PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this annual information form (“Annual Information Form” or “AIF”) is given as at or for the year ended December 31, 2010. Amounts are expressed in Canadian dollars unless otherwise indicated. Financial information is presented in accordance with Canadian generally accepted accounting principles.

The Accounting Standards Board (“AcSB’) of the Canadian Institute of Chartered Accountants has announced that Canadian publicly accountable enterprises are required to prepare interim and annual financial statements using International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board, effective January 1, 2011. Effective January 1, 2011, TransAlta Corporation (“TransAlta” or “Corporation”) will begin reporting under IFRS. For more information on TransAlta’s conversion project, see TransAlta’s MD&A under “Future Accounting Changes – IFRS Convergence”.

SPECIAL NOTE REGARDING FORWARD LOOKING INFORMATION

This Annual Information Form, 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 TransAlta’s 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 TransAlta’s future performance and are subject to risks, uncertainties and other important factors that could cause TransAlta’s actual performance to be materially different from those projected.

In particular, this Annual Information Form 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 study regarding CCS 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; 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 a party; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; expectations for the outcome of existing or potential legal/administrative claims; and expectations for the ability to access capital markets at reasonable terms.

Factors that may adversely impact the Corporation’s 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 the Corporation operates; (iii) environmental requirements and changes in, or liabilities under, these requirements including reclamation of lands; (iv) changes in general economic conditions including interest rates; (v) operational risks involving the Corporation’s facilities, including unplanned outages at such facilities; (vi) natural disasters; (vii) equipment failure; (viii) disruptions in the transmission and distribution of electricity; (iv) effects of weather; (x) disruptions in the source of fuels, water, wind or biomass required to operate the Corporation’s facilities; (xi) 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) the Corporation’s 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 on time and expected costs. The foregoing risk factors, among others, are described in further detail under the heading “Risk Factors” in this Annual Information Form and in the documents incorporated by reference in this Annual Information Form, including the TransAlta Management’s Discussion and Analysis for the year ended December 31, 2010 (the “Annual MD&A”).

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 the Corporation does 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 the Corporation has described or might not occur. The Corporation cannot assure you that projected results or events will be achieved.

DOCUMENTS INCORPORATED BY REFERENCE

TransAlta’s Audited Consolidated Financial Statements for the year ended December 31, 2010 and the Annual MD&A are hereby specifically incorporated by reference in this Annual Information Form. Copies of these documents are available on SEDAR at www.sedar.com.

CORPORATE STRUCTURE

Name and Incorporation

TransAlta Corporation was formed by Certificate of Amalgamation issued under the Canada Business Corporations Act (the “CBCA”) on October 8, 1992. On December 31, 1992, a Certificate of Amendment was issued in connection with a plan of arrangement involving the Corporation and TransAlta Utilities Corporation (“TransAlta Utilities” or “TAU”) under the CBCA. The plan of arrangement, which was approved by shareholders on November 26, 1992, resulted in common shareholders of TransAlta Utilities exchanging their common shares for shares of TransAlta on a one for one basis. Upon completion of the arrangement, TransAlta Utilities became a wholly owned subsidiary of TransAlta. On January 1, 2009, TransAlta was again issued a Certificate of Amalgamation under the CBCA in connection with the amalgamation of TransAlta Corporation, TransAlta Utilities, TransAlta Energy Corporation (“TransAlta Energy” or “TEC”) and Keephills 3 GP Ltd. The amalgamation was completed as part of a series of transactions involving TransAlta and certain of its subsidiaries and affiliates carried out to reorganize (the “Reorganization”) TransAlta’s interest in certain of its assets.

The registered office and principal place of business of TransAlta are at 110 - 12th Avenue S.W., Calgary, Alberta, Canada, T2R 0G7.

Intercorporate Relationships

Effective January 1, 2009, the Corporation completed the Reorganization whereby the assets and business affairs of TAU and TEC (with the exception of the wind business) were transferred to TransAlta Generation Partnership, a new Alberta general partnership, whose partners are TransAlta Corporation and TransAlta Generation Ltd., a wholly owned subsidiary of TransAlta Corporation. TransAlta Generation Partnership is managed by TransAlta Corporation pursuant to the terms of the partnership agreement and a management services agreement. Immediately following the transfer of assets by TAU and TEC to TransAlta Generation Partnership, TransAlta Corporation amalgamated with TAU, TEC, and Keephills 3 GP Ltd. pursuant to the CBCA. TransAlta remains the holding entity of the various businesses of the Corporation, some of which are now held directly, in the case of certain wind assets, and some of which are now held indirectly, in the case of both the former generation assets and businesses of TAU and TEC and the assets and business of Canadian Hydro Developers, Inc. (“Canadian Hydro”). TransAlta completed its acquisition of Canadian Hydro on November 4, 2009.

As of December 31, 2010, the principal subsidiaries of the Corporation and their respective jurisdictions of formation are set out below:

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GENERAL DEVELOPMENT OF THE BUSINESS

The Corporation is organized into three business segments, Generation, Energy Trading2 and Corporate. The Generation group is responsible for constructing, operating and maintaining our electricity generation facilities. The Energy Trading group is responsible for the wholesale trading of electricity and other energy-related commodities and derivatives. It is also responsible for the management of available generating capacity as well as the fuel and transmission needs of the Generation business. Both segments are supported by a corporate group that provides finance, tax, treasury, legal, regulatory, environmental, health and safety, sustainable development, corporate communications, investor and government relations, information technology, human resources, internal audit, and other administrative support.

The significant events and conditions affecting TransAlta’s business during the three most recently completed financial years are summarized below. Certain of these events and conditions are discussed in greater detail under the heading “Business of TransAlta” in this Annual Information Form.

Recent Developments

· On February 18, 2011, the PPA Buyer for our Sundance 1 and 2 facilities provided notice that it intends to dispute our notices of force majeure and termination for destruction, which we provided under the terms of the Sundance A Power Purchase Arrangement (“PPA”). They also advised that they intend to pursue the dispute resolution process set out under the terms of the PPA. Although no assurance can be given as to the ultimate outcome of these matters, 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.

· On February 8, 2011, TransAlta issued notice of termination for destruction on its Sundance 1 and 2 coal-fired generation units under the terms of the PPA. This action was based on our determination that the physical state of the boilers is such that the units cannot be economically restored under the terms of the PPA. Under the PPA, termination for destruction permits the recovery of the net book value specified in the PPA.

· On January 4, 2011, TransAlta declared force majeure for its Sundance 1 and 2 coal-fired generation units related to boiler tube conditions. All 560 MW from Sundance 1 and 2 were at the time determined to be unavailable from December 16 and December 19 respectively, until February 15, as the units were taken offline for inspection to determine the scope of required repairs. The decision to shut down the units was made on the basis of the Alberta Boiler Safety Association (“ABSA”), which indicated that immediate shut down of the units was appropriate action and consistent with industry safety standards. The units cannot be restarted without ABSA inspection and approval. Under the terms of its PPA for these units, TransAlta notified the PPA buyer and the Balancing Pool of a force majeure event. For the duration of the force majeure period, TransAlta is entitled to receive its PPA capacity payments and is protected from having to pay penalties for the units’ lack of availability, to the extent the event meets the force majeure criteria set out in the PPA. While we believe that this event qualifies for force majeure, no assurances can be given.

· On December 20, 2010, TransAlta Cogeneration, L.P. (“TA Cogen”), a partnership that is owned indirectly 50.01 per cent by TransAlta, entered into an agreement for the sale of its 50 per cent interest in the Meridian facility. The sale is expected to close in early 2011.

Generation and Business Development

2010

· On December 6, 2010, the Corporation announced it had commissioned 123 MW from two new wind facilities, both ahead of schedule and on budget. The $135 million Ardenville wind facility, located about eight kilometres south of Fort Macleod, Alberta, involved the installation of 23 Vestas V90-3.0

2	Our Energy Trading segment was referred to as “Commercial Operations and Development” in our prior AIFs.

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MW wind turbines. The Corporation had announced plans to design, build and operate Ardenville, in southern Alberta on April 28, 2009. The facility has an installed capacity of 69 MW. Included in the capital cost of the project is the purchase of an already operational 3 MW turbine at Macleod Flats.

The $100 million expansion of the Kent Hills wind facility, located about 33 kilometres southwest of Moncton, New Brunswick, has increased the existing generation capacity of the facility by 54 MW to 150 MW with the installation of 18 Vestas V90-3.0 MW wind turbines. On January 11, 2010, the Corporation announced that it had been awarded a 25-year power purchase agreement with New Brunswick Power Distribution and Customer Service Corporation (“New Brunswick Power”) for this additional wind power. The 96 MW Kent Hills Wind Farm began commercial operation on December 31, 2008 and consisted of 32 Vestas V90-3.0 MW wind turbines. The capacity from this project is also sold under a power purchase agreement with New Brunswick Power.

· On October 29, 2010 the Corporation announced it is proceeding with the addition of a 15 MW efficiency uprate at its Sundance 3 unit in Alberta. The Sundance unit will be upgraded to 368 MW and is expected to be operational by the end of 2012. The total capital cost of the uprate is estimated at $27 million.

· On June 28, 2010, the Corporation together with Enbridge Inc. announced that Enbridge is participating in the development of Project Pioneer, Canada’s first fully-integrated carbon capture and storage (“CCS”) project involving retro-fitting a coal-fired electricity plant. Enbridge brings to Project Pioneer expertise in the design and construction of pipeline infrastructure, as well as extensive knowledge in CO2 sequestration.

· On June 7, 2010, the Corporation announced it had declared force majeure due to the mechanical failure of critical generator components at its 353 MW Sundance 3 thermal plant located in Wabamun, Alberta. The unit is expected to return to full capability after a major maintenance outage is completed in 2012 due to the 18 - 24 month lead time required to acquire a new generator stator winding.

· On April 26, 2010, the Corporation and the Governor of Washington State signed a memorandum of understanding (“MOU”), to enter discussions on an agreement to significantly reduce greenhouse gas emissions from the Centralia coal-fired plant and provide replacement capacity by 2025. The MOU set forth clear objectives and a definitive timeline to develop an agreement to transition the State to cleaner energy sources while protecting jobs and the local economy. The MOU also recognizes the need to protect the value that Centralia brings to TransAlta’s shareholders.

· On April 1, 2010, the Corporation announced that, after 54 years, it has fully retired all the units of its Wabamun power plant. On March 31, 2010, the last operating unit ended commercial operation. Over the next several years TransAlta will complete the Wabamun remediation and reclamation work as approved by the Government of Alberta.

2009

· On November 17, 2009, the Corporation hosted its second Alberta fixed price power auction, whereby customers were able to lock in wholesale power volumes for 2010 through 2013 at competitive market prices.

· On November 4, 2009, TransAlta completed the acquisition, through a wholly-owned subsidiary, of all of the issued and outstanding common shares of Canadian Hydro for aggregate cash consideration of $755.0 million. At closing of the acquisition, Canadian Hydro operated 694 MW of wind, hydro and biomass facilities in British Columbia, Alberta, Ontario and Québec and also had 18 MW under construction.

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· Effective September 30, 2009, the Corporation signed a new long-term contract with the Ontario Power Authority (the “OPA”) for the Sarnia regional natural gas cogeneration power plant. The contract is capacity based and has a term from July 1, 2009 to December 31, 2025. While the specific terms and conditions of the contract are confidential, the OPA has indicated that the agreement is in line with other similar agreements executed by the OPA.

· On May 20, 2009, the Corporation announced that it would advance a major maintenance outage on its 353 MW Sundance 3 facility from the second quarter of 2010 into the second and third quarters of 2009.

· On February 10, 2009, the Corporation reported that the 406 MW Sundance 4 facility had experienced an unplanned outage in December 2008 relating to the failure of an induced draft fan. At the time, the unit was derated to approximately 205 MW. The repair of the fan components by the original equipment manufacturer took longer than planned and, therefore, Unit 4 did not return to full service until February 23, 2009. As a result of the extended derate, first quarter production was reduced by 328 gigawatt hour (“GWh”) and net earnings declined by approximately $10 million. On April 27, 2009, the Balancing Pool, an entity established by the Government of Alberta, rejected the Corporation’s assertion that this outage should be regarded as a High Impact Low Probability Force Majeure Event. As required by the PPA legislation, the Corporation was required to pay the penalties related to the derate. The Corporation settled the issue in the third quarter and the terms of the settlement are confidential.

· On January 29, 2009, the Corporation announced that it would be proceeding with the addition of two 23 MW efficiency uprates at its Keephills plant in Alberta. Both Keephills units 1 and 2 will be upgraded to 406 MW and are expected to be operational by the end of 2012. The total capital cost of the projects is estimated to be $68 million.

2008

· On October 8, 2008, the Corporation announced the completion of the sale of its Mexican businesses to Intergen Global Ventures B.V. II for a sale price of US$303.5 million. The sale included the 252 MW natural gas/diesel combined cycle natural gas plant in Campeche, a 259 MW combined cycle natural gas plant in Chihuahua and all associated commercial arrangements.

· On May 27, 2008, the Corporation announced that, commencing in 2009, it would be constructing a 66 MW expansion at our Summerview facility in southern Alberta. The project will consist of 22 Vestas V90-3.0 MW wind turbines. The Summerview 2 facility commenced commercial operations on February 23, 2010. Total capital cost of the project was $118 million.

· On April 21, 2008, the Corporation announced a 53 MW efficiency uprate at Unit 5 of its Sundance facility. The total capital cost of the project was approximately $77 million and commercial operations commenced in November 2009.

· On April 3, 2008, TransAlta announced a partnership with Alstom LLC to develop a one million tonne/year carbon capture and storage project at one of TransAlta’s coal-fired power stations in Alberta.

· On February 20, 2008, the Corporation announced it had signed a purchase and sale agreement with Intergen Global Ventures B.V. (“Intergen”) pursuant to which Intergen agreed to pay the Corporation US$303.5 million in cash for its Mexican assets.

· On February 13, 2008, the Corporation announced that, commencing in 2009, it would be constructing a 66 MW wind generation facility in southern Alberta, consisting of 22 Vestas V90-3 MW wind turbines. The total capital cost for this Blue Trail wind power project was $113 million. The capacity from this project is sold on the Alberta Power Pool.

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Corporate Matters

2010

· On December 10, 2010, the Corporation issued $300 million principal amount of 4.60% cumulative rate reset preferred shares for net proceeds to the Corporation of $291.2 million.

· On November 28, 2010, the Corporation and the Global Carbon Capture and Storage Institute announced that Project Pioneer, the Corporation’s CCS project, has been awarded $5 million AUD funding to further CCS knowledge sharing. Project Pioneer is Canada’s first fully-integrated CCS project involving retro-fitting a coal-fired electricity plant. Project Pioneer will contribute to and access international research and leading-edge knowledge from a global CCS forum. On June 28, 2010, the Corporation together with Enbridge Inc. announced that Enbridge is participating in the development of Project Pioneer. Enbridge brings to Project Pioneer expertise in the design and construction of pipeline infrastructure as well as extensive knowledge in CO2 sequestration. On October 14, 2009, the federal and provincial governments announced that Project Pioneer, had received committed funding of more than $750 million. Joining the Corporation and Alstom as a participant in the development of Project Pioneer is Capital Power L.P. The Corporation is the managing partner of this joint government-industry partnership. The funding will also support the undertaking of a Front End Engineering and Design (“FEED”) study, expected to be completed by the end of 2011. Construction of the facility, if supported by the study, would be targeted for completion in 2015 - 18. Project Pioneer was first announced on April 3, 2008, as an agreement with Alstom Canada Inc. to develop the one million tonne/year CCS project at one of TransAlta’s coal-fired power stations in Alberta.

· On June 23, 2010, the Corporation responded to the federal government’s recent policy announcement mandating the phased end of coal-fired electricity generation in Canada. Under Ottawa’s proposal, power companies would have to close their coal-fired facilities at 45 years of age, or the end of their power purchase arrangements, whichever is later. Companies would be prohibited from making investments to extend the lives of those plants unless emission levels can be reduced to levels equivalent to those of a natural gas combined cycle plant.

· On March 12, 2010, the Corporation issued US$300 million principal amount of 6.50% senior notes maturing March 15, 2040 for net proceeds to the Corporation of US$293.3 million.

2009

· On November 18, 2009, the Corporation issued $400 million principal amount of 6.4% medium term notes maturing November 18, 2019 for net proceeds to the Corporation of $397.2 million.

· On November 13, 2009, the Corporation issued US$500 million principal amount of 4.75% senior notes maturing January 15, 2015 for net proceeds to the Corporation of US$495.9 million.

· On November 5, 2009, the Corporation completed a public offering of 20,522,500 common shares at a price of $20.10 per common share, resulting in net proceeds to the Corporation of $396.0 million.

· On October 14, 2009, the federal and provincial governments announced that the Corporation’s CCS project, Project Pioneer, had received committed funding of more than $750 million. The funding is being provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative. The funding will also support the undertaking of a FEED study. The FEED study is expected to cost $20 million: $10 million will come from the federal government; $5 million will come from the provincial government; and $5 million will come from the Corporation and the other industry partners. Construction of the facility, if supported as expected by the study, would be targeted for start-up in 2015. The Corporation is the managing partner of the joint government-industry partnership.

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BUSINESS OF TRANSALTA

Generation Business Segment

The Generation business segment is responsible for constructing, operating and maintaining the Corporation’s electricity generation facilities. The following table summarizes the Corporation’s generation facilities which are operating, under construction or under development, as at December 31, 2010. Subsequent sections provide more detailed information on facilities by geographic location and fuel type.

