TransAlta Corporation

THIRD QUARTER REPORT FOR 2005

MANAGEMENT’S DISCUSSION AND ANALYSIS

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

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

RESULTS OF OPERATIONS

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

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

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

	3 months ended Sept. 30				9 months ended Sept. 30
		2005		2004 1		2005		2004 1
Availability (%)		89.8		88.0		89.1		88.8
Production (GWh)		13,172		12,685		38,402		38,146
Revenue	$	722.9	$	678.2	$	2,028.4	$	1,926.1
Gross margin 2	$	372.8	$	353.6	$	1,075.4	$	1,023.9
Operating income 2	$	119.8	$	113.6	$	346.8	$	320.6
Earnings from continuing operations	$	52.1	$	35.8	$	128.6	$	98.5
Gain on disposal of discontinued operations, net of tax		–		–		–		9.6
Net earnings	$	52.1	$	35.8	$	128.6	$	108.1
Basic earnings per common share:
Earnings from continuing operations	$	0.27	$	0.18	$	0.66	$	0.51
Gain on disposal of discontinued operations, net of tax		–		–		–		0.05
Net earnings	$	0.27	$	0.18	$	0.66	$	0.56
Diluted earnings per common share:
Earnings from continuing operations	$	0.27	$	0.18	$	0.65	$	0.51
Gain on disposal of discontinued operations, net of tax		–		–		–		0.05
Net earnings	$	0.27	$	0.18	$	0.65	$	0.56
Cash flow from operating activities	$	148.5	$	142.6	$	407.5	$	415.3

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

TransAlta Corporation  Q3/05          1

NET EARNINGS

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

Net earnings for 3 months ended Sept. 30, 2004	$	35.8
Increased Generation gross margins		27.2
Reduced planned maintenance costs, offset by lost earnings due to planned outages		3.2
Lower Energy Marketing gross margins		(4.5)
Increase in operational and administrative costs		(19.4)
Decreased depreciation		2.3
Lower income tax expense		6.9
2004 gain on sale of TransAlta Power partnership units		(3.1)
Other		3.7
Net earnings for 3 months ended Sept. 30, 2005	$	52.1

Production for the third quarter increased by 487 gigawatt hours (GWh) from the same period in 2004 as a result of increased production due to lower unplanned outages at the Alberta Thermal plants of 313 GWh, incremental production from the addition of Genesee 3 of 424 GWh, offset by the decommissioning of units one and two of the Wabamun plant of 206 GWh and the outage at unit four of the Wabamun plant of 208 GWh.

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

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

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

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

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

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

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

CASH FLOW

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

Cash flow from operating activities for 3 months ended Sept. 30, 2004	$	142.6
Increased net earnings		16.3
Asset retirement obligations costs settled		(5.5)
Changes in other non-cash items		(15.1)
Changes in non-cash working capital		10.2
Cash flow from operating activities for 3 months ended Sept. 30, 2005	$	148.5

Cash flow from operating activities of $148.5 million increased $5.9 million as compared to the third quarter of 2004 mainly due to higher earnings. Capital expenditures in the quarter were $77.0 million compared to $100.4 million in the third quarter last year. Net debt retirement in the quarter, including both short- and long-term debt, was $110.2 million compared to $44.3 million in the same period in 2004.

