board (FASB) Emerging Issues Task Force (EITF) pronouncement 02-03.

The following table illustrates movements in the fair value of the corporation's price risk management assets during the nine months ended Sept. 30, 2005:



Change in fair value of net assets Fair value
---------------------------------------------------------------------
Net price risk management assets outstanding at
Dec. 31, 2004 $ 15.5
Contracts realized, amortized or settled during the
period (16.7)
Changes in values attributable to market price and other
market changes 6.1
New contracts entered into during the current calendar year 16.1
---------------------------------------------------------------------
Net price risk management assets outstanding at
Sept. 30, 2005 $ 21.0
---------------------------------------------------------------------
---------------------------------------------------------------------


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

2010 and
2005 2006 2007 2008 2009 thereafter Total
---------------------------------------------------------------------
Prices
actively
quoted $ 2.1 $ 5.3 $ 1.2 $ 1.6 $ 0.6 $ 0.3 $ 11.1
Prices
based on
models 7.3 2.6 - - - - 9.9
---------------------------------------------------------------------
$ 9.4 $ 7.9 $ 1.2 $ 1.6 $ 0.6 $ 0.3 $ 21.0
---------------------------------------------------------------------
---------------------------------------------------------------------


The carrying and fair value of energy trading assets and liabilities
included on the consolidated balance sheet are as follows:

Sept. 30 Dec. 31
Balance Sheet 2005 2004
---------------------------------------------------------------------
Price risk management assets
Current $ 249.1 $ 61.4
Long-term 38.9 32.5
Price risk management liabilities
Current (230.3) (49.9)
Long-term (36.7) (28.5)
---------------------------------------------------------------------
Net price risk management assets
outstanding $ 21.0 $ 15.5
---------------------------------------------------------------------
---------------------------------------------------------------------


In accordance with EITF 02-03, physical transmission is accounted for under accrual accounting. As of Sept. 30, 2005, TransAlta had recorded $1.6 million on the consolidated balance sheet as prepaid transmission related to these contracts. The maximum term of these contracts is 12 months.

The corporation's trading positions at Sept. 30, 2005 were as follows:



Electricity Natural Gas
Units (000s) (MWh) (GJ)
---------------------------------------------------------------------
Fixed price payor, notional amounts,
Sept. 30, 2005 24,151 39,587
Fixed price payor, notional amounts,
Dec. 31, 2004 14,138 35,222

Fixed price receiver, notional amounts,
Sept. 30, 2005 27,042 34,718
Fixed price receiver, notional amounts,
Dec. 31, 2004 15,854 29,721

Maximum term in months, Sept. 30, 2005 39 25
Maximum term in months, Dec. 31, 2004 48 34
---------------------------------------------------------------------


The corporation's electrical transmission contracts trading position was 11.8 million megawatt hours (MWh) at Sept. 30, 2005 compared to 4.4 million MWh at Dec. 31, 2004.

4. LONG-TERM RECEIVABLES

At Dec. 31, 2000, TransAlta made a provision of US$28.8 million to account for potential refund liabilities relating to energy sales in California. On Dec. 12, 2002, a U.S. Federal Energy Regulatory Commission (FERC) Administrative Law Judge issued proposed findings of fact that recommended TransAlta refund US$9.0 million for electricity sales made to the California Independent System Operator (CAISO) and US$13.0 million for electricity sales made to the California Power Exchange (CALPX). In March 2003, FERC ordered the CAISO to review reference power and gas prices which are used to determine mitigated market clearing prices and refund obligations. On March 17, 2004, the CAISO released its preliminary adjusted prices. Based on these prices, the estimated refund liability now owed by TransAlta is US$46.0 million, being US$27.6 million to the CAISO, US$17.9 million to the CALPX and US$0.5 million to the Automated Power Exchange. Therefore, in March 2004, TransAlta recorded an additional pre-tax provision of US$17.2 million (Cdn$22.9 million). The after-tax impact was Cdn$14.9 million. The final adjusted prices were released in October 2004 and were substantially the same as those released on March 17, 2004.

FERC has provided TransAlta with an opportunity to petition for relief from refund obligations. To be successful in such a petition for relief TransAlta will be required to demonstrate that, as a result of the refund methodology, it has suffered operating losses in respect of California transactions during the refund period. On Aug. 8, 2005, FERC issued an order detailing the methodology for a petition for relief from refund obligations. TransAlta prepared a petition for relief from the refund obligation and filed it with FERC. The CAISO and CALPX reviewed and commented on our petition and TransAlta replied to the CAISO and CALPX comments on Oct. 17, 2005. While the outcome of this filing cannot be determined at this time, any such relief would be accounted for only at the time that it is obtained from FERC.

The impact of prior period regulatory decisions relating to prior reporting periods are recorded when the effect of such decisions are known, without adjustment to the financial statements of prior periods.



5. LONG-TERM DEBT AND NET INTEREST EXPENSE

A. Amounts outstanding

As at Sept. 30, 2005 Dec. 31, 2004
---------------------------------------------------------------------
Outstanding Interest Outstanding Interest
(2) (1) (1)
---------------------------------------------------------------------
Debentures, due
2005 to 2033 $ 1,388.5 6.5% $ 1,388.5 6.5%
Senior Notes,
US$600.0 million 700.6 6.3% 733.6 6.3%
Non-recourse debt 372.3 6.9% 423.3 6.9%
Notes payable
- Windsor plant,
due 2005 to 2014 52.1 7.4% 55.0 7.4%
Preferred
securities,
due in 2048 (3) 175.0 7.8% 475.0 7.8%
Capital lease
obligation, due
2005 to 2006 0.1 8.0% 0.8 8.0%
---------------------------------------------------------------------
2,688.6 3,076.2
Less current portion 523.9 580.1
---------------------------------------------------------------------
$ 2,164.7 $ 2,496.1
---------------------------------------------------------------------
---------------------------------------------------------------------

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

(2) Except as noted, terms have not changed materially from
disclosure in Note 11 of the Dec. 31, 2004 annual report.

