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

EX-13.2 3 mda.htm MANAGEMENT???S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF THE REGISTRANT AS AT AND FOR THE PERIOD ENDED MARCH 31, 2011. MD Filed by Filing Services Canada Inc. (403) 717-3898

TRANSALTA CORPORATION

FIRST 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 April 25, 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 consolidated financial statements of the Corporation as at and for the three months ended March 31, 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 / Q1 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 Statements of Earnings and Statements of Financial Position items. While individual line items in the Statement 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 in the equity section of the Consolidated Statements of Financial Position.

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


3 months ended March 31	2011	2010
Availability (%)⁽¹⁾	90.3	91.4
Production (GWh)⁽¹⁾	10,104	12,914
Revenues	818	696
Gross margin⁽²⁾	608	379
Operating income⁽²⁾	359	133
Net earnings attributable to common shareholders	204	60
Net earnings per share attributable to common shareholders, basic and diluted	0.92	0.27
Comparable earnings per share⁽²⁾	0.34	0.27
Comparable EBITDA⁽²⁾	287	249
Funds from operations⁽²⁾	226	194
Funds from operations per share⁽²⁾	1.02	0.89
Cash flow from operating activities	147	171
Free cash flow⁽²⁾	99	77
Dividends paid per common share	0.29	0.29

As at	March 31, 2011	Dec. 31, 2010
Total assets	9,425	9,635
Total long-term liabilities	4,996	5,009

AVAILABILITY & PRODUCTION

Availability for the three months ended March 31, 2011 decreased compared to the same period in 2010 primarily due to higher unplanned outages at the Alberta Coal PPA facilities and higher planned outages at Centralia Thermal, being partially offset by lower unplanned outages at Centralia Thermal.

Production for the three months ended March 31, 2011 decreased 2,810 gigawatt hours (“GWh”) compared to the same period in 2010 due to economic dispatching at Centralia Thermal of 1,718 GWh, higher unplanned outages at the Alberta Coal PPA facilities, primarily related to the shutdown of our Sundance Units 1 and 2, the decommissioning of Wabamun, and the sale of the Meridian facility.

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NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

The primary factors contributing to the change in net earnings attributable to common shareholders for the three months ended March 31, 2011 are presented below:


	3 months ended March 31
Net earnings attributable to common shareholders, 2010	60
Increase in Generation gross margins	28
Mark-to-market movements - Generation	200
Increase in Energy Trading gross margins	1
Decrease in operations, maintenance, and administrative costs	6
Increase in depreciation expense	(8)
Increase in net interest expense	(1)
Decrease in equity loss	4
Increase in income tax expense	(73)
Increase in net earnings attributable to non-controlling interests	(6)
Increase in preferred share dividends	(4)
Other	(3)
Net earnings attributable to common shareholders, 2011	204

Generation gross margins, excluding the impact of mark-to-market movements, increased compared to the same period in 2010 primarily due to favourable pricing, higher hydro margins, and higher wind volumes, partially offset by the decommissioning of Wabamun and lower recoveries as we are no longer operating the Poplar Creek base plant.

Mark-to-market movements increased for the three months ended March 31, 2011 compared to the same period in 2010 primarily due to the recognition of unrealized gains resulting from certain power hedging relationships being deemed ineffective for accounting purposes primarily due to increased economic dispatching at Centralia Thermal.

Energy Trading gross margins increased for the three months ended March 31, 2011 compared to the same period in 2010 due to better results in Alberta and Eastern Canada, driven by reduced generation, cold weather, and transmission congestion.

Operations, maintenance, and administration (“OM&A”) costs for the three months ended March 31, 2011 decreased compared to the same period in 2010 primarily due to lower costs as we are no longer operating the Poplar Creek base plant, partially offset by costs associated with several productivity initiatives.

Depreciation expense for the three months ended March 31, 2011 increased compared to the same period in 2010 primarily due to an increased asset base and the impact of the reduction in Wabamun decommissioning costs during the first three months of 2010, partially offset by changes to estimated residual values and the sale of Meridian.

Net interest expense for the three months ended March 31, 2011 increased compared to the same period in 2010 due to higher debt levels and interest rates, partially offset by higher capitalized interest.

Equity loss for the three months ended March 31, 2011 decreased compared to the same period in 2010 primarily due to lower unplanned outages and the realization of a gain on sale of a property, partially offset by lower income tax recoveries and unfavourable foreign exchange rates.

