PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this annual information form (“Annual Information Form”) is given as at or for the year ended December 31, 2009. Amounts are expressed in Canadian dollars unless otherwise indicated. Financial information is presented in accordance with Canadian generally accepted accounting principles.

SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS

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 and their attendant costs; expectations relating to the timing and cost of planned uprates and upgrades at various facilities; expectations relating to the timing of the completion of the FEED (as defined herein) study regarding carbon capture and storage and the cost of the study; estimates of recoverable coal reserves at the Corporation’s Whitewood and Highvale mines; TransAlta’s plans to invest in new capacity; expectations for demand for electricity in both the short and long term; expectations in respect of generation production; TransAlta’s plans to install mercury control equipment at its Alberta thermal operations and its initiative to reduce nitrogen oxide and mercury emissions from its Centralia Plant; expected governmental regulatory regimes; the Corporation’s trading strategies; and expectations relating to the renegotiation of certain of the collective bargaining agreements to which TransAlta is a party.

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; (iv) changes in general economic conditions including interest rates; (v) operational risks involving the Corporation’s facilities, including unplanned outages at such facilities; (vi) disruptions in the transmission and distribution of electricity; (vii) effects of weather; (viii) disruptions in the source of fuels, water, wind or biomass required to operate the Corporation’s facilities; (ix) natural disasters; (x) equipment failure; (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. 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, 2009 (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, 2009 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 is 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 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 January 1, 2009, the principal subsidiaries of the Corporation and their respective jurisdictions of formation are set out below:

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In the United States, the Corporation’s principal facilities include a 1,376 MW thermal facility and a 248 MW gas fired facility, both located in Centralia, Washington, which supply electricity to the Pacific northwest. The Corporation also holds a 50 per cent interest in CE Generation, LLC (“CE Generation”), through which it has an aggregate net ownership interest of approximately 385 MW of generating capacity in geothermal facilities in California and gas fired facilities in Texas, Arizona and New York. In addition, the Corporation has 6 MW of electrical generating capacity through hydroelectric facilities located in Washington and Hawaii.

In Australia, the Corporation has 300 MW of net electrical generating capacity from gas fired generation facilities.

The Corporation regularly reviews its operations in order to optimize its generating assets and evaluates appropriate growth opportunities. The Corporation has in the past and may in the future make changes and additions to its fleet of coal, gas, hydro, wind, geothermal and biomass fuelled facilities.

The Corporation is organized into two business segments: Generation and Commercial Operations and Development. The Generation group is responsible for constructing, operating and maintaining electricity generation facilities. The Commercial Operations and Development group is responsible for managing the sale of production, purchasing natural gas, transmission capacity and market risks associated with the Corporation’s generation assets and for non asset backed trading activities. Both segments are supported by a corporate group that provides finance, treasury, legal, regulatory, environmental, health and safety, sustainable development, corporate communications, government relations, information technology, human resources, internal audit, and other administrative support.

GENERAL DEVELOPMENT OF THE BUSINESS

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 January 11, 2010, the Corporation announced it has been awarded a 25-year power purchase agreement to provide an additional 54 MW of wind power to New Brunswick Power Distribution and Customer Service Corporation (“New Brunswick Power”). The capital cost of the project is estimated to be $100 million. Construction is expected to commence in early 2010 and the facility is expected to be in service by the end of 2010.

Year Ended December 31, 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 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 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 gross proceeds to the Corporation of approximately $412.5 million. The net proceeds from the offering were used to repay a portion of the indebtedness incurred in connection with the Corporation’s acquisition of Canadian Hydro.

· 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

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and biomass facilities in British Columbia, Alberta, Ontario and Québec and also had 18 MW under construction.

· On October 14, 2009, the federal and provincial governments announced that the Corporation’s carbon capture and storage (“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 Front End Engineering and Design (“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. The FEED study is expected to be completed by the end of 2010. 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.

· 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 29, 2009, the Corporation issued $200 million principal amount of 6.45% senior notes maturing May 29, 2014. The net proceeds from the offering were used for debt repayment, financing of the Corporation’s long-term investment plan, and for general corporate purposes.

· 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 May 6, 2009, the Corporation announced that it had received regulatory approval from the Toronto Stock Exchange (“TSX”) for the renewal of its normal course issuer bid (“NCIB”) program. Under the NCIB, the Corporation has approval to purchase for cancellation, up to 9.9 million of its common shares, representing 5 per cent of its common shares issued and outstanding as of April 30, 2009.

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

· 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 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 board of directors of the Corporation (the “Board”) declared a quarterly dividend of $0.29 per common share, payable April 1, 2009 to holders of record on March 1, 2009. This represents a $0.02 per share increase in the quarterly dividend, yielding on an annualized basis a dividend of $1.16 per share.

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· 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 2011 and 2012, respectively. The total capital cost of the projects is estimated to be $68 million.

· 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, an Alberta general partnership, whose partners are TransAlta and TransAlta Generation Ltd., a wholly owned subsidiary of TransAlta. TransAlta Generation Partnership is managed by TransAlta pursuant to the terms of a 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 held directly, in the case of the wind assets, and some of which are held indirectly, in the case of the former generation assets and businesses of TAU and TEC.

Year Ended December 31, 2008

· On December 31, 2008, the Corporation announced that the 96 MW, $170 million Kent Hills Wind Farm had begun commercial operation. The wind farm consists of 32 Vestas V90, 3MW wind turbines. The capacity from this project is sold under a power purchase agreement with New Brunswick Power.

· 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 gas/diesel combined cycle gas plant in Campeche, a 259 MW combined cycle gas plant in Chihuahua and all associated commercial arrangements.

· On May 27, 2008, the Corporation announced that, commencing in 2009, it would be constructing another 66 MW wind generation facility in southern Alberta, consisting of 22 Vestas V90 3 MW wind turbines. The total capital cost for this expansion of the Summerview wind power project is expected to be $123 million. The capacity from this project is expected to be sold on the Alberta Power Pool.

· On May 5, 2008, the Corporation announced that it had received regulatory approval from the TSX for the continuation of its NCIB program. Under the NCIB program, the Corporation received approval to purchase, for cancellation, up to 19.9 million of its common shares, representing 10 per cent of its public float as of April 23, 2008.

