CC Filed by Filing Services Canada Inc. 403-717-3898

EX-13.2 3 ex132.htm MD&A CC Filed by Filing Services Canada Inc. 403-717-3898

TRANSALTA CORPORATION

THIRD QUARTER REPORT FOR 2009

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 31 for additional information.

This MD&A should be read in conjunction with the unaudited interim consolidated financial statements of TransAlta Corporation as at and for the nine months ended Sept. 30, 2009 and 2008, and should also be read in conjunction with the audited consolidated financial statements and MD&A contained in our 2008 Annual Report. In this MD&A, unless the context otherwise requires, ‘we’, ‘our’, ‘us’, the ‘corporation’ and ‘TransAlta’ refers to TransAlta Corporation and its subsidiaries. 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. 26, 2009. 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. We have two business segments: Generation and Commercial Operations & Development (“COD”). Our segments are supported by a corporate group that provides finance, tax, treasury, legal, regulatory, environmental, health and safety, sustainable development, corporate communications, government and investor relations, information technology, risk management, human resources, internal audit, and other administrative support.

In this MD&A, the impact of foreign exchange fluctuations on foreign currency denominated 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 relating to self-sustaining foreign operations is reflected in the equity section of the consolidated balance sheets.

TRANSALTA CORPORATION / Q3 2009 1

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


	3 months ended Sept. 30		9 months ended Sept. 30
	2009	2008	2009	2008
Availability (%)	83.9	86.0	84.4	85.7
Production (GWh)	11,610	12,357	33,439	36,235
Revenue	666	791	2,007	2,302
Gross margin⁽¹⁾	380	398	1,107	1,207
Operating income⁽¹⁾	120	124	219	406
Net earnings	66	61	102	141
Net earnings per share, basic and diluted	0.34	0.31	0.52	0.71
Comparable earnings per share⁽¹⁾	0.34	0.32	0.49	1.06
Cash flow from operating activities	194	202	334	610
Free cash flow (deficiency)⁽¹⁾	12	20	(196)	(33)
Cash dividends declared per share	0.29	0.27	0.87	0.81

			As at Sept. 30, 2009	As at Dec. 31, 2008
Total assets			7,870	7,824
Total long-term financial liabilities			3,889	3,636

AVAILABILITY & PRODUCTION

Availability for the three months ended Sept. 30, 2009 decreased to 83.9 per cent from 86.0 per cent compared to the same period in 2008 due to higher unplanned outages at the Centralia Thermal plant (“Centralia Thermal”), and higher planned outages at the Alberta Thermal plants (“Alberta Thermal”), Windsor, and Mississauga.

Availability for the nine months ended Sept. 30, 2009 decreased to 84.4 per cent from 85.7 per cent compared to the same period in 2008 due to higher planned and unplanned outages at Alberta Thermal, and higher planned outages at Windsor and Mississauga, partially offset by lower planned and unplanned outages at Centralia Thermal, and no planned maintenance in 2009 at Genesee 3.

Production for the three months ended Sept. 30, 2009 decreased 747 gigawatt hours (“GWh”) compared to the same period in 2008 due to lower Power Purchase Agreement (“PPA”) customer demand, the expiration of the long-term contract at Saranac, higher unplanned outages at Centralia Thermal, and lower hydro volumes, partially offset by higher production at the Centralia gas-fired facility (“Centralia Gas”).

Production for the nine months ended Sept. 30, 2009 decreased 2,796 GWh compared to the same period in 2008 due to higher planned and unplanned outages at Alberta Thermal, higher economic dispatching at Centralia Thermal, lower PPA customer demand, lower hydro volumes, and the expiration of the long-term contract at Saranac, partially offset by lower planned and unplanned outages at Centralia Thermal, and no planned maintenance in 2009 at Genesee 3.

1() Gross margin, Operating income, Comparable earnings, and Free cash flow are not defined under Canadian GAAP. Refer to the Non-GAAP Measures
section on page 28 of this MD&A for further discussion of these items, including a reconciliation to net earnings and cash flow from operating activities.

2 TRANSALTA CORPORATION / Q3 2009

NET EARNINGS

A reconciliation of net earnings is presented below:


	3 months ended Sept. 30	9 months ended Sept. 30
Net earnings, 2008	61	141
Increase (decrease) in Generation gross margins	4	(69)
Mark-to-market movements - Generation	(8)	13
Decrease in COD gross margins	(14)	(44)
Decrease (increase) in operations, maintenance, and administration costs	17	(51)
Increase in depreciation expense	(3)	(34)
Increase in net interest expense	(3)	(1)
Decrease in equity loss	-	97
Decrease in non-controlling interest	12	11
(Increase) decrease in income tax expense	(5)	29
Other	5	10
Net earnings, 2009	66	102

Generation gross margins, net of mark-to-market movements, were comparable for the three months ended Sept. 30, 2009 to the same period in 2008 as a result of favourable contractual pricing, lower penalties due to lower spot pricing, and favourable foreign exchange rates, largely offset by lower hydro volumes, the expiration of the long-term contract at Saranac, and lower production at Centralia Thermal.

For the nine months ended Sept. 30, 2009, Generation gross margins, net of mark-to-market movements, decreased due to higher planned and unplanned outages at Alberta Thermal, lower hydro volumes, and the expiration of the long-term contract at Saranac, partially offset by favourable foreign exchange rates, favourable contractual pricing, and no planned maintenance in 2009 at Genesee 3.

For the three months and nine months ended Sept. 30, 2009, COD gross margins decreased relative to the same period in 2008 due to the effect of reduced industrial demand, gas price uncertainty, and market structure changes in the Western region.

Operations, maintenance, and administration (“OM&A”) costs for the three months ended Sept. 30, 2009 decreased primarily due to targeted cost savings throughout the company and lower compensation costs.

For the nine months ended Sept. 30, 2009, OM&A costs increased compared to the same period in 2008 primarily due to higher planned outages and unfavourable foreign exchange rates, partially offset by targeted cost savings throughout the company and lower compensation costs.

Depreciation expense for the three months ended Sept. 30, 2009 is comparable with the prior period as a result of an increased asset base and unfavourable foreign exchange being partially offset by lower production at Saranac, which is depreciated on a unit of production basis.

For the nine months ended Sept. 30, 2009, depreciation expense increased compared to the same period in 2008 due to unfavourable foreign exchange rates, an increased asset base, and the retirement of certain assets during planned maintenance activities, partially offset by reduced production at Saranac and the early retirement of certain components as a result of equipment modifications made at Centralia Thermal in 2008.

In the first quarter of 2008, an equity loss of $97 million was recorded to reflect the writedown of our Mexican investment that was sold in the fourth quarter of the same year.

TRANSALTA CORPORATION / Q3 2009 3

For the three and nine months ended Sept. 30, 2009, non-controlling interest decreased primarily due to lower earnings resulting from the expiration of the long-term contract at Saranac.

Income tax expense increased for the three months ended Sept. 30, 2009 compared to the same period in 2008 due to higher pre-tax earnings.

For the nine months ended Sept. 30, 2009, income tax expense decreased compared to the same period in 2008 due to lower pre-tax earnings, partially offset by the tax recovery on the writedown of our Mexican investment in 2008.

CASH FLOW

Cash flow from operating activities for the three months ended Sept. 30, 2009 decreased $8 million due to unfavourable changes in working capital, partially offset by higher cash earnings.

Cash flow from operating activities for the nine months ended Sept. 30, 2009 decreased $276 million due to lower cash earnings, the receipt of an additional PPA payment in 2008, and higher inventory balances in 2009.

Free cash flow for the three months ended Sept. 30, 2009 decreased $8 million primarily due to lower cash earnings.

The free cash flow deficiency for the nine months ended Sept. 30, 2009 increased $163 million compared to the same period in 2008 due to lower cash earnings and the receipt of an additional PPA payment in 2008.

SIGNIFICANT EVENTS

Three months ended Sept. 30, 2009

Sarnia Contract

On Sept. 30, 2009, we entered into a new agreement with the Ontario Power Authority (“OPA”) for our Sarnia regional cogeneration power plant. The contract is capacity based and the term of the new agreement is from July 1, 2009 through to the end of 2025. While the specific terms and conditions of the new agreement are confidential, the OPA has indicated that the agreement is in line with other similar agreements issued by the OPA.

Offer to Acquire Canadian Hydro Developers, Inc.

On July 20, 2009 we announced an all-cash offer to acquire Canadian Hydro Developers, Inc. ("Canadian Hydro") at an initial price of $4.55 per share. On Oct. 5, 2009, we increased our all-cash offer to $5.25 per share. As of October 23, 2009 we have completed the acquisition and payment for approximately 87 percent of the outstanding common shares of Canadian Hydro. Refer to the Subsequent Events section of this MD&A for further details.