Western Canada
Facility	Capacity (MW) (1)	Ownership (%)	Net Capacity Ownership Interest (1)	Fuel	Revenue Source	Contract Expiry Date

Sundance(2)(3)	2,141	100	2,141	Coal	Alberta PPA / Merchant(3)	2017, 2020
Keephills (4)	812	100	812	Coal	Alberta PPA/Merchant(4)	2020
Keephills 3 (5)	450	50	225	Coal	Merchant	-
Sheerness	780	25	195	Coal	Alberta PPA	2020
Genesee 3	450	50	225	Coal	Merchant	-
Fort Saskatchewan	118	30	35	Natural gas	Long-term contract (“LTC”)	2019
Meridian	220	25	55	Natural gas	LTC	2024
Poplar Creek	356	100	356	Natural gas	LTC/Merchant	2024
Blue Trail	66	100	66	Wind	Merchant	-
Castle River (6)	44	100	44	Wind	LTC/Merchant	2011
Cowley North	20	100	20	Wind	Merchant	-
Cowley Ridge	21	100	21	Wind	Merchant	-
Macleod Flats	3	100	3	Wind	Merchant	-
McBride Lake	75	50	38	Wind	LTC	2023
Sinnott	7	100	7	Wind	Merchant	-
Soderglen	71	50	35	Wind	Merchant	-
Summerview 1 (7)	70	100	70	Wind	Merchant	-
Summerview 2	66	100	66	Wind	Merchant	-
Taylor Wind	3	100	3	Wind	Merchant	-
Ardenville	69	100	69	Wind	Merchant	-
Akolkolex	10	100	10	Hydro	LTC	2015
Barrier	13	100	13	Hydro	Alberta PPA	2020
Bearspaw	17	100	17	Hydro	Alberta PPA	2020
Belly River	3	100	3	Hydro	Merchant	-
Big Horn	120	100	120	Hydro	Alberta PPA	2020
Bone Creek (5)	19	100	19	Hydro	LTC	2031
Brazeau	355	100	355	Hydro	Alberta PPA	2020
Cascade	36	100	36	Hydro	Alberta PPA	2020
Ghost	51	100	51	Hydro	Alberta PPA	2020
Horseshoe	14	100	14	Hydro	Alberta PPA	2020
Interlakes	5	100	5	Hydro	Alberta PPA	2020
Kananaskis	19	100	19	Hydro	Alberta PPA	2020
Pingston	45	50	23	Hydro	LTC	2023
Pocaterra	15	100	15	Hydro	Alberta PPA	2013
Rundle	50	100	50	Hydro	Alberta PPA	2020
Spray	103	100	103	Hydro	Alberta PPA	2020
St. Mary	2	100	2	Hydro	Merchant	-
Taylor Hydro	13	50	6	Hydro	Merchant	-
Three Sisters	3	100	3	Hydro	Alberta PPA	2020
Upper Mamquam	25	100	25	Hydro	LTC	2025
Waterton	3	100	3	Hydro	Merchant	-
GPEC	25	100	25	Biomass	LTC	2019-2024
Total Western Canada	6,788		5,403

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Eastern Canada
Facility	Capacity (MW) (1)	Ownership (%)	Net Capacity Ownership Interest (1)	Fuel	Revenue Source	Contract Expiry Date

Mississauga	108	50	54	Natural gas	LTC	2017
Ottawa	68	50	34	Natural gas	LTC	2012
Sarnia (8)	506	100	506	Natural gas	LTC	2022-2025
Windsor	68	50	34	Natural gas	LTC/Merchant	2016
Kent Hills	150	83	125	Wind	LTC	2033-2035
Le Nordais	99	100	99	Wind	LTC	2033
Melancthon	200	100	200	Wind	LTC	2026-2028
Wolfe Island	198	100	198	Wind	LTC	2029
Appleton	1	100	1	Hydro	LTC	2011
Galetta	2	100	2	Hydro	LTC	2011
Misema	3	100	3	Hydro	LTC	2027
Moose Rapids	1	100	1	Hydro	LTC	2011
Ragged Chute	7	100	7	Hydro	LTC	2011
Total Eastern Canada	1,411		1,264

US
Facility	Capacity (MW) (1)	Ownership (%)	Net Capacity Ownership Interest (1)	Fuel	Revenue Source	Contract Expiry Date

Centralia(9)	1,340	100	1,340	Coal	Merchant	-
Centralia Natural gas	248	100	248	Natural gas	Merchant	-
Power Resource	212	50	106	Natural gas	Merchant	-
Saranac	240	37.5	90	Natural gas	Merchant	-
Yuma	50	50	25	Natural gas	LTC	2024
Imperial Valley Geothermal Facilities (10)	327	50	164	Geothermal	LTC	2016-2029
Skookumchuck (11)	1	100	1	Hydro	LTC	2020
Wailuku	10	50	5	Hydro	LTC	2023
Total US	2,428		1,979

Australia
Facility	Capacity (MW) (1)	Ownership (%)	Net Capacity Ownership Interest (1)	Fuel	Revenue Source	Contract Expiry Date

Parkeston	110	50	55	Natural gas	LTC	2016
Southern Cross(12)	245	100	245	Natural gas/Diesel	LTC	2013
Total Australia	355		300

TOTAL	10,982		8,946

Notes:
(1)	MW are rounded to the nearest whole number.
(2)	Please refer to Recent Developments in this AIF for information with respect to our Sundance 1 and 2 units.
(3)	Merchant capacity refers to 15 MW (under development), 53 MW, 53 MW and 44 MW uprates on units 3, 4, 5 and 6, respectively.
(4)	Includes two 23 MW uprates on units 1 and 2, both expected to be commercial in 2012. Merchant capacity refers to these two uprates.
(5)	These facilities are currently under development.
(6)	Includes seven additional turbines at other locations.
(7)	Comprised of two facilities.
(8)	Sarnia’s NMC has been adjusted from 575 MW due to decommissioning of equipment at the facility.
(9)	Centralia Thermal’s NMC has been reduced from 1,404 MW to reflect a lower plant output as a result of its conversion to burning Powder River Basin coal.
(10)	Comprised of ten facilities.

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(11)	This facility is used to provide a reliable water supply to TransAlta’s other generation facilities at Centralia.
(12)	Comprised of four facilities.

Canada: Western Canada

Thermal Facilities

The following table summarizes the Corporation’s Western Canadian thermal generation facilities:

Location	Province	Plant	Capacity (MW)	Ownership (%)	Commissioning Dates	Contract Expiry Date

Sundance	AB	Sundance Unit No. 1(1)	280	100	1970	2017
	AB	Sundance Unit No. 2(1)	280	100	1973	2017
	AB	Sundance Unit No. 3(2)	368	100	1976	2020
	AB	Sundance Unit No. 4	406	100	1977	2020
	AB	Sundance Unit No. 5	406	100	1978	2020
	AB	Sundance Unit No. 6	401	100	1980	2020
Keephills	AB	Keephills Unit No. 1(3)	406	100	1983	2020
	AB	Keephills Unit No. 2(3)	406	100	1984	2020
	AB	Keephills Unit No. 3(4)	450	50	2011	-
Sheerness	AB	Sheerness Unit No. 1	390	25	1986	2020
	AB	Sheerness Unit No. 2	390	25	1990	2020
Genesee	AB	Genesee 3	450	50	2005	-

Total			4,633

Notes:
(1)	Please refer to Recent Developments in this AIF for information with respect to our Sundance 1 and 2 units.
(2)	Includes a 15 MW uprate expected to be commercial in 2012.
(3)	Includes two 23 MW uprates on units 1 and 2, both expected to be commercial in 2012.
(4)	This facility is currently under development.

The Sundance and Keephills facilities (the “Alberta thermal plants”) are located approximately 70 kilometres west of Edmonton, Alberta and are owned by TransAlta. The Sheerness facility is located approximately 200 kilometres northeast of Calgary, Alberta and is jointly owned by TA Cogen, an Ontario limited partnership, and ATCO Power (2000) Ltd. (“ATCO Power”). The Genesee facility is located approximately 70 kilometres west of Edmonton, Alberta and is jointly owned by TransAlta and Capital Power. TransAlta’s thermal plants are generally base load plants, meaning that they are expected to operate for long periods of time at or near their rated capacity.

Fuel requirements for TransAlta’s Western Canadian thermal power facilities are supplied by a surface strip coal mine located in close proximity to the facilities. TransAlta owns the Highvale mine that supplies coal to the Sundance and Keephills facilities. TransAlta estimates that the recoverable coal reserves contained in this mine are expected to be sufficient to supply the anticipated requirements for the life of the facilities which it serves, including running post PPA expiry and potential plant expansion. TransAlta also owns the Whitewood mine, which formerly supplied coal to the now decommissioned Wabamum facility. The Whitewood mine is no longer in operation.

Coal for the Sheerness facility is provided from the adjacent Sheerness mine. The coal reserves of the mine are owned, leased or controlled jointly by TA Cogen, ATCO Power and Prairie Mines & Royalties Limited (“PMRL”). TA Cogen and ATCO Power have entered into coal supply agreements with PMRL, which operates the mine, to supply coal until 2026.

Coal for the Genesee 3 facility is provided from the adjacent Genesee mine. The coal reserves of the mine are owned, leased or controlled jointly by PMRL and Capital Power. The Corporation has entered into coal supply agreements with PMRL, which operates the mine, to supply coal for the life of the facility.

In February 2001, the Corporation had originally proposed a 900 MW expansion at its Keephills facility. Although the Corporation received regulatory approval to proceed with the expansion, it subsequently made an application in

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December 2004 to amend its 900 MW permit to allow for the construction of a smaller 450 MW facility using improved technology.

The Alberta Energy and Utilities Board (“AEUB”) approved the amendment and on February 1, 2006, the Corporation entered into a development agreement with Capital Power, to jointly pursue the 450 MW Keephills 3 power project. On December 18, 2006, the Corporation assigned its rights in the development agreement to K3LP, an affiliate of the Corporation. K3LP subsequently sold a 50 per cent undivided interest in the Keephills 3 power project to the EPCOR Power Development (K3) Limited Partnership (a predecessor to Capital Power) and the parties have entered into a joint venture agreement governing the continued development of the Keephills 3 power project.

On February 26, 2007, construction of the net 450 MW Keephills 3 power project was commenced. The capital cost for the project, including mine capital, is expected to be approximately $1.9 billion and is expected to be completed at the end of the second quarter of 2011. Through K3LP, TransAlta and Capital Power are equal partners in the ownership of Keephills 3, with Capital Power responsible for construction and TransAlta responsible for managing the joint venture. Upon completion, it is expected that TransAlta will operate the facility and Capital Power and TransAlta will independently dispatch and market their share of the unit’s electrical output. TransAlta will also provide coal to the facility through the Highvale mine.

Natural Gas-Fired Facilities

The following table summarizes the Corporation’s western Canadian natural gas-fired generation facilities:

Location	Province	Plant	Capacity (MW)	Ownership (%)	Commissioning Dates	Contract Expiry Date

Fort McMurray	AB	Poplar Creek	356	100	2001	2024
Fort Saskatchewan	AB	Fort Saskatchewan	118	30	1999	2019
Lloydminster	SK	Meridian	220	25	1999	2024

Total			694

The Poplar Creek plant is located in Fort McMurray, Alberta and is owned by the Corporation. This 356 MW cogeneration plant became fully operational in the first quarter of 2001 and delivers approximately 150 MW of electricity and steam to Suncor Energy Inc. (“Suncor”). Any surplus power not used by Suncor is available for sale by the Corporation to other parties, in which case Suncor is entitled to a share of that revenue, under certain conditions.

The Corporation’s interests in the Fort Saskatchewan and Meridian facilities are held through TA Cogen. See “TA Cogen” later in this AIF. The Fort Saskatchewan plant is located in Fort Saskatchewan, Alberta and is owned by TA Cogen and Strongwater Energy Ltd. The 118 MW Fort Saskatchewan natural gas-fired combined cycle cogeneration plant provides electricity and steam to Dow Chemical Canada Inc.

The Meridian plant is located in Lloydminster, Saskatchewan and is equally owned by TA Cogen and Husky Oil Operations Limited. This 220 MW cogeneration plant sells electricity to Saskatchewan Power Corporation, a Crown corporation owned by the Province of Saskatchewan. The steam produced by the Meridian Plant is sold to Husky Oil Limited to be utilized by its adjacent heavy oil upgrader.

On December 20, 2010, TA Cogen entered into an Asset Purchase Agreement to sell its 50 per cent ownership interest in the Meridian plant to Meridian Limited Partnership, an affiliate of Stanley Power Inc., the other limited partner to TA Cogen. The closing of the transaction, which is expected in early 2011, is subject to regulatory approval, the consent of Saskatchewan Power Corporation, the settlement of all matters of dispute between TA Cogen and Husky Oil Limited and its affiliates, and to the contemporaneous acquisition of Meridian Limited Partnership of the remaining 50 per cent interest in the Meridian facility from Husky Oil Limited. TA Cogen will provide transition support services to the purchaser for a period of six months following the closing.

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Hydroelectric Facilities

The following table summarizes the Corporation’s western Canadian hydroelectric facilities:

Location	Province	Plant	Capacity (MW) (1)	Ownership (%)	Commissioning Dates	Contract Expiry Date

Akolkolex River System(3)	BC	Akolkolex	10	100	1995	2015
	BC	Pingston	45	50	2003, 2004	2023
Mamquam River System(3)	BC	Upper Mamquam	25	100	2005	2025
Thompson River System	BC	Bone Creek(2)	19	100	2011	2031
Bow River System	AB	Horseshoe	14	100	1911	2020
	AB	Kananaskis	19	100	1913, 1951	2020
	AB	Ghost	51	100	1929, 1954	2020
	AB	Cascade	36	100	1942, 1957	2020
	AB	Barrier	13	100	1947	2020
	AB	Bearspaw	17	100	1954	2020
	AB	Pocaterra	15	100	1955	2013
	AB	Interlakes	5	100	1955	2020
	AB	Spray	103	100	1951, 1960	2020
	AB	Three Sisters	3	100	1951	2020
	AB	Rundle	50	100	1951, 1960	2020
North Saskatchewan	AB	Brazeau	355	100	1965, 1967	2020
River System	AB	Bighorn	120	100	1972	2020
Oldman River System(3)	AB	Belly River	3	100	1991	-
	AB	Waterton	3	100	1992	-
	AB	St. Mary	2	100	1992	-
	AB	Taylor Hydro	13	50	2000	-

Total			921

Notes:
(1)	MW are rounded to the nearest whole number.
(2)	Facility under construction reflects expected capacity and commissioning date.
(3)	These facilities are EcoPower®registered.

The Corporation’s Bow River and North Saskatchewan River System hydroelectric facilities are primarily peaking plants, meaning they are generally only operated during times of peak demand, and all output from these facilities is sold under one Alberta PPA.

Akolkolex River System

Akolkolex is a run-of-river hydroelectric facility with installed capacity of 10 MW located on the Akolkolex River, south of Revelstoke, British Columbia and is owned by the Corporation. It has been operating since 1995. The output from the facility is sold to BC Hydro.

Pingston is a run-of-river hydroelectric facility with installed capacity of 45 MW located on Pingston Creek, southwest of Revelstoke, British Columbia and down river of Akolkolex. The facility is equally owned by the Corporation and Brookfield Renewable Power Inc. and has been operating since 2003. The output from the facility is sold to BC Hydro.

Mamquam River System

Upper Mamquam is a run-of-river hydroelectric facility with installed capacity of 25 MW located on the Mamquam River, east of Squamish, British Columbia, and north of Vancouver and is owned by the Corporation. It has been operating since 2005. The output from the facility is sold to BC Hydro.

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Thompson River System

Bone Creek is a run-of-river hydroelectric facility currently under construction with expected capacity of 19 MW located on Bone Creek, north of Kamloops, near the town of Valemount, British Columbia and is owned by the Corporation. Bone Creek is expected to commence commercial operations in Q1 of 2011. The output from the facility is under contract with BC Hydro. The facility also qualifies for payments of $10/MWh until 2020 from Natural Resources Canada (“NRCan”), a division of the federal government, through the ecoEnergy for Renewable Power (“eERP”) program.

Bow River System

Horseshoe is a run-of-river hydroelectric facility with installed capacity of 14 MW located in Seebe, Alberta. The plant is owned by the Corporation and has been operating since 1911. The output from the facility is under contract with BC Hydro.

Kananaskis is a run-of-river hydroelectric facility with installed capacity of 19 MW located in Seebe, Alberta. The plant is owned by the Corporation. The plant has been operating since 1913 and was expanded in 1951 and modified again in 1994. The facility operates under an Alberta PPA.

Ghost is a hydroelectric facility with installed capacity of 51 MW located on the Bow River in Cochrane, Alberta. The plant is owned by the Corporation and has been operating since 1929. The facility operates under an Alberta PPA.

Cascade is a hydroelectric facility with installed capacity of 36 MW located on the Cascade River in Banff National Park, Alberta. The plant is owned by the Corporation and was purchased from the Government of Canada in 1941. The following year, TransAlta built a new dam and power plant to replace the original, the Corporation then added a second generating unit in 1957. The facility operates under an Alberta PPA.

Barrier is a run-of-river hydroelectric facility with installed capacity of 13 MW located in Seebe, Alberta. The plant is owned by the Corporation and has been operating since 1947. The facility operates under an Alberta PPA.

Bearspaw is a hydroelectric facility with installed capacity of 17 MW located on the Bow River in Calgary, Alberta. The plant is owned by the Corporation and has been operating since 1954. The facility operates under an Alberta PPA.

Pocaterra is a hydroelectric facility with installed capacity of 15 MW located in Kananaskis, Alberta. The plant is owned by the Corporation and has been operating since 1955. The facility operates under an Alberta PPA.

Interlakes is a hydroelectric facility with installed capacity of 5 MW located in Kananaskis, Alberta. The plant is owned by the Corporation and has been operating since 1955. The facility operates under an Alberta PPA.

Spray is a hydroelectric facility with installed capacity of 103 MW located in Canmore, Alberta on the Spray system. The plant uses water from the Spray Lakes Storage Reservoir. The plant is owned by the Corporation and has been operating since 1951. The facility operates under an Alberta PPA.

Three Sisters is a hydroelectric facility with installed capacity of 3 MW located at the base of the Three Sisters Dam in Canmore, Alberta on the Spray system. The plant uses water from the Spray Lakes Storage Reservoir. The plant is owned by the Corporation and has been operating since 1951. The facility operates under an Alberta PPA.

Rundle is a hydroelectric facility with installed capacity of 50 MW located in Canmore, Alberta on the Spray system. The plant uses water from the Spray Lakes Storage Reservoir, which was created by the Canyon Dam to the south, and the Three Sisters dam to the north. The plant is owned by the Corporation and has been operating since 1951. The facility operates under an Alberta PPA.

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North Saskatchewan River System

Brazeau is a hydroelectric facility with installed capacity of 355 MW located in Drayton Valley, Alberta. The plant is owned by the Corporation and has been operating since 1965. The facility operates under an Alberta PPA.

Bighorn is a hydroelectric facility with installed capacity of 120 MW located in Nordegg, Alberta. The plant is owned by the Corporation and has been operating since 1972. The facility operates under an Alberta PPA.

Oldman River System

Belly River is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Waterton-St. Mary Headworks Irrigation Canal System, east of the Waterton Reservoir, approximately 75 kilometres southwest of Lethbridge in southern Alberta. Due to its location along the irrigation canal, Belly River operates from April to October when water is diverted through the canal as part of the St. Mary Irrigation District Water Management Plan. Belly River has been operating since March 1991. Generation from the facility is sold in the Alberta spot market.

Waterton is a run-of-river hydroelectric facility with installed capacity of 3 MW located at the base of the Waterton Dam on the Waterton Reservoir, near Hillspring, southwest of Lethbridge, Alberta. Waterton has been operating since November 1992. Generation from the facility is sold in the Alberta spot market.

St. Mary is a run-of-river hydroelectric facility with installed capacity of 2 MW located at the base of the St. Mary Dam on the Waterton Reservoir, near Magrath, in southern Alberta. St. Mary has been operating since December 1992. Generation from the facility is sold in the Alberta spot market.

Taylor consists of separate hydroelectric and wind facilities. The hydroelectric facility (“Taylor Hydro”) is a run-of-river facility with installed capacity of 13 MW and is located adjacent to the Taylor Coulee Chute on the Waterton-St. Mary Headworks Irrigation Canal System which is owned by the Government of Alberta. Taylor Hydro has operated since May 2000, and is jointly owned by the Corporation along with Capital Power. Generation from the facility is sold in the Alberta spot market.

Wind Generation Facilities

The Corporation owns and operates approximately 1,064 MW of net wind generation capacity in twelve wind farms in western Canada, three in Ontario, one in Québec and two in New Brunswick.

Wind is not a dispatchable fuel, therefore in merchant markets, wind is not able to secure the annual average pool price. An assumption is made by TransAlta on the difference in revenue received for a generation forecast from a wind asset compared to a baseload asset. If these assumption and generation forecasts are correct, the corresponding revenue received may be reduced. Generation forecasts are based on the long-term production forecast from a site, which reflects the forty-year average climatic conditions for a site. Within one year there may be variation from this long-term average. In order to forecast the long-term average generation a number of factors which affect generation have to be assumed based on historic on-site data, such as, the blade icing, site access, wake and array losses and wind shear; the potential impact of topographical variations; and the electrical losses within the site. If these assumptions are incorrect there will be a long-term trend to under-generate, relative to the long-term forecast for the site.

As well as contracting for power, TransAlta enters into long-term and short-term contracts to sell the environmental attributes from our merchant wind and hydro facilities. These activities help to ensure earnings consistency from these assets. For 2011, TransAlta has sold approximately 76 per cent of the environmental attributes from our merchant wind facilities and 91 per cent of the environmental attributes from our merchant hydro facilities. Generally, for facilities under long-term contract, the benefit of the environmental attributes generated flow through to the contract holder.

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The following table summarizes the Corporation’s western Canadian wind generation facilities:

Location	Province	Plant	Capacity (MW) (1)	Ownership (%)	Commissioning Dates	Contract Expiry Date

Fort Macleod	AB	McBride Lake	75	50	2003	2023
Fort Macleod	AB	Macleod Flats	3	100	2004	-
Fort Macleod	AB	Ardenville	69	100	2010	-
Pincher Creek	AB	Castle River	44	100	1997-2001	2011
Pincher Creek	AB	Summerview 1	70	100	2004	-
Fort Macleod	AB	Blue Trail	66	100	2009	-
Pincher Creek	AB	Summerview 2	66	100	2010	-
Pincher Creek	AB	Cowley Ridge	21	100	1993	-
Magrath	AB	Taylor Wind	3	100	2004	-
Pincher Creek	AB	Cowley North	20	100	2001	-
Pincher Creek	AB	Sinnott	7	100	2001	-
Fort Macleod	AB	Soderglen	71	50	2006	-

Total			515

Note:
(1)	MW are rounded to the nearest whole number. The capacity listed is for 100 per cent of the facility.