· 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 $113.5 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 costs for this Blue Trail wind power project is expected to be $115 million. The capacity from this project is expected to be sold on the Alberta Power Pool.

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· On February 1, 2008, the Board declared a quarterly dividend of $0.27 per common share, payable April 1, 2008 to holders of record on March 1, 2008. This represents a $0.02 per share increase in the quarterly dividend, yielding on an annualized basis a dividend of $1.08 per share.

Year Ended December 31, 2007

· During the third quarter, the Corporation completed an uprate on the Sundance Unit 4 facility. A final measurement took place in the fourth quarter of 2007 and the generating capacity added as a result of this uprate was 53 MW.

· On September 11, 2007, the Corporation announced it had received regulatory approval to increase the number of shares it may purchase under its NCIB program. As a result, the Corporation was authorized to purchase for cancellation up to 20.2 million of its common shares or approximately 10 per cent of the 202 million common shares issued and outstanding as of April 23, 2007.

· On July 17, 2007, the Corporation amended the power purchase agreement with New Brunswick Power to increase capacity at its Kent Hills wind power facility from 75 MW to 96 MW. As a result, total capital costs for the Kent Hills project increased by $40 million, from $130 million to $170 million. The Corporation also signed a purchase and sale agreement with Vector Wind Energy, then a wholly owned subsidiary of Canadian Hydro, to acquire its Fairfield Hill wind power site, including an option to develop the site at a future date.

· On June 21, 2007, TransAlta Utilities entered into an agreement with Bucyrus Canada Limited and Bucyrus International Inc. for the purchase of a dragline to be used primarily in the supply of coal for the Keephills 3 joint venture project. The total dragline purchase costs were approximately $150 million, with final payments for goods and services due by May 2010. The total payments made under this agreement to December 31, 2009 were $124.7 million.

· On February 26, 2007, the Corporation and EPCOR Power Development Corporation (now Capital Power Corporation or “Capital Power”) announced that they were proceeding with building the 450 MW Keephills 3 power project located approximately 70 kilometres west of Edmonton, Alberta. The capital cost for the project, including mine capital, is expected to be approximately $1.6 billion and is expected to be completed at the end of the first quarter of 2011. Through the Keephills 3 Limited Partnership (“K3LP”), an affiliate of the Corporation, TransAlta and Capital Power will be equal partners in the ownership of Keephills 3, with TransAlta responsible for managing the joint venture and Capital Power responsible for the construction. 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. The project has received approval from the AEUB and from Alberta Environment.

· On January 19, 2007, the Corporation announced that it had been awarded a 25 year power purchase agreement to provide 75 MW of wind power to New Brunswick Power. Under the agreement, TransAlta constructed, owns and operates a wind power facility in New Brunswick.

· On January 2, 2007, the Corporation redeemed, at par, all of its outstanding 7.75 per cent preferred securities, with an outstanding principal amount of $175 million.

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BUSINESS OF TRANSALTA

Generation Business Segment

The following table summarizes the Corporation’s generation facilities which are operating, under construction or under development, as at January 31, 2010:

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

Sundance	2,126	100	2,126	Coal	Alberta PPA / Merchant(2)	2017, 2020
Keephills (4)	812	100	812	Coal	Alberta PPA/Merchant(4)	2020
Sheerness	780	25	195	Coal	Alberta PPA	2020
Wabamun	279	100	279	Coal	Merchant	-
Genesee 3	450	50	225	Coal	Merchant	-
Keephills 3 (3)	450	50	225	Coal	Merchant	-
Fort Saskatchewan	118	30	35	Gas	Long-term contract (“LTC”)	2019
Meridian	220	25	55	Gas	LTC	2024
Poplar Creek	356	100	356	Gas	LTC/Merchant	2024
Blue Trail	66	100	66	Wind	Merchant	-
Castle River (5)	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	2024
Sinnott	7	100	7	Wind	Merchant	-
Soderglen	71	50	35	Wind	Merchant	-
Summerview 1 (6)	70	100	70	Wind	Merchant	-
Summerview 2 (3)	66	100	66	Wind	Merchant	-
Taylor Wind	3	100	3	Wind	Merchant	-
Ardenville (3)	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 (3)	18	100	18	Hydro	LTC	2047
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	7,051		5,666

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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	Gas	LTC	2017
Ottawa	68	50	34	Gas	LTC	2012
Sarnia (7)	506	100	506	Gas	LTC	2022-2025
Windsor	68	50	34	Gas	LTC/Merchant	2016
Kent Hills	96	83	80	Wind	LTC	2033
Kent Hills Expansion (3)	54	100	54	Wind	LTC	2035
Le Nordais	99	100	99	Wind	LTC	2033
Melancthon I	68	100	68	Wind	LTC	2026
Melancthon II	132	100	132	Wind	LTC	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		1,273

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

Centralia(8)	1,376	100	1,376	Coal	Merchant	-
Centralia Gas	248	100	248	Gas	Merchant	-
Power Resource	212	50	106	Gas	Merchant	-
Saranac	240	37.5	90	Gas	Merchant	-
Yuma	50	50	25	Gas	LTC	2024
Imperial Valley Geothermal Facilities (9)	327	50	164	Geothermal	LTC	2016-2029
Skookumchuk (10)	1	100	1	Hydro	-	-
Wailuku	10	50	5	Hydro	LTC	2023
Total US	2,464		2,015

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

Parkeston	110	50	55	Gas	LTC	2016
Southern Cross(11)	245	100	245	Gas/Diesel	LTC	2013
Total Australia	355		300

TOTAL	11,281		9,254

Notes:

(1) Megawatts are rounded to the nearest whole number.

(2) Merchant capacity refers to 53 MW, 53 MW and 44 MW uprates on units 4, 5 and 6, respectively.

(3) These facilities are currently under development.

(4) Includes two 23 MW uprates on units 1 and 2 expected to be commercial in 2011, and 2012, respectively. Merchant capacity refers to these two uprates.

(5) Includes 7 individual turbines at other locations.

(6) Comprised of 2 facilities.

