TransAlta Corporation
TSX : TA
NYSE : TAC

TransAlta Corporation

July 21, 2005 09:00 ET

TransAlta delivers strong second quarter results

CALGARY, ALBERTA--(CCNMatthews - July 21, 2005) - TransAlta Corporation (TSX:TA)(NYSE:TAC) -

Second Quarter Highlights:

- Earnings from continuing operations of $0.13 per share compared to $0.08 per share in 2004

- Improved earnings from continuing operations reflect increased revenues, reduced costs on planned maintenance and higher gross margin from Energy Marketing

TransAlta Corporation (TSX:TA;NYSE:TAC) today announced earnings from continuing operations of $24.8 million ($0.13 per share), compared to $15.5 million ($0.08 per share) for the second quarter 2004. Net earnings were also $24.8 million ($0.13 per share) in the quarter as there were no earnings from discontinued operations. A $9.6 million after tax gain ($0.05 per share) from the final settlement on disposal of the Transmission operation resulted in net earnings of $25.1 million ($0.13 per share) for the second quarter 2004.

"We are pleased with our performance in the second quarter," said Steve Snyder, TransAlta president and CEO. "The strong financial results demonstrate our commitment to focus on productivity gains and cost control as well as our ability to capitalize on market opportunities."

Cash generated from operating activities for the quarter was $103.6 million, compared to $85.7 million in the second quarter 2004 resulting mainly from improved operating earnings.

Earnings from continuing operations for the six months ended June 30, 2005 were $0.39 per share versus $0.33 for the year prior. Net earnings were $76.5 million ($0.39 per share), compared to $72.3 million ($0.38 per share) for the same period in 2004.

For the six months ended June 30, 2005, cash from operating activities was $242.1 million, compared to $270.0 million for the same period in 2004. Capital expenditures were $144.9 million during the first six months of 2005, compared to $167.7 million for the first six months of 2004. Net debt was reduced by a further $35.5 million.



TransAlta consolidated financial highlights

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(In millions except per 3 months ended June 30
share amounts) 2005 2004
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Amount Per share Amount Per share
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Revenue $ 621.2 $ 592.9
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Net earnings from continuing
operations $ 24.8 $ 0.13 $ 15.5 $ 0.08
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Gain on disposal of
discontinued operation,
net of tax - - $ 9.6 $ 0.05
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Net earnings $ 24.8 $ 0.13 $ 25.1 $ 0.13
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Comparable earnings(i) $ 24.8 $ 0.13 $ 8.0 $ 0.04
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Cash flow from operating
activities $ 103.6 $ 85.7
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(In millions except per 6 months ended June 30
share amounts) 2005 2004
---------------------------------------
Amount Per share Amount Per share
---------------------------------------------------------------------
Revenue $1,305.5 $1,247.9
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Net earnings from continuing
operations $ 76.5 $ 0.39 $ 62.7 $ 0.33
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Gain on disposal of
discontinued operation,
net of tax - - $ 9.6 $ 0.05
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Net earnings $ 76.5 $ 0.39 $ 72.3 $ 0.38
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Comparable earnings(i) $ 76.5 $ 0.39 $ 57.9 $ 0.30
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Cash flow from operating
activities $ 242.1 $ 270.0
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3 months ended 6 months ended
June 30 June 30
2005 2004 2005 2004
---------------------------------------------------------------------
Availability (%) 84.1 85.2 88.7 90.1
Production (GWh) 12,124 12,088 25,230 25,461
Electricity trading volumes (GWh) 21,376 17,803 41,353 35,989
Gas trading volumes (million GJ) 65.8 107.5 154.8 182.9
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(i) 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 17 of the MD&A.

In the second quarter 2005, TransAlta:

- Announced it would begin negotiations with the Ontario Power Authority for a contract at the Sarnia Regional Cogeneration Plant.

- Renewed its $1.5 billion committed revolving credit facility for a three-year term.

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.

TRANSALTA CORPORATION

Q2 2005

MANAGEMENT'S DISCUSSION AND ANALYSIS

This management's discussion and analysis (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 six months ended June 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 July 20, 2005. Additional information respecting TransAlta, including its annual information form, is available on SEDAR at www.sedar.com.

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.

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.

CERTIFICATION

The corporation's financial reporting procedures and practices have enabled the certification of TransAlta's second quarter report to shareholders in voluntary compliance with the requirements of Section 302 of the Sarbanes-Oxley Act and in compliance with the requirements of Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings".

HIGHLIGHTS AND SUMMARY OF RESULTS

During the second quarter of 2005 the corporation:

- Generated net earnings of $24.8 million compared to $25.1 million in the second quarter of 2004.

- Generated earnings on a comparable basis of $24.8 million compared to $8.0 million in the second quarter of 2004. Earnings on a comparable basis is not defined under GAAP. Refer to the Non-GAAP Measures section on page 17 of this MD&A for a further discussion of earnings on a comparable basis, including a reconciliation to net earnings.

- Generated cash flow from operations of $103.6 million and used these cash flows and existing cash balances to fund capital expenditures of $105.2 million and to pay dividends and distributions to a subsidiary's non-controlling limited partner ($19.8 million).

- Renewed its $1.5 billion committed revolving credit facility for a three-year term.

During the six months ended June 30, 2005 the corporation:

- Generated net earnings of $76.5 million compared to $72.3 million in the first six months of 2004.

- Generated earnings on a comparable basis of $76.5 million compared to $57.9 million in the first six months of 2004. Earnings on a comparable basis is not defined under GAAP. Refer to the Non-GAAP Measures section on page 17 of this MD&A for a further discussion of earnings on a comparable basis, including a reconciliation to net earnings.

- Generated cash flow from operations of $242.1 million and used these cash flows to fund capital expenditures of $144.9 million and to pay dividends and distributions to a subsidiary's non-controlling limited partner ($71.2 million).

- 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.

- Commissioned the Genesee 3 plant on March 1, 2005.

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



3 months ended June 30 2005 2004(1)
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Availability (%) 84.1 85.2
Production (GWh) 12,124 12,088
Electricity trading volumes (GWh) 21,376 17,803
Gas trading volumes (million GJ) 65.8 107.5
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Revenue $ 621.2 $ 592.9
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Gross margin(2)(3) $ 348.7 $ 317.8
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Operating income(2)(3) $ 91.0 $ 72.3
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Gain on disposal of discontinued operations,
net of tax $ - $ 9.6
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Net earnings $ 24.8 $ 25.1
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Basic earnings per common share:
Earnings from continuing operations $ 0.13 $ 0.08
Gain on disposal of discontinued operations,
net of tax $ - $ 0.05
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Net earnings $ 0.13 $ 0.13
Diluted earnings per common share:
Earnings from continuing operations $ 0.13 $ 0.08
Gain on disposal of discontinued operations,
net of tax $ - $ 0.05
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Net earnings $ 0.13 $ 0.13
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Cash flow from operating activities $ 103.6 $ 85.7
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6 months ended June 30 2005 2004(1)
---------------------------------------------------------------------
Availability (%) 88.7 90.1
Production (GWh) 25,230 25,461
Electricity trading volumes (GWh) 41,353 35,989
Gas trading volumes (million GJ) 154.8 182.9
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Revenue $ 1,305.5 $ 1,247.9
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Gross margin(2)(3) $ 702.6 $ 670.3
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Operating income (2)(3) $ 226.7 $ 207.0
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Earnings from continuing operations $ 76.5 $ 62.7
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Gain on disposal of discontinued operations,
net of tax - 9.6
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Net earnings $ 76.5 $ 72.3
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Basic earnings per common share:
Earnings from continuing operations $ 0.39 $ 0.33
Gain on disposal of discontinued operations,
net of tax $ - $ 0.05
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Net earnings $ 0.39 $ 0.38
Diluted earnings per common share:
Earnings from continuing operations $ 0.39 $ 0.32
Gain on disposal of discontinued operations,
net of tax $ - $ 0.05
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Net earnings $ 0.39 $ 0.37
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Cash flow from operating activities $ 242.1 $ 270.0
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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) For reconciliation of gross margin and operating income, see page
three of this MD&A.

(3) Gross margin and operating income are not defined under GAAP.
Refer to the non-GAAP Measures section on page 17 of this MD&A
for a further discussion of operating income, including a
reconciliation to net earnings.


For the three and six months ended June 30, 2005, availability decreased slightly compared to the same periods in 2004 due to planned maintenance at the Poplar Creek and Sarnia plants.

Total electricity volumes of proprietary trading transactions in the three and six months ended June 30, 2005 are higher than the same period in 2004 due to opportunities created from increasing liquidity in some markets.

The decrease in gas volumes for the three and six months ended June 30, 2005 relates to lower second quarter trading activities due to a decrease in physical and financial gas volumes, caused by a temporary decline in heat rate contracts, which involve a gas component, to manage power price risk in electricity trading.

OPERATING INCOME

Operating income for the three and six months ended June 30, 2005 increased by $18.7 million and $19.7 million, respectively, compared to the same periods in 2004. Operating income for the three and six months ended June 30, 2005 is reconciled to operating income for the same periods in 2004, as shown below:



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Operating income for 3 months ended June 30, 2004 $ 72.3
Increased Generation gross margins 10.0
Reduced planned maintenance costs and lost earnings due
to planned outages 16.8
Higher Energy Marketing gross margins 9.2
Increase in operational and administrative costs (13.4)
Increased depreciation (3.1)
2004 gain on sale of TransAlta Power partnership units (1.2)
Other 0.4
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Operating income for 3 months ended June 30, 2005 $ 91.0
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Operating income for 6 months ended June 30, 2004 $ 207.0
Increased Generation gross margins 15.6
Reduced planned maintenance costs and lost earnings due
to planned outages 12.7
Higher Energy Marketing gross margins 8.4
Increase in operational and administrative costs (16.1)
Increased depreciation (3.4)
2004 gain on sale of TransAlta Power partnership units (21.1)
2004 prior period regulatory decision 22.9
Other 0.7
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Operating income for 6 months ended June 30, 2005 $ 226.7
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SIGNIFICANT EVENTS

All gains and losses discussed below are presented as pre-tax (after-tax) amounts.

Three months ended June 30, 2005 and June 30, 2004

Gain on Transmission sale

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.

New Zealand tax settlement

In June 2004, TransAlta received notice from the New Zealand Inland Revenue of a favorable settlement relating to the 1999 taxation year. A NZ$8.0 million (Cdn$6.8 million) income tax recovery was recorded in the second quarter of 2004.