McBride Lake is a 75 MW wind farm comprised of 114 Vestas V47-660 kW turbines located at Fort Macleod, Alberta. It was constructed by the Corporation and has been producing electricity since the third quarter of 2003. McBride Lake is operated by the Corporation and is owned equally by the Corporation and ENMAX Green Power Inc. The output from the facility is 100 per cent contracted in the form of a 20-year LTC with ENMAX Energy Corp. (“ENMAX”). The Corporation is also entitled to receive Wind Power Production Incentive (“WPPI”) payments from the federal government at $12/MWh in respect of the McBride Lake facility until 2013. The Corporation also owns 100 per cent of the 0.7 MW McBride Lake East facility in the same vicinity.

Macleod Flats consists of a single Vestas V90-3.0 MW turbine and is located near Fort Macleod. It was commissioned in 2004 and was purchased by TransAlta in 2009.

On November 10, 2010, the 69 MW Ardenville wind farm began commercial operations. The wind farm is located in southern Alberta, near Fort Macleod. Ardenville is comprised of 23-3.0 MW Vestas V90 turbines and the output is sold in the Alberta spot market. The capital cost of the Ardenville project was approximately $135 million, which includes the purchase of an already operational 3.0 MW turbine at Macleod Flats.

Castle River is a 40 MW wind farm comprised of 59 Vestas V47-660 kW turbines and one Vestas V44-600 kW turbine located at Pincher Creek, Alberta. The facility is 71 per cent contracted primarily to ENMAX and is the sole Green Energy® provider to the City of Calgary’s “Ride the Wind” Light Rail Transit program. The Corporation also owns and operates seven additional turbines totalling 4 MW located individually in the Cardston County and Hillspring areas of southwestern Alberta.

Summerview is a 68 MW wind farm comprised of 38-1.8MW turbines and is located approximately 15 kilometres northeast of Pincher Creek, Alberta. It was constructed by the Corporation and commenced commercial operations in 2004. The Summerview facility, together with an existing 1.8 MW turbine in the area, brings the total wind generation capacity at that location to 70 MW. The Summerview wind farm is a merchant facility but is entitled to receive WPPI payments from the federal government at $10/MWh until 2014.

Blue Trail is a 66 MW wind farm comprised of 22 Vestas V90-3.0 MW turbines located in southern Alberta which commenced commercial operations in November 2009. The total capital cost for this wind power project was $115 million. The capacity from this project is sold on the Alberta Power Pool. The Blue Trail wind farm is entitled to receive payments from NRCan, through the eERP program.

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On February 23, 2010, the Corporation announced the commissioning of the 66 MW Summerview 2 wind generation facility in southern Alberta, located northeast of Pincher Creek. The facility consists of 22 Vestas V90-3.0 MW wind turbines. The total capital costs for this expansion of the Summerview 2 wind power project was $118 million. The capacity from this project is sold in the Alberta spot market. The Summerview 2 wind farm expansion receives payments from NRCan through the eERP program.

Cowley Ridge has total installed capacity of 21 MW and is located near the towns of Cowley and Pincher Creek, in southern Alberta. Cowley Ridge and Cowley expansion are 100 per cent owned by the Corporation, and are comprised of two parts: Cowley Ridge, which became operational in 1993, and the Cowley Expansion which became operational in 1994. Generation from this facility is sold in the Alberta spot market.

Taylor has total installed capacity of 3 MW and is located adjacent to Taylor Hydro. Taylor Wind began commercial operations in December 2004 and is owned by the Corporation. Generation from this facility is sold in the Alberta spot market.

Cowley North and Sinnott have a total installed capacity of 20 MW and 7 MW at Sinnot and are located adjacent to Cowley Ridge and directly east of Cowley Ridge, respectively. Cowley North and Sinnott began operations in the fall of 2001 and are 100 per cent owned by the Corporation. Generation from this facility is sold in the Alberta spot market.

Soderglen is a 71 MW facility located in southern Alberta, southwest of Fort Macleod and 40 kilometres from the Corporation’s wind operations near Pincher Creek. This 71 MW facility is equally owned by the Corporation and Nexen Inc. The facility began commercial operations in September 2006. Generation from this facility is sold in the Alberta spot market.

Biomass Facilities

Grande Prairie is a biomass co-generation facility with an installed capacity of 25 MW and is located adjacent to Canadian Forest Products Ltd., in the city of Grande Prairie, in northern Alberta. The facility became commercially operational in 2005. Generation from this facility is sold to Canadian Forest Products Ltd., Alberta Infrastructure and the City of Grande Prairie.

Alberta PPAs

All of the Corporation’s Alberta thermal and hydroelectric facilities, other than the Genesee 3, Belly River, Waterton, St. Mary and Taylor facilities, and uprated capacity, operate under Alberta PPAs. The Alberta PPAs establish committed capacity and electrical energy generation requirements and availability targets to be achieved by each thermal plant, energy and ancillary services obligations for the hydroelectric plants, and the price at which electricity is to be supplied. The Corporation bears the risk or retains the benefit of volume variances (except for those arising from events considered to be force majeure, in the case of the thermal plants) and any change in costs (unless due to a change in law) required to maintain and operate the facilities.

Under the Alberta PPAs for the formerly regulated thermal facilities, the Corporation is exposed to electricity price risk if availability declines below contracted levels (other than as a result of outages caused by an event of force majeure). In those circumstances, the Corporation must pay a penalty for the lost availability based upon a price equal to the 30 day rolling average of Alberta’s market electricity prices. This rolling average provision attempts to mitigate price spikes that can occur as a result of sudden outages. The Corporation attempts to further mitigate this exposure by maintaining contracted and uncontracted capacity in the market, through operation and maintenance practices, and hedging activities.

The Corporation’s hydroelectric facilities, other than Belly River, Waterton, St. Mary and Taylor Hydro, are contracted on an aggregated basis through one Alberta PPA which provides for financial obligations for energy and ancillary services based on hourly targets. These targeted amounts are met by the Corporation through physical delivery or third party purchases.

The Corporation’s compensation under the Alberta PPAs is based on a pricing formula which replaced the cost of service regime that applied previously under utility regulation. Key elements of the pricing formula are the amount of common

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equity deemed to form part of the capital structure, the amount of risk premium attributable to deemed common equity and a recovery of fixed and variable costs. Common equity is deemed to be 45 per cent of total capital and the return on equity is set annually at a 4.5 per cent premium over the rate of a ten-year Government of Canada Bond.

The pricing formula includes a provision for site restoration costs for the thermal generating plants during the term of the PPA. If the costs recovered are insufficient, then the Corporation can apply to the Balancing Pool to recover the incremental portion. The Alberta PPAs include, as part of the capacity payment for hydroelectric operations, an amount for decommissioning.

The expiry dates for the Corporation’s Alberta PPAs range from 2013 to 2020. The Corporation is evaluating the economics of running assets post PPA expiry. Upon the expiry of the PPAs, and subject to any legislative limitations, which are addressed below and the Corporation’s ability to procure an extension to the operating licenses, if required, TransAlta will then be in a position to sell its electricity to the Alberta Power Pool and to third party purchasers through direct sales agreements.

The Alberta PPAs (together with legislation which applies thereto) permit the Balancing Pool, directly or indirectly as successor to the power purchaser under the Alberta PPAs, to terminate the Alberta PPAs in certain circumstances. These termination provisions are similar to those found in some PPAs entered into by government related power purchasers. The Corporation will be entitled to receive a lump sum payment in connection with any such termination, other than a termination resulting from the Corporation’s default, and will thereafter be able to sell the output from any affected facilities for its own account.

In June of 2010, the Government of Canada proposed a new regulation to deal with emissions from Canada’s fleet of coal-fired power plants. Under Ottawa’s proposal, at 45 years of age each coal-fired generating unit would have to meet a new emissions-performance standard or cease operations. The emissions standard for coal-fired facilities is expected to be equivalent to the emission performance of a combined-cycle natural gas power plant. If companies can deploy technology on their coal units to meet the new standard, then those units may operate beyond 45 years. However, if the units cannot physically meet the new emissions standard by their 45th year, then they would be required to cease operations.

TransAlta’s position is that the transition to this new regulatory framework must be done in a careful and orderly fashion to maintain the critical reliability of our electricity infrastructure. This includes working closely with both the Governments of Canada and Alberta to address transition costs, the impacts on Alberta’s PPAs, standards for emission requirements for natural gas facilities, and the mechanism for continued support of CCS as a lower-emitting generation technology.

Canada: Eastern Canada

Natural Gas-Fired Facilities

The Corporation’s Ontario natural gas-fired generating facilities are summarized in the following table:

Location	Province	Plant	Capacity (MW)	Ownership (%)	Commissioning Dates	Contract Expiry Date

Sarnia	ON	Sarnia	506	100	2003	2022-2025
Ottawa	ON	Ottawa	68	50	1992	2012
Mississauga	ON	Mississauga	108	50	1992	2017
Windsor	ON	Windsor	68	50	1996	2016

Total			750

The Sarnia plant is a combined cycle cogeneration facility which is owned by the Corporation. The Corporation acquired 135 MW of existing electric and steam generation capacity in 2002, and in March 2003 the Corporation completed construction and commissioning on a new 440 MW facility. In 2009, the Corporation decommissioned and removed a 69 MW natural gas turbine. The 506 MW Sarnia facility provides steam and electricity to nearby industrial

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facilities owned by LANXESS (formerly Bayer Inc.), Nova Chemicals (Canada) Ltd. (which in turn supplies INEOS NOVA) and Suncor Energy Products Inc. On February 15, 2006, TransAlta announced that it had signed a five-year agreement with the OPA for generation from its Sarnia facility. Subsequently, the Ontario Minister of Energy and Infrastructure directed the OPA to seek contracts with TransAlta and certain other “Early Movers” to obtain terms and conditions which are more in keeping with those contracts it is offering to new facilities. In September 2009, TransAlta concluded a contract with the OPA, effective as of July 1, 2009 and terminating on December 31, 2025, which provides more favourable terms than those previously held by the facility. In addition, the new agreement brings the combined total term contracted with the OPA to 20 years and includes provisions for the parties to share in the impact and benefit of changes in customer steam load or loss of steam customer.

The Ottawa plant is owned by TA Cogen. It is a combined cycle cogeneration facility designed to produce 68 MW of electrical energy. This capacity is sold under a long-term contract with the Ontario Electricity Financial Corporation (“OEFC”), an agency of the Province of Ontario. This agreement expires in 2012. The Ottawa plant also provides thermal energy to the member hospitals and treatment centers of the Ottawa Health Sciences Centre, National Defence Medical Centre and the Perley and Rideau Veterans’ Health Centre.

The Mississauga plant is owned by TA Cogen. It is a combined cycle cogeneration facility designed to produce 108 MW of electrical energy. This capacity is contracted under a long-term contract with the OEFC which expires in 2017. The Mississauga Plant provided cogeneration services to Boeing Canada Inc. (“Boeing”) until July 2005 at which time Boeing exercised its right under the cogeneration services agreement to no longer take and pay for cogeneration services due to the closure of its manufacturing facility. Boeing remains entitled to any steam credits based on the total plant electricity generation revenue. On or prior to each of January 1, 2013, 2018 and 2023, Boeing may give notice of its intention to continue to purchase or discontinue cogeneration services. In addition, on those same dates, Boeing has the option to require the removal of the Mississauga Plant from the leased lands or purchase the Mississauga Plant at its net salvage value.

The Windsor plant is owned by TA Cogen. It is a combined cycle cogeneration facility designed to produce 68 MW of electrical energy. Currently, 50 MW of the capacity is sold under a long-term contract to the OEFC. This agreement expires in 2016. The Windsor plant also provides thermal energy to Chrysler Canada Inc.’s minivan assembly facility in Windsor. In 2010, a new agreement was reached with the OEFC to make the plant fully dispatchable in order to sell the remaining capacity and ancillary services to the Ontario power market when it is economic to do so.

Hydroelectric Facilities

The Corporation’s Ontario hydro-electric facilities are summarized in the following table:

Location	Province	Plant	Capacity (MW) (1)	Ownership (%)	Commissioning Dates	Contract Expiry Date

Montréal River System	ON	Ragged Chute	7	100	1991	2011
Wanapiki River System	ON	Moose Rapids	1	100	1997	2011
Mississippi River System	ON	Appleton	1	100	1994	2011
Mississippi River System	ON	Galetta	2	100	1998	2011
Misema River System	ON	Misema	3	100	2003	2027

Total			14

Note:
(1)	MW are rounded to the nearest whole number.

Ragged Chute is a run-of-river hydroelectric facility with installed capacity of 7 MW located on the Montréal River, south of New Liskeard, in northern Ontario. Ragged Chute is 100 per cent owned by the Corporation. Generation from this facility is sold to Constellation Newenergy Canada, Inc. (“Constellation”). Ragged Chute has been operating since 1991.

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Moose Rapids is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Wanapiki River, near Sudbury, in northern Ontario. Moose Rapids is 100 per cent owned by the Corporation. Generation from this facility is sold to Constellation. Moose Rapids has been operating since 1997.

Appleton is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Mississippi River, near Almonte, Ontario. Appleton is 100 per cent owned by the Corporation. Generation from this facility is sold to Constellation. Appleton has been operating since 1994.

Galetta is a run-of-river hydroelectric facility with installed capacity of 2 MW also located on the Mississippi River, near Galetta, Ontario. Galetta is 100 per cent owned by the Corporation. Galetta was originally built in 1907 and was retrofitted in 1998. Generation from this facility is sold to Constellation.

Misema is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Misema River, close to Englehart, in northern Ontario. Misema is 100 per cent owned by the Corporation. Generation from this facility is sold to Constellation. Misema has been operating since 2003.

Wind Generation Facilities

The Corporation’s Ontario, Québec and New Brunswick wind generation facilities are summarized in the following table:

Location	Province	Plant	Capacity (MW) (1)	Ownership (%)	Commissioning Dates	Contract Expiry Date

Melancthon Township	ON	Melancthon I	68	100	2006	2026
Melancthon and Amaranth Townships	ON	Melancthon II	132	100	2008	2028
Kingston	ON	Wolfe Island	198	100	2009	2029
Québec	QC	Le Nordais	99	100	1999	2033
Kent Hills	NB	Kent Hills	96	83	2008	2033
Kent Hills	NB	Kent Hills Expn.	54	83	2010	2035

Total			647

Notes:
(1)	MW are rounded to the nearest whole number.

Melancthon I has total installed capacity of 68 MW and is located in Melancthon Township near Shelburne, Ontario. Melancthon I became commercially operational on March 4, 2006. Generation from this facility is sold to the Ontario Power Authority (the “OPA”).

Melancthon II is a 132 MW wind project located adjacent to Melancthon I, in Melancthon and Amaranth Townships. Melancthon II commenced commercial operations on November 24, 2008. Generation from this facility is sold to the OPA.

The Wolfe Island Wind Project is located on Wolfe Island, near Kingston, Ontario. This project’s key components include 86-2.3 MW Siemens wind turbines, low voltage collector system and a high voltage transmission system, a 34.5-40 kV transformer station, and an operations and maintenance building. This facility is owned by the Corporation, and commenced commercial operation on June 26, 2009. Generation from this facility is sold to the OPA.

Le Nordais is located at two sites: Cap-Chat with 56.25 MW of installed capacity (75 turbines); and Matane with 42.75 MW of installed capacity (57 turbines). Le Nordais is on the Gaspé Peninsula of Québec. Le Nordais began commercial operations in 1999. Production from this facility is sold to Hydro-Québec.

Kent Hills is a 96 MW project comprised of 32-3.0 MW Vestas V90 turbines located in Kent Hills, New Brunswick, and delivers power under a 25 LTC with New Brunswick Power. Natural Forces Technologies Inc. (“Natural Forces”), an

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United States

The Corporation’s generation facilities in the United States are summarized in the following table:

Location	State	Plant	Capacity (MW)	Ownership (%)	Commissioning Dates	Contract Expiry Date

Centralia	WA	Centralia Coal No. 1	670	100	1971	-
		Centralia Coal No. 2	670	100	1971	-
		Centralia Natural gas	248	100	2002	-
		Skookumchuck	1	100	1970	2020
Saranac	NY	Saranac	240	37.5	1994	-
Imperial Valley	CA	Vulcan	34	50	1986	2016
		Del Ranch	38	50	1989	2018
		Elmore	38	50	1989	2018
		Leathers	38	50	1990	2019
		CE Turbo	10	50	2000	2029
		Salton Sea I	10	50	1987	2017
		Salton Sea II	20	50	1990	2020
		Salton Sea III	50	50	1989	2019
		Salton Sea IV	40	50	1996	2026
		Salton Sea V	49	50	2000	2020
Big Springs	TX	Power Resources	212	50	1988	-
Yuma	AZ	Yuma	50	50	1994	2024
Hilo	HI	Wailuku	10	50	1993	2023

Total			2,428

Centralia

The Corporation owns a two unit 1,340 MW thermal facility and a 248 MW natural gas-fired facility in Centralia, Washington, located south of Seattle. The Corporation also owns a 1 MW hydroelectric generating facility on the Skookumchuck River near Centralia, and related assets which are used to provide water supply to TransAlta’s other generation facilities in Centralia. On December 10, 2010, TransAlta entered into an agreement with Puget Sound Energy Inc. for Skookumchuck to provide power until 2020.

The Corporation has entered into a number of medium to long-term energy sales agreements from the Centralia facility. The Corporation also sells electricity from the Centralia facility into the Western Electricity Coordinating Council and, in particular, on the spot market in the U.S. Pacific Northwest energy market. The Corporation’s strategy is to balance contracted and non contracted sales of electricity to manage production and price risk.

TransAlta also owns a coal mine adjacent to the Centralia facility. The Corporation stopped mining operations at its Centralia coal mine on November 27, 2006. Prior to that date, the Centralia mine produced approximately five to six million tons of coal annually, or approximately 70 to 85 per cent of the Centralia plant’s annual coal requirements. Although the Corporation estimates that certain coal reserves remain to be extracted, the Corporation has not yet received permits for, nor developed the new area, from which this coal could be produced. The Corporation has entered into contracts to purchase and transport coal from the Powder River Basin in Montana and Wyoming to fuel its facility until such time, if any, as it is economic to pursue the extraction of coal at its Centralia mine.

During 2009, TransAlta wrote down the mining development costs incurred with respect to the Westfield project. These costs were carried from the shutdown of the Centralia mine as the Corporation continued to develop mining plans and longer term operation performance of Centralia Thermal. As a result of these plans being put on indefinite hold, these costs were written off.

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CE Generation

TransAlta owns 50 per cent of CE Generation. CE Generation, through its subsidiaries, is primarily engaged in the development, ownership and operation of independent power production facilities in the United States using geothermal and natural gas resources. CE Generation holds a net ownership interest of approximately 385 MW in 13 facilities, having an aggregate operating capacity of 829 MW, including 327 MW of geothermal generation in California and 502 MW of natural gas-fired cogeneration in New York State, Texas and Arizona.

CE Generation affiliates operate the ten geothermal facilities located in the Imperial Valley, California. Each of the geothermal facilities sells electricity pursuant to independent, long-term contracts.

CE Generation affiliates also operate three natural gas-fired facilities in Texas, Arizona and New York State, having an aggregate generation capacity of 502 MW. The Arizona facility sells its output pursuant to long-term contracts while the Texas facility sold its output in 2009 under a tolling agreement, but has since moved to selling its output in the spot market. The New York facility operates an energy management agreement with a third party who is responsible for marketing the output from the facility and in return, the owners receive a fixed capacity payment and 80 per cent of dispatch revenue.

Wailuku

On February 17, 2006, a subsidiary of TransAlta, together with a subsidiary of MidAmerican Energy Holdings Company entered into an arrangement to purchase a 10 MW hydro facility in Hawaii to be held directly by the Wailuku Holding Company LLC. Each of TransAlta and Mid American hold a 50 per cent interest in the facility. The facility sells electricity pursuant to the terms of a 30-year long-term contract with the Hawaii Electricity Light Company.

