EX-13.1 2 a13-5903_1ex13d1.htm TRANSALTA CORPORATION ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2012

Exhibit 13.1

TRANSALTA CORPORATION

2013 RENEWAL ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2012

February 26, 2013

TABLE OF CONTENTS |
PRESENTATION OF INFORMATION | 1
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS | 1
DOCUMENTS INCORPORATED BY REFERENCE | 2
CORPORATE STRUCTURE | 2
OVERVIEW | 3
GENERAL DEVELOPMENT OF THE BUSINESS | 5
BUSINESS OF TRANSALTA | 11
ENVIRONMENTAL RISK MANAGEMENT | 29
RISK FACTORS | 31
EMPLOYEES | 41
CAPITAL STRUCTURE | 41
CREDIT RATINGS | 46
DIVIDENDS | 47
COMMON SHARES | 47
SERIES A SHARES | 48
SERIES C SHARES | 48
SERIES E SHARES | 48
MARKET FOR SECURITIES | 49
COMMON SHARES | 49
SERIES A SHARES | 49
SERIES C SHARES | 50
SERIES E SHARES | 50
DIRECTORS AND OFFICERS | 51
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS | 58
INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS | 59
CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS | 59
CONFLICTS OF INTEREST | 60
LEGAL PROCEEDINGS AND REGULATORY ACTIONS | 60
TRANSFER AGENT AND REGISTRAR | 60
INTERESTS OF EXPERTS | 60
ADDITIONAL INFORMATION | 61
AUDIT AND RISK COMMITTEE | 61
APPENDIX “A” – AUDIT AND RISK COMMITTEE CHARTER | A-1
APPENDIX “B” – GLOSSARY OF TERMS | B-1

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PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this annual information form (“Annual Information Form” or “AIF”) is given as at or for the year ended December 31, 2012. On January 1, 2011, we adopted International Financial Reporting Standards (“IFRS”) for Canadian publicly accountable enterprises. Prior to the adoption of IFRS, we followed Canadian Generally Accepted Accounting Principles (“Canadian GAAP” or “our previous GAAP”). All dollar amounts are in Canadian dollars unless otherwise noted. Unless the context otherwise requires, all references to the “Corporation” and to “TransAlta”, “we”, “our” and “us” herein refer to TransAlta Corporation and its subsidiaries on a consolidated basis. References to “TransAlta Corporation” herein refer to TransAlta Corporation, excluding its subsidiaries.

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 our beliefs as well as assumptions based on information available at the time the assumption was made and on management’s experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as “may”, “will”, “believe”, “expect”, “anticipate”, “intend”, “plan”, “foresee”, “potential”, “enable”, “continue” or other comparable terminology. These statements are not guarantees of our future performance and are subject to risks, uncertainties and other important factors that could cause our actual performance to be materially different from that projected.

In particular, this Annual Information Form contains forward-looking statements pertaining to the following: expectations relating to the timing, completion and commissioning of projects under development, including uprates and major projects, and their attendant costs; our estimated spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations, capital spend, and maintenance, and the variability of those costs; the impact of certain hedges on future reporting earnings and cash flows; expectations related to future earnings and cash flow from operating and contracting activities; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity in both the short-term and long-term, and the resulting impact on electricity prices; expected impacts of load growth and natural gas costs on power prices; expectations in respect of generation availability, capacity and production; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation and their expected impact on us, as well as the cost of complying with resulting regulations and laws; our trading strategy and the risk involved in these strategies; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; accounting estimates; expectations for the outcome of existing or potential legal and contractual claims; expectations for the ability to access capital markets at reasonable terms; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the U.S. dollar; the monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment; our credit practices; and the estimated contribution of energy trading activities to gross margin.

Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in market prices and the availability of fuel supplies required to generate electricity; our ability to contract our generation for prices that will provide expected returns, the regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; changes in general economic conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather; disruptions in the source of fuels, water or wind required to operate our facilities; natural disasters; the threat of domestic terrorism and cyber-attacks; equipment failure; energy trading risks; industry risk and competition; fluctuations in the value of foreign currencies and foreign political risks; the need for additional financing; structural subordination of securities; counterparty credit risk; insurance coverage; our provision for income taxes; legal and contractual proceedings involving the Corporation; reliance on key personnel; labour relations matters; and development projects and acquisitions. The foregoing risk factors, among others, are described in further detail under the heading “Risk Factors” in this Annual Information Form and in the documents incorporated by reference in this Annual Information Form, including our Management’s Discussion and Analysis for the year ended December 31, 2012 (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

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document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties and assumptions, the forward-looking events might occur to a different extent or at a different time than we have described or might not occur. We cannot assure that projected results or events will be achieved.

DOCUMENTS INCORPORATED BY REFERENCE

TransAlta’s audited consolidated financial statements for the year ended December 31, 2012 and related Annual MD&A are hereby specifically incorporated by reference in this AIF. Copies of these documents are available on SEDAR at www.sedar.com.

CORPORATE STRUCTURE

Name and Incorporation

TransAlta Corporation was formed by Certificate of Amalgamation issued under the Canada Business Corporations Act (the “CBCA”) on October 8, 1992. On December 31, 1992, a Certificate of Amendment was issued in connection with a plan of arrangement involving TransAlta Corporation and TransAlta Utilities Corporation (“TransAlta Utilities” or “TAU”) under the CBCA. The plan of arrangement, which was approved by shareholders on November 26, 1992, resulted in common shareholders of TransAlta Utilities exchanging their common shares for shares of TransAlta Corporation on a one for one basis. Upon completion of the arrangement, TransAlta Utilities became a wholly owned subsidiary of TransAlta Corporation.

Effective January 1, 2009, TransAlta completed a reorganization (the “Reorganization’), whereby the assets and business affairs of TAU and TransAlta Energy Corporation (“TransAlta Energy” or “TEC”) (with the exception of the wind business) were transferred to TransAlta Generation Partnership, a new Alberta general partnership, whose partners are TransAlta Corporation and TransAlta Generation Ltd., a wholly owned subsidiary of TransAlta Corporation. TransAlta Generation Partnership is managed by TransAlta Corporation pursuant to the terms of the partnership agreement and a management services agreement.

Immediately following the transfer of assets by TAU and TEC to TransAlta Generation Partnership, TransAlta Corporation amalgamated with TAU, TEC, and Keephills 3 GP Ltd. pursuant to the CBCA. TransAlta Corporation remains the holding entity of the various businesses of the Corporation, some of which are now held directly, in the case of certain wind assets, and some of which are now held indirectly, in the case of both the former generation assets and businesses of TAU and TEC and the assets and business of Canadian Hydro Developers, Inc. (“Canadian Hydro”). TransAlta completed its acquisition of Canadian Hydro on November 4, 2009.

TransAlta amended its articles on December 7, 2010 to create its First Preferred Series A and B shares; on November 23, 2011 to create the First Preferred Series C and D shares; and again on August 3, 2012 to create the First Preferred Series E and F shares.

The registered and head office of TransAlta is located at 110 - 12 th Avenue S.W., Calgary, Alberta, Canada, T2R 0G7.

As of December 31, 2012, the principal subsidiaries of TransAlta Corporation and their respective jurisdictions of formation are set out below:

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Notes:

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

OVERVIEW

TransAlta and its predecessors have been engaged in the production and sale of electric energy since 1909. We are among Canada’s largest non-regulated electricity generation and energy marketing companies with an aggregate net ownership interest of 8,408 megawatts (“MW”) of generating capacity. We operate facilities having approximately 10,280 MW of aggregate generating capacity. In addition, we have facilities under construction with a net and aggregate ownership interest of 68 MW of generating capacity, as well as 560 MW of generating capacity under restoration in Sundance units 1 and 2. Total net ownership is 9,051 MW of generating capacity in facilities that have or will have aggregate capacity of 10,923 MW. We are focused on generating electricity in Canada, the United States and Western Australia through our diversified portfolio of facilities fuelled by coal, natural gas, diesel, hydroelectric, wind and geothermal resources.

In Canada, excluding assets under development and restoration, we hold a net ownership interest of approximately 6,002 MW of electrical generating capacity in thermal, natural gas-fired, wind powered and hydroelectric facilities, comprised of 4,738 MW in Western Canada, 1,040 MW in Ontario, 99 MW in Québec and 125 MW in New Brunswick.

In the United States, our principal facilities include a 1,340 MW thermal facility and a 248 MW natural gas-fired facility, both located in Centralia, Washington, which supply electricity to the Pacific Northwest. We also hold a 50 per cent interest in CE Generation, LLC (“CE Generation”), through which we have an aggregate net ownership

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interest of approximately 385 MW of generating capacity in geothermal facilities in California and natural gas-fired facilities in Texas, Arizona and New York. In addition, we have 6 MW of electrical generating capacity through hydroelectric facilities located in Washington and Hawaii.

In Australia, we have 425 MW of net electrical generating capacity from natural gas and diesel-fired generation facilities that are located at customer mine sites.

We regularly review our operations in order to optimize our generating assets and evaluate appropriate growth opportunities to maximize value to the Corporation. We have in the past and may in the future make changes and additions to our fleet of coal, natural gas, hydro, wind and geothermal fuelled facilities.

TransAlta’s Map of Operations

The following map outlines TransAlta’s operations as of December 31, 2012.

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GENERAL DEVELOPMENT OF THE BUSINESS

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

The significant events and conditions affecting our 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 AIF.

Recent Developments

2013

Puget Sound Energy PPA

On January 9, 2013, the Washington Utilities and Transportation Commission (the “WUTC”) conditionally approved the proposed long-term power purchase agreement (“PPA”) between Puget Sound Energy (“PSE”) and TransAlta Centralia Generation LLC for power output from our Centralia, Washington power plant. On January 23, 2013, PSE filed a petition for reconsideration of certain conditions within the decision issued by WUTC. On February 5, 2013, the WUTC granted a 30-day extension to the petition and indicated that it would issue its decision on the petition no later than March 29, 2013.

Generation and Business Development

2012

Sundance Unit 3

On June 7, 2010, an outage occurred at unit 3 of our Sundance facility caused by the mechanical failure of critical generator components, which outage resulted in the unit operating at a reduced capacity level. In response to the event, the Corporation gave notice of a High Impact Low Probability (“HILP”) event and claimed force majeure relief under the Sundance B3 PPA. The claim was disputed by the buyers under the PPA.

The matter was heard before an arbitration panel during the third quarter of 2012. On November 23, 2012, the arbitration panel concluded that a HILP event had occurred and our claim for force majeure relief was affirmed. As a result, no penalties were due under the PPA. We have reversed the accrual for penalties and, as a result, recognized an additional $9 million in revenues for the year.

During the fourth quarter of 2012, the uprate at Sundance unit 3 was completed. The total cost of the project was approximately $25 million and it is expected that a 15 MW efficiency uprate will be achieved at the facility once the generator stator is replaced.

Acquisition of Solomon Power Station

On September 28, 2012, we announced that we completed the acquisition from Fortescue Metals Group Ltd. (“Fortescue”) of its 125 MW natural gas- and diesel-fired Solomon power station in Western Australia for U.S.$318 million. The facility is currently under construction and is expected to be commissioned in the first half of 2013. The facility is fully contracted with Fortescue under a long-term PPA with an initial term of 16 years, which term commenced in October 2012, after which Fortescue will have the option to either extend the agreement by an additional five years under the same terms, or to acquire the facility.

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Sundance Unit 6

On August 18, 2011, the Sundance unit 6 Generator Step-Up Transformer was damaged as a result of a fire. We gave notice and claimed force majeure relief under the PPA. During the third quarter of 2012, the PPA buyer informed us that they will be taking the matter to arbitration.

Centralia Thermal

On July 25, 2012, we announced that we entered into an 11-year agreement to provide electricity from the Centralia Thermal plant to PSE. The contract begins in 2014 and runs until 2025 when the plant is scheduled to be shut down under the TransAlta Energy Bill (chapter 180, Laws of 2011) that was signed on December 23, 2011. Under the agreement with PSE, PSE will buy 180 MW of firm, base-load power starting in December 2014. In December 2015, the contracted volume increases to 280 MW and from December 2016 to December 2024 the contract is for 380 MW. In the last year of the contract, the contracted volume is 300 MW. Please see “General Development of the Business – Recent Developments -2013 - Puget Sound Energy PPA” for updated information.

Sundance Units 1 and 2

On December 16, 2010 and December 19, 2010, unit 1 and unit 2, respectively, of our Sundance facility were shut down due to conditions observed in the boilers at both units. On February 8, 2011, we issued a notice of termination for destruction based on the determination that the units could not be economically restored to service under the terms of the PPA.

The matter was heard before an arbitration panel during the second quarter of 2012. On July 20, 2012, the arbitration panel concluded that units 1 and 2 were not economically destroyed and we are required to restore the facility to service. The panel affirmed that the event met the criteria for force majeure beginning on November 20, 2011 and until such time as the units are returned to service. We recorded penalties net of capacity payments, impairment on the units, and interest. The pre-tax earnings impact recorded during 2012 was $254 million. Prior to the arbitration ruling, we had been accruing the capacity payments, net of a provision, and depreciating the asset.

The cost to repair the units is estimated at approximately $190 million. Work to restore the units is expected to be completed in the fourth quarter of 2013.

Keephills Units 1 and 2 Uprates

Testing of the Keephills units 1 and 2 uprates has been completed and it was determined that the actual capability of the uprates was less than originally anticipated. As a result, we have adjusted the uprates to 13 MW bringing the maximum capability of these units to 396 MW each. The total cost of the projects was approximately $51 million.

Project Pioneer

On April 26, 2012, Project Pioneer’s industry partners announced they would not proceed with the joint carbon capture and storage (“CCS”) project. Project Pioneer was a joint effort by TransAlta, Capital Power Corporation (“Capital Power”), Enbridge Inc., and the Canadian federal and provincial governments to demonstrate the commercial-scale viability of CCS technology.

The first step of the project was to prove the technical and economic feasibility of CCS through a front end engineering and design (“FEED”) study before making any major capital commitments. Following the conclusion of the FEED study, the industry partners determined that, although it was expected that the technology would be successful and capital costs were in line with expectations, the revenue from carbon sales and the price of emissions reductions were insufficient to allow the project to proceed.

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2011

Genesee Unit 3 Outage

On November 11, 2011, the Genesee unit 3 plant, a 466 MW joint venture with Capital Power Corporation (233 MW net ownership interest), experienced an unplanned outage that resulted in damage to the turbine/generator bearings. Genesee unit 3 returned to service on January 15, 2012.

Keephills Unit 3

On September 1, 2011, our 450 MW Keephills unit 3 thermal facility, of which we have a 50 per cent ownership interest, began commercial operations. The total cost of the project was approximately $1.98 billion.

Sale of Grande Prairie Facility

On July 27, 2011, we signed an agreement to sell our interest in the biomass facility located in Grande Prairie. This sale closed on October 1, 2011, and we realized a pre-tax gain of $9 million in the fourth quarter of 2011.

Bone Creek

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

Sale of Meridian

On December 20, 2010, TransAlta Cogeneration, L.P. (“TA Cogen”), a subsidiary that is owned 50.01 per cent by TransAlta, entered into an agreement for the sale of its 50 per cent interest in the Meridian facility located in Lloydminster Saskatchewan, which sale was completed on April 1, 2011, effective January 1, 2011. We realized a pre-tax gain of $3 million during the second quarter of 2011.

New Richmond

On March 28, 2011, we announced that we had received approval from the Government of Québec to proceed with the construction of the 68 MW New Richmond wind project located on the Gaspé Peninsula. New Richmond is contracted under a 20-year Electricity Supply Agreement with Hydro-Québec Distribution. The cost of the project is estimated to be approximately $205 million and commercial operations are expected to commence during the first quarter of 2013.

2010

Kent Hills 2

On November 21, 2010, the 54 MW expansion of our Kent Hills wind farm began commercial operations on budget and ahead of schedule. The total cost of the project was approximately $100 million. Natural Forces Technologies, Inc. (“Natural Forces”) exercised its option to purchase a 17 per cent interest in the Kent Hills 2 project subsequent to the commencement of commercial operations for proceeds of $15 million based on costs incurred in 2010.

Ardenville

On November 10, 2010, our 69 MW Ardenville wind farm began commercial operations on budget and ahead of schedule. The total cost of the project was approximately $135 million.

Decommissioning of Wabamun Plant

On March 31, 2010, we fully retired all units of the Wabamun plant. Over the next several years, we completed the Wabamun plant remediation and reclamation work as approved by the Government of Alberta.

Summerview 2

On February 23, 2010, our 66 MW Summerview 2 wind farm began commercial operations on budget and ahead of schedule. The total cost of the project was approximately $118 million.

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Corporate and Energy Trading

2012

Senior Notes Offering

On November 7, 2012, we completed our offering of U.S.$400 million senior notes maturing in 2022 and bearing interest of 4.50%. The net proceeds from the offering were used to repay borrowings under existing credit facilities and for general corporate purposes.

Corporate Restructuring

On October 30, 2012, we announced a restructuring of our resources as part of our ongoing strategy to continuously improve operational excellence and accelerate growth. As part of this restructuring, we incurred a one-time pre-tax charge of approximately $13 million. We anticipate annual cost savings of approximately $25 to $30 million from these initatives by the end of 2013.

Strategic Partnership

On October 25, 2012, TransAlta and MidAmerican Energy Holdings Company (“MidAmerican”) entered into a new strategic partnership through which the two companies will work together to develop, build, and operate new natural gas-fired electricity generation projects in Canada. The agreement also encompasses our proposed Sundance 7 project. All development and construction, or acquisition, of approved projects will be funded equally by each partner and it is expected that TransAlta will be responsible for construction management, operations, and maintenance of projects that proceed under the agreement with MidAmerican.

Sale of Common Shares

On September 13, 2012, we completed our public offering of 19.2 million common shares and on September 20, 2012, the underwriters exercised, in part, their over-allotment option to purchase 2.0 million common shares, all at a price of $14.30 per common share, resulting in aggregate gross proceeds of $304 million. The net proceeds of the offering were used to partially fund the acquisition of the Solomon power station in Western Australia, to fund the construction of our 68 MW New Richmond wind project, to repay short-term debt, and for general corporate purposes.

MF Global Inc.

In 2011, MF Global Holdings Ltd. filed for bankruptcy protection in the United States. MF Global Holdings Ltd. is the parent company of MF Global Inc., which we used as a broker-dealer for certain commodity transactions. During 2011, a reserve of U.S.$18 million was taken on the collateral when the parent company of MF Global Inc. filed for bankruptcy protection. During 2012, we sold our claim against MF Global Inc. pertaining to the return of U.S.$36 million of collateral that we had posted, for net proceeds of U.S.$33 million. As a result, a pre-tax gain of $15 million ($11 million after tax) was realized in 2012.

Sale of Preferred Shares

On August 10, 2012, we completed our public offering of 9.0 million Series E 5.0% Cumulative Redeemable Rate Reset First Preferred Shares, resulting in gross proceeds of $225 million. The proceeds from the offering were used for general corporate purposes, including the funding of capital projects and the reduction of short-term indebtedness of the Corporation.

Premium Dividend™, Dividend Reinvestment and Optional Common Share Purchase Plan

On February 21, 2012, TransAlta added a Premium Dividend TM Component to its existing Dividend Reinvestment and Share Purchase Plan. The amended and restated plan, the Premium Dividend TM, Dividend Reinvestment and Optional Common Share Purchase Plan provides eligible shareholders of TransAlta with two options: i) to reinvest dividends at a current three per cent discount (may be from zero to five per cent at the discretion of the Board of Directors) to the average market price towards the purchase of new shares of TransAlta (the Dividend Reinvestment Component) or ii) to receive the equivalent to 102% of the dividends payable in cash, the premium cash payment (the Premium Dividend TM Component).