(7) Sarnia’s NMC has been adjusted from 575 MW due to decommissioning of equipment at the facility.

(8) 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.

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(9) Comprised of 10 facilities.

(10) This facility is used to provide a reliable water supply to TransAlta’s other generation facilities at Centralia.

(11) Comprised of 4 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

Wabamun(1)	AB	Wabamun Unit No. 4	279	100	1968	-
Sundance	AB	Sundance Unit No. 1	280	100	1970	2017
	AB	Sundance Unit No. 2	280	100	1973	2017
	AB	Sundance Unit No. 3	353	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(2)	406	100	1983	2020
	AB	Keephills Unit No. 2(2)	406	100	1984	2020
	AB	Keephills Unit No. 3(3)	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			4,897

Notes:

(1) Wabamun unit is expected to be removed from service upon the expiry of its license March 31, 2010.

(2) Includes two 23 MW uprates on units 1 and 2 expected to be commercial in 2011, and 2012, respectively.

(3) This facility is currently under development.

The Wabamun, 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 jointly owned by TransAlta Cogeneration, L.P. (“TA Cogen”), an Ontario limited partnership, and ATCO Power (2000) Ltd. (“ATCO Power”). The Genesee facility 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. Availability is an important measure of the economic success of a thermal plant. The weighted equivalent availability factor for the Alberta thermal plants in 2009 was 78.0 per cent compared with 82.9 per cent in 2008 and 87.1 per cent in 2007. For the Sheerness facility, the weighted equivalent availability factor was 93.3 per cent in 2009 compared to 94.1 per cent in 2008 and 94.4 per cent in 2007. For the Genesee 3 facility, the weighted equivalent availability factor was 97.5 per cent in 2009 compared to 78.2 per cent in 2008 and 92.9 per cent in 2007.

Fuel requirements for TransAlta’s thermal power facilities are supplied by surface strip coal mines located in close proximity to the facilities. TransAlta owns two surface mines in Alberta that supply coal to its Alberta thermal plants. The Whitewood mine supplies the Wabamun plant and the Highvale mine supplies the Sundance and Keephills facilities. TransAlta estimates that the recoverable coal reserves contained in these mines are expected to be sufficient to supply the anticipated requirements for the life of these facilities including running post PPA expiry and plant expansion.

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.

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

The 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 power project 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 TransAlta responsible for managing the joint venture and Capital Power responsible for construction. 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. The Corporation will also provide coal to the facility through the Highvale mine.

Gas fired facilities

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

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

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

Total			694

The Corporation’s interests in the Meridian and Fort Saskatchewan facilities are held through TA Cogen. See “TA Cogen”.

The Meridian plant is located in Lloydminster, Saskatchewan and is 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, and steam to a heavy oil upgrader in Lloydminster, Saskatchewan.

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 Fort Saskatchewan plant is located in Fort Saskatchewan, Alberta and is owned by TA Cogen and Strongwater Energy Ltd. (purchased from Air Liquide Canada Inc. in 2009). The 118 MW Fort Saskatchewan gas fired combined cycle cogeneration plant in Alberta provides electricity and steam to Dow Chemical Canada Inc.

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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	BC	Akolkolex	10	100	1995	2015
	BC	Pingston	45	50	2003, 2004	2023
Mamquam River System	BC	Upper Mamquam	25	100	2005	2025
Thompson River System	BC	Bone Creek(2)	18	100	2011	2047
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	1953, 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	AB	Belly River	3	100	1991	-
	AB	Waterton	3	100	1992	-
	AB	St. Mary	2	100	1992	-
	AB	Taylor Hydro	13	50	2000	-

Total			920

Notes:

(1) Megawatts are rounded to the nearest whole number.

(2) Facility under construction reflects expected capacity and commissioning date.

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 EcoPower® Centre 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. The output from the facility is sold to BC Hydro. Akolkolex has been operating since April 1995.

Pingston EcoPower® Centre 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 output from the facility is sold to BC Hydro. Pingston has been operating since 2003 and is 50 per cent owned, via a joint venture, with a subsidiary of Brookfield Renewable Power Inc.

Mamquam River System

Upper Mamquam EcoPower® Centre 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. The output from the facility is sold to BC Hydro. Upper Mamquam has been operating since 2005.

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Thompson River System

Bone Creek is a run-of-river hydroelectric facility currently under construction with expected capacity of 18 MW located on Bone Creek, north of Kamloops, near the town of Valemount, British Columbia. Bone Creek is expected to commence commercial operations in the first quarter of 2011.

Bow River System

Horeshoe 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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Oldman River System

Belly River EcoPower® Centre 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 EcoPower® Centre 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 EcoPower® Centre 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 EcoPower® Centre 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 972 MW of net wind generation capacity (excluding facilities under development) primarily in 12 wind farms in western Canada, three in Ontario, one in Québec and one in New Brunswick.

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 2010, TransAlta has sold approximately 70 per cent of the environmental attributes from our merchant wind facilities and 100 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.

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	2024
Pincher Creek	AB	MacLeod Flats	3	100	2004	-
Pincher Creek	AB	Ardenville(2)	69	100	2011	-
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(2)	66	100	2010	-
Pincher Creek	AB	Cowley Ridge	21	100	1993	-
Waterton	AB	Taylor Wind	3	100	2004	-
Pincher Creek	AB	Cowley North	20	100	2001	-
Pincher Creek	AB	Sinnott	7	100	2001	-
Pincher Creek	AB	Soderglen	71	50	2006	-

Total			515

Notes:

(1) Megawatts are rounded to the nearest whole number.

(2) Facility under development reflects expected capacity and commissioning date.

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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 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 MW turbine and is located near Fort Macleod. It was commissioned in 2004 and was purchased by TransAlta in 2009.

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

Castle River is a 40 MW wind farm comprised of 59 Vestas V47 (660 kW) turbines and 1 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 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 Natural Resources Canada (“NRCan”), a division of the federal government, through the eco Energy for Renewable Power (“eERP”) program.