Australia

The Corporation holds interests in Western Australia consisting of the 110 MW Parkeston generation facility through a 50/50 joint venture with NP Kalgoorlie Pty Ltd., a subsidiary of Newmont Australia Limited, and the 245 MW Southern Cross Energy natural gas and diesel generation facilities. Most of TransAlta’s generation supplies two large mining companies through long-term capacity contracts and the remaining amount of surplus energy and capacity is sold into Australia’s Wholesale Electricity Market.

Energy Trading Segment

The Energy Trading group provides a number of strategic functions to the Corporation, including the following:

· Gathering and assessing market intelligence, enabling management to more effectively engage in strategic planning and decision making for the Corporation. This includes identifying and ranking energy markets which are the most attractive to enter, and developing strategies and plans to effectively compete in each market where the Corporation operates;

· Negotiating and entering into contractual agreements with customers for the sale of output from the Corporation’s generation assets, including electricity, steam or other energy related commodities;

· Negotiating and managing fuel supply arrangements with third parties for the Corporation’s generation assets;

· Scheduling physical deliveries of natural gas supplies used to generate electricity and the electrical generation outputs from each asset to meet contractual obligations while managing the physical and financial risks associated with the generation and transmission of electrical energy, including during periods of unplanned outages;

· Managing the value of electricity output and fuel inputs from each generating asset through a variety of regional portfolio optimization strategies in both the current year and over the long-term; and

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· Recommending optimum maintenance schedules and operating levels according to current and anticipated market conditions that will maximize earnings from each of the generation assets.

Beyond these functions, the Energy Trading group derives additional revenue and earnings from the wholesale trading of electricity and other energy related commodities and derivatives.

The group seeks to manage and limit risk exposures from both financial and physical positions, as well as counterparty risks. The key risk control activities of the Energy Trading group, in conjunction with other functions of the Corporation, include credit review approval and reporting, risk measurement monitoring and reporting, validation of transactions, and trading portfolio valuation monitoring and reporting.

The Corporation uses mark to market valuation and the application of a value at risk (“VAR”) determination for risk control practices for its trading portfolios. This approach is a measure of assessing the potential trading losses that the Corporation could experience over a given time due to fluctuations in energy prices in each market. The Corporation’s policy is to actively manage and limit the group’s aggregate VAR exposure within board approved limits.

Competitive Environment

TransAlta is the largest generator of electricity in Alberta, measured by capacity, and has a significant portfolio of generation assets in the Pacific Northwest and the western U.S. The Corporation also owns and operates generating assets in British Columbia, Ontario, Québec, New Brunswick and Australia.

The Corporation expects electricity demand to grow as the current recession ends. In the long-term, most markets are expected to show growing demand for electricity; however, an increasing emphasis on efficiency may reduce future growth rates below historical levels. In addition to increased demand, many of the markets in which TransAlta participates have established renewable portfolio targets or standards that require new renewable power investments. As most forms of renewable generation also involve intermittent or uncertain levels and timing of production, higher levels of renewable generation may be accompanied by greater capacity requirements. The Corporation believes that continued and growing demand for electricity, renewable portfolio standards, and the potential of increasing amounts of renewable generation to require additional capacity may provide an opportunity to increase its generation capacity.

Alberta is Canada’s fourth largest province by population with approximately 3.72 million residents representing approximately 11 per cent of Canada’s total population. Alberta consumed approximately 71,600 GWh of electricity in 2010. As at December 8, 2010, the aggregate installed capacity of generating facilities in Alberta was approximately 12,915 MW.

British Columbia is Canada’s third largest province by population with approximately 4.53 million residents, representing approximately 13.3 per cent of Canada’s total population. In 2007, British Columbia adopted “The BC Energy Plan” which sets to “develop realistic and achievable goals for conservation, energy efficiency and clean energy”. Under the BC Energy Plan, British Columbia will be self-sufficient by 2016 with “insurance” power to supply increased demand levels.

Ontario is Canada’s largest province with approximately 13.2 million residents representing approximately 38.7 per cent of Canada’s total population. Ontario consumed approximately 142,400 GWh of electricity in 2009. Ontario Power Generation Inc., the successor to the generation business of Ontario’s former integrated electric utility, controls two thirds of Ontario’s approximately 34,557 MW of installed capacity, the balance of which is owned by municipal electric utilities and private independent power producers or industrial consumers.

Québec is Canada’s second largest province by population with approximately 7.91 million residents, representing approximately 23.2 per cent of Canada’s total population. The government in Québec has established the province’s Energy Strategy which includes up to 4,500 MW of additional hydroelectric capacity and 4,000 MW of wind capacity installed by 2015.

In New Brunswick, wholesale and industrial consumers are allowed to purchase power from either New Brunswick Power or a competing supplier. This competitive market does not extend to retail customers, businesses or small

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industries. In 2007, New Brunswick announced the Charter for Change requiring ten per cent of electricity purchases to be from renewable sources commencing in 2016.

Electrical utilities in the U.S. and Canadian Pacific Northwest are organized into the Western Electricity Coordinating Council (“WECC”). The WECC is the largest geographically of the ten regions in the North American Electric Reliability Council and is divided into four sub regions, of which Region 1 includes British Columbia, Alberta, Washington, Oregon, Idaho, Montana, Utah, Western Wyoming and Northern Nevada. This sub region is referred to as the Northwest Power Pool (“NWPP”). The WECC estimates that approximately 362,000 GWh of electricity was consumed in the NWPP in 2010. The WECC also reported an estimated aggregate electrical generating capacity of approximately 95,000 MW in the NWPP for the year ending December 31, 2010.

Australia is heavily dependent on coal for electricity, with over 80 per cent of the power produced derived from coal. Natural gas is increasingly used for electricity, especially in South Australia and Western Australia. The major reform in the Australian electricity industry involved the establishment in southern and eastern Australia of the National Electricity Market (“NEM”). In Western Australia, where TransAlta’s power assets are located, a new Wholesale Electricity Market (“WEM”) was introduced in late 2006. Total installed capacity in the WEM is about 5,000 MW, while TransAlta’s capacity in the region is approximately 300 MW. The Independent Market Operator of Western Australia estimates that there will be a 3.7 per cent annual growth in energy demand through 2020-21, and that capacity will grow to approximately 5,500 MW by 2012-13. TransAlta enjoys a solid competitive advantage in power supply to mining operations, especially remote mining operations, and has built up significant knowledge and expertise in this field.

Competitive Strengths

The Corporation believes it is well positioned to achieve its business strategy due to its competitive strengths, which include the following:

Financial strength - The Corporation has investment grade ratings from Moody’s Investor Services, Inc. (“Moody’s”), Standard & Poor’s, a division of the McGraw Hill Companies, Inc. (“S&P”) and Dominion Bond Rating Service Limited (“DBRS”).

Stable cash flow base – Through the use of Alberta PPAs, long-term contracts, and other short-term physical and financial contracts, on average, approximately 75 per cent of our capacity is contracted over the next seven years. The net revenue received under these contractual arrangements helps to minimize short-term revenue fluctuations due to the variable price of electricity.

Fuel diversity - The Corporation has a diverse mix of fuels used for the generation of electricity, including coal, natural gas, hydro, geothermal, wind and biomass. The Corporation believes that this mix reduces the impact on corporate performance in the event of external events affecting one fuel source.

Management team - The Corporation’s management team has substantial industry, international and local market experience.

Energy Trading expertise - The Corporation believes that its Energy Trading group has enhanced returns from the Corporation’s existing generation base and has allowed the Corporation to obtain more favourable pricing for uncommitted electricity, secure fuel supply on a cost effective basis and fulfill electricity delivery obligations in the event of an outage.

Ownership or control of coal supply - The Corporation owns, controls or leases extensive coal reserves in Alberta that provide a long-term and stable source of fuel for all of its thermal generation capacity in Alberta. The Corporation’s mines in Alberta contain some of the lowest sulphur coal in North America, averaging 0.25 per cent sulphur at the Highvale mine. Coal with lower sulphur content emits less sulphur dioxide when it is burned.

Wind Generation - The Corporation is the largest owner and operator of wind generation in Canada. Its management team has developed key relationships with customers, suppliers and policy makers that provide a competitive advantage in the development, operations and marketing of wind generation.

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Environment – The Corporation is a recognized leader in Sustainable Development and has taken early preventative action on a number of environmental fronts in advance of regulation.

Capital Expenditures

Capital expenditures for property and investments (including acquisitions) by TransAlta for the past five years were:

	Sustaining Capital	(1)	Growth Capital(2)	Total Capital Expenditures
2010	$308 million		$482 million	$790 million
2009	$380 million		$1,290 million	$1,670 million
2008	$465 million		$541 million	$1,006 million
2007	$371 million		$228 million	$599 million
2006	$207 million		$17 million	$224 million

Notes:
(1)	Sustaining capital includes routine and productivity expenditures, mining equipment and land purchases, equipment modifications at Centralia, and planned maintenance.
(2)	Growth capital consists primarily of expenditures for Keephills 3, the acquisition of Canadian Hydro, uprates and wind projects and for 2009 and 2010 includes joint venture contributions for the Keephills 3 dragline.

CORPORATE SEGMENT

Our Corporate Segment, which consists of 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 services, provides compliance, governance and support to our Generation and Energy Trading businesses.

ENVIRONMENTAL RISK MANAGEMENT

TransAlta is subject to federal, provincial, state and local environmental laws, regulations and guidelines concerning the generation and transmission of electrical and thermal energy and surface mining. TransAlta is committed to complying with legislative and regulatory requirements and to minimizing the environmental impact of its operations. TransAlta works with governments and the public to develop appropriate frameworks to protect the environment and to promote sustainable development.

Ongoing and Recently Passed Environmental Legislation

Changes in current environmental legislation do have, and will continue to have, an impact upon our business.

Canada

On June 23, 2010, the Government of Canada announced plans to regulate Greenhouse Gas (“GHG”) emissions from the coal-fired power sector. The proposal, if passed into law, would become effective in 2015 and require existing coal-fired plants to meet a natural gas emissions performance standard by their 45th year of operation, or the end of their PPA term, whichever is later. If the plants subject to the regulation do not meet the required performance standard by that time, they would be required to cease operations. Until then, the plants would not be subject to any federal GHG compliance costs.

The Federal Government continues with the drafting of the above regulations, and has stated its intention to release draft regulations in April 2011. The draft regulations would then be subject to consultations with provinces, industry and the public. We are in discussions with both the Governments of Canada and Alberta about the design of the proposed regulation.

The above development would provide regulatory clarity for future capital decision-making. There are some issues that will have to be resolved, including how transition costs are recovered by generators, the impacts on PPAs, standards for

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emission requirements for natural gas-fired facilities, and how CCS will continue to be supported. The effect of this proposal on the Alberta deregulated market and PPA structure must also be considered.

Additionally, work has continued on the development of a national Clean Air Management System (“CAMS”) for air pollutants. Development work is being done through collective efforts of federal and provincial governments, industry, and environmental organizations, with the goal of constructing an acceptable national structure for managing pollutants such as sulphur dioxide (“SO2”), nitrogen oxide (“NOx”) and particulates. Conceptually the system would establish baseline ambient air quality standards, industry emission standards, and mechanisms to address areas of non-compliance. It is expected that the CAMS model would default to provincial jurisdiction unless air quality problems remain unresolved. This process is expected to take several more years to complete. We are involved in the working groups and impact of CAMS on our operations, if implemented, is not evident at this time.

In Ontario, the provincial government continues to develop its plans for a GHG regulatory framework consistent with the Western Climate Initiative model, which uses a cap and trade design as the regulatory vehicle. Details of the Government of Ontario’s proposed design have not yet been released.

In Alberta, mercury capture technology was installed by the end of the year and began operating at our coal-fired plants in order to achieve compliance with the Alberta requirement to reduce mercury emissions by 70 per cent by Jan. 1, 2011. To date performance of these units is meeting the mercury reductions required.

In British Columbia, the provincial government is in the process of developing regulations for emissions trading and an offsets system under the Greenhouse Gas Reduction (Cap and Trade) Act. The system would be compatible with the Western Climate Initiative Model (“WCI”). The WCI model is a cap and trade design being developed jointly with several Canadian provinces and U.S. states, including California, to establish similar reduction targets and a common emissions trading market. Consultations are underway regarding its design, with finalization of the regulations expected in 2011. Given TransAlta’s low-carbon operations in B.C. this regulatory initiative is not expected to have any material impact on the company.

United States

In the U.S., the future direction on climate change has not been resolved. A variety of legislative proposals continue to be discussed, representing a mixture of energy-related and environmental legislation, though the dynamics and direction of the new Congress on this matter have yet to be clarified. Development of a cap and trade system for carbon is unlikely at this stage.

In the absence of legislative action, the administration is moving to regulate greenhouse gases under the Clean Air Act. Under the “tailoring rule” adopted in 2010, on July 1, 2011, the Environmental Protection Agency (“EPA”) will require certain new plants, or major modifications to existing plants, to acquire permits for GHGs. After that point, new or modified plants that otherwise trigger major source preconstruction permit thresholds would be required to employ best available technology to reduce their GHG emissions. The EPA began implementing these rules on January 2, 2011. The definition of best available technology has not yet been determined. This EPA regulation is expected to face legal challenges as well as some opposition from Congress, and may be subject to further refinement in other rulemakings.

Further, at the end of December in 2010, the EPA stated its intentions to implement New Source Performance Standards for GHGs for power plants and refineries. They would cover emissions from both new and existing sources. The regulations are expected to be completed by the end of 2012, but the EPA does not expect existing sources would be affected until 2015 or 2016. These proposed regulations have not yet been developed so their impact is unclear. Again, this initiative is expected to face legal hurdles.

In Washington, we have been working with the State government to develop a plan to reduce GHG emissions from our Centralia plant, consistent with the Governor’s Executive Order to reduce emissions by approximately 50 per cent of current levels by 2025. Discussions with the State and other stakeholders are ongoing.

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TransAlta Activities

Reducing the environmental impact of our activities has a benefit not only to our operations and financial results, but also to the communities in which we operate. We expect that increased scrutiny will be placed on environmental emissions and compliance, and we therefore have a proactive approach to minimizing risks to our results.

Our environment management programs encompass the following elements:

Renewable Power

In addition to our acquisition of Canadian Hydro, our investment in renewable power sources continues through the building or expansion of renewable power resources such as the Summerview 2, Kent Hills, and Ardenville wind farms. An increased renewable portfolio provides increased flexibility in generation and creates incremental environmental value through renewable energy certificates or in future offsets.

Environmental Controls and Efficiency

We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. We have installed mercury control equipment at our Alberta Thermal operations in 2010 in order to meet the province’s 70 per cent reduction objectives. Our new Keephills 3 plant will use supercritical combustion technology to maximize thermal efficiency, as well as SO2 capture and low NOx combustion technology.

The PPAs for our Alberta-based coal facilities contain change-in-law provisions that allow us the opportunity to recover capital and operating compliance costs from our PPA customers.

Policy Participation

We are active in policy discussions at a variety of levels of government. These stakeholder negotiations have allowed us to engage in proactive discussions with governments and industry participants to meet environmental requirements over the longer term.

CCS Development

On Oct. 14, 2009, the governments of Canada and Alberta announced that Project Pioneer, our CCS project, received committed funding of more than $750 million. This funding is provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative. The funding supports a FEED study that is expected to be completed in 2011. Once built, the prototype plant will be one of the largest CCS facilities in the world and the first to have an integrated underground storage system. The project will be designed to capture one megatonne of carbon dioxide (“CO2”) at one of our Alberta Thermal units. The CO2 will be used for enhanced oil recovery as well as injected into a permanent geological storage site. Additionally, on Nov. 28, 2010, Project Pioneer was awarded $5AUD million from the Global Carbon Capture and Storage Institute to enhance knowledge transfer from the project both nationally and globally.

In addition, we look to advance other clean energy technologies through organizations such as the Canadian Clean Coal Power Coalition which examines emerging clean combustion technologies such as gasification. We are also part of a group of companies participating in the Integrated CO2 Network to develop carbon capture and storage systems and infrastructure for Canada.

Offsets Portfolio

TransAlta maintains an offset portfolio with a variety of instruments than can be used for compliance purposes or otherwise banked or sold. We continue to examine additional emission offset opportunities that also allow us to meet emission targets at a competitive cost. We ensure that any investments in offsets will meet certification criteria in the market in which they are to be used.

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RISK FACTORS

Readers should consider carefully the risk factors set forth below as well as the other information contained and incorporated by reference in this Annual Information Form. For a further discussion of risk factors affecting TransAlta, please refer to “Risk Factors” in the Annual MD&A, which is incorporated by reference herein.

A reference herein to a material adverse effect on the Corporation means such an effect on the Corporation on its business, financial condition, results of operations, or its cash flows, as the context requires.

Changes in the price of electricity and availability of fuel supplies required to generate electricity may materially adversely affect the Corporation.

A significant portion of the Corporation’s revenues are tied, either directly or indirectly, to the market price for electricity in the markets in which the Corporation operates. Market electricity prices are impacted by a number of factors including: the strength of the economy, the available transmission capacity, the price of fuel that is used to generate electricity (and, accordingly, certain of the factors that affect the price of fuel described below); the management of generation and the amount of excess generating capacity relative to load in a particular market; the cost of controlling emissions of pollution, including potentially the cost of carbon; the structure of the particular market; and weather conditions that impact electrical load. As a result, the Corporation cannot accurately predict future electricity prices and electricity price volatility could have a material adverse effect on the Corporation.

The Corporation buys natural gas and some of its coal to supply the fuel needed to generate electricity. The Corporation could be materially adversely affected if the cost of fuel that it must buy to generate electricity increases to a greater degree than the price that it can obtain for the electricity that it sells. Several factors affect the price of fuel, many of which are beyond the Corporation’s control, including:

· prevailing market prices for fuel, including any associated transportation costs;

· global demand for energy products;

· the cost of carbon and other environmental concerns;

· weather-related disruptions affecting ability to deliver fuels or near-term demand for fuels;

· increases in the supply of energy products in the wholesale power markets;

· the extent of fuel transportation capacity or cost of fuel transportation service into the Corporation’s markets; and

· the cost of mining that, in turn, depends on various factors such as labour market pressures, equipment replacement costs and permitting.

Changes in any of these factors may increase the Corporation’s cost of producing power or decrease the amount of revenue it receives from the sale of power, which could materially adversely affect the Corporation.

The rules and regulations in the various markets in which the Corporation operates are subject to change, which may materially adversely affect the Corporation.

Certain of the markets in which the Corporation operates and intends to operate are subject to significant regulatory oversight and control. The Corporation is not able to predict whether there will be any further changes in the regulatory environment, including potential regulation of the rates allowed to be charged and the capital structure of wholesale generating companies such as the Corporation, or what the ultimate effect of a changing regulatory environment will have on its business. Existing market rules and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Corporation or its facilities which could have a material adverse effect on the Corporation. The Corporation cannot guarantee that it will be able to adapt its business in a timely manner in

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response to any changes in the regulatory regimes in which it operates, and such failure to adapt could have a material adverse effect on the Corporation.

Regulatory authorities may also from time to time investigate the Corporation’s activities in the markets in which it operates or pursues trading. Such investigations may result in sanctions or penalties which may materially affect the Corporation’s future activities or financial status.

The Corporation’s facilities are also subject to various licensing and permitting requirements in the jurisdictions in which they operate. Many of these licenses and permits need to be renewed from time to time. If the Corporation is unsuccessful in renewing such licenses or permits, or the terms of such licenses or permits are changed in a manner that is adverse to the Corporation, the Corporation could be materially adversely affected.

Any changes in the rules and regulations of provincial or state public utility commissions or other regulatory bodies in the other markets in which the Corporation competes or may compete in the future may materially adversely affect the Corporation.