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Eligible shareholders enrolled in either the Dividend Reinvestment Component or the Premium Dividend TM Component will also be eligible to purchase new shares at a discount to the average market price under the optional cash payment component (the OCP Component) of the plan by directly investing up to $5,000 per quarter. The applicable discount under the OCP Component is determined from time to time by the Board and is currently set at three per cent.

2011

Sale of Preferred Shares

On November 30, 2011, we completed our public offering of 11.0 million Series C 4.60% Cumulative Redeemable Rate Reset First Preferred Shares, resulting in gross proceeds of $275 million. The net proceeds from the offering were used for general corporate purposes, including the funding of capital projects and the reduction of short-term indebtedness of the Corporation.

President and Chief Executive Officer

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

Effective January 1, 2012, Mr. Snyder retired as a member of the Board of Directors of TransAlta Corporation (the “Board”) and effective January 2, 2012, Mrs. Farrell was appointed to the Board.

Board Appointments

On July 18, 2011, Mr. Yakout Mansour was appointed to our Board. Mr. Mansour, a professional engineer and a Fellow of the Institute of Electrical and Electronics Engineers, recently retired from his position as the President and CEO of the California Independent System Operator Corporation.

On February 24, 2011, the Board announced that Ambassador Gordon D. Giffin, subject to his re-election at our 2011 Annual Shareholders meeting, would succeed Donna Soble Kaufman as chair to the Board, whose two consecutive three-year term limits as Chair were to expire on April 28, 2011. Ambassador Giffin was successfully re-elected and presently serves as Chair to the Board.

2010

Sale of Preferred Shares

On December 10, 2010, we completed our public offering of 12.0 million Series A 4.60% Cumulative Redeemable Rate Reset First Preferred Shares, resulting in gross proceeds of $300 million. The net proceeds from the offering were used for general corporate purposes, including the funding of capital projects and the reduction of short-term indebtedness of the Corporation and its affiliates.

Chief Financial Officer

On June 18, 2010, we announced that Brett Gellner was appointed Chief Financial Officer, succeeding Brian Burden, who retired from TransAlta.

Dividend Reinvestment and Share Purchase (“DRASP”)

On April 29, 2010, in accordance with the terms of our DRASP plan (now the Premium Dividend TM, Dividend Reinvestment and Optional Common Share Purchase Plan), the Board of Directors approved the issuance of shares from Treasury at a three per cent discount from the weighted average price of the shares traded on the Toronto Stock Exchange on the last five days preceding the dividend payment date. Under the terms of our DRASP plan, eligible participants are able to purchase additional common shares by reinvesting dividends or making an additional contribution of up to $5,000 per quarter. TransAlta reserves the right to alter the discount or return to purchasing the shares on the open market at any time.

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Senior Notes Offering

On March 12, 2010, we completed our offering of U.S.$300 million senior notes maturing in 2040 and bearing interest of 6.50%. The net proceeds from the offering were used to repay borrowings under existing credit facilities and for general corporate purposes.

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BUSINESS OF TRANSALTA

Generation Business Segment

Our Generation business segment is responsible for constructing, operating and maintaining our electricity generation facilities. The following table summarizes our generation facilities which are operating, under construction or under development, as at December 31, 2012. Subsequent sections provide more detailed information on facilities by geographic location and fuel type.

Western Canada |  |  |  |  |  |  |  |  |  |  |  |
Facility |  | Gross Capacity (MW) (1) |  | Ownership (%) |  | Net Capacity Ownership Interest (1) |  | Fuel |  | Revenue Source |  | Contract Expiry Date(2)
Genesee 3 |  | 466 |  | 50 |  | 233 |  | Coal |  | Merchant |  | -
Keephills (3)(4) |  | 792 |  | 100 |  | 792 |  | Coal |  | Alberta PPA/Merchant(3) |  | 2020
Keephills 3 |  | 450 |  | 50 |  | 225 |  | Coal |  | Merchant |  | -
Sheerness |  | 780 |  | 25 |  | 195 |  | Coal |  | Alberta PPA |  | 2020
Sundance 1 & 2 units(5) |  | 560 |  | 100 |  | 560 |  | Coal |  | Alberta PPA |  | 2017
Sundance 3, 4, 5, 6 units (6) |  | 1,581 |  | 100 |  | 1,581 |  | Coal |  | Alberta PPA / Merchant |  | 2020
Fort Saskatchewan |  | 118 |  | 30 |  | 35 |  | Natural gas |  | Long-term contract (“LTC”) |  | 2019
Poplar Creek |  | 356 |  | 100 |  | 356 |  | Natural gas |  | LTC/Merchant |  | 2024
Ardenville |  | 69 |  | 100 |  | 69 |  | Wind |  | Merchant |  | -
Blue Trail |  | 66 |  | 100 |  | 66 |  | Wind |  | Merchant |  | -
Castle River (7) |  | 44 |  | 100 |  | 44 |  | Wind |  | LTC/Merchant |  | -
Cowley North |  | 20 |  | 100 |  | 20 |  | Wind |  | Merchant |  | -
Cowley Ridge |  | 21 |  | 100 |  | 21 |  | Wind |  | Merchant |  | -
Macleod Flats |  | 3 |  | 100 |  | 3 |  | Wind |  | Merchant |  | -
McBride Lake |  | 75 |  | 50 |  | 38 |  | Wind |  | LTC |  | 2023
Sinnott |  | 7 |  | 100 |  | 7 |  | Wind |  | Merchant |  | -
Soderglen |  | 71 |  | 50 |  | 35 |  | Wind |  | Merchant |  | -
Summerview 1 (8) |  | 70 |  | 100 |  | 70 |  | Wind |  | Merchant |  | -
Summerview 2 |  | 66 |  | 100 |  | 66 |  | Wind |  | Merchant |  | -
Akolkolex |  | 10 |  | 100 |  | 10 |  | Hydro |  | LTC |  | 2015
Barrier |  | 13 |  | 100 |  | 13 |  | Hydro |  | Alberta PPA |  | 2020
Bearspaw |  | 17 |  | 100 |  | 17 |  | Hydro |  | Alberta PPA |  | 2020
Belly River |  | 3 |  | 100 |  | 3 |  | Hydro |  | Merchant |  | -
Big Horn |  | 120 |  | 100 |  | 120 |  | Hydro |  | Alberta PPA |  | 2020
Bone Creek |  | 19 |  | 100 |  | 19 |  | Hydro |  | LTC |  | 2031
Brazeau |  | 355 |  | 100 |  | 355 |  | Hydro |  | Alberta PPA |  | 2020
Cascade |  | 36 |  | 100 |  | 36 |  | Hydro |  | Alberta PPA |  | 2020
Ghost |  | 51 |  | 100 |  | 51 |  | Hydro |  | Alberta PPA |  | 2020
Horseshoe |  | 14 |  | 100 |  | 14 |  | Hydro |  | Alberta PPA |  | 2020
Interlakes |  | 5 |  | 100 |  | 5 |  | Hydro |  | Alberta PPA |  | 2020
Kananaskis |  | 19 |  | 100 |  | 19 |  | Hydro |  | Alberta PPA |  | 2020
Pingston |  | 45 |  | 50 |  | 23 |  | Hydro |  | LTC |  | 2023
Pocaterra |  | 15 |  | 100 |  | 15 |  | Hydro |  | Alberta PPA |  | 2013
Rundle |  | 50 |  | 100 |  | 50 |  | Hydro |  | Alberta PPA |  | 2020
Spray |  | 103 |  | 100 |  | 103 |  | Hydro |  | Alberta PPA |  | 2020
St. Mary |  | 2 |  | 100 |  | 2 |  | Hydro |  | Merchant |  | -
Taylor |  | 13 |  | 100 |  | 13 |  | Hydro |  | Merchant |  | -
Three Sisters |  | 3 |  | 100 |  | 3 |  | Hydro |  | Alberta PPA |  | 2020
Upper Mamquam |  | 25 |  | 100 |  | 25 |  | Hydro |  | LTC |  | 2025
Waterton |  | 3 |  | 100 |  | 3 |  | Hydro |  | Merchant |  | -
Total Western Canada |  | 6,536 |  |  |  | 5,315 |  |  |  |  |  |

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Eastern Canada |  |  |  |  |  |  |  |  |  |  |  |
Facility |  | Gross Capacity (MW) (1) |  | Ownership (%) |  | Net Capacity Ownership Interest (1) |  | Fuel |  | Revenue Source |  | Contract Expiry Date(2)
Mississauga |  | 108 |  | 50 |  | 54 |  | Natural gas |  | LTC |  | 2018
Ottawa |  | 68 |  | 50 |  | 34 |  | Natural gas |  | LTC |  | 2013
Sarnia (9) |  | 506 |  | 100 |  | 506 |  | Natural gas |  | LTC |  | 2022-2025
Windsor |  | 68 |  | 50 |  | 34 |  | Natural gas |  | LTC/Merchant |  | 2016
Kent Hills |  | 150 |  | 83 |  | 125 |  | Wind |  | LTC |  | 2033-2035
Le Nordais |  | 99 |  | 100 |  | 99 |  | Wind |  | LTC |  | 2033
Melancthon |  | 200 |  | 100 |  | 200 |  | Wind |  | LTC |  | 2026-2028
New Richmond (10) |  | 68 |  | 100 |  | 68 |  | Wind |  | LTC |  | 2031
Wolfe Island |  | 198 |  | 100 |  | 198 |  | Wind |  | LTC |  | 2029
Appleton |  | 1 |  | 100 |  | 1 |  | Hydro |  | LTC |  | 2030
Galetta |  | 2 |  | 100 |  | 2 |  | Hydro |  | LTC |  | 2030
Misema |  | 3 |  | 100 |  | 3 |  | Hydro |  | LTC |  | 2027
Moose Rapids |  | 1 |  | 100 |  | 1 |  | Hydro |  | LTC |  | 2030
Ragged Chute |  | 7 |  | 100 |  | 7 |  | Hydro |  | Merchant |  | -
Total Eastern Canada |  | 1,479 |  |  |  | 1,332 |  |  |  |  |  |
US |  |  |  |  |  |  |  |  |  |  |  |
Facility |  | Gross Capacity (MW) (1) |  | Ownership (%) |  | Net Capacity Ownership Interest (1) |  | Fuel |  | Revenue Source |  | Contract Expiry Date(2)
Centralia Thermal(11)(12) |  | 1,340 |  | 100 |  | 1,340 |  | Coal |  | LTC/Merchant |  | -
Centralia Natural gas |  | 248 |  | 100 |  | 248 |  | Natural gas |  | Merchant |  | -
Power Resource |  | 212 |  | 50 |  | 106 |  | Natural gas |  | Merchant |  | -
Saranac |  | 240 |  | 37.5 |  | 90 |  | Natural gas |  | Merchant |  | -
Yuma |  | 50 |  | 50 |  | 25 |  | Natural gas |  | LTC |  | 2024
Imperial Valley Geothermal Facilities (13) |  | 327 |  | 50 |  | 164 |  | Geothermal |  | LTC |  | 2016-2029
Skookumchuck (14) |  | 1 |  | 100 |  | 1 |  | Hydro |  | LTC |  | 2020
Wailuku |  | 10 |  | 50 |  | 5 |  | Hydro |  | LTC |  | 2023
Total US |  | 2,428 |  |  |  | 1,979 |  |  |  |  |  |
Australia |  |  |  |  |  |  |  |  |  |  |  |
Facility |  | Gross Capacity (MW) (1) |  | Ownership (%) |  | Net Capacity Ownership Interest (1) |  | Fuel |  | Revenue Source |  | Contract Expiry Date(2)
Parkeston |  | 110 |  | 50 |  | 55 |  | Natural gas |  | LTC |  | 2016
Solomon(15) |  | 125 |  | 100 |  | 125 |  | Natural gas/Diesel |  | LTC |  | 2028
Southern Cross(16) |  | 245 |  | 100 |  | 245 |  | Natural gas/Diesel |  | LTC |  | 2014
Total Australia |  | 480 |  |  |  | 425 |  |  |  |  |  |
TOTAL |  | 10,937 |  |  |  | 9,065 |  |  |  |  |  |

Notes:

(1) |  | MW are rounded to the nearest whole number. Capacity includes all generating assets (generation operations, finance lease, and equity investments).
(2) |  | Where no contract expiry date is indicated, the facility operates as merchant.
(3) |  | Capacity includes a 13 MW uprate on units 1 and 2, which began operation in the second quarter of 2012.

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(4) |  | Testing of the Keephills unit 1 and unit 2 uprates was completed in the first quarter of 2013 and based on the results we have adjusted the uprate capacity to 13 MW bringing the maximum capacity of these Units to 396 MW each.
(5) |  | These units are currently under restoration. Please refer to the General Development of the Business section of this AIF for information with respect to our Sundance 1 and 2 units.
(6) |  | Capacity includes uprates of 15 MW (under development), 53 MW, 53 MW and 44 MW on Sundance units 3, 4, 5 and 6, respectively.
(7) |  | Includes seven additional turbines at other locations.
(8) |  | Comprised of two facilities.
(9) |  | Sarnia’s NMC has been adjusted from 575 MW due to decommissioning of equipment at the facility.
(10) |  | This facility is currently under development.
(11) |  | 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.
(12) |  | Please see General Development of the Business – Recent Developments – 2013 – Puget Sound Energy PPA section in this AIF for information surrounding the contract with PSE.
(13) |  | Comprised of ten facilities.
(14) |  | This facility is used to provide a reliable water supply to our other generation facilities at Centralia.
(15) |  | The facility is currently under construction and is expected to be commissioned in the first half of 2013.
(16) |  | Comprised of four facilities.

Canada: Western Canada

Thermal Facilities

The following table summarizes our Western Canadian thermal generation facilities:

Location |  | Province |  | Plant |  | Capacity (MW) |  | Ownership (%) |  | Commissioning Dates |  | Contract Expiry Date(4)
Genesee |  | AB |  | Genesee 3 |  | 466 |  | 50 |  | 2005 |  | -
Keephills |  | AB |  | Keephills Unit No. 1(1) |  | 396 |  | 100 |  | 1983 |  | 2020
|  | AB |  | Keephills Unit No. 2(1) |  | 396 |  | 100 |  | 1984 |  | 2020
|  | AB |  | Keephills Unit No. 3 |  | 450 |  | 50 |  | 2011 |  | -
Sheerness |  | AB |  | Sheerness Unit No. 1 |  | 390 |  | 25 |  | 1986 |  | 2020
|  | AB |  | Sheerness Unit No. 2 |  | 390 |  | 25 |  | 1990 |  | 2020
Sundance |  | AB |  | Sundance Unit No. 1(2) |  | 280 |  | 100 |  | 1970 |  | 2017
|  | AB |  | Sundance Unit No. 2(2) |  | 280 |  | 100 |  | 1973 |  | 2017
|  | AB |  | Sundance Unit No. 3(3) |  | 368 |  | 100 |  | 1976 |  | 2020
|  | AB |  | Sundance Unit No. 4 |  | 406 |  | 100 |  | 1977 |  | 2020
|  | AB |  | Sundance Unit No. 5 |  | 406 |  | 100 |  | 1978 |  | 2020
|  | AB |  | Sundance Unit No. 6 |  | 401 |  | 100 |  | 1980 |  | 2020
Total |  |  |  |  |  |  | 4,629 |  |  |  |  |  |  |

Notes:

(1) |  | Testing of the Keephills unit 1 and unit 2 uprates was completed in the first quarter of 2013 and based on the results we have adjusted the uprate capacity to 13 MW bringing the maximum capacity of these units to 396 MW each.
(2) |  | Please refer to General Development of the Business in this AIF for information with respect to the event of force majeure that resulted in our Sundance 1 and 2 units being removed from service for the duration of 2012, and the arbitration panel’s decision that units 1 and 2 were not economically destroyed and are to be returned to service. The units are expected to start generating cash flow in the fall of 2013.
(3) |  | Includes the completed 15MW uprate. Although the uprate has been completed, the resulting increased capacity will not be realized until we replace the generator stator.
(4) |  | Where no contract expiry date is indicated, the facility operates as merchant.

Our 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. The Genesee facility, is located approximately 50 kilometres west of Edmonton, Alberta, is jointly owned with Capital Power. Coal for the Genesee 3 facility is provided from the adjacent Genesee mine. The coal reserves of the mine are owned, leased or controlled jointly by PMRL and Capital Power. We have entered into coal supply agreements with PMRL, which operates the mine, to supply coal for the life of the facility.

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The Keephills and Sundance facilities are located approximately 70 kilometres southwest of Edmonton, Alberta, and are both owned by TransAlta. Testing of the Keephills unit 1 and unit 2 uprates was completed in the first quarter of 2013 and based on the results we have adjusted the uprates capacity to 13 MW bringing the maximum capacity of these units to 396 MW each. The Sheerness facility is located approximately 200 kilometres northeast of Calgary, Alberta and is jointly owned by TA Cogen, an Ontario limited partnership, and ATCO Power (2000) Ltd. (“ATCO Power”).

On December 16, 2010 and December 19, 2010, unit 1 and unit 2, of our Sundance facility were shut down due to conditions observed in the boilers at both units. On February 8, 2011, we issued a notice of termination for destruction based on the determination that the units could not be economically restored to service under the terms of the PPA. Due to the uncertainty of the results of the arbitration ruling, we had been continuing to accrue the capacity payments, net of a provision, and to depreciate the asset. The matter was heard before an arbitration panel during the second quarter of 2012. On July 20, 2012, the arbitration panel concluded that units 1 and 2 were not economically destroyed and we were required to restore the facility to service. The panel affirmed that the event met the criteria for force majeure beginning on November 20, 2011 until such time as the units are returned to service.

Fuel requirements for our Western Canadian thermal generation facilities are supplied by a surface strip coal mine located in close proximity to the facilities. We own the Highvale mine that supplies coal to the Sundance and Keephills facilities and perform the mining, reclamation and associated work at the Highvale mine. PMRL, under contract with TransAlta, operated the mine on our behalf until January 17, 2013. On January 17, 2013, we assumed, through our wholly-owned subsidiary Sunhills Partnership, operating and management control of the Highvale Mine. The decision to directly operate our facility is expected to improve our operating model by providing us with greater control over our costs and operations. The SunHills Partnership employs the 604 employees previously employed by PMRL.

We estimate that the recoverable coal reserves contained in this mine are sufficient to supply the anticipated requirements for the life of the facilities which it serves, including those running post PPA expiry and potential plant expansion. We also own the Whitewood mine, which formerly supplied coal to the now decommissioned Wabamun facility. The Whitewood mine is no longer in operation and we have completed reclamation of the site as required by Alberta Environment.

Construction on the Keephills 3 power project started on February 26, 2007. Through Keephills 3 Limited Partnership, TransAlta and Capital Power are equal partners in the ownership of the facility, with Capital Power having been responsible for construction and us being responsible for managing the joint venture. Keephills 3 began commercial operations on September 1, 2011. The facility is jointly operated by Capital Power and us. Each partner independently dispatches and markets its share of the unit’s electrical output. We provide the coal fuel to the facility through our Highvale mine.

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

Natural Gas-Fired Facilities

The following table summarizes our Western Canadian natural gas-fired generation facilities:

Location |  | Province |  | Plant |  | Capacity (MW) |  | Ownership (%) |  | Commissioning Dates |  | Contract Expiry Date
Fort Saskatchewan |  | AB |  | Fort Saskatchewan |  | 118 |  | 30 |  | 1999 |  | 2019
Fort McMurray |  | AB |  | Poplar Creek |  | 356 |  | 100 |  | 2001 |  | 2024
Total |  |  |  |  |  | 474 |  |  |  |  |  |

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Our interest in the Fort Saskatchewan facility is held through TA Cogen. See “TA Cogen” later in this AIF. The 118 MW natural gas-fired combined-cycle cogeneration Fort Saskatchewan plant and is owned by TA Cogen and Strongwater Energy Ltd. The facility provides electricity and steam to Dow Chemical Canada Inc. under the terms of a long-term contract which expires in 2019.