Six months ended June 30, 2005

Commissioning of the Genesee 3 Generating Facility

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

Six months ended June 30, 2004

Sale of the TransAlta Power Units

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 TransAlta Cogeneration, L.P. (TA Cogen). As part of the financing, and concurrent with the sale, TransAlta Power, L.P. (TransAlta 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 TransAlta Power on July 31, 2003 was approximately 26 per cent. Each warrant, when exercised, was exchangeable for one TransAlta Power unit at any time until Aug. 3, 2004. As the warrants were exercised, TransAlta sold TransAlta Power units back to TransAlta Power for $9.30 per unit, reducing its ownership interest in TransAlta Power and increasing cash proceeds. As a result of exercising warrants and the subsequent sale of TransAlta Power units by the corporation, TransAlta's ownership interest in TransAlta Power was reduced to 0.01 per cent held by TransAlta Power Ltd., the general partner of TransAlta Power, as at June 30, 2005.

For the three and six months ended June 30, 2004, TransAlta recognized $1.2 million and $21.1 million, respectively, of dilution gains on the exercise of warrants.

Prior period regulatory decision

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. TransAlta has prepared a petition for relief from the refund obligation that may be filed once FERC provides stakeholders with a direction on the filing of such positions. 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.

NEW ACCOUNTING STANDARDS

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, defined as a variable interest, 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 operation are presented as equity income from 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 flow 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
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Total assets $ 286.6 $ 341.3
Total liabilities $ 189.7 $ 12.4
Ownership interest and maximum exposure to loss $ 92.7 $ 326.3
Capacity (MW) 252 259
Production (GWh) 856 574
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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., Mexico and Australia. At June 30, 2005, Generation had 8,339 MW of gross generating capacity in operation (7,935 MW net ownership interest).

For the three months ended June 30, 2005, availability decreased slightly to 84.1 per cent from 85.2 per cent in the same period in 2004 due to planned maintenance at the Poplar Creek and Sarnia plants.

For the six months ended June 30, 2005, availability decreased slightly to 88.7 per cent from 90.1 per cent in the same period in 2004 due to planned maintenance at the Poplar Creek and Sarnia plants.

The results of the Generation segment are as follows:



2005 2004
3 months ended June 30 Total Per MWh Total Per MWh
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Revenues $ 564.5 $ 46.56 $ 535.7 $ 44.32
Fuel and purchased power (241.4) (19.91) (234.3) (19.38)
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Gross margin 323.1 26.65 301.4 24.94
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Operations, maintenance
and administration 137.6 11.35 130.8 10.82
Depreciation and
amortization 89.1 7.35 85.7 7.09
Taxes, other than
income taxes 5.7 0.47 6.1 0.50
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Operating expenses 232.4 19.17 222.6 18.41
Gain on sale of
TransAlta Power
partnership units - - 1.2 0.10
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Operating income
before corporate
allocations 90.7 7.48 80.0 6.63
Corporate allocations 18.0 1.48 18.4 1.52
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Operating income $ 72.7 $ 6.00 $ 61.6 $ 5.11
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2005 2004
6 months ended June 30 Total Per MWh Total Per MWh
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Revenues $ 1,177.8 $ 46.68 $ 1,138.0 $ 44.70
Fuel and purchased
power (513.0) (20.33) (497.1) (19.52)
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Gross margin 664.8 26.35 640.9 25.18
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Operations,
maintenance and
administration 241.1 9.55 232.4 9.13
Depreciation and
amortization 175.3 6.95 171.7 6.74
Taxes, other than
income taxes 11.4 0.45 12.1 0.48
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Operating expenses 427.8 16.95 416.2 16.35
Gain on sale of
TransAlta Power
partnership units - - 21.1 0.83
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Operating income
before corporate
allocations 237.0 9.40 245.8 9.66
Corporate allocations 36.6 1.45 36.4 1.43
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Operating income $ 200.4 $ 7.95 $ 209.4 $ 8.23
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Generation's revenues are derived from the availability and production of electricity and steam as well as ancillary services such as system support. Gas and coal-fired facilities that have exposure to market fluctuations in energy commodity prices represent 4 per cent and 27 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. These instruments are designated as effective hedge positions of future cash flows or fair values of the output and production of its owned assets. Under Canadian GAAP, settlement accounting is used for transactions that qualify for hedge accounting. Under U.S. GAAP, hedging activities are accounted for in accordance with the Financial Accounting Standards Board (FASB) Statement 133.

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



Fuel &
Production Purchased Gross
3 months ended June 30, 2005 (GWh) Revenue Power Margin
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Alberta PPAs 6,194 $ 161.5 $ 42.5 $ 119.0
Long-term contracts 1,738 150.7 84.3 66.4
Merchant 3,463 178.6 97.8 80.8
CE Gen 729 73.7 16.8 56.9
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TOTAL 12,124 $ 564.5 $ 241.4 $ 323.1
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Fuel &
Purchased Gross
Revenue Power per Margin per
3 months ended June 30, 2005 per MWh MWh MWh
---------------------------------------------------------------------
Alberta PPAs $ 26.07 $ 6.86 $ 19.21
Long-term contracts 86.72 48.51 38.21
Merchant 51.58 28.24 23.34
CE Gen 101.08 23.04 78.04
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TOTAL $ 46.56 $ 19.91 $ 26.65
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Fuel &
Production Purchased Gross
3 months ended June 30, 2004 (GWh) Revenue Power Margin
---------------------------------------------------------------------
Alberta PPAs 6,712 $ 182.3 $ 46.1 $ 136.2
Long-term contracts 1,757 138.3 83.5 54.8
Merchant 2,976 146.4 87.2 59.2
CE Gen 643 68.7 17.5 51.2
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TOTAL 12,088 $ 535.7 $ 234.3 $ 301.4
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Fuel &
Purchased Gross
Revenue Power per Margin per
3 months ended June 30, 2004 per MWh MWh MWh
---------------------------------------------------------------------
Alberta PPAs $ 27.16 $ 6.87 $ 20.29
Long-term contracts 78.72 47.53 31.19
Merchant 49.20 29.30 19.90
CE Gen 106.84 27.22 79.62
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TOTAL $ 44.32 $ 19.38 $ 24.94
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Fuel &
Production Purchased Gross
6 months ended June 30, 2005 (GWh) Revenue Power Margin
---------------------------------------------------------------------
Alberta PPAs 12,639 $ 339.1 $ 93.0 $ 246.1
Long-term contracts 3,573 312.0 176.9 135.1
Merchant 7,664 387.7 210.0 177.7
CE Gen 1,354 139.0 33.1 105.9
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TOTAL 25,230 $1,177.8 $ 513.0 $ 664.8
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Fuel &
Purchased Gross
Revenue Power per Margin per
6 months ended June 30, 2005 per MWh MWh MWh
---------------------------------------------------------------------
Alberta PPAs $ 26.83 $ 7.36 $ 19.47
Long-term contracts 87.31 49.50 37.81
Merchant 50.59 27.40 23.19
CE Gen 102.65 24.44 78.21
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TOTAL $ 46.68 $ 20.33 $ 26.35
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Fuel &
Production Purchased Gross
6 months ended June 30, 2004 (GWh) Revenue Power Margin
---------------------------------------------------------------------
Alberta PPAs 13,376 $ 360.7 $ 94.7 $ 266.0
Long-term contracts 3,609 291.5 174.7 116.8
Merchant 7,235 353.0 195.7 157.3
CE Gen 1,241 132.8 32.0 100.8
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TOTAL 25,461 $1,138.0 $ 497.1 $ 640.9
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Fuel &
Purchased Gross
Revenue Power per Margin per
6 months ended June 30, 2004 per MWh MWh MWh
---------------------------------------------------------------------
Alberta PPAs $ 26.97 $ 7.08 $ 19.89
Long-term contracts 80.78 48.41 32.37
Merchant 48.79 27.05 21.74
CE Gen 107.01 25.79 81.22
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TOTAL $ 44.70 $ 19.52 $ 25.18
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Alberta PPAs

Under the Power Purchase Agreements (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 June 30, 2005 decreased by 518 gigawatt hours (GWh) compared to the same period in 2004 primarily due to increased major maintenance at the Alberta Thermal plants (269 GWh) and higher unplanned outages at the Alberta Thermal plants (191 GWh).

Production for the six months ended June 30, 2005 decreased by 737 GWh compared to the same period in 2004 primarily due to increased major maintenance at the Alberta Thermal plants (362 GWh), higher unplanned outages at the Alberta Thermal plants (139 GWh), and excess production in 2004 (71 GWh).

Revenues for the three months ended June 30, 2005 decreased by $20.8 million compared to the same period in 2004 primarily due to increased major maintenance at the Alberta Thermal plants ($11.5 million) and unplanned outages at the Alberta Thermal plants ($10.8 million). Revenues for the six months ended June 30, 2005 decreased by $21.6 million compared to the same period in 2004 primarily due to increased planned maintenance at the Alberta Thermal plants ($15.7 million) and unplanned outages at the Alberta Thermal plants ($8.3 million).

Revenues per megawatt hour (MWh) for the three and six months ended June 30, 2005 decreased by $1.09 per MWh and $0.14 per MWh, respectively, compared to the same period in 2004, primarily as a result of higher penalties due to increased planned maintenance and unplanned outages.

Total fuel for the three months ended June 30, 2005 was $3.6 million lower than the comparable period in 2004 primarily due to lower production for the reasons outlined above. Fuel decreased by $0.01 per MWh for the three months ended June 30, 2005. Total fuel for the six months ended June 30, 2005 was $1.7 million lower than the comparable period in 2004 due to lower production ($3.3 million) and decreased gas consumption ($1.4 million), partially offset by higher coal costs resulting from increased overburden removal costs ($5.9 million). Fuel increased by $0.28 per MWh for the six months ended June 30, 2005 due to the increase in coal costs outlined above.

Long-term contracts

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

For the three months ended June 30, 2005, revenues increased by $12.4 million ($8.00 per MWh), primarily due to higher revenues earned from the Sarnia plant ($3.9 million) mainly due to higher steam revenue, and revised contracting ($3.2 million). For the six months ended June 30, 2005, revenues increased by $20.5 million ($6.53 per MWh) primarily due to higher revenues earned from the Sarnia plant ($7.8 million) mainly due to higher steam revenue, revised contracting ($4.8 million), and contract escalations at other Ontario plants ($2.1 million). The impact of planned maintenance at the Sarnia plant had no significant impact on margin.

Fuel and purchased power for the three and six months ended June 30, 2005 remained consistent with the same periods in 2004.