Many of the Corporation’s activities and properties are subject to environmental requirements and changes in, or liabilities under these requirements, may materially adversely affect the Corporation

The Corporation’s operations are subject to federal, provincial, state and local environmental laws, regulations and guidelines, relating to the generation and transmission of electrical and thermal energy and surface mining, pertaining to pollution and protection of the environment, health and safety and governing among other things, air emissions, water usage and discharges, storage, treatment and disposal of waste and other materials and remediation of sites and land use responsibility (collectively, “environmental regulation”). These laws can impose liability for costs to investigate and remediate contamination without regard to fault and under certain circumstances liability may be joint and several, resulting in one responsible party being held responsible for the entire obligation. Environmental regulation can also impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transport, treatment and disposal of hazardous substances and waste and can impose clean up, disclosure or other responsibilities with respect to spills, releases and emissions of various substances to the environment. Environmental regulation can also require that facilities and other properties associated with the Corporation’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, there is an increasing level of environmental regulation regarding the use, treatment and discharge of water and increasing anticipation of new or additional emission regulations at a national level in Canada and the United States which may impose different compliance requirements standards on the Corporation. These various compliance standards may result in duplicate compliance and costs requirements for the Corporation or may impact our ability to operate our facilities.

To comply with environmental regulation, the Corporation must incur material capital and operating expenditures relating to environmental monitoring, emissions and effluent control equipment and processes, emissions measurement, verification and reporting, emissions fees and other compliance activities or obligations. The Corporation expects to continue to have environmental expenditures in the future. Stricter standards, new or greater regulation, increased enforcement by regulatory authorities, more extensive permitting requirements, an increase in the number and types of assets operated by the Corporation subject to environmental regulation and the implementation of provincial, state and national GHG emissions, mercury emissions or other air emissions regulation in a jurisdiction in which we operate could increase the amount of these expenditures. To the extent these expenditures cannot be passed through to our customers under our power purchase agreements, including Alberta PPAs or otherwise, the costs to the Corporation could be material. In addition, compliance with environmental regulation might result in restrictions on some of the Corporation’s operations. If the Corporation does not comply with environmental regulation, regulatory agencies could seek to impose statutory, administrative and/or criminal liabilities on the Corporation or to curtail its operations and significant expenditures on compliance, new equipment or technology, reporting obligations and research and development. In addition to environmental regulation, the Corporation could also face civil liability in the event that private parties seek to impose liability on the Corporation for property damage, personal injury or other costs and losses. The Corporation cannot guarantee that lawsuits or administrative or investigative actions will not be commenced against it and otherwise affect its operations and assets. If an action is filed against the Corporation or which may otherwise affect its operations and assets, the Corporation could be required to make substantial expenditures to defend or evidence its activities or to bring the Corporation, its operations and assets into compliance, which could have a material adverse effect on the Corporation.

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A number of recent federal, provincial, state and local regulatory efforts continue to focus on potential climate change or GHG emissions regulation, and mandatory GHG reporting requirements will be effective for 2010 in both Ontario and the United States. In both Canada and the U.S., GHG legislation or alternative forms of regulation are still under development, and it is too early to determine their impacts. Mandatory GHG emissions reductions requirements are expected to impose increased costs on the Corporation, as is expected to be the case generally for thermal power producers in North America. The Corporation is subject to other air quality regulation including mercury regulation. At this time, the Corporation cannot assess the potential impact of future mercury regulation at its United States facilities. To the extent new or additional GHG, mercury or other air emission regulations may require the Corporation to incur costs that cannot be passed through to its customers under its power purchase agreements, including Alberta PPAs or otherwise, the costs could be material and have a material adverse effect on the Corporation.

The Corporation’s surface mining operations are subject to laws and regulations establishing mining, environmental protection and reclamation standards for all aspects of surface mining. As a mine owner or operator, the Corporation must obtain permits from the applicable regulatory body providing for the authorization of certain mining operations that result in a disturbance of the surface. These requirements seek to limit the adverse impacts of coal mining and more restrictive requirements may be adopted from time to time. TransAlta, as a mine owner or operator, may also be required to submit a bond or otherwise secure payment of certain long-term obligations including mine closure or reclamations costs. Surety bond costs have increased in recent years while the market terms of such bonds have generally become more unfavourable. In addition, the number of companies willing to issue surety bonds has decreased. TransAlta could be required to self fund these obligations should it be unable to renew or secure the required surety bonds for its mining operations or because it is more economic to do so.

Changes in general economic conditions may have a material adverse effect on the Corporation.

Adverse changes in general economic and market conditions could negatively impact product demand, revenue, operating costs, timing and extent of capital expenditures, the net recoverable value of plant, property and equipment, results of financing efforts, credit risk and counterparty risk, which could have a material adverse effect on the Corporation. Changes in interest rates can impact the Corporation’s borrowing costs and the capacity revenues the Corporation receives pursuant to the Alberta PPAs.

Under the government mandated Alberta PPAs pursuant to which the Corporation operates most of its thermal and hydroelectric facilities in Alberta, the Corporation is subject to certain risks, including the possibilities of penalties for unplanned outages and the burden of increased costs required to maintain and operate its generation facilities.

The majority of the Corporation’s Alberta thermal and hydroelectric generating plants operate under the Alberta PPAs which established committed capacity and electrical energy generation requirements and availability targets to be achieved by each coal-fired plant, energy and ancillary services obligations for the hydroelectric plants, and the compensation for meeting the PPA obligations. Under the Alberta PPAs applicable to coal-fired plants, in the event of an unplanned outage, other than an outage determined to be caused by force majeure, the Corporation must pay a penalty for the lost production based upon a price equal to the 30 day trailing average of Alberta market electricity prices. Consequently, an unplanned outage could have a material adverse effect on the Corporation.

The Corporation bears some of the impact of increases in its operating costs (other than increases arising as a result of a “change of law” as such term is defined in the Alberta PPAs) because the price at which the Corporation is able to receive for its capacity under the Alberta PPAs is based on a schedule of forecast fixed costs. Many of the forecast costs will be determined by indices, formulae or other means for the entire term of the Alberta PPA. The Corporation’s actual results will vary and depend on performance compared to the forecasts on which the Alberta PPAs are based. Operating costs could increase as a result of a number of factors which are beyond the Corporation’s control. A significant increase in the Corporation’s operating costs could have a material adverse effect on the Corporation.

From time to time during the term of the Alberta PPAs, issues may arise regarding the intended operation of the Alberta PPAs which may require certain provisions of the Alberta PPAs to be interpreted, and the interpretations given may not be favourable to the Corporation. In such circumstances, the Corporation could be materially adversely affected.

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The operation and maintenance of the Corporation’s facilities involves risks that may materially adversely affect the Corporation.

The operation, maintenance, refurbishment, construction and expansion of power generation facilities involve risks, including breakdown or failure of equipment or processes, fuel interruption and performance below expected levels of output or efficiency. Certain of the Corporation’s generation facilities, particularly in Alberta, were constructed many years ago and may require significant capital expenditures to maintain peak efficiency or to maintain operations. There can be no assurance that our maintenance program will be able to detect potential failures in our facilities prior to occurrence or eliminate all adverse consequences in the event of failure. In addition, weather related interference, work stoppages and other unforeseen problems may disrupt the operation and maintenance of the Corporation’s facilities and may materially adversely affect the Corporation.

The Corporation has entered into ongoing maintenance and service agreements with the manufacturers of certain critical equipment. If a manufacturer is unable or unwilling to provide satisfactory maintenance or warranty support, the Corporation may have to enter into alternative arrangements with other providers if it cannot perform the maintenance itself. These arrangements could be more expensive to the Corporation than its current arrangements and this increased expense could have a material adverse effect on the Corporation. If the Corporation is unable to enter into satisfactory alternative arrangements, the inability of the Corporation to access technical expertise or parts could have a material adverse effect on the Corporation.

While the Corporation maintains an inventory, or otherwise makes arrangements to obtain, spare parts to replace critical equipment and maintains insurance for property damage to protect against certain operating risks, these protections may not be adequate to cover lost revenues or increased expenses and penalties which could result if the Corporation is unable to operate its generation facilities at a level necessary to comply with sales contracts (including Alberta PPAs).

The Corporation may be subject to the risk that it is necessary to operate a plant at a capacity level beyond that which the Corporation has contracted to provide steam in order to fulfill a contract. In such circumstances the costs to produce the steam being sold may exceed the revenues derived therefrom.

The Corporation could be adversely affected by natural disasters or other catastrophic events.

The Corporation’s generation facilities and its operations are exposed to potential damage and partial or complete loss, resulting from environmental disasters (e.g. floods, high winds, fires and earthquakes), equipment failures and other events beyond our control. The occurrence of a significant event which disrupts the ability of the generation facilities to produce or sell power for an extended period, including events which preclude existing customers from purchasing electricity, could have a material adverse effect on the Corporation. The Corporation’s generation facilities could be exposed to effects of severe weather conditions, natural disasters and potentially catastrophic events such as a major accident or incident at the Corporation’s sites. In certain cases, there is the potential that some events may not excuse the Corporation from performing its obligations pursuant to agreements with third parties. The fact that several of the Corporation’s generation facilities are located in remote areas may make access for repair of damage difficult.

Equipment failure may have a material adverse effect on the Corporation.

There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse affect on the Corporation. Although the Corporation’s generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. In addition, there can be no assurance that any applicable insurance coverage would be adequate to protect the Corporation from material adverse effects.

The Corporation relies on transmission lines that it does not own or control, which may hinder its ability to deliver electricity.

The Corporation depends on transmission and distribution facilities that are owned and operated by utilities and other power companies to deliver the electricity the Corporation generates. An extended disruption in transmission or a failure

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in the transmission system could impact the Corporation’s ability to sell and deliver electricity, which could have a material adverse effect on the Corporation.

Variations in weather can affect demand for electricity and the Corporation’s ability to generate electricity.

By the nature of the Corporation’s business, the Corporation’s earnings are sensitive to weather variations from period to period. Variations in winter weather affect the demand for electrical heating requirements. Variations in summer weather affect the demand for electrical cooling requirements. These variations in demand translate into spot market price volatility. Variations in precipitation also affect water supplies, which in turn affect the Corporation’s hydroelectric assets.

The Corporation may be adversely affected if its supply of water is materially reduced.

Hydroelectric, natural gas, biomass and coal-fired plants require continuous water flow for their operation. Shifts in weather or climate patterns, seasonable precipitation, the timing and rate of melting, run off, and other factors beyond the control of the Corporation, may reduce the water flow to the Corporation’s facilities. Any material reduction in the water flow to the Corporation’s facilities would limit the Corporation’s ability to produce and market electricity from these facilities and could have a material adverse effect on the Corporation. There is an increasing level of regulation respecting the use, treatment and discharge of water, and respecting the licensing of water rights in jurisdictions where the Corporation operates. Any such change in regulations could have a material adverse effect on the Corporation.

Dam failures may result in lost generating capacity, increased maintenance and repair costs and other liabilities.

The occurrence of dam failures at any of our hydroelectric facilities could result in a loss of generating capacity, and repairing such failures could require us to incur significant expenditures of capital and other resources. If such failures occur, we could be exposed to significant liability for damages. There can be no assurance that our dam safety program will be able to detect potential dam failures prior to occurrence or eliminate all adverse consequences in the event of failure. Other safety regulations could change from time to time, potentially impacting our costs and operations. Upgrading all dams to enable them to withstand more severe events could require us to incur significant expenditures of capital and other resources. The consequences of dam failures could have a material adverse effect on the Corporation. We attempt to manage this risk by following preventative maintenance procedures and obtaining insurance coverage, however, in the event of a sufficiently large dam failure, insurance coverage may not be adequate and we may suffer a material adverse effect.

Variation in wind levels may negatively impact the amount of electricity generated at the Corporation’s wind facilities.

Wind is naturally variable. Therefore, the level of electricity production from our wind facilities will also be variable. In addition, the strength and consistency of the wind resource at our wind facilities may vary from what we anticipate due to a number of factors including: the extent to which our site-specific historic wind data and wind forecasts accurately reflects actual long-term wind speeds, strength and consistency; the potential impact of climatic factors; the accuracy of our assumptions relating to, among other things, weather, icing and soiling of wind turbines, site access, wake and line losses and wind shear; the potential impact of topographical variations; and the potential for electricity losses to occur before delivery.

A reduced amount of wind at the location of one or more of our wind facilities over an extended period may reduce the production from such facilities, as well as any environmental attributes that accrue to the Corporation and reduce our revenues and profitability.

Disruption in fuel supply from the forest products industry could negatively impact our biomass facility.

GPEC has its full electrical capacity committed to long-term contracts, which requires consistent wood waste deliveries for fuel. These fuel deliveries are in part supplied directly from the on-site customer, with the balance delivered by truck from other customer owned facilities. Loss of the on-site supply of wood waste may result in increased fuel expense in order to continue to meet all electrical supply obligations.

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Trading risks may have a material adverse effect on the Corporation.

The Corporation’s trading and marketing business frequently involves the establishment of trading positions in the wholesale energy markets on both a medium-term and short-term basis. To the extent that the Corporation has long positions in the energy markets, a downturn in market prices will result in losses from a decline in the value of such long positions. Conversely, to the extent that the Corporation enters into forward sales contracts to deliver energy the Corporation does not own, or take short positions in the energy markets, an upturn in market prices will expose the Corporation to losses as it attempts to cover any short positions by acquiring energy in a rising market.

In addition, from time to time, the Corporation may have a trading strategy consisting of simultaneously holding a long position and a short position, from which the Corporation expects to earn a profit based on changes in the relative value of the two positions. If, however, the relative value of the two positions changes in a direction or manner the Corporation did not anticipate, it would realize losses from such a paired position.

If the strategy the Corporation uses to hedge its exposures to these various risks is not effective, it could incur significant losses. The Corporation’s trading positions can be impacted by volatility in the energy markets that, in turn, depend on various factors, including weather in various geographical areas and short-term supply and demand imbalances, which cannot be predicted with any certainty. A shift in the energy markets could adversely affect the Corporation’s positions which could also have a material adverse effect on the Corporation.

While the Corporation uses a number of risk management controls conducted by the Corporation’s independent Risk Management group to limit its exposure to risks arising from its trading activities, including value at risk, stop loss restrictions, stress testing, volumetric and term limits and restrictions on authorized instruments, the Corporation cannot guarantee that losses will not occur and such losses could have a material adverse effect on the Corporation.

The Corporation operates a highly competitive environment and may not be able to compete successfully.

We operate in a number of Canadian provinces, as well as in the United States and Australia. These areas of operation are affected by competition ranging from large utilities to small independent power producers, as well as private equity and international conglomerates. Some competitors have significantly greater financial and other resources than we do. Competitive harm could have a material adverse effect on the Corporation.

Because of the Corporation’s multinational operations, the Corporation is subject to currency rate risk and regulatory and political risk.

A significant part of the Corporation’s revenues and expenditures are in U.S. and other currencies. Fluctuations in the exchange rate between these currencies and the Canadian dollar could have a negative effect on the Corporation. While the Corporation attempts to manage this risk through its use of hedging instruments, including cross currency swaps, forward exchange contracts and by matching revenues and expenses by currency at the Corporate level, there can be no assurance that these risk management efforts will be effective and fluctuations in these exchange rates may have a material adverse effect on the Corporation.

In addition to currency rate risk, the Corporation’s foreign operations may be subject to regulatory and political risk. Any change to the regulations governing power generation or the political climate in countries where the Corporation has operations could impose additional costs and have a material adverse effect on the Corporation.

The Corporation may have difficulty raising needed capital in the future, which could significantly harm its business.

To the extent that the Corporation’s sources of cash and cash flow from operations are insufficient to fund the Corporation’s activities, it may need to raise additional funds. Additional financing may not be available when needed and, if such financing is available, it may not be available on terms favourable to the Corporation.

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The Corporation’s debt securities will be structurally subordinated to any debt of its subsidiaries that is currently outstanding or may be incurred in the future.

The Corporation operates its business through, and a majority of its assets are held by, its subsidiaries, including partnerships. The Corporation’s results of operations and ability to service indebtedness are dependent upon the results of operations of its subsidiaries and the payment of funds by these subsidiaries to it in the form of loans, dividends or otherwise. The Corporation’s subsidiaries will not have an obligation to pay amounts due pursuant to any debt securities issued by the Corporation or make any funds available for payment of debt securities issued by the Corporation, whether by dividends, interests, loans, advances or other payments. In addition, the payment of dividends and the making of loans, advances and other payments to the Corporation by its subsidiaries may be subject to statutory or contractual restrictions.

In the event of the liquidation of any subsidiary, the assets of the subsidiary would be used first to repay the indebtedness of the subsidiary, including trade payables or obligations under any guarantees, prior to being used to pay the Corporation’s indebtedness, including any debt securities issued by the Corporation. Such indebtedness and any other future indebtedness of such subsidiaries would be structurally senior to any debt securities issued by the Corporation.

The Corporation’s subsidiaries have financed some investments using non recourse project financing. Each non recourse project loan is structured to be repaid out of cash flow provided by the investment. In the event of a default under a financing agreement which is not cured, the lenders would generally have rights to the related assets. In the event of foreclosure after a default, the Corporation’s subsidiary may lose its equity in the asset or may not be entitled to any cash that the asset may generate. Although a default under a project loan will not cause a default with respect to any debt securities issued by the Corporation, it may materially affect the Corporation’s ability to service its outstanding indebtedness.

Certain of the contracts to which the Corporation is a party require the Corporation to provide collateral against its obligations.

The Corporation is exposed to risk under certain electricity and natural gas purchase and sale contracts entered into for the purposes of hedges and proprietary trading. The terms and conditions of these contracts require the Corporation to provide collateral when the fair value of these contracts is in excess of any credit limits granted by the Corporation’s counterparties and the contract obliges the Corporation to provide the collateral. The change in fair value of these contracts occurs due to changes in commodity prices. These contracts include: (i) purchase agreements, when forward commodity prices are less than contracted prices; and (ii) sales agreements, when forward commodity prices exceed contracted prices. Downgrades in the Corporation’s creditworthiness by certain credit rating agencies may decrease the credit limits granted by the Corporation’s counterparties and accordingly increase the amount of collateral the Corporation may have to provide, which could have a material adverse effect on the Corporation.

If counterparties to the Corporation’s contracts are unable to meet their obligations, the Corporation may be materially adversely affected.

If purchasers of the Corporation’s electricity, steam or other contractual counterparties of the Corporation default on their obligations, the Corporation may be materially adversely affected. While the Corporation seeks to control its exposure to credit risk by considering the ability of counterparties to fulfill their obligations under the related contracts prior to entering into such contracts, the Corporation cannot guarantee that it will be successful in identifying credit worthy customers. Moreover, while the Corporation seeks to monitor trading activities to ensure that the credit limits for counterparties are not exceeded, it cannot guarantee that it will be successful in doing so. If counterparties to the Corporation’s contracts are unable to meet their obligations, the Corporation could suffer a reduction in revenue which could have a material adverse effect on the Corporation.

Insurance coverage may not be sufficient.

The Corporation has insurance for its facilities, including all risk property insurance, commercial general liability insurance and, boiler and machinery coverage in amounts and with deductibles that the Corporation considers appropriate. The Corporation also carries replacement power and business interruption insurance for certain of its

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facilities where it does not otherwise have contractual arrangements to address these potential losses or where in other cases it would not be economic to do so.

The Corporation’s insurance coverage may not be available in the future on commercially reasonable terms or adequate insurance limits may not be available in the market. In addition, the insurance proceeds received for any loss or damage to any of its generation facilities may not be sufficient to permit it to continue to make payments on its debt.

Provision for income taxes may not be sufficient.

The Corporation’s operations are complex, and the computation of the provision for income taxes involves tax interpretations, regulations, and legislation that are continually changing. In addition, the Corporation’s tax filings are subject to audit by taxation authorities. While the Corporation believes that its tax filings have been made in material compliance with all applicable tax interpretations, regulations, and legislation, the Corporation cannot guarantee that it will not have disagreements with taxation authorities with respect to the Corporation’s tax filings that could have a material adverse effect on the Corporation.

The Corporation may be unsuccessful in the defence of legal actions.

The Corporation is occasionally named as a defendant in various claims and legal actions and as a party in commercial disputes which are resolved by arbitration. There can be no assurance that the Corporation will be successful in the defence of these claims and legal actions or that any claim or legal action that is decided adverse to the Corporation will not materially adversely affect the Corporation.

If the Corporation fails to attract and retain key personnel, it could be materially adversely affected.

The loss of any of the Corporation’s key personnel or its inability to attract, train, retain and motivate additional qualified management and other personnel could have a material adverse effect on the Corporation. Competition for these personnel is intense and there can be no assurance that the Corporation will be successful in this regard.