4 TRANSALTA CORPORATION / Q3 2009

Nine months ended Sept. 30, 2009

Carbon Capture and Storage

On June 30, 2009 the Alberta Government announced that our Project Pioneer was not selected as part of the first carbon capture and storage (“CCS”) projects to receive funding under its $2 billion CCS initiative. Refer to the Subsequent Events section of this MD&A for further details.

Senior Notes Offering

On May 26, 2009, we announced an offering of $200 million senior notes maturing in 2014 and bearing an interest rate of 6.45 per cent. The net proceeds from the offering will be used for debt repayment, financing of our long-term investment plan, and for general corporate purposes.

Major Maintenance Plans

On May 20, 2009, we announced the advancement of a major maintenance outage on Unit 3 of our Sundance facility from the second quarter of 2010 into the second and third quarters of 2009. The advancement of the maintenance outage takes advantage of current low power prices, optimizes preventative maintenance in the short-term, and is expected to provide an economic cash benefit over the two-year period, and improves the unit’s availability. As a result of the change in schedule, 2009 lost GWh increased by 396 GWh and net income declined by $24 million ($0.12 per share).

Normal Course Issuer Bid (“NCIB”) Program

On May 6, 2009, we announced plans to renew our NCIB program until May 6, 2010. We received the approval to purchase, for cancellation, up to 9.9 million of our common shares representing 5 per cent of our 198 million common shares issued and outstanding as at April 30, 2009. Any purchases undertaken will be made on the open market through the Toronto Stock Exchange at the market price of such shares at the time of acquisition. No purchases were made under the NCIB program through Sept. 30, 2009.

Chief Operating Officer

On April 28, 2009 we announced the appointment of Dawn Farrell to the position of Chief Operating Officer. In this new role, Ms. Farrell will lead our operations, commercial, engineering, technology, and procurement activities. Prior to this appointment, Ms. Farrell was Executive Vice President of Commercial Operations and Development.

Additionally, Richard Langhammer, Executive Vice President of Generation Operations, took on a new assignment as Chief Productivity Officer for the remainder of 2009 with the responsibility for identifying strategies to create sustainable costs savings across the company. Mr. Langhammer announced his retirement earlier this year; he will formally retire at the end of 2009 after 23 years of service.

Ardenville Wind Power Project

On April 28, 2009, we announced plans to design, build, and operate Ardenville, a 69 megawatt (“MW”) wind power project in southern Alberta. The capital cost of the project is estimated at $135 million. Included in the capital cost of the project is the purchase of an already operational 3 MW turbine at Macleod Flats. Commercial operations of the remainder of the Ardenville wind project is expected to commence in the first quarter of 2011.

TRANSALTA CORPORATION / Q3 2009 5

Sundance Unit 4 Derate

On Feb. 10, 2009, we reported the first quarter financial impact of an extended derate on Unit 4 of our Sundance facility (“Unit 4”). The facility experienced an unplanned outage in December 2008 related to the failure of an induced draft fan. At that time, Unit 4, which has a capacity of 406 MW, had been derated to approximately 205 MW. The repair of the induced draft fan components by the original equipment manufacturer took longer than planned, and therefore, Unit 4 did not return to full service until Feb. 23, 2009. As a result of the extended derate, first quarter production and net earnings were reduced by 328 GWh and $10 million, respectively representing both lost merchant revenue and penalties.

In response to this event, as required by the appropriate PPA legislation, we gave notice of a High Impact Low Probability Force Majeure Event to the PPA Buyer and the Balancing Pool. On April 27, 2009, the Balancing Pool rejected our assertion that this outage should be regarded as a High Impact Low Probability Force Majeure Event. As required by the PPA legislation, we were required to pay the penalties related to the derate. As a result, accounting standards required that we also record an additional charge in the second quarter of $7 million after-tax related to this event. We settled the issue in the third quarter and the terms of the settlement are confidential.

Keephills Units 1 and 2 Uprates

On Jan. 29, 2009, we announced a 46 MW (23 MW per unit) efficiency uprate at Unit 1 and Unit 2 of our Keephills facility. The total capital cost of the project is estimated at $68 million with commercial operations of Unit 2 expected by the end of 2011 and Unit 1 by the end of 2012.

Dividend Increase

On Jan. 28, 2009, our Board of Directors declared a quarterly dividend of $0.29 per share on common shares, an increase of $0.02 per share, which on an annual basis will yield $1.16 per share versus $1.08 per share in 2008.

SUBSEQUENT EVENTS

Keephills 3

On Oct. 26, 2009, the Board of Directors approved an increase in the construction cost of Keephills 3 to $988 million due to a change in our original expectations of the labour required to complete the project, and a change to the commencement of commercial operations from the first quarter of 2011 to the second quarter of 2011. The increase in construction cost is due to a change in our original expectations of the labour required to complete the project. Even with the delay of operations and increased cost, Keephills 3 is still expected to meet our investment hurdles.

Carbon Capture and Storage

On Oct. 14, 2009, the federal and provincial governments announced that our CCS project, Project Pioneer, has received committed funding of more than $750 million. The funding is being provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative. The funding will support the undertaking of a Front End Engineering and Design (“FEED”) study to determine if the project is viable. The FEED study is expected to cost $20 million; $10 million will come from the federal government, $5 million will come from the provincial government, and $5 million will come from TransAlta and from industry partners Alstom Canada and Capital Power Corporation. The FEED study is expected to be complete in 2010 and if we proceed with construction, the prototype plant has a targeted start-up date of 2015.

6 TRANSALTA CORPORATION / Q3 2009

Offer to Acquire Canadian Hydro

On Oct. 5, 2009, we entered into a definitive pre-acquisition agreement with Canadian Hydro to acquire all of their issued and outstanding common shares for $5.25 per share in cash. The transaction has a total value of approximately $1.7 billion, and has the unanimous support of the Board of Directors of both companies. The amended offer is subject to certain conditions, including acceptance of the amended offer by holders of at least 66⅔ per cent of Canadian Hydro's common shares calculated on a fully-diluted basis.

On Oct. 23, 2009, we completed the acquisition and payment for approximately 87 percent of the outstanding common shares of Canadian Hydro. We have extended our amended offer for common shares of Canadian Hydro to 3:00 p.m. (Calgary time) on Nov. 3, 2009 to allow additional time for Canadian Hydro shareholders to tender their shares.

Canadian Hydro operates 694 MW of wind, hydro, and biomass facilities in Alberta, Ontario, Quebec, and British Columbia. Canadian Hydro’s assets are highly contracted with counterparties of recognized financial standing. On a combined basis, we will have 9,144 MW of gross generating capacity⁽¹⁾ in operation (8,657 MW net ownership interest). The renewables portfolio will include 1,900 MW in operation, or 22 per cent of the combined portfolio. In addition, there would be 543 MW net under construction and over 500 MW in advanced-stage development.

The transaction will be initially funded with new committed credit facilities that are fully underwritten by a Canadian chartered bank, which, along with existing credit facilities and internally generated cash will provide ample funding to take up and pay for all of the outstanding Canadian Hydro shares. The transaction is not expected to impact our dividend policy.

BUSINESS ENVIRONMENT

We operate in a variety of business environments to generate electricity, find buyers for the power we generate, and arrange for its transmission. The major markets we operate in are Western Canada, the Pacific Northwest, and Eastern Canada. For a further description of the regions in which we operate as well as the impact of prices of electricity and natural gas upon our financial results, refer to our 2008 Annual Report. The key characteristics of these markets are described below.

Electricity Prices

Please refer to page 21 of the 2008 Annual Report for a full discussion of the spot electricity market and the impact of electricity prices upon our business and our strategy to hedge our risk on changes in those prices.

The average spot electricity prices and spark spreads for the third quarter of 2009 and 2008 in our three main markets are shown in the following graphs.

1() We measure capacity as net maximum capacity (see glossary for definition of this and other key items) which is consistent with industry standards. Capacity
figures represent capacity owned and in operation unless otherwise stated.

TRANSALTA CORPORATION / Q3 2009 7

[ex132004.gif]

For the third quarter of 2009, average spot prices decreased in Alberta, the Pacific Northwest, and in Ontario compared to the same period in 2008 due to lower natural gas prices and weaker demand for electricity.

For the nine months ended Sept. 30, 2009, average electricity prices in all three markets were lower than the same period in 2008. These lower prices were primarily due to lower natural gas prices and lower demand for electricity. Details on how our contracted assets and hedging activities help reduce the impact of price changes upon our current results are discussed below. Discussion of our longer-term plans for helping to reduce the impact of price changes to our results are discussed in further detail on page 22 of this MD&A.

8 TRANSALTA CORPORATION / Q3 2009

[ex132006.gif]

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

For the three months ended Sept. 30, 2009, average spark spreads increased in Alberta, the Pacific Northwest and Ontario compared to the same period in 2008 due to power prices decreasing less than natural gas prices.