Merchant

Average Spot Electricity Prices
($ per MWh)
---------------------------------------------------------------------
Q2 Q2 YTD YTD
2004 2005 2004 2005
---------------------------------------------------------------------
Alberta System Market Price (Cdn$/MWh) $ 60 $ 51 $ 54.48 $ 48.40
Mid-Columbia Price (US$/MWh) $ 39 $ 39 $ 39.73 $ 43.38
Ontario Market Price (CDN$/MWh) $ 47 $ 60 $ 51.46 $ 58.12
---------------------------------------------------------------------


Average Spark Spreads (1)
($ per MWh)
---------------------------------------------------------------------
Q2 Q2 YTD YTD
2004 2005 2004 2005
---------------------------------------------------------------------
Alberta System Market Price
vs. AECO (Cdn$/MWh) $ 11 ($ 1) $ 8 ($ 1)
Mid-Columbia Price vs. Sumas (US$/MWh) $ 3 ($ 2) $ 4 ($ 2)
Ontario Market Price
vs. Dawn (Cdn$/MWh) ($ 14) ($ 2) ($ 6) ($ 1)
---------------------------------------------------------------------

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


Spot electricity prices in Alberta were lower in the second quarter of 2005 compared to the same period in 2004 as year over year supply growth and moderate demand from cool weather more than offset the slight increase in gas prices. Spot electricity prices in the Pacific Northwest were relatively unchanged in the second quarter of 2005 compared to the same period in 2004 as the period saw similar hydro generation levels year over year despite early forecasts for less water. In Ontario, higher gas prices combined with especially warm weather and weak supply accounted for higher second quarter 2005 electricity spot prices compared to the same period in 2004. With the exception of Ontario where those same factors contributed to higher year over year spark spreads, spark spreads decreased in the second quarter of 2005 for all markets relative to the same period in 2004.

In the second quarter of 2005, merchant production was 3,463 GWh, of which 1,188 GWh was contracted under short- to medium-term contracts. In the second quarter of 2004, merchant production was 2,976 GWh, of which 1,091 GWh was contracted. The increase in production was primarily due to the addition of Genesee 3 in 2005 (369 GWh), fewer GWh lost to planned maintenance at the Alberta merchant plants (388 GWh), and increased hydro production due to lower reservoir levels in the second quarter of 2004 (230 GWh), partially offset by the decommissioning of units one and two of the Wabamun plant (189 GWh), and less production from the Poplar Creek plant (210 GWh) due to lower market heat rates and higher planned maintenance.

In the six months ended June 30, 2005, merchant production was 7,664 GWh, of which 3,124 GWh was contracted under short- to medium-term contracts. In the six months ended June 30, 2004, merchant production was 7,235 GWh, of which 2,930 GWh was contracted. The increase in production was primarily due to the addition of Genesee 3 in 2005 (519 GWh), fewer GWh lost to planned maintenance at the Alberta merchant plants (388 GWh), and increased hydro production due to lower reservoir levels in the first six months of 2004 (283 GWh), partially offset by the decommissioning of two units at the Wabamun plant (416 GWh), and less production from the Poplar Creek plant due to lower market heat rates and planned maintenance (207 GWh).

For the three months ended June 30, 2005, merchant revenues increased by $32.2 million while fuel and purchased power increased by $10.6 million resulting in a gross margin increase of $21.6 million compared to the same period in 2004. The gross margin increase is due to the addition of Genesee 3 ($15.1 million), lower planned maintenance at the Alberta merchant plants ($16.2 million), increased hydro margins due to higher reservoir levels in the second quarter ($14.4 million), partially offset by the decommissioning of two units of the Wabamun plant ($6.4 million), lower margins at Poplar Creek ($9.1 million) due to a decline in spark spread and the impact of higher planned maintenance, and lower margins at the Alberta merchant plants due to higher unplanned outages in the quarter ($1.5 million). At Centralia Coal margins are down $4.1 million due primarily to an increase in the cost of coal as a result of higher diesel prices and increased overburden removal costs. On a per MWh basis for the three months ended June 30, 2005, merchant revenues increased by $2.38 per MWh while fuel and purchased power decreased by $1.06 per MWh resulting in a gross margin increase of $3.44 per MWh compared to the same period in 2004 for the reasons noted above.

For the six months ended June 30, 2005, merchant revenues increased by $34.7 million while fuel and purchased power increased by $14.3 million resulting in a gross margin increase of $20.4 million compared to the same period in 2004. The gross margin increase is due to the addition of Genesee 3 ($21.1 million), lower planned maintenance at the Alberta merchant plants ($16.2 million), increased hydro margins due to higher reservoir levels in the second quarter ($18.7 million), partially offset by the decommissioning of two units of the Wabamun plant ($13.3 million), and lower margins at Poplar Creek due to a decline in spark spread ($13.0 million). At Centralia Coal margins have decreased $6.0 million primarily due to an increase in the cost of coal as a result of higher diesel prices and increased overburden removal costs. On a per MWh basis for the six months ended June 30, 2005, merchant revenues increased by $1.80 per MWh while fuel and purchased power increased by $0.35 per MWh resulting in a gross margin increase of $1.45 per MWh compared to the same period in 2004 for the reasons noted above.

CE Gen

TransAlta's share of CE Generation LLC's (CE Gen) production for the three and six months ended June 30, 2005, increased by 86 GWh and 113 GWh, respectively, when compared to the same periods in 2004 primarily due to lower planned maintenance at Imperial Valley in the second quarter of 2005 as compared to the same period in 2004, and due to a slight increase in production at the Saranac plant.

In the three and six months ended June 30, 2005, revenues decreased by $5.76 per MWh and $4.36 per MWh, respectively, compared to the same period in 2004 primarily due to the strengthening of the Canadian dollar compared to the U.S. dollar, partially offset by increased pricing at Imperial Valley in the second quarter. In the three months ended June 30, 2005, fuel and purchased power decreased by $4.18 per MWh, primarily due to the strengthening of the Canadian dollar compared to the U.S. dollar, partially offset by increased fuel pricing and production at the gas plants. For the six months ended June 30, 2005, fuel and purchased power decreased by $1.35 per MWh, primarily due to the strengthening of the Canadian dollar compared to the U.S. dollar, partially offset by increased pricing and production at the gas plants.

Operations, maintenance and administration expense

In the three and six months ended June 30, 2005, operations, maintenance and administration (OM&A) expenses increased by $6.8 million and $8.7 million compared to the same periods in 2004 primarily due to incremental expenses from the addition of Genesee 3 and higher plant operating costs.

Planned maintenance

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




3 months ended June 30 Coal Gas and Hydro Total
---------------------------------------------------------------------
2005 2004 2005 2004 2005 2004
---------------------------------------------------------------------
Capitalized $27.0 $34.9 $23.3 $ 0.7 $50.3 $35.6
Expensed 26.2 31.3 1.5 1.2 27.7 32.5
---------------------------------------------------------------------
$53.2 $66.2 $24.8 $ 1.9 $78.0 $68.1
---------------------------------------------------------------------
---------------------------------------------------------------------

GWh lost 1,095 1,219 347 97 1,442 1,316
---------------------------------------------------------------------
---------------------------------------------------------------------


6 months ended June 30 Coal Gas and Hydro Total
---------------------------------------------------------------------
2005 2004 2005 2004 2005 2004
---------------------------------------------------------------------
Capitalized $ 29.4 $ 39.6 $ 26.8 $ 5.5 $56.2 $ 45.1
Expensed 30.5 33.5 1.6 2.8 32.1 36.3
---------------------------------------------------------------------
$ 59.9 $ 73.1 $ 28.4 $ 8.3 $88.3 $ 81.4
---------------------------------------------------------------------
---------------------------------------------------------------------

GWh lost 1,188 1,219 367 112 1,555 1,331
---------------------------------------------------------------------
---------------------------------------------------------------------


In the three and six months ended June 30, 2005, there were 1,442 GWh and 1,555 GWh of production lost due primarily to planned maintenance compared to 1,316 GWh and 1,331 GWh lost for planned maintenance in the three and six months ended June 30, 2004.

In the three and six months ended June 30, 2005, capitalized maintenance costs increased by $14.7 million and $11.1 million, respectively, compared to the same period in 2004 due to three additional gas plant outages in the second quarter of 2005. Operating maintenance costs in the three and six months ended June 30, 2005 decreased slightly from the same periods in 2004. In the first six months of 2005 there were also $14.2 million (2004 - $6.9 million) of expenditures related to items purchased for use in future periods.

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, 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. 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.

In compliance with FASB Emerging Issues Task Force (EITF) 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement 133, Accounting for Derivative Instruments and Hedging Activities, and Not "Held for Trading Purposes" as defined in EITF 02-3, TransAlta has concluded that energy trading contracts settled in the real-time physical markets meet the definition of derivative contracts held for delivery and therefore results of these contracts are reported on a gross basis (trading revenues and trading purchases are shown separately) in the consolidated statement of earnings.

The results of the Energy Marketing segment are as follows:




3 months ended June 30 6 months ended June 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Revenues $ 56.7 $ 57.2 $ 127.7 $ 109.9
Trading purchases (31.1) (40.8) (89.9) (80.5)
---------------------------------------------------------------------
Gross margin 25.6 16.4 37.8 29.4
---------------------------------------------------------------------
Operations,
maintenance and
administration 4.2 2.8 5.2 3.4
---------------------------------------------------------------------
Depreciation and
amortization 0.4 0.5 0.8 0.9
---------------------------------------------------------------------
Operating expenses 4.6 3.3 6.0 4.3
---------------------------------------------------------------------
Prior period
regulatory decision - - - 22.9
---------------------------------------------------------------------
Operating income
before corporate
allocations 21.0 13.1 31.8 2.2
---------------------------------------------------------------------
Corporate
allocations 2.7 2.4 5.5 4.6
---------------------------------------------------------------------
Operating income
(loss) $ 18.3 $ 10.7 $ 26.3 $ (2.4)
---------------------------------------------------------------------
---------------------------------------------------------------------


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 June 30, 2005, real-time physical power purchases decreased by $9.7 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 June 30, 2005 gross margin increased by $9.2 million compared to the same period in 2004. Gross margin reported in the second quarter of 2005 includes approximately $20.0 million of unrealized earnings due to net positions held across all regions and associated forward market price changes. Potential earnings volatility exists on these forward energy trading contracts until their future settlement dates.

Revenues increased $17.8 million while trading purchases for energy trading contracts settled in the real-time physical markets increased $9.4 million for the six months ended June 30, 2005 relative to the same period in 2004. The increase in trading purchases is primarily due to an increase in gross real-time physical power purchases from 2004 levels.

In the six months ended June 30, 2005 gross margin increased by $8.4 million compared to the same period in 2004 due to strong second quarter results in 2005.

OM&A costs for the three and six months ended June 30, 2005 have increased by $1.4 million and $1.8 million, respectively, relative to the same periods in 2004 due to an increase in staff complement 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 June 30, 2005, and $13.0 million (2004 - $13.0 million) for the six months ended June 30, 2005.



TransAlta's fixed price trading positions were as follows:

Electricity Natural
Units (000s) (MWh) (Gas GJ)
---------------------------------------------------------------------
Fixed price payor, notional amounts,
June 30, 2005 22,935.2 35,204.3
Fixed price payor, notional amounts,
Dec. 31, 2004 14,138.0 35,221.7
---------------------------------------------------------------------

---------------------------------------------------------------------
Fixed price receiver, notional amounts,
June 30, 2005 25,628.6 36,593.2
Fixed price receiver, notional amounts,
Dec. 31, 2004 15,854.2 29,721.2
---------------------------------------------------------------------

---------------------------------------------------------------------
Maximum term in months, June 30, 2005 42 28
Maximum term in months, Dec. 31, 2004 48 34
---------------------------------------------------------------------
---------------------------------------------------------------------


Proprietary trading encompasses a range of contractual terms spanning from short-term speculative trading of one to 24 months to longer-term marketing transactions with potential terms greater than 24 months. Changes in trading positions from Dec. 31, 2004 to June 30, 2005 are due to changing market conditions and corresponding regional strategy positioning.