(3) During the first quarter of 2005, TransAlta redeemed all of its
7.50 per cent Preferred Securities which had an aggregate
principal amount of $175.0 million and all of its 8.15 per cent
Preferred Securities which had an aggregate principal amount of
$125.0 million.


B. Principal repayments

2005 $ 243.9
2006 395.8
2007 46.9
2008 155.0
2009 237.1
2010 and thereafter 1,609.9
---------------------------------------------------------------------
$ 2,688.6
---------------------------------------------------------------------
---------------------------------------------------------------------


TransAlta has included the corporation's preferred securities as a liability on the consolidated balance sheets. Preferred securities distributions are included in interest expense as shown below:



3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Interest on recourse and
non-recourse debt $ 48.3 $ 47.4 $ 141.2 $ 150.8
Interest on preferred
securities 3.4 9.2 13.1 27.6
Interest income (2.7) (0.8) (2.7) (1.7)
Capitalized interest - (5.5) (3.4) (15.3)
---------------------------------------------------------------------
Net interest expense $ 49.0 $ 50.3 $ 148.2 $ 161.4
---------------------------------------------------------------------
---------------------------------------------------------------------


6. ASSET RETIREMENT OBLIGATIONS

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

Balance, Dec. 31, 2004 $ 243.4
Liabilities incurred in period 9.8
Liabilities settled in period (21.0)
Accretion expense 15.2
Revisions in estimated cash flows 3.7
Change in foreign exchange rates (6.6)
---------------------------------------------------------------------
Balance, Sept. 30, 2005 $ 244.5
---------------------------------------------------------------------
---------------------------------------------------------------------


Asset retirement obligations are included in deferred credits and other long-term liabilities on the consolidated balance sheets.

7. EMPLOYEE FUTURE BENEFITS

The corporation has registered pension plans in Canada and the U.S. covering substantially all employees of the corporation in these countries and specific named employees working internationally. These plans have defined benefit and defined contribution options and in Canada, there is an additional supplemental defined benefit plan for certain employees. The defined benefit option of the registered pension plans has been closed for new employees for all periods presented. Costs recognized in the period are presented below:



3 months ended
Sept. 30, 2005 Registered Supplemental Other Total
---------------------------------------------------------------------
Current service cost $ 1.1 $ 0.3 $ 0.3 $ 1.7
Interest cost 5.1 0.5 0.3 5.9
Expected return on plan assets (6.0) - - (6.0)
Experience loss 0.6 0.1 0.1 0.8
Amortization of net transition
(asset)obligation (2.3) 0.1 0.1 (2.1)
---------------------------------------------------------------------
Defined benefit (income)expense (1.5) 1.0 0.8 0.3
Defined contribution option
expense of registered pension
plan 2.7 - - 2.7
---------------------------------------------------------------------
Net expense $ 1.2 $ 1.0 $ 0.8 $ 3.0
---------------------------------------------------------------------
---------------------------------------------------------------------


3 months ended
Sept. 30, 2004 Registered Supplemental Other Total
---------------------------------------------------------------------
Current service cost $ 1.1 $ 0.2 $ 0.3 $ 1.6
Interest cost 5.1 0.5 0.3 5.9
Expected return on plan assets (5.9) - - (5.9)
Experience loss 0.5 0.1 0.1 0.7
Amortization of net transition
(asset)obligation (2.3) - - (2.3)
---------------------------------------------------------------------
Defined benefit (income)expense (1.5) 0.8 0.7 -
Defined contribution option
expense of registered pension
plan 2.4 - - 2.4
---------------------------------------------------------------------
Net expense $ 0.9 $ 0.8 $ 0.7 $ 2.4
---------------------------------------------------------------------
---------------------------------------------------------------------


9 months ended
Sept. 30, 2005 Registered Supplemental Other Total
---------------------------------------------------------------------
Current service cost $ 3.3 $ 0.9 $ 0.9 $ 5.1
Interest cost 15.3 1.5 0.9 17.7
Expected return on plan assets (18.0) - - (18.0)
Experience loss 1.8 0.3 0.3 2.4
Amortization of net transition
(asset)obligation (6.9) 0.3 0.3 (6.3)
---------------------------------------------------------------------
Defined benefit (income)expense (4.5) 3.0 2.4 0.9
Defined contribution option
expense of registered pension
plan 9.1 - - 9.1
---------------------------------------------------------------------
Net expense $ 4.6 $ 3.0 $ 2.4 $10.0
---------------------------------------------------------------------
---------------------------------------------------------------------


9 months ended
Sept. 30, 2004 Registered Supplemental Other Total
---------------------------------------------------------------------
Current service cost $ 3.2 $ 0.8 $ 0.5 $ 4.5
Interest cost 15.4 1.6 0.8 17.8
Expected return on plan assets (17.8) - - (17.8)
Experience loss 1.6 0.4 0.3 2.3
Amortization of net transition
(asset)obligation (6.9) 0.2 - (6.7)
---------------------------------------------------------------------
Defined benefit expense (income) (4.5) 3.0 1.6 0.1
Defined contribution option
expense of registered pension
plan 8.0 - - 8.0
---------------------------------------------------------------------
Net expense $ 3.5 $ 3.0 $ 1.6 $ 8.1
---------------------------------------------------------------------
---------------------------------------------------------------------