Income tax expense for the three months ended March 31, 2011 increased compared to the same period in 2010 due to higher pre-tax earnings and the higher U.S. tax rate on the recognition of unrealized gains resulting from ineffectiveness of hedging relationships due to increased economic dispatching at Centralia Thermal.

Net earnings attributable to non-controlling interests for the three months ended March 31, 2011 increased compared to the same period in 2010 due to higher earnings at TransAlta Cogeneration, L.P. (“TA Cogen”).

TRANSALTA CORPORATION / Q1 2011 3

Preferred share dividends for the three months ended March 31, 2011 increased compared to the same period in 2010 due to issuance of preferred shares in the fourth quarter of 2010.

FUNDS FROM OPERATIONS AND FREE CASH FLOW

Funds from operations for the three months ended March 31, 2011 increased $32 million compared to the same period in 2010 primarily due to higher net earnings, partially offset by higher unrealized after tax gains related to hedging relationships deemed ineffective for accounting purposes.

Free cash flow for the three months ended March 31, 2011 increased $22 million compared to the same period in 2010 due to the increase in funds from operations, driven from higher earnings. Higher sustaining capital expenditures were largely offset by lower common share dividends paid in cash, as a result of the Dividend Reinvestment and Share Purchase (“DRASP”) Plan.

SIGNIFICANT EVENTS

Three months ended March 31, 2011

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 66 megawatt (“MW”) New Richmond wind project located on the Gaspé Peninsula. New Richmond is contracted under a 20-year Power Purchase 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.

Centralia Coal

On March 5, 2011, the Washington State Senate passed the TransAlta Energy Transition Bill (“the Bill”) that reflects the agreement reached with the Governor's office, state legislators, and local environmental groups to establish a transition plan that would allow the Centralia Coal plant to run until 2025.

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, 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 5 years and Washington State Utilities that enter into contracts with Centralia 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.

4 TRANSALTA CORPORATION / Q1 2011

On April 11, 2011, the Bill was passed by the Washington State House of Representatives. Because the Bill was amended in the House Environment and Capital Budget Committees, it was voted on again by the Senate on April 21, 2011 and passed. It must now be signed into Law by the Governor no later than May 14, 2011. 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.

Sundance Units 1 and 2 Outage

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 1,210 GWh, were unavailable for the three months ended March 31, 2011.

Under the terms of the Alberta Power Purchase Arrangement (“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.

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.

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.

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. We remain committed to continuing to work with the PPA Buyer and the Balancing Pool under the processes established within the PPA.

Change in Estimated Residual Values

During the three months ended March 31, 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 $3 million for the three months ended March 31, 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.

TRANSALTA CORPORATION / Q1 2011 5

SUBSEQUENT EVENTS

Sale of Meridian

On April 1, 2011, TA Cogen, a subsidiary that is owned 50.01 per cent by TransAlta, completed the sale of its 50 per cent interest in the Meridian facility. The sale was effective Jan. 1, 2011. The impact of this transaction on our net earnings is not expected to be significant.

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 months ended March 31, 2011 and 2010 in our three major markets are shown in the following graphs.

[mda004.gif]

For the three months ended March 31, 2011, average spot prices increased in Alberta, decreased in the Pacific Northwest, and remained relatively unchanged in Ontario, compared to the same period in 2010. In Alberta, stronger demand and reduced supply offset lower natural gas prices. In the Pacific Northwest, lower natural gas prices and increased hydro generation, with water levels at a 40 year high, resulted in lower prices. In Ontario, lower natural gas prices were offset by higher demand.

6 TRANSALTA CORPORATION / Q1 2011

During the first quarter of 2011, our consolidated power portfolio was 90 per cent 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.

[mda006.gif]

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

For the three months ended March 31, 2011, average spark spreads increased in Alberta and Ontario compared to the same period in 2010 due to colder weather and demand growth. For the three months ended March 31, 2011, average spark spreads decreased in the Pacific Northwest compared to the same period in 2010 due to increased generation from hydro and wind resources in the region.

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.