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

2          TransAlta Corporation  Q3/05

DISCUSSION OF SEGMENTED RESULTS

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

SIGNIFICANT EVENTS

Wabamun outage

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

Summerview Wind Farm

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

Commissioning of the Genesee 3 Generating Facility

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

The results of the Generation segment are as follows:
				2005				2004
3 months ended Sept. 30		Total	Per MWh			Total	Per MWh
Revenues	$	668.2	$	50.73	$	604.4	$	47.65
Fuel and purchased power		(304.8)		(23.14)		(264.7)		(20.87)
Gross margin		363.4		27.59		339.7		26.78
Operations, maintenance and administration		138.7		10.53		134.7		10.62
Depreciation and amortization		83.0		6.30		84.9		6.69
Taxes, other than income taxes		5.1		0.39		5.5		0.43
Operating expenses		226.8		17.22		225.1		17.74
Gain on sale of TransAlta Power partnership units		–		–		3.1		0.24
Operating income before corporate allocations		136.6		10.37		117.7		9.28
Corporate allocations		19.8		1.50		14.1		1.11
Operating income	$	116.8	$	8.87	$	103.6	$	8.17
Production (GWh)		13,172				12,685
Availability (%)		89.8				88.0
				2005				2004
9 months ended Sept. 30		Total	Per MWh			Total	Per MWh
Revenues	$	1,846.0	$	48.07	$	1,742.4	$	45.68
Fuel and purchased power		(817.8)		(21.30)		(761.8)		(19.97)
Gross margin		1,028.2		26.77		980.6		25.71
Operations, maintenance and administration		379.8		9.89		367.1		9.62
Depreciation and amortization		258.0		6.72		256.6		6.73
Taxes, other than income taxes		16.5		0.43		17.6		0.46
Operating expenses		654.3		17.04		641.3		16.81
Gain on sale of TransAlta Power partnership units		–		–		24.2		0.63
Operating income before corporate allocations		373.9		9.73		363.5		9.53
Corporate allocations		56.4		1.47		50.5		1.32
Operating income	$	317.5	$	8.26	$	313.0	$	8.21
Production (GWh)		38,402				38,146
Availability (%)		89.1				88.8

TransAlta Corporation  Q3/05          3

Market prices and heat rates

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

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

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

Availability

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

Production

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

Revenue

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

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

Fuel and purchased power

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

4           TransAlta Corporation  Q3/05

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

Operations, maintenance and administration expense

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

Planned maintenance

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

								Gas and
				Coal				Hydro				Total
3 months ended Sept. 30		2005		2004		2005		2004		2005		2004
Capitalized	$	24.5	$	20.5	$	7.2	$	1.7	$	31.7	$	22.2
Expensed		22.7		31.2		2.1		0.4		24.8		31.6
	$	47.2	$	51.7	$	9.3	$	2.1	$	56.5	$	53.8
GWh lost		600		612		94		23		694		635
								Gas and
				Coal				Hydro				Total
9 months ended Sept. 30		2005		2004		2005		2004		2005		2004
Capitalized	$	53.9	$	60.1	$	34.0	$	7.2	$	87.9	$	67.3
Expensed		53.2		64.7		3.7		3.2		56.9		67.9
	$	107.1	$	124.8	$	37.7	$	10.4	$	144.8	$	135.2
GWh lost		1,788		1,831		461		135		2,249		1,966

In the three and nine months ended Sept. 30, 2005, there were 694 GWh and 2,249 GWh of production lost due to planned maintenance compared to 635 GWh and 1,966 GWh lost for planned maintenance in the three and nine months ended Sept. 30, 2004. During the third quarter of 2005, incremental outages in the gas fleet contributed 71 GWh of lost production over the same period in 2004. Lost production in the coal fleet remained consistent between periods. During the first nine months of 2005, incremental outages in the gas fleet contributed to 326 GWh of lost production in 2005 compared to the same period in 2004. Lost production from the coal fleet was 43 GWh lower in the first nine months of 2005 as compared to the same period in 2004, driven primarily by improvements in durations on certain outages in 2005.