8. COMMON SHARES ISSUED AND OUTSTANDING

A. Issued and outstanding

TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value. At Sept. 30, 2005, the corporation had 197.7 million (Dec. 31, 2004 - 194.1 million) common shares issued and outstanding. During the three and nine months ended Sept. 30, 2005, 1.3 million (2004 - 1.0 million) and 3.6 million (2004 - 2.3 million) shares respectively were issued, net of repurchases, for net proceeds of $22.5 million (2004 - $17.3 million) and $61.9 million (2004 - $40.7 million) respectively. Included in the shares issued and net proceeds received are shares issued under the dividend reinvestment and share purchase plan. During the three and nine months ended Sept. 30, 2005, 0.9 million (2004 - 1.0 million) and 2.8 million (2004 - 2.3 million) shares, respectively, were issued for gross proceeds of $17.4 million (2004 - $15.0 million) and $50.1 million (2004 - $39.0 million), respectively.

In February 2004, TransAlta announced a normal course issuer bid to repurchase up to 3.0 million common shares for cancellation. 143,500 shares were repurchased in the first nine months of 2004. The $1.1 million excess of the repurchase price over the average net book value was charged to retained earnings.

B. Stock options

At Sept. 30, 2005, the corporation had 3.3 million outstanding employee stock options (Dec. 31, 2004 - 2.9 million).

The corporation uses the fair value method of accounting for awards granted under its fixed stock option plans and its performance stock option plan. In March 2005, 1.2 million options were granted. One quarter of the options granted vest on each of the first, second, third and fourth anniversaries of the date of grant and expire after 10 years. The estimated fair value of these options granted was determined using the binomial model using the following assumptions, resulting in a fair value of $6.84 per option.



2005
---------------------------------------------------------------------
Risk-free interest rate 4.3%
Life of the options (years) 10.0
Dividend rate 5.6%
Volatility in the price of the corporation's shares 47.0%
---------------------------------------------------------------------


Prior to Jan. 1, 2003, the intrinsic value method was used. The following table provides pro forma measures of net earnings and earnings per share had compensation expense been recognized for awards granted prior to 2003 based on the estimated fair value of the options on the grant date in accordance with the fair value method of accounting for stock-based compensation:



3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Reported net earnings $ 52.1 $ 35.8 $ 128.6 $ 108.1
Compensation expense 0.4 0.4 1.1 1.3
---------------------------------------------------------------------
Pro forma net earnings $ 51.7 $ 35.4 $ 127.5 $ 106.8
---------------------------------------------------------------------
---------------------------------------------------------------------

Reported basic earnings
per share $ 0.27 $ 0.18 $ 0.66 $ 0.56
Compensation expense per
share - - 0.01 0.01
---------------------------------------------------------------------
Pro forma basic earnings per
share $ 0.27 $ 0.18 $ 0.65 $ 0.55
---------------------------------------------------------------------
---------------------------------------------------------------------

Reported diluted earnings
per share $ 0.27 $ 0.18 $ 0.65 $ 0.56
Compensation expense per
share - - 0.01 0.01
---------------------------------------------------------------------
Pro forma diluted earnings
per share $ 0.27 $ 0.18 $ 0.64 $ 0.55
---------------------------------------------------------------------
---------------------------------------------------------------------


9. CONTINGENCIES

TransAlta is occasionally named as a party in various claims and legal proceedings which arise during the normal course of its business. TransAlta reviews each of these claims, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. Although there can be no assurance that any particular claim will be resolved in the corporation's favour, the corporation does not believe that the outcome of any claims or potential claims of which it is currently aware will have a material adverse effect on the corporation, taken as a whole.

10. GUARANTEES

TransAlta has provided guarantees of subsidiaries' obligations under contracts that facilitate physical and financial transactions in various derivatives. To the extent liabilities related to these guaranteed contracts exist for trading activities, they are included in the consolidated balance sheet. To the extent liabilities exist related to these guaranteed contracts for hedges, they are not recognized on the consolidated balance sheet. The guarantees provided for under all contracts facilitating physical and financial transactions in various derivatives at Sept. 30, 2005 was a maximum of $1.5 billion. In addition, the corporation has a number of unlimited guarantees. The fair value of the trading and hedging positions under contracts where TransAlta has a net liability at Sept. 30, 2005, under the limited and unlimited guarantees, was $601.9 million as compared to $345.2 million at Dec. 31, 2004.

TransAlta has also provided guarantees of subsidiaries' obligations to perform and make payments under various other contracts. The amount guaranteed under these contracts at Sept. 30, 2005 was a maximum of $653.3 million, as compared to $662.5 million at Dec. 31, 2004. In addition, the corporation has a number of unlimited guarantees. To the extent actual obligations exist under the performance guarantees at Sept. 30, 2005, they are included in accounts payable and accrued liabilities.

The corporation has approximately $834.8 million of undrawn collateral available to secure these exposures.

11. SEGMENTED DISCLOSURES

Each business segment assumes responsibility for its operating results measured to operating income.