TRANSALTA CORPORATION / Q1 2011 7

GENERATION OPERATIONS: At March 31, 2011, these generating assets had 7,943 MW of gross generating capacity⁽¹⁾ in operation (7,601 MW net ownership interest) and 371 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 March 31	Total	Comparable adjustments⁽²⁾	Comparable Total⁽²⁾	Per installed MWh	Total	Per installed MWh
Revenues	803	(199)	604	35.20	682	35.86
Fuel and purchased power	210	-	210	12.24	317	16.68
Gross margin	593	(199)	394	22.96	365	19.18
Operations, maintenance, and administration	100	-	100	5.83	111	5.84
Depreciation and amortization	109	-	109	6.35	101	5.31
Taxes, other than income taxes	7	-	7	0.41	6	0.32
Intersegment cost allocation	2	-	2	0.12	1	0.05
Operating expenses	218	-	218	12.71	219	11.52
Operating income	375	(199)	176	10.25	146	7.66
Installed capacity (GWh)	17,157		17,157		19,016
Production (GWh)	9,559		9,559		12,362
Availability (%)	90.2		90.2		91.3

(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) Amounts represent comparable figures.

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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 March 31, 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	5,546	6,366	204	59	145	32.05	9.27	22.78
Gas	742	823	38	9	29	46.17	10.94	35.23
Renewables	711	2,840	51	3	48	17.96	1.06	16.90
Total Western Canada	6,999	10,029	293	71	222	29.22	7.08	22.14

Gas	1,006	1,620	117	65	52	72.22	40.12	32.10
Renewables	410	1,428	39	2	37	27.31	1.40	25.91
Total Eastern Canada	1,416	3,048	156	67	89	51.18	21.98	29.20

Coal	816	2,896	125	62	63	43.16	21.41	21.75
Gas	328	1,184	30	10	20	25.34	8.45	16.89
Total International	1,144	4,080	155	72	83	37.99	17.65	20.34

	9,559	17,157	604	210	394	35.20	12.24	22.96


3 months ended March 31, 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	6,823	8,178	199	60	139	24.33	7.34	16.99
Gas	874	1,006	55	24	31	54.67	23.86	30.81
Renewables	605	2,744	32	3	29	11.66	1.09	10.57
Total Western Canada	8,302	11,928	286	87	199	23.98	7.29	16.69

Gas	797	1,620	112	61	51	69.14	37.65	31.49
Renewables	334	1,310	31	-	31	23.66	-	23.66
Total Eastern Canada	1,131	2,930	143	61	82	48.81	20.82	27.99

Coal	2,578	2,974	226	154	72	75.99	51.78	24.21
Gas	351	1,184	27	15	12	22.80	12.67	10.13
Total International	2,929	4,158	253	169	84	60.85	40.64	20.21

	12,362	19,016	682	317	365	35.86	16.68	19.18

(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.

TRANSALTA CORPORATION / Q1 2011 9

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 months ended March 31, 2011 are presented below:


3 months ended March 31
		(GWh)
Production, 2010		8,302
Unplanned outages at the Alberta PPA facilities⁽¹⁾		(636)
Decommissioning of Wabamun		(473)
Sale of Meridian		(236)
Planned outages at the Alberta PPA facilities		(157)
Higher hydro volumes		77
Higher production at natural gas-fired facilities		75
Higher wind volumes		61
Higher PPA customer demand		42
Other		(56)
Production, 2011		6,999

The primary factors contributing to the change in gross margin for the three months ended March 31, 2011 are presented below:


3 months ended March 31
Gross margin, 2010		199
Higher hydro margins		21
Unplanned outages at the Alberta PPA facilities⁽²⁾		16
Favourable pricing		8
Planned outages at the Alberta PPA facilities		3
Higher wind volumes		3
Poplar Creek base plant no longer operated by TransAlta - offset in OM&A		(11)
Decommissioning of Wabamun		(10)
Sale of Meridian		(3)
Other		(4)
Gross margin, 2011		222

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.

(1) Unplanned outages at the Alberta Coal PPA facilities includes the impact of Sundance Units 1 and 2 shutdown of 984 GWh for the 3 months ended March 31, 2011 compared to the same period in 2010.

(2) Unplanned outages at the Alberta PPA facilities includes Sundance Units 1 and 2 shutdown.

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The primary factors contributing to the change in production for the three months ended March 31, 2011 are presented below:


3 months ended March 31
		(GWh)
Production, 2010		1,131
Favourable market conditions at natural gas-fired facilities		184
Higher wind volumes		100
Lower outages at at natural gas-fired facilities		26
Higher outages at wind facilities		(24)
Other		(1)
Production, 2011		1,416

The primary factors contributing to the change in gross margin for the three months ended March 31, 2011 are presented below:


3 months ended March 31
Gross margin, 2010		82
Higher wind volumes		6
Other		1
Gross margin, 2011		89

International

Our International assets consist of coal, natural gas, and hydro 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 months ended March 31, 2011 are presented below:


