TRANSALTA CORPORATION

2009 RENEWAL ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2008

MARCH 16, 2009

- i -

TABLE OF CONTENTS

- 1 -

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, 2008.  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.  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.

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) disruptions in the source of fuels or water required to operate the Corporation’s facilities; (viii) trading risks; (ix) fluctuations in the value of foreign currencies and foreign political risks; (x) need for additional financing; (xi) liquidity risk; (xii) structural subordination of securities; (xiii) counterparty credit risk; (xiv) insurance risk; (xv) the Corporation’s provision for income taxes; (xvi) legal proceedings involving the Corporation; (xvii) reliance on key personnel and (xviii) labour relations matters and (xix) absence of a public market for certain of the securities offered.  The foregoing risk factors, among others, are described in further detail under the heading “Risk Factors” 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, 2008 (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 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, 2008 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.

- 2 -

CORPORATE STRUCTURE

Name and Incorporation

TransAlta Corporation was formed by Certificate of Amalgamation issued under the Canada Business Corporations Act 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 Canada Business Corporations Act.  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 issued a Certificate of Amalgamation under the Canada Business Corporations Act 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 an internal reorganization whereby the assets and business affairs of TAU and TEC (with the exception of the wind business) were transferred to TransAlta Generation Partnership, a new Alberta general partnership, whose partners are TransAlta Corporation and TransAlta Generation Ltd., a wholly-owned subsidiary of TransAlta Corporation. TransAlta Generation Partnership is managed by TransAlta Corporation pursuant to the terms of the partnership agreement and a management services agreement.  Immediately following the transfer of assets by TAU and TEC to TransAlta Generation Partnership, TransAlta Corporation amalgamated with TAU, TEC, and Keephills 3 GP Ltd. pursuant to the Canada Business Corporations Act.  TransAlta remains the holding entity of the various businesses of the Corporation, some of which are now held directly, in the case of the wind assets, and some of which are now held indirectly, in the case of the former generation assets and businesses of TAU and TEC.

As of January 1, 2009, the principal subsidiaries of the Corporation and their respective jurisdictions of formation are set out below.

- 3 -

Unless the context otherwise requires, all references to the “Corporation” and to “TransAlta” herein refer to TransAlta Corporation and its subsidiaries on a consolidated basis.  References to “TransAlta Corporation” herein refer to TransAlta Corporation, excluding its subsidiaries.

OVERVIEW

TransAlta and its predecessors have been engaged in the production and sale of electric energy since 1909.  The Corporation is among Canada’s largest non regulated electricity generation and energy marketing companies with an aggregate net ownership interest of 7,976 megawatts (“MW”) of generating capacity1 operating in facilities having approximately 9,697 MW of aggregate generating capacity. In addition, the Corporation has facilities under construction with a net ownership interest of 456 MW, of an aggregate generating capacity of 681 MW.  The Corporation is focused on generating electricity in Canada, the United States and Australia through its diversified portfolio of facilities fuelled by coal, gas, hydroelectric, wind and geothermal resources.

In Canada, the Corporation holds a net ownership interest of 5,661 MW of electrical generating capacity in thermal, gas-fired, wind-powered and hydroelectric facilities, including 4,937 MW in Western Canada, 628 MW in Ontario and 96 MW in New Brunswick.

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 also 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 and geothermal 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.

1              TransAlta measures capacity as the net maximum capacity that a unit can sustain over a period of time, which is consistent with industry standards.  All capacity amounts are as of the date of this Annual Information Form and represent capacity owned and operated by the Corporation unless otherwise indicated.

- 4 -

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 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 328GWh and net income declined by $17 million.  The Corporation has given notice of a High Impact Low Probability Event to the PPA Buyer and the Balancing Pool which, if successful, will protect the Corporation from the financial loss and related penalties.  The available penalties that the Corporation expects to recover in net income are anticipated to be $14 million.

·                                        On January 29, 2009, the Board of Directors of the Corporation 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.

·                                        On January 29, 2009, the Corporation announced that it will 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 at $68 million.