On May 27, 2008, the Corporation announced that it would be constructing another 66 MW wind generation facility in southern Alberta, consisting of 22 Vestas V90 3 MW wind turbines. The total capital costs for this expansion of the Summerview 2 wind power project is expected to be $123 million. The capacity from this project is expected to be sold on the Alberta Power Pool. The Summerview 2 wind farm expansion is entitled to receive payments from NRCan through the eERP program.

Cowley Ridge EcoPower® Centre (“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 became operational in 1994. Generation from this facility is sold in the Alberta spot market.

Taylor EcoPower® Centre wind facility (“Taylor Wind”) 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 EcoPower® Centre (“Cowley North”) and Sinnott EcoPower® Centre (“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.

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Soderglen EcoPower® Centre (“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 50 per cent owned by the Corporation and 50 per cent owned by Nexen Inc. Commercially operational in September 2006, Soderglen has a total installed capacity of 71 MW. Generation from this facility is sold in the Alberta spot market.

All of the electricity generated and sold by the Corporation’s wind division, with the exception of Blue Trail, Macleod Flats, the Summerview 2 (under construction), a 2.5 MW expansion of Cowley Ridge, and Taylor Wind, is generation from facilities that are EcoLogo certified. The Corporation is an EcoLogo certified distributor of Alternative Source Electricity through Environment Canada’s Environmental Choice program. EcoLogo certification is granted to products with environmental performance that meet or exceed all government, industrial safety and performance standards.

Biomass Facilities

Grande Prairie EcoPower® Centre (“GPEC”) is a biomass co-generation facility with an installed capacity of 25 MW and is located adjacent to Canadian Forest Products Ltd.’s Grande Prairie Sawmill in the city of Grande Prairie, in northern Alberta. GPEC became commercially operational in 2005. Generation from GPEC 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 Wabamun, 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 such 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 operating and maintenance practices, and through hedging activities.

The Corporation’s hydroelectric facilities, other than Belly River, Waterton, St. Mary and Taylor Hydro, are not contracted on a facility by facility basis; rather, facilities are aggregated in a single 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 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 on a 10 year Government of Canada Bond.

The pricing formula includes a provision for site restoration costs of the thermal generating plants for the whole 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. With the expiry of the PPA at the Wabamun facility, the Corporation procured an extension of the license to operate Unit 4 of the Wabamun facility until March 31, 2010, and since the extension has sold most of the electricity from the Wabamun facility on the spot market.

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The Corporation is evaluating the economics of running assets post PPA expiry. Upon the expiry of the PPAs and subject to procuring an extension of the licenses, if required, the Corporation will then be able 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.

Canada: Eastern Canada

Gas-fired facilities

The Corporation’s Ontario 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 gas turbine. The 506 MW Sarnia facility provides steam and electricity to nearby industrial 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 over “Early Movers” on a term and under conditions more in keeping with those contracts it was 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 under more favourable terms. This new agreement brings the combined total term contracted with the OPA to 20 years. The new contract also includes provisions to share the impact and benefit of changes in customer steam load or the loss of a 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.

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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 2003, an agreement was reached with the OEFC to sell the remaining 18 MW 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) Megawatts are rounded to the nearest whole number.

Ragged Chute EcoPower® Centre (“Ragged Chute”) is a run-of-river hydroelectric facility with installed capacity of 7 MW located on the Montreal 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.

Moose Rapids EcoPower® Centre (“Moose Rapids”) is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Wanapitei 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 EcoPower® Centre (“Appleton”) is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Mississippi River, near Appleton, 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 EcoPower® Centre (“Galetta”) is a run-of-river hydroelectric facility with installed capacity of 2 MW also located on the Mississippi River, near Appleton, 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 EcoPower® Centre (“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.

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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
New Brunswick	NB	Kent Hills	96	83	2008	2033
New Brunswick	NB	Kent Hills(2)	54	100	2010	2035

Total			647

Notes:

(1) Megawatts are rounded to the nearest whole number.

(2) Includes the Kent Hills expansion facility under construction and expected commissioning date.

Melancthon I EcoPower® Centre (“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. Together, Melancthon I and II are known as the Melancthon EcoPower® Centre. Melancthon II achieved 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 / 340 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 EcoPower® Centre (“Le Nordais”) is located at two sites: Cap-Chat (56.25 MW installed capacity, 75 turbines); and Matane (42.75 MW installed capacity, 57 turbines). Le Nordais is on the Gaspé Peninsula of Québec. Production from this facility is sold to Hydro-Québec. Le Nordais has been commercially operational since 1999.

Kent Hills is located in Kent Hills, New Brunswick, and is a 75 MW of wind power facility with output sold under a 25 year LTC with New Brunswick Power.

On January 19, 2007, the Corporation announced that it had been awarded a 25 year LTC to deliver 75 MW of wind power to New Brunswick Power. On July 17, 2007, the Corporation announced it had amended its LTC with New Brunswick Power from 75 MW to 96 MW bringing the total capital cost for the project to an estimated $170 million. The project was completed by the end of 2008. The project was completed by the end of 2008. Natural Forces Technologies Inc. (“Natural Forces”), an Atlantic Canada based wind developer, is TransAlta’s co development partner in this project and Natural Forces exercised its option to purchase up to 17 per cent of the Kent Hills project in May 2009.

On January 11, 2010, the Corporation announced that it had been awarded another 25 year LTC to expand the existing Kent Hills project by 54 MW of wind power to New Brunswick Power with a further capital cost of an estimated $100 million. The project is scheduled to be completed by the end of 2010.

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TA Cogen

The Corporation’s interest in the 220 MW Meridian natural gas fired generation facility in Saskatchewan, the 780 MW Sheerness thermal generation facility, the 118 MW Fort Saskatchewan gas fired cogeneration facility in Alberta, and the Mississauga, Ottawa and Windsor Essex facilities in Ontario, are held through TA Cogen, an Ontario limited partnership owned 50.01 per cent by subsidiaries of TransAlta and 49.99 per cent by Stanley Power Inc., a subsidiary of Cheung Kong Infrastructure Holdings Limited.