3 months ended March 31
		(GWh)
Production, 2010		2,929
Economic dispatching at Centralia Thermal		(1,718)
Higher planned outages at Centralia Thermal		(151)
Lower unplanned outages at Centralia Thermal		102
Other		(18)
Production, 2011		1,144

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The primary factors contributing to the change in comparable gross margin⁽¹⁾ for the three months ended March 31, 2011 are presented below:


3 months ended March 31
Comparable gross margin⁽¹⁾, 2010		84
Economic dispatching at Centralia Thermal		8
Lower production at Centralia Thermal		(3)
Unfavourable foreign exchange		(1)
Other		(5)
Comparable gross margin⁽¹⁾, 2011		83

Operations, Maintenance, and Administration Expense

OM&A costs for the three months ended March 31, 2011 decreased compared to the same period in 2010 as we are no longer operating the Poplar Creek base plant, resulting in reduced OM&A expenditures and associated cost recoveries.

Depreciation Expense

The primary factors contributing to the change in depreciation expense for the three months ended March 31, 2011 are presented below:


3 months ended March 31
Depreciation and amortization expense, 2010		101
Decommissioning costs at Wabamun		9
Increase in asset base		7
Change in residual values		(3)
Sale of Meridian		(2)
Favourable foreign exchange		(2)
Other		(1)
Depreciation and amortization expense, 2011		109

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 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 4 of our interim consolidated financial statements as at and for the three months ended March 31, 2011 for additional information regarding our finance lease.

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Fort Saskatchewan is a natural gas-fired facility that has 71 MW of gross generating capacityin operation (35 MW net ownership interest) at March 31, 2011. Key operational information related to our interest in the Fort Saskatchewan facility, which we continue to operate, is summarized below:


3 months ended March 31	2011	2010
Availability (%)	105.4	103.6
Production (GWh)	119	127

Availability for the three months ended March 31, 2011 was comparable to the same period in 2010.

Production for the three months ended March 31, 2011 decreased by 8 GWh compared to the same period in 2010 primarily due to lower customer demand.

Finance lease income for the three months ended March 31, 2011 and 2010 was $2 million.

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 have chosen to use the equity method to account for these interests to align with the requirements of IFRS 11 Joint Arrangements, expected to be finalized by the International Accounting Standards Board (“IASB”) in 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 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 loss” on the Consolidated Statements of Earnings. Please refer to Note 5 of our interim consolidated financial statements as at and for the three months ended March 31, 2011 for additional financial information regarding our equity accounted investments.

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


3 months ended March 31	2011	2010
Availability (%)	90.6	89.6
Production (GWh)
Gas	125	154
Renewables	301	271
Total production	426	425

Availability for the three months ended March 31, 2011 increased compared to the same period in 2010 due to lower unplanned outages at CE Gen facilities.

Production for the three months ended March 31, 2011 was comparable to the same period in 2010.

During the three months ended March 31, 2011, our equity loss from CE Gen and Wailuku was nil as compared to a loss of $4 million for the same period in 2010. The equity loss decreased compared to the same period in 2010 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.

TRANSALTA CORPORATION / Q1 2011 13

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 March 31	2011	2010
Gross margin	15	14
Operations, maintenance, and administration	5	4
Intersegment cost recovery	(2)	(1)
Operating expenses	3	3
Operating income	12	11

For the three months ended March 31, 2011, gross margin increased relative to the same period in 2010 due to better results in Alberta primarily from effective positions on volatile pricing brought on by generation supply issues, and in the Eastern region primarily from cold weather and transmission congestion. These gains were partially offset by lower results in the Pacific Northwest brought on by lower pricing from increased generation supply in the region.

OM&A costs for the three months ended March 31, 2011 increased over the same period in 2010 due to increased compensation costs.

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 March 31	2011	2010
Operations, maintenance, and administration	23	19
Depreciation and amortization	5	5
Operating expenses	28	24

For the three months ended March 31, 2011, OM&A costs increased compared to the same period in 2010 as a result of costs associated with several productivity initiatives.