3 months ended Energy
Sept. 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Revenues $ 668.2 $ 54.7 $ - $ 722.9
Trading purchases - (45.3) - (45.3)
Fuel and purchased power (304.8) - - (304.8)
---------------------------------------------------------------------
Gross margin 363.4 9.4 - 372.8
---------------------------------------------------------------------
Operations, maintenance
and administration 138.7 3.0 20.1 161.8
Depreciation
and amortization 83.0 0.5 2.6 86.1
Taxes, other than
income taxes 5.1 - - 5.1
---------------------------------------------------------------------
Operating expenses 226.8 3.5 22.7 253.0
---------------------------------------------------------------------
Operating income (loss)
before corporate
allocations 136.6 5.9 (22.7) 119.8
Corporate allocations 19.8 2.9 (22.7) -
---------------------------------------------------------------------
Operating income $ 116.8 $ 3.0 $ - 119.8
---------------------------------------------------------------------
Foreign exchange gain 1.2
Net interest expense (49.0)
Equity income (2.1)
---------------------------------------------------------------------
Earnings from
operations before
income taxes and
non-controlling
interests $ 69.9
---------------------------------------------------------------------
---------------------------------------------------------------------


3 months ended Energy
Sept. 30, 2004 Generation Marketing Corporate Total
---------------------------------------------------------------------
Revenues $ 604.4 $ 73.8 $ - $ 678.2
Trading purchases - (59.9) - (59.9)
Fuel and purchased power (264.7) - - (264.7)
---------------------------------------------------------------------
Gross margin 339.7 13.9 - 353.6
---------------------------------------------------------------------
Operations, maintenance
and administration 134.7 1.6 12.9 149.2
Depreciation
and amortization 84.9 0.6 2.9 88.4
Taxes, other than
income taxes 5.5 - - 5.5
---------------------------------------------------------------------
Operating expenses 225.1 2.2 15.8 243.1
---------------------------------------------------------------------
Gain on sale of
TransAlta Power
partnership units 3.1 - - 3.1
---------------------------------------------------------------------
Operating income (loss)
before corporate
allocations 117.7 11.7 (15.8) 113.6
Corporate allocations 14.1 1.7 (15.8) -
---------------------------------------------------------------------
Operating income $ 103.6 $ 10.0 $ - 113.6
---------------------------------------------------------------------
Foreign exchange loss (1.7)
Net interest expense (50.3)
Equity loss (1.8)
---------------------------------------------------------------------
Earnings from
operations before
income taxes and
non-controlling
interests $ 59.8
---------------------------------------------------------------------
---------------------------------------------------------------------


9 months ended Energy
Sept. 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Revenues $1,846.0 $ 182.4 $ - $2,028.4
Trading purchases - (135.2) - (135.2)
Fuel and purchased power (817.8) - - (817.8)
---------------------------------------------------------------------
Gross margin 1,028.2 47.2 - 1,075.4
---------------------------------------------------------------------
Operations, maintenance
and administration 379.8 8.2 56.0 444.0
Depreciation
and amortization 258.0 1.3 8.8 268.1
Taxes, other than
income taxes 16.5 - - 16.5
---------------------------------------------------------------------
Operating expenses 654.3 9.5 64.8 728.6
---------------------------------------------------------------------
Operating income (loss)
before corporate
allocations 373.9 37.7 (64.8) 346.8
Corporate allocations 56.4 8.4 (64.8) -
---------------------------------------------------------------------
Operating income $ 317.5 $ 29.3 $ - 346.8
---------------------------------------------------------------------
Foreign exchange gain 1.7
Net interest expense (148.2)
Equity income 0.1
---------------------------------------------------------------------
Earnings from
continuing operations
before income taxes
and non-controlling
interests $ 200.4
---------------------------------------------------------------------
---------------------------------------------------------------------


9 months ended Energy
Sept. 30, 2004 Generation Marketing Corporate Total
---------------------------------------------------------------------
Revenues $1,742.4 $ 183.7 $ - $1,926.1
Trading purchases - (140.4) - (140.4)
Fuel and purchased power (761.8) - - (761.8)
---------------------------------------------------------------------
Gross margin 980.6 43.3 - 1,023.9
---------------------------------------------------------------------
Operations, maintenance
and administration 367.1 5.0 47.6 419.7
Depreciation
and amortization 256.6 1.5 9.2 267.3
Taxes, other than
income taxes 17.6 - - 17.6
---------------------------------------------------------------------
Operating expenses 641.3 6.5 56.8 704.6
---------------------------------------------------------------------
Prior period
regulatory decision - (22.9) - (22.9)
Gain on sale of
TransAlta Power
partnership units 24.2 - - 24.2
---------------------------------------------------------------------
Operating income (loss)
before corporate
allocations 363.5 13.9 (56.8) 320.6
Corporate allocations 50.5 6.3 (56.8) -
---------------------------------------------------------------------
Operating income $ 313.0 $ 7.6 $ - 320.6
---------------------------------------------------------------------
Foreign exchange loss (2.4)
Net interest expense (161.4)
Equity loss (4.2)
---------------------------------------------------------------------
Earnings from
continuing operations
before income taxes
and non-controlling
interests $ 152.6
---------------------------------------------------------------------
---------------------------------------------------------------------


II. Selected balance sheet information

Energy
Sept. 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Goodwill $ 108.9 $ 29.5 $ - $ 138.4
Total segment assets $6,483.9 $ 530.4 $ 927.1 $7,941.4
---------------------------------------------------------------------
---------------------------------------------------------------------


Dec. 31, 2004
---------------------------------------------------------------------
Goodwill $ 112.7 $ 29.5 $ - $ 142.2
Total segment assets $6,980.7 $ 278.6 $ 839.5 $8,098.8
---------------------------------------------------------------------
---------------------------------------------------------------------