For the nine months ended Sept. 30, 2009, average spark spreads decreased in Alberta relative to the same period in 2008 due to power prices decreasing more than natural gas prices. Spark spreads in the Pacific Northwest and Ontario increased relative to 2008 as power prices have decreased less than natural gas prices.

During the third quarter, our consolidated power portfolio was over 95 per cent hedged at an average price ranging from $60-$65 per megawatt hour (“MWh”) in Alberta, and an average price ranging from U.S.$50-$55/MWh in the Pacific Northwest. The use of these hedges reduced the impact of lower prices upon our consolidated financial results.

TRANSALTA CORPORATION / Q3 2009 9

DISCUSSION OF SEGMENTED RESULTS

GENERATION: Comprised of hydro, wind, geothermal, natural gas- and coal-fired plants, and related mining operations in Canada, the U.S., and Australia. 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 2008 Annual Report). At Sept. 30, 2009, Generation had 8,386 MW of gross generating capacity⁽¹⁾ in operation (7,963 MW net ownership interest) and 525 MW net under construction. For a full listing of all of our generating assets and the regions in which they operate, refer to page 18 of our 2008 Annual Report.

The results of the Generation segment are as follows:


	2009		2008
3 months ended Sept. 30	Total	Per installed MWh⁽¹⁾	Total	Per installed MWh⁽¹⁾
Revenues	659	35.59	770	41.60
Fuel and purchased power	(286)	(15.45)	(393)	(21.23)
Gross margin	373	20.14	377	20.37
Operations, maintenance and administration	116	6.27	129	6.97
Depreciation and amortization	106	5.72	102	5.51
Taxes, other than income taxes	5	0.27	5	0.27
Intersegment cost allocation	8	0.43	7	0.38
Operating expenses	235	12.69	243	13.13
Operating income	138	7.45	134	7.24
Installed capacity (GWh)	18,516		18,511
Production (GWh)	11,610		12,357
Availability (%)	83.9		86.0


	2009		2008
9 months ended Sept. 30	Total	Per installed MWh⁽¹⁾	Total	Per installed MWh⁽¹⁾
Revenues	1,970	35.86	2,221	40.21
Fuel and purchased power	(900)	(16.38)	(1,095)	(19.82)
Gross margin	1,070	19.48	1,126	20.38
Operations, maintenance and administration	434	7.90	368	6.66
Depreciation and amortization	330	6.01	298	5.39
Taxes, other than income taxes	17	0.31	15	0.27
Intersegment cost allocation	24	0.44	22	0.40
Operating expenses	805	14.66	703	12.73
Operating income	265	4.82	423	7.66
Installed capacity (GWh)	54,938		55,240
Production (GWh)	33,439		36,235
Availability (%)	84.4		85.7

10 TRANSALTA CORPORATION / Q3 2009

Production and Gross Margins

Generation’s production volumes, electricity and steam production revenues, and fuel and purchased power costs based on geographical regions are presented below.¹


3 months ended Sept. 30, 2009	Production (GWh)		Installed (GWh)	Revenue	Fuel & purchased power	Gross margin	Revenue per installed MWh⁽¹⁾	Fuel & purchased power per installed MWh⁽¹⁾	Gross margin per installed MWh⁽¹⁾
Western Canada		7,311	11,538	295	106	189	25.57	9.19	16.38
Eastern Canada		818	1,868	83	44	39	44.43	23.55	20.88
International		3,481	5,110	281	136	145	54.99	26.61	28.38
		11,610	18,516	659	286	373	35.59	15.45	20.14


3 months ended Sept. 30, 2008	Production (GWh)	Installed (GWh)	Revenue	Fuel & purchased power	Gross margin	Revenue per installed MWh⁽¹⁾	Fuel & purchased power per installed MWh⁽¹⁾	Gross margin per installed MWh⁽¹⁾
Western Canada	7,839	11,531	316	132	184	27.40	11.45	15.96
Eastern Canada	801	1,808	117	84	33	64.71	46.46	18.25
International	3,717	5,172	337	177	160	65.16	34.22	30.94
	12,357	18,511	770	393	377	41.60	21.23	20.37


9 months ended Sept. 30, 2009	Production (GWh)	Installed (GWh)	Revenue	Fuel & purchased power	Gross margin	Revenue per installed MWh⁽¹⁾	Fuel & purchased power per installed MWh⁽¹⁾	Gross margin per installed MWh⁽¹⁾
Western Canada	22,227	34,230	841	316	525	24.57	9.23	15.34
Eastern Canada	2,701	5,543	294	171	123	53.04	30.85	22.19
International	8,511	15,165	835	413	422	55.06	27.23	27.83
	33,439	54,938	1,970	900	1,070	35.86	16.38	19.48


9 months ended Sept. 30, 2008	Production (GWh)	Installed (GWh)	Revenue	Fuel & purchased power	Gross margin	Revenue per installed MWh⁽¹⁾	Fuel & purchased power per installed MWh⁽¹⁾	Gross margin per installed MWh⁽¹⁾
Western Canada	24,522	34,347	1,012	391	621	29.46	11.38	18.08
Eastern Canada	2,416	5,386	381	274	107	70.74	50.87	19.87
International	9,297	15,507	828	430	398	53.40	27.73	25.67
	36,235	55,240	2,221	1,095	1,126	40.21	19.82	20.38

TRANSALTA CORPORATION / Q3 2009 11

¹Western Canada

Our Western Canada assets consist of coal and natural gas-fired plants, hydro facilities, and wind farms. Refer to page 36 of our 2008 Annual Report for further details on our Western operations.

The change in production for the three and nine months ended Sept. 30, 2009 is reconciled below:


	3 months ended Sept. 30	9 months ended Sept. 30
	(GWh)	(GWh)
Production, 2008	7,839	24,522
Lower hydro volumes	(156)	(348)
Higher planned outages at Alberta Thermal	(78)	(1,278)
Lower (higher) unplanned outages at Alberta Thermal	35	(259)
No planned outage at Genesee 3 in 2009	-	145
Lower PPA customer demand	(292)	(536)
Other	(37)	(19)
Production, 2009	7,311	22,227

The change in gross margin for the three and nine months ended Sept. 30, 2009 is reconciled below:


	3 months ended Sept. 30	9 months ended Sept. 30
Gross margin, 2008	184	621
Higher planned outages at Alberta Thermal	(5)	(99)
Lower hydro volumes and prices	(14)	(32)
Lower (higher) unplanned outages at Alberta Thermal	2	(11)
No planned outage at Genesee 3 in 2009	-	12
Adjustment to prior period indices	14	14
Mark-to-market movements	(2)	3
Higher coal costs	-	(8)
Lower penalties due to lower spot prices	11	11
Other	(1)	14
Gross margin, 2009	189	525

Indices, based upon changes in regional costs, are used in determining several components of revenue earned under the Alberta PPAs. In 2009, the indices used in these calculations during 2002 through to 2008 were revised, resulting in an increase in the revenue earned under the PPAs.

Eastern Canada

Our Eastern Canada assets consist of four natural gas-fired facilities and one wind farm. Refer to page 37 of our 2008 Annual Report for further details on our Eastern operations.

Production for the three months ended Sept. 30, 2009 increased 17 GWh primarily due to the commissioning of Kent Hills and higher market heat rates at Sarnia, partially offset by higher planned outages at the Mississauga and Windsor facilities.

12 TRANSALTA CORPORATION / Q3 2009

Production for the nine months ended Sept. 30, 2009 increased 285 GWh primarily due to the commissioning of Kent Hills and higher market heat rates at Sarnia.

For the three months ended Sept. 30, 2009, gross margin increased $6 million due to the commissioning of Kent Hills and the new agreement with the OPA at our Sarnia regional cogeneration power plant, partially offset by higher planned outages at the Mississauga and Windsor facilities.

Gross margin for the nine months ended Sept. 30, 2009 increased $16 million due to the commissioning of Kent Hills and the new agreements with the OPA at our Sarnia regional cogeneration power plant.

International

Our International assets consist of natural gas, coal, hydro, and geothermal assets in various locations in the United States and natural gas assets in Australia. Refer to page 37 of our 2008 Annual Report for further details on our International operations.

The change in production for the three and nine months ended Sept. 30, 2009 is reconciled below:


	3 months ended Sept. 30	9 months ended Sept. 30
	(GWh)	(GWh)
Production, 2008	3,717	9,297
Lower planned outages at Centralia Thermal	-	613
(Higher) lower unplanned outages at Centralia Thermal	(165)	107
Economic dispatching at Centralia Thermal	(24)	(1,331)
Expiration of Saranac contract	(199)	(199)
Higher production at Centralia Gas	130	2
Other	22	22
Production, 2009	3,481	8,511

The change in gross margin for the three and nine months ended Sept. 30, 2009 is reconciled below:


	3 months ended Sept. 30	9 months ended Sept. 30
Gross margin, 2008	160	398
Lower production at Centralia Thermal	(6)	(5)
Favourable pricing	8	30
Favourable foreign exchange	7	49
Higher coal costs	(4)	(17)
Mark-to-market movements	(3)	11
Favourable commercial settlements in 2008	-	(14)
Expiration of Saranac contract	(17)	(17)
Other	-	(13)
Gross margin, 2009	145	422

The mark-to-market movements primarily relate to contracts that did not qualify for hedge accounting in 2008 due to the expected reduced production at Centralia Thermal during the boiler modification work planned for 2009.

