MD - Filed by Filing Services Canada Inc. (403) 717-3898

EX-13.2 3 mda.htm MANAGEMENT DISCUSSION & ANALYSIS - SEPTEMBER 30, 2011 MD - Filed by Filing Services Canada Inc. (403) 717-3898

TRANSALTA CORPORATION

THIRD QUARTER REPORT FOR 2011

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 the Forward Looking Statements section of this MD&A for additional information.

In this MD&A, unless the context otherwise requires, ‘we’, ‘our’, ‘us’, the ‘Corporation’ and ‘TransAlta’ refers to TransAlta Corporation and its subsidiaries. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. This MD&A is dated Oct. 27, 2011. Additional information respecting TransAlta, including its Annual Information Form, is available on SEDAR at www.sedar.com.

BASIS OF PRESENTATION AND TRANSITION TO IFRS

On Jan. 1, 2011, we adopted International Financial Reporting Standards (“IFRS”) for Canadian publicly accountable enterprises. Prior to the adoption of IFRS, we followed Canadian Generally Accepted Accounting Principles (“Canadian GAAP” or “our previous GAAP”). While IFRS has many similarities to Canadian GAAP, some of our accounting policies have changed as a result of our transition to IFRS. The most significant accounting policy changes that have had an impact on the results of our operations are discussed within the applicable sections of this MD&A, and in more detail in the Accounting Changes section of this MD&A.

This MD&A should be read in conjunction with the unaudited interim condensed consolidated financial statements of the Corporation as at and for the three and nine months ended Sept. 30, 2011, which have been prepared using IFRS, and should also be read in conjunction with the audited consolidated financial statements, which were prepared using Canadian GAAP, and the MD&A, contained within our 2010 Annual Report. All comparative figures have been restated using IFRS, unless otherwise noted.

TRANSALTA CORPORATION / Q3 2011 1

RESULTS OF OPERATIONS

The results of operations are presented on a consolidated basis and by business segment. We have three business segments: Generation, Energy Trading, and Corporate. In this MD&A, the impact of foreign exchange fluctuations on foreign currency denominated transactions and balances is discussed with the relevant Condensed Consolidated Statements of Earnings and Condensed Consolidated Statements of Financial Position items. While individual line items in the Condensed Consolidated Statements of Financial Position may be impacted by foreign exchange fluctuations, the net impact of the translation of these items relating to foreign operations to our presentation currency is reflected in Accumulated Other Comprehensive Income (“AOCI”) in the equity section of the Condensed Consolidated Statements of Financial Position.

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


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Availability (%)⁽¹⁾	83.9	91.0	83.7	88.1
Production (GWh)⁽¹⁾	10,368	12,742	29,350	35,857
Revenues	629	651	1,962	1,894
Gross margin⁽²⁾	371	336	1,307	1,037
Operating income⁽²⁾	111	85	537	288
Net earnings attributable to common shareholders	50	40	266	163
Net earnings per share attributable to common shareholders, basic and diluted	0.22	0.18	1.20	0.74
Comparable earnings per share⁽²⁾	0.27	0.18	0.91	0.60
Comparable EBITDA⁽²⁾	246	217	804	660
Funds from operations⁽²⁾	168	175	620	571
Funds from operations per share⁽²⁾	0.75	0.80	2.79	2.60
Cash flow from operating activities	221	224	512	521
Free cash (deficiency) flow⁽²⁾	(7)	26	172	116
Dividends paid per common share	0.29	0.29	0.87	0.87


As at	Sept. 30, 2011	Dec. 31, 2010
Total assets	9,709	9,635
Total long-term liabilities	5,149	5,009

¹²

AVAILABILITY & PRODUCTION

Availability for the three months ended Sept. 30, 2011 decreased compared to the same period in 2010 primarily due to higher planned and unplanned outages at Centralia Thermal, higher planned and unplanned outages at the Alberta coal Power Purchase Arrangement (“PPA”) facilities, and higher planned and unplanned outages at natural gas-fired facilities.

(1) Production and availability includes all generating assets (generation operations, finance lease, and equity investments).

(2) Gross margin, operating income, comparable earnings per share, comparable earnings before interest, taxes, depreciation, and amortization (“EBITDA”), funds from operations, funds from operations per share, and free cash (deficiency) flow are not defined under IFRS. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders and cash flow from operating activities.

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Availability for the nine months ended Sept. 30, 2011 decreased compared to the same period in 2010 primarily due to higher planned and unplanned outages at Centralia Thermal partially offset by lower planned and unplanned outages at the Alberta coal PPA facilities.

Production for the three months ended Sept. 30, 2011 decreased 2,374 gigawatt hours (“GWh”) compared to the same period in 2010 due to the shut down at Sundance Units 1 and 2⁽¹⁾, higher planned and unplanned outages at the Alberta coal PPA facilities, higher planned and unplanned outages at Centralia Thermal, and lower production at natural gas-fired facilities, being partially offset by the commencement of commercial operations of Keephills Unit 3, lower economic dispatching at Centralia Thermal, and higher hydro volumes.

Production for the nine months ended Sept. 30, 2011 decreased 6,507 GWh compared to the same period in 2010 due to the shut down at Sundance Units 1 and 2⁽¹⁾, higher economic dispatching at Centralia Thermal, higher planned and unplanned outages at Centralia Thermal, the sale of the Meridian facility, and the decommissioning of Wabamun, partially offset by lower planned and unplanned outages at the Alberta coal PPA facilities, higher wind volumes, higher hydro volumes, and the commencement of commercial operations of Keephills Unit 3.

The outages at Centralia Thermal did not negatively impact our gross margins for the three and nine months ended Sept. 30, 2011 as we were able to extend our planned and unplanned outages to take advantage of lower market prices to purchase power on the market to fulfill our power contracts. Availability, after adjusting for the higher economic dispatching at Centralia, was 88.3 per cent and 88.2 per cent for the three and nine months ended Sept. 30, 2011, respectively.

NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

The primary factors contributing to the change in net earnings attributable to common shareholders for the three and nine months ended Sept. 30, 2011 are presented below:


	3 months ended Sept. 30	9 months ended Sept. 30
Net earnings attributable to common shareholders, 2010	40	163
(Decrease) increase in Generation gross margins	(2)	60
Mark-to-market movements - Generation	(5)	130
Increase in Energy Trading gross margins	42	80
Increase in operations, maintenance, and administrative costs	(19)	(19)
Decrease (increase) in depreciation expense	10	(2)
Increase in gain on sale of assets	-	3
Increase in asset impairment charges	(5)	(14)
Increase in net interest expense	(5)	(21)
Increase in equity income	3	8
Increase in income tax expense	(5)	(102)
Increase in net earnings attributable to non-controlling interests	(1)	(7)
Increase in preferred share dividends	(4)	(11)
Other	1	(2)
Net earnings attributable to common shareholders, 2011	50	266

(1) Refer to Sundance Units 1 and 2 shut down under the Significant Events section of this MD&A for further discussion.

TRANSALTA CORPORATION / Q3 2011 3

Generation gross margins, excluding the impact of mark-to-market movements, for the three months ended Sept. 30, 2011 increased compared to the same period in 2010 primarily due to higher hydro margins and the commencement of commercial operations of Keephills Unit 3, partially offset by the sale of the Meridian facility, lower recoveries from the Poplar Creek base plant which we no longer operate, and higher planned and unplanned outages at the Alberta coal PPA facilities. The lower recoveries at the Poplar Creek base plant are offset by lower operations, maintenance, and administration (“OM&A”) costs.

For the nine months ended Sept. 30, 2011, generation gross margins, excluding the impact of mark-to-market movements, increased compared to the same period in 2010 primarily due to higher hydro margins, lower planned and unplanned outages at the Alberta coal PPA facilities, favourable pricing, the commencement of commercial operations of Keephills Unit 3, and higher wind volumes, partially offset by lower recoveries from the Poplar Creek base plant which we no longer operate, the sale of the Meridian facility, and the decommissioning of Wabamun. The lower recoveries at Poplar Creek base plant are offset by lower OM&A costs.

Mark-to-market movements decreased for the three months ended Sept. 30, 2011 compared to the same period in 2010 because of certain hedges being deemed ineffective in 2011. The mark-to-market gains on the ineffective hedges were recognized in earnings during the first quarter at the time the hedges were deemed ineffective. If the hedges had not been deemed ineffective, the
mark-to-market gains would have been recognized in the third quarter.

Mark-to-market movements increased for the nine months ended Sept. 30, 2011 compared to the same period in 2010 due to the recognition of unrealized gains resulting from certain power hedging relationships being deemed ineffective and increased weakening in market prices in the Pacific Northwest relative to our hedged prices.

Energy Trading gross margins increased for the three months ended Sept. 30, 2011 compared to the same period in 2010 due to strong trading results in the Western regions. These results were partially offset by lower gross margins in the Pacific Northwest region resulting from weak pricing and reduced electricity demand.

For the nine months ended Sept. 30, 2011, Energy Trading gross margins increased compared to the same period in 2010 due to strong trading results in the Western regions during the second and third quarters and increased earnings from the acquisition of electricity and natural gas contracts. These positive results were partially offset by lower gross margins in the Pacific Northwest region resulting from weak pricing and reduced electricity demand.

OM&A costs for the three months ended Sept. 30, 2011 increased compared to the same periods in 2010 primarily due to higher compensation costs associated with strong results, costs associated with several productivity initiatives, and the write off of certain wind development costs, partially offset by lower costs associated with the discontinuation of managing the base plant at Poplar Creek.

For the nine months ended Sept. 30, 2011 OM&A costs increased compared to the same period in 2010 due to the write off of certain wind development costs and costs associated with several productivity initiatives, partially offset by lower costs associated with the discontinuation of managing the base plant at Poplar Creek.

Depreciation expense for the three months ended Sept. 30, 2011 decreased compared to the same period in 2010 primarily due to a current period adjustment to the Wabamun decommissioning and restoration provision and changes to estimated residual values.

For the nine months ended Sept. 30, 2011, depreciation expense increased compared to the same period in 2010 primarily due to an increased asset base, the writedown of capital spares, and the impact of the 2010 decrease in Wabamun decommissioning and restoration costs partially offset by changes to estimated residual values, the sale of the Meridian facility, and favourable foreign exchange rates.

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Asset impairment charges for the three and nine months ended Sept. 30, 2011 increased compared to the same period in 2010 due to the recognition of pre-tax impairment charges on assets within the renewables fleet in order to write these assets down to their fair values.

Net interest expense for the three and nine months ended Sept. 30, 2011 increased compared to the same periods in 2010 due to lower capitalized interest, lower interest income related to the resolution of certain tax matters in 2010, and higher interest rates.

Equity income for the three months ended Sept. 30, 2011 increased compared to the same period in 2010 primarily due to lower planned and unplanned outages.