·                                        Effective January 1, 2009, the Corporation completed an internal 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 and TransAlta Generation Ltd., a wholly-owned subsidiary of TransAlta. TransAlta Generation Partnership is managed by TransAlta pursuant to the terms of the partnership agreement and a management services agreement.  Immediately following the transfer of assets by TAU and TEC to TransAlta Generation Partnership, TransAlta Corporation amalgamated with TAU, TEC, and Keephills 3 GP Ltd. pursuant to the Canada Business Corporations Act.  TransAlta remains the holding entity of the various businesses of the Corporation, some of which are now held directly, in the case of the wind assets, and some of which are now 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 Distribution and Customer Service Corporation (“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.

- 5 -

·                                        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 Toronto Stock Exchange (“TSX”) for the continuation of its normal course issuer bid (“NCIB”) program.  Under the NCIB program, the Corporation has 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 is estimated at $75 million with commercial operations expected to commence by the end of 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.  This project has been shortlisted by the Alberta Government for contributory funding as part of the province’s $2 billion carbon capture and storage (“CCS”) program, with a decision expected by June 30, 2009.

·                                        On February 20, 2008, the Corporation announced it had signed a purchase and sale agreement with Intergen Global Ventures B.V. 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.

·                                        On February 1, 2008, the Board of Directors of the Corporation 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 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 will also increase by $40 million, from $130 million to $170 million. The Corporation also signed a purchase and sale agreement with Vector Wind Energy,

- 6 -

a wholly owned subsidiary of Canadian Hydro Developers Inc., 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 are approximately $150 million, with final payments for goods and services due by May 2010. The total payments made under this agreement in 2007 were $18 million.

·                                        On February 26, 2007, the Corporation and EPCOR Power Development Corporation (“EPCOR”) 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 EPCOR will be equal partners in the ownership of Keephills 3, with TransAlta responsible for managing the joint venture and EPCOR responsible for the construction.  Upon completion, it is expected that TransAlta will operate the facility and EPCOR and TransAlta will independently dispatch and market their share of the unit’s electrical output.  The project has received approval from the Alberta Energy and Utilities Board and from Alberta Environment.

·                                        On January 19, 2007, the Corporation announced that it had been awarded a 25-year Power Purchase Agreement (“PPA”) to provide 75 MW of wind power to New Brunswick Power.  Under the agreement, TransAlta will construct, own and operate a wind power facility in New Brunswick.  The capital cost of the project is estimated to be $130 million.  The project is subject to regulatory and environmental approvals and is expected to begin commercial operations by the end of 2008.  Natural Forces Technologies Inc., an Atlantic Canada based wind developer, is TransAlta’s co-development partner in this project.

·                                        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.

Year ended December 31, 2006

·                                        On December 18, 2006, TransAlta Utilities assigned its rights in the development agreement it held with EPCOR, governing the joint development of the Keephills 3 power project, to K3LP.  K3LP subsequently sold a 50 per cent undivided interest in the Keephills 3 power project to the EPCOR Power Development (K3) Limited Partnership and has entered into a joint venture agreement governing the continued development of the Keephills 3 power project.  In the event the Keephills 3 power project proceeds to operation, it is anticipated that TransAlta will be the operator of the project pursuant to an operations and maintenance agreement and coal supply agreement.

·                                        On November 27, 2006, TransAlta announced it would immediately stop mining operations at its Centralia, Washington coal-mine.  TransAlta also announced that it had entered into agreements to purchase and transport coal from the Powder River Basin to fuel TransAlta’s Centralia thermal facility.

·                                        On November 17, 2006, TransAlta Utilities entered into a settlement agreement with Canadian National Railway Company for a portion of outstanding claims for lost margin and incremental expenses relating to the train derailment and resulting oil spill into Lake Wabamun in 2005.  The terms of the settlement are subject to a confidentiality agreement and cannot be disclosed.

- 7 -

·                                        On February 17, 2006, a wholly-owned subsidiary of TransAlta, together with a subsidiary of Mid-American Energy Company (“Mid-American”), entered into an agreement to purchase a 10 MW hydro facility in Hawaii to be held directly by the Wailuku Holding Company LLC, a company jointly and equally owned by TransAlta and Mid-American.