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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 March 31	2011	2010
Interest on debt	55	53
Capitalized interest	(11)	(9)
Interest expense	44	44
Accretion of discount on provisions	5	4
Net interest expense	49	48

The change in net interest expense for the three months ended March 31, 2011, compared to the same period in 2010 is shown below:


	3 months ended March 31
Net interest expense, 2010		48
Higher debt levels		2
Higher interest rates		2
Higher capitalized interest		(2)
Favourable foreign exchange		(1)
Net interest expense, 2011		49

INCOME TAXES

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


3 months ended March 31	2011	2010
Earnings before income taxes	313	86
Income attributable to non-controlling interests	(13)	(7)
Equity loss	-	4
Impacts associated with certain de-designated and ineffective hedges	(199)	-
Earnings attributable to TransAlta shareholders excluding non-comparable items subject to tax	101	83
Income tax expense	92	19
Income tax expense related to impacts associated with certain de-designated and ineffective hedges	(70)	-
Income tax expense excluding non-comparable items	22	19
Effective tax rate on earnings attributable to TransAlta shareholders excluding non-comparable items and income taxes (%)	22	23

The income tax expense excluding non-comparable items for the three months ended March 31, 2011 increased compared to the same period in 2010 due to higher comparable earnings.

TRANSALTA CORPORATION / Q1 2011 15

The effective tax rate on earnings attributable to TransAlta shareholders, excluding non-comparable items, for the three months ended March 31, 2011 decreased 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 months ended March 31, 2011 increased $6 million compared to the same period in 2010 due to higher earnings at TA Cogen.

FINANCIAL POSITION

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


	Increase/
	(Decrease)	Primary factors explaining change
Accounts receivable	(113)	Timing of customer receipts and lower revenues
Prepaid expenses	17	Prepayments of annual insurance premiums
Inventory	32	Lower production at our coal facilities
Property, plant, and equipment, net	(60)	Depreciation and unfavourable foreign exchange impacts, partially offset by capital additions
Deferred income tax assets	(18)	Tax effect on changes in risk management assets and liabilities
Risk management assets (current and long-term)	(61)	Price movements and changes in underlying positions
Accounts payable and accrued liabilities	(157)	Timing of payments and lower capital accruals
Collateral received	(19)	Reduction in collateral received from counterparties associated with changes in forward prices
Dividends payable	(63)	Timing of common share dividend declarations
Long-term debt (including current portion)	(33)	Increase in borrowings under credit facilities, offset by favourable foreign exchange rate impacts
Risk management liabilities (current and long-term)	60	Price movements and changes in underlying positions
Equity attributable to shareholders	14	Increase in net earnings, offset by movements in AOCI

FINANCIAL INSTRUMENTS

Refer to Note 7 of the notes to the consolidated financial statements within our 2010 Annual Report and Note 9 of our interim consolidated financial statements as at and for the three months ended March 31, 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.

16 TRANSALTA CORPORATION / Q1 2011

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

As a result of our acquisition of 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 March 31, 2011, Level III financial instruments had a net liability carrying value of $39 million (Dec. 31, 2010 – $20 million).

During the three months ended March 31, 2011, net unrealized pre-tax gains of $206 million were recognized in earnings due to certain power hedging relationships being deemed ineffective for accounting purposes primarily due to increased economic dispatching at Centralia Thermal. 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.

STATEMENTS OF CASH FLOWS

Our transition to IFRS changed the presentation of several items on the 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 Wailuki’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 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 / Q1 2011 17

The following charts highlight significant changes in the Consolidated Statements of Cash Flows for the three months ended
March 31, 2011 compared to the same period in 2010:


3 months ended March 31	2011	2010	Primary factors explaining change
Cash and cash equivalents, beginning of period	35	53
Provided by (used in):
Operating activities	147	171	Higher cash earnings of $32 million, offset by unfavourable changes in working capital balances of $56 million, primarily due to the timing of payments and receipts

Investing activities	(112)	(51)	$96 million decrease in collateral received from counterparties, offset by lower additions to PP&E of $34 million

Financing activities	(29)	(117)	Higher borrowings of $66 million, lower cash dividends on common shares, and a decrease in amounts paid on settlement of financial instruments
Translation of foreign currency cash	(1)	-
Cash and cash equivalents, end of period	40	56

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.

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 $4.0 billion at March 31, 2011 and $4.1 billion at Dec. 31, 2010.

Credit Facilities

At March 31, 2011, we have a total of $2.0 billion (Dec. 31, 2010 – $2.0 billion) of committed credit facilities of which $1.0 billion
(Dec. 31, 2010 – $1.1 billion) is not drawn and available, subject to customary borrowing conditions. At March 31, 2011, the $1.0 billion (Dec. 31, 2010 – $0.9 billion) of credit utilized under these facilities is comprised of actual drawings of $0.7 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 2012, 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.

18 TRANSALTA CORPORATION / Q1 2011

In addition to the $1.0 billion available under the credit facilities, we also have $40 million of cash.