For the nine months ended Sept. 30, 2011, equity income increased compared to the same period in 2010 primarily due to lower planned and unplanned outages and the realization of a gain on the sale of a property, partially offset by lower income tax recoveries and unfavourable foreign exchange rates.

The income tax expense for the three months ended Sept. 30, 2011 increased compared to the same period in 2010 due to higher pre-tax earnings in 2011.

For the nine months ended Sept. 30, 2011, income tax expense increased compared to the same period in 2010 due to higher
overall pre-tax earnings, including higher U.S. earnings on the recognition of unrealized gains resulting from ineffectiveness of hedging relationships, and an income tax recovery in 2010 related to the resolution of certain tax matters.

Net earnings attributable to non-controlling interests for the three and nine months ended Sept. 30, 2011 increased compared to the same period in 2010 due to higher earnings at TransAlta Cogeneration, L.P. (“TA Cogen”).

The preferred share dividends for the three and nine months ended Sept. 30, 2011 increased compared to the same periods in 2010 due to the issuance of preferred shares in the fourth quarter of 2010.

FUNDS FROM OPERATIONS AND FREE CASH (DEFICIENCY) FLOW

Funds from operations for the three months ended Sept. 30, 2011 decreased $7 million compared to the same period in 2010 primarily due to lower net earnings after adjusting for the impact of certain non-cash foreign exchange and risk management
mark-to-market gains.

For the nine months ended Sept. 30, 2011, funds from operations increased $49 million compared to the same period in 2010 primarily due to higher net earnings.

Free cash (deficiency) flow for the three months ended Sept. 30, 2011 decreased $33 million compared to the same period in 2010 due to the decrease in funds from operations, higher preferred share dividends, and higher sustaining capital expenditures partially offset by lower distributions to subsidiaries’ non-controlling interests.

For the nine months ended Sept. 30, 2011, free cash (deficiency) flow increased $56 million compared to the same period in 2010 due to the increase in funds from operations and lower common share dividends paid in cash as a result of the Dividend Reinvestment and Share Purchase (“DRASP”) Plan partially offset by higher sustaining capital expenditures and higher preferred share dividends.

TRANSALTA CORPORATION / Q3 2011 5

SIGNIFICANT EVENTS

Three months ended Sept. 30, 2011

Asset Impairment Charges

During the third quarter of 2011, we recognized a pre-tax impairment charge of $5 million related to two assets within the renewables fleet. The impairment resulted from operational factors that impacted the expected useful lives of the assets. The impairment loss is included in the Generation segment.

Keephills Unit 3

On Sept. 1, 2011, our 450 megawatt (“MW”) Keephills Unit 3 thermal facility, of which we have a 50 per cent ownership interest, began commercial operations. The total cost of the project is estimated to be $1.98 billion.

Sale of Grande Prairie Facility

On July 27, 2011, we signed an agreement to sell our interest in the biomass facility located in Grande Prairie. This deal closed on
Oct. 1, 2011.

President and Chief Executive Officer

On July 27, 2011, we announced that TransAlta’s President and Chief Executive Officer Steve Snyder will retire, effective Jan. 1, 2012. Dawn Farrell, TransAlta’s Chief Operating Officer, will succeed Mr. Snyder as President and Chief Executive Officer on Jan. 2, 2012.

Nine months ended Sept. 30, 2011

Sundance Unit 3 Outage

On June 7, 2010, we announced an outage at Unit 3 of our Sundance facility due to the mechanical failure of critical generator components. In response to this event, we gave notice of a High Impact Low Probability (“HILP”) event and claimed force majeure relief under the PPA. Since the event, we have recorded an after-tax charge of $16 million, or 50 per cent of the penalties, as calculated under the PPA, pending a resolution of this matter.

On Oct. 20, 2010, the Balancing Pool confirmed our determination that the mechanical failure met the requirements of a HILP event under the PPA. On July 5, 2011, the Balancing Pool purported to rescind its earlier determination. Neither action is a conclusive finding of a force majeure event, nor does either provide a definitive resolution to the dispute. Management continues to be of the view that the event constitutes both a HILP and force majeure and that they will be resolved in TransAlta’s favour. The arbitration hearing has been set for May 2012. Pending a resolution of this matter, we may be required to pay to the PPA Buyers the penalties as calculated under the PPA and record an additional $16 million charge to earnings. There is no additional impact to earnings at this time as the facility is operating at full capacity. The unit may be operated in that manner for as long as our monitoring indicates that it can be operated safely, subject to the terms of the agreement, market conditions and other operating requirements. The previously announced major maintenance at this facility remains scheduled for the middle of 2012.

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Bone Creek

On June 1, 2011, our 19 MW Bone Creek hydro facility began commercial operations. The total capital cost of the project was approximately $52 million.

Centralia Coal

On April 29, 2011, the Washington State Governor signed the TransAlta Energy Bill (the "Bill") into law. The Bill represents a collaborative agreement reached with the Governor's office, state legislators, and local environmental groups to establish a framework to transition from coal-fired energy produced at the Centralia Coal plant by 2025. The Memorandum of Agreement, which is part of the Bill, must be signed by the Governor no later than Jan. 1, 2012. We will continue to work with the State government and other impacted parties to successfully achieve and implement the transition plan.

The Bill, and associated Memorandum of Agreement, includes the following key elements:

One unit will be shut down by the end of 2020 and the other by the end of 2025, at which time the site will be restored to an industrial land use standard;

We will install Selective Non-Catalytic Reduction emission reduction technology before Jan. 1, 2013 and Washington State and the environmental community will advocate to the Environmental Protection Agency (“EPA”) that we be exempt from installing more expensive Selective Catalytic Reduction (“SCR”) technology. In the event the EPA imposes installation of SCRs at Centralia Coal, we are relieved of our obligations under the Bill;

We will commit to fund $55 million over the life of the facility to support economic development, promoting energy efficiency and developing energy technologies related to the improvement of the environment;

The Centralia coal plant is exempt from any Washington State imposed greenhouse gas (“GHG”) regulations;

We are no longer restricted to power contract terms of less than five years and Washington State Utilities that enter into contracts with Centralia Coal are permitted to earn a return on the contracts; and

Washington State will provide expedited permitting for a replacement natural gas fired generation facility, which would also be exempt from Washington State GHG regulations.

Sale of Meridian

On April 1, 2011, TA Cogen, a subsidiary that is owned 50.01 per cent by TransAlta, closed the sale of its 50 per cent interest in the Meridian facility. The sale was effective Jan. 1, 2011. As a result, we realized a pre-tax gain of $3 million during the second quarter.

Asset Impairment Charges

During the second quarter of 2011, we completed an impairment assessment based on fair value estimates derived from the long range forecast and prices evidenced in the market place. As a result, we recorded a pre-tax impairment charge of $9 million on an asset within the renewables fleet. This impairment is included in the Generation segment.

New Richmond

On March 28, 2011, we announced that we had received approval from the Government of Quebec to proceed with the construction of the 68 MW New Richmond wind project located on the Gaspé Peninsula. New Richmond is contracted under a 20-year Electricity Supply Agreement with Hydro-Québec Distribution. The cost of the project is estimated to be approximately $205 million and commercial operations are expected to commence during the fourth quarter of 2012.

TRANSALTA CORPORATION / Q3 2011 7

Sundance Units 1 and 2 Shut Down

In December 2010, Unit 1 and Unit 2 of our Sundance coal-fired generation facility were shut down due to conditions observed in the boilers at both units. As a result, all 560 MW from both units, with potential production of 1,236 GWh and 3,669 GWh, were unavailable for the three and nine months ended Sept. 30, 2011, respectively.

We are pursuing all our remedies under the PPA resulting from these events. Firstly, under the terms of the PPA for these units, we notified the PPA Buyer and the Balancing Pool of a force majeure event. To the extent the event meets the force majeure criteria set out in the PPA, we believe we are entitled to receive our PPA capacity payments and are protected from having to pay penalties for the units’ lack of availability and as a result, we do not expect any material adverse effect on our results or operations. Secondly, on Feb. 8, 2011, we issued a notice of termination for destruction on Sundance Units 1 and 2 under the terms of the PPA. This action was based on the determination that the physical state of the boilers was such that the units cannot be economically restored to service under the terms of the PPA. To the extent the event meets the termination for destruction criteria set out in the PPA, we believe we are entitled to recover the net book value specified in the PPA, and as a result, we do not expect any material financial impact.

On Feb. 18, 2011, the PPA Buyer provided notice that it intends to dispute the notice of force majeure and termination for destruction, and intends to pursue the dispute resolution process as set out under the terms of the PPA. The binding arbitration process to resolve the dispute is underway. The arbitration panel identified dates in March and April 2012 to hear these claims and unless timelines are shortened by agreement of the parties, indicated that its decision would be forthcoming in mid-2012.

Although no assurance can be given as to the timing or ultimate outcome of these matters, which could impact cash flows during the interim period, we believe that they will be resolved in our favour.

Change in Estimated Residual Values

During the first quarter of 2011, management completed a comprehensive review of the residual values of all of our generating assets, having regard for, among other things, expectations about the future condition of the assets, metal volumes, as well as other market-related factors. As a result, estimated residual values were revised resulting in depreciation decreasing by $4 million and $10 million for the three and nine months ended Sept. 30, 2011 compared to the same period in 2010. Depreciation for the year ended Dec. 31, 2011 is expected to be lower by approximately $13 million.

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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 2010 Annual Report.

Electricity Prices

Please refer to the Business Environment section of our 2010 Annual Report for a full discussion of the spot electricity market and the impact of electricity prices on our business, as well as our strategy to hedge our risk on changes in those prices.

The average spot electricity prices and spark spreads for the three and nine months ended Sept. 30, 2011 and 2010 in our three major markets are shown in the following graphs.

For the three and nine months ended Sept. 30, 2011, average spot prices increased in Alberta and decreased in the Pacific Northwest and Ontario compared to the same period in 2010. In Alberta, the increase was due to load growth from the prior year and supply tightening in the market. In the Pacific Northwest and Ontario, prices decreased due to increased hydro generation. In Ontario, prices also decreased due to lower natural gas prices and lower demand.

During the third quarter of 2011, more than 90 per cent of our consolidated power portfolio was contracted through the use of PPAs and other long-term contracts. We also enter into short-term physical and financial contracts for the remaining volumes, which are primarily for periods of up to five years, with the average price of these contracts for the balance of 2011 ranging from $60 to $65 per megawatt hour (“MWh”) in Alberta, and from U.S.$50 to U.S.$55 per MWh in the Pacific Northwest.

TRANSALTA CORPORATION / Q3 2011 9

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

For the three and nine months ended Sept. 30, 2011, average spark spreads increased in Alberta and decreased in the Pacific Northwest and Ontario compared to the same period in 2010. In Alberta, average spark spreads were higher due to higher power prices. In the Pacific Northwest and Ontario, average spark spreads decreased as a result of lower power prices. In the Pacific Northwest, average spark spreads were also lower due to higher natural gas prices.