The PPA between our Saranac facility and New York State Electric and Gas expired in June 2009. The facility now operates under a combined capacity and merchant dispatch contract. As the facility is depreciated on a unit of production basis, there is a corresponding $5 million decrease in depreciation expense from this lower level of production. Further, as a portion of the facility is owned by a third party, there is also a decrease in earnings attributable to non-controlling interests. Therefore, the net pre-tax earnings impact of this event is approximately $4 million.

TRANSALTA CORPORATION / Q3 2009 13

Operations, Maintenance and Administration Expense

OM&A costs for the three months ended Sept. 30, 2009 decreased primarily due to targeted cost savings.

Depreciation Expense

The change in depreciation expense for the three and nine months ended Sept. 30, 2009 is reconciled below:


	3 months ended Sept. 30	9 months ended Sept. 30
Depreciation and amortization expense, 2008	102	298
Increased asset base	5	9
Unfavourable foreign exchange	2	15
Asset retirements	3	9
Expiration of Saranac PPA	(5)	(5)
Acceleration depreciation at Centralia Thermal in 2008	(1)	(11)
Other	-	15
Depreciation and amortization expense, 2009	106	330

COMMERCIAL OPERATIONS & DEVELOPMENT (“COD”): Derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives. Achieving gross margins while remaining within Value at Risk (“VaR”) limits is a key measure of COD’s trading activities.

COD is responsible for the management of commercial activities for our current generating assets. COD also manages available generating capacity as well as the fuel and transmission needs of the Generation business by utilizing contracts of various durations for the forward sales of electricity and for the purchase of natural gas, coal, and transmission capacity. Further, COD is responsible for developing or acquiring new cogeneration, wind, geothermal, and hydro generating assets and recommending portfolio optimization opportunities. The results of all of these activities are included in the Generation segment.

For a more in-depth discussion of our Energy Trading activities, refer to page 38 of our 2008 Annual Report.

The results of the COD segment are as follows:


	3 months ended Sept. 30		9 months ended Sept. 30
	2009	2008	2009	2008
Gross margin	7	21	37	81
Operations, maintenance and administration	9	17	25	37
Depreciation and amortization	1	1	2	2
Intersegment cost allocation	(8)	(7)	(24)	(22)
Operating expenses	2	11	3	17
Operating income	5	10	34	64

14 TRANSALTA CORPORATION / Q3 2009

OM&A costs for the three months and nine months ended Sept. 30, 2009 decreased compared to the same period in 2008 due to a reduction in both discretionary expenditures and staff compensation costs.

The inter-segment cost allocations are comparable with prior periods.

NET INTEREST EXPENSE

The components of interest expense are shown below:


	3 months ended Sept. 30		9 months ended Sept. 30
	2009	2008	2009	2008
Interest on long-term debt	46	45	132	129
Interest income	(3)	(6)	(6)	(15)
Capitalized interest	(10)	(6)	(27)	(13)
Other	3	-	3	-
Net interest expense	36	33	102	101

The change in net interest expense for the three months and nine months ended Sept. 30, 2009, compared to the same period in 2008 is shown below:


	3 months ended Sept. 30	9 months ended Sept. 30
Net interest expense, 2008	33	101
Higher long-term debt levels	4	8
Lower interest rates	(4)	(12)
Lower interest income	3	9
Higher capitalized interest	(4)	(14)
Unfavourable foreign exchange and other	4	10
Net interest expense, 2009	36	102

NON-CONTROLLING INTERESTS

The earnings attributable to non-controlling interests for the three and nine months ended Sept. 30, 2009 decreased $12 million and $11 million, respectively, due to lower earnings at CE Generation, LLC (“CE Gen”) as a result of the expiration of the Saranac contract and lower earnings at TransAlta Cogeneration, L.P. (“TA Cogen”).

TRANSALTA CORPORATION / Q3 2009 15

INCOME TAXES


	3 months ended Sept. 30		9 months ended Sept. 30
	2009	2008	2009	2008
Earnings before income taxes	82	72	102	170
Equity loss	-	-	-	97
Other income	-	-	(7)	(5)
Earnings before income taxes, equity loss, and other income	82	72	95	262
Income tax expense	16	11	-	29
Income tax expense on other income	-	-	(1)	(1)
Income tax expense on writedown of equity investment	-	-	-	28
Income tax expense excluding equity loss and other income	16	11	(1)	56
Effective tax rate on earnings before income taxes, equity loss, and other income (%)	20	15	(1)	21

Income tax expense increased for the three months ended Sept. 30, 2009 compared to the same period in 2008 due to higher pre-tax earnings. For the nine months ended Sept. 30, 2009 income tax expense decreased compared to the same period in 2008 due to lower pre-tax earnings, partially offset by the tax recovery on the writedown of our Mexican investment in 2008.

The effective tax rate increased for the three months ended Sept. 30, 2009 and decreased for the nine months ended Sept. 30, 2009 compared to the same periods in 2008 primarily due to a change in pre-tax earnings and certain deductions that do not fluctuate with earnings.

16 TRANSALTA CORPORATION / Q3 2009

FINANCIAL POSITION

The following chart highlights significant changes in the Consolidated Balance Sheets from Dec. 31, 2008 to Sept. 30, 2009:


	Increase/
	(Decrease)	Primary factors explaining change
Cash and cash equivalents	36	Timing of operational payments primarily at CE Gen
Accounts receivable	(140)	Timing of customer receipts and lower revenues
Collateral paid	(11)	Collateral paid to counterparties associated with our obligations as a result of a change in forward prices
Inventory	40	Lower production and economic dispatching
Risk management assets (current and long-term)	(45)	Price movements
Property, plant, and equipment, net	217	Capital additions, partially offset by depreciation expense
Intangible assets	(52)	Amortization expense and strengthening of the Canadian dollar compared to the U.S. dollar
Other assets	28	Growth and productivity initiatives
Accounts payable and accrued liabilities	(209)	Timing of payments and lower operational and construction expenditures
Collateral received	83	Collateral collected from counterparties associated with their obligations as a result of a change in forward prices
Long-term debt (including current portion)	292	Issuance of long-term debt and increased draws on credit facilities, partially offset by foreign exchange and maturities
Risk management liabilities (current and long-term)	(150)	Price movements
Asset retirement obligation (including current portion)	(18)	Strengthening of the Canadian dollar compared to the U.S. dollar and costs settled
Deferred credits and other long-term liabilities	10	Timing of accrued benefits and deferred revenues
Net future income tax liabilities (including current portions)	50	Tax effect on the increase in net risk management assets
Non-controlling interests	15	Sale of portion of Kent Hills, partially offset by distributions in excess of earnings attributable to non-controlling interests

FINANCIAL INSTRUMENTS

Refer to Note 7 on page 84 of the 2008 Annual Report and the interim consolidated financial statements as at and for the nine months ended Sept. 30, 2009 for details on Financial Instruments. During the quarter, the net risk management asset position decreased as a result of decreases in future prices on contracts in our Generation segment. Refer to the ‘Risk Management’ section in the MD&A of our 2008 Annual Report outlining our risks and how we manage them. Our risk management profile and practices have not changed materially from Dec. 31, 2008.

In limited circumstances, Energy Trading may enter into commodity transactions involving non-standard features for which market observable data is not available. These are defined under GAAP as Level III financial instruments. Level III financial instruments are not traded in an active market and fair value is therefore developed using valuation models or upon internally developed assumptions or inputs. Our Level III fair values are determined using valuation techniques with inputs that are based on historical data such as unit availability, transmission congestion, or demand profiles. Fair values are validated on a quarterly basis by using reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in the notes to the financial statements. At Sept. 30, 2009, Level III financial instruments had a net carrying value of $4 million (Dec. 31, 2008 – nil).

TRANSALTA CORPORATION / Q3 2009 17

STATEMENTS OF CASH FLOWS

The following chart highlights significant changes in the Consolidated Statements of Cash Flows for the three months ended Sept. 30, 2009 and 2008:


3 months ended Sept. 30	2009	2008	Primary factors explaining change
Cash and cash equivalents, beginning of period	54	50
Provided by (used in):
Operating activities	194	202	Unfavourable changes in working capital of $11 million, partially offset by higher cash earnings of $3 million.

Investing activities	(270)	(292)	Decrease in capital spending of $37 million, partially offset by a decrease in collateral held of $15 million.