Share Capital

On April 25, 2011, we had 222.0 million common shares outstanding and 12.0 million first preferred shares outstanding.

At March 31, 2011, we had 221.2 million (Dec. 31, 2010 – 220.3 million) common shares issued and outstanding. During the three months ended March 31, 2011, 0.9 million (March 31, 2010 – 0.2 million) common shares were issued for $18 million
(March 31, 2010 – $1 million). Of the 0.9 million common shares issued, 0.1 million were issued for cash proceeds of $1 million and 0.8 million were issued for $17 million under the terms of the DRASP plan.

We employ a variety of stock-based compensation to align employee and corporate objectives. At March 31, 2011, we had
2.2 million outstanding employee stock options (Dec. 31, 2010 – 2.2 million). During the three months ended March 31, 2011, a nominal number of 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 March 31, 2011, we provided letters of credit totalling $325 million (Dec. 31, 2010 – $297 million) and cash collateral of
$35 million (Dec. 31, 2010 – $27 million). These letters of credit and cash collateral secure certain amounts included on our Consolidated Statements of Financial Positions under “Risk Management Liabilities” and “Provisions”.

CLIMATE CHANGE AND THE ENVIRONMENT

On June 23, 2010, the Government of Canada announced plans to regulate GHG emissions from the coal-fired power sector. The federal election call and campaign currently underway is expected to delay the initial release of the draft regulations beyond the previously announced date of April 2011. We are in discussions with both the Governments of Canada and Alberta about the design of the proposed regulation.

In Ontario, the provincial government continues to develop its plans for a GHG regulatory framework consistent with the Western Climate Initiative (“WCI”) model. On April 12, 2011, the government announced that it intended to take more time to develop its GHG framework and would delay implementation until sometime after January, 2012, the intended start date for the WCI mechanism.

On Jan. 25, 2011, President Obama proposed a Clean Energy Standard to require that 80 per cent of the nation’s electricity come from clean energy technologies by 2035. The diverse clean energy sources could include renewables, nuclear power, efficient natural gas, and clean coal. Congressional committees are now exploring how such a goal could be achieved.

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.

TRANSALTA CORPORATION / Q1 2011 19

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 2011, power prices are expected to be higher than 2010 levels in Alberta and lower than 2010 levels in the Pacific Northwest. In the Alberta market, the longer-term fundamentals of the market remain positive and the recovery of the oil sands sector is expected to drive load growth. In the Pacific Northwest, natural gas prices remain low and the region has been, and will likely continue to be, affected by strong hydro fundamentals through the first half of 2011, negatively impacting power 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 greenhouse gas 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 instead regulation will be applied by the EPA. Each of these outcomes could create widely different results for the energy industry in the U.S., and indirectly for Canada's regulatory approach.

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

Economic Environment

The economic environment has shown signs of 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 first 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 increase during the remainder of 2011, compared to the first quarter of 2011, due to the start of operations at Keephills 3 and Bone Creek. Overall production is expected to decrease in 2011 compared to 2010 due to the shut down of Sundance Units 1 and 2 and higher economic dispatching at Centralia Thermal, partially offset by the start of commercial operations at Keephills 3 and Bone Creek, and lower planned and unplanned outages. Overall fleet availability is expected to be approximately 89 to 90 per cent in 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 first quarter, approximately 91 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.

20 TRANSALTA CORPORATION / Q1 2011

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 in 2011 due to lower tonnes mined and delivered to the thermal units.

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 be consistent with 2010.

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.

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 lower than 2010 OM&A costs, which have been restated to conform to IFRS, as a result of no longer operating the Poplar Creek base plant. The impact of reduced OM&A and associated cost recoveries resulting from no longer operating the Poplar Creek base plant is not expected to be significant to net earnings.

Energy Trading

Earnings from our Energy Trading segment are affected by prices in the market, positions taken, and the duration of those positions. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our 2011 objective is for Energy Trading to contribute between $45 million and $65 million in gross margin.

Exposure to Fluctuations in Foreign Currencies

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. dollar 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.

TRANSALTA CORPORATION / Q1 2011 21

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 monitor our exposures and obligations to ensure we have sufficient liquidity to meet our requirements.

Accounting Estimates

A number of our accounting estimates, including those outlined in Note 2Y of our notes to the unaudited interim consolidated financial statements as at and for the three months ended March 31, 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.

Income Taxes

The effective tax rate on earnings excluding non-comparable items for 2011 is expected to be approximately 17 to 22 per cent.