Our Poplar Creek plant is located in Fort McMurray, Alberta. We operate this 356 MW cogeneration plant which became fully operational in the first quarter of 2001 and delivers approximately 150 MW of electricity and steam to Suncor Energy Inc. (“Suncor”) under the terms of a long-term contract which expires in 2024. Any surplus power not used by Suncor is available to us to sell to other parties, in which case Suncor is entitled to share in the revenue, under certain conditions.

Hydroelectric Facilities

As well as contracting for power, we enter into long-term and short-term contracts to sell the environmental attributes from our merchant hydro facilities. These activities help to ensure earnings consistency from these assets. For 2012, we sold approximately 94 per cent of the environmental attributes from our merchant hydro facilities. For 2013, we have sold approximately 93 per cent of the environmental attributes from our merchant hydro facilities to date. Generally, for facilities under long-term contract, the benefit of the environmental attributes generated flow through to the contract holder.

The following table summarizes our Western Canadian hydroelectric facilities:

Location |  | Province |  | Plant |  | Capacity (MW) (1) |  | Ownership (%) |  | Commissioning Dates |  | Contract Expiry Date(3)
Akolkolex River System |  | BC |  | Akolkolex(2) |  | 10 |  | 100 |  | 1995 |  | 2015
|  | BC |  | Pingston(2) |  | 45 |  | 50 |  | 2003, 2004 |  | 2023
Mamquam River System |  | BC |  | Upper Mamquam(2) |  | 25 |  | 100 |  | 2005 |  | 2025
Thompson River System |  | BC |  | Bone Creek(2) |  | 19 |  | 100 |  | 2011 |  | 2031
Bow River System |  | AB |  | Barrier |  | 13 |  | 100 |  | 1947 |  | 2020
|  | AB |  | Bearspaw |  | 17 |  | 100 |  | 1954 |  | 2020
|  | AB |  | Cascade |  | 36 |  | 100 |  | 1942, 1957 |  | 2020
|  | AB |  | Ghost |  | 51 |  | 100 |  | 1929, 1954 |  | 2020
|  | AB |  | Horseshoe |  | 14 |  | 100 |  | 1911 |  | 2020
|  | AB |  | Interlakes |  | 5 |  | 100 |  | 1955 |  | 2020
|  | AB |  | Kananaskis |  | 19 |  | 100 |  | 1913, 1951 |  | 2020
|  | AB |  | Pocaterra |  | 15 |  | 100 |  | 1955 |  | 2013
|  | AB |  | Rundle |  | 50 |  | 100 |  | 1951, 1960 |  | 2020
|  | AB |  | Spray |  | 103 |  | 100 |  | 1951, 1960 |  | 2020
|  | AB |  | Three Sisters |  | 3 |  | 100 |  | 1951 |  | 2020
North Sask. River System |  | AB |  | Bighorn |  | 120 |  | 100 |  | 1972 |  | 2020
|  | AB |  | Brazeau |  | 355 |  | 100 |  | 1965, 1967 |  | 2020
Oldman River System |  | AB |  | Belly River(2) |  | 3 |  | 100 |  | 1991 |  | -
|  | AB |  | St. Mary(2) |  | 2 |  | 100 |  | 1992 |  | -
|  | AB |  | Taylor(2) |  | 13 |  | 100 |  | 2000 |  | -
|  | AB |  | Waterton |  | 3 |  | 100 |  | 1992 |  | -
Total |  |  |  |  |  | 921 |  |  |  |  |  |

Notes:

(1) |  | MW are rounded to the nearest whole number.
(2) |  | These facilities are EcoPower® registered.
(3) |  | Where no contract expiry date is indicated, the facility operates as merchant.

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Akolkolex River System

Akolkolex is a run-of-river hydroelectric facility with installed capacity of 10 MW located on the Akolkolex River, south of Revelstoke, British Columbia. We own 100 per cent of this facility. It has been operating since 1995. The output from the facility is sold to British Columbia Hydro Power Authority (“BC Hydro”).

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

Mamquam River System

Upper Mamquam is a run-of-river hydroelectric facility with installed capacity of 25 MW located on the Mamquam River, east of Squamish, British Columbia, and north of Vancouver. We own 100 per cent of this facility. It has been operating since 2005. The output from the facility is sold to BC Hydro.

Thompson River System

Bone Creek is a run-of-river hydroelectric facility with installed capacity of 19 MW located on Bone Creek, 90 kilometres south of the town of Valemount, British Columbia, and we own 100 per cent of this facility. Bone Creek commenced commercial operations on June 1, 2011. The output from the facility is under contract with BC Hydro. The facility also currently qualifies for payments of $10/MWh until 2020 from Natural Resources Canada (“NRCan”), a division of the federal government, through the ecoEnergy for Renewable Power (“eERP”) program.

Bow River System

Barrier is a run-of-river hydroelectric facility with installed capacity of 13 MW located in Seebe, Alberta. We own 100 per cent of this facility. It has been operating since 1947. The facility operates under an Alberta PPA.

Bearspaw is a hydroelectric facility with installed capacity of 17 MW located on the Bow River in Calgary, Alberta. We own 100 per cent of this facility. It has been operating since 1954. The facility operates under an Alberta PPA.

Cascade is a hydroelectric facility with installed capacity of 36 MW located on the Cascade River in Banff National Park, Alberta. We own 100 per cent of this facility, having purchased it from the Government of Canada in 1941. The following year, we built a new dam and power plant to replace the original, and then, in 1957, added a second generating unit. The facility operates under an Alberta PPA.

Ghost is a hydroelectric facility with installed capacity of 51 MW located on the Bow River in Cochrane, Alberta. We own 100 per cent of this facility. It has been operating since 1929. The facility operates under an Alberta PPA.

Horseshoe is a run-of-river hydroelectric facility with installed capacity of 14 MW located in Seebe, Alberta. We own 100 per cent of this facility. It has been operating since 1911. The facility operates under an Alberta PPA.

Interlakes is a hydroelectric facility with installed capacity of 5 MW located in Kananaskis, Alberta. We own 100 per cent of this facility. It has been operating since 1955. The facility operates under an Alberta PPA.

Kananaskis is a run-of-river hydroelectric facility with installed capacity of 19 MW located in Seebe, Alberta. We own 100 per cent of this facility. It has been operating since 1913. It was expanded in 1951 and modified in 1994. The facility operates under an Alberta PPA.

Pocaterra is a hydroelectric facility with installed capacity of 15 MW located in Kananaskis, Alberta. We own 100 per cent of this facility. It has been operating since 1955. The facility operates under an Alberta PPA, expiring in 2013, at which time the generation from this facility will be sold into the Alberta spot market.

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Rundle is a hydroelectric facility with installed capacity of 50 MW located in Canmore, Alberta on the Spray system. The plant uses water from the Spray Lakes Storage Reservoir. We own 100 per cent of this facility. It has been operating since 1951. The facility operates under an Alberta PPA.

Spray is a hydroelectric facility with installed capacity of 103 MW located in Canmore, Alberta on the Spray system. The plant uses water from the Spray Lakes Storage Reservoir. We own 100 per cent of this facility. It has been operating since 1951. The facility operates under an Alberta PPA.

Three Sisters is a hydroelectric facility with installed capacity of 3 MW located at the base of the Three Sisters Dam in Canmore, Alberta on the Spray system. The plant uses water from the Spray Lakes Storage Reservoir. We own 100 per cent of this facility. It has been operating since 1951. The facility operates under an Alberta PPA.

North Saskatchewan River System

Bighorn is a hydroelectric facility with installed capacity of 120 MW located in Nordegg, Alberta. We own 100 per cent of this facility. It has been operating since 1972. The facility operates under an Alberta PPA.

Brazeau is a hydroelectric facility with installed capacity of 355 MW located in Drayton Valley, Alberta. We own 100 per cent of this facility. It has been operating since 1965. The facility operates under an Alberta PPA.

Oldman River System

Belly River is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Waterton-St. Mary Headworks Irrigation Canal System, east of the Waterton Reservoir, approximately 75 kilometres southwest of Lethbridge in Southern Alberta. Due to its location, along the irrigation canal, Belly River operates from April to October when water is diverted through the canal as part of the St. Mary Irrigation District Water Management Plan. We own 100 per cent of this facility. It has been operating since March 1991. Generation from the facility is sold in the Alberta spot market.

St. Mary is a run-of-river hydroelectric facility with installed capacity of 2 MW located at the base of the St. Mary Dam on the Waterton Reservoir, near Magrath, in Southern Alberta. We own 100 per cent of this facility. It has been operating since December 1992. Generation from the facility is sold in the Alberta spot market.

Taylor is a run-of-river hydroelectric facility with installed capacity of 13 MW and is located adjacent to the Taylor Coulee Chute on the Waterton-St. Mary Headworks Irrigation Canal System which is owned by the Government of Alberta. We own 100 per cent of this facility. It has been operating since May 2000. Generation from the facility is sold in the Alberta spot market.

Waterton is a run-of-river hydroelectric facility with installed capacity of 3 MW located at the base of the Waterton Dam on the Waterton Reservoir, near Hillspring, southwest of Lethbridge, Alberta. We own 100 per cent of this facility. It has been operating since November 1992. Generation from the facility is sold in the Alberta spot market.

Wind Generation Facilities

We own and operate approximately 1,061 MW of net wind generation capacity in 11 wind farms in western Canada, three in Ontario, one in Québec and two in New Brunswick. We also have the 68 MW New Richmond wind project in Québec under construction which is expected to be commissioned in the first quarter of 2013.

Wind is not generally a dispatchable fuel; therefore, in merchant markets, wind assets may not be able to secure the annual average pool price. As such, we make different assumptions in forecast revenue received for generation from a wind asset compared to a base load asset. If these price assumption and generation production forecasts are not correct, the corresponding revenue received may be reduced. Generation production forecasts are based on the long-term average production forecast for a site, reflecting historical climatic conditions. Within any year there may be variations from this long-term average. In order to forecast generation production, a number of factors have to be assumed based on historic on-site data and wind farm design including wake and array losses, wind shear and the

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electrical losses within the site. If these assumptions are incorrect then actual production will be higher or lower than the long-term forecast for the site.

As well as contracting for power, we enter into long-term and short-term contracts to sell the environmental attributes from our merchant wind facilities. These activities help to ensure earnings consistency from these assets. For 2012, we sold approximately 91 per cent of the environmental attributes from our merchant wind facilities. For 2013, we have sold approximately 79 per cent of the environmental attributes from our merchant wind facilities to. Generally, for facilities under long-term contract, the benefit of the environmental attributes generated flow through to the contract holder.

The following table summarizes our Western Canadian wind generation facilities:

Location |  | Province |  | Plant |  | Capacity (MW)(1) |  | Ownership (%) |  | Commissioning Dates |  | Contract Expiry Date(2)
Fort Macleod |  | AB |  | Ardenville |  | 69 |  | 100 |  | 2010 |  | -
Fort Macleod |  | AB |  | Blue Trail |  | 66 |  | 100 |  | 2009 |  | -
Fort Macleod |  | AB |  | Macleod Flats |  | 3 |  | 100 |  | 2004 |  | -
Fort Macleod |  | AB |  | McBride Lake |  | 75 |  | 50 |  | 2003 |  | 2023
Fort Macleod |  | AB |  | Soderglen |  | 71 |  | 50 |  | 2006 |  | -
Pincher Creek |  | AB |  | Castle River |  | 44 |  | 100 |  | 1997-2001 |  | -
Pincher Creek |  | AB |  | Cowley North |  | 20 |  | 100 |  | 2001 |  | -
Pincher Creek |  | AB |  | Cowley Ridge |  | 21 |  | 100 |  | 1993 |  | -
Pincher Creek |  | AB |  | Sinnott |  | 7 |  | 100 |  | 2001 |  | -
Pincher Creek |  | AB |  | Summerview 1 |  | 70 |  | 100 |  | 2004 |  | -
Pincher Creek |  | AB |  | Summerview 2 |  | 66 |  | 100 |  | 2010 |  | -
Total |  |  |  |  |  |  | 512 |  |  |  |  |  |  |

Notes:

(1) | MW are rounded to the nearest whole number. The capacity listed is for 100 per cent of the facility.
(2) | Where no contract expiry date is indicated, the facility operates as merchant.

Ardenville is a 69 MW wind farm located approximately eight kilometres south of Fort Macleod, Alberta adjacent to the Macleod Flats wind facility. We constructed the project, which commenced commercial operations on November 10, 2010. The output from this facility is sold in the Alberta spot market. The Ardenville wind farm is entitled to receive payments of $10/MWh until 2020 from NRCan, through the eERP program.

Blue Trail is a 66 MW wind farm located in southern Alberta which commenced commercial operations in November 2009. The output from this facility is sold on the Alberta spot market. The Blue Trail wind farm is entitled to receive payments of $10/MWh until 2019 from NRCan, through the eERP program.

Macleod Flats consists of a single 3 MW turbine and is located near Fort Macleod. It was commissioned in 2004 and was purchased by us in 2009.

McBride Lake is a 75 MW wind farm located at Fort Macleod, Alberta. We constructed the wind farm, which commenced commercial operations in the third quarter of 2003. McBride Lake is operated by us and is equally owned with ENMAX Green Power Inc. The output from the facility is 100 per cent contracted in the form of a 20-year LTC with ENMAX Energy Corp. We are 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. We also own the 0.7 MW McBride Lake East facility in the same vicinity.

Soderglen is a 71 MW facility located in southern Alberta, southwest of Fort Macleod and 40 kilometres from our wind operations near Pincher Creek. We share equal ownership of this facility with Nexen Inc. The facility began commercial operations in September 2006. The output from this facility is sold in the Alberta spot market. Soderglen is entitled to receive WPPI payments from the federal government at $10/MWh.

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Castle River is a 40 MW wind farm located in Pincher Creek, Alberta. We also own and operate seven additional turbines totalling 4 MW located individually in the Cardston County and Hillspring areas of southwestern Alberta. The output from this facility is sold in the Alberta spot market.

Cowley North is a 20 MW wind farm, located adjacent to Cowley Ridge. It commenced commercial operations in the fall of 2001. We own this facility and the output from it is sold in the Alberta spot market.

Cowley Ridge has total installed capacity of 21 MW and is located adjacent to Cowley North. It is comprised of two parts: Cowley Ridge, which became operational in 1993, and the Cowley Expansion which became operational in 1994, both of which we own 100 per cent. The output from this facility is sold in the Alberta spot market.

Sinnott has a total installed capacity of 7 MW and is located directly east of Cowley Ridge. It commenced commercial operations in the fall of 2001. We own this facility and the output from it is sold in the Alberta spot market.

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

Summerview 2 is a 66 MW wind farm is located northeast of Pincher Creek, Alberta. We constructed the facility, which began commercial operations in February 2010. The output is sold in the Alberta spot market. The Summerview 2 wind farm expansion is entitled to receive payments of $10/MWh until 2020 from NRCan, through the eERP program.

Alberta PPAs

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

Our thermal facilities are operated by us, however, they are cycled or dispatched by the buyers under the PPA. Under the Alberta PPAs, we are exposed to electricity price risk if availability declines below contracted levels (other than as a result of outages caused by an event of force majeure). In those circumstances, we must pay a penalty on the difference between target availability and actual availability at 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. We attempt to further mitigate this exposure by maintaining contracted and uncontracted capacity in the market, through operation and maintenance practices, and hedging activities.

Our hydroelectric facilities, other than Belly River, St. Mary, Taylor and Waterton, are aggregated through one Alberta PPA which provides for financial obligations for energy and ancillary services based on hourly targets. We meet these targeted amounts through physical delivery or third party purchases.

Our compensation under the Alberta PPAs is founded on a pricing formula based on the previous cost of service regime that applied 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 certain fixed and variable costs. Common equity is deemed to be 45 per cent of total capital and the return on equity is set annually at a 4.5 per cent premium over the rate of a Government of Canada Bond with maturity of ten years.

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The pricing formula includes a provision for site restoration costs for the thermal generating plants during the term of the Alberta PPAs. If the costs recovered are insufficient, then we 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 our Alberta PPAs range from 2013 to 2020. We are evaluating the economics of running assets post PPA expiry, taking into account published and expected provincial and federal greenhouse gas (“GHG”) and other environmental legislation, including the published federal regulations governing GHG emissions from coal-fired plants. Upon the expiry of the Alberta PPAs, and subject to any legislative limitations, which are addressed below, and our ability to procure an extension to operating licenses, if required, we will then be in a position to sell our electricity to the Alberta Power Pool and to third party purchasers through direct sales agreements.

The Alberta PPAs (together with legislation which applies thereto) permit the Balancing Pool, directly or indirectly as successor to the power purchaser under the Alberta PPAs, to terminate the Alberta PPAs in certain circumstances. If the Balancing Pool exercises its ability to terminate, we will, in those circumstances, be entitled to receive a lump-sum payment in connection with such termination.

In September of 2012, the Canadian federal Government published the final regulations governing GHG emissions from coal-fired power plants, which regulations become effective on July 1, 2015. Please see the section entitled Environmental Risk Management - Ongoing and Recently Passed Environmental Legislation below for more details on this legislation.

Canada: Eastern Canada

Natural Gas-Fired Facilities

Our Ontario natural gas-fired generating facilities are summarized in the following table:

Location |  | Province |  | Plant |  | Capacity (MW) |  | Ownership (%) |  | Commissioning Dates |  | Contract Expiry Date
Mississauga |  | ON |  | Mississauga (1) |  | 108 |  | 50 |  | 1992 |  | 2018
Ottawa |  | ON |  | Ottawa (1) |  | 68 |  | 50 |  | 1992 |  | 2013
Sarnia |  | ON |  | Sarnia |  | 506 |  | 100 |  | 2003 |  | 2022-2025
Windsor |  | ON |  | Windsor (1) |  | 68 |  | 50 |  | 1996 |  | 2016
Total |  |  |  |  |  | 750 |  |  |  |  |  |

Note:

(1) | We have a 50 per cent interest in these three facilities through our ownership interest in TA Cogen.

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 Ontario Electricity Financial Corporation (“OEFC”) which expires in 2018. Prior to July 2005, the Mississauga plant also provided cogeneration services to Boeing Canada Inc. (“Boeing”). Boeing exercised its right under the cogeneration services agreement to no longer take and pay for cogeneration services due to the closure of its manufacturing facility. Boeing remains entitled to any steam credits which are based on the total plant electricity generation revenue. On or prior to each of January 1, 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. Boeing is, however, incented to run the lease to term in 2028 by the annual steam credit payment it receives.

The Ottawa plant is owned by TA Cogen. It is a combined-cycle cogeneration facility designed to produce 68 MW of electrical energy. The capacity is sold under a long-term contract with the OEFC, an agency of the Province of Ontario. The agreement expires December 31, 2013. Negotiations are underway with the Ontario Power Authority (“OPA”) to enter into a long-term contract commencing in 2014. The Ottawa plant also provides steam, hot water, and chilled water to the member hospitals and treatment centers of the Ottawa Health Sciences Centre and the

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National Defence Medical Centre. The thermal energy contract with the Ottawa Health Sciences Centre expires on December 31, 2022 and the thermal energy contract with the National Defence Medical Centre expires on December 31, 2017.

The Sarnia plant is a 506 MW combined-cycle cogeneration facility that provides steam and electricity to nearby industrial facilities owned by LANXESS AG (formerly Bayer Inc.), Nova Chemicals (Canada) Ltd. (which in turn supplies Styrolution, a Styrene production facility formerly owned by NOVA) and Suncor Energy Products Inc. We own 100 per cent of this facility. On February 15, 2006, we signed a five-year agreement with the OPA for generation from our Sarnia facility. Subsequently, the Ontario Minister of Energy and Infrastructure directed the OPA to seek contracts with us and certain other “Early Movers” to obtain terms and conditions which were more in keeping with the contracts it was offering new facilities. In September 2009, we signed a new contract with the OPA, effective as of July 1, 2009 and terminating on December 31, 2025, which provides more favourable terms than those previously held by the facility. In addition, the new agreement brings the combined total term contracted with the OPA to 20 years and includes provisions for the parties to share in the impact and benefit of changes in customer steam load or loss of steam customer.