If the Corporation is unable to successfully negotiate new collective bargaining agreements with its unionized workforce, as required from time to time, it will be adversely affected.

While the Corporation believes it has a satisfactory relationship with its unionized employees, the Corporation cannot guarantee that it will be able to successfully negotiate or renegotiate its collective bargaining agreements on terms agreeable to the Corporation. The Corporation expects to re-negotiate three collective bargaining agreements, involving 551 of its employees, in 2011 and an additional three collective bargaining agreements, involving 267 of its employees, in 2012. Any problems in negotiating these collective bargaining agreements could lead to higher employee costs and a work stoppage or strike, which could have a material adverse effect on the Corporation.

Risks relating to TransAlta’s development projects and acquisitions may materially adversely affect the Corporation

Development projects and acquisitions undertaken by the Corporation may be subject to execution and capital cost risks, including, but not limited to, risks relating to regulatory approvals, third party opposition, cost escalations, construction delays, shortages of raw materials or skilled labour and capital constraints. The occurrences of these risks could have a material adverse impact on TransAlta’s business, financial condition, results of operations and cash flows.

Expansion of TransAlta’s business through development projects and acquisitions may place increased demands on our management, operating systems, internal controls and financial and physical resources. In addition, the process of integrating acquired businesses or development projects may involve unforeseen difficulties. Failure to successfully manage or integrate any acquired businesses or development projects could have a material adverse impact on TransAlta’s business, financial condition, results of operations and cash flows. Further, TransAlta cannot make assurances that it will be successful in integrating any acquisition or that the commercial opportunities or operational synergies of any acquisition will be realized as expected.

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With respect to acquisitions, TransAlta cannot make assurances that it will identify suitable transactions or that it will have access to sufficient resources, through its credit facilities, the capital markets or otherwise, to pursue and complete any identified acquisition opportunities on a timely basis and at a reasonable cost. Any acquisition the Corporation proposes or completes would be subject to normal commercial risks that the transaction may not be completed on the terms negotiated, on time, or at all. An unavoidable level of risk remains regarding potential undisclosed or unknown liabilities relating to any acquisition. The existence of such undisclosed liabilities may have a material adverse impact on the Corporation’s business, financial condition, results of operations and cash flows.

EMPLOYEES

As of December 31, 2010, the Corporation had 2,389 active employees, which comprises full-time, part-time and temporary employees, of which 1,650 were employed in TransAlta’s generation business and 66 were employed in TransAlta’s energy trading business. Approximately 46 per cent of the Corporation’s employees are represented by labour unions. The Corporation is currently a party to 11 different collective bargaining agreements. Overall in 2010, the Corporation renewed seven of the agreements; an additional three agreements are expected to be re-negotiated in 2011.

CAPITAL STRUCTURE

General

The Corporation’s authorized share capital consists of an unlimited number of common shares and an unlimited number of first preferred shares, issuable in series. As at February 23, 2011, there were 221,187,779 common shares outstanding and 12,000,000 first preferred shares were outstanding.

Common Shares

Each common share of the Corporation entitles the holder thereof to one vote for each common share held at all meetings of shareholders of the Corporation, except meetings at which only holders of another specified class or series of shares are entitled to vote, to receive dividends if, as and when declared by the Board, subject to prior satisfaction of preferential dividends applicable to any first preferred shares, and to participate rateably in any distribution of the assets of the Corporation upon a liquidation, dissolution or winding up and subject to prior rights and privileges attaching to first preferred shares. The common shares are not convertible and are not entitled to any pre-emptive rights. The common shares are not entitled to cumulative voting.

First Preferred Shares

The Corporation is authorized to issue an unlimited number of first preferred shares, issuable in series and, with respect to each series, the Board is authorized to fix the number of shares comprising the series and determine the designation, rights, privileges, restrictions and conditions attaching to such shares, subject to certain limitations.

The first preferred shares of all series rank senior to all other shares of the Corporation with respect to priority in payment of dividends and with respect to distribution of assets in the event of liquidation, dissolution or winding up of the Corporation, or a reduction of stated capital. Holders of first preferred shares are entitled to receive cumulative quarterly dividends on the subscription price thereof as and when declared by the Board at the rate established by the Board at the time of issue of shares of a series. No dividends may be declared or paid on any other shares of the Corporation unless all cumulative dividends accrued upon all outstanding first preferred shares have been paid or declared and set apart. In the event of the liquidation, dissolution or winding up of the Corporation, or a reduction of stated capital, no sum shall be paid or assets distributed to holders of other shares of the Corporation until the holders of first preferred shares shall have been paid the subscription price of the shares, plus a sum equal to the premium payable on a redemption, plus a sum equal to the arrears of dividends accumulated on the first preferred shares to the date of such liquidation, dissolution, winding up, or reduction of stated capital, as applicable. After payment of such amount, the holders of first preferred shares shall not be entitled to share further in the distribution of the assets of the Corporation.

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The Board may include, in the share conditions attaching to a particular series of first preferred shares, certain voting rights effective upon the Corporation failing to make payment of six quarterly dividend payments, whether or not consecutive. These voting rights continue for so long as any dividends remain in arrears. These voting rights are the right to one vote for each $25.00 of subscription price on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.

Subject to the share conditions attaching to any particular series providing to the contrary, the Corporation may redeem first preferred shares of a series, in whole or from time to time in part, at the redemption price applicable to each series and the Corporation has the right to acquire any of the first preferred shares of one or more series by purchase for cancellation in the open market or by invitation for tenders at a price not to exceed the redemption price applicable to the series.

Series A Shares

The only outstanding preferred shares are the rate reset shares issued on December 10, 2010 with a coupon of 4.60% (“Series A Shares”), as discussed in the section entitled General Development of the Business. Certain provisions of the Series A Shares are discussed below.

Dividends on Series A Shares

The holders of Series A Shares will be entitled to receive, as and when declared by the Board out of moneys of the Corporation properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax required to be deducted and withheld by the Corporation).

For each five-year period after the Initial Fixed Rate Period (each a “Subsequent Fixed Rate Period”, as defined herein), the holders of Series A Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate (as defined herein) for such Subsequent Fixed Rate Period by $25.00 (less any tax required to be deducted and withheld by the Corporation). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by the Corporation on the Fixed Rate Calculation Date (as defined herein) and will be equal to the sum of the Government of Canada Yield (as defined herein) on the Fixed Rate Calculation Date plus a spread of 2.03 per cent. This spread will apply to both the Series A Shares and the Series B Shares described below, and will remain unchanged over the life of the Series A Shares.

Redemption of Series A Shares

The Series A Shares shall not be redeemable prior to March 31, 2016. The Series A Shares are redeemable by TransAlta in whole or in part on or after March 31, 2016, and on March 31 in every fifth year thereafter by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax required to be deducted and withheld by the Corporation).

If the Corporation gives notice to the holders of the Series A Shares of the redemption of all of the Series A Shares, the right of a holder of Series A Shares to convert such Series A Shares shall terminate and the Corporation shall not be required to give notice to the registered holders of the Series A Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series A Shares.

Conversion of Series A Shares into Series B Shares

The holders of the Series A Shares will have the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, series B of the Corporation (the “Series B Shares”), subject to certain conditions, on

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March 31, 2016 and on March 31 in every fifth year thereafter. The holders of the Series B Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a “Quarterly Floating Rate Period”), in the amount per share determined by multiplying the “Floating Quarterly Dividend Rate” (which means, for any Quarterly Floating Rate Period, the annual rate of interest, (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 2.03 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax required to be deducted and withheld by the Corporation). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 2.03 per cent.

The Series A Shares and Series B Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series A Shares and Series B Shares are identical in all material respects.

Modification

The provisions attaching to the Series A Shares as a class may be amended with the written approval of all the holders of Series A Shares outstanding or by at least two-thirds of the votes cast at a meeting of the holders of such shares duly called for the purpose and at which a quorum is present.

Dividend Reinvestment and Share Purchase Plan

TransAlta has a Dividend Reinvestment and Share Purchase Plan which permits common shareholders of TransAlta to elect to reinvest their cash dividends in additional Common Shares of TransAlta. These Common Shares may be provided to the participants at a discount of up to five per cent to the weighted average market price traded on the Toronto Stock Exchange (“TSX”) during the last five trading days preceding the relevant dividend payment dates. The discount was set at three per cent commencing with the dividend payable in July 1, 2010. Participants may also make additional cash payments of up to $5,000 per quarter to purchase additional Common Shares. Participants are not responsible for payment of brokerage commissions or other transaction expenses for purchases made pursuant to the Dividend Reinvestment and Share Purchase Plan.

CREDIT RATINGS

Issuer Rating

The following information relating to the Company’s credit ratings is provided as it relates to the Company’s financing costs, liquidity and operations. Specifically, credit ratings affect the Company’s ability to obtain short-term and long-term financing and the cost of such financing. Additionally, the ability of the Company to engage in certain collateralized business activities on a cost effective basis depends on the Company’s credit ratings. A reduction in the current rating on the Company’s debt by its rating agencies, particularly a downgrade below investment grade ratings, or a negative change in the Company’s ratings outlook could adversely affect the Company’s cost of financing and its access to sources of liquidity and capital. In addition, changes in credit ratings may affect the Company’s ability to, and the associated costs of, (i) entering into ordinary course derivative or hedging transactions and may require the Company to post additional collateral under certain of its contracts, and (ii) entering into and maintaining ordinary course contracts with customers and suppliers on acceptable terms.

As of December 31, 2010, the Corporation’s corporate credit rating from S&P was BBB (stable), its senior unsecured debt rating from Moody’s was Baa2 (negative outlook), and its issuer rating from DBRS was BBB (stable).

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Senior Unsecured Long-Term Debt

As of December 31, 2010, the Corporation’s senior unsecured long-term debt is rated BBB (stable) by DBRS, BBB (stable) by S&P and Baa2 (negative outlook) by Moody’s. The ratings for debt instruments range from a high of AAA to a low of D in the case of both DBRS and S&P and from a high of Aaa to a low of C in the case of Moody’s.

According to the DBRS rating system, debt securities rated BBB are of adequate credit quality. Protection of interest and principal is considered acceptable, but the entity is more susceptible to adverse changes in financial and economic conditions, or there may be other adverse conditions present which reduce the strength of the entity and its rated securities. “High” or “Low” grades indicate the relative standing within a rating category. DBRS also assigns rating trends to each of its ratings to give investors an understanding of DBRS’ opinion regarding the outlook for the rating in question.

According to the S&P rating system, debt securities rated BBB exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on such obligations than on obligations in the higher rating categories. The ratings from AA to B may be modified by the addition of a plus (+) or minus (–) sign to show relative standing within the major rating categories.

The Moody’s rating system provides that debt securities rated Baa are subject to moderate credit risk. They are considered medium grade and as such may possess certain speculative characteristics. Numerical modifiers 1, 2 and 3 are applied to each rating category, with 1 indicating that the obligation ranks in the higher end of the category, 2 indicating a mid range ranking and 3 indicating a ranking in the lower end of the category.

Series A Shares

The Series A Shares have been rated Pfd-3 (stable) by DBRS and P-3(high) (stable) by S&P. The ratings for preferred shares range from a high of Pfd-1 to a low of D for DBRS and from a high of P-1 to a low of C for S&P.

According to the DBRS rating system, securities rated Pfd-3 are of adequate credit quality. “High” or “low” grades are used to indicate the relative standing within a rating category.

According to the S&P rating system, securities rated P-3 are less vulnerable to non payment than other speculative issues. The ratings from P-1 to -3 may be modified by “high”, “mid” and “low” grades which indicate relative standing within the major rating categories.

Note Regarding Credit Ratings

Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. The credit ratings accorded to the Corporation’s outstanding securities by S&P, Moody’s and DBRS, as applicable, are not recommendations to purchase, hold or sell such securities inasmuch as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that the ratings will remain in effect for any given period or that a rating will not be revised or withdrawn entirely by S&P, Moody’s or DBRS in the future if, in its judgement, circumstances so warrant.

DIVIDENDS

Common Shares

In setting dividends, the Board considers the Corporation’s financial performance and balances liquidity requirements, capital reinvestment and returning capital to shareholders, with a policy of paying annual dividends to its shareholders in the range of 60 to 70 per cent of comparable earnings. The payment and level of future dividends on the common shares are determined by the Board upon consideration of such factors. TransAlta has declared and paid the following dividends per share on its outstanding common shares for the past three years:

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Period		Dividend per Common Share

2008	First Quarter	$0.27
	Second Quarter	$0.27
	Third Quarter	$0.27
	Fourth Quarter	$0.27

2009	First Quarter	$0.29
	Second Quarter	$0.29
	Third Quarter	$0.29
	Fourth Quarter	$0.29

2010	First Quarter	$0.29
	Second Quarter	$0.29
	Third Quarter	$0.29
	Fourth Quarter	$0.29

On December 7, 2010, the Board declared a cash dividend of $0.29 per common share, payable on April 1, 2011 to shareholders of record on March 1, 2011.

Series A Shares

On December 13, 2010, the Board approved an initial dividend of $0.3497 per share on TransAlta’s issued and outstanding Series A Shares for the period from December 10, 2010 to March 31, 2011. The dividend is payable on March 31, 2011 to shareholders of record on March 1, 2011.

MARKET FOR SECURITIES

Common Shares

TransAlta’s common shares are listed on the TSX under the symbol “TA” and the New York Stock Exchange under the symbol “TAC”. The following table sets forth the reported high and low trading prices and trading volumes of the Corporation’s common shares as reported by the TSX for the periods indicated:

	Price ($)
Month	High	Low	Volume

2010
January	23.98	22.06	12,926,828
February	24.00	21.62	10,623,554
March	23.35	22.00	19,248,855
April	22.93	20.54	17,663,924
May	21.09	19.55	16,062,435
June	21.67	19.60	17,881,262
July	21.12	19.70	9,290,865
August	21.50	20.26	14,098,678
September	22.05	21.20	16,199,764
October	22.24	20.31	11,286,417
November	21.61	20.12	16,691,928
December	21.71	20.81	16,897,528

2011
January	22.08	20.60	10,328,775
February 1 to 23	21.25	20.57	12,720,649

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Series A Shares

TransAlta’s Series A Shares are listed on the TSX under the symbol “TA.PR.D”.

Date(s) of Issuance	Number of Common Shares or Securities	Issue Price per Security	Description of Transaction

December 10, 2010(1)	12,000,000 Series A Shares	$25.00	Public Offering

Note:
(1)	Preferred Shares were issued pursuant to the Corporation’s public offering of Series A Shares pursuant to a prospectus supplement dated October 19, 2009. See “General Development of the Business –Year Ended December 31, 2010”.

	Price($)
Month	High	Low	Volume
2010
December 10 – 31	26.00	24.75	1,257,242
2011
January	25.55	25.00	494,424
February 1 to 23	25.45	25.00	204,880

DIRECTORS AND OFFICERS

The name, province or state and country of residence of each of the directors and officers of TransAlta as at February 22, 2011, their respective position and office and their respective principal occupation during the five preceding years, are set out below. The year in which each director was appointed to serve to the Board is also set out below. Each director is appointed to serve until the next annual meeting of TransAlta or until his or her successor is elected or appointed.

Name, Province (State)
and Country of
Residence(1)

Year first
became
Director

Principal Occupation

William D. Anderson
Ontario, Canada

2003

Corporate Director. Mr. Anderson was President of BCE Ventures (a subsidiary of BCE Inc.) from 2001 to 2005 (telecommunications) and prior to that, Chief Financial Officer (“CFO”) of BCE Inc., Bell Canada Inc. and of Bell Cablemedia plc (telecommunications). As President of BCE Ventures, he was responsible for a number of significant operating companies as well as being Chief Executive Officer (“CEO”) of Bell Canada International Inc. In his CFO roles, Mr. Anderson was responsible for all financial operations of the respective companies and executed numerous debt and equity financings, corporate acquisition and disposition transactions as well as corporate and operational restructurings.

Mr. Anderson is a director of Gildan Activewear Inc., Sun Life Financial Inc. and Chair of the Board of Nordion Inc. (formerly MDS Inc.) He is a past director at BCE Emergis Inc., Bell Cablemedia plc, Bell Canada International Inc., CGI Group Inc., Four Seasons Hotels Inc., Sears Canada Inc. and Videotron Holdings plc.

At TransAlta, Mr. Anderson is the Chair of the Audit and Risk Committee of the Board.

Mr. Anderson holds a bachelor in business administration from the University of Western Ontario (London, ON) and is a Chartered Accountant.

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Name, Province (State) and Country of Residence(1)	Year first became Director	Principal Occupation

Stephen L. Baum New Hampshire, U.S.A.	2008	*Corporate Director*. Mr. Baum was Chairman and CEO of Sempra Energy from July 2000 to February 2006, a San Diego-based Fortune 500 energy services holding company formerly known as Enova Corporation. Previous to that, Mr. Baum was President, COO and Vice-Chairman of Sempra Energy, from July 1998 to July 2000. Prior to that he was Chairman, CEO and a member of the board of directors of Enova Corporation, the parent company of San Diego Gas & Electric (SDG&E) where he served in various officer positions including General Counsel. Before joining SDG&E, he was Senior Vice-President and General Counsel of the New York Power Authority. He has also held various legal positions, including General Attorney at Orange & Rockland Utilities, and as an associate with the law firm of Curtis, Mallet-Prevost, Colt & Mosle in New York City. Mr. Baum is a member of the board of directors of Computer Sciences Corporation and is a member of its Audit Committee and Governance Committee. At TransAlta, Mr. Baum is a member of the Human Resources Committee of the Board. Mr. Baum is a graduate of Harvard University and the University of Virginia Law School. He has also served as a Captain in the U.S. Marine Corps.

Timothy W. Faithfull England, U.K.	2003	*Corporate Director*. Mr. Faithfull is a 36-year veteran of Royal Dutch/Shell plc (energy), where he held diverse international roles principally in oil products and LNG project development. As President and CEO of Shell Canada Limited, he was responsible for bringing the $6 billion Athabasca Oil Sands Project on line, the first fully integrated oil sands venture in 25 years. Mr. Faithfull has extensive experience with commodity exposure and risk management, the result of his time directing the global crude oil trading operations of Shell International Trading and Shipping Company from 1993 to 1996. He was Chairman and CEO of Shell Eastern Petroleum in Singapore from 1996 to 1999, including Shell’s main refinery and oil products trading for Asia Pacific. During his time in Singapore, he was a director of DBS Bank, and the Port of Singapore Authority. He was a trustee of the main Singapore Arts/Theatre complex. In Calgary, he served on the board of the Calgary Health Trust and the Epcor Arts Centre. Mr. Faithfull is a director of Canadian Pacific Railway Limited, Canadian Natural Resources Limited, Shell Pension Trust Limited and AMEC plc, where he is the senior independent director. He is a past director of Enerflex Systems Income Fund. At TransAlta, Mr. Faithfull is the Chair of the Human Resources Committee of the Board. Mr. Faithfull holds a master of arts in philosophy, politics and economics from the University of Oxford, UK.

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Name, Province (State) and Country of Residence(1)	Year first became Director	Principal Occupation

Amb. Gordon D. Giffin(2) Georgia, U.S.A.	2002	*Lawyer and Senior Partner, McKenna, Long & Aldridge LLP* (law firm). From 1997 to 2001, Mr. Giffin served as the United States Ambassador to Canada with responsibility for managing Canada/US bilateral relations, including energy and environmental policy. Prior to this appointment, he practised law for 18 years as a senior partner in Atlanta, Georgia and Washington, DC. His practice focused on energy regulatory work at the state and federal levels. Prior to that, he served as Chief Counsel and Legislative Director to United States Senator Sam Nunn, with responsibility for the legal and legislative operations of the office. In 2001, Mr. Giffin returned to private practice where he specialized in state and federal regulatory matters, including those related to trade, energy and trans-border commerce. Mr. Giffin is a director of Canadian Imperial Bank of Commerce, Canadian National Railway Company, Canadian Natural Resources Limited, and Just Energy Group Inc. At TransAlta, Mr. Giffin is the Chair of the Governance and Environment Committee of the Board. Mr. Giffin holds a bachelor of arts from Duke University (Durham, NC) and a juris doctorate from Emory University School of Law (Atlanta, GA).