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

3 months ended June 30 6 months ended June 30
---------------------------------------------------------------------
Electricity (GWh) 2005 2004 2005 2004
---------------------------------------------------------------------
Physical 9,961 13,790 22,014 27,339
Financial 11,415 4,013 19,339 8,650
---------------------------------------------------------------------
21,376 17,803 41,353 35,989
---------------------------------------------------------------------
---------------------------------------------------------------------

3 months ended June 30 6 months ended June 30
---------------------------------------------------------------------
Gas (million GJ) 2005 2004 2005 2004
---------------------------------------------------------------------
Physical 12.3 26.5 42.2 49.7
Financial 53.5 81.0 112.6 133.2
---------------------------------------------------------------------
65.8 107.5 154.8 182.9
---------------------------------------------------------------------
---------------------------------------------------------------------


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

The decrease in gas volumes for the three months and six months ended June 30, 2005 relates to lower second quarter trading activities. In the three months ended June 30, 2005, relative to the same period in 2004, the decrease in physical and financial gas volumes is due to a temporary decline in heat rate contracts, which involve a gas component, to manage power price risk in electricity trading. Gas trading, independent of power trading strategies, continues to be a small part of the risk taken in the marketplace.

The corporation's electrical transmission contracts net trading position of 11.5 million MWh at June 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

TransAlta'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 in accordance with FASB EITF 02-03. 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:




June 30 Dec. 31
Balance Sheet 2005 2004
---------------------------------------------------------------------
Price risk management assets
Current $ 86.5 $ 61.4
Long-term 16.1 32.5
Price risk management liabilities
Current (57.3) (49.9)
Long-term (17.4) (28.5)
---------------------------------------------------------------------
Net price risk management assets outstanding $ 27.9 $ 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 (11.5)
Changes in values attributable to market price
and other market changes (2.4)
New contracts entered into during the current
calandar year 26.3
---------------------------------------------------------------------
Net price risk management assets outstanding
at June 30, 2005 $ 27.9
---------------------------------------------------------------------
---------------------------------------------------------------------


The net price risk management assets and liabilities increased by $12.4 million compared to Dec. 31, 2004 due to settlement of current and prior year contracts, changes in value associated with contracts existing at year-end and the value of new contracts entered into in the current year. Changes in net price risk management assets and liabilities are generally reflected within gross margin of both Energy Marketing and Generation business segments.

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 $ 14.2 $ 3.0 $ 1.0 $ 1.6 $ 0.6 $ 0.3 $ 20.7
Prices based
on models 7.2 - - - - - 7.2
---------------------------------------------------------------------
$ 21.4 $ 3.0 $ 1.0 $ 1.6 $ 0.6 $ 0.3 $ 27.9
---------------------------------------------------------------------
---------------------------------------------------------------------


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 AND NON-CONTROLLING INTERESTS

3 months ended June 30 6 months ended June 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Interest on recourse
and non-recourse debt $ 48.4 $ 51.0 $ 92.9 $ 103.4
Interest on preferred
securities 3.4 9.2 9.7 18.4
Interest income - (0.5) - (0.9)
Capitalized interest - (5.4) (3.4) (9.8)
---------------------------------------------------------------------
Net interest expense $ 51.8 $ 54.3 $ 99.2 $ 111.1
---------------------------------------------------------------------
---------------------------------------------------------------------


Net interest expense in the three and six months ended June 30, 2005 was $2.5 million lower and $11.9 million lower, respectively, than the same periods in 2004 due to decreased debt levels, decreased interest rates, and decreased interest on the preferred securities as a result of the redemption of $300 million of preferred securities in the first quarter of 2005, partially offset by a reduction in capitalized interest.

The earnings attributable to non-controlling interests in the three and six months ended June 30, 2005 increased from $4.3 million to $7.2 million and from $19.0 million to $24.2 million, respectively, compared to the same periods in 2004 as a result of the sale of the Meridian Cogeneration Facility to TA Cogen in the fourth quarter of 2004.



EQUITY INCOME

3 months ended June 30 6 months ended June 30
2005 2004 2005 2004
---------------------------------------------------------------------
Equity income (loss) $ 3.8 $ (0.4) $ 6.0 $ (2.2)
---------------------------------------------------------------------
---------------------------------------------------------------------


For the three months ended June 30, 2005, equity income increased by $4.2 million as compared to the same period in 2004 primarily due to fluctuations in the Mexican Peso as compared to the Canadian dollar.

For the six months ended June 30, 2005, equity income increased by $8.2 million as compared to the same period in 2004 due to fluctuations in the Mexican peso as compared to the Canadian dollar and an increase in gross margin at the Chihuahua plant as a result of higher unplanned outages in the fist quarter of 2004.



INCOME TAXES

3 months ended June 30 6 months ended June 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Income tax expense $ 9.1 $ (3.7) $ 29.8 $ 11.1
Effective tax rate (%) 26.8 (31.4) 28.0 15.0
---------------------------------------------------------------------
---------------------------------------------------------------------


The effective income tax rate in the second quarter of 2005, expressed as a percentage of earnings before income taxes, was higher compared to the same period in 2004. During the second quarter of 2004, TransAlta received a NZ$8.0 million (Cdn$6.8 million) current income tax recovery resulting from a favorable settlement from the New Zealand Inland Revenue relating to the 1999 taxation year. Additionally, during the second quarter of 2005, the effective income tax rate was higher due to higher incremental earnings as compared to the second quarter of 2004.

The effective income tax rate in the first six months of 2005, expressed as a percentage of earnings before income taxes, was higher compared to the same period in 2004. During the first quarter of 2004, a reduction in the corporate tax rate resulted in a $3.8 million reduction in future taxes payable and during the second quarter of 2004, TransAlta received a $6.8 million current income tax recovery as noted above.

FINANCIAL POSITION

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



Increase/
(Decrease) Explanation
---------------------------------------------------------------------
Cash and cash equivalents $ (42.9) Refer to Consolidated Statements
of Cash Flows.

Accounts receivable 69.9 Increased Energy Marketing
trading, offset by decreased
Generation activity due to lower
availability.
Prepaid expenses 23.9 Increase in prepaids due to
timing.

Other assets (including (264.7) Decrease due to scheduled
current portion) maturities of net investment
hedge contracts.

Short-term debt 240.5 Issuances of short term debt.

Accounts payable and 53.1 Increased Energy Marketing
accrued liabilities trading.

Dividends payable 30.6 Dividends declared in second
quarter remain payable.

Recourse long-term debt (291.8) Redemption of preferred
(including current securities.
portion)

Non-recourse long-term (31.7) Repayment of long-term debt.
debt (including current
portion)

Deferred credits and (217.9) Decrease due to scheduled
other long-term maturities of net investment
liabilities (including hedge contracts.
current portion)
---------------------------------------------------------------------


STATEMENTS OF CASH FLOWS:

3 months ended June 30 2005 2004 Explanation
---------------------------------------------------------------------
Cash and cash equivalents,
beginning of period $ 104.5 $ 94.8
Provided by (used in):
Operating activities 103.6 85.7 Due to increased cash
earnings.

In 2004, due to lower
cash earnings.

Investing activities (97.6) (103.8) Capital expenditures of
$105.2 relating primarily
to planned maintenance
and the purchase of
mining equipment, offset
by foreign exchange gains
on net investment hedges
of $8.3 million.

In 2004, capital
expenditures of $79.7
million relating
primarily to the
construction of the
Summerview Wind Farm and
the Genesse 3 project
and foreign exchange
losses on net investment
hedges of $37.9 million.

Financing activities (49.3) 28.3 Net repayment of
short-term debt of $24.7
million, net repayment of
long-term borrowings of
$15.3 million and
non-controlling interest
distributions of $17.2.

In 2004, net issuance of
$77.9 million of
short-term debt offset
by net repayment of
long-term borrowing of
$17.6 million and cash
dividends on common
shares of $33.5 million.

Translation of foreign
currency cash (2.9) 1.3
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 58.3 $ 106.3
---------------------------------------------------------------------
---------------------------------------------------------------------



6 months ended June 30 2005 2004 Explanation
---------------------------------------------------------------------
Cash and cash equivalents,
beginning of period $ 101.2 $ 123.8

Provided by (used in):
Operating activities 242.1 270.0 Due to increased cash
earnings, offset by
higher working capital
requirements.

In 2004, due to lower
cash earnings, offset by
lower working capital
requirements.

Investing activities (137.7) (49.7) Capital expenditures of
$144.9 million including
completion of the
Genesee 3 plant, planned
maintenance, and the
purchase of mining
equipment.

In 2004, capital
expenditures of $167.7
million relating
primarily to the
construction of the
Summerview Wind Farm and
the Genesse 3 project,
and foreign exchange
loss on net investment
hedges of $37.9 million,
partially offset by
proceeds from the
exercise of TransAlta
Power warrants of $59.1
million, and collection
of the $90.8 million Zinc
Recovery long-term
Receivable.

Financing activities (143.6) (237.8) Net issuance of
short-term debt of $231.7
million and common share
issuances of $8.0 million
were used to fund the
redemption of preferred
securities of $300.0
million, repayment of
long-term borrowings of
$21.9 million,
non-controlling interest
distributions of $35.6
million and dividend
payments of $35.6
million.

In 2004, net repayment of
short-term debt of $37.5
million, net repayment of
long-term debt of $126.4
million and cash
dividends on common
shares of $70.0 million.

Translation of foreign (3.7) -
currency cash
---------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 58.3 $ 106.3
---------------------------------------------------------------------
---------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

In the three and six months ended June 30, 2005, TransAlta spent $105.2 million and $144.9 million, respectively, on capital expenditures. In the three and six months ended June 30, 2004, TransAlta spent $79.7 million and $167.7 million, respectively, on capital expenditures.

In the three months ended June 30, 2005, TransAlta had an overall net debt repayment (which includes both short- and long-term debt) of $40.0 million compared to a $60.3 million net issuance in the same period in 2004. In the six months ended June 30, 2005, TransAlta had an overall net issuance in debt of $209.8 million compared to a $163.9 million net repayment in the same period in 2004, excluding preferred securities. The majority of the total decrease in debt for the first six months of 2005 is related to the redemption of $300.0 million of preferred securities which has been financed through short-term debt.