GENERATION: TransAlta owns and operates hydro, wind, geothermal, biomass, natural gas- and coal-fired facilities, and related mining operations in Canada, the U.S., and Australia. Generation revenues and overall profitability are derived from the availability and production of electricity and steam as well as ancillary services such as system support. For a full listing of all of our generating assets and the regions in which they operate, refer to the Plant Summary section of our 2010 Annual Report.

Due to our transition to IFRS, our interest in the Fort Saskatchewan generating facility is now accounted for as a finance lease and our interests in the CE Generation, LLC (“CE Gen”) and Wailuku River Hydroelectric L.P. (“Wailuku”) joint ventures are now accounted for using the equity method. Accordingly, the related operational and financial results are no longer included in the results of our Western Canada and International geographical regions, respectively. Under Canadian GAAP, these assets were proportionately consolidated. Although these assets no longer contribute to the operating income of the Generation segment for accounting purposes, it is management’s view that these facilities still form part of our Generation segment. Please refer to the Finance Lease and Equity Investments sections of the Generation segment discussion, and to the Accounting Changes section of this MD&A, for further details.

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GENERATION OPERATIONS: During 2011, we began commercial operations at Keephills Unit 3, a 450 MW supercritical
coal-fired plant in Alberta, of which we have a 50 per cent ownership interest, and at Bone Creek, a 19 MW hydro facility in British Columbia. At Sept. 30, 2011, our generating assets had 8,192 MW of gross generating capacity⁽¹⁾ in operation (7,850 MW net ownership interest) and 129 MW net under construction. The following information excludes assets that are accounted for as a finance lease or using the equity method, which are discussed separately within this discussion of the Generation Segment.

The results produced by these assets are as follows:


	2011				2010
3 months ended Sept. 30	Total	Comparable adjustments⁽²⁾	Comparable total⁽²⁾	Per installed MWh	Total	Per installed MWh
Revenues	584	9	593	32.78	648	34.42
Fuel and purchased power	258	-	258	14.26	315	16.73
Gross margin	326	9	335	18.52	333	17.69
Operations, maintenance, and administration	100	-	100	5.53	102	5.42
Depreciation and amortization	111	-	111	6.14	120	6.37
Taxes, other than income taxes	7	-	7	0.39	7	0.37
Intersegment cost allocation	2	-	2	0.11	1	0.05
Operating expenses	220	-	220	12.17	230	12.21
Operating income	106	9	115	6.36	103	5.48
Installed capacity (GWh)	18,088		18,088		18,826
Production (GWh)	9,826		9,826		12,161
Availability (%)	83.0		83.0		91.2


	2011				2010
9 months ended Sept. 30	Total	Comparable adjustments⁽²⁾	Comparable total⁽²⁾	Per installed MWh	Total	Per installed MWh
Revenues	1,865	(125)	1,740	33.06	1,877	33.24
Fuel and purchased power	655	-	655	12.44	857	15.18
Gross margin	1,210	(125)	1,085	20.62	1,020	18.06
Operations, maintenance and administration	309	(5)	304	5.78	317	5.61
Depreciation and amortization	333	(4)	329	6.25	332	5.88
Taxes, other than income taxes	21	-	21	0.40	21	0.37
Intersegment cost allocation	6	-	6	0.11	4	0.07
Operating expenses	669	(9)	660	12.54	674	11.93
Operating income	541	(116)	425	8.08	346	6.13
Installed capacity (GWh)	52,634		52,634		56,462
Production (GWh)	27,753		27,753		34,216
Availability (%)	82.9		82.9		87.8

(1) We measure capacity as net maximum capacity (see glossary for definition of this and other key items) which is consistent with industry standards.

(2) Comparable figures are not defined under IFRS. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders and cash flow from operating activities.

TRANSALTA CORPORATION / Q3 2011 11

¹Production and Comparable Gross Margins⁽¹⁾

Production volumes, comparable revenues⁽¹⁾, fuel and purchased power costs, and comparable gross margins⁽¹⁾ based on geographical regions and fuel types are presented below.


3 months ended Sept. 30, 2011	Production (GWh)	Installed (GWh)	Revenue⁽²⁾	Fuel & purchased power	Gross margin⁽²⁾	Revenue per installed MWh⁽²⁾	Fuel & purchased power per installed MWh	Gross margin per installed MWh⁽²⁾

Coal	5,237	7,022	229	109	120	32.61	15.52	17.09
Gas	500	841	19	6	13	22.59	7.13	15.46
Renewables	827	2,939	54	3	51	18.37	1.02	17.35
Total Western Canada	6,564	10,802	302	118	184	27.96	10.92	17.04

Gas	898	1,656	91	51	40	54.95	30.80	24.15
Renewables	242	1,459	23	1	22	15.76	0.69	15.07
Total Eastern Canada	1,140	3,115	114	52	62	36.60	16.69	19.91

Coal	1,767	2,961	147	79	68	49.65	26.68	22.97
Gas	355	1,210	30	9	21	24.79	7.44	17.35
Total International	2,122	4,171	177	88	89	42.44	21.10	21.34

	9,826	18,088	593	258	335	32.78	14.26	18.52


3 months ended Sept. 30, 2010	Production (GWh)	Installed (GWh)	Revenue	Fuel & purchased power	Gross margin	Revenue per installed MWh	Fuel & purchased power per installed MWh	Gross margin per installed MWh

Coal	6,183	7,744	209	91	118	26.99	11.75	15.24
Gas	787	1,084	49	14	35	45.20	12.92	32.28
Renewables	627	2,751	22	3	19	8.00	1.09	6.91
Total Western Canada	7,597	11,579	280	108	172	24.18	9.33	14.85

Gas	1,110	1,656	109	63	46	65.82	38.04	27.78
Renewables	272	1,340	26	2	24	19.40	1.49	17.91
Total Eastern Canada	1,382	2,996	135	65	70	45.06	21.70	23.36

Coal	2,626	3,037	197	127	70	64.87	41.82	23.05
Gas	556	1,214	36	15	21	29.65	12.36	17.29
Total International	3,182	4,251	233	142	91	54.81	33.40	21.41

	12,161	18,826	648	315	333	34.42	16.73	17.69

(1) Comparable figures are not defined under IFRS. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders and cash flow from operating activities.

(2) Amounts represent comparable figures.

12 TRANSALTA CORPORATION / Q3 2011


9 months ended Sept. 30, 2011	Production (GWh)	Installed (GWh)	Revenue⁽¹⁾	Fuel & purchased power	Gross margin⁽¹⁾	Revenue per installed MWh⁽¹⁾	Fuel & purchased power per installed MWh	Gross margin per installed MWh⁽¹⁾

Coal	16,057	19,824	649	263	386	32.74	13.27	19.47
Gas	1,897	2,496	86	25	61	34.46	10.02	24.44
Renewables	2,422	8,692	155	8	147	17.83	0.92	16.91
Total Western Canada	20,376	31,012	890	296	594	28.70	9.54	19.16

Gas	2,723	4,914	308	172	136	62.68	35.00	27.68
Renewables	1,035	4,331	99	5	94	22.86	1.15	21.71
Total Eastern Canada	3,758	9,245	407	177	230	44.02	19.15	24.87

Coal	2,583	8,786	352	154	198	40.06	17.53	22.53
Gas	1,036	3,591	91	28	63	25.34	7.80	17.54
Total International	3,619	12,377	443	182	261	35.79	14.70	21.09

	27,753	52,634	1,740	655	1,085	33.06	12.44	20.62


9 months ended Sept. 30, 2010	Production (GWh)	Installed (GWh)	Revenue	Fuel & purchased power	Gross margin	Revenue per installed MWh	Fuel & purchased power per installed MWh	Gross margin per installed MWh

Coal	18,607	23,581	592	234	358	25.10	9.92	15.18
Gas	2,595	3,162	161	57	104	50.92	18.03	32.89
Renewables	1,801	8,216	97	7	90	11.81	0.85	10.96
Total Western Canada	23,003	34,959	850	298	552	24.31	8.52	15.79

Gas	2,870	4,914	324	183	141	65.93	37.24	28.69
Renewables	906	3,976	86	5	81	21.63	1.26	20.37
Total Eastern Canada	3,776	8,890	410	188	222	46.12	21.15	24.97

Coal	6,151	9,018	525	334	191	58.22	37.04	21.18
Gas	1,286	3,595	92	37	55	25.59	10.29	15.30
Total International	7,437	12,613	617	371	246	48.92	29.41	19.51

	34,216	56,462	1,877	857	1,020	33.24	15.18	18.06

(1) Amounts represent comparable figures.

TRANSALTA CORPORATION / Q3 2011 13

Western Canada

Our Western Canada assets consist of coal, natural gas, hydro, biomass, and wind facilities. Refer to the Discussion of Segmented Results section of our 2010 Annual Report for further details on our Western operations.

The primary factors contributing to the change in production for the three and nine months ended Sept. 30, 2011 are presented below:


	3 months ended Sept. 30	9 months ended Sept. 30
	(GWh)	(GWh)
Production, 2010	7,597	23,003
(Higher) lower planned and unplanned outages at the Alberta coal PPA facilities	(298)	724
Higher hydro volumes	129	368
Higher wind volumes	71	253
Commencement of commercial operations of Keephills Unit 3	159	159
(Lower) higher production at natural gas-fired facilities	(20)	9
Shut down at Sundance Units 1 and 2	(667)	(2,619)
Sale of Meridian	(121)	(555)
Decommissioning of Wabamun	-	(473)
Market curtailments	(116)	(244)
Higher planned and unplanned outages at natural gas-fired facilities	(144)	(144)
Lower PPA customer demand	(28)	(137)
Other	2	32
Production, 2011	6,564	20,376

The primary factors contributing to the change in comparable gross margin⁽¹⁾ for the three and nine months ended Sept. 30, 2011 are presented below:


	3 months ended Sept. 30	9 months ended Sept. 30
Comparable gross margin⁽¹⁾, 2010	172	552
Higher hydro margins	18	49
(Higher) lower planned and unplanned outages at the Alberta coal PPA facilities	(8)	40
Commencement of commercial operations of Keephills Unit 3	13	13
Higher wind volumes	3	9
Poplar Creek base plant no longer operated by TransAlta - offset in OM&A	(14)	(38)
Sale of Meridian	(5)	(12)
Decommissioning of Wabamun	-	(10)
Favourable (unfavourable) pricing⁽²⁾	7	(9)
Higher planned and unplanned outages at natural gas-fired facilities	(4)	(4)
Other	2	4
Comparable gross margin⁽¹⁾, 2011	184	594

(2) Net of any penalties paid under the Alberta PPAs during outages.

14 TRANSALTA CORPORATION / Q3 2011

Eastern Canada

Our Eastern Canada assets consist of natural gas, hydro, and wind facilities. Refer to the Discussion of Segmented Results section of our 2010 Annual Report for further details on our Eastern operations.