Capital Expenditures

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

22 TRANSALTA CORPORATION / Q1 2011

Growth Capital Expenditures

We have six significant growth capital projects that are currently in progress with targeted completion dates between Q2 2011 and Q4 2012. A summary of each of these significant projects is outlined below:¹


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

Keephills 3⁽²⁾	1,010 - 1,020	955	70 - 90	27	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	6	10 - 20	2	Q4 2012	A 23 MW efficiency uprate at our Keephills facility
Keephills Unit 2 uprate	34	6	20 - 30	-	Q4 2012	A 23 MW efficiency uprate at our Keephills facility
Bone Creek	48	55	(5) - (10)	1	Q2 2011	An 19 MW hydro facility in British Columbia
Sundance Unit 3 Uprate	27	3	10 - 15	-	Q4 2012	A 15 MW efficiency uprate at our Sundance facility
New Richmond	205	-	20 - 40	-	Q4 2012	A 66 MW wind farm in Quebec
Total growth	1,358 - 1,368	1,025	125 - 185	30

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

The capital cost estimate for Keephills 3 has increased due to testing and timing of commercial operations.

The total estimated spend for Bone Creek is less than the amount incurred to date due to expected project recoveries.

(1) Represents amounts spent as of March 31, 2011. In 2011, we also spent a combined total of $4 million on Ardenville and Kent Hills 2.

(2) Keephills 3 amounts spent as of March 31, 2011 include non-capital spend of $1 million.

TRANSALTA CORPORATION / Q1 2011 23

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	24
Productivity capital	Projects to improve power production efficiency	10 - 20	3
Mining equipment and land purchases	Expenditures related to mining equipment and land purchases	25 - 30	5
Planned maintenance	Regularly scheduled major maintenance	180 - 210	27
Total sustaining expenditures		310 - 365	59

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	27
Expensed	0 - 0	0 - 5	0 - 5	-
	105 - 130	75 - 85	180 - 215	27

	Coal	Gas and Renewables	Total
GWh lost	1,770 - 1,790	370 - 380	2,140 - 2,170	427

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.

(1) Represents amounts incurred as of March 31, 2011.

24 TRANSALTA CORPORATION / Q1 2011

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.

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 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 other comprehensive income, 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 Developers 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 consolidated financial statements as at and for the three months ended March 31, 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, March 31, and Dec. 31, 2010, respectively, and of net earnings and comprehensive income for the three and twelve months ending March 31, and Dec. 31, 2010, respectively; and information regarding the impacts of IFRS transition on our cash flows.

TRANSALTA CORPORATION / Q1 2011 25

Future Accounting Changes

I. IFRS Policies

Our interim financial statements as at and for the three months ended March 31, 2011 and 2010 and our IFRS Statements of Financial Position as at Jan.1 and Dec. 31, 2010, respectively, have been prepared using the IFRS 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 new standards 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.

II. 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 other comprehensive income 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 other comprehensive income, rather than within net earnings.

The IFRS 9 requirements are effective for annual periods beginning on or after Jan. 1, 2013, and must be applied retrospectively. Earlier adoption is permitted.

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.

26 TRANSALTA CORPORATION / Q1 2011

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 March 31	2011	2010
Revenues	818	696
Fuel and purchased power	210	317
Gross margin	608	379
Operations, maintenance, and administration	128	134
Depreciation and amortization	114	106
Taxes, other than income taxes	7	6
Operating expenses	249	246
Operating income	359	133
Finance lease income	2	2
Equity loss	-	(4)
Foreign exchange gain	1	3
Net interest expense	(49)	(48)
Earnings before non-controlling interests and income taxes	313	86
Income tax expense	92	19
Net earnings	221	67
Non-controlling interests	13	7
Net earnings attributable to TransAlta shareholders	208	60
Preferred share dividends	4	-
Net earnings attributable to common shareholders	204	60

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 comparable 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.


3 months ended March 31	2011	2010
Net earnings attributable to common shareholders	204	60
Impacts associated with certain de-designated and ineffective hedges, net of tax	(129)	-
Earnings on a comparable basis	75	60

Weighted average number of common shares outstanding in the period	221	219
Earnings on a comparable basis per share	0.34	0.27

TRANSALTA CORPORATION / Q1 2011 27

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 March 31	2011	2010
Operating income	359	133
Depreciation and amortization per the Consolidated Statements of Cash Flows⁽¹⁾	127	116
EBITDA	486	249
Impacts associated with certain de-designated and ineffective hedges, pre-tax	(199)	-
Comparable EBITDA	287	249

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 March 31	2011	2010
Cash flow from operating activities	147	171
Change in non-cash operating working capital balances	79	23
Funds from operations	226	194
Weighted average number of common shares outstanding in the period	221	219
Funds from operations per share	1.02	0.89

Free Cash Flow

Free cash flow represents the amount of cash generated by our business, before changes 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 flow with changes that are considered 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 March 31, 2011 represents total additions to PP&E and intangibles per the Consolidated Statements of Cash Flows less $33 million that we have invested in growth projects.