At June 30, 2005, TransAlta's total debt (including non-recourse debt) to invested capital ratio was 46.1 per cent (42.3 per cent excluding non-recourse debt). This represents a slight improvement from the Dec. 31, 2004 ratio of 46.4 per cent. Debt to invested capital is defined on page 34 of this quarterly report.

At June 30, 2005, TransAlta's working capital ratio was 64.1 per cent compared to 77.0 per cent at Dec. 31, 2004. This decrease is attributable to an increase in short-term debt outstanding due to the issuance of short-term debt in February 2005, partially offset by repayments of this debt in March 2005. TransAlta expects to generate sufficient cash flow from operations to meet dividend payments, distributions to non controlling interests and maintenance capital requirements. Any fluctuations in cash flow are expected to be funded through the use of short-term debt.

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 June 30, 2005 was a maximum of $2.2 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 June 30, 2005, under the limited and unlimited guarantees, was $406.4 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.

TransAlta has also provided guarantees of subsidiaries' obligations to perform and make payments under various other contracts. The amount guaranteed under these contracts at June 30, 2005 was a maximum of $675.0 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 June 30, 2005, they are included in accounts payable and accrued liabilities.

The corporation has approximately $1.0 billion of undrawn collateral available to secure these exposures.

On July 20, 2005, the corporation had approximately 197.3 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 the year as a result of less planned maintenance and additional production from Genesee 3.

Power prices

Electricity spot prices for the remainder of 2005 are anticipated to be comparable to or higher than those in the first half of 2005 in all markets with expectations for higher gas prices, weaker hydro generation, and stronger seasonal power demand. Spark spreads are expected to be higher than those seen in the first half of 2005 in Alberta and the Pacific Northwest as power prices are expected to increase more than natural gas prices. Spark spreads may be lower in the second half of the year in Ontario where spark spreads may compress as power prices fail to reflect the full increase in gas prices expected late in the year.

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 91 per cent of output is contracted, a significant portion of which relates to the Alberta PPAs, which are based on achieving specified availability rates.

In December, 2004, the Ontario government passed Bill 100 to reform Ontario's electricity sector. The Bill includes a combination of a regulated and competitive market, targets for energy conservation and the use of renewable energy, providing consumer price stability and the creation of a new Ontario Power Authority (OPA) to ensure an adequate long-term supply of electricity. Negotiations have commenced with the OPA for a contract with the Sarnia Cogeneration plant.

Fuel costs

Mining coal is subject to cost escalations 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. Coal costs per MWh are expected to increase slightly for the remainder of the year.

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 commodity agreements for gas for these merchant plants as gas will be purchased coincident with spot pricing.

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 remainder of 2005 are expected to decrease as compared to the second quarter due to increased production.

Capital and maintenance expenditures

Capital expenditures for 2005 are expected to be approximately $360 million to $375 million of which approximately $140 million will be spent on major maintenance (excluding CE Gen), $100 million will be spent on the Alberta and Centralia mines and approximately $45 million on growth to complete the Genesee 3 projectand to expand capacity in Australia, of which $26.7 million has been spent in the first six 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):



Coal Gas and 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 1,555 GWh were lost in the first six 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 will continue to offset foreign denominated assets with foreign denominated liabilities. TransAlta also has foreign currency expenses, primarily interest charges that offset foreign currency revenues. This strategy is designed to minimize the impact on TransAlta of fluctuations in the Canadian dollar against the U.S. dollar.

Net interest expense

Net interest expense for the remainder of the year is expected to remain consistent with the first half of 2005.

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 ended June 30 6 months ended June 30
---------------------------------------------------------------------
2005 2004(1) 2005 2004(1)
---------------------------------------------------------------------
Gross margin $ 348.7 $ 317.8 $ 702.6 $ 670.3
Operating expenses (257.7) (246.7) (475.9) (461.5)
---------------------------------------------------------------------
91.0 71.1 226.7 208.8
Gain on sale of
TransAlta Power
partnership units - 1.2 - 21.1
Prior period regulatory
decision - - - (22.9)
---------------------------------------------------------------------
Operating income 91.0 72.3 226.7 207.0
Foreign exchange gain
(loss) (1.9) (1.5) (3.0) (0.9)
Net interest expense (51.8) (54.3) (99.2) (111.1)
Other Income 3.8 (0.4) 6.0 (2.2)
---------------------------------------------------------------------
Earnings before
non-controlling
interests and income
taxes 41.1 16.1 130.5 92.8
Non-controlling interests 7.2 4.3 24.2 19.0
---------------------------------------------------------------------
Earnings before income
taxes 33.9 11.8 106.3 73.8
Income tax expense 9.1 (3.7) 29.8 11.1
---------------------------------------------------------------------
Earnings from continuing
operations 24.8 15.5 76.5 62.7
Gain on disposal of
discontinued operations,
net of tax - 9.6 - 9.6
---------------------------------------------------------------------
Net earnings $ 24.8 $ 25.1 $ 76.5 $ 72.3
---------------------------------------------------------------------
---------------------------------------------------------------------

(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: gains on sale of the Sheerness Generating Station, TransAlta 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 ended June 30 6 months ended June 30
---------------------------------------------------------------------
2005 2004(1) 2005 2004(1)
---------------------------------------------------------------------
Earnings on a
comparable basis $ 24.8 $ 8.0 $ 76.5 $ 57.9
Gain on sale of TA
Power units, net
of tax - 0.7 - 12.9
Prior period
regulatory decision,
net of tax - - - (14.9)
Gain from discontinued
operations, net of tax - 9.6 - 9.6
New Zealand tax settlement - 6.8 - 6.8
---------------------------------------------------------------------
Net earnings $ 24.8 $ 25.1 $ 76.5 $ 72.3
---------------------------------------------------------------------
---------------------------------------------------------------------

Weighted average
common shares
outstanding in the
period 195.3 192.2 195.7 191.8
---------------------------------------------------------------------
---------------------------------------------------------------------

Earnings on a
comparable basis per
share $ 0.13 $ 0.04 $ 0.39 $ 0.30
---------------------------------------------------------------------
---------------------------------------------------------------------

(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)
Q3 2004 Q4 2004 Q1 2005 Q2 2005
---------------------------------------------------------------------

Revenue $ 678.1 $ 660.2 $ 684.3 $ 621.2
Earnings from continuing
operations 35.8 62.1 51.7 24.8
Net earnings 35.8 62.1 51.7 24.8
Basic earnings per common share:
Continuing operations 0.18 0.32 0.27 0.13
Net earnings 0.18 0.32 0.27 0.13
Diluted earnings per common
share:
Continuing operations 0.18 0.32 0.26 0.13
Net earnings 0.18 0.32 0.26 0.13
---------------------------------------------------------------------
---------------------------------------------------------------------

Q3 2003 Q4 2003 Q1 2004 Q2 2004
---------------------------------------------------------------------

Revenue $ 615.3 $ 609.1 $ 655.0 $ 592.9
Earnings from continuing
operations 118.4 43.8 47.2 15.5
Net earnings 118.4 43.8 47.2 25.1
Basic earnings per common share:
Continuing operations 0.62 0.23 0.25 0.08
Net earnings 0.62 0.23 0.25 0.13
Diluted earnings per common
share:
Continuing operations 0.62 0.23 0.24 0.08
Net earnings 0.62 0.23 0.24 0.13
---------------------------------------------------------------------
---------------------------------------------------------------------

(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 impacted 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 six months of 2004 and 2005 as described previously within this MD&A.



TRANSALTA CORPORATION
CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS

(IN MILLIONS OF CANADIAN DOLLARS EXCEPT PER SHARE AMOUNTS)

3 months ended 6 months ended
June 30 June 30
Unaudited 2005 2004 2005 2004
---------------------------------------------------------------------
(Restated, Note 1) (Restated, Note 1)

Revenues $ 621.2 $ 592.9 $ 1,305.5 $ 1,247.9
Trading purchases (31.1) (40.8) (89.9) (80.5)
Fuel and purchased power (241.4) (234.3) (513.0) (497.1)
---------------------------------------------------------------------
Gross margin 348.7 317.8 702.6 670.3
--------------------------------------------------------------------
Operations, maintenance
and administration 159.4 151.1 282.2 270.5
Depreciation and
amortization (Note 11) 92.6 89.5 182.3 178.9
Taxes, other than income
taxes 5.7 6.1 11.4 12.1
---------------------------------------------------------------------
Operating expenses 257.7 246.7 475.9 461.5
--------------------------------------------------------------------
Gain on sale of TransAlta
Power partnership units
(Note 2) - (1.2) - (21.1)
Prior period regulatory
decision (Note 4) - - - 22.9
---------------------------------------------------------------------
- (1.2) - 1.8
---------------------------------------------------------------------
Operating income 91.0 72.3 226.7 207.0
Foreign exchange gain (loss) (1.9) (1.5) (3.0) (0.9)
Net interest expense
(Note 5) (51.8) (54.3) (99.2) (111.1)
Equity income (loss)
(Note 1) 3.8 (0.4) 6.0 (2.2)
---------------------------------------------------------------------
Earnings before
non-controlling interests
and income taxes 41.1 16.1 130.5 92.8
Non-controlling interests 7.2 4.3 24.2 19.0
---------------------------------------------------------------------
Earnings before income taxes 33.9 11.8 106.3 73.8
Income tax expense 9.1 (3.7) 29.8 11.1
---------------------------------------------------------------------
Earnings from continuing
operations 24.8 15.5 76.5 62.7
Gain on disposal of
discontinued operations,
net of tax (Note 2) - 9.6 - 9.6
---------------------------------------------------------------------
Net earnings $ 24.8 $ 25.1 $ 76.5 $ 72.3
Common share dividends (49.1) (48.0) (97.9) (95.9)
Adjustment arising from
normal course issuer bid
(Note 8) - (1.1) - (1.1)
Retained earnings
Opening balance 913.2 933.2 910.3 933.9
---------------------------------------------------------------------
---------------------------------------------------------------------
Closing balance $ 888.9 $ 909.2 $ 888.9 $ 909.2
---------------------------------------------------------------------
---------------------------------------------------------------------

Weighted average common
shares outstanding in
the period 195.3 192.2 195.7 191.8
--------------------------------------------------------------------
--------------------------------------------------------------------
Basic earnings per share
Earnings from continuing
operations $ 0.13 $ 0.08 $ 0.39 $ 0.33
Earnings from discontinued
operations - 0.05 - 0.05
---------------------------------------------------------------------
Net earnings $ 0.13 $ 0.13 $ 0.39 $ 0.38
---------------------------------------------------------------------
---------------------------------------------------------------------

Diluted earnings per share
Earnings from continuing
operations $ 0.13 $ 0.08 $ 0.39 $ 0.32
Earnings from discontinued
operations - 0.05 - 0.05
---------------------------------------------------------------------
Net earnings $ 0.13 $ 0.13 $ 0.39 $ 0.37
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes.