The primary factors contributing to the change in production for the three and nine months ended Sept. 30, 2011 are presented below:


	3 months ended Sept. 30	9 months ended Sept. 30
	(GWh)	(GWh)
Production, 2010	1,382	3,776
(Lower) higher wind volumes	(28)	129
Higher planned outages at natural gas-fired facilities	(121)	(72)
Unfavourable market conditions at natural gas-fired facilities	(91)	(58)
Other	(2)	(17)
Production, 2011	1,140	3,758

The primary factors contributing to the change in gross margin for the three and nine months ended Sept. 30, 2011 are presented below:


	3 months ended Sept. 30	9 months ended Sept. 30
Gross margin, 2010	70	222
(Lower) higher wind volumes	(2)	14
Higher planned outages at natural gas-fired facilities	(3)	(3)
Other	(3)	(3)
Gross margin, 2011	62	230

International

Our International assets consist of coal and natural gas facilities in various locations in the United States, and natural gas assets in Australia. Refer to the Discussion of Segmented Results section of our 2010 Annual Report for further details on our International operations.

The primary factors contributing to the change in production for the three and nine months ended Sept. 30, 2011 are presented below:


	3 months ended Sept. 30	9 months ended Sept. 30
	(GWh)	(GWh)
Production, 2010	3,182	7,437
Higher unplanned outages at Centralia Thermal	(683)	(1,937)
Lower (higher) economic dispatching at Centralia Thermal	147	(986)
Higher planned outages at Centralia Thermal	(324)	(658)
Lower production at natural gas-fired facilities	(200)	(233)
Other	-	(4)
Production, 2011	2,122	3,619

TRANSALTA CORPORATION / Q3 2011 15

The primary factors contributing to the change in comparable gross margin⁽¹⁾ for the three and nine months ended Sept. 30, 2011 are presented below:


	3 months ended Sept. 30	9 months ended Sept. 30
Comparable gross margin⁽¹⁾, 2010	91	246
Favourable pricing, primarily driven by lower purchased power prices	-	28
Lower production at Centralia Thermal	-	(3)
Unfavourable foreign exchange	(2)	(1)
Other	-	(9)
Comparable gross margin⁽¹⁾, 2011	89	261

The outages at Centralia Thermal did not negatively impact our gross margins as we were able to extend our planned outage to take advantage of lower market prices to purchase power on the market to fulfill our power contracts.

Operations, Maintenance, and Administration Expense

OM&A costs for the three months ended Sept. 30, 2011 decreased compared to the same period in 2010 due to reduced costs associated with the discontinuation of management of the base plant at Poplar Creek, partially offset by costs associated with several productivity initiatives.

For the nine months ended Sept. 30, 2011 OM&A costs decreased compared to the same period in 2010 due to lower costs associated with the discontinuation of managing the base plant at Poplar Creek, partially offset by the write off of certain wind development costs during the second quarter, resulting in a one time $5 million pre-tax ($3 million after-tax) increase in OM&A of the Generation segment and costs associated with several productivity initiatives.

Depreciation Expense

The primary factors contributing to the change in depreciation expense for the three and nine months ended Sept. 30, 2011 are presented below:


	3 months ended Sept. 30	9 months ended Sept. 30
Depreciation and amortization expense, 2010	120	332
Increase in asset base	2	10
(Decrease) increase in decommissioning and restoration costs at Wabamun	(4)	5
Writedown of capital spares	-	4
Change in residual values	(4)	(10)
Sale of Meridian	(2)	(6)
Favourable foreign exchange	(2)	(6)
Other	1	4
Depreciation and amortization expense, 2011	111	333

16 TRANSALTA CORPORATION / Q3 2011

FINANCE LEASE

Although we continue to operate the Fort Saskatchewan facility, our long-term contract was determined to be a finance lease under IFRS, as the principal risks and rewards of ownership have been transferred to the customer. As a result, the assets subject to the lease have been removed from property, plant, and equipment (“PP&E”) and the amounts due under the lease have been recorded in the Condensed Consolidated Statements of Financial Position as a finance lease receivable. Under Canadian GAAP, we had proportionately consolidated our interest in the financial and operational results of the Fort Saskatchewan facility. Please refer to Note 5 of our interim condensed consolidated financial statements as at and for the three and nine months ended Sept. 30, 2011 for additional information regarding our finance lease.

Fort Saskatchewan is a natural gas-fired facility that had 71 MW of gross generating capacityin operation (35 MW net ownership interest) at Sept. 30, 2011. Key operational information related to our interest in the Fort Saskatchewan facility, which we continue to operate, is summarized below:


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Availability (%)	92.2	89.9	97.3	95.7
Production (GWh)	118	115	351	368

Availability for the three and nine months ended Sept. 30, 2011 increased compared to the same periods in 2010 due to lower planned outages.

Production for the three months ended Sept. 30, 2011 was comparable to the same period in 2010.

For the nine months ended Sept. 30, 2011, production decreased by 17 GWh compared to the same period in 2010 primarily due to lower customer demand.

Finance lease income for the three and nine months ended Sept. 30, 2011 was consistent with the same periods in 2010 at
$2 million and $6 million, respectively.

EQUITY INVESTMENTS

Under IFRS, interests in joint ventures that are jointly controlled entities, like our CE Gen and Wailuku joint ventures, can be recognized using either the proportionate consolidation or equity method. We adopted the equity method to account for these interests to align with the requirements of IFRS 11 Joint Arrangements, which was issued by the International Accounting Standards Board (“IASB”) in May 2011. Under Canadian GAAP, we had proportionately consolidated our interests in the financial and operational results of CE Gen and Wailuku.

This change resulted in the reclassification of our share of assets and liabilities from each respective line item on our Condensed Consolidated Statements of Financial Position to a single line item entitled “Investments”. Our proportionate share of revenue and expenses was also reclassified from each respective line item and presented as a single amount entitled “Equity income” on the Condensed Consolidated Statements of Earnings. Please refer to Note 6 of our interim condensed consolidated financial statements as at and for the three and nine months ended Sept. 30, 2011 for additional financial information regarding our equity accounted investments.

TRANSALTA CORPORATION / Q3 2011 17

Our equity accounted investments are comprised of geothermal, natural gas, and hydro facilities in various locations throughout the U.S., with 839 MW of gross generating capacity (390 MW net ownership interest). The table below summarizes key operational information from our equity accounted investments:


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Availability (%)	98.5	97.6	96.4	94.5
Production (GWh)
Gas	79	122	284	327
Renewables	345	344	962	946
Total production	424	466	1,246	1,273

Availability for the three and nine months ended Sept. 30, 2011 increased compared to the same periods in 2010 due to lower planned and unplanned outages at our CE Gen facilities.

Production for the three and nine months ended Sept. 30, 2011 decreased compared to the same periods in 2010 due to unfavourable market conditions partially offset by lower planned and unplanned outages.

During the three months ended Sept. 30, 2011, our equity income from CE Gen and Wailuku was $14 million as compared to income of $11 million for the same period in 2010. The equity income increased primarily due to lower planned and unplanned outages.

Equity income from CE Gen and Wailuku for the nine months ended Sept. 30, 2011 was $16 million as compared to income of $8 million for the same period in 2010. The equity income increased primarily due to lower unplanned outages and the realization of a gain on the sale of property, partially offset by lower income tax recoveries and unfavourable foreign exchange rates.

18 TRANSALTA CORPORATION / Q3 2011

ENERGY TRADING: 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 limits, is a key measure of Energy Trading’s activities.

Energy Trading 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 and transmission capacity. Energy Trading is also responsible for recommending portfolio optimization decisions. The results of these activities are included in the Generation segment.

For a more in-depth discussion of our Energy Trading activities, refer to the Discussion of Segmented Results section of our 2010 Annual Report.

The results of the Energy Trading segment are as follows:


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Gross margin	45	3	97	17
Operations, maintenance, and administration	12	4	27	13
Depreciation and amortization	-	-	1	1
Intersegment cost recovery	(2)	(1)	(6)	(4)
Operating expenses	10	3	22	10
Operating income	35	-	75	7

For the three months ended Sept. 30, 2011, gross margins increased relative to the same period in 2010 due to strong trading results in the Western regions. These results were partially offset by lower gross margins in the Pacific Northwest region resulting from weak pricing and reduced electricity demand.

Gross margin increased for the nine months ended Sept. 30, 2011 relative to the same period in 2010 due to strong trading results in the Western regions during the second and third quarters and increased earnings from the acquisition of electricity and natural gas contracts. These positive results were partially offset by lower gross margins in the Pacific Northwest region resulting from weak pricing and reduced electricity demand.

OM&A costs for the three and nine months ended Sept. 30, 2011 increased over the same period in 2010 due to higher compensation costs associated with strong results and costs associated with several productivity initiatives.

CORPORATE: Our Generation and Energy Trading business 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.

The expenses incurred by the Corporate segment are as follows:


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Operations, maintenance, and administration	26	13	64	51
Depreciation and amortization	4	5	15	14
Operating expenses	30	18	79	65

TRANSALTA CORPORATION / Q3 2011 19

OM&A costs increased for the three and nine months ended Sept. 30, 2011 compared to the same periods in 2010 due to costs associated with several productivity initiatives and higher compensation costs.

NET INTEREST EXPENSE

Under IFRS, where discounting is used, the increase in the carrying amount of a provision, such as for decommissioning and restoration activities, associated with the passage of time is recognized as a finance cost and included in net interest expense. Under Canadian GAAP, this was recognized as part of depreciation and amortization expense or fuel and purchased power.

The components of net interest expense are shown below:


	3 months ended Sept. 30			9 months ended Sept. 30
	2011	2010	2011		2010
Interest on debt	57	60	167		168
Interest income	-	(2)	-		(16)
Capitalized interest	(8)	(13)	(31)		(35)
Ineffectiveness on fair value hedges	(1)	-	(1)		-
Other	-	-	1		-
Interest expense	48	45	136		117
Accretion of discount on provisions	6	4	15		13
Net interest expense	54	49	151		130

The change in net interest expense for the three and nine months ended Sept. 30, 2011, compared to the same period in 2010 is shown below:


	3 months ended Sept. 30	9 months ended Sept. 30
Net interest expense, 2010	49	130
Lower interest income primarily due to the resolution of certain outstanding tax matters in 2010	-	15
Higher interest rates	2	7
Lower capitalized interest	5	4
Higher decommissioning and restoration accretion	1	1
Favourable foreign exchange	-	(4)
Lower debt levels	(2)	(1)
Ineffective gain on fair value hedges	(1)	(1)
Net interest expense, 2011	54	151

20 TRANSALTA CORPORATION / Q3 2011

INCOME TAXES

A reconciliation of income taxes and effective tax rates on earnings excluding non-comparable items is presented below:


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Earnings before income taxes	70	50	399	176
Income attributable to non-controlling interests	(7)	(6)	(27)	(20)
Equity income	(14)	(11)	(16)	(8)
Impacts associated with certain de-designated and ineffective hedges	9	-	(125)	-
Asset impairment charges	5	-	14	-
Other non-comparable items	-	-	6	-
Earnings attributable to TransAlta shareholders excluding non-comparable items subject to tax	63	33	251	148
Income tax (recovery) expense	9	4	95	(7)
Income tax recovery (expense) related to impacts associated with certain de-designated and ineffective hedges	2	-	(45)	-
Income tax recovery related to asset impairment charges	1	-	3	-
Income tax recovery related to the resolution of certain outstanding tax matters	-	-	-	30
Income tax related to other non-comparable items	-	-	2	-
Income tax expense excluding non-comparable items	12	4	55	23
Effective tax rate on earnings attributable to TransAlta shareholders excluding non-comparable items	19	12	22	16

The income tax expense excluding non-comparable items for the three and nine months ended Sept. 30, 2011 increased compared to the same periods in 2010 due to higher comparable earnings and changes in the composition of jurisdictions in which pre-tax income is earned.