III. Selected cash flow information

3 months ended Energy
Sept. 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Capital expenditures $ 77.0 $ - $ - $ 77.0
---------------------------------------------------------------------
---------------------------------------------------------------------


3 months ended
Sept. 30, 2004
---------------------------------------------------------------------
Capital expenditures $ 98.2 $ 0.1 $ 2.1 $ 100.4
---------------------------------------------------------------------
---------------------------------------------------------------------


9 months ended Energy
Sept. 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Capital expenditures $ 218.1 $ - $ 3.8 $ 221.9
---------------------------------------------------------------------
---------------------------------------------------------------------


9 months ended
Sept. 30, 2004
---------------------------------------------------------------------
Capital expenditures $ 261.0 $ 0.5 $ 6.6 $ 268.1
---------------------------------------------------------------------
---------------------------------------------------------------------


3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Depreciation and amortization
expense for reportable segments $ 86.1 $ 88.4 $ 268.1 $ 267.3
Mining equipment depreciation,
included in fuel and purchased
power 12.6 16.5 38.0 40.4
Accretion expense, included
in depreciation and amortization
expense (4.9) (5.1) (15.2) (15.4)
Other (1.5) (3.3) (0.1) 0.2
---------------------------------------------------------------------
Depreciation and amortization
expense per statements of
cash flow $ 92.3 $ 96.5 $ 290.8 $ 292.5
---------------------------------------------------------------------
---------------------------------------------------------------------


12. RELATED PARTY TRANSACTIONS

On March 8, 2005, TA Cogen entered into an agreement with TEC whereby TEC provided a financial fixed-for-floating price swap to TA Cogen during planned maintenance at Sheerness in the second quarter of 2005.

13. SUBSEQUENT EVENT

On Oct. 14, 2005, holders of $141.1 million of TransAlta's 6.25 per cent Series A debentures exercised their option to renew these debentures, extending their maturity to Dec. 15, 2030 at an interest rate of 6.90 per cent. These debentures had an original maturity of Nov. 15, 2005 and are included in the current portion of long-term debt - recourse at Sept. 30, 2005.

14. COMPARATIVE FIGURES

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

15. UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

These consolidated financial statements have been prepared in accordance with Canadian GAAP, which, in most respects, conform to U.S. GAAP. Significant differences between Canadian and U.S. GAAP are as follows:



A. EARNINGS AND EARNINGS PER SHARE (EPS)

3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
Reconciling
items 2005 2004 2005 2004
---------------------------------------------------------------------
Earnings from
continuing
operations
- Canadian GAAP $ 52.1 $ 35.8 $ 128.6 $ 98.5
Derivatives and
hedging activities,
net of tax I 0.3 (0.4) (1.5) (2.4)
Start-up costs,
net of tax II - (0.1) (0.1) (0.1)
Amortization of
pension transition
adjustment V (1.0) (1.2) (3.0) (3.5)
---------------------------------------------------------------------
Earnings from
continuing
operations
- U.S. GAAP 51.4 34.1 124.0 92.5
Net gain on disposal
of discontinued
operations - Canadian
and U.S. GAAP - - - 9.6
---------------------------------------------------------------------
Net earnings
- U.S. GAAP $ 51.4 $ 34.1 $ 124.0 $102.1
Foreign currency
cumulative
translation
adjustment I,VII 9.1 0.2 8.0 23.8
Net (loss) gain on
derivative instruments I,VII (214.1) 5.9 (274.7) (5.7)
---------------------------------------------------------------------
Comprehensive (loss)
income - U.S. GAAP $(153.6) $ 40.2 $(142.7) $120.2
---------------------------------------------------------------------
---------------------------------------------------------------------

Basic EPS - U.S. GAAP
Earnings from
continuing
operations $ 0.26 $ 0.18 $ 0.63 $ 0.48
Net gain on disposal
of discontinued
operations - - - 0.05
---------------------------------------------------------------------
Net earnings $ 0.26 $ 0.18 $ 0.63 $ 0.53
---------------------------------------------------------------------
---------------------------------------------------------------------

Diluted EPS - U.S. GAAP
Earnings from
continuing
operations $ 0.26 $ 0.18 $ 0.63 $ 0.48
Net gain on disposal
of discontinued
operations - - - 0.05
---------------------------------------------------------------------
Net earnings $ 0.26 $ 0.18 $ 0.63 $ 0.53
---------------------------------------------------------------------
---------------------------------------------------------------------


B. BALANCE SHEET INFORMATION

Sept. 30, 2005 Dec. 31, 2004
---------------------------------------------------------------------
Reconciling Canadian U.S. Canadian U.S.
items GAAP GAAP GAAP GAAP(1)
---------------------------------------------------------------------
Assets
Price risk management
assets, current I 249.1 255.5 61.4 109.2
Accounts receivable VIII 567.3 567.3 447.0 445.5
Income taxes receivable I 62.2 84.3 60.1 75.1
Property, plant
and equipment, net II 5,572.9 5,569.8 5,702.6 5,680.7
Price risk management
assets, long-term I 38.9 205.0 32.5 220.2
Other assets
(including current
portion) I, II 199.2 59.7 502.4 300.5