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

TransAlta Corporation  Q3/05          5

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

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

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

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

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

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

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

6           TransAlta Corporation  Q3/05

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

Long-term contracts

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

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

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

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

Merchant

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

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

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

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

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

CE Gen

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

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

TransAlta Corporation  Q3/05          7

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

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

The results of the Energy Marketing segment are as follows:
	3 months ended Sept. 30				9 months ended Sept. 30
		2005		2004		2005		2004
Revenues	$	54.7	$	73.8	$	182.4	$	183.7
Trading purchases		(45.3)		(59.9)		(135.2)		(140.4)
Gross margin		9.4		13.9		47.2		43.3
Operations, maintenance and administration		3.0		1.6		8.2		5.0
Depreciation and amortization		0.5		0.6		1.3		1.5
Operating expenses		3.5		2.2		9.5		6.5
Prior period regulatory decision		–		–		–		22.9
Operating income before corporate allocations		5.9		11.7		37.7		13.9
Corporate allocations		2.9		1.7		8.4		6.3
Operating income	$	3.0	$	10.0	$	29.3	$	7.6

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

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

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

TransAlta’s fixed price trading positions were as follows:
	Electricity	Natural Gas
Units (000s)	(MWh)	(GJ)
Fixed price payor, notional amounts, Sept. 30, 2005	24,151	39,587
Fixed price payor, notional amounts, Dec. 31, 2004	14,138	35,222
Fixed price receiver, notional amounts, Sept. 30, 2005	27,042	34,718
Fixed price receiver, notional amounts, Dec. 31, 2004	15,854	29,721
Maximum term in months, Sept. 30, 2005	39	25
Maximum term in months, Dec. 31, 2004	48	34

8          TransAlta Corporation  Q3/05

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

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

Electricity (GWh)	3 months ended Sept. 30		9 months ended Sept. 30
	2005	2004	2005	2004
Physical	11,707	19,515	33,721	46,854
Financial	19,456	5,765	38,795	14,415
	31,163	25,280	72,516	61,269
Gas (million GJ)	3 months ended Sept. 30		9 months ended Sept. 30
	2005	2004	2005	2004
Physical	22.7	39.3	64.9	88.9
Financial	121.0	91.5	233.6	224.7
	143.7	130.8	298.5	313.6

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

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

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

PRICE RISK MANAGEMENT

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

		Sept. 30		Dec. 31
Balance Sheet		2005		2004
Price risk management assets
Current	$	249.1	$	61.4
Long-term		38.9		32.5
Price risk management liabilities
Current		(230.3)		(49.9)
Long-term		(36.7)		(28.5)
Net price risk management assets outstanding	$	21.0	$	15.5
Change in fair value of net assets			Fair value
Net price risk management assets outstanding at Dec. 31, 2004			$	15.5
Contracts realized, amortized or settled during the period				(16.7)
Changes in values attributable to market price and other market changes				6.1
New contracts entered into during the current calendar year				16.1
Net price risk management assets outstanding at Sept. 30, 2005			$	21.0

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

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

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

TransAlta Corporation  Q3/05          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
	3 months ended Sept. 30				9 months ended Sept. 30
		2005		2004		2005		2004
Interest on recourse and non-recourse debt	$	48.3	$	47.4	$	141.2	$	150.8
Interest on preferred securities		3.4		9.2		13.1		27.6
Interest income		(2.7)		(0.8)		(2.7)		(1.7)
Capitalized interest		–		(5.5)		(3.4)		(15.3)
Net interest expense	$	49.0	$	50.3	$	148.2	$	161.4