TRANSALTA CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

(IN MILLIONS OF CANADIAN DOLLARS)

3 months ended 6 months ended
June 30 June 30
--------------------------------------------------------------------
Unaudited 2005 2004 2005 2004
---------------------------------------------------------------------
(Restated, Note 1) (Restated, Note 1)
Operating activities
Net earnings $ 24.8 $ 25.1 $ 76.5 $ 72.3
Depreciation and
amortization (Note 11) 102.5 100.1 198.8 196.1
Non-controlling interests 7.1 4.3 24.2 19.0
Asset retirement obligation
accretion (Note 6) 5.5 5.3 10.3 10.3
Future income taxes (7.3) (7.4) (0.5) (11.1)
Unrealized loss (gain)
from Energy Marketing
activities (4.1) (6.8) (12.4) (9.4)
Asset retirement
obligation costs settled (4.5) (5.1) (5.4) (6.6)
Foreign exchange loss (gain) 1.9 1.5 3.0 0.9
Gain on sale of assets - (12.1) - (12.1)
Equity loss (Note 1) (3.8) 0.4 (6.0) 2.2
Other non-cash items (2.8) (2.8) (2.3) (3.9)
Prior period regulatory
decision (Note 4) - - - 22.9
Gain on sale of TransAlta
Power partnership units
(Note 2) - (1.2) - (21.1)
---------------------------------------------------------------------
119.3 101.3 286.2 259.5
Change in non-cash
operating working capital
balances (a) (15.7) (15.6) (44.1) 10.5
---------------------------------------------------------------------
Cash flow from operating
activities 103.6 85.7 242.1 270.0
---------------------------------------------------------------------
Investing activities
Long-term receivables - - - 90.8
Additions to property,
plant and equipment (105.2) (79.7) (144.9) (167.7)
Proceeds on sale of
property, plant and
equipment - 12.0 - 12.0
Proceeds on sale of
TransAlta Power
partnership units (Note 2) - 3.7 - 59.1
Restricted cash - (1.8) 4.6 (1.1)
Realized foreign exchange gain
(loss) on net investments 8.3 (37.9) 3.3 (37.9)
Deferred charges and other (0.7) (0.1) (0.7) (4.9)
---------------------------------------------------------------------
Cash flow from (used in)
investing activities (97.6) (103.8) (137.7) (49.7)
---------------------------------------------------------------------
Financing activities
Increase (repayment) of
short-term debt (24.7) 77.9 231.7 (37.5)
Repayment of long-term debt (15.3) (17.6) (21.9) (129.1)
Dividends on common shares (2.6) (33.5) (35.6) (70.0)
Issuance of long-term debt - - - 2.7
Redemption of common shares - (1.5) - (1.5)
Redemption of preferred
securities - - (300.0) -
Net proceeds on issuance of
common shares (Note 8) 4.6 - 8.0 -
Distributions to subsidiary's
non-controlling interests (17.2) 3.3 (35.6) (1.6)
Reduction in advance to
TransAlta Power (Note 2) (3.9) - - -
Deferred financing charges
and other 9.8 (0.3) 9.8 (0.8)
---------------------------------------------------------------------
Cash flow used in financing
activities (49.3) 28.3 (143.6) (237.8)
---------------------------------------------------------------------
Cash flow from (used in)
operating, investing and
financing activities (43.3) 10.2 (39.2) (17.5)
Effect of translation on
foreign currency cash (2.9) 1.3 (3.7) -
---------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents (46.2) 11.5 (42.9) (17.5)
Cash and cash equivalents,
beginning of period 104.5 94.8 101.2 123.8
---------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 58.3 $ 106.3 $ 58.3 $ 106.3
---------------------------------------------------------------------
---------------------------------------------------------------------

Cash taxes paid $ 6.5 $ 6.1 $ 18.5 $ 16.4
Cash interest paid $ 52.8 $ 65.4 $ 97.3 $ 116.5
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes.
(a) Includes an increase in dividends payable for the three and six
months ended June 30, 2005 of $30.6 million (2004-nil).


TRANSALTA CORPORATION
CONSOLIDATED BALANCE SHEETS

(IN MILLIONS OF CANADIAN DOLLARS)

June 30 Dec. 31
Unaudited 2005 2004(a)
---------------------------------------------------------------------

ASSETS (Restated, Note 1)
Current assets
Cash and cash equivalents $ 58.3 $ 101.2
Accounts receivable 516.9 447.0
Prepaid expenses 76.2 52.3
Price risk management assets (Note 3) 86.5 61.4
Future income tax assets 20.7 21.5
Income taxes receivable 62.2 60.1
Inventory 50.6 39.9
Current portion of other assets 64.3 296.4
---------------------------------------------------------------------
935.7 1,079.8
---------------------------------------------------------------------
Restricted cash 4.3 8.9
Investments (Note 1) 422.0 402.5
Property, plant and equipment
Cost 8,443.5 8,314.2
Accumulated depreciation (2,732.6) (2,592.8)
---------------------------------------------------------------------
5,710.9 5,721.4
Goodwill 142.6 142.2
Intangible assets 380.6 392.3
Future income tax assets 153.1 132.0
Price risk management assets (Note 3) 16.1 32.5
Other assets 173.4 206.0
---------------------------------------------------------------------
Total assets $ 7,938.7 $ 8,117.6
---------------------------------------------------------------------
---------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt $ 274.9 $ 34.4
Accounts payable and accrued liabilities 515.6 462.5
Price risk management liabilities (Note 3) 57.3 49.9
Income taxes payable 17.9 6.1
Future income tax liabilities 15.8 11.1
Dividends payable 49.9 19.3
Deferred credits and other current
liabilities 5.7 239.0
Current portion of long-term debt
- recourse 487.6 530.5
Current portion of long-term debt
- non-recourse 36.1 49.6
---------------------------------------------------------------------
1,460.8 1,402.4
---------------------------------------------------------------------
Long-term debt - recourse 1,690.9 1,939.8
Long-term debt - non-recourse 363.1 381.3
Preferred securities (Note 5) 175.0 175.0
Deferred credits and other long-term
liabilities (Note 6) 415.7 400.3
Future income tax liabilities 730.1 703.9
Price risk management liabilities (Note 3) 17.4 28.5
Non-controlling interests 608.3 616.4
Common shareholders' equity
Common shares (Note 8) 1,652.4 1,611.9
Retained earnings 888.9 910.3
Cumulative translation adjustment (63.9) (52.2)
---------------------------------------------------------------------
2,477.4 2,470.0
---------------------------------------------------------------------
Total liabilities and shareholders' equity $ 7,938.7 $ 8,117.6
---------------------------------------------------------------------
---------------------------------------------------------------------

Contingencies (Notes 4 and 9)
Commitments (Notes 10 and 12)

See accompanying notes.
(a) 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.

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, defined as a variable interest, 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 from 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 $ 286.6 $ 341.3
Total liabilities $ 189.7 $ 12.4
Ownership interest and maximum exposure to loss $ 92.7 $ 326.3
Capacity (MW) 252 259
Production (GWh) 856 574
---------------------------------------------------------------------
---------------------------------------------------------------------


2. DISPOSALS

On Dec. 1, 2004, TransAlta completed the sale of its 50 per cent interest in the 220-megawatt 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. (TransAlta 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 TransAlta Power and by the issuance of a note payable to TEC for $30.0 million. The advance outstanding at June 30, 2005 was $1.6 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, TransAlta 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 TransAlta Power on July 31, 2003 was approximately 26 per cent. Each warrant, when exercised, was exchangeable for one TransAlta Power unit at any time until Aug. 3, 2004. As the warrants were exercised, TransAlta sold TransAlta Power units back to TransAlta Power for $9.30 per unit, reducing its ownership interest in TransAlta Power and increasing cash proceeds. As a result of exercising warrants and the subsequent sale of TransAlta Power units by the corporation, TransAlta's ownership interest in TransAlta Power was reduced to 0.01% held by TransAlta Power Ltd., the general partner of TransAlta Power, as at June 30, 2005.

For the three and six months ended June 30, 2004, TransAlta recognized $1.2 million and $21.1 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 three months ended June 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 (11.5)
Changes in values attributable to market price
and other market changes (2.4)
New contracts entered into during the current
calendar year 26.3
---------------------------------------------------------------------
Net price risk management assets outstanding
at June 30, 2005 $ 27.9
---------------------------------------------------------------------
---------------------------------------------------------------------


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 $ 14.2 $ 3.0 $ 1.0 $ 1.6 $ 0.6 $ 0.3 $ 20.7
Prices based
on models 7.2 - - - - - 7.2
$ 21.4 $ 3.0 $ 1.0 $ 1.6 $ 0.6 $ 0.3 $ 27.9
---------------------------------------------------------------------
---------------------------------------------------------------------


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


June 30, Dec. 31,
Balance Sheet 2005 2004
---------------------------------------------------------------------
Price risk management assets
Current $ 86.5 $ 61.4
Long-term 16.1 32.5
Price risk management liabilities
Current (57.3) (49.9)
Long-term (17.4) (28.5)
---------------------------------------------------------------------
Net price risk management assets outstanding $ 27.9 $ 15.5
---------------------------------------------------------------------
---------------------------------------------------------------------


In accordance with EITF 02-03, physical transmission is accounted for under accrual accounting. As of June 30, 2005, TransAlta had recorded $2.5 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 June 30, 2005 were as follows:



Electricity Natural
Units (000s) (MWh) (Gas GJ)
---------------------------------------------------------------------
Fixed price payor, notional amounts,
June 30, 2005 22,935.2 35,204.3
Fixed price payor, notional amounts,
Dec. 31, 2004 14,138.0 35,221.7


Fixed price receiver, notional amounts,
June 30, 2005 25,628.6 36,593.2
Fixed price receiver, notional amounts,
Dec. 31, 2004 15,854.2 29,721.2


Maximum term in months, June 30, 2005 42 28
Maximum term in months, Dec. 31, 2004 48 34
---------------------------------------------------------------------
---------------------------------------------------------------------


The corporation's electrical transmission contracts trading position was 11.5 million megawatt hours (MWh) at June 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. TransAlta has prepared a petition for relief from the refund obligation that may be filed once FERC provides stakeholders with a direction on the filing of such positions. 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

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



3 months ended June 30 6 months ended June 30
2005 2004 2005 2004
---------------------------------------------------------------------
Interest on recourse
and non-recourse debt $ 48.4 $ 51.0 $ 92.9 $ 103.4
Interest on preferred
securities 3.4 9.2 9.7 18.4
Interest income - (0.5) - (0.9)
Capitalized interest - (5.4) (3.4) (9.8)
---------------------------------------------------------------------
Net interest expense $ 51.8 $ 54.3 $ 99.2 $ 111.1
---------------------------------------------------------------------
---------------------------------------------------------------------