Financing activities	110	109	Decreased debt maturities of $108 million and decreased distributions to non-controlling interests of $18 million, partially offset by lower draws on credit facilities of $126 million.
Translation of foreign currency cash	(2)	(3)
Cash and cash equivalents, end of period	86	66

The following chart highlights significant changes in the Consolidated Statements of Cash Flows for the nine months ended Sept. 30, 2009 and 2008:


9 months ended Sept. 30	2009	2008	Primary factors explaining change
Cash and cash equivalents, beginning of period	50	51
Provided by (used in):
Operating activities	334	610	Decrease in cash earnings of $116 million and unfavourable changes in working capital of $160 million.

Investing activities	(562)	(626)	Collateral received from counterparties of $105 million, partially offset by a decrease in realized gains on financial instruments of $53 million.

Financing activities	266	31	Increased draws on credit facilities of $193 million, decreased long-term debt maturities of $220 million, and decreased share repurchases of $130 million, partially offset by lower debt issuances of $302 million.
Translation of foreign currency cash	(2)	-
Cash and cash equivalents, end of period	86	66

18 TRANSALTA CORPORATION / Q3 2009

LIQUIDITY AND CAPITAL RESOURCES

Details on our liquidity needs and capital resources can be found on page 46 of our 2008 Annual Report.

Our ability to generate adequate cash flow from operations, maintain our financial capacity and flexibility, and to provide for planned growth remains substantially unchanged since Dec. 31, 2008.

Debt

Recourse and non-recourse debt totalled $3.1 billion at Sept. 30, 2009 compared to $2.8 billion at Dec. 31, 2008. Amounts drawn on credit facilities increased in 2009 as a result of lower cash earnings and higher capital expenditures, partially offset by an increase in collateral received in 2009, which was used to repay credit facility balances. Total long-term debt increased from Dec. 31, 2008 primarily due to debt issued during the second quarter of 2009.

Credit Facilities

We have a total of $2.1 billion of committed credit facilities of which $1.1 billion is not drawn and is available as of Sept. 30, 2009, subject to customary borrowing conditions. At Sept. 30, 2009, credit utilized under these facilities is $1.0 billion, which is comprised of actual drawings of $744 million and of letters of credit of $296 million.

Beyond the cash flow generated by our business, our primary source for short-term liquidity requirements is from our $2.1 billion of committed credit facilities. These facilities are comprised of a $1.5 billion committed syndicated bank facility, which matures in 2012, with the remainder comprised of bilateral credit facilities which mature between 2010 and 2013. We anticipate renewing these facilities, based on reasonable commercial terms, prior to their maturities.

Share Capital

On Oct. 26, 2009, we had approximately 198 million common shares outstanding.

At Sept. 30, 2009, we had 1.5 million outstanding employee stock options with a weighted average exercise price of $26.45. For the three and nine months ended Sept. 30, 2009, no options were exercised.

Normal Course Issuer Bid Program

On May 6, 2009, we announced plans to renew our NCIB program until May 6, 2010. We received the approval from the Toronto Stock Exchange to purchase, for cancellation, up to 9.9 million of our common shares representing five per cent of our 198 million common shares issued and outstanding as at April 30, 2009. Any purchases undertaken will be made on the open market through the Toronto Stock Exchange at the market price of such shares at the time of acquisition.

For the three and nine months ended Sept. 30, 2009, no shares were purchased under the NCIB program.

Credit Risk Exposure

Credit risk exposure is the risk to our business associated with changes in creditworthiness of entities with which we have commercial exposures. Refer to page 55 of our 2008 Annual Report for further details on our credit risk management profile and practices.

TRANSALTA CORPORATION / Q3 2009 19

While we had no counterparty losses in the third quarter of 2009, we continue to keep a close watch on changes and trends in the market and the impact these changes could have on our trading business and hedging activities, and will take appropriate actions as required although no assurance can be given that we will always be successful.

We are exposed to minimal credit risk from our Alberta PPAs because under the terms of these arrangements, receivables are substantially all secured by letters of credit. Our credit risk management profile and practices have not changed materially since Dec. 31, 2008.

Guarantee Contracts

We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties including those related to potential environmental obligations, trading activities, hedging activities, and purchase obligations. At Sept. 30, 2009, we provided letters of credit totalling $296 million (Dec. 31, 2008 – $430 million) and cash collateral of $26 million (Dec. 31, 2008 – $37 million). The decrease in letters of credit and cash collateral is due primarily to lower forward electricity prices in the Pacific Northwest and reduced trading activity with exchanges. These letters of credit and cash collateral secure certain amounts included on our balance sheet under “Risk Management Liabilities” and “Asset Retirement Obligations”.

CLIMATE CHANGE AND THE ENVIRONMENT

In the third quarter of 2009, there were no significant changes to environmental legislation affecting power generation in Canada. The federal government continues to develop its greenhouse gas (“GHG”) regulatory framework with the goal of having regulations in place by 2010 for implementation in 2012. However, announcement of the details have been delayed pending, in part, developments of the parallel U.S. framework.

Development of new Canadian air pollutant requirements for sulphur dioxide, nitrogen oxide (“NOx”) and mercury continues through a stakeholder consultation process involving industry, provincial and federal governments, and environmental organizations. There is currently no defined date for the finalization and implementation of any recommendations.

On Oct. 14, 2009, the federal and provincial governments announced that Project Pioneer, our CCS project, has received committed funding of more than $750 million. This funding is provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative. The funding will support the undertaking of a Front End Engineering and Design (“FEED”) study that is expected to be complete in 2010.

Recent changes to environmental regulations may materially adversely affect us. As indicated under ‘‘Risk Factors’’ in the Annual Information Form, many of our activities and properties are subject to environmental requirements and changes in, or liabilities under, these requirements may materially adversely affect us. Since the date of the Annual Information Form, the state government of Washington has determined a target for our facilities in Centralia to reduce their GHG emissions by 50 per cent by 2025. Accomplishing this reduction will require some substantive change to generation technology, fuel or operation at those facilities prior to 2025. On Sept. 30, 2009, the United States Environmental Protection Agency proposed new regulations that would require additional permitting and possible controls or other reductions in GHGs from large industrial sources of carbon dioxide and other GHGs, including our facilities in Centralia. Due to the early stage of these regulatory programs, we cannot yet determine the impact from these programs if and when they become effective.

20 TRANSALTA CORPORATION / Q3 2009

In September 2009, after the conclusion of a mediation process, we agreed to enter into a voluntary agreement with the Washington State Department of Ecology that will result in lower limits of oxides or nitrogen emissions and installation of mercury controls in 2012 in advance of enforceable U.S. federal or state requirements at our facilities in Centralia. We do not believe the costs of these programs will be material. The draft settlement agreement has been circulated for public comment.

OUTLOOK

For 2009, we now anticipate comparable earnings per share to be below last year's comparable earnings per share due to the move of the Sundance 3 major maintenance outage to 2009, higher OM&A due to our accelerated major maintenance program, lower availability, and poor hydro conditions. The other significant factors that influence our results are discussed below and exclude the impact of acquiring Canadian Hydro unless otherwise specified.

Business Environment

Economic Environment

As a result of the ongoing economic environment, commodity prices continue to be low, and could result in lower input costs for us in the future. Although we have contracted the price of the majority of our inputs in the short-term, in the longer-term we may see the benefit of lower operating costs.

A number of financial and industrial counterparties have experienced credit rating downgrades and we expect the balance of 2009 will continue to be challenging for some of our counterparties. While we had no counterparty losses in the first three quarters of 2009, we continue to monitor counterparty credit risk and act in accordance with our established risk management policies. We do not anticipate any material change to our existing credit practices and continue to deal primarily with investment grade counterparties.

Our strong financial position, available committed lines of credit, and relatively low debt maturity profile allows us to be selective about when we go to the market for financing. We also see continued support in capital markets for other projects that meet our return requirements.

While we do expect our results from operations in 2009 to be impacted by the current economic environment, this impact is somewhat mitigated by the contracted production and prices through our PPAs and other long-term contracts.

Spot Power Prices

For the remainder of 2009, spot power prices are expected to remain lower than 2008 due to lower natural gas prices and continued weakened demand for electricity.

Environmental Legislation

The state of development of environmental regulations in both Canada and the U.S. remains fluid. Canada has expressed its plan to coordinate its regulatory framework in time and stringency with the U.S. In the U.S., it is not clear if climate change legislation will prevail or if instead regulation will be applied by the EPA. Each of these outcomes could create widely different results for the energy industry in the U.S., and indirectly for Canada's regulatory approach.

We continue to closely monitor the progress and risks associated with environmental legislation changes on our future operations.