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

Hydroelectric Facilities

Our Ontario hydroelectric facilities are summarized in the following table:

Location |  | Province |  | Plant |  | Capacity (MW) (1) |  | Ownership (%) |  | Commissioning Dates |  | Contract Expiry Date(3)
Misema River System |  | ON |  | Misema |  | 3 |  | 100 |  | 2003 |  | 2027
Mississippi River System |  | ON |  | Appleton |  | 1 |  | 100 |  | 1994 |  | 2030
Mississippi River System |  | ON |  | Galetta(2) |  | 2 |  | 100 |  | 1998 |  | 2030
Montréal River System |  | ON |  | Ragged Chute |  | 7 |  | 100 |  | 1991 |  | -
Wanapitei River System |  | ON |  | Moose Rapids |  | 1 |  | 100 |  | 1997 |  | 2030
Total |  |  |  |  |  | 14 |  |  |  |  |  |

Notes:

(1) | MW are rounded to the nearest whole number.
(2) | Galetta was originally built in 1907, but was retrofitted in 1998.
(3) | Where no contract expiry date is indicated, the facility operates as merchant.

Misema is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Misema River, close to Englehart, in northern Ontario. We own this facility and it has been operating since 2003. Generation from this facility is sold to the OPA under a contract that terminates May 3, 2027.

Appleton is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Mississippi River, near Almonte, Ontario. We own this facility and it has been operating since 1994. Generation from this facility is sold to the OPA under a contract that terminates November 30, 2030.

Galetta is a run-of-river hydroelectric facility with installed capacity of 2 MW located on the Mississippi River, near Galetta, Ontario. We own this facility, which was originally built in 1907 and retrofitted in 1998. Generation from this facility is sold to the OPA under a contract that terminates November 30, 2030.

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Ragged Chute is a run-of-river hydroelectric facility with installed capacity of 7 MW located on the Montréal River, south of New Liskeard, in northern Ontario. We lease this facility from Ontario Power Generation and it has been operating since 1991. Generation from this facility is currently sold into the Ontario market, but application has been made to the OPA to contract the facility under its Hydroelectric Contract Initiative.

Moose Rapids is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Wanapitei River, near Sudbury, in northern Ontario. We own this facility and it has been operating since 1997. Generation from this facility is sold to the OPA under a contract that terminates November 30, 2030.

Wind Generation Facilities

Our Ontario, Québec and New Brunswick wind generation facilities are summarized in the following table:

Location |  | Province |  | Plant |  | Capacity (MW) (1) |  | Ownership (%) |  | Commissioning Dates |  | Contract Expiry Date
Kingston |  | ON |  | Wolfe Island |  | 198 |  | 100 |  | 2009 |  | 2029
Melancthon Township |  | ON |  | Melancthon I |  | 68 |  | 100 |  | 2006 |  | 2026
Melancthon and Amaranth Townships |  | ON |  | Melancthon II |  | 132 |  | 100 |  | 2008 |  | 2028
Gaspe Peninsula |  | QC |  | Le Nordais |  | 99 |  | 100 |  | 1999 |  | 2033
|  | QC |  | New Richmond(2) |  | 68 |  | 100 |  | 2012 |  | 2032
Kent Hills |  | NB |  | Kent Hills |  | 96 |  | 83 |  | 2008 |  | 2033
|  | NB |  | Kent Hills Expn. |  | 54 |  | 83 |  | 2010 |  | 2035
Total |  |  |  |  |  | 647 |  |  |  |  |  |

Notes:

(1) | MW are rounded to the nearest whole number.
(2) | This facility is currently under development.

Wolfe Island is a 198 MW wind project located on Wolfe Island, near Kingston, Ontario. We own this facility and it commenced commercial operations in June 2009. Generation from this facility is sold to the OPA.

Melancthon I is a 68 MW wind project located in Melancthon Township near Shelburne, Ontario. We own the facility and it commenced commercial operations on March 4, 2006. Generation from this facility is sold to the OPA.

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

Le Nordais is located at two sites: Cap-Chat with 56.25 MW of installed capacity; and Matane with 42.75 MW of installed capacity. Le Nordais is located on the Gaspé Peninsula of Québec. We own this facility and it commenced commercial operations in 1999. Generation from this facility is sold to Hydro-Québec.

Currently under construction is our 68 MW New Richmond wind project also located on the Gaspé Peninsula. New Richmond is contracted under a 20-year Electricity Supply Agreement with Hydro-Québec Distribution. The cost of the project is estimated to be approximately $205 million and commercial operation is expected to commence during the first quarter of 2013.

Kent Hills is a 96 MW project located in Kent Hills, New Brunswick, and delivers power under a 25 year LTC with New Brunswick Power. Natural Forces Technologies Inc., an Atlantic Canada-based wind developer, is our co-development partner in this project and exercised its option to purchase up to 17 per cent of the Kent Hills project in May 2009. Kent Hills commenced commercial operations in 2008.

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The Kent Hills expansion is a 54 MW wind farm which also delivers power under a 25 year LTC with New Brunswick Power. Natural Forces exercised their option to purchase a 17 per cent interest in the Kent Hills expansion project subsequent to the commencement of commercial operations. The facility commenced commercial operations in November of 2010.

All of the electricity generated and sold by our wind division with the exception of Macleod Flats is from facilities that are EcoLogo certified. We are 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.

TA Cogen

We hold a 50.01 per cent limited partnership interest in TA Cogen, which is an Ontario limited partnership. The remaining 49.99 per cent ownership is now held by Stanley Power Inc., a subsidiary of Cheung Kong Infrastructure Holdings Limited which amalgamated with Stanley Energy Inc., a subsidiary of Stanley Power Inc., on December 31, 2011.

TA Cogen holds interest in the 780 MW Sheerness thermal generation facility in Alberta, the 118 MW Fort Saskatchewan natural gas-fired cogeneration facility in Alberta, the 108 MW Mississauga, the 68 MW Ottawa and 68 MW Windsor natural gas-fired cogeneration facilities located in Ontario.

United States

Our generation facilities in the United States are summarized in the following table:

Location |  | State |  | Plant |  | Capacity (MW) |  | Ownership (%) |  | Commissioning Dates |  | Contract Expiry Date(3)
Centralia |  | WA |  | Centralia Thermal No. 1(1) |  | 670 |  | 100 |  | 1971 |  | -
|  |  |  | Centralia Thermal No. 2(1) |  | 670 |  | 100 |  | 1971 |  | -
|  |  |  | Centralia Natural gas |  | 248 |  | 100 |  | 2002 |  | -
|  |  |  | Skookumchuck |  | 1 |  | 100 |  | 1970 |  | 2020
Big Springs (2) |  | TX |  | Power Resources |  | 212 |  | 50 |  | 1988 |  | -
Saranac (2) |  | NY |  | Saranac |  | 240 |  | 37.5 |  | 1994 |  | -
Yuma (2) |  | AZ |  | Yuma |  | 50 |  | 50 |  | 1994 |  | 2024
Imperial Valley (1) |  | CA |  | Vulcan |  | 34 |  | 50 |  | 1986 |  | 2016
|  |  |  | Del Ranch |  | 38 |  | 50 |  | 1989 |  | 2018
|  |  |  | Elmore |  | 38 |  | 50 |  | 1989 |  | 2018
|  |  |  | Leathers |  | 38 |  | 50 |  | 1990 |  | 2019
|  |  |  | CE Turbo |  | 10 |  | 50 |  | 2000 |  | 2029
|  |  |  | Salton Sea I |  | 10 |  | 50 |  | 1987 |  | 2017
|  |  |  | Salton Sea II |  | 20 |  | 50 |  | 1990 |  | 2020
|  |  |  | Salton Sea III |  | 50 |  | 50 |  | 1989 |  | 2019
|  |  |  | Salton Sea IV |  | 40 |  | 50 |  | 1996 |  | 2026
|  |  |  | Salton Sea V |  | 49 |  | 50 |  | 2000 |  | 2020
Hilo (2) |  | HI |  | Wailuku |  | 10 |  | 50 |  | 1993 |  | 2023
Total |  |  |  |  |  | 2,428 |  |  |  |  |  |

Notes:

(1) | Please see “General Development of the Business – Recent Developments – 2013” section in this AIF for information surrounding the contract with PSE.
(2) | Under IFRS, our interests in these facilities are accounted for as equity investments. Under Canadian GAAP, we previously proportionately consolidated our interests in the financial and operational results of these facilities.
(3) | Where no contract expiry date is indicated, the facility operates as merchant.

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Centralia

We own a two-unit 1,340 MW thermal facility and a 248 MW natural gas-fired facility in Centralia, Washington, located south of Seattle. We have entered into a number of multiple year medium and short- term energy sales agreements from the Centralia Thermal plant. In 2011, Washington State passed the TransAlta Energy Bill (chapter 180, Laws of 2011) allowing the Centralia Thermal plant to comply with the State’s GHG emissions performance standards by shutting down one of its two boilers by the end of 2020 and the other by the end of 2025. This legislation removed restrictions that had previously been imposed on the facility limiting the duration of new contracts from the facility, and limiting the technology that the facility would be required to implement for nitrogen oxides (“NOx”) controls. On December 23, 2011, TransAlta and the state entered into the MoA which confirmed some of these arrangements in contractual form with the provision that certain terms could terminate at our option if we do not secure at least 500 MW of long-term contract for the Centralia Thermal plant by the end of 2013. On July 25, 2012, we announced that we entered into an 11-year agreement to provide electricity from our Centralia Thermal plant to PSE. The contract begins in 2014 and runs until 2025 when the plant is scheduled to be shut down. Under the agreement, PSE will buy 180 MW of firm, base-load power starting in December 2014. In December 2015 the contract increases to 280 MW and from December 2016 to December 2024 the contract is for 380 MW. In the last year of the contract, the contracted volume is for 300 MW. The agreement was conditionally approved by the WUTC on January 9, 2013, and on January 23, 2013, PSE filed a petition for reconsideration of certain of the conditions within the decision issued by the WUTC. On February 5, 2013, the WUTC granted a 30-day extension to the petition and indicated that it would issue its decision on the petition no later than March 29, 2013.

We also sell electricity from the Centralia Thermal plant into the Western Electricity Coordinating Council (“WECC”) and, in particular, on the spot market in the U.S. Pacific Northwest energy market. Our strategy is to balance contracted and non-contracted sales of electricity to manage production and price risk.

We also own a 1 MW hydroelectric generating facility on the Skookumchuck River near Centralia, and related assets which are used to provide water supply to our other generation facilities in Centralia. On December 10, 2010, we entered into an agreement with PSE for Skookumchuck to provide power until 2020.

We also own a coal mine adjacent to the Centralia facility; however, we stopped mining operations at our Centralia coal mine on November 27, 2006. Although we estimate that certain coal reserves remain to be extracted, we have not yet received permits for, nor developed the new area, from which this coal could be produced. Coal to fuel the Centralia plant is now sourced from the Powder River basin in Montana and Wyoming. Our existing coal contracts from Powder River Basin Mines in Montana and Wyoming expire at the end of 2014. We expect to continue to source our future coal needs from the Powder River Basin.

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

Under the U.S. Federal Mine Safety and Health Act, TransAlta must report all “significant and substantial” citations at its Centralia mine. During 2012, TransAlta had no reportable events relating to electric equipment and the examination, testing and maintenance thereof. The mine is not in operation. There were no injury incidents or fatalities at the mine during 2012. The total dollar value of all Mine Safety and Health Administration (“MSHA”) assessments was not significant. There are no pending legal actions before the Federal Mine Safety and Health Review Commission involving the Centralia mine and none were pending during 2012.

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Reportable Events – Centralia Mine

Mine or Operating Name/MSHA Identification Number |  |  | Section 104 S&S Citations (#) |  |  | Total Dollar Value of MSHA Assessments Proposed ($) |  |  | Total Number of Mining Related Fatalities (#) |  |  | Received Notice of Pattern Violations Under Section 104(e) (yes/no) |  |  | Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no) |  |  | Legal Actions Initiated or Pending During Period (#) |
4500416 |  |  | 0 |  |  | $600 |  |  | 0 |  |  | no |  |  | no |  |  | 0 |

CE Generation

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

CE Generation affiliates operate the ten geothermal facilities located in Imperial Valley, California, with an aggregate generation capacity of 327 MW, as well as the three natural-gas fired facilities in Texas, Arizona, and New York State having an aggregate generation capacity of 502 MW. Each of the geothermal facilities sells electricity pursuant to independent, long-term contracts. The Arizona facility sells its output pursuant to long-term contracts while the Texas and New York facilities operate under an energy management agreement with a third party who is responsible for marketing the output from the facilities on a short term basis.

Wailuku

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

Australia

Our natural-gas and diesel fired generation facilities in Australia are summarized in the following table:

Location |  | State |  | Plant |  | Capacity (MW) |  | Ownership (%) |  | Commissioning Dates |  | Contract Expiry Date
Kalgoorlie |  | WA |  | Parkeston |  | 110 |  | 50 |  | 1996 |  | 2016
Eastern Goldfields Region |  | WA |  | Southern Cross(1) |  | 245 |  | 100 |  | 1996 |  | 2014
Pilbara Region |  | WA |  | Solomon(2) |  | 125 |  | 100 |  | 2013 |  | 2028
Total |  |  |  |  |  | 480 |  |  |  |  |  |

Notes:

(1) | Comprised of four facilities.
(2) | This facility was acquired in September 2012 and was under construction for the remainder of 2012. The plant is expected to be fully commissioned in the first half of 2013.

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The Parkeston plant is a 110 MW dual-fuel natural-gas and diesel fired power station, which we own in partnership through a 50/50 joint venture with NP Kalgoorlie Pty Ltd., a subsidiary of Newmont Australia Limited. The Parkeston facility primarily supplies energy to Kalgoorlie Consolidated Gold Mines and is contracted until 2016. Any merchant capacity and energy are sold into Australia’s Wholesale Electricity Market.

The Southern Cross plant is composed of four natural-gas and diesel fired generation facilities with a combined capacity of 245 MW. The Southern Cross plant sells its output pursuant to a contract with BHP Billiton which is set to expire in January of 2014. We are working on an extension of the contract.

We acquired the 125 MW natural-gas and diesel fired Solomon power station in September 2012 from Fortescue. The Solomon Power Station is in the final stages of construction and commissioning, and we expect the plant to be fully commissioned in the first half of 2013. The Solomon facility is fully contracted with Fortescue under a long-term contract that is intended to support their iron ore mining operations.

Energy Trading Segment

Our Energy Trading segment provides a number of strategic functions, including the following:

· | Gathering and assessing market intelligence, enabling our management to more effectively engage in strategic planning and decision making. This includes identifying and ranking energy markets which are the most attractive to enter, and developing strategies and plans to effectively participate in each market where we operate;
· | Negotiating and entering into contractual agreements with customers for the sale of output from our generation assets, including electricity, steam or other energy-related commodities;
· | Negotiating and managing fuel supply arrangements with third parties for our generation assets;
· | Scheduling physical deliveries of natural gas supplies used to generate electricity and the electrical generation output from each asset to meet contractual obligations while managing the physical and financial risks associated with the generation and transmission of electrical energy, including during periods of unplanned outages; and
· | Managing the value of electricity output and fuel inputs from each generating asset through a variety of regional portfolio optimization strategies in both the current year and over the long-term.

The Energy Trading segment also derives additional revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives.

The segment seeks to manage and limit market, operational, credit, and compliance risks from all of its positions. The key risk control activities of the Energy Trading segment, in conjunction with other functions of our business, include credit review approval and reporting, risk measurement monitoring and reporting, validation of transactions, trading portfolio valuation monitoring and reporting, and ensuring transactions are within the compliance framework established by the Corporation.

We use mark to market valuation and the application of a value at risk (“VaR”), stress testing, and non-parametric tests for monitoring market risks within our trading portfolios. VaR is a measure of assessing the potential trading losses that we could experience over a given time due to fluctuations in energy prices in each market. Our policy is to actively manage and limit the segment’s aggregate VaR exposure within Board approved limits.

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Competitive Environment

We are the largest generator of electricity in Alberta, measured by capacity, and have a significant portfolio of generation assets in the Pacific Northwest and the western U.S. We also own and operate generating assets in British Columbia, Ontario, Québec, New Brunswick, and Australia.

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

Alberta is Canada’s fourth largest province by population with approximately 3.87 million residents representing approximately 11.1 per cent of Canada’s total population. Alberta consumed approximately 75,574 GWh of electricity in 2012, with a daily peak demand of 10,600 MW. As at December 31, 2012, the aggregate installed capacity of generating facilities in Alberta was approximately 14,400 MW 1.

British Columbia is Canada’s third largest province by population with approximately 4.6 million residents, representing approximately 13.3 per cent of Canada’s total population. In 2010, British Columbia passed the Clean Energy Act which sets to develop realistic and achievable goals for conservation, energy efficiency and clean energy. Under the Clean Energy Act, British Columbia is expected to be self-sufficient by 2016 with at least 93 per cent of electricity generated from clean or renewable sources. British Columbia’s electricity hourly consumption averaged 6,875 MW in 2011 and 6,889 MW in 2012. The majority of current electricity is obtained from their hydro system. Due to new mining and oil and gas development, and liquefied natural gas terminals at coastal locations, British Columbia’s load profile is changing and is expected to require considerable new energy and capacity additions over the next 20 years.

Ontario is Canada’s largest province by population with approximately 13.5 million residents representing approximately 38.7 per cent of Canada’s total population. Ontario consumed 141,288 GWh of electricity in 2012. Near term power demand outlook is expected to remain relatively unchanged from 2012 for Ontario, as the global economy continues to struggle combined with conservation initiatives, downward pressure from embedded solar capacity growth, Global Adjustment impacts (as determined by the Ontario Independent Electricity System Operator), and time-of-use-rates. Ontario Power Generation Inc., the successor to the generation business of Ontario’s former integrated electric utility, controls 53 per cent of Ontario’s approximately 36,072 MW of installed capacity. The balance is owned by municipal electric utilities and private independent power producers or industrial consumers.

Québec is Canada’s second largest province by population with approximately 8 million residents, representing approximately 23.1 per cent of Canada’s total population. The government in Québec has established the province’s Energy Strategy which includes up to 4,500 MW of additional hydroelectric capacity and 4,000 MW of wind capacity to be installed by 2015.

New Brunswick is Canada’s eighth largest province by population with approximately 0.8 million residents. In New Brunswick, the peak demand forecast for 2012/2013 is 2,960 MW, and the province has installed capacity of about 4,400 MW including the Point Lepreau nuclear facility which came back online in November 2012. The New Brunswick market allows wholesale and industrial consumers to purchase power from either New Brunswick Power or a competing supplier. This competitive market does not extend to retail customers, businesses or small industries. In 2007, New Brunswick announced the Charter for Change requiring ten per cent of electricity purchases to be from renewable sources commencing in 2016.

1 Includes Sundance unit 1 and unit 2 capacity that is currently offline.

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Electrical utilities in Western Canada, the northern portion of Baja California, Mexico and 14 western states are organized into the 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 NWPP’s peak electricity demand reached approximately 62,000 MW in 2012, a three per cent increase from 2011, and had an installed generating capacity of over 100,000 MW in 2012.

Australia has two separate electricity markets, the National Electricity Market (“NEM”) and the Western Australia Electricity Market (“WAEM”), as well as two smaller vertically integrated utilities. The WAEM, where our Australian assets are located, is comprised of the South West Interconnected System (“SWIS”) and the North West Interconnected System (“NWIS”), as well as 29 non-interconnected distribution systems. SWIS serves the south west corner of the state with an installed capacity of approximately 5,996 MW. The NWIS is relatively small with an installed capacity of approximately 500 MW and serves two northern industrial towns. We own 300 MW of gas generation in the SWIS region and 125 MW of non-connected gas and diesel generation in the northern region.