·                                        On February 15, 2006, TransAlta announced it had signed a five-year agreement with the Ontario Power Authority (“OPA”) for the supply of electricity from TransAlta’s Sarnia Regional Cogeneration Power Plant.  Under the terms of the agreement, Transalta will be available to supply an average of 400 MW of electricity to the Ontario electricity market.  The supply contract is effective until December 31, 2010.

·                                        On February 1, 2006, TransAlta Utilities entered into a development agreement with EPCOR to jointly pursue the Keephills 3 power project.  Keephills 3 is a proposed 450 MW facility adjacent to TransAlta’s existing Keephills facility, approximately 70 kilometres west of Edmonton, Alberta.

- 8 -

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, 2009:

Notes:

(1)                    Includes a 53 MW uprate expected to be commercial in 2009.

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

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

(4)                    These facilities are currently under development.

(5)                    Comprised of 13 facilities.

- 9 -

(6)                          Includes 7 individual turbines at other locations.

(7)                          Comprised of 2 facilities.

(8)                          Sarnia’s net maximum capacity (“NMC”) has been adjusted from 575 MW due to decommissioning of equipment at the facility.

(9)                          Centralia Thermal’s NMC has been reduced from 1,404 MW to reflect a lower plant output as a result of its conversion to burning Powder River Basin coal.

(10)                      Comprised of 10 facilities.

(11)                      Comprised of 4 facilities.

Canada:  Alberta

Thermal facilities

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

Notes:

(1)                         Wabamun unit 4 is expected to be removed from service upon the expiry of its license in 2010.

(2)                         Includes a 53 MW uprate expected to be commercial in 2009.

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

(4)                         This facility is currently under development.

The Keephills, Sundance and Wabamun 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 EPCOR.  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 2008 was 82.9 per cent compared with 87.1 per cent in 2007 and 88.7 per cent in 2006.  For the Sheerness facility, the weighted equivalent availability factor was 94.1 per cent in 2008 compared to 94.4 per cent in 2007 and 92.2 per cent in 2006.  For the Genesee 3 facility, the weighted equivalent availability factor was 78.2 per cent in 2008 compared to 92.9 per cent in 2007 and 96.9 per cent in 2006.

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”). 

- 10 -

TA Cogen and ATCO Power have entered into coal supply agreements with PMRL, which operates the mine, to supply coal until 2026.

Coal for the Genesee 3 facility is provided from the adjacent Genesee mine.  The coal reserves of the mine are owned, leased or controlled jointly by PMRL and EPCOR.  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 announced a proposal for a 900 MW expansion at its Keephills facility.  Although the Corporation received regulatory approval to proceed with the expansion, an application was made, in December 2004, to the AEUB to amend its 900 MW permit to allow for the construction of a smaller 450 MW facility using improved technology.

On February 1, 2006, the Corporation entered into a development agreement with EPCOR to jointly pursue the 450 MW Keephills 3 power project.  On December 18, 2006, the Corporation assigned its rights in the development agreement which it held with EPCOR for the joint development of the Keephills 3 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 and has entered into a joint venture agreement governing the continued development of the Keephills 3 power project.  The project received approval from the Alberta Energy and Utilities Board and from Alberta Environment.

On February 26, 2007, the Corporation and EPCOR commenced construction of the net 450 MW Keephills 3 power project.  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 K3LP, TransAlta and EPCOR will be equal partners in the ownership of Keephills 3, with TransAlta responsible for managing the joint venture and EPCOR responsible for construction.  Upon completion, it is expected that TransAlta will operate the facility and EPCOR 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.  On January 29, 2009, the Corporation’s estimate of total costs for Keephills 3 increased by $73 million, due to higher material and labour costs, for a total projected cost of $1.7 billion.  The Corporation continues to monitor the costs and will look for opportunities to reduce the cost increases.

Gas fired facilities

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

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. The Meridian 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 200 MW of electricity and steam to Suncor Energy Inc. (“Suncor”).  Any surplus power not used by Suncor is available for sale

- 11 -

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 Air Liquide Canada Inc.  The 118 MW Fort Saskatchewan gas fired combined cycle cogeneration plant in Alberta provides electricity and steam to Dow Chemical Canada Inc.

Hydroelectric facilities

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

The Corporation’s hydroelectric facilities are primarily peaking plants, meaning they are generally only operated during times of peak demand.