TRANSALTA CORPORATION / Q3 2009 21

Operations

Canadian Hydro Acquisition

As noted in the Subsequent Events section of this MD&A, we completed the acquisition and payment for approximately 87 percent of the outstanding common shares of Canadian Hydro. Planning of integration activities has commenced and we expect that we will be able to fully integrate Canadian Hydro’s operations within a reasonable period of time.

Production, Availability, and Capacity

Generating capacity is expected to increase due to the uprate at Sundance Unit 5 in late 2009 and the completion of Blue Trail. Production and availability are expected to be higher in the fourth quarter due to lower planned and unplanned outages. Overall fleet availability for 2009 is expected to be between 86 and 87 per cent. The decrease in availability from the second quarter outlook is mainly due to the level of unplanned outages during the third quarter.

Commodity Hedging

Through the Alberta PPAs and our other long-term contracts, approximately 70 per cent of our capacity is contracted over the next 10 years. To provide further stability to future earnings, we enter into physical and financial contracts for periods of up to four years. Under this strategy, we target being up to 90 per cent contracted for the upcoming year, stepping down to 70 per cent in the fourth year. As at the end of the third quarter, more than 95 per cent of our 2009 remaining capacity and approximately 85 per cent of our 2010 capacity is contracted with the average contracted price in 2009 of $60-$65/MWh in Alberta and U.S.$50-$55/MWh in the Pacific Northwest.

We continue to closely monitor the risks associated with commodity price changes on our future operations and, where we consider appropriate, use various physical and financial instruments to hedge our assets and operations from such price risk.

Fuel Costs

Coal costs in Alberta are subject to increases related to mining such as increased overburden removal, inflation, and increases in commodity prices. Seasonal variations in coal costs at our Alberta mines are minimized through the application of standard costing. Although the risk of cost increases due to commodity prices is much lower, coal costs for the remainder of 2009, on a standard cost basis, are expected to remain flat compared to the prior year due to increased capital expenditures in 2008 being offset by cost savings and productivity initiatives in 2009.

Fuel at Centralia Thermal is purchased from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel for the remainder of 2009 is expected to increase between 10 and 15 per cent from the prior year due to rail and transportation contract escalations.

Our natural gas-fired facilities have minimal exposure to market fluctuations in energy commodity prices. Exposure to natural gas costs for facilities under long-term sales contracts are minimized to the extent possible through long-term natural gas purchase contracts. Merchant natural gas facilities are exposed to the changes in spark spreads because the majority of the natural gas is purchased and power is sold on a spot basis. The input costs that are purchased on a spot basis benefited from lower prices seen throughout the third quarter. We expect lower natural gas prices to continue for the remainder of 2009.

22 TRANSALTA CORPORATION / Q3 2009

Operations, Maintenance, and Administration Costs

OM&A costs per MWh of installed capacity fluctuate by quarter and are dependent on the timing and nature of maintenance activities. OM&A costs per installed MWh for the remainder of 2009 are expected to decrease as a result of lower planned maintenance activities, cost savings, and productivity initiatives. OM&A costs for the full year are expected to be $30-$40 million higher than last year due exclusively to higher major maintenance.

Energy Trading

Earnings from our COD segment are affected by prices in the market, the positions taken, and duration of those positions. We continuously monitor both the market and our exposure with the view to maximize earnings while still maintaining an acceptable risk profile. Our 2009 objective for Energy Trading is to contribute between $50 million and $70 million in gross margin.

Exposure to Fluctuations in Foreign Currencies

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. dollar and Australian dollar by offsetting foreign denominated assets with foreign denominated liabilities and foreign exchange contracts. We also have foreign-denominated currency expenses, including interest charges, which serve as a natural hedge for a portion of our foreign currency revenues. Any residual foreign exchange exposure in the current year is hedged with foreign exchange contracts.

Net Interest Expense

Net interest expense for the remainder of 2009 is expected to be higher compared to the prior year mainly due to higher debt balances and lower interest income. However, changes in interest rates and in the value of the Canadian dollar relative to the U.S. dollar will affect the amount of net interest expense incurred.

Liquidity and Capital Resources

If there is increased volatility in power and natural gas markets, or if market trading activities increase, there may be the need for additional liquidity. To mitigate this liquidity risk, we maintain and monitor $2.1 billion of committed credit facilities as well as monitor exposures to determine expected liquidity requirements.

Accounting Estimates

Although we do not expect significant changes in our accounting estimates as a result of the current economic environment, some fluctuation could be seen on the fair valuation of our risk management assets and liabilities due to large variation in future commodity prices and foreign exchange and interest rate forward curves. Any significant changes in forward prices and rates could result in material differences in the amount of unrealized gains or losses and risk management assets and liabilities recorded at each reporting date due to the fair valuation performed at that time. However, any such change in fair value will not impact cash flow as we will continue to receive our contracted prices associated with Generation asset contracts.

TRANSALTA CORPORATION / Q3 2009 23

Capital Expenditures

Projects and Growth

Our major projects are comprised of spending to sustain our current operations and for growth activities. Seven significant growth capital projects are currently in progress as outlined in the table below:


	Total Project		2009		Target
Project	Estimated spend	Incurred to date	Estimated spend	Incurred to date	completion date	Details

Keephills 3	988	648	235 - 255	172	Q2 2011	A 450 MW (225 MW net ownership interest) supercritical coal-fired plant and associated mine capital in a partnership with Capital Power Corporation
Blue Trail	115	102	85 - 90	76	Q4 2009	A 66 MW wind farm in southern Alberta
Sundance Unit 5 uprate	80	60	55 - 65	43	Q4 2009	A 53 MW efficiency uprate at our Sundance facility
Summerview 2	123	84	80 - 90	59	Q1 2010	A 66 MW expansion of our Summerview wind farm in southern Alberta
Keephills Unit 1 uprate	34	1	5 - 10	1	Q4 2011	A 23 MW efficiency uprate at our Keephills facility
Keephills Unit 2 uprate	34	1	5 - 10	1	Q4 2012	A 23 MW efficiency uprate at our Keephills facility
Ardenville	135	26	25 - 35	26	Q1 2011	A 69 MW wind farm in southern Alberta
Total growth	1,509	922	490 - 555	378

Our estimate of total costs for Keephills 3 has increased by $100 million due to a change in our original expectations of the labour required to complete the project.

Our estimate for the total cost of the Sundance Unit 5 uprate has increased by $5 million due to the reclassification of some costs out of planned maintenance to more accurately reflect the type of work being done.

24 TRANSALTA CORPORATION / Q3 2009

Sustaining Expenditures

For 2009, our estimate for total sustaining capital expenditures, net of any contributions received, is allocated among the following:


Category	Description	Expected cost	Incurred to date

Routine capital	Expenditures to maintain our existing generating capacity	130 - 150	99
Productivity capital	Projects to improve power production efficiency	40 - 45	37
Mining equipment and land purchases	Expenditures related to mining equipment and land	35 - 45	28
Centralia modifications	Capital project to allow for usage of third party supplied coal	20 - 25	19
Planned maintenance	Regularly scheduled major maintenance	115 - 125	99
Total sustaining expenditures		340 - 390	282

The expected cost for routine capital has increased and the expected cost for planned maintenance has decreased due to the reclassification of some costs to more accurately reflect the type of work that has been completed to date and expectations for the remainder of the year, as well as the overall savings in our capital programs.

Details of the 2009 planned maintenance program are outlined as follows:


	Coal	Gas and hydro	Expected cost	Incurred to date
	Coal	Gas and hydro	Expected cost	Incurred to date
Capitalized	80 - 85	35 - 40	115 - 125	99
Expensed	115 - 125	0 - 5	115 - 130	111
	195 - 210	35 - 45	230 - 255	210

	Coal lost	Gas and hydro lost	Total lost	Lost to date
GWh lost	3,250 - 3,300	200 - 250	3,450 - 3,550	3,375

The expected GWh to be lost have increased compared to previous estimates to more accurately reflect the actual results to date and expectations for the remainder of the year.

Financing

Financing for these capital expenditures is expected to be provided by cash flow from operating activities and from existing borrowing capacity. The funds required for committed growth and sustaining projects are not expected to be impacted by the current economic environment due to the highly contracted nature of our cash flows and amount of committed credit available at Sept. 30, 2009.

RELATED PARTY TRANSACTIONS

On Dec.16, 2006, predecessors of TransAlta Generation Partnership (“TAGP”), a firm owned by the Corporation and one of its subsidiaries, entered into an agreement with the partners of the Keephills 3 joint venture project to supply coal for the coal-fired plant. The joint venture project is held in a partnership owned by Keephills 3 Limited Partnership (“K3LP”), a wholly owned subsidiary of the Corporation, and Capital Power Corporation. TAGP will supply coal until the earlier of the permanent closure of the

TRANSALTA CORPORATION / Q3 2009 25

Keephills 3 facility or the early termination of the agreement by TAGP and the partners of the joint venture. As at Sept. 30, 2009, TAGP had received $48 million from K3LP for future coal deliveries. Commercial operation of the Keephills plant is scheduled to commence in the second quarter of 2011. Payments received prior to that date for future coal deliveries are recorded in deferred revenues and will be amortized into revenue over the life of the coal supply agreement when operations commence.