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	688	100	1971	-
		Centralia Coal No. 2	688	100	1971	-
		Centralia Gas	248	100	2002	-
		Skookumchuk	1	100	1970	-
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			2,464

Centralia

The Corporation owns a two unit 1,376 MW thermal facility and a 248 MW gas fired facility in Centralia, Washington, located south of Seattle. The Corporation also owns a 1 MW hydro electric generating facility on the Skookumchuk River near Centralia, and related assets which are used to provide water supply to TransAlta’s other generation facilities at Centralia.

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.

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During 2009, we wrote down the mining development costs incurred related 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.

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 gas fired cogeneration in New York State, Texas and Arizona.

CE Generation affiliates operate the 10 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 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.

Commercial Operations and Development

The Commercial Operations and Development 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;

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· 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;

· Increasing 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

· 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 Commercial Operations and Development 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 Commercial Operations and Development 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 3.7 million residents representing approximately 11 per cent of Canada’s total population. Alberta consumed approximately 70,000 GWh of electricity in 2009. As at December 31, 2009, the aggregate installed capacity of generating facilities in Alberta was approximately 12,800 MW.

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 370,000 GWh of electricity was consumed in the NWPP in 2009. The WECC also reported an estimated aggregate electrical generating capacity of approximately 86,000 MW in the NWPP for the year ending 2009.

British Columbia is Canada’s third largest province by population with approximately 4.5 million residents, representing approximately 13 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

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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 13.1 million residents representing approximately 39 per cent of Canada’s total population. Ontario consumed approximately 139,000 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 35,465 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 7.8 million residents, representing approximately 23 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 industries. In 2007, New Brunswick announced the Charter for Change requiring 10 per cent of electricity purchases to be from renewable sources commencing in 2016.

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 Australian Bureau of Agriculture and Resource Economics (“ABARE”) estimated total production of 283,000 GWh for 2009 with a growth rate of approximately 2.8 per cent per annum from 2010 to 2015. 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 4,500 MW, while TransAlta’s capacity in the region is approximately 300 MW. 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 – Approximately 77 per cent of the Corporation’s generating capacity is contracted through PPAs, LTCs or other wholesale market transactions for the next five 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.

Commercial Operations and Development expertise - The Corporation believes that its Commercial Operations and Development 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.

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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 Whitewood mine and 0.25 per cent at the Highvale mine. Coal with lower sulphur content emits less sulphur dioxide when it is burned.

Wind Generation - The Corporation is one of the largest owners and operators of wind generation in Canada. The Wind 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.

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 Expenditures
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
2005	$287 million	$39 million	$326 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.

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.

TransAlta’s approach to managing its environmental, health and safety (“EHS”) risks has three elements:

· Compliance based activities, such as permitting and reporting;

· ISO based EHS Management systems and programs, such as safety programs and auditing; and

· Longer term strategic initiatives, including climate change and government policy development.

These elements are integrated into TransAlta’s corporate wide operations and management systems. They are designed to mitigate risks of TransAlta’s activities to employees, the public and the environment, and to address potential competitive risks from future changes in environmental policy. They are also supportive of TransAlta’s corporate commitment to sustainability and are part of our long term strategy.

To meet regulatory requirements and improve environmental performance, TransAlta made environmental operating and capital expenditures in fiscal year 2009 of approximately $45 million. Long term environmental expenditures are generally defined as expenditures incurred to comply with Canadian or international environmental regulations, conventions or voluntary agreements.

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All TransAlta’s facilities are in material compliance with existing regulatory requirements. Environmental risk at the plants operated by TransAlta has been reduced by actions in several areas:

· Continued investment in mercury control technology leading to expected installation of mercury capture equipment at our Alberta coal plants in 2010, and at our Centralia, Washington coal plant by 2012;

· Uprate improvements delivering higher efficiency generation at the Sundance plant;

· Continued program of compliance and management system audits at all facilities;

· The planned decommissioning of the older Wabamun thermal plant in 2010;

· Acquisition of carbon offsets;

· Continued expansion of the renewable energy business, with minimal emissions footprint; and

· Initiation of the Project Pioneer carbon capture and storage demonstration project in Alberta.

TransAlta anticipates future environmental regulatory developments in areas such as climate change, air quality and water. Regulatory changes and policy developments are tracked in all relevant jurisdictions. Relevant regulatory developments are discussed below.

Canada

In December 2009, the Copenhagen Accord on climate change was negotiated and announced by participating countries. The Accord is not binding and does not stipulate a global target for greenhouse gas (“GHG”) reductions. Countries are responsible for determining their own targets and policies to manage emissions. The Government of Canada had targeted a 20 per cent GHG reduction by 2020. However, the Government of Canada has not yet implemented a framework or regulations to that effect and has consistently stated that it intends to coordinate its climate change policies with those of the U.S. to facilitate a continental cap and trade system. TransAlta anticipates that the details and schedule of the Canadian program will depend on the development and direction of the U.S. approach.

Separately, the Government of Canada announced its intent to develop new Canadian air pollutant requirements for sulphur dioxide, nitrogen oxide (“NOx”) and mercury. No regulations have yet been developed. Work continues through a stakeholder consultation process involving industry, provincial and federal governments, and environmental organizations. There is currently no defined date for the finalization and implementation of any recommendations.

On December 1, 2009, the Government of Ontario released its mandatory GHG reporting regulation, requiring industrial facilities over 25,000 tonnes of carbon dioxide (“CO2”) emissions per year to report annually. The first reporting is required by June 2011 for 2010 emissions. This regulation is intended to lay the groundwork for an Ontario-based GHG regulatory framework to be implemented in 2010.

Alberta continues to maintain its GHG regulatory regime which requires reductions of 12 per cent in emission intensity from a 2003-2005 average baseline. The Corporation’s PPAs, for our Alberta-based coal facilities, contain change-in-law provisions that allow us to recover these compliance costs from the PPA customers. For 2009 emissions, after flow-through, our annual net GHG compliance costs will be approximately $4 million. We continue to examine compliance options, including additions to our offsets portfolio to minimize our compliance risk beyond that period.