The effective tax rate on earnings attributable to TransAlta shareholders excluding non-comparable items for the three and nine months ended Sept. 30, 2011 increased primarily due to the effect of certain deductions that do not fluctuate with earnings and changes in the composition of jurisdictions in which pre-tax income is earned.

NON-CONTROLLING INTERESTS

As a result of our transition to IFRS, the non-controlling interest related to our proportionate share of ownership in the Saranac facility is reported as part of our net investment in CE Gen. Please refer to the Equity Investments section of this MD&A for further discussion.

Net earnings attributable to non-controlling interests for the three and nine months ended Sept. 30, 2011 increased $1 million and $7 million, respectively, compared to the same periods in 2010 due to higher earnings at TA Cogen.

TRANSALTA CORPORATION / Q3 2011 21

FINANCIAL POSITION

The following chart highlights significant changes in the Condensed Consolidated Statements of Financial Position from
Dec. 31, 2010 to Sept. 30, 2011:


	Increase/
	(Decrease)	Primary factors explaining change
Cash and cash equivalents	31	Increase in net earnings and increase in borrowings under credit facilities
Accounts receivable	71	Timing of customer receipts and higher revenues
Income taxes receivable	(18)	Resolution of certain tax matters
Inventory	46	Lower production at our coal facilities and higer average coal costs
Assets held for sale	(57)	Completion of sale of the Meridian facility partially offset by the sale of the Grande Prairie facility
Investments	23	Equity income and favourable foreign exchange
Risk management assets (current and long-term)	(17)	Price movements and changes in underlying positions
Other assets	(17)	Transfer of project to property, plant, and equipment
Accounts payable and accrued liabilities	(34)	Timing of payments and lower capital accruals
Collateral received	(97)	Reduction in collateral received from counterparties associated with changes in forward prices
Dividends payable	(64)	Timing of common share dividend declarations
Long-term debt (including current portion)	206	Increase in borrowings under credit facilities
Decommissioning and other provisions (current and long-term)	70	Increase in decommissioning and commercial provisions
Deferred credits and other long-term liabilities	33	Increase in defined benefit accrual
Deferred income tax liabilities	(32)	Tax effect on the increase in net risk management liabilities
Risk management liabilities (current and long-term)	107	Price movements and changes in underlying positions
Equity attributable to shareholders	(66)	Increase in net earnings, offset by movements in AOCI
Non-controlling interests	(51)	Distributions paid, partially offset by non-controlling interests' portion of net earnings

FINANCIAL INSTRUMENTS

Refer to Note 7 of the notes to the consolidated financial statements within our 2010 Annual Report and Note 10 of our interim condensed consolidated financial statements as at and for the three and nine months ended Sept. 30, 2011 for details on Financial Instruments. Refer to the Risk Management section of our 2010 Annual Report for further details on our risks and how we manage them. Our risk management profile and practices have not changed materially from Dec. 31, 2010 and our transition to IFRS did not have a material effect on our accounting for financial instruments.

Energy Trading may enter into commodity transactions involving non-standard features for which market observable data is not available. These are defined under IFRS 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.

22 TRANSALTA CORPORATION / Q3 2011

As a result of our acquisition of Canadian Hydro Developers, Inc. (“Canadian Hydro”), we also have various contracts with terms that extend beyond five years. As forward price forecasts are not available for the full period of these contracts, the value of these contracts must be derived by reference to a forecast that is based on a combination of external and internal fundamental modeling, including discounting. As a result, these contracts are classified in Level III. These contracts are for a specified price with counterparties that we believe to be creditworthy.

At Sept. 30, 2011, Level III financial instruments had a net liability carrying value of $14 million (Dec. 31, 2010 - $20 million).

During the three and nine months ended Sept. 30, 2011, unrealized pre-tax gains of $3 million and $207 million, respectively, were released from AOCI and recognized in earnings due to certain power hedging relationships being deemed ineffective for accounting purposes. These unrealized gains were calculated using current forward prices which will change between now and the time the underlying hedged transactions are expected to occur. Had these hedges not been deemed ineffective for accounting purposes, the revenues associated with these contracts would have been recorded in net earnings in the period in which they settle, the majority of which will occur during 2011 and 2012. As these gains have already been recognized in earnings in the current period, future reported earnings will be lower, however, the expected cash flows from these contracts will not change.

We discontinued hedge accounting for certain cash flow hedges that no longer met the criteria for hedge accounting. As at Sept. 30, 2011, cumulative gains of $95 million, $78 million of which was discontinued in the third quarter of 2011, will continue to be deferred in AOCI and will be reclassified to net earnings as the forecasted transactions occur.

STATEMENTS OF CASH FLOWS

Our transition to IFRS changed the presentation of several items on the Condensed Consolidated Statements of Cash Flows. The most significant of these items is the effect of using the equity method instead of the proportionate consolidation method to account for our interests in CE Gen and Wailuku. Our share of CE Gen and Wailuku’s cash and cash equivalents and cash flow changes are no longer presented within each line item of the operating, investing, or financing activities sections of the Condensed Consolidated Statements of Cash Flows, and instead, cash distributions received are presented as an operating activity and cash returns of invested capital or additional cash invested are presented as an investing activity. The capitalization of costs associated with planned major maintenance and inspection activities that were previously expensed under Canadian GAAP will result in these cash expenditures being reported as an investing activity under IFRS. Under Canadian GAAP these expenditures impacted cash flow from operations.

TRANSALTA CORPORATION / Q3 2011 23

The following charts highlight significant changes in the Condensed Consolidated Statements of Cash Flows for the three and nine months ended Sept. 30, 2011 compared to the same periods in 2010:


3 months ended Sept. 30	2011	2010	Primary factors explaining change
Cash and cash equivalents, beginning of period	38	32
Provided by (used in):
Operating activities	221	224	Lower cash earnings of $7 million, offset by favourable changes in working capital balances of $4 million primarily due to the timing of payments and receipts

Investing activities	(192)	(134)	Decrease in collateral received from counterparties of $100 million, offset by a decrease in additions to PP&E of $66 million

Financing activities	(1)	(71)	Increased borrowings due to higher usage of cash in investing activities
Translation of foreign currency cash	-	6
Cash and cash equivalents, end of period	66	57


9 months ended Sept. 30	2011	2010	Primary factors explaining change
Cash and cash equivalents, beginning of period	35	53
Provided by (used in):
Operating activities	512	521	Unfavourable changes in working capital balances of $58 million primarily due to the timing of payments and receipts offset by higher cash earnings of $49 million

Investing activities	(411)	(552)	Decrease in additions to PP&E of $297 million and proceeds on the sale of the Meridian facility of $30 million, offset by an $182 million decrease in collateral received from counterparties

Financing activities	(71)	32	Reduced borrowings and lower cash dividends on common shares
Translation of foreign currency cash	1	3
Cash and cash equivalents, end of period	66	57

LIQUIDITY AND CAPITAL RESOURCES

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

Our liquidity needs are met through a variety of sources, including cash generated from operations, borrowings under our long-term credit facilities, and long-term debt issued under our Canadian and U.S. shelf registrations. Our primary uses of funds are operational expenses, capital expenditures, dividends, distributions to non-controlling limited partners, and interest and principal payments on debt securities.

24 TRANSALTA CORPORATION / Q3 2011

Debt

Under IFRS, debt arising through our equity accounted joint ventures is no longer presented as part of non-recourse debt. Recourse and non-recourse debt totalled $4.3 billion at Sept. 30, 2011 and $4.1 billion at Dec. 31, 2010.

Credit Facilities

At Sept. 30, 2011, we have a total of $2.0 billion (Dec. 31, 2010 - $2.0 billion) of committed credit facilities of which $0.7 billion
(Dec. 31, 2010 - $1.1 billion) is not drawn and available, subject to customary borrowing conditions. At Sept. 30, 2011, the
$1.3 billion (Dec. 31, 2010 - $0.9 billion) of credit utilized under these facilities is comprised of actual drawings of $1.0 billion
(Dec. 31, 2010 - $0.6 billion) and of letters of credit of $0.3 billion (Dec. 31, 2010 - $0.3 billion). These facilities are comprised of a $1.5 billion committed syndicated bank facility, which matures in 2015, with the remainder comprised of bilateral credit facilities which mature between the fourth quarter of 2012 and the third quarter of 2013. We anticipate renewing these facilities, based on reasonable commercial terms, prior to their maturities.

In addition to the $0.7 billion available under the credit facilities, we also have $66 million of cash available.

Share Capital

On Oct. 27, 2011, we had 223.6 million common shares outstanding and 12.0 million first preferred shares outstanding.

At Sept. 30, 2011, we had 222.9 million (Dec. 31, 2010 - 220.3 million) common shares issued and outstanding. During the three months ended Sept. 30, 2011, 0.9 million (Sept. 30, 2010 - 0.7 million) common shares were issued for $17 million
(Sept. 30, 2010 - $15 million). During the three months ended Sept. 30, 2011 and 2010, all the common shares were issued under the terms of the DRASP plan. During the nine months ended Sept. 30, 2011, 2.6 million (Sept. 30, 2010 - 1.1 million) common shares were issued for $52 million (Sept. 30, 2010 - $19 million). Of the 2.6 million common shares issued during the nine months ended Sept. 30, 2011, 0.1 million were issued for cash proceeds of $1 million and 2.5 million were issued for $51 million under the terms of the DRASP plan. Of the 1.1 million common shares issued during the nine months ended Sept. 30, 2010, 0.2 million were issued for cash proceeds of $1 million and 0.9 million were issued for $18 million under the terms of the DRASP plan.

We employ a variety of stock-based compensation to align employee and corporate objectives. At Sept. 30, 2011, we had
1.8 million outstanding employee stock options (Dec. 31, 2010 - 2.2 million). During the three months ended Sept. 30, 2011, a nominal number of options expired, or were exercised or cancelled (Sept. 30, 2010 - a nominal number of options expired, or were exercised or cancelled). During the nine months ended Sept. 30, 2011, 0.4 million options expired, or were exercised or cancelled (Sept. 30, 2010 - 0.1 million options expired, or were exercised or cancelled).