Liabilities
Accounts payable and
accrued liabilities V 561.0 545.1 462.5 387.6
Income taxes payable II - - 6.1 0.7
Price risk management
liabilities, current I 230.3 483.9 49.9 82.1
Long-term debt I 1,989.7 2,032.5 2,321.1 2,365.0
Deferred credits and
other liabilities
(including current
portion) I, XI, 387.5 387.5 639.3 646.1
Price risk management
liabilities, long-term I 36.7 274.6 28.5 77.1
Future or deferred
income tax liabilities
(including current
portion) I,II,IV,V 754.9 606.3 715.0 705.9
Non-controlling interest I 597.3 596.7 616.4 615.4
Equity
Contributed surplus X, XI - 133.0 - 133.0
Retained earnings I,II,V,XI 872.8 728.9 891.5 752.2
Cumulative translation
adjustment I (59.2) - (52.2) -
Accumulated other
comprehensive income I,V,VII - (359.3) - (92.6)
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Restated, reconciling items X and XI


C. RECONCILING ITEMS

I. Derivatives and hedging activities

Under U.S. GAAP, trading and non-trading activities are accounted for in accordance with Statement 133, which requires that derivative instruments be recorded in the consolidated balance sheets at fair value as either assets or liabilities, and that changes in fair value be recognized currently in earnings, unless specific hedge accounting criteria are met. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized currently in earnings. If the derivative is designated as a cash flow hedge, the changes in the fair value of the derivative are recorded in other comprehensive income (OCI), and the gains and losses related to these derivatives are recognized in earnings in the same period as the settlement of the underlying hedged transaction. Any ineffectiveness relating to these hedges is recognized currently in earnings. The assets and liabilities related to derivative instruments for which hedge accounting criteria are met are reflected as price risk management assets and liabilities in the consolidated balance sheets. Many of the corporation's electricity sales and fuel supply agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment. This exemption is available for the electricity industry as electricity cannot be stored in significant quantities and generators may be required to maintain sufficient capacity to meet customer demands. This exemption is also available for some physically settled commodity contracts if certain criteria are met. Non-derivatives used in trading activities are accounted for using the accrual method under U.S. GAAP.

(i) FAIR VALUE HEDGING STRATEGY

The corporation enters into forward exchange contracts to hedge certain firm commitments denominated in foreign currencies to protect against adverse changes in exchange rates and uses interest rate swaps to manage interest rate exposure. The swaps modify exposure to interest rate risk by converting a portion of the corporation's fixed-rate debt to a floating rate.

There was no ineffectiveness related to these hedges in the three and nine months ended Sept. 30, 2005 and 2004.

(ii) CASH FLOW HEDGING STRATEGY

At Sept. 30, 2005, cash flow hedges of the forecasted sale of power and the forecasted purchase of natural gas for the corporation's plants resulted in the recognition of an after-tax unrealized loss in OCI of $284.2 million. These hedges are accounted for on an accrual basis under Canadian GAAP but have been recorded on the balance sheets at fair value for U.S. GAAP.

In the three and nine months ended Sept. 30, 2005, the corporation's cash flow hedges resulted in an after-tax gain of $0.3 million and an after-tax loss of $1.5 million (2004 - loss of $0.4 million and loss of $2.4 million respectively) related to the ineffective portion of its hedging instruments, and an after-tax gain of $nil for the three and nine months ended Sept. 30, 2005 and 2004 related to the portion not designated as a hedge.

In November 2003, forward starting swaps with a notional amount of US$200.0 million and treasury and spread locks with a notional amount of $100.0 million were settled and debt was issued, resulting in an after-tax loss of $25.3 million. The loss is being reclassified from accumulated other comprehensive income (AOCI) into income as interest expense is recognized on the debt.

Over the next 12 months, the corporation estimates that $234.9 million of after-tax losses that arose from cash flow hedges will be reclassified from AOCI to net earnings. The corporation also estimates that $3.7 million of after-tax losses on cash flow hedging instruments that arose on adoption of Statement 133 will be reclassified from AOCI to earnings. These estimates assume constant gas and power prices, interest rates and exchange rates over time; however, the actual amounts that will be reclassified will vary based on changes in these factors. Therefore, management is unable to predict what the actual reclassification from AOCI to earnings (positive or negative) will be for the next 12 months.

(iii) NET INVESTMENT HEDGES

The company uses cross-currency interest rate swaps, forward foreign currency contracts and direct foreign currency debt to hedge its exposure to changes in the carrying value of its investments in its foreign subsidiaries in the U.S., Australia and Mexico. Realized and unrealized gains and losses from these hedges are included in OCI, with the related amounts due to or from counterparties included in long-term price risk management assets and liabilities and long-term debt.

In the three and nine months ended Sept. 30, 2005, the corporation recognized an after-tax gain of $215.9 million and $277.4 million, respectively, (2004 - $5.0 million loss and $8.4 million gain respectively) on its net investment hedges, included in OCI.

In the three and nine months ended Sept. 30, 2005 and 2004, the corporation did not recognize any ineffectiveness related to net investment hedges.

(iv) TRADING ACTIVITIES

The corporation markets energy derivatives to optimize returns from assets, to earn trading revenues and to gain market information. Derivatives, as defined under Statement 133, are recorded on the consolidated balance sheets at fair value under both Canadian and U.S. GAAP. Non-derivative contracts entered into subsequent to the rescission of EITF 98-10 are accounted for using the accrual method.

II. Start-up Costs

Under U.S. GAAP, certain start-up costs, including revenues and expenses in the pre-operating period, are expensed rather than capitalized to deferred charges and property, plant and equipment under Canadian GAAP, which also results in decreased depreciation and amortization expense under U.S. GAAP.