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

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On October 14, 2009, the Alberta and Canadian governments each announced that Project Pioneer, TransAlta’s CCS project, had received committed funding of more than $750 million. This funding is provided as part of the Government of Canada’s $1 billion Clean Energy Fund and the Government of Alberta’s $2 billion CCS initiative. The funding will support the undertaking of FEED study that is expected to be completed in 2010. Once built, the 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 pilot Alstom Canada’s proprietary chilled ammonia carbon capture technology and will be designed to capture one megatonne of CO2 per year at our Keephills 3 facility. The CO2 will be used for enhanced oil recovery as well as injected into a permanent geological storage site.

In addition, TransAlta looks 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. TransAlta is also part of a group of companies participating in the Integrated CO2 Network to develop carbon capture and storage systems and infrastructure for Canada.

United States

In the United States, the Senate is currently considering GHG legislation following passage in the U.S. House of Representatives of the American Clean Energy and Security Act in June 2009. The legislation is based on a cap and trade system which is designed to achieve a 17 per cent reduction in GHG emissions by 2020. There is significant uncertainty regarding the form and schedule of legislation from the Senate.

Meanwhile, the U.S. Environmental Protection Agency (the “EPA”) is pursuing a separate path to regulate GHG’s under the Clean Air Act. In November 2009, the EPA upheld its endangerment finding which determines that CO2 is a pollutant and, therefore, able to be regulated by the EPA under the Clean Air Act. The implications of a legislative option versus the EPA regulatory approach is uncertain. In September 2009, the EPA adopted a mandatory GHG reporting rule for all facilities emitting more than 25,000 tons per year of CO2 equivalents. This rule became effective on December 29, 2009, and will require reporting to commence for such facilities in the U.S., including our Centralia facilities, during 2010.

In May 2009, in the state of Washington, the governor signed an executive order outlining the state government’s plan for addressing climate change related emissions. The executive order included a directive to the State Department of Ecology to work with TransAlta to apply the Washington’s GHG performance standard for power generation to the Centralia facilities no later than 2025. The standard will require emissions of approximately 0.5 tonnes/MWh, or about half of what is currently emitted at Centralia. Exploratory discussions are underway with the State Department of Ecology about how this might be achieved. At this time, it is not clear how Washington’s target and timeframe will align with federal GHG legislation when it comes into effect.

Further, in the state of Washington, since September there has been a public process to review a draft agreement between TransAlta and Washington regarding TransAlta’s voluntary initiative to reduce NOx and mercury emissions from the Centralia facilities. Specifically, TransAlta has proposed to:

· control NOx emissions to a maximum of 0.24 lbs/million BTU’s fuel input, and

· reduce mercury emissions by 50 per cent from current levels.

It is expected that Washington State will issue its final determination in the spring of 2010.

Environmental issues concerning water use are managed within the ISO 14001 framework. TransAlta continues to work with regulators in each jurisdiction in which it operates, to ensure water is used wisely on site and that all regulations pertaining to water and wetlands management, both on and off site, are met.

TransAlta’s environmental efforts have been recognized by the Dow Jones North American Sustainability Index for four years in a row. The Index represents the best environmental performance leaders in North America. In 2008, TransAlta also participated in the global Carbon Disclosure Project which requires detailed assessments of corporate climate change plans and actions.

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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 prices and availability of fuel supplies required to generate electricity, and in the price of 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 other sources of 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; and

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

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 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.

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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 which 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 extensive 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.

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 price at which power will be supplied. 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 sell its generation 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 at all. 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 on going 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 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 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 would 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.

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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 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.

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 or at a generating facility owned by a third party to which the Corporation’s transmission assets are connected. 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 materially adversely affect 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.

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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 the markets is likely to 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 the energy markets is likely to 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 could 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 are subject to the level of 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, if material, 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, boiler and machinery coverage, replacement power and business interruption insurance, in amounts and with deductibles that the Corporation considers appropriate. The Corporation’s insurance coverage may not be available in

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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 each 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 six collective bargaining agreements, involving 404 of its employees, in 2010 and an additional three collective bargaining agreements, involving 540 of its employees, in 2011. 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

TransAlta continues to focus on expanding its business through development projects and acquisitions. The development and construction of the Corporation’s projects are 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. Such risks may 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.

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

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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, including the acquisition of Canadian Hydro. 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, 2009, the Corporation had 2,228 full and part time employees, of which 1,295 were employed in TransAlta’s generation business and 59 were employed in TransAlta’s energy marketing 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 2009, the Corporation renewed five of the agreements; an additional six agreements are expected to be re-negotiated in 2010.

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 22, 2010, there were 218,597,610 common shares outstanding and no 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 of Directors, 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.

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

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right to one vote for each $25 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.

CREDIT RATINGS

Issuer Rating

As of December 31, 2009, the Corporation’s corporate credit rating from S&P was BBB (stable), its senior unsecured debt rating from Moody’s was Baa2 (stable), and its issuer rating from DBRS was BBB (stable).

Senior Unsecured Long Term Debt

As of December 31, 2009, the Corporation’s senior unsecured long term debt is rated BBB (stable) by DBRS, BBB (stable) by S&P and Baa2 (stable) 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.

According to the Moody’s rating system, 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.

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.

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DIVIDENDS

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:

Period		Dividend per Common Share

2007	First Quarter	$0.25
	Second Quarter	$0.25
	Third Quarter	$0.25
	Fourth Quarter	$0.25

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

On January 29, 2010, the Corporation’s Board of Directors declared a cash dividend of $0.29 per common share, payable on April 1, 2010 to shareholders of record on March 1, 2010.

MARKET FOR SECURITIES

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

2009
January	26.60	21.13	10,881,392
February	22.96	18.50	16,191,905
March	21.05	17.96	23,251,069
April	21.29	18.14	18,614,529
May	21.57	19.81	17,675,250
June	23.93	19.80	23,782,366
July	22.40	20.56	13,891,386
August	22.91	20.86	17,313,964
September	22.22	20.61	13,392,244
October	22.05	20.10	12,836,564
November	22.23	20.04	19,249,898
December	23.65	21.51	15,714,132

2010
January	23.98	22.06	12,926,828
February 1 to 22	24.00	21.62	7,670,115

PRIOR SALES

In the 12 months prior to the date hereof, the following securities of the Corporation have been issued:

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Common Shares

The following table summarizes the issuances of Common Shares within the twelve month period prior to the date of this short form prospectus.