Wind Generation Facilities

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

Note:

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

The Corporation owns and operates approximately 248 MW of net capacity (excluding facilities under development) and operates approximately 285 MW of capacity primarily in three wind farms in southwestern Alberta and one in New Brunswick.

Castle River is a 40 MW facility 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 Energy Corp.

- 12 -

(“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 Pincher Creek, Fort Macleod and Hillspring areas of southwestern Alberta.

McBride Lake is a 75 MW facility 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 PPA with 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.

On October 13, 2004, TransAlta announced the commencement of commercial operations at its $100 million Summerview 68 MW wind farm located approximately 15 kilometres northeast of Pincher Creek, Alberta.  The Summerview facility, which comprises 38 1.8 MW turbines, 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.

On January 19, 2007, the Corporation announced that it had been awarded a 25 year PPA to deliver 75 MW of wind power to New Brunswick Power. On July 17, 2007, the Corporation announced it had amended its PPA 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.  Natural Forces Technologies Inc. (“Natural Forces”), an Atlantic Canada based wind developer, is TransAlta’s co-development partner in this project and Natural Forces has an option to purchase up to 17 per cent of the Kent Hills project within 180 days of its completion.

On February 13, 2008, the Corporation announced that, commencing in 2009, it would be constructing a 66 MW wind generation facility in southern Alberta, consisting of 22 Vestas V90 3 MW wind turbines.  The total capital cost for this Blue Trail wind power project is expected to be $115 million.  The capacity from this project is expected to be 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, 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 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.  With this announcement, existing and planned wind generation facilities owned and operated by the Corporation total 419 MW.  The Summerview 2 wind farm expansion is entitled to receive payments from NRCan through the eERP program.

All of the electricity generated and sold by the Corporation’s wind division is from generation 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.  The Corporation’s wind facilities constructed after April 2001, also qualify for the Green E and Green Leaf certifications.

Alberta PPAs

All of the Corporation’s Alberta thermal and hydroelectric facilities, other than the Wabamun, Genesee 3 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

- 13 -

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 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.  Until 2017, 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 four of the Wabamun facility until March 31, 2010.  The Corporation holds various licenses from Alberta Environment and the AEUB to operate its other facilities, most of which are renewed every few years.  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 Corporation is currently selling most of its electricity from the Wabamun facility on the spot market.

The Alberta PPAs (together with legislation which applies thereto) permit the Balancing Pool, an entity established by the Government of Alberta, 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:  Ontario

The Corporation’s Ontario generating facilities are summarized in the following table:

- 14 -

The Sarnia facility is a combined cycle cogeneration facility which is owned by the Corporation.  The Corporation acquired 135 MW of electric generation capacity in 2002, and in March 2003 the Corporation acquired the remaining 440 MW of capacity.  On January 1, 2009, the Corporation applied, and subsequently received approval, to decommission a 69 MW turbine at Sarnia.  The 506 MW facility provides steam and electricity to nearby facilities owned by Dow Chemical Canada Inc., Lanxess (formerly Bayer Inc.), Nova Chemicals (Canada) Ltd. and Suncor Energy Products Inc.  On February 15, 2006, TransAlta announced that it had signed a five-year agreement with the OPA for production at its Sarnia facility.  Under the terms of the contract, TransAlta will be available to supply an average of 400 MW of electricity to the Ontario electricity market.  The supply contract is effective until December 31, 2010.  On December 24, 2008, the Minister of Energy and Infrastructure directed the OPA to seek contracts with certain energy providers in Ontario, namely those listed in a December 14, 2005 Direction which includes Sarnia, for the supply of clean and efficient electricity generation.  The OPA is not required to enter a new contract with the energy provider where an agreement cannot be reached as to what constitutes a reasonable cost to Ontario electricity consumers and a reasonable balancing of risk and reward.

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 recent closure of its manufacturing facility.  Boeing remains entitled to any steam credits based on the total plant electricity generation revenue.  On or prior to each of January 1, 2013, 2018 and 2023, Boeing may give notice of its intention to continue to purchase, or discontinue, cogeneration services.  In addition, on those same dates, Boeing has the option to require the removal of the Mississauga Plant from the leased lands or purchase the Mississauga Plant at its net salvage value.