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, energy trading activities, hedging activities, and purchase obligations.
At Sept. 30, 2011, we provided letters of credit totalling $302 million (Dec. 31, 2010 - $297 million) and cash collateral of
$38 million (Dec. 31, 2010 - $27 million). These letters of credit and cash collateral secure certain amounts included on our Condensed Consolidated Statements of Financial Positions under “Risk Management Liabilities” and “Decommissioning and Other Provisions”.

TRANSALTA CORPORATION / Q3 2011 25

CLIMATE CHANGE AND THE ENVIRONMENT

On Aug. 27, 2011, the Government of Canada published in the Canada Gazette draft regulations entitled “Reduction of CO₂ Emissions from Coal-Fired Generation of Electricity”. These regulations propose a 45-year end-of-life for coal-fired power units, at which point the units would have to meet a GHG emissions performance standard similar to natural gas-fired levels, or close. Should they be passed, the regulations would become effective on July 1, 2015. Under federal consultation provisions, industry, provinces and other stakeholders have 60 days to provide comments on the regulations and subsequently the federal government will consider this input in the development of the second draft.

We are currently in discussions with both the federal and Alberta governments about modifications to the regulations that would result in significant GHG emission reductions in the most economically efficient manner, and would also provide alignment with other current and future regulations on air pollutants and on natural gas generation. These discussions are expected to continue through October and November.

In the U.S., the EPA announced on Sept. 14, 2011 that it was further delaying the release of draft GHG regulations for coal-fired power plants beyond its Sept. 30, 2011 target date. It is not known when the regulations might be forthcoming or their exact form.

TransAlta is proceeding with the installation of voluntary mercury capture technology at the Centralia coal-fired plant which will be operational by 2012. That plant is also planning for the installation of additional capture technology to further reduce oxides of nitrogen (“NOx”), consistent with the Washington State Bill passed in April 2011 requiring TransAlta to begin operating such technology by Jan. 1, 2013. Both these initiatives are well in advance of the finalization of any federal regulations on mercury and NOx-related ozone.

For further details regarding these, and other matters, please refer to the discussion in the Climate Change and the Environment section of our 2010 Annual Report.

2011 OUTLOOK

In 2011, we anticipate modest growth in comparable earnings per share, funds from operations, and comparable EBITDA based upon the factors that are discussed below.

Business Environment

Power Prices

For the remainder of 2011, power prices in Alberta are expected to be higher compared to the same period last year primarily as a result of tighter supply and demand balances. In the Pacific Northwest, prices are expected to be comparable to 2010 due to low natural gas prices.

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 the timing and structure of its GHG regulatory framework with the U.S., although coal-fired power is being addressed separately and earlier. In the U.S., it is not clear if climate change legislation will prevail or if 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.

26 TRANSALTA CORPORATION / Q3 2011

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

The siting, construction, and operation of electrical energy facilities requires interaction with many stakeholders. More recently, certain stakeholders have brought actions against government agencies and owners over alleged adverse impacts of wind projects. We are monitoring these claims in order to access the risk associated with these activities.

Economic Environment

The economic environment has shown modest improvement in 2011 and we expect this trend to continue through 2011 at a slow to moderate pace.

We had no counterparty losses in the third quarter of 2011, and 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.

Operations

Capacity, Production, and Availability

Generating capacity is expected to be constant for the remainder of 2011. Production is expected to increase for the remainder of 2011 due to lower planned and unplanned outages, lower economic dispatching, and the commencement of commercial operations of Keephills Unit 3. Availability is expected to increase for the remainder of 2011 due to lower planned and unplanned outages.

Commodity Hedging

Through the use of Alberta PPAs, long-term contracts, and other short-term physical and financial contracts, on average approximately 70 per cent of our capacity is contracted over the next seven years. On an aggregated portfolio basis we target being up to 90 per cent contracted for the upcoming year, stepping down to 65 per cent in the fourth year. As at the end of the third quarter, approximately 95 per cent of our 2011 capacity was contracted. The average price of our short-term physical and financial contracts for the balance of 2011 ranges from $60 to $65 per MWh in Alberta, and from U.S.$50 to U.S.$55 per MWh in the Pacific Northwest.

Fuel Costs

Mining coal in Alberta is subject to cost increases due to greater overburden removal, inflation, capital investments, and commodity prices. Seasonal variations in coal costs at our Alberta mines are minimized through the application of standard costing. Coal costs for 2011, on a standard cost basis, are expected to increase by approximately 14 per cent compared to 2010 due to lower tonnes mined and delivered to the thermal units as a result of the shut down at Sundance Units 1 and 2.

Fuel at Centralia Thermal is purchased from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel for 2011 is expected to remain consistent with the prior year.

We purchase natural gas from outside companies coincident with production or have it supplied by our customers, thereby minimizing our risk to changes in prices. The continued success of unconventional gas production in North America could reduce the year to year volatility of prices going forward.

TRANSALTA CORPORATION / Q3 2011 27

We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risk.

Operations, Maintenance, and Administration Costs

OM&A costs for 2011 are expected to be lower than amounts previously reported under Canadian GAAP due primarily to major inspection costs being capitalized under IFRS. Under Canadian GAAP, major inspection costs were expensed as incurred.

OM&A costs for 2011 are expected to be higher than 2010 OM&A costs under IFRS primarily due to costs associated with a number of productivity initiatives, the write off of development costs, and higher compensation costs.

Energy Trading

Earnings from our Energy Trading segment are affected by prices in the market and overall strategies adopted. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our revised 2011 objective is for Energy Trading to contribute between $100 million and $125 million in gross margin. The annual objective for Energy Trading gross margin contribution has increased from prior estimates to reflect the year-to-date results.

Exposure to Fluctuations in Foreign Currencies

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. and Australian dollar by offsetting foreign denominated assets with foreign denominated liabilities and by entering into foreign exchange contracts. We also have foreign denominated expenses, including interest charges, which largely offset our net foreign denominated revenues.

Net Interest Expense

Net interest expense for 2011 is expected to be higher than our reported 2010 net interest expense under Canadian GAAP mainly due to higher debt balances, higher variable interest rates, lower capitalized interest, 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 in the future. To mitigate this liquidity risk, we expect to maintain $2.0 billion of committed credit facilities, and will continuously monitor our exposures and obligations.

Accounting Estimates

A number of our accounting estimates, including those outlined in Note 1Y of our notes to the unaudited interim condensed consolidated financial statements as at and for the three and nine months ended Sept. 30, 2011, are based on the current economic environment and outlook. While we do not anticipate significant changes to these estimates as a result of the current economic environment, market fluctuations could impact, among other things, future commodity prices, foreign exchange rates, and interest rates, which could, in turn, impact future earnings and the unrealized gains or losses associated with our risk management assets and liabilities.

28 TRANSALTA CORPORATION / Q3 2011

Income Taxes

The effective tax rate on earnings excluding non-comparable items for 2011 is expected to be approximately 18 to 23 per cent.

Capital Expenditures

Our major projects are focused on sustaining our current operations and supporting our growth strategy.

Growth Capital Expenditures

We have four significant growth capital projects that are currently in progress with targeted completion date of Q4 2012. A summary of each of these significant projects and the projects we completed is outlined below:


	Total Project		2011		Target
Project	Estimated spend	Spend to date⁽¹⁾	Estimated spend	Spend to date⁽¹⁾	completion date	Details

Keephills Unit 3⁽²⁾	1,010 - 1,020	993	70 - 90	64	Commercial operations began Q3 2011	A 450 MW (225 MW net ownership interest) supercritical coal-fired plant and associated mine capital in a partnership with Capital Power
Keephills Unit 1 uprate	34	8	5 - 15	4	Q4 2012	A 23 MW efficiency uprate at our Keephills facility
Keephills Unit 2 uprate	34	7	10 - 20	1	Q4 2012	A 23 MW efficiency uprate at our Keephills facility
Bone Creek⁽³⁾	52	50	(0) - (5)	(4)	Commercial operations began Q2 2011	A 19 MW hydro facility in British Columbia
Sundance Unit 3 uprate	27	9	5 - 10	6	Q4 2012	A 15 MW efficiency uprate at our Sundance facility
New Richmond⁽⁴⁾	205	12	20 - 40	12	Q4 2012	A 68 MW wind farm in Quebec
Total growth	1,362 - 1,372	1,079	110 - 170	83

Our estimated spend for 2011 for Bone Creek has increased by $5 million and our estimated spend for 2011 has decreased by $5 million for the Keephills Unit 1 and Sundance 3 uprates and by $10 million for the Keephills Unit 2 uprate to more accurately reflect the expected timing of related costs.

Amounts disclosed in the above chart are shown net of any joint venture contributions received or other recoveries.

(1) Represents amounts spent as of Sept. 30, 2011. In 2011, we also spent a combined total of $6 million on Ardenville and Kent Hills 2.

(2) Keephills Unit 3 amounts spent as of Sept. 30, 2011 includes a non-capital expenditures of $7 million and a coal cost reduction of $2 million.

(3) Bone Creek amounts spent as of Sept. 30, 2011 includes a non-capital credit of $9 million.

(4) New Richmond amounts spent as of Sept. 30, 2011 includes expenditures of $5 million which had been previously included in project development costs.

TRANSALTA CORPORATION / Q3 2011 2

Sustaining Capital Expenditures

A significant portion of our sustaining capital expenditures is planned major maintenance, which includes inspection, repair and maintenance of existing components, and the replacement of existing components. Some of these amounts were previously expensed under Canadian GAAP. Under IFRS, planned major maintenance costs are capitalized as part of PP&E and are amortized on a straight-line basis over the term until the next major maintenance event.

For 2011, our estimate for total sustaining capital expenditures, net of any contributions received, is allocated among the following:¹


Category	Description	Expected cost	Spend to date⁽¹⁾

Routine capital	Expenditures to maintain our existing generating capacity	95 - 105	85
Productivity capital	Projects to improve power production efficiency	10 - 20	14
Mining equipment and land purchases	Expenditures related to mining equipment and land purchases	25 - 30	15
Planned maintenance	Regularly scheduled major maintenance	180 - 210	136
Total sustaining expenditures		310 - 365	250

Details of the 2011 planned maintenance program, including major inspection costs, are outlined as follows:


	Coal		Expected cost	Spend to date⁽¹⁾
	Coal	Gas and Renewables	Expected cost	Spend to date⁽¹⁾
Capitalized	105 - 130	75 - 80	180 - 210	136
Expensed	0 - 0	0 - 5	0 - 5	2
	105 - 130	75 - 85	180 - 215	138

	Coal	Gas and Renewables	Expected total	Lost to date
GWh lost	2,610 - 2,620	430 - 440	3,040 - 3,060	2,676

Financing

Financing for these capital expenditures is expected to be provided by cash flow from operating activities, existing borrowing capacity, and capital markets. 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 flow, our financial position, and the amount of capital available to us under existing committed credit facilities.