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

November 5, 2009(1)	20,522,000 Common Shares	$20.10	Public Offering

Note:

(1) Common Shares were issued pursuant to the Corporation’s public offering of Common Shares pursuant to a prospectus supplement dated October 29, 2009. See “General Development of the Business —Year Ended December 31, 2009”.

DIRECTORS AND OFFICERS

The name, province or state and country of residence of each of the directors and officers of TransAlta as at February 21, 2010, 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 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. and Chair of the Board of 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 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 December 1996 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, CEO and Vice-Chairman of Sempra Energy. 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 Audit and Risk Committee and 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.

Stanley J. Bright(2) Maryland, U.S.A.	1999	*Corporate Director.* Mr. Bright was Chairman, President and CEO of MidAmerican Energy Company (“MidAmerican”) from 1997 to 1999 (electric and gas utility). He was also Chairman, President, and CEO of predecessor companies, including the Iowa Illinois Gas & Electric Company (“IIG&E”) from 1991 to 1997. As the CEO of IIG&E, Mr. Bright was successful with the consolidation of IIG&E and other Iowa based utilities in anticipation of emerging market competition, giving rise to the creation of MidAmerican. As the Chairman, President and CEO of the new entity, Mr. Bright led the realization of significant merger related synergies while working through the post-merger transition. The company also structured a long-term rate plan with the Iowa Public Service Commission. He retired as CEO of MidAmerican in 1999 but continued as a director until 2006. At TransAlta, Mr. Bright is a member of the Human Resources Committee of the Board.

		Mr. Bright holds an undergraduate degree in accounting from The George Washington University (Washington, D.C.) and is a Certified Public Accountant.

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

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, Shell Pension Trust Limited and AMEC plc. He is a past director of Enerflex Systems Income Fund.

		At TransAlta, Mr. Faithfull is 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, U.K.

Ambassador Gordon D. Giffin 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/U.S. 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, D.C. 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 Income Fund.

		At TransAlta, Mr. Giffin is Chair of the Governance and Environment Committee of the Board.

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

		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., CCR Technologies Ltd. and Orion Oil & Gas Ltd. and a director of Matrikon Inc., Axia NetMedia Corporation and CanElson Drilling Inc.

		At TransAlta, Mr. Jespersen is a member of the Governance and Environment 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).

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 $3.4 billion.

		Mr. Kanovsky is a director of Argosy Energy Corporation, ARC Energy Trust, Bonavista Energy Trust, Devon Energy Corporation, and Pure Technologies Ltd.

		At TransAlta, Mr. Kanovsky is a member of the Audit and Risk Committee of the Board.

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

		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 Chair of the Board and an ex officio member of all committees 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).

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 Oil & Gas Trust 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.

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

		At TransAlta, Mr. Lackenbauer is a member of the Governance and Environment Committee and the Audit and Risk 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.

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 Human Resources Committee and the Governance and Environment 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.

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

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 director of the Calgary Stampede Foundation Campaign. He is an immediate past Director of the Canadian Imperial Bank of Commerce, past Chair of the Calgary Stampede Foundation, and past Chair of the Alberta Secretariat for Action on Homelessness. Mr. Snyder is the past Chair of 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, and the Conference Board Honorary Associate Award for 2008 and in 2009 the Chamber of Commerce Sherrold Moore Award of Excellence.

Notes:

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

(2) Mr. Bright served as a director of Access Air Inc. (“Access Air”) for the period of December 4, 1997 to January 31, 2000, a privately held start up airline company. The company Mr. Bright was employed by, and whom he represented on the Access Air board, supported Access Air in the hope that it would improve air service to the state of Iowa. Access Air filed for bankruptcy protection on November 29, 1999.

(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
Brian Burden	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
W. Frank Hawkins	Vice-President and Treasurer	Alberta, Canada
Hume D. Kyle	Vice-President, Finance and Controller	Alberta, Canada
Maryse C. St.-Laurent	Vice-President and Corporate Secretary	Alberta, Canada

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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 April 2009, Brian Burden was Executive Vice-President and Chief Financial Officer of the Corporation. Prior to December 2005, he was Executive Vice-President and Chief Financial Officer of Molson Inc. Prior to 2002, he was Senior Vice-President, Seagram Corporate/Venture Transition of Diageo PLC.

· Prior to April 2009, Kenneth Stickland was Executive Vice-President, Legal, SD and EH&S of the Corporation. Prior to April, 2007, he was Executive Vice-President, Legal.

· Prior to April 2009, Michael Williams was Executive Vice-President, Human Resources, IT and Communications of the Corporation. Prior to July 2007, he was Executive Vice-President, HR & Communications.

· 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.

· Prior to April 2009, Frank Hawkins was Vice-President and Treasurer of the Corporation. Prior to June 2007, he was Assistant Treasurer.

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

· Prior to April 2009, Maryse St.-Laurent was Corporate Secretary of the Corporation. Prior to June 2005, she was Secretary of TC PipeLines, LP since September 2003 and Recording Secretary since January 2001, and Senior Legal Counsel TransCanada Corporation since June 1997.

As of February 23, 2010, the directors and executive officers of TransAlta, as a group, beneficially owned, directly or indirectly, or exercised control or direction over an aggregate of 722,564 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 10 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 2010 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, 2009, there has been no indebtedness outstanding to TransAlta from any of TransAlta’s directors, nominees for election as directors, executive officers, senior officers or associates of any such directors, nominees or officers.

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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 10 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 10 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:

(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

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Corporation’s audited consolidated financial statements for the year ended December 31, 2009 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 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 from the Vice-President and Corporate Secretary of TransAlta Corporation.

Additional financial information is provided in TransAlta’s audited consolidated financial statements as at and for the year ended December 31, 2009 and in the Annual MD&A, each of which is incorporated by reference in this Annual Information Form. See “Documents Incorporated by Reference” herein.

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), Stephen L. Baum, Michael M. Kanovsky, 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 and Mr. Gordon S. Lackenbauer 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.

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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.