(1) To calculate EBITDA, we use depreciation and amortization per the 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 Consolidated Statements of Earnings.

28 TRANSALTA CORPORATION / Q1 2011

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


3 months ended March 31	2011	2010
Cash flow from operating activities	147	171
Add (Deduct):
Changes in working capital	79	23
Sustaining capital expenditures	(59)	(44)
Dividends paid on common shares	(47)	(59)
Dividends paid on preferred shares	(4)	-
Distributions paid to subsidiaries' non-controlling interests	(17)	(14)
Free cash flow	99	77

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

SELECTED QUARTERLY INFORMATION


	Q2 2010	Q3 2010	Q4 2010	Q1 2011

Revenue	548	651	778	818
Net earnings attributable to common shareholders	61	41	97	204
Net earnings per share attributable to common shareholders, basic and diluted	0.28	0.18	0.44	0.92
Comparable earnings per share	0.14	0.19	0.38	0.34

	Q2 2009⁽¹⁾	Q3 2009⁽¹⁾	Q4 2009⁽¹⁾	Q1 2010

Revenue	585	666	763	696
Net earnings (loss) attributable to common shareholders	(6)	66	79	60
Net (loss) earnings per share attributable to common shareholders, basic and diluted	(0.03)	0.34	0.37	0.27
Comparable (loss) earnings per share	(0.03)	0.34	0.40	0.27

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.

(1) Q2 2009 to Q4 2009 represent Canadian GAAP figures.

TRANSALTA CORPORATION / Q1 2011 29

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 March 31, 2011, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

FORWARD LOOKING STATEMENTS

This 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; expectations relating to the timing of the completion of the Front End Engineering Design study regarding Carbon Capture and Storage and the cost of the study; 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 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 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.

30 TRANSALTA CORPORATION / Q1 2011

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.

TRANSALTA CORPORATION / Q1 2011 31


SUPPLEMENTAL INFORMATION		March 31, 2011	Dec. 31, 2010

Closing market price (TSX) ($)		20.44	21.15

Price range for the last 12 months (TSX) ($)	High	22.89	23.98

	Low	19.61	19.61

Debt to invested capital including non recourse debt (%)		52.8	53.1

Debt to invested capital excluding non recourse debt (%)		50.3	50.7

Return on shareholders' equity (%)		14.4	9.6

Comparable return on shareholders' equity^{(1), (2)} (%)		8.2	8.0

Return on capital employed⁽¹⁾(%)		9.6	6.6

Comparable return on capital employed^{(1), (2)}(%)		6.7	6.3

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

Price/comparable earnings ratio⁽¹⁾ (times)		19.7	21.8

Earnings coverage⁽¹⁾ (times)		3.2	2.2

Dividend payout ratio based on net earnings⁽¹⁾ (%)		64.2	125.1

Dividend payout ratio based on comparable earnings^{(1), (2)}(%)		112.3	149.8

Dividend payout ratio based on funds from operations^{(1), (2)}(%)		30.6	39.6

Dividend yield⁽¹⁾ (%)		5.7	5.5

Cash flow to debt⁽¹⁾ (%)		20.7	19.6

Cash flow to interest coverage⁽¹⁾ (times)		4.7	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)

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)

32 TRANSALTA CORPORATION / Q1 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 / Q1 2011 33

TransAlta Corporation

Box 1900, Station “M”

110 - 12th Avenue S.W.

Calgary, Alberta Canada T2P 2M1

Phone

403.267.7110

Website

www.transalta.com

CIBC Mellon Trust Company

P.O. Box 7010 Adelaide Street Station

Toronto, Ontario Canada M5C 2W9

Phone

Toll-free in North America: 1.800.387.0825

Toronto or outside North America: 416.643.5500

Fax

416.643.5501

Website

www.cibcmellon.com

FOR MORE INFORMATION

Media inquiries

Bob Klager

Director, Public Affairs

Phone

403.267.7330

E-mail

Robert_Klager@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

34 TRANSALTA CORPORATION / Q1 2011