6. ASSET RETIREMENT OBLIGATIONS

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



---------------------------------------------------------------------
Balance, Dec. 31, 2004 $ 243.4
Liabilities incurred in period 6.2
Liabilities settled in period (5.4)
Accretion expense 10.3
Revisions in estimated cash flows 3.7
Change in foreign exchange rates 0.7
---------------------------------------------------------------------
Balance, June 30, 2005 $ 258.9
---------------------------------------------------------------------
---------------------------------------------------------------------


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
June 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
obligation (asset) (2.3) 0.1 0.1 (2.1)
---------------------------------------------------------------------
Defined benefit
expense (income) (1.5) 1.0 0.8 0.3
Defined contribution
option expense
of registered
pension plan 2.6 - - 2.6
---------------------------------------------------------------------
Net expense $ 1.1 $ 1.0 $ 0.8 $ 2.9
---------------------------------------------------------------------
---------------------------------------------------------------------

3 months ended
June 30, 2004 Registered Supplemental Other Total
---------------------------------------------------------------------
Current service cost $ 1.0 $ 0.3 $ 0.1 $ 1.4
Interest cost 5.2 0.6 0.2 6.0
Expected return on
plan assets (6.0) - - (6.0)
Experience loss 0.6 0.2 0.1 0.9
Amortization of
net transition
obligation (asset) (2.3) 0.1 - (2.2)
---------------------------------------------------------------------
Defined benefit
expense (income) (1.5) 1.2 0.4 0.1
Defined contribution
option expense
of registered
pension plan 2.5 - - 2.5
---------------------------------------------------------------------
Net expense $ 1.0 $ 1.2 $ 0.4 $ 2.6
---------------------------------------------------------------------
---------------------------------------------------------------------


6 months ended
June 30, 2005 Registered Supplemental Other Total
---------------------------------------------------------------------
Current service cost $ 2.2 $ 0.6 $ 0.6 $ 3.4
Interest cost 10.2 1.0 0.6 11.8
Expected return on
plan assets (12.0) - - (12.0)
Experience loss 1.2 0.2 0.2 1.6
Amortization of
net transition
obligation (asset) (4.6) 0.2 0.2 (4.2)
---------------------------------------------------------------------
Defined benefit
expense (income) (3.0) 2.0 1.6 0.6
Defined contribution
option expense
of registered
pension plan 6.4 - - 6.4
---------------------------------------------------------------------
Net expense $ 3.4 $ 2.0 $ 1.6 $ 7.0
---------------------------------------------------------------------
---------------------------------------------------------------------

6 months ended
June 30, 2004 Registered Supplemental Other Total
---------------------------------------------------------------------
Current service cost $ 2.1 $ 0.6 $ 0.3 $ 3.0
Interest cost 10.3 1.1 0.5 11.9
Expected return
on plan assets (11.9) - - (11.9)
Experience loss 1.1 0.3 0.2 1.6
Amortization of
net transition
obligation (asset) (4.6) 0.2 - (4.4)
---------------------------------------------------------------------
Defined benefit
expense (income) (3.0) 2.2 1.0 0.2
Defined contribution
option expense
of registered
pension plan 5.6 - - 5.6
---------------------------------------------------------------------
Net expense $ 2.6 $ 2.2 $ 1.0 $ 5.8
---------------------------------------------------------------------
---------------------------------------------------------------------


8. COMMON SHARES AND OUTSTANDING

A. Issued and Outstanding

TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value. At June 30, 2005, the corporation had 196.4 million (Dec. 31, 2004 - 194.1 million) common shares issued and outstanding. During the three and six months ended June 30, 2005, 1.1 million (2004 - 0.6 million) and 2.3 million (2004 - 1.3 million) shares respectively were issued, net of repurchases, for net proceeds of $20.5 million (2004 - $9.9 million) and $39.7 million (2004 - $23.5 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 six months ended June 30, 2005, 1.0 million (2004-0.7 million) and 1.9 million (2004-1.4 million) shares, respectively, were issued for gross proceeds of $16.6 million (2004-$12.0 million) and $32.7 million (2004-$24.0 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 six 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 June 30, 2005, the corporation had 3.7 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 ended June 30 6 months ended June 30
2005 2004 2005 2004
---------------------------------------------------------------------
Reported net earnings $ 24.8 $ 25.1 $ 76.5 $ 72.3
Compensation expense 0.3 0.5 0.7 0.9
---------------------------------------------------------------------
Pro forma net earnings $ 24.5 $ 24.6 $ 75.8 $ 71.4
---------------------------------------------------------------------
---------------------------------------------------------------------

Reported basic
earnings per share $ 0.13 $ 0.13 $ 0.39 $ 0.38
Compensation expense
per share - - - -
---------------------------------------------------------------------
Pro forma basic
earnings per share $ 0.13 $ 0.13 $ 0.39 $ 0.38
---------------------------------------------------------------------
---------------------------------------------------------------------

Reported diluted
earnings per share $ 0.13 $ 0.13 $ 0.39 $ 0.37
Compensation expense
per share - - - -
---------------------------------------------------------------------
Pro forma diluted
earnings per share $ 0.13 $ 0.13 $ 0.39 $ 0.37
---------------------------------------------------------------------
---------------------------------------------------------------------


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 corporations 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 June 30, 2005 was a maximum of $2.2 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 June 30, 2005, under the limited and unlimited guarantees, was $406.4 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 June 30, 2005 was a maximum of $675.0 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 June 30, 2005, they are included in accounts payable and accrued liabilities.

The corporation has approximately $1.0 billion 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
June 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Revenues $ 564.5 $ 56.7 $ - $ 621.2
Trading purchases - (31.1) - (31.1)
Fuel and purchased power (241.4) - - (241.4)
---------------------------------------------------------------------
Gross margin 323.1 25.6 - 348.7
---------------------------------------------------------------------
Operations, maintenance
and administration 137.6 4.2 17.6 159.4
Depreciation and
amortization 89.1 0.4 3.1 92.6
Taxes, other than
income taxes 5.7 - - 5.7
---------------------------------------------------------------------
Operating expenses 232.4 4.6 20.7 257.7
---------------------------------------------------------------------
Operating income (loss)
before corporate
allocations 90.7 21.0 (20.7) 91.0
Corporate allocations 18.0 2.7 (20.7) -
---------------------------------------------------------------------
Operating income $ 72.7 $ 18.3 $ - 91.0
---------------------------------------------------------------------
Foreign exchange loss (1.9)
Net interest expense (51.8)
Equity income 3.8
---------------------------------------------------------------------
Earnings from operations
before income taxes and
non-controlling interests $ 41.1
---------------------------------------------------------------------
---------------------------------------------------------------------


3 months ended Energy
June 30, 2004 Generation Marketing Corporate Total
---------------------------------------------------------------------
Revenues $ 535.7 $ 57.2 $ - $ 592.9
Trading purchases - (40.8) - (40.8)
Fuel and purchased power (234.3) - - (234.3)
---------------------------------------------------------------------
Gross margin 301.4 16.4 - 317.8
---------------------------------------------------------------------
Operations, maintenance
and administration 130.8 2.8 17.5 151.1
Depreciation and
amortization 85.7 0.5 3.3 89.5
Taxes, other than
income taxes 6.1 - - 6.1
---------------------------------------------------------------------
Operating expenses 222.6 3.3 20.8 246.7
---------------------------------------------------------------------
Gain on sale of
TransAlta Power
partnership units 1.2 - - 1.2
---------------------------------------------------------------------
Operating income (loss)
before corporate
allocations 80.0 13.1 (20.8) 72.3
Corporate allocations 18.4 2.4 (20.8) -
---------------------------------------------------------------------
Operating income $ 61.6 $ 10.7 $ - 72.3
---------------------------------------------------------------------
Foreign exchange loss (1.5)
Net interest expense (54.3)
Equity loss (0.4)
---------------------------------------------------------------------
Earnings from operations
before income taxes and
non-controlling interests $ 16.1
---------------------------------------------------------------------
---------------------------------------------------------------------

6 months ended Energy
June 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Revenues $ 1,177.8 $ 127.7 $ - $1,305.5
Trading purchases - (89.9) - (89.9)
Fuel and purchased power (513.0) - - (513.0)
---------------------------------------------------------------------
Gross margin 664.8 37.8 - 702.6
---------------------------------------------------------------------
Operations, maintenance
and administration 241.1 5.2 35.9 282.2
Depreciation and
amortization 175.3 0.8 6.2 182.3
Taxes, other than
income taxes 11.4 - - 11.4
---------------------------------------------------------------------
Operating expenses 427.8 6.0 42.1 475.9
---------------------------------------------------------------------
Operating income (loss)
before corporate
allocations 237.0 31.8 (42.1) 226.7
Corporate allocations 36.6 5.5 (42.1) -
---------------------------------------------------------------------
Operating income $ 200.4 $ 26.3 $ - 226.7
---------------------------------------------------------------------
Foreign exchange loss (3.0)
Net interest expense (99.2)
Equity income 6.0
---------------------------------------------------------------------
Earnings from
continuing operations
before income taxes and
non-controlling interests $ 130.5
---------------------------------------------------------------------
---------------------------------------------------------------------


6 months ended Energy
June 30, 2004 Generation Marketing Corporate Total
---------------------------------------------------------------------
Revenues $ 1,138.0 $ 109.9 $ - $ 1,247.9
Trading purchases - (80.5) - (80.5)
Fuel and purchased power (497.1) - - (497.1)
---------------------------------------------------------------------
Gross margin 640.9 29.4 - 670.3
---------------------------------------------------------------------
Operations, maintenance
and administration 232.4 3.4 34.7 270.5
Depreciation and
amortization 171.7 0.9 6.3 178.9
Taxes, other than
income taxes 12.1 - - 12.1
---------------------------------------------------------------------
Operating expenses 416.2 4.3 41.0 461.5
---------------------------------------------------------------------
Prior period regulatory
decision - (22.9) - (22.9)
Gain on sale of TransAlta
Power partnership units 21.1 - - 21.1
---------------------------------------------------------------------
Operating income (loss)
before corporate
allocations 245.8 2.2 (41.0) 207.0
Corporate allocations 36.4 4.6 (41.0) -
---------------------------------------------------------------------
Operating income (loss) $ 209.4 $ (2.4) $ - 207.0
---------------------------------------------------------------------
Foreign exchange loss (0.9)
Net interest expense (111.1)
Equity loss (2.2)
---------------------------------------------------------------------
Earnings from
continuing operations
before income taxes and
non-controlling interests $ 92.8
---------------------------------------------------------------------
---------------------------------------------------------------------


II. Selected balance sheet information

Energy
June 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Goodwill $ 113.1 $ 29.5 $ - $ 142.6
Total segment assets $ 6,960.8 $ 348.1 $ 629.8 $7,938.7
---------------------------------------------------------------------
---------------------------------------------------------------------

Dec. 31, 2004
---------------------------------------------------------------------
Goodwill $ 112.7 $ 29.5 $ - $ 142.2
Total segment assets $ 6,999.5 $ 278.6 $ 839.5 $8,117.6
---------------------------------------------------------------------
---------------------------------------------------------------------