CE Gen has entered into contracts with related parties to provide administrative and maintenance services. The total value of these contracts are U.S.$3 million per year for the years ending Dec. 31, 2009 and 2010.

For the period November 2002 to November 2012, one of our subsidiaries, TA Cogen, entered into various transportation swap transactions with TAGP. TAGP operates and maintains TA Cogen's three combined-cycle power plants in Ontario and a plant in Fort Saskatchewan, Alberta. TAGP also provides management services to the Sheerness thermal plant, which is operated by Canadian Utilities Limited. The business purpose of these transportation swaps is to provide TA Cogen with the delivery of fixed price gas without being exposed to escalating costs of pipeline transportation for three of its plants over the period of the swap. The notional gas volume in the swap transactions is equal to the total delivered fuel for each of the facilities. Exchange amounts are based on the market value of the contract. We entered into an offsetting contract and therefore have no risk other than counterparty risk.

CURRENT ACCOUNTING CHANGES

Financial Instruments – Recognition and Measurement

On June 17, 2009, the Accounting Standards Board of Canada (“AcSB”) released Embedded Derivatives on Reclassification of Financial Assets, amending Section 3855, Financial Instruments – Recognition and Measurement. The amendment indicates that contracts with embedded derivatives cannot be reclassified out of the held for trading category if the embedded derivative cannot be fair valued. The implementation of this standard did not have a material impact upon our consolidated financial statements.

Credit Risk

On Jan. 1, 2009, we adopted the Emerging Issues Committee (“EIC”) Abstract 173 Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. Under EIC–173, an entity’s own credit risk and the credit risk of the counterparty should be taken into account in determining the fair value of financial assets and liabilities, including derivative instruments. The implementation of this standard did not have a material impact upon our consolidated financial statements.

Deferral of Costs and Internally Developed Intangibles

On Jan. 1, 2009, we adopted Handbook Section 3064, Goodwill and Intangible Assets, replacing Section 3062, Goodwill and Other Intangible Assets, and Section 3450, Research and Development Costs. Section 3064 further defines that an internally developed intangible asset must demonstrate technical feasibility, an intention for use or sale, the generation of future economic benefits, and adequate access to resources to complete the development of the intangible asset in order to be able to capitalize associated costs. The implementation of this standard did not have a material impact upon our consolidated financial statements.

Mining Exploration Costs

On Jan. 1, 2009, we adopted EIC–174, Mining Exploration Costs. EIC–174 provides guidance on the capitalization of mining exploration costs, particularly when mining reserves have not been proven. The EIC also defines when an impairment test should be performed on previously capitalized costs. The implementation of this standard did not have a material impact upon our consolidated financial statements.

26 TRANSALTA CORPORATION / Q3 2009

FUTURE ACCOUNTING CHANGES

Financial Instruments Disclosures

On July 29, 2009, the AcSB released Impairment of Financial Assets amending Section 3855, Financial Instruments – Recognition and Measurement. The amendments changed the categories into which debt instruments could be classified and the impairment requirements for certain financial assets. Consequential amendments to Section 3025, Impaired Loans, were made to incorporate these changes. This standard will be effective for us for the annual period ending Dec. 31, 2009 and its adoption is not anticipated to have a material impact upon the consolidated financial statements.

In June 2009, the AcSB amended Section 3862, Financial Instruments – Disclosures, to converge with Improving Disclosures about Financial Instruments (Amendments to International Financial Reporting Standard (IFRS 7). The amendments expand the disclosures required in respect of recognized fair value measurements and clarify existing principles for disclosures about the liquidity risk associated with financial instruments. This standard will be effective for us for the annual period ending Dec. 31, 2009. It is not anticipated that the impacts of adopting this standard will be significant, as many of the expanded disclosure requirements are already provided as part of our existing financial instrument disclosures.

International Financial Reporting Standards (“IFRS”) Convergence

On May 8, 2009, the AcSB re-confirmed that IFRS will be required for interim and annual financial statements commencing on Jan. 1, 2011, with appropriate comparative IFRS financial information for 2010. The project to convert to IFRS consists of four phases: diagnostic, design and planning, solution development, and implementation. The design and planning stage consists of cross-functional, issue-specific teams analyzing further the key areas of convergence, and along with Information Technology and Internal Control resources, determining process, system, and financial reporting controls changes required to effect dual reporting in 2010 and full convergence in 2011. The design and planning stage is essentially complete and the cross-functional teams are focusing on solution development activities. Staff training programs are underway and an internal communication plan is in place and is being carried out.

A steering committee monitors the progress and critical decisions in the transition to IFRS and continues to meet regularly. This committee includes representatives from Finance, Information Technology, Treasury, Investor Relations, Human Resources, and Operations. Quarterly updates are provided to the Audit and Risk Committee.

Based on work to-date, our view is that while IFRS uses a conceptual framework similar to Canadian GAAP and that while there are many similarities between Canadian GAAP and IFRS, there are several significant differences in accounting policies that must be addressed. The major differences for us will likely arise in respect of property, plant, and equipment, the impairment of long-lived assets, accounting for joint ventures, and accounting for long-term contracts. In addition, there is significantly more disclosure required, which is not anticipated to have a material impact upon our consolidated financial statements. We continue to carefully evaluate the transitional options available under IFRS at the adoption date, the most appropriate long-term accounting policies, and the impacts of the differences identified.

The International Accounting Standards Board (“IASB”) is currently undertaking several IFRS projects which will likely result in significant changes to existing IFRS standards in areas such as financial statement presentation, leases, revenue recognition, post-employment benefits, taxes, and financial instruments. At this time, it is not anticipated that any material new standards or amendments relating to these projects will be effective on convergence in 2011. However, the progress and recommendations of these IASB projects are being monitored closely to ensure that any potential adverse impacts to the convergence project can be minimized. Accordingly, the full impact of adopting IFRS on our future financial position and future results cannot reasonably be determined at this time.

TRANSALTA CORPORATION / Q3 2009 27

NON-GAAP MEASURES

We evaluate our performance and the performance of our 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 operating activities, as determined in accordance with GAAP, as an indicator of our 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 and gross margin provides management and investors with a measurement of operating performance which is readily comparable from period to period.

Net Earnings Reconciliation

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


	3 months ended Sept. 30		9 months ended Sept. 30
	2009	2008	2009	2008
Revenues	666	791	2,007	2,302
Fuel and purchased power	(286)	(393)	(900)	(1,095)
Gross margin	380	398	1,107	1,207
Operations, maintenance, and administration	144	161	525	474
Depreciation and amortization	111	108	346	312
Taxes, other than income taxes	5	5	17	15
Operating expenses	260	274	888	801
Operating income	120	124	219	406
Foreign exchange gain (loss)	1	(4)	4	(5)
Net interest expense	(36)	(33)	(102)	(101)
Equity loss	-	-	-	(97)
Other income	-	-	8	5
Earnings before non-controlling interests and income taxes	85	87	129	208
Non-controlling interests	3	15	27	38
Earnings before income taxes	82	72	102	170
Income tax expense	16	11	-	29
Net earnings	66	61	102	141

Earnings on a Comparable Basis

Presenting earnings on a comparable basis from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Earnings on a comparable basis are based on earnings per share and are additive quarter over quarter.

28 TRANSALTA CORPORATION / Q3 2009

In calculating comparable earnings for 2009, we have excluded the settlement of an outstanding commercial issue that has been recorded in other income as this was related to our previously held Mexican investment.

The change in life of certain component parts at Centralia Thermal was excluded from the calculation of comparable earnings in 2009 and 2008 as it relates to the cessation of mining activities at the Centralia coal mine and conversion to consuming solely third party supplied coal.

In calculating comparable earnings for 2008, we have also excluded the writedown of our Mexican investment. We also excluded the gains recorded on the sale of assets at the previously operated Centralia coal mine as we do not normally dispose of large quantities of fixed assets.


	3 months ended Sept. 30		9 months ended Sept. 30
	2009	2008	2009	2008
Net earnings	66	61	102	141
Sale of assets at Centralia, net of tax	-	-	-	(4)
Change in life of Centralia parts, net of tax	-	1	1	8
Settlement of commercial issue, net of tax	-	-	(6)	-
Writedown of Mexican investment, net of tax	-	-	-	65
Earnings on a comparable basis	66	62	97	210

Weighted average common shares outstanding in the period	198	198	198	199
Earnings on a comparable basis per share	0.34	0.32	0.49	1.06

Free Cash Flow (Deficiency)

Free cash flow is intended to demonstrate the amount of cash we have available to invest in capital growth initiatives, repay recourse debt, pay common share dividends, or repurchase common shares.