Australia generates approximately 75 per cent of its power from coal; however, Western Australia generates 60 per cent of its power from gas and 35 per cent from coal. A shift from coal-fired to gas-fired generation is anticipated in Australia, partially driven by new regulations such as the Clean Energy Future Plan (passed in September 2011) and the introduction of the Renewable Energy Target policy (implemented in 2010). Western Australia is projected to have the largest energy consumption growth in Australia from now until the 2034-2035 time period due to the growing mining sector and high degree of exports. The Chamber of Minerals and Energy of Western Australia estimate that the electricity growth rate will be 5.6 per cent per annum over the period to 2023. Domestic gas is expected to account for 72 per cent of Western Australia’s forecasted growth of electricity generation into 2035, as estimated by The Bureau of Resources and Energy Economics. We believe we have significant knowledge and expertise in the supply of gas powered electricity to independent mining operations.

Competitive Strengths

We believe that we are well positioned to achieve our business strategy due to our competitive strengths, which include the following:

Financial strength – We have 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”).

Operating strength – Our gas and wind fleet performance is above industry standards. We have outperformed the average North American Energy Reliability Corporation availability for gas-fired units for the time period 2007-2012, and our wind fleet availability has outperformed the North American Benchmark by GL Garrad Hassan for the years 2009-2011. We expect to outperform these benchmarks in 2012 and 2013. In addition, availability has been recognized at our Alberta coal facilities to be above NERC average for similar plants.

Stable cash flow base – Through the use of Alberta PPAs, long-term contracts, and other short-term physical and financial contracts, on average, approximately 77 per cent of our capacity is contracted over the next seven years. The net revenue received under these contractual arrangements helps to minimize short-term revenue fluctuations due to the variable price of electricity.

Fuel diversity – We have a diverse mix of fuels used for the generation of electricity, including coal, natural gas, hydro, geothermal and wind. We believe that this mix reduces the impact on our performance in the event of external events affecting one fuel source.

Management team – Our management team has substantial industry, international, government, investment and market experience.

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Energy Trading expertise – We believe that our Energy Trading segment has enhanced returns from our existing generation base and has allowed us 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 – We own, control or lease coal reserves in Alberta which provide a long-term and stable source of fuel for our thermal generation facilities in Alberta. Our mines in Alberta contain some of the lowest sulphur coal in North America, averaging 0.25 per cent sulphur at the Highvale mine. Coal with lower sulphur content emits less sulphur dioxide (“SO 2”) when it is burned.

Wind Generation – We are the largest owner and operator of wind generation in Canada. Our 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 – We are a recognized leader in sustainable development and we have taken early preventative action on a number of environmental fronts in advance of regulation.

Corporate Segment

Our Corporate Segment provides finance, tax, treasury, legal, regulatory, environmental, health and safety, sustainable development, corporate communications, government and investor relations, information technology, risk management, human resources, internal audit, and other administrative support.

For further information on TransAlta’s segment earnings and assets, please refer to Note 40 of our audited consolidated financial statements for the year ended December 31, 2012, which financial statements are incorporated by reference herein. See “Documents Incorporated by Reference” herein.

ENVIRONMENTAL RISK MANAGEMENT

We are 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. We are committed to complying with legislative and regulatory requirements and to minimizing the environmental impact of our operations. We work with governments and the public to develop appropriate frameworks to protect the environment and to promote sustainable development.

Ongoing and Recently Passed Environmental Legislation

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

Alberta

In October 2012, the Alberta Government released its renewed Clean Air Strategy which sets out a broad framework for managing air emissions and air quality in the future. The framework focuses on a continuous improvement model for regional air quality. It also states that Alberta will take responsibility for implementing any federal air quality standards. There are no specific requirements in this framework that immediately impact our operations.

In Alberta there are requirements for coal-fired generation units to implement additional air emission controls for NOx, SO 2, and particulate matter, once they reach the end of their respective PPA’s, in most cases at 2020. These regulatory requirements were developed by the province in 2004 as a result of multi-stakeholder discussions under Alberta’s Clean Air Strategic Alliance (“CASA”). However, the release of the federal GHG regulations may create a misalignment between the CASA air pollutant requirements and schedules, and the GHG retirement schedules for older coal plants, which in themselves will result in significant reductions of NOx, SO 2, and particulates. We are in discussions with the provincial government to ensure coordination between GHG and air pollutant regulations, such that emission reduction objectives are achieved in the most effective manner while taking into consideration the reliability and cost of Alberta’s generation supply.

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Canada

On September 11, 2012, the Canadian federal government published the final regulations governing GHG emissions from coal-fired plants, which become effective on July 1, 2015. The regulations provide for up to 50 years of life for coal units, at which point units must meet an emissions performance standard of approximately 420 tonnes per GWh. There are some exceptions that require older units commissioned before 1975 to reach end of life by December 31, 2019, and units commissioned between 1975 and 1986 to reach end of life by December 31, 2029. Compared to the initial draft version of these regulations, we believe the final regulations provide additional operating time and increased flexibility for our Canadian coal units, allowing for a smoother transition of those units and in a more cost-effective manner.

United States

On March 27, 2012, the U.S. Environmental Protection Agency (“EPA”) proposed GHG emission standards for future coal-fired power plants. It is intended that the proposed standard would be met by fuel switching or through clean coal technologies. As this regulatory framework is for new coal-fired plants, we expect no material impact on our existing coal-fired units at Centralia.

In December 2011, the EPA issued national standards for mercury emissions from power plants. Existing sources will have up to four years to comply. We have already voluntarily installed mercury capture technology at our Centralia Thermal plant, and began full capture operations in early 2012. We have also installed additional technology to further reduce NOx, consistent with the Washington State Bill passed in April 2011 requiring TransAlta to begin operating such technology by January 1, 2013.

In addition to the Federal, Regional and State regulations that we must comply with, we also comply with the standards established by the North American Electric Reliability Corporation (“NERC”). NERC is the electric reliability organization certified by the Federal Energy Regulatory Commission in the United States to establish and enforce reliability standards for the bulk-power system. NERC develops and enforces reliability standards; assesses adequacy annually; monitors the bulk-power system; and educates, trains and certifies industry personnel.

TransAlta Activities

Reducing the environmental impact of our activities has a benefit not only to our operations and financial results, but to the communities in which we operate. We expect that increased scrutiny will be placed on environmental emissions and compliance. We, therefore, take a proactive approach to minimizing risks to our results. Our Board provides oversight to our environmental management programs and emission reduction initiatives in order to ensure continued compliance with environmental regulations.

Our environmental management programs encompass the following elements:

Renewable Power

We continue to invest in and build renewable power resources. Our 68 MW New Richmond wind facility is currently under construction and commercial operations are expected to commence during the first quarter of 2013. A larger renewable portfolio provides increased flexibility in generation and creates incremental environmental value through renewable energy certificates or through offsets.

Environmental Controls and Efficiency

We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. We installed mercury control equipment at our Alberta thermal operations in 2010 in order to meet the province’s 70 per cent reduction objectives, and at our Centralia Thermal plant in 2012 on a voluntary basis. Our new Keephills 3 plant began operation in September 2011 using supercritical combustion technology to maximize thermal efficiency, as well as SO 2 capture and low NOx combustion

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technology, which is consistent with the technology that is currently in use at Genesee 3. Uprate projects at our Keephills and Sundance plants are expected to improve the energy and emissions efficiency of those units.

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

Policy Participation

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

Clean Combustion Technologies

We look to advance clean energy technologies through organizations such as the Canadian Clean Coal Power Coalition, which examines emerging clean combustion technologies such as gasification. We are also part of a group of companies participating in the Integrated CO 2 Network to promote carbon capture and storage systems and infrastructure for Canada.

Offsets Portfolio

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

Environmental Regulations

Recent changes to environmental regulations may materially adversely affect us. As indicated under “Risk Factors” in this AIF and within the Risk Management section of the Annual MD&A, many of our activities and properties are subject to environmental requirements, as well as changes in our liabilities under these requirements, which may have a material adverse effect upon our consolidated financial results.

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 AIF. 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.

The operation and maintenance of our facilities involves risks that may materially and adversely affect our business.

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 our generation facilities, particularly in Alberta, were constructed many years ago and may require significant capital expenditures to maintain peak efficiency or to maintain operations. There can be no assurance that our maintenance program will be able to detect potential failures in our facilities prior to occurrence or eliminate all adverse consequences in the event of failure. In addition, weather related interference, work stoppages and other unforeseen problems may disrupt the operation and maintenance of our facilities and may materially adversely affect us.

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

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

We may be subject to the risk that it is necessary to operate a plant at a capacity level beyond that which we have contracted for power in order to provide steam in fulfillment of such a contract. In such circumstances, the costs to produce the steam being sold may exceed the revenues derived therefrom.

Equipment failure may cause us to suffer a material adverse effect.

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

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

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

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

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

We may be adversely affected if our 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 our

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control, may reduce the water flow to our facilities. Any material reduction in the water flow to our facilities would limit our ability to produce and market electricity from these facilities and could have a material adverse effect on us. There is an increasing level of regulation respecting the use, treatment and discharge of water, and respecting the licensing of water rights in jurisdictions where we operate. Any such change in regulations could have a material adverse effect on us.

Variation in wind levels may negatively impact the amount of electricity generated at our wind facilities.

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

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

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

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

We buy natural gas and a portion of our coal to supply the fuel needed to generate electricity. We could be materially adversely affected if the cost of fuel that we must buy to generate electricity increases to a greater degree than the price that we can obtain for the electricity that we sell. Several factors affect the price of fuel, many of which are beyond our control, including:

· | prevailing market prices for fuel;
· | global demand for energy products;
· | the cost of carbon and other environmental concerns;
· | weather-related disruptions affecting the ability to deliver fuels or near-term demand for fuels;
· | increases in the supply of energy products in the wholesale power markets;
· | the extent of fuel transportation capacity or cost of fuel transportation service into our markets; and
· | the cost of mining that, in turn, depends on various factors such as labour market pressures, equipment replacement costs and permitting.

Changes in any of these factors may increase our cost of producing power or decrease the amount of revenue received from the sale of power, which could have a material adverse effect on us.

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Disruption of fuel supply to certain of our thermal plants could have an adverse impact on our financial condition.

Certain of our thermal facilities depend on third parties to supply fuel, including natural gas and coal. As a result, we face the risks of supply interruptions and fuel price volatility, as fuel deliveries may not exactly match those required for energy sales, due in part to our need to pre-purchase fuel inventories for reliability and dispatch requirements. Disruption of transportation services of fuel, whether because of weather-related problems, strikes, lock-outs, break-downs of locks and dams or other events could impair our ability to generate electricity and could adversely affect our results of operations. Significantly, the coal used to fuel the Centralia Thermal facility is now sourced from the Powder River basin in Montana and Wyoming and we have entered into contracts to purchase and transport such coal to our Centralia Thermal facility. Our existing coal contracts for the Centralia Thermal plant expire at the end of 2014. The loss of our suppliers or our inability to renew our existing coal contracts for Powder River Basin coal at favorable terms could also significantly affect our ability to serve our customers and have an adverse impact on our financial condition and results of operations.

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

Adverse changes in general economic and market conditions could negatively impact demand for electricity, 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 cause us to suffer a material adverse effect. Changes in interest rates can impact our borrowing costs and the capacity revenues that we receive pursuant to the Alberta PPAs.

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

The majority of our Alberta thermal and hydroelectric generating plants operate under the Alberta PPAs, which establish committed capacity and availability targets to be achieved by each coal-fired plant, energy and ancillary services obligations for the hydroelectric plants, and compensation for meeting the PPA obligations. Under the Alberta PPAs applicable to coal-fired plants, in the event of an unplanned outage other than an outage determined to be caused by force majeure, we 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 us.

We bear some of the impact of increases in our 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 which we are able to receive for our capacity under the Alberta PPAs is based on a schedule of forecast fixed costs. Many of the forecast costs will be determined by indices, formulae or other means for the entire term of the Alberta PPAs. Our 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 our control. A significant increase in our operating costs could have a material adverse effect on our business.

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 in our favour. In such circumstances, we could be materially and adversely affected.

We operate in a highly competitive environment and may not be able to compete successfully.

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

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Variations in weather can affect demand for electricity and our ability to generate electricity.

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

We may be unsuccessful in the defence of legal actions.

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

The laws and regulations in the various markets in which we operate are subject to change, which may materially adversely affect us.

Certain of the markets in which we operate and intend to operate are subject to significant regulatory oversight and control. We are 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 ours, changes in market structure or market design or what the ultimate effect of a changing regulatory environment will have on our business. Existing market rules and regulations are often dynamic and may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our facilities which could have a material adverse effect on us.

We manage these risks systematically through a regulatory and compliance program designed to reduce any potential negative impact on us. However, we cannot guarantee that we will be able to adapt our business in a timely manner in response to any changes in the regulatory regimes in which we operate, and such failure to adapt could have a material adverse effect on our business.

Regulatory authorities may also from time to time investigate our activities in the markets in which we operate or pursue trading. Such investigations may result in sanctions or penalties which may materially affect our future activities or financial status.

Our facilities are also subject to various licensing and permitting requirements in the jurisdictions in which we operate. Many of these licenses and permits need to be renewed from time to time. If we are unsuccessful in renewing such licenses or permits, or the terms of such licenses or permits are changed in a manner that is adverse to our business, we 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 we compete or may compete in the future may materially adversely affect us.

Our business could be materially affected by greater regulation of over-the-counter derivatives, which could materially affect our ability to economically hedge our generation.

Title VII of the Dodd-Frank Act increases the regulation of transactions involving over-the-counter (“OTC”) derivative financial instruments, including the requirement for central clearing of many OTC derivatives transactions. The effect of the Dodd-Frank Act, as well as of comparable Canadian derivatives regulation, on our business depends on pending rulemaking proceedings. Regulatory change could materially adversely affect our ability to economically hedge our generation, by reducing liquidity in the energy markets and, if we are required to clear such transactions on exchanges or meet other requirements, by significantly increasing the collateral costs associated with these activities. It is not known at this time whether, and, if so, to what extent, we will be required to provide collateral (for both our cleared and uncleared transactions) in excess of what we currently provide under our existing hedge relationships. Other features of derivative regulation which will have an impact on our energy

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marketing and treasury activities include trade reporting, position limits and trade execution. Rulemaking and implementation will take effect over several years which makes it difficult to assess its full impact on us at this time.

Many of our activities and properties are subject to environmental requirements and changes in, or liabilities under these requirements, may materially adversely affect our business.

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

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

A number of recent federal, provincial, state and local regulatory efforts continue to focus on potential climate change or GHG emissions regulation, and mandatory GHG reporting requirements have become effective for 2010 in both Ontario and the United States. In the United States, GHG legislation or alternative forms of regulation are still under development, and it is too early to determine their impacts. Mandatory GHG emissions reductions requirements are expected to impose increased costs on our business, as is expected to be the case generally for thermal power producers in North America. We are subject to other air quality regulations including mercury regulations. At this time, we cannot assess the potential impact of future mercury regulations at our United States facilities. To the extent new or additional GHG, mercury or other air emission regulations may require us to incur costs that cannot be passed through to our customers under its power purchase agreements, including Alberta PPAs or otherwise, the costs could be material and have a material adverse effect on our business. The Australian Government implemented a national carbon tax of $23 AUS/tonne on July 1, 2012. Approximately 300 facilities with annual CO 2 emissions over 25,000 tonnes/year are subject to the tax on every tonne of CO 2 emitted. Principal

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sectors affected include mining, heavy industry and the power sector, both coal and natural gas-fired generation. The tax is designed to increase by just over $1 AUS/tonne annually until July 1, 2015, at which time the carbon tax will be replaced by an emissions trading scheme with the carbon price set by the market. In terms of TransAlta’s existing gas-fired facilities, we currently have change-in-law provisions allowing flow-through of any carbon tax-related costs, and we expect that any new contracts will contain similar provisions.

Our surface mining operations are subject to laws and regulations establishing mining, environmental protection and reclamation standards for all aspects of surface mining. As a mine owner or operator, we 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. As a mine owner or operator, we 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. We could be required to self-fund these obligations should we be unable to renew or secure the required surety bonds for our mining operations or because it is more economical to do so.

Changes in opinions of our Corporation from external parties may have a material adverse effect on us.

Reputation risk relates to the risk associated with our business because of changes in opinion from the general public, private stakeholders, governments, and other entities. Our reputation is one of our most valued assets. The potential for harming our reputation exists in every business decision and all risks can have an impact on reputation, which in turn can negatively impact our business and securities. Reputation risk cannot be managed in isolation from other forms of risk. Negative impacts from a compromised reputation could include revenue loss, reduction in customer base, and decreased value of our securities.

Our information technology systems are vulnerable to damages from computer viruses, natural disasters, unauthorized access, cyber-attack and other similar disruptions, all of which could have a material adverse effect on our business.

We have put in place a number of systems, processes and practices designed to protect against intentional or unintentional misappropriation or corruption of our systems and information or disruption of our operations. Despite our implementation of security measures, our IT systems are vulnerable to damages from computer viruses, natural disasters, unauthorized access, cyber-attack and other similar disruptions. Any system failure, accident or security breach could result in disruptions to our operations and a loss of confidential or proprietary data which could adversely affect our reputation, diminish customer confidence, disrupt operations, and subject us to possible financial liability, any of which could have a material adverse effect on our financial condition and results of operations. We closely monitor both preventive and detective measures to manage these risks.

We rely on transmission lines that we do not own or control, which may hinder our ability to produce, sell and deliver electricity.

We depend on transmission and distribution facilities that are owned and operated by utilities and other power companies to deliver the electricity that we generate. An extended disruption in transmission, a failure in the transmission system or a lack of available transmission and distribution facilities could impact our ability to produce, sell and deliver electricity, which could have a material adverse effect on our business.

Trading risks may have a material adverse effect on our business.

Our trading and marketing business frequently involves the establishment of trading positions in the wholesale energy markets on both a medium-term and short-term basis. To the extent that we have long positions in the energy markets, a downturn in market prices will result in losses from a decline in the value of such long positions. Conversely, to the extent that we enter into forward sales contracts to deliver energy that we do not own, or take short positions in the energy markets, an upturn in market prices will expose us to losses as we attempt to cover any short positions by acquiring energy in a rising market.

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In addition, from time to time, we may have a trading strategy consisting of simultaneously holding a long position and a short position, from which we expect 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 that we did not anticipate, we would realize losses from such a paired position.

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

While we use a number of risk management controls conducted by our independent Risk Management group to limit our exposure to risks arising from our trading activities, including VaR, stop loss restrictions, stress testing, volumetric and term limits and restrictions on authorized instruments, we cannot guarantee that losses will not occur and such losses could materially adversely affect us.

Because of our multinational operations, we are subject to currency rate risk and regulatory and political risk.

We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the earnings from those operations, the acquisition of equipment and services from foreign suppliers, and our U.S. denominated debt. Our exposures are primarily to the U.S., Australian and Euro currencies. Changes in the values of these currencies relative to the Canadian dollar could negatively impact our earnings or the value of our foreign investments. While we attempt to manage this risk through the use of hedging instruments, including cross-currency interest rate swaps, forward exchange contracts and by matching revenues and expenses by currency at the Corporate level, there can be no assurance that these risk management efforts will be effective, and fluctuations in these exchange rates may have a material adverse effect on our business.

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

We may have difficulty raising needed capital in the future, which could significantly harm our business.

To the extent that our sources of cash and cash flow from operations are insufficient to fund our activities, we 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 that are favourable to our business.

Our debt securities will be structurally subordinated to any debt of our subsidiaries that are currently outstanding or may be incurred in the future.