C. Kent Jespersen Alberta, Canada	2004	*Corporate Director.* Mr. Jespersen has been Chair and CEO of La Jolla Resources International Ltd. since 1998 (advisory and investments). He has also held senior executive positions with NOVA Corporation of Alberta, Foothills Pipe Lines Ltd., and Husky Oil Limited before assuming the presidency of Foothills Pipe Lines Ltd. and later, NOVA Gas International Ltd. (“NOVA”). At NOVA, he led the non-regulated energy services business (including energy trading and marketing) and all international activities. Mr. Jespersen is Chairman and a director of Orvana Minerals Ltd. and Orion Oil & Gas Ltd. and a director of Axia NetMedia Corporation, CanElson Drilling Inc., Rodinia Oil Corp. and Elson Energy Enterprises Ltd. At TransAlta, Mr. Jespersen is a member of the Audit and Risk Committee and the Human Resources Committee of the Board. Mr. Jespersen holds a bachelor of science in education and a master of science in education from the University of Oregon (Eugene, OR).

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Name, Province (State) and Country of Residence(1)	Year first became Director	Principal Occupation

Michael M. Kanovsky Alberta, Canada	2004	*Corporate Director and Independent Businessman. Mr. Kanovsky co-founded Northstar Energy Corporation (“Northstar”) with initial capital of $400,000 and helped build this entity into an oil and gas producer that was sold to Devon Energy Corporation for approximately $600 million in 1998. During this period, Mr. Kanovsky was responsible for strategy and finance as well as merger and acquisition activity. He initiated Northstar’s entry into electrical cogeneration through its wholly-owned power subsidiary, Powerlink Corporation (“Powerlink*”). Powerlink developed one of the first independent power producer (IPP) gas-fired co-generation plants in Ontario and also internationally. In 1997, he founded Bonavista Energy Trust, which has grown to a present day market capitalization of approximately $4.5 billion. Mr. Kanovsky currently is a director of Argosy Energy Inc., ARC Resources Ltd., Bonavista Energy Corporation, Devon Energy Corporation and Pure Technologies Ltd. Mr. Kanovsky intends to reduce these public directorships from five to four effective 2011. At TransAlta, Mr. Kanovsky is a member of the Governance and Environment Committee and the Human Resources Committee of the Board. Mr. Kanovsky, a Professional Engineer, holds a bachelor of science in mechanical engineering from Queen’s University (Kingston, ON) as well as a master of business administration from the Richard Ivey School of Business at the University of Western Ontario (London, ON).

Donna Soble Kaufman Ontario, Canada	1989	*Lawyer and Corporate Director*. Mrs. Kaufman is a former partner with Stikeman Elliott LLP, an international law firm, where she practised antitrust law (law firm). She has served on a number of boards since 1987, when she became a director of Selkirk Communications Limited, a diversified communications company. A year later she was appointed Chair of the Board, President and CEO. She has also served on the boards of Southam Inc., Provigo Inc., Bell Canada International Inc., Bell Globemedia Inc., the Public Sector Pension Investment Board, the Hudson’s Bay Company and UPM-Kymmene Corporation. She also currently serves on the boards of BCE Inc. and Bell Canada. She is also a director of The Historica-Dominion Institute, a private-sector education initiative to promote knowledge of Canadian history and heritage, the Institute of Corporate Directors, and a member of the Canadian Advisory Board of Catalyst, a non-profit organization working to advance women in business. In 2001, she was named a Fellow of the Institute of Corporate Directors and in 2009 she was appointed a member of the Prime Minister’s Advisory Committee on the Public Service of Canada. At TransAlta, Mrs. Kaufman is the Chair of the Board. Mrs. Kaufman holds a bachelor of civil law from McGill University (Montréal, QC) and a master of laws from the Université de Montréal (Montréal, QC).

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Name, Province (State) and Country of Residence(1)	Year first became Director	Principal Occupation

Gordon S. Lackenbauer(3) Alberta, Canada	2005	*Corporate Director*. Mr. Lackenbauer was Deputy Chairman of BMO Nesbitt Burns Inc. (investment banking) from 1990 to 2004. Prior to this, he was responsible for the principal activities of the firm, which included fixed income sales and trading, new issue underwriting, syndication and merger and acquisition advisory mandates. Mr. Lackenbauer has worked with many of Canada’s leading utilities and has frequently acted as an expert financial witness testifying on the cost of capital, appropriate capital structure, and the fair rate of return, principally before the Alberta Utilities Commission, the National Energy Board, and the Ontario Energy Board. Mr. Lackenbauer is a director of NAL Energy Corporation and Chair of its Audit Committee and a member of both the Corporate Governance and Reserves Committees. He is also a director of CTV Globemedia Inc. At TransAlta, Mr. Lackenbauer is a member of the Audit and Risk Committee and the Governance and Environment Committee of the Board. Mr. Lackenbauer holds a bachelor of arts in economics from Loyola College (Montréal, QC) as well as a master of business administration from the University of Western Ontario (London, ON). He is also a chartered financial analyst.

Karen E. Maidment Ontario, Canada	2010	*Corporate Director. Ms. Maidment was Chief Financial and Administrative Officer (“CFAO”) of BMO Financial Group (“BMO”) from 2007 to 2009. Prior to that she was Senior Executive Vice-President and Chief Financial Officer (“CFO”) from 2003 to 2007 and Executive Vice-President and CFO from 2000 to 2003 of BMO. As CFAO of BMO, she was responsible for all global finance operations, risk management, legal and compliance, communications and mergers and acquisitions. Prior to that, Ms. Maidment held several executive positions with Clarica Life Insurance Company (“Clarica*”) from 1988 to 2000, including CFO. Ms. Maidment was CFO when Clarica was the first demutualization of an insurance company in Canada with an initial public offering of $950 million. She also led the insurance industry group, working with government, to develop regulations and framework to convert Canada’s major insurers from mutual to public companies. Ms. Maidment is a past director of Harris Bank, BMO Nesbitt Burns, where she was also Chair of the Audit Committee, Bank of Montreal Pension Fund, Mutual Trustco, MCAP Financial and The Mutual Group (US). She currently serves on the Board of TD Ameritrade Holding Corporation and is a member of both the Audit and Risk Committees, and a member of the Princess Margaret Hospital Foundation Board. At TransAlta, Ms. Maidment is a member of the Audit and Risk Committee and the Governance and Environment Committee of the Board. Ms. Maidment holds a bachelor of commerce from McMaster University (Hamilton, ON), is a Chartered Accountant and in 2000 she was named Fellow of the Institute of Chartered Accountants of Ontario.

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Name, Province (State) and Country of Residence(1)	Year first became Director	Principal Occupation

Dr. Martha C. Piper British Columbia, Canada	2006	*Corporate Director. Dr. Piper was President and Vice-Chancellor of the University of British Columbia (“UBC*”) from 1997 to 2006 (education). Prior to her appointment at UBC, she served as Vice-President, Research at the University of Alberta. She served on the boards of the Alberta Research Council, the Conference Board of Canada and the Centre of Frontier Engineering Research. Dr. Piper was also appointed by the Prime Minister of Canada to the Advisory Council on Science and Technology and served as Chair of the Board of the National Institute for Nanotechnology. Dr. Piper is a director of the Bank of Montreal, Shoppers Drug Mart Corporation and a member of the Canadian delegation to the Trilateral Commission, an organization fostering closer cooperation among the core democratic industrialized areas of the world. At TransAlta, Dr. Piper is a member of the Governance and Environment Committee and the Human Resources Committee of the Board. Dr. Piper holds a bachelor of science in physical therapy from the University of Michigan (Ann Arbor, MI), a master of arts in child development from the University of Connecticut (Storrs, CT), and a doctorate of philosophy in epidemiology and biostatistics from McGill University (Montréal, QC). She has also received honorary degrees from 18 international universities. Dr. Piper is an Officer of the Order of Canada and a recipient of the Order of British Columbia.

Stephen G. Snyder Alberta, Canada	1996	*President and Chief Executive Officer of TransAlta Corporation since 1996*. Previously, Mr. Snyder was President & CEO, Noma Industries Ltd., President & CEO, GE Canada Inc., and President & CEO, Camco, Inc. Mr. Snyder is a director of Intact Financial Corporation and co-chair of the Calgary Stampede Foundation Campaign. He is a past Director of the Canadian Imperial Bank of Commerce. He is past Chair of the Calgary Stampede Foundation, the Alberta Secretariat for Action on Homelessness, the Calgary Committee to End Homelessness, the Canada-Alberta ecoEnergy Carbon Capture & Storage Task Force, the Conference Board of Canada, the Calgary Zoological Society, the Canadian Electrical Association, the United Way Campaign of Calgary and Area, and the Calgary Zoo’s “Destination Africa” capital campaign. Mr. Snyder holds a bachelor of science in chemical engineering from Queen’s University (Kingston, ON) as well as a master of business administration from the University of Western Ontario (London, ON). He has honourary degrees from the University of Calgary (LLD), and the Southern Alberta Institute of Technology (Bachelor of Applied Technology). He was awarded the Alberta Centennial Medal in 2005, the Conference Board Honorary Associate Award for 2008, the Chamber of Commerce Sherrold Moore Award of Excellence for 2009 and received the Canadian Energy Person of the Year Award for 2010 from the Energy Council of Canada.

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Notes:
(1)	The following nominee directors are Canadian residents: William D. Anderson, C. Kent Jespersen, Michael M. Kanovsky, Donna Soble Kaufman, Gordon S. Lackenbauer, Karen E. Maidment, Martha C. Piper and Stephen G. Snyder.

(2)	Ambassador Giffin was a director of AbitibiBowater Inc. (“Abitibi”) from October 29, 2007 until his resignation on January 22, 2009. In April 2009, Abitibi and certain of its U.S. and Canadian subsidiaries filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware for relief under the provisions of Chapter 11 and Chapter 15 of the United States Bankruptcy Code, as amended, and sought creditor protection under the CCAA with the Superior Court of Quebec in Canada. On September 14, 2010, Abitibi announced that it had received approval for its plan of reorganization from unsecured creditors under the CCAA in Canada. On September 21, 2010, Abitibi announced it had received the necessary creditor approval for its plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code. On September 23, 2010, Abitibi announced that the Quebec Superior Court rendered an order sanctioning the plan of reorganization under the CCAA. On November 22, 2010, Abitibi announced that the U.S. Bankruptcy Court for the District of Delaware issued an opinion confirming the plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code. On December 9, 2010, Abitibi announced that it had successfully completed its reorganization and emerged from creditor protection under the CCAA in Canada and Chapter 11 of the U.S. Bankruptcy Code.

(3)	Mr. Lackenbauer resigned from the Board of Directors of Tembec Inc. (“Tembec”) on August 2, 2007. On December 19, 2007, Tembec announced its proposed recapitalization transaction providing a consensual solution to both noteholders and shareholders. On February 22, 2008, Tembec announced that it had received the approval of the majority of shareholders and the requisite majority of noteholders of Tembec Industries Inc. On February 27, 2008, Tembec announced that it had received approval from the Ontario Superior Court of Justice (Commercial List) with respect to their plan of arrangement relating to the proposed recapitalization transaction. On October 31, 2008, Tembec announced that it had successfully obtained a final American court order recognizing its Canadian plan of arrangement as a foreign proceeding in the United States.

Officers

Name	Principal Occupation	Residence

Stephen G. Snyder	President and Chief Executive Officer	Alberta, Canada
Dawn L. Farrell	Chief Operating Officer	Alberta, Canada
Brett Gellner	Chief Financial Officer	Alberta, Canada
Kenneth S. Stickland	Chief Legal Officer	Alberta, Canada
Michael Williams	Chief Administration Officer	Alberta, Canada
William D. A. Bridge	Chief Technology Officer	Alberta, Canada
Hume D. Kyle	Vice-President, Controller and Treasurer	Alberta, Canada
Maryse C. St.-Laurent	Vice-President and Corporate Secretary	Alberta, Canada

All of the officers of TransAlta have held their present principal occupation or position for the past five years, except for the following:

· Prior to April 2009, Dawn Farrell was Executive Vice-President, Commercial Operations and Development of the Corporation. Prior to July 2007, she was Executive Vice-President Engineering, Aboriginal Relations and Generation at BC Hydro and prior to June 2006 she was Executive Vice-President Generation.

· Prior to June 2010, Brett Gellner was Vice-President, Commercial Operations of the Corporation. Prior to July 2008, he was Co-Head and Managing Director, Investment Banking at CIBC World Markets Inc.

· Mr. Kenneth Stickland has held the same principal occupation for the past five years, though his title has changed over the course of this period of time.

· Mr. Michael Williams has held the same principal occupation for the past five years, with the exception that in July 2007 he was given added responsibility for Information Technology and in November 2010 this responsibility was assigned to the Chief Operating Officer.

· Prior to April 2009, William Bridge was Executive Vice-President, Generation Technology and PMM of the Corporation. Prior to July 2007, he was Vice-President, Western Canada Operations. Prior to October 2005, Mr. Bridge was Vice-President, Customer and Asset Management; prior to September 2003, he was Vice-President, Development & Acquisition; and prior to September 2001 he was Director, Commercial Operations and Development, Eastern Canada.

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· Prior to December 2010, Hume Kyle was Vice-President, Finance and Controller of the Corporation. Prior to February 2009, he was Vice-President, Finance and Chief Financial Officer of Fort Chicago Energy Management Ltd.

· Ms. Maryse St.-Laurent has held the same principal occupation for the past five years.

As of February 23, 2011, the directors and executive officers of TransAlta, as a group, beneficially owned, directly or indirectly, or exercised control or direction over an aggregate of 666,722 common shares of TransAlta. This constitutes less than one per cent of TransAlta’s outstanding common shares.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director or executive officer of the Corporation, no person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over more than ten per cent of the common shares of the Corporation, and no associate or affiliate of any of them, has or has had any material interest, direct or indirect, in any transaction involving the Corporation within the three most recently completed financial years or to date in 2011 or in any proposed transactions that has materially affected or will materially affect the Corporation.

INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS

Since January 1, 2010, there has been no indebtedness outstanding to TransAlta from any of TransAlta’s directors, executive officers, senior officers or associates of any such directors, nominees or officers.

CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS

Corporate Cease Trade Orders

Except as otherwise disclosed herein, no director, executive officer or controlling security holder of TransAlta Corporation is, as at the date of this Annual Information Form, or has been, within the past ten years before the date hereof, a director or executive officer of any other issuer that, while that person was acting in that capacity:

(i) was the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or

(ii) was subject to an event that resulted, after the person ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or

(iii) within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

Personal Bankruptcies

No director, executive officer or controlling security holder of TransAlta Corporation has, within the ten years before the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or became subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold such person’s assets.

Penalties or Sanctions

No director, executive officer or controlling security holder of TransAlta Corporation has:

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(i) been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, other than penalties for late filing of insider reports; or

(ii) been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

CONFLICTS OF INTEREST

Circumstances may arise where members of the Board serve as directors or officers of corporations which are in competition to the interests of the Corporation. No assurances can be given that opportunities identified by such member of the Board will be provided to the Corporation.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

TransAlta is occasionally named as a party in various claims and legal proceedings which arise during the normal course of its business. TransAlta reviews each of these claims, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. Although there can be no assurance that any particular claim will be resolved in the Corporation’s favour, the Corporation does not believe that the outcome of any claims or potential claims of which it is currently aware will have a material adverse effect on the Corporation, taken as a whole, after taking into account amounts reserved by the Corporation. For further information, please refer to Notes 26 and 28 of the Corporation’s audited consolidated financial statements for the year ended December 31, 2010 which financial statements are incorporated by reference herein. See “Documents Incorporated by Reference” herein.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for TransAlta’s common shares and TransAlta’s First Preferred Shares Series A is CIBC Mellon Trust Company in Vancouver, Calgary, Winnipeg, Toronto and Montréal. The transfer agent and registrar for the common shares in the United States is Mellon Investor Services LLC at its principal office in New York, New York.

INTERESTS OF EXPERTS

Ernst & Young LLP, Chartered Accountants, 1000, 440 – 2nd Avenue, S.W., Calgary, Alberta, T2P 5E9 are the auditors of the Corporation.

TransAlta’s auditors, Ernst & Young LLP, are independent in accordance with the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and have complied with the SEC’s rules on auditor independence.

ADDITIONAL INFORMATION

Additional information in relation to TransAlta may be found under TransAlta’s profile on SEDAR at www.sedar.com.

Additional information including directors’ and officers’ remuneration and indebtedness, principal holders of TransAlta’s securities and securities authorized for issuance under equity compensation plans (all where applicable), is contained in TransAlta’s Management Proxy Circular for its most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request to TransAlta’s Investor Relations department.

Additional financial information is provided in TransAlta’s audited consolidated financial statements as at and for the year ended December 31, 2010 and in the Annual MD&A, each of which is incorporated by reference in this Annual Information Form. See “Documents Incorporated by Reference” herein.

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AUDIT AND RISK COMMITTEE

General

The members of TransAlta’s Audit and Risk Committee (“ARC”) satisfy the requirements for independence under the provisions of Canadian Securities Regulators, Multilateral Instrument 52 110 Audit Committees, Section 303A of the New York Stock Exchange Rules and Rule 10A-3 under the U.S. Securities and Exchange Act of 1934. The ARC’s Charter requires that it be comprised of a minimum of three independent directors. It currently has five independent members, William D. Anderson (Chair), C. Kent Jespersen, Karen E. Maidment, Gordon S. Lackenbauer and Donna S. Kaufman as an ex officio member. All members of the committee are financially literate pursuant to both Canadian and U.S. securities requirements and each of Mr. William D. Anderson, Mr. Gordon S. Lackenbauer and Ms. Karen E. Maidment have been determined by the Board to be an “audit committee financial expert”, within the meaning of Section 407 of the United States Sarbanes Oxley Act of 2002 (“Sarbanes Oxley Act”).

Mandate of the Audit and Risk Committee

The mandate of the ARC is to assist the Board in its oversight responsibility to the shareholders of the Corporation, the investment community and others relating to the integrity of the Corporation’s financial statements, the quality of its financial reporting processes, the systems of internal accounting and financial controls, the risk identification assessments conducted by management and the programs established in response to such risks, the internal audit function, the external auditors’ qualifications, independence, performance and reports and to provide oversight with respect to legal compliance programs established by management which may have a material effect on the financial statements of the Corporation. The ARC also reviews the Corporation’s compliance with the Corporation’s code of conduct, financial code of conduct and the Corporation’s policy with respect to the hiring of employees of the external auditors.

The ARC’s function is oversight. Management is responsible for the preparation, presentation and integrity of the financial statements of the Corporation. Management and the internal audit group of the Corporation are responsible for maintaining appropriate accounting and financial reporting principles and policy and internal controls and procedures for compliance with accounting standards and applicable laws and regulations.

While the ARC has the responsibilities and powers set forth herein, it is not the duty of the ARC to plan or conduct audits or to determine that the Corporation’s financial statements are complete and accurate and in accordance with generally accepted accounting principles. This is the responsibility of management and the external auditors.

Management is responsible for preparing the interim and annual financial statements and financial disclosure of the Corporation and for maintaining a system of internal controls to provide reasonable assurance that assets are safeguarded and that transactions are authorized, executed, recorded and reported properly. The ARC’s role is to provide direct, meaningful and effective oversight of the Corporation’s financial reporting and counsel to management without assuming responsibility for management’s day to day duties.

Audit and Risk Committee Charter

The Charter of the Audit and Risk Committee is attached as Appendix “A”.

Relevant Education and Experience of Audit and Risk Committee Members

The following is a brief summary of the education or experience of each member of the ARC that is relevant to the performance of their responsibilities as a member of the ARC, including any education or experience that has provided the member with an understanding of the accounting principles used by TransAlta to prepare its annual and interim financial statements.

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Name of ARC Member		Relevant Education and Experience

W. D. Anderson		Mr. Anderson is a Chartered Accountant, with 17 years experience with a major Chartered Accountant firm in Canada. Mr. Anderson has served as CEO of a public company and as CFO of several public companies. In such capacities, Mr. Anderson actively supervised persons engaged in preparing, auditing, analyzing or evaluating financial statements. Mr. Anderson has also served as a principal financial officer and accounting officer and as a director and audit committee chair and member of several public companies. He has served on the board and audit committee of a public company that reports under U.S. GAAP.