Sustaining capital expenditures for the three months ended Sept. 30, 2009, represents total additions to property, plant, and equipment per the Consolidated Statements of Cash Flow less $154 million ($153 million net of joint venture contributions) that we have invested in growth projects. For the same period in 2008, we invested $213 million ($209 million net of joint venture contributions) in growth projects. For the nine months ended Sept. 30, 2009 and 2008, we invested $387 million ($378 million net of joint venture contributions) and $416 million ($401 million net of joint venture contributions), respectively, in growth projects.

TRANSALTA CORPORATION / Q3 2009 29

The reconciliation between cash flow from operating activities and free cash flow is calculated below:


	3 months ended Sept. 30		9 months ended Sept. 30
	2009	2008	2009	2008
Cash flow from operating activities	194	202	334	610
Add (Deduct):
Sustaining capital expenditures	(116)	(97)	(294)	(294)
Dividends on common shares	(58)	(58)	(169)	(163)
Distribution to subsidiaries' non-controlling interest	(7)	(25)	(40)	(69)
Non-recourse debt repayments	(1)	(1)	(19)	(3)
Timing of contractually scheduled PPA payments	-	-	-	(116)
Other income	-	-	(8)	-
Cash flows from equity investments	-	(1)	-	2
Free cash flow (deficiency)	12	20	(196)	(33)

We seek to maintain sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to our business.

SELECTED QUARTERLY INFORMATION


	Q4 2008	Q1 2009	Q2 2009	Q3 2009

Revenue	808	756	585	666
Net earnings (loss)	94	42	(6)	66
Basic and diluted earnings (loss) per common share	0.47	0.21	(0.03)	0.34
Comparable earnings (loss) per share	0.40	0.18	(0.03)	0.34

	Q4 2007	Q1 2008	Q2 2008	Q3 2008

Revenue	783	803	708	791
Net earnings	130	33	47	61
Basic and diluted earnings per common share	0.64	0.17	0.24	0.31
Comparable earnings (loss) per share	0.51	0.50	0.25	0.32

CONTROLS AND PROCEDURES

As required by Rule 13a-15 under the Securities Exchange Act of 1934 (“Exchange Act”), management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act are recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act are accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management was required to apply its judgment in evaluating and implementing possible controls and procedures. There has been no change in the internal control over financial reporting during the period

30 TRANSALTA CORPORATION / Q3 2009

covered by this report that has materially affected, or is reasonably likely to materially affect, the Corporation’s internal control over financial reporting. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of Sept. 30, 2009, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

FORWARD-LOOKING STATEMENTS

This document, documents incorporated herein by reference, and other reports and filings made with the securities regulatory authorities, include forward-looking statements. All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may", "will", "believe", "expect", "anticipate", "intend", "plan", "foresee", "potential", "enable", "continue" or other comparable terminology. These statements are not guarantees of our future performance and are subject to risks, uncertainties and other important factors that could cause TransAlta's actual performance to be materially different from those projected.

Factors that may adversely impact our forward-looking statements include risks relating to: (i) fluctuations in market prices and availability of fuel supplies required to generate electricity and in the price of electricity; (ii) the regulatory and political environments in the jurisdictions in which we operate; (iii) environmental requirements and changes in, or liabilities under, these requirements; (iv) changes in general economic conditions including interest rates; (v) operational risks involving our facilities, including unplanned outages at such facilities; (vi) disruptions in the transmission and distribution of electricity; (vii) disruptions in the source of fuels or water required to operate our facilities; (viii) trading risks; (ix) fluctuations in the value of foreign currencies and foreign political risks; (x) need for additional financing; (xi) liquidity risk; (xii) structural subordination of securities; (xiii) counterparty credit risk; (xiv) insurance risk; (xv) our provision for income taxes; (xvi) legal proceedings involving us; (xvii) reliance on key personnel; (xviii) labour relations matters; and (xix) absence of a public market for certain of the securities offered. The foregoing risk factors, among others, are described in further detail under the heading "Risk Factors" on page 22 of our 2008 Annual Information Form and on page 53 of our 2008 Annual Report.

Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties and assumptions, the forward-looking events might or might not occur. We cannot assure you that projected results or events will be achieved.

TRANSALTA CORPORATION / Q3 2009 31

SUPPLEMENTAL INFORMATION


		Sept. 30, 2009	Dec. 31, 2008
Closing market price (TSX) ($)		21.84	24.30
Price range for the last 12 months (TSX) ($)	High	29.83	37.50
	Low	18.11	21.00
Debt to invested capital including non recourse debt (%)		50.1	48.1
Debt to invested capital excluding non recourse debt (%)		48.2	45.6
Return on shareholders' equity (%)		8.2	9.4
Comparable return on shareholders' equity^{(1), (2)} (%)		7.4	11.6
Return on capital employed⁽¹⁾(%)		6.0	7.7
Comparable return on capital employed^{(1), (2)}(%)		6.0	9.6
Cash dividends per share⁽¹⁾ ($)		1.14	1.08
Price/earnings ratio¹ (times)		22.1	20.6
Earnings coverage¹ (times)		2.1	2.8
Dividend payout ratio based on net earnings⁽¹⁾ (%)		115.3	91.5
Dividend payout ratio based on comparable earnings^{(1), (2)}(%)		127.7	74.1
Dividend coverage⁽¹⁾ (times)		3.4	4.8
Dividend yield⁽¹⁾ (%)		5.2	4.4
Cash flow to debt⁽¹⁾ (%)		23.6	31.1
Cash flow to interest coverage⁽¹⁾ (times)		5.8	7.2

(1) Last 12 months

(2) These ratios incorporate items that are not defined under Canadian GAAP. None of these measurements are used to enhance the Corporation’s reported financial performance or position. These ratios are useful complementary measurements for assessing the Corporation’s financial performance, efficiency, and liquidity and are common in the reports of other companies but may differ by definition and application.

RATIO FORMULAS

Debt to invested capital = (long-term debt – cash and cash equivalents) / (debt + non-controlling interests + shareholders’ equity – cash and cash equivalents)

Return on shareholders’ equity = net earnings or comparable earnings / average shareholders’ equity excluding Accumulated Other Comprehensive Income (“AOCI”)

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

Comparable return on capital employed = (comparable earnings before non-controlling interests and income taxes + net interest expense) / average invested capital excluding AOCI

Price/earnings ratio = current period’s close / basic earnings per share

Earnings coverage = (net earnings + income taxes + net interest expense) / (net interest expense plus capitalized interest)

Dividend payout ratio = dividends / net earnings or comparable earnings

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

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

Cash flow to debt = cash flow from operating activities before changes in working capital / average total debt

Cash flow to interest coverage = (cash flow from operating activities before changes in working capital + net interest expense) / (net interest expense plus capitalized interest)

32 TRANSALTA CORPORATION / Q3 2009

GLOSSARY OF KEY TERMS

Alberta Power Purchase Agreement (PPA) - A long-term arrangement established by regulation for the sale of electric energy from formerly regulated generating units to PPA Buyers.

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, regardless of whether or not it is actually generating electricity.

British thermal unit (Btu) - 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.

Carbon Capture and Storage (CCS) - An approach to mitigating the contribution of greenhouse gas emissions to global warming, which is based on capturing carbon dioxide emissions from industrial operations and permanently storing them in deep underground formations.

Cogeneration - A generating facility that produces electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, heating or cooling purposes.

Derate - To lower the rated electrical capability of a power generating facility or unit.

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.

Greenhouse Gas (GHG) – Gases having potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons and perfluorocarbons.

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

Megawatt (MW) - 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 natural gas).

Unplanned Outage - The shutdown of a generating unit due to an unanticipated breakdown.

Uprate - To increase the rated electrical capability of a power generating facility or unit.

Value at Risk (VaR) - A measure to manage earnings exposure from trading activities.

TRANSALTA CORPORATION / Q3 2009 33

TransAlta Corporation

Box 1900, Station “M”

110 - 12th Avenue S.W.

Calgary, Alberta Canada T2P 2M1

Phone

403.267.7110

Website

www.transalta.com

CIBC Mellon Trust Company

P.O. Box 7010 Adelaide Street Station

Toronto, Ontario Canada M5C 2W9

Phone

Toll-free in North America: 1.800.387.0825

Toronto or outside North America: 416.643.5500

Fax

416.643.5501

Website

www.cibcmellon.com

FOR MORE INFORMATION

Media inquiries

Michael Lawrence

Manager, External Relations

Phone

403.267.7330

E-mail

media_relations@transalta.com

Investor inquiries

Jennifer Pierce, MA, MBA

Vice-President, Communications and Investor Relations

Phone

1.800.387.3598 in Canada and United States

or 403.267.2520

Fax

403.267.2590

E-mail

investor_relations@transalta.com

34 TRANSALTA CORPORATION / Q3 2009