We operate our business through, and a majority of our assets are held by, our subsidiaries, including partnerships. Our results of operations and ability to service indebtedness are dependent upon the results of operations of our subsidiaries and the payment of funds by these subsidiaries to TransAlta in the form of loans, dividends or otherwise. Our subsidiaries will not have an obligation to pay amounts due pursuant to any debt securities issued by TransAlta or make any funds available for payment of debt securities issued by TransAlta, 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 us by our 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 TransAlta’s indebtedness, including any debt securities issued by TransAlta. Such indebtedness and any other future indebtedness of such subsidiaries would be structurally senior for such subsidiary to any debt securities issued by TransAlta.

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Our 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, our 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 TransAlta, it may materially affect our ability to service our outstanding indebtedness.

A downgrade of our credit ratings could materially and adversely affect us.

Rating agencies regularly evaluate us, basing their ratings of our long-term and short-term debt on a number of factors. There can be no assurance that one or more of our credit ratings will not be downgraded. Our borrowing costs and ability to raise funds are directly impacted by our credit ratings. Credit ratings may be important to suppliers or counterparties when they seek to engage in certain transactions with us. A credit rating downgrade could potentially impair our ability to enter into arrangements with suppliers or counterparties, to engage in certain transactions, and could limit our access to private and public credit markets and increase the costs of borrowing under our existing credit facilities. A credit rating downgrade could require us to post a material amount of new collateral to our counterparties. For further information on posting collateral in the event of a credit downgrade, please see Note 17 section C. III of our audited consolidated financial statements for the year ended December 31, 2012, which financial statements are incorporated by reference herein. Please also see “Documents Incorporated by Reference.”

Changes in statutory or contractual restrictions that affect our corporate structure may have a material adverse effect on us.

We conduct a significant amount of business through subsidiaries and partnerships. Our ability to meet and service debt obligations is dependent upon the results of operations of our subsidiaries and the payment of funds by our subsidiaries in the form of distributions, loans, dividends, or otherwise. In addition, our subsidiaries may be subject to statutory or contractual restrictions that limit their ability to distribute cash to us.

Certain of the contracts to which we are a party require that we provide collateral against our obligations.

We are 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 us to provide collateral when the fair value of these contracts is in excess of any credit limits granted by our counterparties and the contract obliges that we 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 our creditworthiness by certain credit rating agencies may decrease the credit limits granted by our counterparties and accordingly increase the amount of collateral that we may have to provide, which could materially adversely affect us.

If counterparties to our contracts are unable to meet their obligations, we may be materially and adversely affected.

If purchasers of our electricity and steam or other contractual counterparties default on their obligations, we may be materially and adversely affected. While we have procedures and controls in place to manage our counterparty credit risk prior to entering into contracts, all contracts inherently contain default risk. Moreover, while we seek to monitor trading activities to ensure that the credit limits for counterparties are not exceeded, we cannot guarantee that a party will not default. If counterparties to our contracts are unable to meet their obligations, we could suffer a reduction in revenue which could have a material adverse effect on our business.

Insurance coverage may not be sufficient.

We have insurance for our facilities, including all risk property insurance, commercial general liability insurance and boiler and machinery coverage in amounts and with deductibles that we consider appropriate. We also carry

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business interruption insurance for certain of our facilities where we do not otherwise have contractual arrangements to address these potential losses or where in other cases it would not be economical to do so.

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

Provision for income taxes may not be sufficient.

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

If we fail to attract and retain key personnel, we could be materially adversely affected.

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

If we are unable to successfully negotiate new collective bargaining agreements with our unionized workforce, as required from time to time, we will be adversely affected.

While we believe we have a satisfactory relationship with our unionized employees, we cannot guarantee that we will be able to successfully negotiate or renegotiate our collective bargaining agreements on terms agreeable to TransAlta. We expect to re-negotiate eight collective bargaining agreements, involving 1,319 of our employees, in 2013 and an additional two collective bargaining agreements, involving 65 of our employees, in 2014. 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 us.

Risks relating to TransAlta’s development projects and acquisitions may materially and adversely affect us.

Development projects and acquisitions that we undertake may be subject to execution and capital cost risks, including, but not limited to, risks relating to regulatory approvals, third party opposition, cost escalations, construction delays, shortages of raw materials or skilled labour and capital constraints. The occurrences of these risks could have a material and adverse impact on us, our financial condition, results of operations and cash flows.

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

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

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EMPLOYEES

As of December 31, 2012, we had 2,084 active employees, which figure includes full-time, part-time and temporary employees, of which 1,493 were employed in our Generation business and 77 were employed in our Energy Trading business. Approximately 43 per cent of our employees are represented by labour unions. We are currently a party to 11 different collective bargaining agreements. In 2012, we renewed two of the collective bargaining agreements, which were set to expire on December 31, 2012.

Effective January 17, 2013, we assumed, through our wholly owned SunHills Partnership, the operation and management of our Highvale mine. The SunHills Partnership employs 604 employees that had previously been employed by PMRL, which employees are being employed by SunHill Partnership pursuant to the terms of one bargaining agreement.

CAPITAL STRUCTURE

General

Our authorized share capital consists of an unlimited number of common shares and an unlimited number of first preferred shares, issuable in series. As at February 26, 2013, there were 258,420,400 common shares outstanding and 12,000,000 Series A, 11,000,000 Series C and 9,000,000 Series E first preferred shares outstanding.

Common Shares

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

First Preferred Shares

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

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

The Board may include, in the share conditions attaching to a particular series of first preferred shares, certain voting rights effective upon our failing to make payment of six quarterly dividend payments, whether or not consecutive. These voting rights continue for so long as any dividends remain in arrears. These voting rights are the right to one vote for each $25.00 of subscription price on all matters in respect of which shareholders vote, and

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additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of TransAlta if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.

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

Series A Shares

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

Dividends on Series A Shares

The holders of Series A Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.

For each five-year period after the Initial Fixed Rate Period (each a “Subsequent Fixed Rate Period”), the holders of Series A Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30 th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five year bond) on the Fixed Rate Calculation Date plus a spread of 2.03 per cent. This spread will apply to both the Series A Shares and the Series B Shares described below, and will remain unchanged over the life of the Series A Shares.

Redemption of Series A Shares

The Series A Shares are redeemable by TransAlta in whole or in part, on or after March 31, 2016, and on March 31 in every fifth year thereafter by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).

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

Conversion of Series A Shares into Series B Shares

The holders of the Series A Shares have the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series B of TransAlta (the “Series B Shares”), subject to certain conditions, on March 31, 2016 and on March 31 in every fifth year thereafter. The holders of the Series B Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a “Quarterly Floating Rate Period”), in the amount per share determined by multiplying the “Floating

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Quarterly Dividend Rate” (which means, for any Quarterly Floating Rate Period, the annual rate of interest, (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 2.03 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 2.03 per cent.

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

Modification

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

Series C Shares

The Series C rate reset preferred shares were issued on November 30, 2011 with a coupon of 4.60 per cent (“Series C Shares”), as discussed in the section entitled General Development of the Business. Certain provisions of the Series C Shares are discussed below.

Dividends on Series C Shares

The holders of Series C Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.

For each five-year period after the Initial Fixed Rate Period (each a “Subsequent Fixed Rate Period”), the holders of Series C Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30 th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five year bond) on the Fixed Rate Calculation Date plus a spread of 3.10 per cent. This spread will apply to both the Series C Shares and the Series D Shares described below, and will remain unchanged over the life of the Series C Shares.

Redemption of Series C Shares

The Series C Shares are redeemable by TransAlta in whole or in part, on or after June 30, 2017, and on June 30 in every fifth year thereafter by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).

If we give notice to the holders of the Series C Shares of the redemption of all of the Series C Shares, the right of a holder of Series C Shares to convert such Series C Shares shall terminate and we shall not be required to give notice

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to the registered holders of the Series C Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series C Shares.

Conversion of Series C Shares into Series D Shares

The holders of the Series C Shares have the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series D of TransAlta (the “Series D Shares”), subject to certain conditions, on June 30, 2017 and on June 30 in every fifth year thereafter. The holders of the Series D Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a “Quarterly Floating Rate Period”), in the amount per share determined by multiplying the “Floating Quarterly Dividend Rate” (which means, for any Quarterly Floating Rate Period, the annual rate of interest, (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.10 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.10 per cent.

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

Modification

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

Series E Shares

The Series E rate reset preferred shares were issued on August 10, 2012 with a coupon of 5.00 per cent (“Series E Shares”), as discussed in the section entitled General Development of the Business. Certain provisions of the Series E Shares are discussed below.

Dividends on Series E Shares

The holders of Series E Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.

For each five-year period after the Initial Fixed Rate Period (each a “Subsequent Fixed Rate Period”), the holders of Series E Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta Corporation on the Fixed Rate Calculation Date (30 th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five year bond) on

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the Fixed Rate Calculation Date plus a spread of 3.65 per cent. This spread will apply to both the Series E Shares and the Series F Shares described below, and will remain unchanged over the life of the Series E Shares.

Redemption of Series E Shares

The Series E Shares are redeemable by TransAlta Corporation in whole or in part, on or after September 30, 2017, and on September 30 in every fifth year thereafter by the payment of an amount of $25.00 in cash for each share to be redeemed plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).

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

Conversion of Series E Shares into Series F Shares

The holders of the Series E Shares have the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series F of TransAlta (the “Series F Shares”), subject to certain conditions, on September 30, 2017 and on September 30 in every fifth year thereafter. The holders of the Series F Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a “Quarterly Floating Rate Period”), in the amount per share determined by multiplying the “Floating Quarterly Dividend Rate” (which means, for any Quarterly Floating Rate Period, the annual rate of interest, (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.65 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.65 per cent.

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

Modification

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

Premium Dividend™, Dividend Reinvestment and Optional Common Share Purchase Plan

On February 21, 2012, TransAlta Corporation added a Premium Dividend TM Component to its existing Dividend Reinvestment and Share Purchase Plan. The amended and restated plan, the Premium Dividend TM, Dividend Reinvestment and Optional Common Share Purchase Plan provides eligible shareholders of TransAlta with two options: i) to reinvest dividends at a current three per cent discount (may be from zero to five per cent at the discretion of the Board of Directors) to the average market price towards the purchase of new shares of TransAlta (the Dividend Reinvestment Component) or ii) receive the equivalent to 102% of the dividends payable in cash, a premium cash payment (the Premium Dividend TM Component).

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Eligible shareholders enrolled in either the Dividend Reinvestment Component or the Premium Dividend TM Component will also be eligible to purchase new shares at a discount to the average market price under the optional cash payment component (the OCP Component) of the plan by directly investing up to $5,000.00 per quarter. The applicable discount under the OCP Component is also determined from time to time by the Board and is currently set at three per cent.

CREDIT RATINGS

Issuer Rating

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

As of December 31, 2012, our issuer rating was BBB- (stable) from S&P and BBB (stable) from DBRS.

Senior Unsecured Long-term Debt

As of December 31, 2012, our senior unsecured long-term debt is rated BBB (stable) by DBRS, BBB- (stable) by S&P and Baa3 (stable) by Moody’s. The ratings for debt instruments range from a high of AAA to a low of D in the case of both DBRS and S&P and from a high of Aaa to a low of C in the case of Moody’s.

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

According to the S&P rating system, debt securities rated BBB exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on such obligations than on obligations in the higher rating categories. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (–) sign to show relative standing within the major rating categories. S&P also assigns a rating outlook to each of its ratings to give investors an understanding of S&P’s opinion regarding the potential direction for the long-term credit rating over the intermediate term.

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

On July 31, 2012 our senior unsecured debt rating was lowered to Baa3 stable from Baa2 negative outlook by Moody’s. On August 1, 2012, our corporate credit and senior unsecured debt ratings were lowered to ‘BBB- stable’ from ‘BBB negative outlook’ by S&P. We are focused on maintaining a strong financial position and cash flow coverage ratios to support stable investment grade credit ratings. Our investment grade credit rating, available credit facilities, funds from operations, and our manageable debt maturity profile provide us with financial flexibility. As a result we can be selective as to if and when we go to the capital markets for funding.

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Preferred Shares

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

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

According to the S&P rating system, securities rated P-3 are of adequate credit quality. The ratings from P-1 to -5 may be modified by “high” or “low” grades which indicate relative standing within the major rating categories.

Note Regarding Credit Ratings

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

We have paid for rating services fees to S&P, Moody’s, and DBRS, but have not paid for other rating agency services during the last two years. We expect to pay market fees for other rating agency services in the future.

DIVIDENDS

Common Shares

Dividends on our common shares are at the discretion of the Board. In determining the payment and level of future dividends, the Board considers our financial performance, our results of operations, cash flow and needs, with respect to financing our ongoing operations and growth, balanced against returning capital to shareholders. The Board continues to focus on building sustainable earnings and cash flow growth.

TransAlta has declared and paid the following dividends per share on its outstanding common shares for the past three years:

Period |  |  |  | Dividend per Common Share |
2010 |  | First Quarter |  | $0.29 |
|  | Second Quarter |  | $0.29 |
|  | Third Quarter |  | $0.29 |
|  | Fourth Quarter |  | $0.29 |
2011 |  | First Quarter |  | $0.29 |
|  | Second Quarter |  | $0.29 |
|  | Third Quarter |  | $0.29 |
|  | Fourth Quarter |  | $0.29 |
2012 |  | First Quarter |  | $0.29 |
|  | Second Quarter |  | $0.29 |
|  | Third Quarter |  | $0.29 |
|  | Fourth Quarter |  | $0.29 |

On January 28, 2013, the Board declared a cash dividend of $0.29 per common share, payable on April 1, 2013 to shareholders of record on March 1, 2013.

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Series A Shares

Period |  |  |  | Dividend per Series A Preferred Share |
2011 |  | First Quarter(1) |  | $0.3497 |
|  | Second Quarter |  | $0.2875 |
|  | Third Quarter |  | $0.2875 |
|  | Fourth Quarter |  | $0.2875 |
2012 |  | First Quarter |  | $0.2875 |
|  | Second Quarter |  | $0.2875 |
|  | Third Quarter |  | $0.2875 |
|  | Fourth Quarter |  | $0.2875 |

Note:

(1) | On December 31, 2010, the Board approved an initial dividend of $0.3497 per Series A Shares for the period from issuance on December 10, 2010 to March 31, 2011.

On January 28, 2013, the Board declared a cash dividend of $0.2875 per Series A Preferred share, payable on March 31, 2013 to shareholders of record on March 1, 2013.

Series C Shares

Period |  |  |  | Dividend per Series C Preferred Share |
2012 |  | First Quarter(1) |  | $0.3844 |
|  | Second Quarter |  | $0.2875 |
|  | Third Quarter |  | $0.2875 |
|  | Fourth Quarter |  | $0.2875 |

Note:

(1) | On January 25, 2012 the Board approved an initial dividend of $0.3844 per Series C Preferred share for the period from issuance on November 29, 2011 to March 31, 2012.

On January 28, 2013, the Board declared a cash dividend of $0.2875 per Series C Preferred share, payable on March 31, 2013 to shareholders of record on March 1, 2013.

Series E Shares

Period |  |  |  | Dividend per Series E Preferred Share |
2012 |  | Fourth Quarter(1) |  | $0.4897 |

Note:

(1) | On October 24, 2012 the Board approved an initial dividend of $0.4897 per Series E Preferred share for the period from issuance on August 10, 2012 to December 31, 2012.

On January 28, 2013, the Board declared a cash dividend of $0.3125 per Series E Preferred share, payable on March 31, 2013 to shareholders of record on March 1, 2013.

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MARKET FOR SECURITIES

Common Shares

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

|  | Price ($) |  |
Month |  | High |  | Low |  | Volume
2012 |  |  |  |  |  |
January |  | 21.51 |  | 20.00 |  | 15,700,737
February |  | 21.20 |  | 20.27 |  | 13,235,698
March |  | 20.86 |  | 18.42 |  | 25,017,326
April |  | 18.72 |  | 15.94 |  | 16,664,435
May |  | 17.59 |  | 16.17 |  | 15,483,252
June |  | 17.75 |  | 16.43 |  | 20,661,918
July |  | 17.85 |  | 15.44 |  | 15,992,777
August |  | 16.13 |  | 14.86 |  | 11,535,958
September |  | 15.30 |  | 13.96 |  | 32,902,543
October |  | 16.08 |  | 14.81 |  | 14,165,679
November |  | 16.00 |  | 14.50 |  | 10,702,261
December |  | 15.15 |  | 14.44 |  | 19,578,424
2013 |  |  |  |  |  |
January |  | 16.89 |  | 15.01 |  | 13,124,537
February 1-26 |  | 16.69 |  | 16.07 |  | 9,210,789

Series A Shares

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

Date(s) of Issuance |  | Number of Securities |  | Issue Price per Security |  | Description of Transaction
December 10, 2010(1) |  | 12,000,000 Series A Shares |  | $25.00 |  | Public Offering

Note:

(1) | Series A Shares were issued pursuant to a public offering in a prospectus supplement dated December 3, 2010. See “General Development of the Business –Corporate and Energy Trading”.

|  | Price ($) |  |
Month |  | High |  | Low |  | Volume
2012 |  |  |  |  |  |
January |  | 25.71 |  | 24.87 |  | 235,338
February |  | 25.89 |  | 24.94 |  | 131,209
March |  | 25.43 |  | 24.61 |  | 159,410
April |  | 24.94 |  | 21.84 |  | 457,256
May |  | 23.92 |  | 22.65 |  | 265,655
June |  | 24.00 |  | 23.19 |  | 160,613
July |  | 24.40 |  | 23.57 |  | 198,733
August |  | 23.95 |  | 22.99 |  | 241,534
September |  | 23.60 |  | 22.66 |  | 200,631
October |  | 22.92 |  | 22.55 |  | 170,656
November |  | 23.14 |  | 22.26 |  | 821,830
December |  | 22.45 |  | 21.55 |  | 271,562
2013 |  |  |  |  |  |
January |  | 24.41 |  | 21.90 |  | 666,234
February 1-26 |  | 24.20 |  | 23.84 |  | 240,827

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Series C Shares

Our Series C Shares are listed on the TSX under the symbol “TA.PR.F”.

Date(s) of Issuance |  | Number of Securities |  | Issue Price per Security |  | Description of Transaction
November 30, 2011(1) |  | 11,000,000 Series C Shares |  | $25.00 |  | Public Offering

Note:

(1) | Series C Shares were issued pursuant to a public offering in a prospectus supplement dated November 23, 2011. See “General Development of the Business –Corporate and Energy Trading”.

|  | Price ($) |  |
Month |  | High |  | Low |  | Volume
2012 |  |  |  |  |  |
January |  | 25.60 |  | 25.16 |  | 797,165
February |  | 25.90 |  | 25.13 |  | 400,185
March |  | 25.49 |  | 25.06 |  | 211,968
April |  | 25.34 |  | 22.03 |  | 655,774
May |  | 24.00 |  | 22.90 |  | 464,839
June |  | 24.46 |  | 23.31 |  | 353,668
July |  | 24.89 |  | 23.90 |  | 228,083
August |  | 24.35 |  | 23.36 |  | 224,541
September |  | 24.09 |  | 22.90 |  | 191,122
October |  | 23.91 |  | 23.10 |  | 141,599
November |  | 23.91 |  | 23.14 |  | 222,286
December |  | 24.04 |  | 23.31 |  | 226,551
2013 |  |  |  |  |  |
January |  | 25.95 |  | 24.04 |  | 480,660
February 1-26 |  | 25.20 |  | 25.00 |  | 322,804

Series E Shares

Our Series E Shares are listed on the TSX under the symbol “TA.PR.H”.