III. Debt extinguishment

Under U.S. GAAP, the premium on redemption of long-term debt related to the 1998 limited partnership transaction was recorded when incurred, whereas for Canadian GAAP, the loss was being amortized to earnings over the period of the limited partnership (20 years). As the buyback option was terminated in connection with the sale of the Sheerness plant, the deferred amount was recognized in earnings in 2003.

IV. Income taxes

Future income taxes under Canadian GAAP are referred to as deferred income taxes under U.S. GAAP.

Deferred income taxes under U.S. GAAP are as follows:



Sept. 30 Dec. 31
2005 2004
---------------------------------------------------------------------
Future income tax liabilities (net)
under Canadian GAAP $ (588.2) $ (561.5)
Derivatives 160.6 23.2
Start-up costs (2.3) (2.3)
Employee future benefits (9.7) (11.8)
---------------------------------------------------------------------
$ (439.6) $ (552.4)
---------------------------------------------------------------------
---------------------------------------------------------------------

Comprised of the following: Sept. 30 Dec. 31
2005 2004
---------------------------------------------------------------------
Current deferred income tax assets $ 22.7 $ 21.5
Long-term deferred income tax assets 144.0 132.0
Current deferred income tax liabilities (17.0) (11.1)
Long-term deferred income tax liabilities (589.3) (694.8)
---------------------------------------------------------------------
$ (439.6) $ (552.4)
---------------------------------------------------------------------
---------------------------------------------------------------------


V. Employee Future Benefits

U.S. GAAP requires that the cost of employee pension benefits be determined using the accrual method with application from 1989. It was not feasible to apply this standard using this effective date. The transition asset as at Jan. 1, 1998 was determined in accordance with elected practice prescribed by the Securities and Exchange Commission (SEC) and is amortized over 10 years.

As a result of the corporation's plan asset return experience for its U.S. registered pension plan, at Dec. 31, 2004, the corporation was required under U.S. GAAP to recognize an additional minimum liability. The liability was recorded as a reduction in common equity through a charge to OCI, and did not affect net income for 2004. The charge to OCI will be restored through common equity in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

VI. Joint Ventures

In accordance with Canadian GAAP, joint ventures are required to be proportionately consolidated regardless of the legal form of the entity. Under U.S. GAAP, incorporated joint ventures are required to be accounted for by the equity method. However, in accordance with practices prescribed by the SEC, the corporation, as a Foreign Private Issuer, has elected for the purpose of this reconciliation to account for incorporated joint ventures by the proportionate consolidation method.



VII. Other comprehensive income (loss)

The changes in the components of OCI were as follows:

3 months 9 months
ended Sept. 30 ended Sept. 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Net gain on derivative
instruments:
Unrealized gain, net of taxes
of $152.3 million $ (215.9) $ 5.0 $ (277.4) $ (8.4)
Reclassification adjustment
for gains included in net
income, net of taxes
of $1.5 million 1.8 0.9 2.7 2.7
---------------------------------------------------------------------
Net gain on derivative
instruments (214.1) 5.9 (274.7) (5.7)
Translation adjustments 9.1 0.2 8.0 23.8
---------------------------------------------------------------------
Other comprehensive
(loss)income $ (205.0) $ 6.1 $ (266.7) $ 18.1
---------------------------------------------------------------------
---------------------------------------------------------------------

The components of AOCI were:
Sept. 30 Dec. 31
2005 2004
---------------------------------------------------------------------
Net loss on derivative instruments $ (335.5) $ (60.8)
Translation adjustments (22.1) (30.1)
Registered pension alternate minimum liabilities (1.7) $ (1.7)
---------------------------------------------------------------------
Accumulated other comprehensive loss $ (359.3) $ (92.6)
---------------------------------------------------------------------
---------------------------------------------------------------------


VIII. Right of Offset Agreement

The corporation had a New Zealand bank deposit that had been offset with a New Zealand bank facility under a right of offset agreement. The arrangement did not qualify for offsetting under U.S. GAAP. During the second quarter of 2004, the corporation refinanced certain foreign operations and the bank deposit was used to settle the bank facility in full.

IX. Asset Retirement Obligations

FASB issued Statement 143, Asset Retirement Obligations, which requires asset retirement obligations to be measured at fair value and recognized when the obligation is incurred. A corresponding amount is capitalized as part of the asset's carrying amount and depreciated over the asset's useful life. TransAlta adopted the provisions of Statement 143 effective Jan. 1, 2003.

In accordance with Canadian GAAP, the asset retirement obligations standard was adopted retroactively with restatement of prior periods. Under U.S. GAAP, the impact of adopting Statement 143 was recognized as a cumulative effect of a change in accounting principle as of Jan. 1, 2003, the beginning of the fiscal year in which the Statement was first applied. The change resulted in an after-tax increase in net earnings of $52.5 million ($82.7 million pre-tax).

X. Limited Partnership Transaction

In 1998, the Corporation transferred generation assets to its subsidiary TA Cogen. TA Power, an unrelated entity, concurrently subscribed to a minority interest in TA Cogen. The fair value paid by TA Cogen for the assets exceeded their historical carrying values. For Canadian GAAP, the Corporation recognized a portion of this difference, to the extent it was funded by TA Power's investment in TA Cogen, as a gain. As TA Power held an option to resell their interest in TA Cogen to the Corporation in 2018, this gain under Canadian GAAP was initially deferred and amortized over a 30 year period. In 2003, TA Power's option to resell these units was eliminated and the unamortized balance of the gain was recognized in income.