Name of ARC Member		Relevant Education and Experience

W. D. Anderson		Mr. Anderson is a Chartered Accountant. 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.

Stephen L. Baum		Mr. Baum has over 25 years of financial, legal and industry experience gained working as a senior officer, director and Chairman of energy companies. During his tenure as CEO of Sempra Energy, Mr. Baum had financial officers reporting directly to him. Mr. Baum also serves as Chairman of the Audit Committee of Computer Sciences Corporation, a NYSE listed company. Mr. Baum holds a law degree from the University of Virginia.

M. M. Kanovsky		Mr. Kanovsky has over 30 years of financial and industry experience gained through working in the investment banking business as well as a director, officer and audit committee member of several public companies and trusts. Mr. Kanovsky is a graduate of the MBA program from the Richard Ivey School of Business at the University of Western Ontario.

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 MBA degree from the University of Western Ontario and is a Chartered Financial Analyst.

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Name of ARC Member		Relevant Education and Experience

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, 2009 are:

Governance and Environment Committee		Human Resources Committee

Chair: Ambassador Gordon D. Giffin		Chair: Timothy W. Faithfull
C. Kent Jespersen		Stephen L. Baum
Gordon S. Lackenbauer		Stanley J. Bright
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, 2009 and December 31, 2008, Ernst & Young LLP and its affiliates were paid $3,562,032 and $3,372,142, respectively, as detailed below:

Ernst & Young LLP

Year Ended Dec. 31	2009		2008

Audit Fees	$	2,679,080	$	2,594,183
Audit related fees	824,631		432,343
Tax fees	58,321		345,616

Total	$	3,562,032	$	3,372,142

No other audit firms provided audit services in 2009 or 2008.

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 2009 include payments related to 2008 in the amount of $1,212,080. Total audit fees for 2008 include payments related to 2007 in the amount of $1,403,923.

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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 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 or any of its members 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 of its members may call a special meeting of the Committee at any time. Although the Corporation’s Chief Executive Officer may attend meetings of the Committee, the Committee shall also meet in separate executive sessions.

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8. Quorum

A majority of the members of the Committee present in person or by telephone or other telecommunication device that permits all persons participating in the meeting to speak to each other, shall constitute a quorum.

9. Notice of Meetings

Notice of the time and place of every meeting shall be given in writing (including by way of written facsimile communication or email) to each member of the Committee at least 48 hours prior to the time fixed for such meeting, provided, however, that a member may in any manner waive notice of a meeting; and attendance of a member at a meeting constitutes a waiver of notice of the meeting, except where a member attends for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called. Notice of every meeting shall also be provided to the external and internal auditors.

10. Attendance at Meetings

At the invitation of the Chair of the Committee, other Board members, officers or employees of the Corporation, the external auditors, and other experts or consultants may attend a meeting of the Committee.

11. Procedure, Records and Reporting

Subject to any statute or the articles and by-laws of the Corporation, the Committee shall fix its own procedures at meetings, keep records of its proceedings and report to the Board generally not later than the next scheduled meeting of the Board.

12. Review of Charter

The Committee shall evaluate its performance and review and reassess the adequacy of its Charter at least annually or otherwise, as it deems appropriate, and if necessary propose changes to the Governance and Environment Committee and the Board for review and approval.

13. Outside Experts and Advisors

The Committee Chair, on behalf of the Committee, or any of its members is authorized, at the expense of the Corporation, when deemed necessary or desirable, to retain independent counsel, outside experts and other advisors to advise the Committee independently on any matter.

B. Mandate of the Committee

The Committee provides assistance to the Board in fulfilling its oversight responsibilities to shareholders, the investment community and others, relating to the integrity of the Corporation’s financial statements, the financial reporting process, the systems of internal financial controls, the risk identification assessment conducted by management and the programs established by management in response to such assessment, the internal audit function and 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 that are in compliance 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.

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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

The Committee shall:

(a) 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;

(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)	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

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	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;

(vii)	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; and

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

(b) review with management and the Corporation’s 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;

(ii)	review any report or opinion to be rendered in connection therewith;

(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 the release of all to the public;

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(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)	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;

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

(h)	review and recommend to the Board for approval the Corporation’s issuance and redemption of securities, financial commitments and limits, and any material changes underlying any of these commitments;

(i)	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;

(j)	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;

(k)	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;

(l)	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;

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

(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 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;

(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)	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

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	objectives of the plans, the statement of investment policy, the appointment of investment managers, and reporting thereon to the Board annually;

(r)	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;

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

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

(u)	review annually the Corporation’s annual sponsorship, donations and political contributions;

(v)	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;

(w)	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;

(x)	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;

(y)	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;

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

(aa)	review disclosure made to the Committee by the Chief Executive Officer, Chief Financial Officer 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;

(bb)	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;

(cc)	report annually to shareholders on the work of the Committee during the year;

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(dd)	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;

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

2. 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

(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;

(c)	review the Corporation’s enterprise risk management framework and reporting methodology;

(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

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PRESENTATION OF INFORMATION	1
SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS	1
DOCUMENTS INCORPORATED BY REFERENCE	2
CORPORATE STRUCTURE	2
OVERVIEW	3
GENERAL DEVELOPMENT OF THE BUSINESS	4
BUSINESS OF TRANSALTA	8
ENVIRONMENTAL RISK MANAGEMENT	24
RISK FACTORS	27
EMPLOYEES	35
CAPITAL STRUCTURE	35
CREDIT RATINGS	36
DIVIDENDS	37
MARKET FOR SECURITIES	37
PRIOR SALES	37
DIRECTORS AND OFFICERS	38
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	45
INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS	45
CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS	46
CONFLICTS OF INTEREST	46
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	46
TRANSFER AGENT AND REGISTRAR	47
INTERESTS OF EXPERTS	47
ADDITIONAL INFORMATION	47
AUDIT AND RISK COMMITTEE	47
APPENDIX “A” – AUDIT AND RISK COMMITTEE CHARTER	A-1
APPENDIX “B” – GLOSSARY OF TERMS	B-1

(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 on going 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.

APPENDIX “A” – AUDIT AND RISK COMMITTEE CHARTER

APPENDIX “B” – GLOSSARY OF TERMS