Date(s) of Issuance |  | Number of Securities |  | Issue Price per Security |  | Description of Transaction
August 10, 2012(1) |  | 9,000,000 Series E Shares |  | $25.00 |  | Public Offering

Note:

(1) | Series E Shares were issued pursuant to a public offering in a prospectus supplement dated August 3, 2012. See “General Development of the Business –Corporate and Energy Trading”.

|  | Price ($) |  |
Month |  | High |  | Low |  | Volume
2012 |  |  |  |  |  |
August 10 to 31 |  | 25.15 |  | 24.70 |  | 890,819
September |  | 25.25 |  | 24.85 |  | 194,050
October |  | 25.65 |  | 25.00 |  | 320,240
November |  | 25.67 |  | 25.10 |  | 159,234
December |  | 25.25 |  | 25.00 |  | 105,411
2013 |  |  |  |  |  |
January |  | 25.85 |  | 25.07 |  | 155,544
February 1-26 |  | 25.91 |  | 25.50 |  | 178,829

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DIRECTORS AND OFFICERS

The name, province or state and country of residence of each of our directors as at February 26, 2013, their respective position and office and their respective principal occupation during the five preceding years, are set out below. The year in which each director was appointed to serve to the Board is also set out below. Each director is appointed to serve until the next annual meeting of TransAlta or until his or her successor is elected or appointed. Stephen L. Baum resigned as a Director of the Board of TransAlta for personal reasons on May 22, 2012 at the age of 70.

Name, Province (State) and Country of Residence(1) |  | Year first became Director |  | Principal Occupation
William D. Anderson Ontario, Canada |  | 2003 |  | Corporate Director. Mr. Anderson has had a career as a business leader in Canada spanning over thirty years. He was President of BCE Ventures (a subsidiary of BCE Inc.) from 2001 to 2005 (telecommunications) and prior to that, Chief Financial Officer (“CFO”) of BCE Inc., Bell Canada Inc. and of Bell Cablemedia plc (telecommunications). As President of BCE Ventures, he was responsible for a number of significant operating companies as well as being Chief Executive Officer (“CEO”) of Bell Canada International Inc. In his CFO roles, Mr. Anderson was responsible for all financial operations of the respective companies and executed numerous debt and equity financings, corporate acquisition and disposition transactions as well as corporate and operational restructurings. He was also in public practice for nearly twenty years with the accounting firm KPMG LLP, where he was a partner for eleven years. Mr. Anderson is the Chair of Gildan Activewear Inc. and Nordion Inc. and a director of Sun Life Financial Inc. Mr. Anderson is a past director at BCE Emergis Inc., Bell Cablemedia plc, Bell Canada International Inc., CGI Group Inc., Four Seasons Hotels Inc., Sears Canada Inc. and Videotron Holdings plc. At TransAlta, Mr. Anderson is Chair of the Audit and Risk Committee of the Board. Mr. Anderson holds a bachelor in business administration from the University of Western Ontario (London, ON) and is a Fellow of the Institute of Chartered Accountants of Ontario and the Institute of Corporate Directors.

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Name, Province (State) and Country of Residence(1) |  | Year first became Director |  | Principal Occupation
Timothy W. Faithfull Oxford, U.K. |  | 2003 |  | Corporate Director. Mr. Faithfull is a 36-year veteran of Royal Dutch/Shell plc (energy), where he held diverse international roles principally in oil products and LNG project development. As President and CEO of Shell Canada Limited, he was responsible for bringing the $6 billion Athabasca Oil Sands Project on line in 2003, the first fully integrated oil sands venture in 25 years. Mr. Faithfull has extensive experience with commodity exposure and risk management, the result of his time directing the global crude oil trading operations of Shell International Trading and Shipping Company from 1993 to 1996. He was Chairman and CEO of Shell Eastern Petroleum in Singapore from 1996 to 1999, including Shell’s main refinery and oil products trading for Asia Pacific. During his time in Singapore, he was a director of DBS Bank and the Port of Singapore Authority. He was a trustee of the main Singapore Arts/Theatre complex. In Calgary, he served on the board of the Calgary Health Trust and the Epcor Arts Centre. Mr. Faithfull is a director of AMEC plc and Canadian Natural Resources Limited. In the U.K., Mr. Faithfull is a director Shell Pension Trust Limited, where he chairs the Technical Committee. He is also a director of ICE Futures Europe. Mr. Faithfull is a trustee of both Starehe UK and Canada UK Colloquium, and a member of the remuneration committee of Keble College, Oxford, all non-public entities. He is a past director of Enerflex Systems Income Fund and Canadian Pacific Railway. At TransAlta, Mr. Faithfull is Chair of the Human Resources Committee of the Board. Mr. Faithfull holds a master of arts in philosophy, politics and economics from the University of Oxford, U.K. (Oxford, U.K.).

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Name, Province (State) and Country of Residence(1) |  | Year first became Director |  | Principal Occupation
Dawn L. Farrell Alberta, Canada |  | 2012 |  | President and Chief Executive Officer of TransAlta Corporation. Mrs. Farrell became President and CEO of TransAlta Corporation on January 2, 2012. Prior to her appointment, she served as Chief Operating Officer from 2009 to 2011 and as Executive Vice-President, Commercial Operations and Development from 2008 to 2009. Mrs. Farrell has over 25 years of experience in the electric energy industry, holding roles at TransAlta and BC Hydro. She has served as Executive Vice-President, Commercial Operations and Development; Executive Vice-President, Corporate Development; Executive Vice-President, Independent Power Projects; and Vice-President, Energy Marketing and IPP Development at TransAlta Corporation. From 2003 to 2006, Mrs. Farrell served as Executive Vice-President, Generation at BC Hydro. In 2006, she was appointed Executive Vice-President Engineering, Aboriginal Relations and Generation. Mrs. Farrell sits on the board of directors of the Calgary Stampede and The Conference Board of Canada. Her past boards include the Mount Royal College Board of Governors, Fording Coal Income Fund, New Relationship Trust Fund, Mount Royal College Foundation and Vision Quest Windelectric. She holds a bachelor of commerce degree with a major in finance and a master’s degree in economics from the University of Calgary (Calgary, AB). Mrs. Farrell has also attended the Advanced Management Program at Harvard University (Cambridge, MA).
Amb. Gordon D. Giffin(2) Georgia, U.S.A. |  | 2002 |  | Lawyer and Senior Partner, McKenna, Long & Aldridge LLP (law firm). Mr. Giffin is Senior Partner of the law firm of McKenna Long & Aldridge, where he maintains offices in Washington, D.C. and Atlanta. His practice focuses on international transactions related to trade, energy and public policy. He has been engaged in the practice of law or government service for more than thirty years. He served as the United States Ambassador to Canada with responsibility for managing Canada/U.S. bilateral relations, including energy and environmental policy from August 1997 to April 2001. Prior to that, he served as Chief Counsel and Legislative Director to United States Senator Sam Nunn, with responsibility for the legal and legislative operations of the office. Mr. Giffin is a director of Canadian Imperial Bank of Commerce, Canadian National Railway Company, Canadian Natural Resources Ltd. and Just Energy Group Inc. At TransAlta, Mr. Giffin is Chair of the Board. Mr. Giffin holds a bachelor of arts from Duke University (Durham, NC) and a juris doctorate from Emory University School of Law (Atlanta, GA).

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Name, Province (State) and Country of Residence(1) |  | Year first became Director |  | Principal Occupation
C. Kent Jespersen(3) Alberta, Canada |  | 2004 |  | Corporate Director. Mr. Jespersen has had a career and held executive positions in the oil and gas industry for over thirty years. He held senior executive positions with NOVA Corporation of Alberta, Foothills Pipe Lines Ltd. and Husky Oil Limited before assuming the presidency of Foothills Pipe Lines Ltd. and later, NOVA Gas International Ltd. (“NOVA”). At NOVA, he led the non-regulated energy services business (including energy trading and marketing) and all international activities. Mr. Jespersen is a director of Axia NetMedia Corporation, CanElson Drilling Inc., Rodinia Oil Corp., MatRRix Energy Technologies Inc. and PetroFrontier Corp. He is also the Chair and CEO of La Jolla Resources International Ltd. (advisory and investments). At TransAlta, Mr. Jespersen is a member of the Human Resources Committee. Mr. Jespersen holds a bachelor of science in education and a master of science in education from the University of Oregon (Eugene, OR).
Michael M. Kanovsky Alberta, Canada |  | 2004 |  | Corporate Director and Independent Businessman. Mr. Kanovsky is a professional engineer. He co-founded Northstar Energy Corporation (“Northstar”) with initial capital of $400,000 and helped build this entity into an oil and gas producer that was sold to Devon Energy Corporation for approximately $600 million in 1998. During this period, Mr. Kanovsky was responsible for strategy and finance as well as merger and acquisition activity. He initiated Northstar’s entry into electrical cogeneration through its wholly-owned power subsidiary, Powerlink Corporation (“Powerlink”). Powerlink developed one of the first independent power producer (IPP) gas-fired co-generation plants in Ontario and also internationally. In 1997, he founded Bonavista Energy Corporation (previously Bonavista Energy Trust), which has grown to a present day market capitalization of approximately $4.5 billion. Mr. Kanovsky is a director of Bonavista Energy Corporation, Devon Energy Corporation and Pure Technologies Inc. At TransAlta, Mr. Kanovsky is Chair of the Governance and Environment Committee and was a member of the Audit and Risk Committee during 2012. Mr. Kanovsky holds a bachelor of science in mechanical engineering from Queen’s University (Kingston, ON) as well as a master of business administration from the Richard Ivey School of Business at the University of Western Ontario (London, ON).

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Name, Province (State) and Country of Residence(1) |  | Year first became Director |  | Principal Occupation
Gordon S. Lackenbauer(4) Alberta, Canada |  | 2005 |  | Corporate Director. Mr. Lackenbauer has over thirty-five years of business and investment banking experience. He was Deputy Chairman of BMO Nesbitt Burns Inc. (investment banking) from 1990 to 2004. Prior to that, he was responsible for the principal activities of the firm, which included fixed income sales and trading, new issue underwriting, syndication and merger and acquisition advisory mandates. Mr. Lackenbauer has worked with many of Canada’s leading utilities and has frequently acted as an expert financial witness testifying on the cost of capital, appropriate capital structure, and the fair rate of return, principally before the Alberta Utilities Commission, the National Energy Board and the Ontario Energy Board. At TransAlta, Mr. Lackenbauer is a member of the Governance and Environment Committee and the Human Resources Committee of the Board. Mr. Lackenbauer holds a bachelor of arts in economics from Loyola College (Montréal, QC) as well as a master of business administration from the University of Western Ontario (London, ON). He is also a Chartered Financial Analyst.
Karen E. Maidment Ontario, Canada |  | 2010 |  | Corporate Director. Ms. Maidment is a seasoned senior executive. She was Chief Financial and Administrative Officer (“CFAO”) of BMO Financial Group (“BMO”) from 2007 to 2009. Prior to that, she was Senior Executive Vice-President and CFO from 2003 to 2007 and Executive Vice-President and CFO of BMO from 2000 to 2003. As CFO of BMO, she was responsible for all global finance operations, risk management, legal and compliance, mergers and acquisitions as well as communications. Prior to that, Ms. Maidment held several executive positions with Clarica Life Insurance Company from 1988 to 2000, including CFO. She also led the insurance industry group, working with government, to develop regulations and framework to convert Canada’s major insurers from mutual to public companies. Ms. Maidment is a director of TD Ameritrade Holding Corporation and The Toronto-Dominion Bank. Ms. Maidment is a past director of Harris Bank, BMO Nesbitt Burns, where she was also Chair of the Audit Committee, Bank of Montreal Pension Fund, Mutual Trustco, MCAP Financial and The Mutual Group (U.S.). She is a member of the Princess Margaret Hospital Foundation Board and serves on the University of Waterloo Board of Governors. At TransAlta, Ms. Maidment is a member of the Audit and Risk Committee and the Governance and Environment Committee of the Board. Ms. Maidment holds a bachelor of commerce from McMaster University (Hamilton, ON), is a Chartered Accountant and, in 2000, was named Fellow of the Institute of Chartered Accountants of Ontario. She was named CFO of the year in 2006 and in 2007 was inducted in Canada’s Most Powerful Women Hall of Fame.

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Name, Province (State) and Country of Residence(1) |  | Year first became Director |  | Principal Occupation
Yakout Mansour California, U.S.A. |  | 2011 |  | Corporate Director. Mr. Mansour has over 40 years of experience as both a professional engineer and executive in the electric utility business in Canada, the United States, and abroad. He retired as President and CEO of the California Independent System Operator Corporation (“CAISO”) in 2011, a position he had held since 2005. CAISO is responsible for operating and controlling 80% of the California electric grid, designing and operating the California electricity market, and for settlements of over $8 Billion annually. Under Mr. Mansour’s leadership CAISO established the market and technical foundation to accommodate one of the most aggressive renewable portfolio standards in the world. Prior to that, Mr. Mansour served in senior executive roles at BC Hydro and British Columbia Transmission Corporation where he was responsible for Operation, Asset Management, and Inter-utility Affairs of the electric grid. A Professional Engineer and a Fellow of the Institute of Electrical and Electronics Engineers, Mr. Mansour has authored and co-authored numerous publications. He is recognized internationally in the field of Power Engineering and received several distinguished awards for his contributions to the industry. In 2009, Mr. Mansour was named to the US Department of Energy Electricity Advisory Committee as a vice chair. He also served on the various committees of the North American Electric Reliability Corporation and its predecessor organization, CEGRE, the Transmission Council of the Canadian Electric Association, and the Board of Directors of the Electric Power Research Institute. At TransAlta, Mr. Mansour is a member of the Audit and Risk Committee of the Board and previously served on the Human Resources Committee. Mr. Mansour is a graduate of the University of Calgary (Calgary, AB) with a master of science and a graduate of the University of Alexandria (Alexandria, Egypt) with a bachelor of science in electrical engineering.

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Name, Province (State) and Country of Residence(1) |  | Year first became Director |  | Principal Occupation
Dr. Martha C. Piper British Columbia, Canada |  | 2006 |  | Corporate Director. Dr. Piper was President and Vice-Chancellor of the University of British Columbia (“UBC”) from 1997 to 2006 (education). Prior to her appointment at UBC, she served as Vice-President, Research at the University of Alberta. She served on the boards of the Alberta Research Council, the Conference Board of Canada and the Centre of Frontier Engineering Research. Dr. Piper was also appointed by the Prime Minister of Canada to the Advisory Council on Science and Technology and served as Chair of the Board of the National Institute for Nanotechnology. Dr. Piper is a member of the board of directors of Shoppers Drug Mart and Bank of Montreal. She is also a member of the Canadian delegation to the Trilateral Commission, an organization fostering closer cooperation among the core democratic industrialized areas of the world. She also sits on the boards of the Dalai Lama Centre for Peace & Education, CARE Canada and the Canadian Stem Cell Foundation, non-public entities. At TransAlta, Dr. Piper is a member of the Governance and Environment Committee and the Human Resources Committee of the Board. Dr. Piper holds a bachelor of science in physical therapy from the University of Michigan (Ann Arbor, MI), a master of arts in child development from the University of Connecticut (Storrs, CT), and a doctorate of philosophy in epidemiology and biostatistics from McGill University (Montréal, QC). She has also received honorary degrees from 18 international universities. Dr. Piper is an Officer of the Order of Canada and a recipient of the Order of British Columbia.

Notes:

(1) | The following nominee directors are Canadian residents: William D. Anderson, Dawn L. Farrell, C. Kent Jespersen, Michael M. Kanovsky, Gordon S. Lackenbauer, Karen E. Maidment and Martha C. Piper.
(2) | Mr. Giffin was a director of AbitibiBowater Inc. (“Abitibi”) from October 29, 2007 until his resignation on January 22, 2009. In April 2009, Abitibi and certain of its U.S. and Canadian subsidiaries filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware for relief under the provisions of Chapter 11 and Chapter 15 of the United States Bankruptcy Code, as amended, and sought creditor protection under the Companies’ Creditors Arrangement Act (Canada) (the “CCAA”) with the Superior Court of Québec in Canada. On September 14, 2010, Abitibi announced that it had received approval for its plan of reorganization from unsecured creditors under the CCAA in Canada. On September 21, 2010, Abitibi announced it had received the necessary creditor approval for its plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code. On December 9, 2010, Abitibi announced that it had successfully completed its reorganization and emerged from creditor protection under the CCAA in Canada and Chapter 11 of the U.S. Bankruptcy Code.
(3) | Mr. Jespersen resigned from the Board of Directors of CCR Technologies Ltd. (“CCR”) in February 2010. CCR filed with the Court of Queen’s Bench of Alberta a proposal dated December 1, 2010 pursuant to provisions of Part III Division I of the Bankruptcy and Insolvency Act to restructure and reorganize the financial affairs of CCR, to compromise the claims of the unsecured creditors, restructure the shares of CCR, and to allow it to conduct a restructuring and “rightsizing” of its operations on a going concern basis. This proposal was approved by the unsecured creditors on December 22, 2010 and by the Court on January 13, 2011. The Alberta Securities Commission issued a variation order dated February 14, 2011 to partially revoke its cease trade order to permit the implementation of the proposal which was subsequently implemented.
(4) | Mr. Lackenbauer resigned from the Board of Directors of Tembec Inc. (“Tembec”) on August 2, 2007. On December 19, 2007, Tembec announced its proposed recapitalization transaction providing a consensual solution to both noteholders and shareholders. On February 22, 2008, Tembec announced that it had received the approval of the majority of shareholders and the requisite majority of noteholders of Tembec Industries Inc. On February 27, 2008, Tembec announced that it had received approval from the Ontario Superior Court of Justice (Commercial List) with respect to their plan of arrangement relating to the proposed recapitalization transaction. On October 31, 2008, Tembec announced that it had successfully obtained a final American court order recognizing its Canadian plan of arrangement as a foreign proceeding in the United States.

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Officers

The name, province or state and country of residence of each of our officers as at February 28, 2013, their respective position and office and their respective principal occupation during the five preceding years, are set out below.

Name |  | Principal Occupation |  | Residence
Dawn L. Farrell |  | President and Chief Executive Officer |  | Alberta, Canada
Robert (Bob) Emmott |  | Chief Engineer |  | Alberta, Canada
Brett M. Gellner |  | Chief Financial Officer |  | Alberta, Canada
Cynthia Johnston |  | Executive Vice-President, Corporate Services |  | Alberta, Canada
David J. Koch |  | Vice-President, Controller |  | Alberta, Canada
John H. Kousinioris |  | Chief Legal and Compliance Officer |  | Alberta, Canada
Dawn E. de Lima |  | Chief Human Resources and Communications Officer |  | Alberta, Canada
Maryse C.C. St.-Laurent |  | Vice-President and Corporate Secretary |  | Alberta, Canada
Robert L. Schaefer |  | Executive Vice-President, Corporate Development |  | Alberta, Canada
J. W. Hugo Shaw |  | Executive Vice-President, Operations |  | Alberta, Canada
Todd J. Stack |  | Vice-President and Treasurer |  | Alberta, Canada
Kenneth S. Stickland |  | Chief Business Development Officer |  | Alberta, Canada
Paul H. E. Taylor |  | President, U.S. Operations |  | Olympia, WA, U.S.A.

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

· | Prior to January 2012, Mrs. Farrell served as Chief Operations Officer from 2009 to 2011. Prior to April 2009, she was Executive Vice-President, Commercial Operations and Development of the Corporation. Prior to July 2007, she was Executive Vice-President Engineering, Aboriginal Relations and Generation at BC Hydro.
· | Prior to October 2010, Mr. Emmott was Vice-President and Chief Engineer. Prior to February 2009, he was Director, Technical Services and prior to 2008 he was Manager, Technical Services.
· | Prior to June 2010, Mr. Gellner was Vice-President, Commercial Operations of the Corporation. Prior to July 2008, he was Co-Head and Managing Director, Investment Banking at CIBC World Markets Inc.
· | Prior to September 2011, Ms. Johnston was Vice-President, Renewable Operations. Prior to December 2009, she was Vice-President Regulatory and Legal with FortisAlberta Inc. from June 2004.
· | Prior to May 2011, Mr. Koch was Vice-President, Operations Finance. Prior to November 2010, he was Vice-President, Financial Operations.
· | Prior to December 2012, Mr. Kousinioris was a Partner and co-head of the Corporate Commercial Group at Bennett Jones LLP, Barristers and Solicitors.
· | Prior to April 2012, Ms. de Lima was Chief Human Resources Officer and Executive Vice-President, Communications. Prior to September 2011, Ms. de Lima was Chief Human Resources Officer. Prior to March 2011, she was Vice-President Supply Chain Management and prior to May 2009 she was Vice-President, Corporate HR from November 2007.
· | Prior to December 2008, Ms. St.-Laurent was Corporate Secretary of TransAlta.