The Windsor plant is owned by TA Cogen.  It is a combined cycle cogeneration facility designed to produce 68 MW of electrical energy.  Currently, 50 MW of the capacity is sold under a long-term contract to the OEFC.  This agreement expires in 2016.  The Windsor plant also provides thermal energy to Chrysler Canada Inc.’s minivan assembly facility in Windsor.  In 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.

United States

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

- 15 -

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 and related assets on the Skookumchuk River near Centralia, which facilities are used to provide reliable water supply to TransAlta’s other generation facilities at Centralia.  TransAlta also owns a coal-mine adjacent to the Centralia facility, however, it stopped all mining operations at the mine in late 2006.

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.

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.

CE Generation

On January 29, 2003, TransAlta announced the completion of the acquisition from El Paso Corporation (“El Paso”) of a 50 per cent interest in CE Generation, for total consideration of approximately US$240 million, which included approximately US$35 million for working capital.  The CE Generation acquisition included the right to a 50 per cent interest in Salton Sea VI, a geothermal project, in the Imperial Valley, California.  While there is still future development potential for CE Generation in the Imperial Valley, the Salton Sea VI project that was being pursued when TransAlta acquired its interest in CE Generation was never developed.

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

- 16 -

capacity of 829 MW, including 327 MW of geothermal generation in California and 502 MW of gas fired cogeneration in New York, Texas and Arizona.

CE Generation affiliates currently operate 10 geothermal facilities in Imperial Valley, California.  Each of the geothermal facilities sells electricity pursuant to independent, long term contracts.

CE Generation affiliates currently 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 has contracted a tolling agreement for capacity, which expires at the end of 2009.  The New York facility sells its output pursuant to long-term contracts until mid-2009, after which point its capacity will be sold on the spot market. The intent is to re-contract both the New York facility and the Texas facility under a tolling agreement for capacity.

Wailuku

On February 17, 2006, a subsidiary of TransAlta, together with a subsidiary of Mid-American 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 which was introduced in Western Australia in late 2006.

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.

Commercial Operations and Development

The Commercial Operations 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 markets which are the most attractive to enter, and developing strategies and plans to effectively compete in each market where the Corporation operates;

·                                          Identifying specific opportunities to develop, acquire, or divest of generation assets in markets where the Corporation is operating or growing and completing the business arrangements so the Corporation can either make investment or divesture decisions;

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

- 17 -

·                                          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 those 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 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 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 western U.S.  The Corporation also owns and operates generating assets in eastern Canada and Australia.

The Corporation expects continued long-term growth of electricity demand in its core markets although short-term growth rates may be significantly reduced in the current economic environment.  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 part of its balanced approach to capital allocation which includes returning capital to shareholders through dividends and share buybacks, TransAlta also has plans for investing in new capacity in its core markets where opportunities exist for renewable and cogeneration assets.

Alberta is Canada’s fourth largest province by population with approximately 3.6 million residents representing approximately 11 per cent of Canada’s total population.  Alberta consumed approximately 70,000 GWh of electricity in 2008.  As at December 31, 2008, the aggregate installed capacity of generating facilities in Alberta was approximately 12,300 MW.

Electrical utilities in the U.S. 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 369,000 GWh of electricity was consumed in the NWPP in 2008.  The WECC also reported an estimated aggregate electrical generating capacity of approximately 85,000 MW in the NWPP for the year ending 2008.

- 18 -

Ontario is Canada’s largest province with approximately 12.9 million residents representing approximately 39 per cent of Canada’s total population.  Ontario consumed approximately 148,700 GWh of electricity in 2008.  Ontario Power Generation Inc., the successor to the generation business of Ontario’s former integrated electric utility, controls two thirds of Ontario’s approximately 32,000 MW of installed capacity, the balance of which is owned by municipal electric utilities and private independent power producers or industrial consumers.

In October 2004, the provincial government of New Brunswick officially opened the electricity market to partial competition and corporate reorganization. The Electricity Act (2004) allows wholesale and industrial consumers to purchase power from either New Brunswick Power or a competing supplier. The new competitive market does not extend to retail customers, businesses or small industries.  In 2007, New Brunswick announced the Charter for Change requiring ten per cent of electricity purchases to be from renewable sources commencing in 2016.