III. Selected cash flow information

3 months ended Energy
June 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Capital expenditures $ 102.4 $ - $ 2.8 $ 105.2
---------------------------------------------------------------------
---------------------------------------------------------------------

3 months ended
June 30, 2004
---------------------------------------------------------------------
Capital expenditures $ 76.7 $ 0.2 $ 2.8 $ 79.7
---------------------------------------------------------------------
---------------------------------------------------------------------

6 months ended Energy
June 30, 2005 Generation Marketing Corporate Total
---------------------------------------------------------------------
Capital expenditures $ 141.1 $ - $ 3.8 $ 144.9
---------------------------------------------------------------------
---------------------------------------------------------------------


6 months ended
June 30, 2004
---------------------------------------------------------------------
Capital expenditures $ 162.8 $ 0.4 $ 4.5 $ 167.7
---------------------------------------------------------------------
---------------------------------------------------------------------



Depreciation and amortization expense per statement of cash flows

3 months ended June 30 6 months ended June 30
2005 2004 2005 2004
---------------------------------------------------------------------
Depreciation and
amortization expense
for reportable
segments $ 92.6 $ 89.5 $ 182.3 $ 178.9
Mining equipment
depreciation,
included in fuel
and purchased power 13.4 12.3 25.4 23.9
Accretion expense,
included in
depreciation and
amortization expense (5.5) (5.3) (10.3) (10.3)
Other 2.0 3.6 1.4 3.6
---------------------------------------------------------------------
102.5 100.1 198.8 196.1
---------------------------------------------------------------------
---------------------------------------------------------------------


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. COMPARATIVE FIGURES

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

14. 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 ended 6 months ended
June 30 June 30
---------------------------------------------------------------------
Reconciling
items 2005 2004 2005 2004
---------------------------------------------------------------------
Earnings from
operations -
Canadian GAAP $ 24.8 $ 15.5 $ 76.5 $ 62.7
Derivatives
and hedging
activities,
net of tax I (2.6) (1.3) (1.8) (2.0)
Start-up costs,
net of tax II (0.1) - (0.1) -
Amortization
of pension
transition
adjustment V (1.0) (1.2) (2.0) (2.3)
---------------------------------------------------------------------
Earnings from
operations -
U.S. GAAP 21.1 13.0 72.6 58.4
Net gain on
disposal of
discontinued
operations -
Canadian and
U.S. GAAP - 9.6 - 9.6
---------------------------------------------------------------------
Net earnings -
U.S. GAAP $ 21.1 $ 22.6 $ 72.6 $ 68.0
Foreign currency
cumulative
translation
adjustment I,VII (6.2) 17.3 (7.3) 23.6
Net gain (loss)
on derivative
instruments I,VII (28.0) (6.2) (88.6) (11.6)
---------------------------------------------------------------------
Comprehensive
income -
U.S. GAAP $(13.1) $ 33.7 $(23.3) $ 80.0
---------------------------------------------------------------------
Basic EPS - U.S. GAAP
Earnings from
continuing
operations $ 0.11 $ 0.07 $ 0.37 $ 0.30
Net gain on
disposal of
discontinued
operations - 0.05 - 0.05
---------------------------------------------------------------------
Net earnings $ 0.11 $ 0.12 $ 0.37 $ 0.35
---------------------------------------------------------------------
Diluted EPS - U.S. GAAP
Earnings from
continuing
operations $ 0.11 $ 0.07 $ 0.37 $ 0.30
Net gain on
disposal of
discontinued
operations - 0.05 - 0.05
---------------------------------------------------------------------
Net earnings $ 0.11 $ 0.12 $ 0.37 $ 0.35
---------------------------------------------------------------------
---------------------------------------------------------------------


B. Balance sheet information

June 30, Dec. 31,
2005 2004
Reconciling Canadian U.S. Canadian U.S.
items GAAP GAAP GAAP GAAP
---------------------------------------------------------------------
Assets
Current derivative
assets I - 11.1 0.0 47.8
Accounts receivable VIII 516.9 516.9 447.0 445.5
Income taxes
receivable I 62.2 78.4 60.1 75.1
Property, plant
and equipment, net II 5,710.9 5,689.3 5,721.4 5,699.5
Long-term
derivative asset I - 195.1 0.0 187.7
Other assets
(including
current portion) I, II 237.7 61.7 502.4 300.5
Liabilities
Accounts payable
and accrued
liabilities V 515.6 498.0 462.5 387.6
Income taxes
payable II 17.9 12.5 6.1 0.7
Current derivative
liabilities I - 15.1 0.0 32.2
Long-term debt I 2,054.0 2,107.9 2,321.1 2,365.0
Deferred credits
and other
liabilities
(including current
portion) I, XI 421.4 430.7 639.3 646.1
Firm commitment I - 0.0 0.0 0.4
Long-term
derivative
liabilities I - 173.8 0.0 48.2
Future or deferred
income tax
liabilities I, II, IV, V 730.1 679.5 703.9 694.8
Non-controlling
interest I 608.3 607.9 616.4 615.4
Equity
Retained earnings I, II, V 888.9 878.7 910.3 904.0
Cumulative
translation
adjustment I (63.9) - (52.2) 0.0
Accumulated other
comprehensive
income I, V - (188.5) 0.0 (92.6)
---------------------------------------------------------------------
---------------------------------------------------------------------


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, 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 derivative hedging instruments 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.

The corporation's fair value hedges resulted in no net impact in the three and six months ended June 30, 2005 and 2004 related to the ineffective portion of its hedging instruments (inclusive of the time value of money) as well as the portion not designated as a hedge.

(ii) Cash flow hedging strategy

In the three and six months ended June 30, 2005, the corporation's cash flow hedges resulted in an after-tax loss of $nil (2004-$nil) related to the ineffective portion of its hedging instruments, and an after-tax gain of $nil for the three and six months ended June 30, 2005 (2004 -$nil) 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 $3.3 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 sales contracts and direct foreign currency debt to hedge its exposure to changes in the carrying value of its investments in its foreign subsidiaries in the U.S., Australia and Mexico. Realized and unrealized gains and losses from these hedges are included in Other Comprehensive Income (OCI), with the related amounts due to or from counterparties included in long-term derivative assets and liabilities and long-term debt.

In the three and six months ended June 30, 2005, the corporation recognized an after-tax gain of $28.9 million and $90.04 million, respectively, (2004-$7.1 million and $13.4 million respectively) on its net investment hedges, included in OCI.

In the three and six months ended June 30, 2005, the corporation recognized after-tax gains of $nil (2004 - $nil), related to ineffectiveness of 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.

(v) Other hedging activities

In the three and six months ended June 30, 2005, the corporation recognized pre-tax losses of $nil (2004 - $nil) related to hedging activities that do not qualify for hedge accounting under Statement 133.

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 as 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 would be as follows:



June 30 Dec. 31
2005 2004
---------------------------------------------------------------------
Future income tax liabilities (net)
under Canadian GAAP $ (572.1) $ (561.5)
Derivatives 63.3 23.2
Start-up costs (2.3) (2.3)
Employee future benefits (10.4) (11.8)
---------------------------------------------------------------------
$ (521.5) $ (552.4)
---------------------------------------------------------------------
---------------------------------------------------------------------


Comprised of the following:
June 30 Dec. 31
2005 2004
---------------------------------------------------------------------
Current deferred income tax assets $ 20.7 $ 21.5
Long-term deferred income tax assets 153.1 132.0
Current deferred income tax liabilities (15.8) (11.1)
Long-term deferred income tax liabilities (679.5) (694.8)
---------------------------------------------------------------------
$ (521.5) $ (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 ended 6 months ended
June 30 June 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Net gain on derivative
instruments:
Unrealized gain, net of
taxes of $52.3 million $ (28.9) $ (7.1) $ (90.4) $ (13.4)
Reclassification adjustment
for gains included in net
income,net of taxes of
$1.0 million 0.9 0.9 1.8 1.8
---------------------------------------------------------------------
Net gain on derivative
instruments (28.0) (6.2) (88.6) (11.6)
Translation adjustments (6.2) 17.3 (7.3) 23.6
---------------------------------------------------------------------
Other comprehensive
income (loss) $ (34.2) $ 11.1 $ (95.9) $ 12.0
---------------------------------------------------------------------
---------------------------------------------------------------------


The components of AOCI were:

June 30 Dec. 31
2005 2004
---------------------------------------------------------------------
Net loss on derivative instruments $ (149.4) $ (60.8)
Translation adjustments (37.4) (30.1)
Registered pension alternate minimum liabilities (1.7) (1.7)
---------------------------------------------------------------------
Accumulated other comprehensive loss $ (188.5) $ (92.6)
---------------------------------------------------------------------
---------------------------------------------------------------------


VIII. Share capital

Under U.S. GAAP, amounts receivable for share capital should be recorded as a deduction from shareholders' equity. Under Canadian GAAP, effective Jan. 1, 2004, TransAlta has prospectively presented employee share purchase plan loans as a deduction from shareholders' equity thereby eliminating the difference between U.S. and Canadian GAAP as of Jan. 1, 2004. Under the corporation's employees share purchase plan, accounts receivable at Dec. 31, 2003 were $0.9 million.

IX. 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.

X. 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).

XI. Guarantees

TransAlta accounts for guarantees and related contracts, for which it is the guarantor, under FASB Interpretation No. 45 (FIN 45), Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others. In accordance with FIN 45, upon issuance or modification of a guarantee on or after Jan. 1, 2003, the corporation recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under the guarantee. TransAlta reduces the obligation over the term of the guarantee or related contract in a systematic and rational manner as risk is reduced under the obligation.



SUPPLEMENTAL INFORMATION

June 30 Dec. 31
(Annualized) 2005 2004
---------------------------------------------------------------------
Restated
Closing market price $ 20.43 $ 18.05
Price range (last 12 months) High $ 20.94 $ 18.79
Low $ 15.40 $ 15.25
Debt/invested capital (including non-
recourse debt) 46.1% 46.4%
Debt/invested capital (excluding non-
recourse debt) 42.3% 42.3%
Return on common shareholders' equity 7.1% 6.5%
Return on invested capital 7.9% 7.6%
Book value per share $ 12.61 $ 12.73
Cash dividends per share $ 1.00 $ 1.00
Price/earnings ratio (times) 23.0 x 21.7 x
Dividend payout ratio 111.6% 120.0%
Dividend coverage (times) 3.4 x 3.2 x
Dividend yield 4.9% 5.5%
Cash flow to debt 20.6% 19.0%
---------------------------------------------------------------------


RATIO FORMULAS

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

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

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

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

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

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

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

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

Dividend yield equals 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

Web site
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

Web site
www.cibcmellon.com



Contact Information

  • TransAlta Corporation - Media inquiries
    Sneh Seetal
    Senior Media Relations Advisor
    (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