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

NON-CONTROLLING INTERESTS

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

EQUITY INCOME

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

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

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

INCOME TAXES

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

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

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

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

10          TransAlta Corporation  Q3/05

FINANCIAL POSITION
The following chart outlines significant changes in the consolidated balance sheet from Dec. 31, 2004 to Sept. 30, 2005:
	Increase/
	(Decrease)		Explanation
Cash and cash equivalents	$	(45.2)	Refer to Consolidated Statements of Cash Flows.
Accounts receivable		120.3	Increased Energy Marketing trading and increased Generation
			activity due to timing and incremental Genesee 3.
Price risk management assets (current)		187.7	Increase in the volumes of power contracts receivable and an
			increase in prices.
Property, plant and equipment,		(129.7)	Increase due to capital additions of $222 million, offset by
net of accumulated depreciation			depreciation of ($291 million) and a change in foreign exchange
			rate of ($101 million).
Intangible assets		(39.1)	Amortization of the CE Gen sales contracts and change in foreign exchange rates.
Other assets (including current portion)		(303.2)	Decrease due to scheduled maturities of net investment hedge contracts.
Short-term debt		141.1	Issuances of short-term debt.
Accounts payable and accrued liabilities		98.5	Increased Energy Marketing trading, increased major maintenance due to timing, and increased interest due to timing of payments.
Price risk management liabilities (current)		180.4	Increase in the volumes of power contracts payable and an increase in prices.
Recourse long-term debt (including current portion)		(329.1)	Redemption of preferred securities.
Non-recourse long-term debt		(58.5)	Repayment of long-term debt.
(including current portion)
Deferred credits and other long-term		(251.8)	Decrease due to scheduled maturities of net investment
liabilities (including current portion)			hedge contracts.
STATEMENTS OF CASH FLOWS
3 months ended Sept. 30		2005		2004	Explanation
Cash and cash equivalents, beginning of period	$	58.3	$	106.3
Provided by (used in):
Operating activities		148.5		142.6	Increased earnings and lower working capital requirements.
Investing activities		27.7		(18.2)	Capital expenditures of $77.0 million, offset by foreign exchange gains on net investment hedges of foreign exchange gains on net investment hedges of $79.9 million and a decrease in the equity investment of $31.8 million.
					In 2004, capital expenditures of $100.4 million relating primarily to the construction of the Summerview Wind Farm, the Genesee 3 project and planned maintenance, offset by a decrease in the equity investment of $21.2 million and foreign exchange gains on net investment hedges of $48.1 million.
Financing activities		(180.4)		(105.6)	Net repayment of short-term debt of $92.0 million, net repayment of long-term borrowings of $18.2 million, cash dividends on common shares of $61.2 million and non-controlling interest distributions of $17.8 million.
					In 2004, net repayment of $35.4 million of short-term debt, cash dividends on common shares of $32.6 million and non-controlling interest distributions of $31.9 million.
Translation of foreign currency cash		1.9		–
Cash and cash equivalents, end of period	$	56.0	$	125.1

TransAlta Corporation  Q3/05          11

9 months ended Sept. 30		2005		2004	Explanation
Cash and cash equivalents, beginning of period	$	101.2	$	123.8
Provided by (used in):
Operating activities		407.5		415.3	Increased earnings offset by higher working capital requirements.
Investing activities		(126.9)		(73.5)	Capital expenditures of $221.9 million, offset by foreign exchange gains on net investment hedges of $83.2 million and a decrease in equity investment of $14.9 million.
					In 2004, capital expenditures of $268.1 million relating primarily to the construction of the Summerview Wind Farm, the Genesee 3 project, and major maintenance, partially offset by proceeds from the exercise of TransAlta Power warrants ($61.7 million) and the collection of the $90.8 million Zinc Recovery long-term receivable.
Financing activities		(324.0)		(340.5)	Net issuance of short-term debt of $139.7 million and common share issuances of $13.4 million were used to partially fund the redemption of preferred securities of $300.0 million, repayment of long-term borrowings of $40.1 million, non-controlling interest distributions of $53.4 million and dividend payments of $96.8 million.
					In 2004, net repayment of short-term debt of $72.9 million, net repayment of long-term debt of $135.1 million, cash dividends on common shares of $102.6 million, and non-controlling interest distributions of $33.5 million.
Translation of foreign currency cash		(1.8)		–
Cash and cash equivalents, end of period	$	56.0	$	125.1