The Corporation expects that the demand for electricity will continue to grow in its target markets over the long-term.  In addition to increased demand, the market for electricity in some of these regions has undergone deregulation.  Legislation in Alberta and Ontario and many states in the United States have mandated the unbundling of generation, transmission and distribution services which were traditionally provided by vertically integrated utilities to promote competition in the market for generation, which caused some integrated utilities to sell all or parts of their generation assets.  While the pace of this process has changed, the Corporation believes that the combination of increased demand for electricity, deregulation and the increased availability of generation assets may provide an opportunity to increase its generation capacity and leverage its Commercial Operations Development capabilities, provided that in doing so, the financial position of the Corporation is not compromised.

Australia is heavily dependent on coal for electricity, more so than any other developed country except Denmark and Greece.  About 80 per cent of power produced is 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 272,000 GWh for 2008 with a growth rate of approximately 2.4 per cent per annum from 2009 to 2012.  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 345 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 70 per cent of the Corporation’s generating capacity is contracted through PPAs or LTC’s for the next five years.  Revenues received under contractual arrangements are not subject to short-term fluctuations in the spot price for electricity.

Fuel diversity - The Corporation has a diverse mix of fuels used for the generation of electricity, including coal, natural gas, hydro, geothermal and wind.  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.

- 19 -

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

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:

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.

To meet regulatory requirements and improve environmental performance, TransAlta made environmental operating and capital expenditures in fiscal year 2008 of approximately $47 million.  Environmental expenditures are generally defined as expenditures incurred to comply with Canadian or international environmental regulations, conventions or voluntary agreements.

- 20 -

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:

On a longer time horizon, 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

On January 24, 2008, the Government of Alberta announced its long-term intention to cut greenhouse gas emissions to 14 per cent below 2005 levels by 2050 through developing and implementing carbon capture and storage technologies, developing conservation and energy efficiency programs, and through increased investment in clean energy technologies.  We are assessing the impact of this proposal upon our operations and our own investment in environmental technologies and programs.

Alberta continues to maintain its greenhouse gas (“GHG”) regulatory regime which was implemented in July 1, 2007, under the Climate Change and Emissions Management Amendment Act.  Under the legislation, baselines and targets for GHG intensity are set on a facility-by-facility basis.  The legislation and subsequent regulations require a 12 per cent reduction in GHG emission intensity from a baseline of the average of 2003 to 2005 emission levels.  New facilities or those in operation for less than three years are exempt; however, upon the fourth year of operations, the facility baseline is established and reduction requirements gradually increase until the eighth year by which time emissions must be 12 per cent below the established baseline.  Emissions over the baseline must be mitigated either through contributions to an Alberta Technology Fund at $15 per tonne, or through the purchase and retirement of Alberta-based offsets from non-regulated sectors.  The PPAs for our Alberta-based coal facilities contain change-in-law provisions that allow us to recover compliance costs from the PPA customers.  After flow-through, the annual net compliance costs for 2008 are estimated to be $1.2 million.

Mercury reduction requirements in Alberta are established at a 70 per cent reduction by 2010.  We submitted our mercury control plan in March 2007.  Detailed mercury technology testing was conducted in 2008 and further is expected in 2009.  Engineering work is underway to have mercury controls fully implemented in 2010.

On April 26, 2007, the Canadian government released details of its proposed environmental legislation in its Turning the Corner policy paper. The federal plan calls for an 18 per cent reduction in GHG emission intensity starting in 2010, increasing to a 20 per cent absolute reduction requirement by 2020. The plan also calls for a reduction in air pollutants such as sulphur dioxide, nitrous oxide, mercury, and particulates starting in the 2012 - 2015 period. Proposed reduction caps range from 45 per cent to 60 per cent of current levels.  A number of material details in the

- 21 -

federal plan are still to be determined, including its interaction with provincial programs, which would allow a reasonable determination of future compliance costs.

The Canadian government indicated in January 2009 that it intends to develop an integrated cap and trade program for greenhouse gas emissions, in cooperation with its North American trading partners.  There are few details of this new approach and it is therefore not possible to determine what compliance costs would be or how it might affect the previous approach.