Under U.S. Securities and Exchange Commission Staff Accounting Bulletin No. 51, the option initially held by TA Power to potentially resell TA Cogen units to the Corporation in 2018 causes the excess of the consideration paid by TA Power over the Corporation's historical carrying value in these assets to be characterized as contributed surplus in 1998. This amount of contributed surplus is reduced by the related tax effect. As a result, under U.S GAAP, there is no amortization of the gain into income in the period from 1998 to 2002 and no recognition of the unamortized balance of the gain in 2003.

XI. Restatement

During the third quarter of 2005, the Corporation determined, as described in footnote X above, that the gain recognized under Canadian GAAP arising from 1998 transactions involving TA Cogen and TA Power is a capital transaction under U.S. GAAP. The Corporation has retroactively corrected its reconciliation to U.S. GAAP. The impact of this adjustment on amounts previously reported under U.S. GAAP is as follows:




(In millions of dollars except per
share amounts) 2004 2003 2002
---------------------------------------------------------------------
Decrease in:
Earnings from continuing operations $ - $ 102.7 $ 6.3
Net earnings $ - $ 102.7 $ 6.3
Net earnings per share in accordance
with U.S. GAAP
Continuing operations $ - $ 0.56 $0.04
Discontinued operations $ - $ - $ -
Basic $ - $ 0.56 $0.04
Diluted $ - $ 0.56 $0.04
---------------------------------------------------------------------
---------------------------------------------------------------------


The impact on previously reported balance sheet amounts for U.S.
GAAP purposes is as follows:


2004 2003
---------------------------------------------------------------------
Increase (decrease) in:
Contributed surplus $ 133.0 $ 133.0
Retained earnings $ (133.0) $ (133.0)
---------------------------------------------------------------------
---------------------------------------------------------------------


For U.S. GAAP purposes, the correction had no impact on total
shareholders' equity at Dec. 31, 2004 and Dec. 31, 2003.


SUPPLEMENTAL INFORMATION
Sept 30 Dec 31
(Annualized) 2005 2004
---------------------------------------------------------------------
Restated

Closing market price $ 23.03 $ 18.05
Price range (last 12 months) High $ 23.66 $ 18.79
Low $ 15.80 $ 15.25
Debt/invested capital
(including non recourse debt) 44.5% 46.6%
Debt/invested capital
(excluding non recourse debt) 40.8% 42.5%
Return on common shareholders' equity 8.1% 6.6%
Return on invested capital 8.4% 7.6%
Book value per share $ 12.59 $ 12.63
Cash dividends per share $ 1.00 $ 1.00
Price/earnings ratio (times) 23.5 x 21.7 x
Dividend payout ratio 97.8% 120.0%
Dividend coverage (times) 3.1 x 3.2 x
Dividend yield 4.3% 5.5%
Cash flow to debt 21.5% 19.0%
---------------------------------------------------------------------
---------------------------------------------------------------------


RATIO FORMULAS

Debt/invested capital = (short-term debt + long-term debt - cash and interest-earning investments) / (debt + preferred securities + non-controlling interests + common equity)

Return on common shareholders' equity = net earnings excluding gain on discontinued operations / average of opening and closing common equity

Return on invested capital = (earnings before non-controlling interests and income taxes + net interest expense) / average annual invested capital

Book value per share = common shareholders' equity / common shares outstanding

Price/earnings ratio = current year's close / basic earnings per share from continuing operations

Cash flow to total debt = cash flow from operations before changes in working capital / two-year average of total debt

Dividend payout = dividends / net earnings excluding gain on discontinued operations

Dividend coverage = cash flow from operating activities / common share dividends

Dividend yield = dividend per common share / current period's close price

GLOSSARY OF KEY TERMS

Availability - A measure of time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year, that a generating unit is capable of generating electricity, whether or not it is actually generating electricity.

Btu (British Thermal Unit) - A measure of energy. The amount of energy required to raise the temperature of one pound of water one degree Fahrenheit, when the water is near 39.2 degrees Fahrenheit.

Capacity - The rated continuous load-carrying ability, expressed in megawatts of generation equipment.

Gigawatt - A measure of electric power equal to 1,000 megawatts.

Gigawatt hour (GWh) - A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.

Heat rate - A measure of conversion, expressed as Btu/MW, of the amount of thermal energy required to generate electrical energy.

Megawatt - A measure of electric power equal to 1,000,000 watts.

Megawatt hour (MWh) - A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.

Net maximum capacity - The maximum capacity or effective rating, modified for ambient limitations that a generating unit or power plant can sustain over a specific period, less the capacity used to supply the demand of station service or auxiliary needs.

Spark spread - A measure of gross margin per MW (sales price less cost of fuel).



TransAlta Corporation
Box 1900, Station "M"
110 - 12th Avenue S.W.
Calgary, Alberta Canada T2P 2M1

Phone
403.267.7110

Website
www.transalta.com


CIBC Mellon Trust Company
P.O. Box 7010 Adelaide Street Station
Toronto, Ontario Canada M5C 2W9

Phone
Toll-free in North America: 1.800.387.0825
Toronto or outside North America: 416.643.5500

Fax
416.643.5501

Website
www.cibcmellon.com


Contact Information

  • TransAlta Corporation - Media inquiries
    Sneh Seetal
    Senior Media Relations Advisor
    Phone: (403) 267-7330
    Pager: (403) 213-7041
    Email: sneh_seetal@transalta.com
    or
    TransAlta Corporation - Investor inquiries
    Daniel J. Pigeon
    Director, Investor Relations
    Phone: (403) 267-2520 or 1-800-387-3598 in Canada and U.S.
    (403) 267-2590 (FAX)
    Email: investor_relations@transalta.com
    Website: www.transalta.com