ACCOUNTING CHANGES

Transition to IFRS

On Jan. 1, 2011, we adopted IFRS for Canadian publicly accountable enterprises, as required by the Accounting Standards Board of Canada. Prior to the adoption of IFRS, we followed Canadian GAAP. While IFRS uses a conceptual framework similar to Canadian GAAP and has many similarities to Canadian GAAP, several of our significant accounting policies have changed. The most significant of these accounting policy changes impacting our results of operations have been outlined in earlier sections of this MD&A (please refer to the Finance Lease and Equity Investments sections of the Generation segment discussion and to the Sustaining Capital Expenditures section of the 2011 Outlook discussion). In addition to these, there have been several other changes to our accounting policies, which are discussed below. To assist with, and in some cases, simplify, transition to IFRS, certain exemptions and elections are available for first-time adopters under IFRS 1 First-Time Adoption of International Financial Reporting Standards (“IFRS 1”). The most significant that we have chosen to use are also discussed below.

(1) Represents amounts incurred as of Sept. 30, 2011.

30 TRANSALTA CORPORATION / Q3 2011

Arrangements That Are, or Contain a Lease: Contractual arrangements exempted from similar review under Canadian GAAP were reviewed to determine if they contained, or were, finance or operating leases. As a result of this review, in addition to our Fort Saskatchewan facility being a finance lease, several of our other PPAs and long-term contracts are considered operating lease arrangements, as we retain the operational risks. Although the nature of these arrangements has changed under IFRS, no differences arose in the way we recognize our revenues, or in how we account for the PP&E, associated with the related facilities.

Employee Future Benefits: On transition to IFRS, the cumulative net actuarial losses related to our defined benefit pension and
post-employment plans were recognized in retained earnings, and will not have an impact on net earnings in future periods. Actuarial gains and losses arising subsequent to transition will be recognized in Other Comprehensive Income (“OCI”) as they occur, in accordance with our accounting policy choice. Under our previous GAAP, the corridor method was used, and actuarial gains or losses were only recognized in net earnings over time, when certain conditions were met.

Foreign Exchange Gains and Losses on Translation of Foreign Operations: Our cumulative net foreign exchange losses on translation of foreign operations, net of hedges and tax, were reset to zero and recognized in retained earnings on transition, and consequently, will not have an impact on future net earnings. Foreign exchange gains or losses on translation of foreign operations arising subsequently will continue to be recognized in OCI, as under our previous GAAP.

Provisions: IFRS requires that provisions, such as obligations for decommissioning and restoration costs, are revalued at the end of each reporting period using a current market-based discount rate. Amounts arising as a result of these revaluations are recognized as a cost of the related asset, and depreciated accordingly. Under Canadian GAAP, the discount rates used were only revised in certain circumstances.

Business Combinations: Acquisitions that occurred prior to transition can continue to be measured and recorded at their previously established Canadian GAAP amounts. As a result of the use of this election, we were not required to restate our 2009 acquisition of Canadian Hydro to comply with IFRS.

Although we adopted IFRS on Jan. 1, 2011, we were required to restate our comparative 2010 annual and interim financial positions and results of operations, effective from Jan. 1, 2010. The 2010 comparative amounts have not been audited by our external auditor. Note 1 of our unaudited interim condensed consolidated financial statements as at and for the three and nine months ended Sept. 30, 2011 outlines our IFRS accounting policies and Note 2 provides a complete list of our IFRS 1 elections; detailed reconciliations between Canadian GAAP and IFRS of shareholders’ equity as at Jan. 1, Sept. 30, and Dec. 31, 2010, respectively, and of net earnings and comprehensive income for the three and nine months ending Sept. 30, and for the twelve months ending
Dec. 31, 2010, respectively; and information regarding the impacts of IFRS transition on our cash flows.

Future Accounting Changes

I. IFRS Policies

Our interim financial statements as at and for the three and nine months ended Sept. 30, 2011 and 2010 and our IFRS Statements of Financial Position as at Jan.1 and Dec. 31, 2010, respectively, have been prepared using the Standards and Interpretations currently issued and expected to be effective at the end of our first annual IFRS reporting period of Dec. 31, 2011. Accounting policies currently adopted under IFRS are subject to change as a result of either a new standard being issued with an effective date of Dec. 31, 2011 or prior, or as a result of a voluntary change in accounting policy made by us during 2011. A change in an accounting policy used may result in material changes to our reported financial position, results of operations and cash flows.

TRANSALTA CORPORATION / Q3 2011 31

II. Consolidated Financial Statements

In May 2011, the IASB issued IFRS 10 Consolidated Financial Statements, which replaces IAS 27 Consolidated and Separate Financial Statements and SIC-12 Consolidation - Special Purpose Entities. IFRS 10 provides a revised definition of control so that a single control model can be applied to all entities for consolidation purposes.

III. Joint Arrangements

In May 2011, the IASB issued IFRS 11 Joint Arrangements, which supersedes IAS 31 Interests in Joint Ventures and SIC-13 Jointly Controlled Entities - Non-Monetary Contributions by Venturers. IFRS 11 provides for a principle-based approach to the accounting for joint arrangements that requires an entity to recognize its contractual rights and obligations arising from its joint arrangements. IFRS 11 also requires the use of the equity method of accounting for interests in joint ventures. Improvements in disclosure requirements are intended to allow investors to gain a better understanding of the nature, extent, and financial effects of the activities that an entity carries out through joint arrangements.

IV. Disclosure of Interests in Other Entities

In May 2011, the IASB issued IFRS 12 Disclosure of Interests in Other Entities, which contains enhanced disclosure requirements about an entity’s interests in consolidated and unconsolidated entities, such as subsidiaries, joint arrangements, associates, and unconsolidated structured entities (special purpose entities).

V. Investments in Associates and Joint Ventures and Separate Financial Statements

Two existing standards, IAS 28 Investments in Associates and Joint Ventures and IAS 27 Separate Financial Statements, were amended. The amendments result from the issuance of IFRS 10, IFRS 11, and IFRS 12.

The requirements of the preceding new standards and amendments to existing standards, outlined in points II to V, are effective for annual periods beginning on or after Jan. 1, 2013. The disclosure requirements of IFRS 12 may be incorporated into the financial statements earlier than Jan. 1, 2013. However, early adoption of the other standards is only permitted if all five are applied at the same time. We are currently assessing the impact of adopting these new standards and amendments on the consolidated financial statements.

VI. Fair Value Measurements

In June 2011, the IASB issued IFRS 13 Fair Value Measurements, which establishes a single source of guidance for all fair value measurements required by other IFRS; clarifies the definition of fair value; and enhances disclosures about fair value measurements. IFRS 13 applies when other IFRS require or permit fair value measurements or disclosures. IFRS 13 specifies how an entity should measure fair value and disclose fair value information. It does not specify when an entity should measure an asset, a liability or its own equity instrument at fair value. IFRS 13 is effective for annual periods beginning on or after Jan. 1, 2013. Earlier application is permitted. We are currently assessing the impact of adopting IFRS 13 on the consolidated financial statements.

32 TRANSALTA CORPORATION / Q3 2011

VII. Presentation of Financial Statements

In June 2011, the IASB issued amendments to IAS 1 Presentation of Financial Statements to improve the consistency and clarity of the presentation of items of comprehensive income by requiring that items presented in OCI be grouped on the basis of whether they are at some point reclassified from OCI to net earnings or not. The amendments to IAS 1 are effective for annual periods beginning on or after July 1, 2012. Earlier application is permitted. We are currently assessing the impact of adopting the amendments to IAS 1 on the consolidated financial statements.

VIII. Employee Benefits

In June 2011, the IASB issued amendments to IAS 19 Employee Benefits to improve the recognition, presentation, and disclosure of defined benefit plans. The amendments require a new presentation approach that improves the visibility of the different types of gains and losses arising from defined benefit plans, as follows: service cost is presented in net earnings; finance cost is presented as part of finance costs in net earnings; and remeasurements of the net defined benefit asset or liability are recognized immediately in OCI, effectively eliminating the option to defer the recognition of actuarial gains and losses, known as the ‘corridor method’. The disclosure requirements are enhanced to provide better information about the characteristics of defined benefit plans and the risks that entities are exposed to through participation in these plans. The amendments to IAS 19 are effective for annual periods beginning on or after Jan. 1, 2013. Earlier application is permitted. We are currently assessing the impact of adopting the amendments to IAS 19 on the consolidated financial statements.

IX. Financial Instruments

In November 2009, the IASB issued IFRS 9 Financial Instruments which replaced the classification and measurement requirements in IAS 39 Financial Instruments: Recognition and Measurement for financial assets. Financial assets must be classified and measured at either amortized cost or fair value through profit or loss or through OCI depending on the basis of the entity’s business model for managing the financial asset and the contractual cash flow characteristics of the financial asset.

In October 2010, the IASB issued additions to IFRS 9 Financial Instruments regarding financial liabilities. The new requirements address the problem of volatility in net earnings arising from an issuer choosing to measure a liability at fair value and require the portion of the change in fair value due to changes in the entity’s own credit risk be presented in OCI, rather than within net earnings.

The requirements are effective for annual periods beginning on or after Jan. 1, 2013, and must be applied retrospectively. Earlier adoption is permitted. The IASB has recently issued an exposure draft which proposes to postpone the mandatory application of IFRS 9 until 2015. We are currently assessing the impact of adopting IFRS 9 on the consolidated financial statements.

NON-IFRS MEASURES

We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed below are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing 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.

TRANSALTA CORPORATION / Q3 2011 33

Reconciliation to Net Earnings Attributable to Common Shareholders

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


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Revenues	629	651	1,962	1,894
Fuel and purchased power	258	315	655	857
Gross margin	371	336	1,307	1,037
Operations, maintenance, and administration	138	119	400	381
Depreciation and amortization	115	125	349	347
Taxes, other than income taxes	7	7	21	21
Operating expenses	260	251	770	749
Operating income	111	85	537	288
Finance lease income	2	2	6	6
Equity income	14	11	16	8
Gain on sale of assets	-	-	3	-
Other income	1	-	2	-
Foreign exchange gain	1	1	-	4
Asset impairment charges	(5)	-	(14)	-
Net interest expense	(54)	(49)	(151)	(130)
Earnings before income taxes	70	50	399	176
Income tax expense (recovery)	9	4	95	(7)
Net earnings	61	46	304	183
Non-controlling interests	7	6	27	20
Net earnings attributable to TransAlta shareholders	54	40	277	163
Preferred share dividends	4	-	11	-
Net earnings attributable to common shareholders	50	40	266	163

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 results from prior periods. Earnings on a comparable basis per share are calculated using the weighted average common shares outstanding during the period.