In August 2007, the Government of Ontario announced its climate change action plan which included a target to reduce GHG emissions by 6 per cent below 1990 level by 2014.  Subsequently the government has indicated its intention to implement a cap and trade system for greenhouse gases by 2010, although no additional legislation or details have been developed.

United States

In the United States, the Washington State Climate Bill 6001 was enacted and came into effect on July 22, 2007.  Our operations will not be impacted by the bill’s performance standards at the current time, provided the facilities do not change ownership or enter into power sales contracts longer than five years.

On December 12, 2008, Washington State introduced draft legislation to enable a cap and trade system to be implemented by 2012.  Specific details of caps and allocations will be developed in 2009.  In parallel, Washington State is engaged with other western states in the Western Climate Initiative (“WCI”) to examine a regional cap and trade system for carbon.  On September 23, 2008, the WCI released its design for a regional greenhouse gas cap and trade system, which will be influential in individual state regulation development.  At this point, there are no indications as to how these initiatives will impact our fossil-fired assets in Washington.

The United States Federal Government continues to contemplate a number of proposed GHG related bills, but to date no clear outcome or schedule is evident.  In February 2009, the Administration provided a budget plan for implementing an economy-wide federal cap & trade system to reduce greenhouse gases to 14 per cent below 2005 levels by 2020.  The budget includes a plan to auction 100 per cent of the required allowances, with approximately $150B of the revenue raised from auctioning to be allocated to clean energy investments over 10 years.

TransAlta is an active participant in the Canadian Clean Power Coalition, which is committed to developing clean coal technology in Canada.  The coalition has several engineering initiatives underway which will provide important guidance on ultimate clean coal solutions for TransAlta’s facilities.  The Corporation is also exploring the possibilities for a CO2 network pipeline through the ICON industry consortium.

In April 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.  This project has been shortlisted by the Alberta Government for contributory funding as part of the province’s $2 billion CCS program, with a decision expected by June 30, 2009.

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 at all times.

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.

- 22 -

To date, TransAlta does not believe that its competitive position in the wholesale generation business has been adversely affected by environmental concerns.  TransAlta continues to make operational improvements and investments to its existing generating facilities to reduce the environmental impact of generating electricity.

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 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;

·              demand for energy products;

·              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

- 23 -

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.

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 Canadian, United States and other 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 (as defined herein) 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

- 24 -

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 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.

A number of recent federal, provincial, state and local regulatory efforts continue to focus on potential climate change or GHG emissions regulation.  GHG legislation is in early stages of evolution in Canada and the United States, and it is relatively early to determine the impact of potential GHG reduction requirements.  For example, the issues of jurisdiction to regulate GHG emissions, as between the federal and provincial governments, and whether both levels of government will be able to agree on harmonization of desired GHG emissions reduction requirements, also remains outstanding in Canada.  In addition, Washington is part of a group of states in the Western Climate Initiative, which have announced the intention to implement a cap and trade program for GHGs by 2012.  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 our customers under our 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 aspect 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 government mandated power purchase arrangements (the “Alberta PPAs”).

Under the government mandated power purchase arrangements pursuant to which the Corporation operates most of its 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 coal fired 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.

- 25 -

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.

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.

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

Hydroelectric, natural gas, 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

- 26 -

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 Alberta.  Any such change in regulations could have a material adverse effect on the Corporation.

Trading risks may have a material adverse affect 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 long 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 to limit its exposure to risks arising from its trading activities, including value-at-risk, 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.

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, 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.

- 27 -

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.

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.

- 28 -

Insurance coverage may not be sufficient.

The Corporation has insurance for its facilities, including all risk property insurance, commercial general public 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 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 of or any 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 accordance with all such tax interpretations, regulations, and legislation, the Corporation cannot guarantee that it will not have disagreements with the Canada Revenue Agency or other taxation authorities with respect to the Corporation’s tax filings.

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.  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 good 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.  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.

EMPLOYEES

As of December 31, 2008, the Corporation had 2,110 full and part-time employees, of which 1,529 were employed in TransAlta’s generation business and 147 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 2008, the Corporation renewed three of the agreements, an additional five agreements are expected to be re-negotiated in 2009, and the remaining three agreements are expected to be re-negotiated in 2010.

- 29 -

CAPITAL STRUCTURE