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

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

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

Funds generated from operations

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

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

12          TransAlta Corporation  Q3/05

Investing activities

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

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

Financing activities

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

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

Guarantee contracts

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

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

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

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

OUTLOOK

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

Production and availability

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

Power prices

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

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

TransAlta Corporation  Q3/05          13

Fuel costs

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

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

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

Operations, maintenance and administration costs

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

Capital expenditures

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

Planned maintenance

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

				Gas and
		Coal		Hydro		Total
Capitalized	$	65-70	$	65-70	$	130-140
Expensed		65-70		10		75-80
	$	130-140	$	75-80	$	205-220
GWh lost		2,300		600		2,900

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

Energy marketing

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

Exposure to fluctuations in foreign currencies

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

Net interest expense

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

Liquidity and capital resources

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

14          TransAlta Corporation  Q3/05

NEW ACCOUNTING STANDARDS

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

U.S. GAAP RESTATEMENT

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

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

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

		2004		2003		2002
Decrease in:
Earnings from continuing operations	$	–	$	102.7	$	6.3
Net earnings	$	–	$	102.7	$	6.3
Net earnings per share in accordance with U.S. GAAP
Continuing operations	$	–	$	0.56	$	0.04
Discontinued operations	$	–	$	–	$	–
Basic	$	–	$	0.56	$	0.04
Diluted	$	–	$	0.56	$	0.04
The impact on previously reported balance sheet amounts for U.S. GAAP purposes is as follows:
				2004		2003
Increase (decrease) in:
Contributed surplus			$	133.0	$	133.0
Retained earnings			$	(133.0)	$	(133.0)

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

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

TransAlta Corporation  Q3/05          15

PRIOR PERIOD REGULATORY DECISION

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

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

NON-GAAP MEASURES

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

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

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

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

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

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

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

16          TransAlta Corporation  Q3/05

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

	3 months ended Sept. 30				9 months ended Sept. 30
		2005		2004 1		2005		2004 1
Earnings on a comparable basis	$	39.1	$	33.8	$	115.6	$	90.9
Tax settlement on deferred receivable		13.0		–		13.0		–
Gain on sale of TA Power units, net of tax		–		2.0		–		15.7
Prior period regulatory decision, net of tax		–		–		–		(14.9)
Gain from discontinued operations, net of tax		–		–		–		9.6
New Zealand tax settlement		–		–		–		6.8
Net earnings	$	52.1	$	35.8	$	128.6	$	108.1
Weighted average common shares outstanding in the period		196.1		193.0		196.3		192.2
Earnings on a comparable basis per share	$	0.20	$	0.17	$	0.59	$	0.47

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

SELECTED QUARTERLY INFORMATION 1
(In millions of Canadian dollars except per share amounts)
		Q4 2004		Q1 2005		Q2 2005		Q3 2005
Revenue	$	660.2	$	684.3	$	621.2	$	722.9
Earnings from continuing operations		62.1		51.7		24.8		52.1
Net earnings		62.1		51.7		24.8		52.1
Basic earnings per common share:
Continuing operations		0.32		0.27		0.13		0.27
Net earnings		0.32		0.27		0.13		0.27
Diluted earnings per common share:
Continuing operations		0.32		0.26		0.13		0.27
Net earnings		0.32		0.26		0.13		0.27
		Q4 2003		Q1 2004		Q2 2004		Q3 2004
Revenue	$	609.1	$	655.0	$	592.9	$	678.2
Earnings from continuing operations		43.8		47.2		15.5		35.8
Net earnings		43.8		47.2		25.1		35.8
Basic earnings per common share:
Continuing operations		0.23		0.25		0.08		0.18
Net earnings		0.23		0.25		0.13		0.18
Diluted earnings per common share:
Continuing operations		0.23		0.24		0.08		0.18
Net earnings		0.23		0.24		0.13		0.18

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

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

TransAlta Corporation  Q3/05          17

FORWARD-LOOKING STATEMENTS

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

CONTROLS AND PROCEDURES

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

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

18          TransAlta Corporation  Q3/05