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· | Prior to October 2011, Mr. Schaefer was Vice-President, Commercial Operations and Development. Prior to June 2010, he was Vice-President, Development. Prior to June 2008, he was Chief Financial Officer at Resin Systems Inc. from August 2005.
· | Prior to October 2011, Mr. Shaw was Vice-President, Coal Operations and Engineering Services. Prior to April 2011, he was Vice-President, Engineering, Environment and Construction. Prior to April 2009, he was Vice-President, Maintenance and Field Engineering & PMO from July 2008.
· | Prior to November 2012, Mr. Stack was Treasurer. Prior to May 2011, Mr. Stack was Assistant Treasurer. Prior to October 2010, he was Director, Treasury Operations. Prior to January 2008, he was Manager, Financial Risk.
· | Prior to December 2012, Mr. Stickland was Chief Legal and Business Development Officer and prior to September 2011 he was Chief Legal Officer. Prior to April 2009, he was Executive Vice-President, Legal, SD and EH&S. Prior to April 2007, he was Executive Vice-President, Legal.
· | Prior to September 2011, Mr. Taylor was Leader, Western Growth Strategy. Prior to April 2011, he was Chief of Staff at the Office of the Premier, Government of BC. Prior to June 2010, he was President, CEO and Director of Naikun Wind Energy Group Inc. Prior to September 2008, he was President and Director of Naikun Wind Energy Group Inc. Prior to May 2008, he was President and CEO of Insurance Corporation of British Columbia from October 2004.

As of February 28, 2013, the directors and executive officers of TransAlta, as a group, beneficially owned, directly or indirectly, or exercised control or direction over an aggregate of 309,762 of our common shares. This constitutes less than one per cent of our outstanding common shares.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director or executive officer of TransAlta, no person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over more than ten per cent of our common shares, and no associate or affiliate of any of them, has or has had any material interest, direct or indirect, in any transaction involving TransAlta within the three most recently completed financial years or to date in 2013 or in any proposed transactions that has materially affected or will materially affect us.

INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS

Since January 1, 2012, there has been no indebtedness outstanding to TransAlta from any of our directors, executive officers, senior officers or associates of any such directors, nominees or senior officers.

CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS

Corporate Cease Trade Orders

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

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

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

Personal Bankruptcies

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

Penalties or Sanctions

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

(iv) | been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, other than penalties for late filing of insider reports; or
(v) | been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

CONFLICTS OF INTEREST

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

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

TransAlta is occasionally named as a party in claims and legal proceedings which arise during the normal course of its business. We review each of these claims, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in our favour or that such claim may not have a material adverse effect on TransAlta. For further information, please refer to Notes 36 and 39 of our audited consolidated financial statements for the year ended December 31, 2012 which financial statements are incorporated by reference herein. See “Documents Incorporated by Reference” herein.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common shares and Series A, Series C and Series E First Preferred Shares is CIBC Mellon Trust Company. Common shares are transferable in Vancouver, Calgary, Toronto, Montréal, and Halifax. Series A, Series C and Series E First Preferred Shares are transferable in Calgary and Toronto. On November 1, 2010, CIBC Mellon sold its issuer services business to Canadian Stock Transfer Company Inc. which is currently operating the stock transfer business in the name of CIBC Mellon Trust Company during a transition period. The transfer agent and registrar for our common shares in the United States is Computershare at its principal office in Jersey City, New Jersey.

INTERESTS OF EXPERTS

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

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

ADDITIONAL INFORMATION

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

Additional information including directors’ and officers’ remuneration and indebtedness, principal holders of our securities and securities authorized for issuance under equity compensation plans (all where applicable), is contained in our Management Proxy Circular for the most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request to our Investor Relations department, or as filed on SEDAR at www.sedar.com.

Additional financial information is provided in our audited consolidated financial statements as at and for the year ended December 31, 2012 and in the related Annual MD&A, each of which is incorporated by reference in this AIF. See “Documents Incorporated by Reference” herein.

AUDIT AND RISK COMMITTEE

General

The members of TransAlta’s ARC satisfy the requirements for independence under the provisions of Canadian Securities Regulators, Multilateral Instrument 52-110 Audit Committees, Section 303A of the New York Stock Exchange Rules and Rule 10A-3 under the U.S. Securities and Exchange Act of 1934. The ARC’s Charter requires that it be comprised of a minimum of three independent directors. During 2012, the ARC comprised four independent members, William D. Anderson (Chair), Michael M. Kanovsky, Karen E. Maidment and Yakout Mansour. Mr. Stephen L. Baum was a member of the ARC until May 22, 2012 at which time he resigned from the Board for personal reasons. Mr. Michael Kanovsky, who had previously served on the ARC, was appointed on May 29, 2012 to the committee to fill the vacancy on a temporary basis. As the Board has determined to nominate an additional director for election at its upcoming Annual and Special meeting of Shareholders on April 23, 2013, Mr. Kanovsky resigned as a member of the ARC on February 26, 2013.

All members of the committee are financially literate pursuant to both Canadian and U.S. securities requirements and each of Mr. William D. Anderson, Ms. Karen E. Maidment and Mr. Yakout Mansour have been determined by the Board to be an “audit committee financial expert”, within the meaning of Section 407 of the United States Sarbanes Oxley Act of 2002 (“Sarbanes Oxley Act”).

Mandate of the Audit and Risk Committee

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

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

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

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

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

Audit and Risk Committee Charter

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

Relevant Education and Experience of Audit and Risk Committee Members

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

Name of ARC Member |  | Relevant Education and Experience
W. D. Anderson |  | Mr. Anderson is a Chartered Accountant, with 17 years experience with a major Chartered Accountant firm in Canada. Mr. Anderson has served as CEO of a public company and as CFO of several public companies. In such capacities, Mr. Anderson actively supervised persons engaged in preparing, auditing, analyzing or evaluating financial statements. Mr. Anderson has also served as a principal financial officer and accounting officer and as a director and audit committee chair and member of several public companies. He has served on the board and audit committee of a public company that reports under U.S. GAAP.
M. M. Kanovsky |  | Mr. Kanovsky has over thirty years of financial and industry experience gained through working in the investment banking business as well as a director, officer and audit committee member of several public companies and trusts. Mr. Kanovsky is a graduate of the MBA program from the Richard Ivey School of Business at the University of Western Ontario.
K. E. Maidment |  | Ms. Maidment is a Chartered Accountant. Ms. Maidment has served as a CFO with financial oversight responsibilities for TSX and NYSE listed public companies for over 15 years. She has also held positions where she was responsible for global finance operations, risk management, legal and compliance, communications and mergers and acquisitions. In addition, Ms. Maidment has worked with government bodies in order to develop regulations and frameworks for the conversion of major insurers from mutual to public companies. Ms. Maidment holds a bachelor of commerce from McMaster University, and in 2000 was named a Fellow of the Institute of Chartered Accountants of Ontario.

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Name of ARC Member |  | Relevant Education and Experience
Y. Mansour |  | Mr. Mansour has over forty years of experience as an executive in the electric utility business. He served as President and CEO of the California Independent System Operation Corporation and was a senior executive at BC Hydro and the British Columbia Transmission Corporation. Mr. Mansour has supervised and dealt with financial reporting and internal control.

Other Board Committees

In addition to the ARC, TransAlta has two other standing committees: the Governance and Environment Committee and the Human Resources Committee. The members of these committees as of December 31, 2012 are:

Governance and Environment Committee |  | Human Resources Committee
Chair: Michael M. Kanovsky |  | Chair: Timothy W. Faithfull
Gordon S. Lackenbauer |  | C. Kent Jespersen
Karen E. Maidment |  | Gordon S. Lackenbauer
Martha C. Piper |  | Martha C. Piper

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

Fees Paid to Ernst & Young LLP

For the years ended December 31, 2012 and December 31, 2011, Ernst & Young LLP and its affiliates were paid $3,459,937 and $3,110,078 respectively, as detailed below:

Ernst & Young LLP

Year Ended Dec. 31 |  | 2012 |  | 2011 |
Audit Fees |  | $ | 2,998,892 |  | $ | 2,725,847 |
Audit-related fees |  | 388,595 |  | 384,231 |
Tax fees |  | 72,450 |  | 0 |
All other fees |  | 0 |  | 0 |
Total |  | $ | 3,459,937 |  | $ | 3,110,078 |

No other audit firms provided audit services in 2012 or 2011.

The nature of each category of fees is described below:

Audit Fees

Audit fees were paid for professional services rendered by the auditors for the audit of our annual financial statements or services provided in connection with statutory and regulatory filings or engagements, including the translation from English to French of our financial statements and other documents. Total audit fees for 2012 include payments related to 2011 in the amount of $1,397,001. Total audit fees for 2011 include payments related to 2010 in the amount of $894,776.

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Audit-Related Fees

The audit-related fees in 2012 were primarily for work performed by Ernst & Young LLP in relation to compliance and regulatory reporting, common share issuances, debt issuances and miscellaneous accounting advice provided to the Corporation. The audit-related fees in 2011 were primarily in relation to preferred share issuances, Canadian and US shelf work, the 2010 Sustainability Report review, and miscellaneous accounting advice provided to the Corporation.

Tax Fees

The tax fees for 2012 relate to various tax related matters in our domestic and foreign operations.

All Other Fees

Nil.

Pre-Approval Policies and Procedures

The ARC has considered whether the provision of services other than audit services is compatible with maintaining the auditors’ independence. In May 2002, the ARC adopted a policy (the “Policy”) that prohibits TransAlta from engaging the auditors for “prohibited” categories of non-audit services and requires pre-approval of the ARC for other permissible categories of non-audit services, such categories being determined under the Sarbanes-Oxley Act. The Policy also provides that the Chair of the ARC may approve permissible non-audit services during the quarter and report such approval to the ARC at its next regularly scheduled meeting. In 2009, the ARC granted management the authority to approve de minimus permissible non-audit services (which are in the aggregate the lesser of five per cent of the total fees paid to the external auditors or $125,000) provided such services are reported to the ARC at its next scheduled meeting.

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APPENDIX “A”

AUDIT AND RISK COMMITTEE CHARTER

TRANSALTA CORPORATION

(the “Corporation”)

A. Establishment of Committee and Procedures

1. Composition of Committee

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

2. Appointment of Committee Members

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

3. Vacancies

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

4. Committee Chair

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

5. Absence of Committee Chair

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

6. Secretary of Committee

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

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7. Meetings

The Chair of the Committee may call a meeting of the Committee. The Committee shall meet at least quarterly and at such other time during each year as it deems appropriate. In addition, the Chair of the Committee or any two members may call a special meeting of the Committee at any time. Although the Corporation’s Chief Executive Officer (“the CEO”) may attend meetings of the Committee, the Committee shall also meet in separate executive sessions.

8. Quorum

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

9. Notice of Meetings

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

10. Attendance at Meetings

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

11. Procedure, Records and Reporting

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

12. Review of Charter and Evaluation of Committee

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

13. Outside Experts and Advisors

The Committee Chair, on behalf of the Committee, or any of its members is authorized, at the expense of the Corporation, when deemed necessary or desirable, to retain independent counsel, outside experts and other advisors to advise the Committee independently on any matter. The retention of such counsel, expert or advisor in no way requires the Committee to act in accordance with the recommendations of such counsel, expert or advisor.

B. Duties and Responsibilities of the Chair

The fundamental responsibility of the Chair of the Committee is to effectively manage the duties of the Committee.

The Chair is responsible for:

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1. Ensuring that the Committee is properly organized so that it functions effectively and meets its obligations and responsibilities.

2. Establishing the frequency of Committee meetings, duly convening the same and confirming that quorum is present when required.

3. Working with Management on the development of agendas and related materials for the meetings.

4. Making suggestions and providing feedback to management regarding information that is or should be provided to the Committee to permit it to properly make decisions when decisions are required.

5. Providing leadership to the Committee and assisting the Committee in reviewing and monitoring its responsibilities.

6. Reporting to the Board on the recommendations and decisions of the Committee.

7. Chair meetings of the Committee.

C. Mandate of the Committee

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

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

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

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

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

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D. Duties and Responsibilities of the Committee

1. Audit and Financial Matters

A) Duties and Responsibilities Related to the External Auditors Qualifications

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

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

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

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

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

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

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

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

B) Duties and Responsibilities Related to Financial Reporting and the Audit Process

(a) Subject to the delegation granted to the Chair of the Committee, pre-approve all audit related services including all non-prohibited non-audit services provided by the external auditors; the Chair of the Committee, is authorized to approve all audit related services

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including non-prohibited non-audit services provided by the external auditors, and shall report all such approvals to the Committee at its next scheduled meeting;

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

(c) Review with management and the external auditors all financial statements and financial disclosure;

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

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

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

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

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

(vi) review with management and the external auditors any changes in accounting principles, practices or policies considering their applicability to the business and financial impact;

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

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

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

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

(f) Review quarterly with senior management and the Chief Legal Officer, and as necessary, outside legal advisors, and the Corporation’s internal and external auditors, the

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effectiveness of the Corporation’s internal controls to ensure the Corporation is in compliance with legal and regulatory requirements and with the Corporation’s policies;

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

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

C) Duties and Responsibilities Related to Financial Planning

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

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

(c) Receive regular updates with respect to the Corporation’s financial obligations, loans, credit facilities, credit position and financial liquidity.

2. Governance

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

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

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

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

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

(f) Review annually the Insider Trading Policy and approve changes as required;

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(g) Review annually the Corporation’s Disclosure Policy and Social Media Policy to ensure continued applicability with the law and the Corporation’s disclosure principles;

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

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

(j) Review at least bi-annually the status of the Corporation’s core IT operating systems;

(k) Review annually the Corporation’s cyber security programs and their effectiveness. Receive an update on the Corporation’s compliance program for cyber threats and security.

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

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

(n) Establish procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal and disclosure controls or auditing matters and the confidential, anonymous submission by employees, contractors, shareholders and other stakeholders of concerns regarding accounting, auditing, ethical or legal violations;

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

(p) Initiate investigations of complaints or allegations as necessary, report to the Board thereon and ensure that appropriate action is taken as necessary to address the matter;

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

(r) Report annually to shareholders on the work of the Committee during the year.

3. Internal Audit

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

(b) Review annually the internal audit department’s charter, the scope and plans for the work of the internal audit group, the adequacy of the group’s resources, the internal auditors’ access to the Corporation’s records, property and personnel;

(c) Recognize and advise senior management that the internal auditors shall have unfettered access to the Committee, as well as the Committee to the internal auditors;

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

(e) Review with the Corporation’s senior financial management and the Director, Internal Audit the adequacy of the Corporation’s systems of internal control and procedures; and

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

4. Risk Management

The Board is responsible for ensuring that the Corporation has adopted processes and key policies for the identification, assessment and management of its principal risks. The Board has delegated to the Committee the responsibility for the oversight of management’s identification of the Corporation’s principal risks, the evaluation of such risks and the implementation of appropriate policies, processes and systems to manage or mitigate the risks within the Corporation’s risk appetite. The Committee reports to the Board thereon.

The Committee shall:

(a) Review, at least quarterly, management’s assessment of the Corporation’s principal risks; discuss with management the processes for the identification of these risks and the efficacy of the policies and procedures for mitigating and/or addressing these risks;

(b) Receive and review managements’ quarterly risk update including an update on residual risks;

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

(d) Review annually the Corporation’s Financial and Commodity Exposure Management Policies and approve changes to such policies;

(e) Review and approve the Corporation’s strategic hedging program, guidelines and risk tolerance;

(f) Review and monitor quarterly results of financial and commodity exposure management activities, including foreign currency and interest rate risk strategies, counterparty credit exposure and the use of derivative instruments;

(g) Review the Corporation’s annual insurance program, including the risk retention philosophy, potential exposure and corporate liability protection programs;

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

(i) Annually, together with management, report and obtain the Board’s approval with respect to:

(i) the Corporation’s principal risks and overall risk appetite/profile;

(ii) the Corporation’s strategies in addressing its risk profile;

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

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

E. Compliance and Powers of the Committee

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

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

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APPENDIX “B”

GLOSSARY OF TERMS

This Annual Information Form includes the following defined terms:

Air Emissions – Substances released to the atmosphere through industrial operations. For the fossil-fuel-fired power sector, the most common air emissions are sulphur dioxide, oxides of nitrogen, mercury, and greenhouse gases.

Power Purchase Arrangement (PPA) – A long-term arrangement established by regulation for the sale of electric energy from formerly regulated generating units to PPA Buyers.

Availability – A measure of time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year, that a generating unit is capable of generating electricity, regardless of whether or not it is actually generating electricity.

Boiler – A device for generating steam for power, processing or heating purposes, or for producing hot water for heating purposes or hot water supply. Heat from an external combustion source is transmitted to a fluid contained within the tubes of the boiler shell.

Capacity – The rated continuous load-carrying ability, expressed in megawatts, of generation equipment.

Carbon Capture and Storage (CCS) – An approach to mitigating the contribution of greenhouse gas emissions to global warming, which is based on capturing carbon dioxide emissions from industrial operations and permanently storing them in deep underground formations.

Cogeneration – A generating facility that produces electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, heating, or cooling purposes.

Combined-Cycle – An electric generating technology in which electricity is produced from otherwise lost waste heat exiting from one or more gas (combustion) turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for use by a steam turbine in the production of electricity. This process increases the efficiency of the electric generating unit.

Derate – To lower the rated electrical capability of a power generating facility or unit.

Dividend – Refers to a cash dividend declared payable by TransAlta on the outstanding Shares.

EcoPower® - Is a registered trademark which provides assurance that the products and services bearing the logo meet environmental standards supported through the Federal Government’s EcoENERGY for Renewable Power Program.

eERP – ecoEnergy for Renewable Power program, a program established by the Federal Government.

Force Majeure – Literally means “greater force”. These clauses excuse a party from liability if some unforeseen event beyond the control of that party prevents it from performing its obligations under the contract.

Geothermal Plant – A plant in which the prime mover is a steam turbine. The turbine is driven either by steam produced from hot water or by natural steam that derives its energy from heat found in rocks or fluids at various depths beneath the surface of the earth. The energy is extracted by drilling and/or pumping.

Gigawatt – A measure of electric power equal to 1,000 megawatts.

Gigawatt hour (GWh) – A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.

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Global Adjustment - is the difference between the total payments made to certain contracted or regulated generators/demand management projects, and market revenues and is calculated each month. The adjustment is determined by the Ontario Independent Electricity System Operator

Greenhouse Gas (GHG) – Gases having potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons.

Kilowatt (kW) – A measure of electric power equal to 1,000 watts.

Kilowatt hour (kWh) – A measure of electricity consumption equivalent to the use of 1,000 watts of power over a period of one hour.

Megawatt (MW) – A measure of electric power equal to 1,000,000 watts.

Megawatt hour (MWh) – A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.

Net Maximum Capacity (NMC) – The maximum capacity or effective rating, modified for ambient limitations, that a generating unit or power plant can sustain over a specific period, less the capacity used to supply the demand of station service or auxiliary needs.

Supercritical Technology – The most advanced coal-combustion technology in Canada employing a supercritical boiler, high-efficiency multi-stage turbine, flue gas desulphurization unit (scrubber), bag house, and low nitrogen oxide burners.

Uprate – To increase the rated electrical capability of a power generating facility or unit.

Value at Risk (VaR) – A measure to manage earnings exposure from energy trading activities.

WPPI – Wind Power Production Incentive payments from the Federal Government.

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