In calculating comparable earnings for 2011, we exclude the impact related to certain power hedging relationships deemed ineffective for accounting purposes, as these transactions are unusual in nature and have not historically been a normal occurrence in the course of operating our business. Had these hedges not been deemed ineffective for accounting purposes, the revenues associated with these contracts would have been recorded in net earnings in the period in which they settle, the majority of which will occur during 2011 and 2012. As these gains have already been recognized in earnings in the current period, future reported earnings will be lower, however, the expected cash flows from these contracts will not change. In addition, we have excluded the gain on the sale of the Meridian facility, the write off of acquired wind development costs, the writedown of certain capital spares, and asset impairment charges as these items are not considered regular business activities.

34 TRANSALTA CORPORATION / Q3 2011


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Net earnings attributable to common shareholders	50	40	266	163
Impacts associated with certain de-designated and ineffective hedges, net of tax	7	-	(80)	-
Gain on sale of the Meridian facility, net of tax	-	-	(2)	-
Write off of wind development costs, net of tax	-	-	3	-
Writedown of capital spares, net of tax	-	-	3	-
Asset impairment charges, net of tax	4	-	11	-
Income tax recovery related to the resolution of certain outstanding tax matters	-	-	-	(30)
Earnings on a comparable basis	61	40	201	133

Weighted average number of common shares outstanding in the period	223	220	222	220
Earnings on a comparable basis per share	0.27	0.18	0.91	0.60

Comparable EBITDA

Presenting comparable EBITDA from period to period provides management and investors with a proxy for the amount of cash generated from operating activities before net interest expense, non-controlling interests, income taxes, and working capital adjustments.


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Operating income	111	85	537	288
Depreciation and amortization per the Condensed Consolidated Statements of Cash Flows⁽¹⁾	126	132	383	372
EBITDA	237	217	920	660
Impacts associated with certain de-designated and ineffective hedges, pre-tax	9	-	(125)	-
Write off of wind development costs, pre-tax	-	-	5	-
Writedown of capital spares, pre-tax	-	-	4	-
Comparable EBITDA	246	217	804	660

^{______________________________________}

(1) To calculate EBITDA, we use depreciation and amortization per the Condensed Consolidated Statements of Cash Flows in order to account for depreciation related to mine assets, which is included in fuel and purchased power on the Condensed Consolidated Statements of Earnings.

TRANSALTA CORPORATION / Q3 2011 35

Funds from Operations and Funds from Operations per Share

Presenting funds from operations and funds from operations per share from period to period provides management and investors with a proxy for the amount of cash generated from operating activities, before changes in working capital, and provides the ability to evaluate cash flow trends more readily in comparison with prior periods’ results. Funds from operations per share is calculated using the weighted average common shares outstanding during the period.


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Cash flow from operating activities	221	224	512	521
Change in non-cash operating working capital balances	(53)	(49)	108	50
Funds from operations	168	175	620	571
Weighted average number of common shares outstanding in the period	223	220	222	220
Funds from operations per share	0.75	0.80	2.79	2.60

Free Cash (Deficiency) Flow

Free cash (deficiency) flow represents the amount of cash generated by our business, before changes in working capital, that is available to invest in growth initiatives, make scheduled principal repayments of recourse debt, pay additional common share dividends, or repurchase common shares. Changes in working capital are excluded so as to not distort free cash (deficiency) flow with changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and the timing of capital projects.

Sustaining capital expenditures for the three months ended Sept. 30, 2011 represents total additions to PP&E and intangibles per the Condensed Consolidated Statements of Cash Flows less $18 million ($17 million net of joint venture contributions) that we have invested in growth projects. For the same period in 2010, we invested $115 million ($113 million net of joint venture contributions) in growth projects. For the nine months ended Sept. 30, 2011 and 2010, we invested $84 million ($83 million net of joint venture contributions) and $390 million ($383 million net of joint venture contributions), respectively, in growth projects.

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


	3 months ended Sept. 30		9 months ended Sept. 30
	2011	2010	2011	2010
Cash flow from operating activities	221	224	512	521
Add (Deduct):
Changes in working capital	(53)	(49)	108	50
Sustaining capital expenditures	(114)	(85)	(250)	(242)
Dividends paid on common shares	(48)	(49)	(143)	(169)
Dividends paid on preferred shares	(4)	-	(11)	-
Distributions paid to subsidiaries' non-controlling interests	(9)	(15)	(44)	(44)
Free cash (deficiency) flow	(7)	26	172	116

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

36 TRANSALTA CORPORATION / Q3 2011

SELECTED QUARTERLY INFORMATION


	Q4 2010	Q1 2011	Q2 2011	Q3 2011

Revenue	779	818	515	629
Net earnings attributable to common shareholders	93	204	12	50
Net earnings per share attributable to common shareholders, basic and diluted	0.42	0.92	0.05	0.22
Comparable earnings per share	0.37	0.34	0.29	0.27

	Q4 2009⁽¹⁾	Q1 2010	Q2 2010	Q3 2010

Revenue	763	696	547	651
Net earnings attributable to common shareholders	79	60	63	40
Net earnings per share attributable to common shareholders, basic and diluted	0.37	0.27	0.29	0.18
Comparable earnings per share	0.40	0.27	0.15	0.18

Basic and diluted earnings per share attributable to common shareholders and comparable earnings per share are calculated each period using the weighted average common shares outstanding during the period. As a result, the sum of the earnings per share for the four quarters making up the calendar year may sometimes differ from the annual earnings per share.

DISCLOSURE 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 covered by this report that has materially affected, or is reasonably likely to materially affect, our 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, 2011, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

^{______________________________________}

(1) Q4 2009 represents Canadian GAAP figures.

TRANSALTA CORPORATION / Q3 2011 37

FORWARD LOOKING STATEMENTS

This MD&A, the 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 and on management’s experience and perception of historical trends, current conditions and expected further developments as well as other factors deemed appropriate in the circumstances. 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 our actual performance to be materially different from those projected.

In particular, this MD&A contains forward looking statements pertaining to the following: expectations relating to the timing of the completion and commissioning of projects under development, including uprates and upgrades, and their attendant costs; expectations related to future earnings and cash flow from operating activities; estimates of fuel supply and demand conditions and the costs of procuring fuel; our plans to invest in existing and new capacity, and the expected return on those investments; expectations for demand for electricity in both the short-term and long-term, and the resulting impact on electricity prices; expectations in respect of generation availability and production; expectations in terms of the cost of operations and maintenance, and the variability of those costs; our plans to install mercury control equipment at our Alberta Thermal operations and our initiative to reduce nitrogen oxide and mercury emissions from our Centralia Plant; expected governmental regulatory regimes and legislation, as well as the cost of complying with resulting regulations and laws; our trading strategy and the risk involved in these strategies; expectations relating to the renegotiation of certain of the collective bargaining agreements to which we are party; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; expectations for the outcome of existing or potential legal and contractual claims; and expectations for the ability to access capital markets at reasonable terms.

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) effects of weather; (viii) disruptions in the source of fuels, water, wind or biomass required to operate our facilities; (ix) natural disasters; (x) equipment failure; (xi) energy trading risks; (xii) industry risk and competition; (xiii) fluctuations in the value of foreign currencies and foreign political risks; (xiv) need for additional financing; (xv) structural subordination of securities; (xvi) counterparty credit risk; (xvii) insurance coverage; (xviii) our provision for income taxes; (xix) legal and contractual proceedings involving the Corporation; (xx) reliance on key personnel (xxi) labour relations matters; and (xxii) development projects and acquisitions. The foregoing risk factors, among others, are described in further detail in the Risk Management section of our 2010 Annual Report and under the heading “Risk Factors” in our 2010 Annual Information Form.

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 occur to a different extent or at a different time than we have described, or might not occur. We cannot assure you that projected results or events will be achieved.

38 TRANSALTA CORPORATION / Q3 2011

SUPPLEMENTAL INFORMATION


		Sept. 30, 2011	Dec. 31, 2010

Closing market price (TSX) ($)		22.81	21.15

Price range for the last 12 months (TSX) ($)	High	23.13	23.98

	Low	19.45	19.61

Debt to invested capital including non recourse debt (%)		55.0	53.1

Debt to invested capital excluding non recourse debt (%)		52.7	50.7

Return on shareholders' equity (%)		13.0	9.6

Comparable return on shareholders' equity^{(1), (2)} (%)		10.2	8.0

Return on capital employed⁽¹⁾(%)		9.5	6.6

Comparable return on capital employed^{(1), (2)}(%)		8.0	6.3

Cash dividends per share⁽¹⁾ ($)		1.16	1.16

Price/comparable earnings ratio⁽¹⁾ (times)		17.8	21.8

Earnings coverage⁽¹⁾ (times)		3.0	2.2

Dividend payout ratio based on net earnings⁽¹⁾ (%)		72.3	125.1

Dividend payout ratio based on comparable earnings^{(1), (2)}(%)		92.3	149.8

Dividend payout ratio based on funds from operations^{(1), (2)}(%)		30.3	39.6

Dividend yield⁽¹⁾ (%)		5.1	5.5

Cash flow to debt⁽¹⁾ (%)		19.8	19.6

Cash flow to interest coverage⁽¹⁾ (times)		4.6	4.6

(1) Last 12 months

(2) These ratios incorporate items that are not defined under IFRS. None of these measurements should be used in isolation or as a substitute for the Corporation’s reported financial performance or position as presented in accordance with IFRS. 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. For a reconciliation of the Non-IFRS measures used in this calculation, refer to the Non-IFRS Measures section of this MD&A.

RATIO FORMULAS

Debt to invested capital = (long-term debt including current portion - cash and cash equivalents) / (debt + non-controlling interests + equity attributable to shareholders - cash and cash equivalents)

TRANSALTA CORPORATION / Q3 2011 39

Return on common shareholders’ equity = net earnings attributable to common shareholders or earnings on a comparable basis / average equity applicable to common shareholders excluding Accumulated Other Comprehensive Income (“AOCI”)

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

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

Earnings coverage = (net earnings attributable to common shareholders+ income taxes + net interest) / (interest on debt - interest income)

Dividend payout ratio = common share dividends / net earnings attributable to common shareholders or earnings on a comparable basis or funds from operations

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 debt

Cash flow to interest coverage = (cash flow from operating activities before changes in working capital + interest on debt - interest income - capitalized interest) / (interest on debt - interest income)

40 TRANSALTA CORPORATION / Q3 2011

GLOSSARY OF KEY TERMS

Alberta Power Purchase Arrangement (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.

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 energy trading activities.

TRANSALTA CORPORATION / Q3 2011 41

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

Glen Whelan

Director, Communications

Phone

403.267.7287

E-mail

Glen_Whelan@transalta.com

Investor inquiries

Jess Nieukerk

Director, 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

42 TRANSALTA CORPORATION / Q3 2011