C. Kent Jespersen		Mr. Jespersen has held several senior management positions and is a director and Chief Executive Officer of several public companies including being the Chair of Axia Net Media’s audit committee. Mr. Jespersen has experience supervising individuals who have experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues raised by TransAlta’s financial statements.

G. S. Lackenbauer		Mr. Lackenbauer has over 35 years of experience in the investment banking industry. Mr. Lackenbauer has also appeared as an expert financial witness with respect to financial markets, capital structure, cost of capital and fair return on common equity, in over 40 regulatory proceedings. Mr. Lackenbauer also has extensive experience as a director or governor of public companies and not for profit organizations. Mr. Lackenbauer holds a bachelor of arts in economics, a master of business administration from the University of Western Ontario and is a Chartered Financial Analyst.

Karen E. Maidment		Ms. Maiment is a Chartered Accountant. Ms. Maidment has served as a Chief Financial Officer with financial oversight responsibilities for TSX and NYSE listed public companies for over 15 years. She has also held positions where she was responsible for global finance operations, risk management, legal and compliance, communications and mergers and acquisitions. In addition, Ms. Maidment has worked with government bodies in order to develop regulations and frameworks for the conversion of major insurers from mutual to public companies. Ms. Maidment holds a bachelor of commerce from McMaster University, and in 2000 was named a Fellow of the Institute of Chartered Accountants of Ontario.

D. S. Kaufman (ex officio)		Mrs. Kaufman has over 25 years of legal, professional and financial management experience gained in the practice of law, as a director of several public companies and as Chair, President and CEO of Selkirk Communications. Mrs. Kaufman has served on several audit committees. Mrs. Kaufman holds a civil law degree from McGill University and a master of laws from the University of Montreal.

Other Board Committees

In addition to the Audit and Risk Committee, TransAlta has two other standing committees: the Governance and Environment Committee and the Human Resources Committee. Mrs. Kaufman, the Chair of the Board, is a non-voting ex officio member of all committees. The members of these committees as of December 31, 2010 are:

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Governance and Environment Committee		Human Resources Committee

Chair: Ambassador Gordon D. Giffin		Chair: Timothy W. Faithfull
Michael M. Kanovsky		Stephen L. Baum
Gordon S. Lackenbauer		C. Kent Jespersen
Karen E. Maidment		Michael M. Kanovsky
Dr. Martha C. Piper		Dr. Martha C. Piper
Donna Soble Kaufman (ex officio)		Donna Soble Kaufman (ex officio)

The Charters of the Governance and Environment Committee and the Human Resources Committee may be found on TransAlta’s website under Corporate Responsibility Governance at www.transalta.com. Further information about the Board and the Corporation’s corporate governance may also be found on our website or in the Corporation’s Management Proxy Circular which is filed on Sedar at www.sedar.com.

Fees Paid to Ernst & Young LLP

For the years ended December 31, 2010 and December 31, 2009, Ernst & Young LLP and its affiliates were paid $3,499,254 and $3,562,032 respectively, as detailed below:

Ernst & Young LLP

Year Ended Dec. 31	2010		2009

Audit Fees	$	2,737,081	$	2,679,080
Audit-related fees	729,873		824,631
Tax fees	32,300		58,321

Total	$	3,499,254	$	3,562,032

No other audit firms provided audit services in 2010 or 2009.

The nature of each category of fees is described below:

Audit Fees

Audit fees were paid for professional services rendered by the auditors for the audit of the Corporation’s annual financial statements or services provided in connection with statutory and regulatory filings or engagements, including the translation from English to French of the Corporation’s financial statements and other documents. Total audit fees for 2010 include payments related to 2009 in the amount of $969,568. Total audit fees for 2009 include payments related to 2008 in the amount of $1,212,080.

Audit-Related Fees

The audit-related fees in 2010 were primarily for work performed by Ernst & Young LLP in relation to the implementation of International Financial Reporting Standards, other audits, public equity and debt offerings, and miscellaneous accounting advice provided to the Corporation. The audit-related fees in 2009 were primarily for work performed by Ernst & Young LLP in relation to the implementation of International Financial Reporting Standards, public equity and debt offerings and miscellaneous advice provided to the Corporation.

Tax Fees

The majority of tax fees for each of 2009 and 2010 relate to various tax related matters in our foreign operations.

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APPENDIX “A” – AUDIT AND RISK COMMITTEE CHARTER

A. Establishment of Committee and Procedures

1. Composition of Committee

The Audit and Risk Committee (the “Committee”) of the Board of Directors (the “Board”) of TransAlta Corporation (the “Corporation”) shall consist of not less than three Directors. All members of the Committee shall be determined by the Board to be independent as required under the provisions of Canadian Securities Regulators’ Multilateral Instrument 52-110 Audit Committees, Section 303A of the New York Stock Exchange rules and Rule 10A-3 of the U.S. Securities and Exchange Act of 1934, as such rules apply to audit committee members. All members of the Committee must be financially literate pursuant to both Canadian and U.S. securities requirements and at least one member must be determined by the Board to be an “audit committee financial expert” within the meaning of Section 407 of the United States Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act’). Determinations as to whether a particular director satisfies the requirements for membership on the Committee shall be made by the Board of Directors (the “Board”) at the recommendation of the Governance and Environment Committee.

2. Appointment of Committee Members

Members of the Committee shall be appointed from time to time by the Board, on the recommendation of the Governance and Environment Committee, and shall hold office until the next annual meeting of shareholders, or until their successors are earlier appointed, or until they cease to be Directors of the Corporation.

3. Vacancies

Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board. The Board shall fill any vacancy if the membership of the Committee is less than three directors.

4. Committee Chair

The Board shall appoint a Chair for the Committee on the recommendation of the Governance and Environment Committee.

5. Absence of Committee Chair

If the Chair of the Committee is not present at any meeting of the Committee, one of the members of the Committee who is present at the meeting shall be chosen by the Committee to preside at the meeting.

6. Secretary of Committee

The Committee shall appoint a Secretary who need not be a director of the Corporation.

7. Meetings

The Chair of the Committee may call a meeting of the Committee. The Committee shall meet at least quarterly and at such other time during each year as it deems appropriate. In addition, the Chair of the Committee or any two members may call a special meeting of the Committee at any time. Although

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B. Mandate of the Committee

The Committee provides assistance to the Board in fulfilling its oversight responsibilities with respect to i) the integrity of the Corporation’s financial statements and financial reporting process, ii) the systems of internal financial controls established by management, iii) the risk identification assessment conducted by management and the programs established by management in response to such assessment, iv) the internal audit function v) compliance with accounting and finance based legal and regulatory requirements, vi) the external auditors’ qualifications, independence and performance. In so doing, it is the Committee’s responsibility to maintain an open avenue of communication between the Committee, the external auditors, the internal auditors and the management of the Corporation.

The function of the Committee is oversight. Management is responsible for the preparation, presentation and integrity of the interim and annual financial statements and related disclosure documents. Management of the Corporation is also responsible for maintaining appropriate accounting and financial reporting policies and systems of internal controls and procedures to comply with accounting standards, applicable laws and regulations and that provide reasonable assurances that assets are safeguarded and that transactions are authorized, executed, recorded and reported properly.

While the Committee has the responsibilities and powers set forth herein, it is not the duty of the Committee to plan or conduct audits or to determine that the Corporation’s financial statements are complete and accurate and in accordance with generally accepted accounting principles. This is the responsibility of management and the external auditors.

The designation of a member or members as an “audit committee financial expert” is based on that individual’s education and experience, which the individual will bring to bear in carrying out his or her duties on the Committee. Designation as an “audit committee financial expert” does not impose on such person any duties, obligations and liability that are greater than the duties, obligations and liability imposed on a member of the Committee and Board in the absence of such designation.

Management is also responsible for the identification and management of the Corporation’s risks and the development and implementation of policies and procedures to mitigate such risks. The Committee’s role is to provide oversight in order to ensure that the Corporation’s assets are protected and safeguarded within reasonable business limits.

C. Duties and Responsibilities of the Committee

The Committee shall have the following specific duties and responsibilities:

1. Audit and Financial Matters

A) External Auditors’ Qualifications

(a) The Committee shall have direct responsibility for the compensation and oversight of the external auditors including nominating the external auditors to the Board for appointment by the shareholders at the Corporation’s general annual meeting. In performing its function, the Committee shall:

(i) review the experience and qualifications of the external auditors’ senior personnel who are providing audit services to the Corporation and the quality control procedures of the external auditors, including obtaining confirmation that the external auditors are in compliance with Canadian and U.S. regulatory registration requirements;

(ii) review and approve annually the external auditors audit plan;

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(iii) review and approve the basis and amount of the external auditors’ fees and ensure the Corporation has provided appropriate funding for payment of compensation to the external auditors;

(iv) review and discuss with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors’ independence, including, without limitation, (i) requesting, receiving and reviewing, at least annually, a formal written statement from the external auditors delineating all relationships that may reasonably be thought to bear on the independence of the external auditors with respect to the Corporation, (ii) discussing with the external auditors any disclosed relationships or services that the external auditors believe may affect the objectivity and independence of the external auditors, and (iii) recommending that the Board take appropriate action in response to the external auditors’ report to satisfy itself of the external auditors’ independence;

(v) resolve disagreements between management and the external auditors regarding financial reporting;

(vi) inform the external auditors and management that the external auditors shall have direct access to the Committee at all times, as well as the Committee to the external auditors;

(vii) instruct the external auditors that they are ultimately accountable to the Committee as representatives of the shareholders of the Corporation; and

(viii) at least annually, obtain and review the external auditors’ report with respect to the auditing firm’s internal quality-control procedures, any material issues raised by the most recent internal quality-control review or peer review of the auditing firm, any inquiry or investigation by governmental or professional authorities within the preceding five years undertaken respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with any such issues;

B) Independent Audit Process

(a) Subject to the delegation granted to the Chair of the Committee, pre-approve all audit related services including all non-prohibited non-audit services provided by the external auditors; the Chair of the Committee, is authorized to approve all audit related services including non-prohibited non-audit services provided by the external auditors, and shall report all such approvals to the Committee at its next scheduled meeting;

(b) Review with management and the external auditors the Corporation’s financial reporting in connection with the annual audit and the preparation of the financial statements, including, without limitation, the annual audit plan of the external auditors, the judgment of the external auditors as to the quality, not just the acceptability, of and the appropriateness of the Corporation’s accounting principles as applied in its financial reporting and the degree of aggressiveness or conservatism of the Corporation’s accounting principles and underlying estimates;

(i) recommend to the Board for approval the Corporation’s audited annual financial statements including the notes thereto; the “Management’s Discussion and Analysis” and any required reconciliation;

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(ii) review any report or opinion to be rendered in connection therewith and report to the Board as required;

(iii) review with the external auditors the cooperation they received during the course of their review and their access to all records, data and information requested;

(iv) discuss with management and the external auditors all significant transactions which are not a regular part of the Corporation’s business;

(v) review the management processes for formulating sensitive accounting estimates and the reasonableness of the estimates;

(vi) review with management and the external auditors any changes in accounting principles and their applicability to the business;

(vii) review with management and the external auditors alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such alternative disclosures and treatments and the treatment preferred by the external auditors;

(viii) satisfy itself that there are no unresolved issues between management and the external auditors that could reasonably be expected to materially affect the financial statements;

(d) Review with management and the external auditors the Corporation’s interim financial statements, including the notes thereto, “Management’s Discussion and Analysis”, US GAAP Note, the related earnings release, and approve their release to the public as required;

(e) Review and discuss with management and the external auditors the use of “pro forma” or “adjusted” non-GAAP information and the applicable reconciliation;

(f) Review with management, the external auditors and, as necessary, internal and external legal counsel, any litigation, claim or contingency, including tax assessments, that could have a material effect upon the financial position of the Corporation, and the manner in which these may be or have been disclosed in the financial statements;

(g) Review disclosures made to the Committee by the CEO and Chief Financial Officer (the “CFO”) during their certification process for the relevant periodic reports filed with securities regulators to ensure that information required to be disclosed is recorded, processed, summarized and reported within the time periods specified for the reporting period. Obtain assurances from the CEO and CFO as to the adequacy and effectiveness of the Corporation’s disclosure controls and procedures and systems of internal control over financial reporting and that any fraud involving management or other employees who have a significant role in the Corporation’s internal controls was reported to the Committee;

C) Financial Planning

(h) Review and recommend to the Board for approval the Corporation’s issuance and redemption of securities (including the review of all public filings to effect any of the issuances or redemptions), financial commitments and limits, and any material changes underlying any of these commitments;

(i) Review annually the Corporation’s annual tax plan;

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2. Governance

(j) On behalf of the Committee, the Chair shall review all public disclosure of material financial information extracted or derived from the Corporation’s financial statements prior to dissemination to the public;

(k) Review with management at least annually the approach and nature of financial information and earnings guidance to be disclosed to analysts and rating agencies;

(l) Review quarterly with senior management and the Chief Legal Officer, and as necessary, outside legal advisors, and the Corporation’s internal and external auditors, the effectiveness of the Corporation’s internal controls to ensure the Corporation is in compliance with legal and regulatory requirements and with the Corporation’s policies;

(m) Review quarterly with the Chief Legal Officer, and, if necessary, outside legal advisors, significant legal, compliance or regulatory matters that may have a material effect on the Corporation’s financial statements;

(n) Discuss with the external auditors their perception of the Corporation’s financial and accounting personnel, any recommendations which the external auditors may have, including those contained in the management letter, with respect to improving internal financial controls, choice of accounting principles or management reporting systems, and review all management letters from the external auditors together with management’s written responses thereto;

(o) Review changes in accounting practices or policies and the financial impact these may have on the Corporation;

(p) Review annually the Annual Pension Report and financial statements of the Corporation’s pension plans including the actuarial valuation, asset/liability forecast, asset allocation, manager performance and plan operating costs;

(q) Review annually the Insider Trading policy and approve changes as required;

(r) Together with the Human Resources Committee of the Board, review annually, and as required, the overall governance of the Corporation’s Pension Plans, approving the broad objectives of the plans, the statement of investment policy, the appointment of investment managers, and reporting thereon to the Board annually;

(s) Review the annual audit of expense accounts and perquisites of the Directors, the CEO and his direct reports and their use of Corporate assets;

(t) Review annually the Corporation’s annual sponsorship, donations and political contributions;

(u) Review management’s processes relating to the assessment of potential fraud, programs and controls to mitigate the risk of fraud and the process put in place for monitoring the risks within targeted areas;

(v) Review disclosure made to the Committee by the CEO, CFO and/or Chief Legal Officer of a material violation of applicable securities laws, a material breach of a fiduciary duty under applicable laws or a similar material violation by the Corporation or by any officer, director, employee or agent of the Corporation, which has been reported to the Committee, determine whether an investigation is necessary regarding any such report and report to the board;

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(w) Establish procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by employees of concerns regarding accounting or auditing matters;

(x) Review all incidents, complaints or information reported through the Ethics Help Line and/or management;

(y) Discuss with management and the external auditors any correspondence from or with regulators or governmental agencies, any employee complaints or any published reports that raise material issues regarding the Corporation’s financial statements or accounting policies;

(z) Review and approve the Corporation’s hiring policies for employees or former employees of the external auditors and monitor the Corporation’s adherence to the policy;

(aa) Report annually to shareholders on the work of the Committee during the year;

3. Internal Audit

(bb) Review and consider, as appropriate, any significant reports and recommendations made by internal audit relating to internal audit issues, together with management’s response thereto;

(cc) Review annually the internal audit department’s charter, the scope and plans for the work of the internal audit group, the adequacy of the group’s resources, the internal auditors access to all functions, records, property and personnel of the Corporation. The Committee shall also inform the internal auditors and management that the internal auditors shall have unfettered access to the Committee, as well as the Committee to the internal auditors;

(dd) Meet separately with management, the external auditors and internal auditors to review issues and matters of concern respecting audits and financial reporting;

(ee) Review with the Corporation’s senior financial management and the Vice-President Internal Audit the adequacy of the Corporation’s systems of internal control and procedures;

(e) Recommend to the Human Resources Committee the appointment, termination or transfer of the Vice-President, Internal Audit.

4. Risk Management

The Committee provides oversight of management’s establishment of an overall risk culture for the Corporation. The Committee shall oversee and approve the processes established and developed by management for the identification of the Corporations principal risks, the evaluation of potential impact and the implementation of appropriate systems to mitigate and manage the risks.

The Committee shall:

(a) Review annually with the Board management’s assessment of the significant risks to which the Corporation is exposed; discuss with management the Corporation’s policies and procedures for identifying and managing the principal risks of its business in order to ensure that management:

(i) has identified appropriate business strategies to take into account the principal risks identified, and

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(ii) is maintaining systems and procedures to manage or mitigate those risks, including programs of loss prevention, insurance and risk reduction and disaster response and recovery programs;

(b) Receive and review managements’ quarterly risk assessment update including an update on residual risks, emergent risks and next steps;

(d) Review annually the Corporation’s Financial and Commodity Exposure Management Policies and approve changes to such policies; review and authorize the Corporation’s strategic hedging program guidelines and risk tolerance; review and monitor quarterly results of financial and commodity exposure management activities, including foreign currency and interest rate risk strategies, counterparty credit exposure and the use of derivative instruments;

(e) Review the Corporation’s annual insurance program, including the risk retention philosophy, and potential exposure and corporate liability protection programs for directors and officers including directors’ and officers’ insurance coverage;

(f) Periodically consider the respective roles and responsibilities of the external auditor, the internal audit department, internal and external counsel concerning risk management of the Corporation and review their performance in relation to such roles and responsibilities; and

(g) Annually, together with management report to the Board on:

(i) the Corporation’s strategies in light of the overall risk profile of the Corporation;

(ii) the nature and magnitude of all significant risks the Corporation is exposed to;

(iii) the processes, policies, procedures and controls in place to manage or mitigate the significant risks; and

(iv) the overall effectiveness of the enterprise risk management process.

D. Compliance and Powers of the Committee

(a) The responsibilities of the Committee complies with applicable Canadian laws and regulations, such as the rules of the Canadian Securities Administrators, and with the disclosure and listing requirements of the Toronto Stock Exchange, as they exist on the date hereof. In addition this Charter complies with applicable US laws, such as the Sarbanes-Oxley Act and the rules and regulations adopted thereunder, and with the New York Stock Exchanges’ corporate governance standards, as they exist on the date hereof. This Charter is reviewed from time to time by the Corporate Secretary together with the Chair of the Committee in order to ensure ongoing compliance with such standards.

(b) The Committee may, at the request of the Board or on its own initiative, investigate such other matters as are considered necessary or appropriate in carrying out its mandate.

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PRESENTATION OF INFORMATION	1
SPECIAL NOTE REGARDING FORWARD LOOKING INFORMATION	1
DOCUMENTS INCORPORATED BY REFERENCE	2
CORPORATE STRUCTURE	2
OVERVIEW	3
GENERAL DEVELOPMENT OF THE BUSINESS	5
BUSINESS OF TRANSALTA	10
ENVIRONMENTAL RISK MANAGEMENT	27
RISK FACTORS	30
EMPLOYEES	38
CAPITAL STRUCTURE	38
CREDIT RATINGS	40
DIVIDENDS	41
COMMON SHARES	41
MARKET FOR SECURITIES	42
COMMON SHARES	42
DIRECTORS AND OFFICERS	43
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	50
INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS	50
CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS	50
CONFLICTS OF INTEREST	51
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	51
TRANSFER AGENT AND REGISTRAR	51
INTERESTS OF EXPERTS	51
ADDITIONAL INFORMATION	51
AUDIT AND RISK COMMITTEE	52
APPENDIX “A” – AUDIT AND RISK COMMITTEE CHARTER	A-1
APPENDIX “B” – GLOSSARY OF TERMS	B-1

Notes:
(1)	TransAlta USA Inc. is an indirect subsidiary of TransAlta.
(2)	The remaining 0.01 per cent interest in TEC Limited Partnerships is owned by TransAlta (Ft. McMurray) Ltd., a wholly owned subsidiary of TransAlta.