EX-13.1 2 a17-7040_1ex13d1.htm EX-13.1

Exhibit 13.1

TRANSALTA CORPORATION

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2016

March 2, 2017

TABLE OF CONTENTS

PRESENTATION OF INFORMATION | 2
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS | 2
DOCUMENTS INCORPORATED BY REFERENCE | 3
CORPORATE STRUCTURE | 3
OVERVIEW | 5
GENERAL DEVELOPMENT OF THE BUSINESS | 6
BUSINESS OF TRANSALTA | 14
CANADIAN COAL BUSINESS SEGMENT | 14
CANADIAN GAS BUSINESS SEGMENT | 15
AUSTRALIAN GAS BUSINESS SEGMENT | 17
HYDRO BUSINESS SEGMENT | 18
WIND AND SOLAR BUSINESS SEGMENT | 21
U.S. COAL BUSINESS SEGMENT | 24
ENERGY MARKETING SEGMENT | 26
CORPORATE SEGMENT | 26
NON-CONTROLLING INTERESTS | 26
PPAS | 27
COMPETITIVE ENVIRONMENT | 29
REGULATORY FRAMEWORK | 31
COMPETITIVE STRENGTHS | 32
ENVIRONMENTAL RISK MANAGEMENT | 33
ONGOING AND RECENTLY PASSED ENVIRONMENTAL LEGISLATION | 33
TRANSALTA ACTIVITIES | 36
RISK FACTORS | 38
EMPLOYEES | 51
CAPITAL STRUCTURE | 51
COMMON SHARES | 51
FIRST PREFERRED SHARES | 51
CREDIT RATINGS | 58
DIVIDENDS | 61
COMMON SHARES | 61
PREFERRED SHARES | 62
MARKET FOR SECURITIES | 64
COMMON SHARES | 64
PREFERRED SHARES | 65
DIRECTORS AND OFFICERS | 70
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS | 80
INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS | 80
CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS | 80
CONFLICTS OF INTEREST | 81
LEGAL PROCEEDINGS AND REGULATORY ACTIONS | 81
TRANSFER AGENT AND REGISTRAR | 81
INTERESTS OF EXPERTS | 81
ADDITIONAL INFORMATION | 81
AUDIT AND RISK COMMITTEE | 82
AUDIT AND RISK COMMITTEE CHARTER | A-1
GLOSSARY OF TERMS | B-1

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, 2016. 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, including TransAlta Renewables Inc., on a consolidated basis. Reference to “TransAlta Corporation” herein refers to TransAlta Corporation, excluding its subsidiaries. Capitalized terms not defined in the body of this AIF shall have their respective meanings set forth in Appendix “B” – Glossary of Terms hereto.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Information Form, the documents incorporated herein by reference, and other reports and filings of the Corporation made with the securities regulatory authorities, include forward-looking statements. All forward-looking statements are based on assumptions relating to 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”, “could”, “would”, “shall”, “believe”, “expect”, “estimate”, “anticipate”, “intend”, “plan”, “forecast” “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 our business and anticipated future financial performance; our success in executing on our growth projects; the timing and the completion of growth projects, including major projects such as the South Hedland Power Project and the Brazeau Pumped Storage Project 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 conversion of our coal fired units to natural gas; the impact of certain hedges on future earnings and cash flows; 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; the impact of load growth, increased capacity, and natural gas costs on power prices; expectations in respect of generation availability, capacity, and production; expectations regarding the role different energy sources will play in meeting future energy needs; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation, including the change to a capacity market in Alberta and the continued implementation of the Alberta Climate Leadership Plan, and their expected impact on us and the timing of the implementation of such regimes and regulations, as well as the cost of complying with resulting regulations and laws; the expected settlement of regulatory investigations and disputes; our trading strategy and the risks involved in these strategies; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; accounting estimates; anticipated growth rates in our markets; our expectations relating to the outcome of existing or potential legal and contractual claims, regulatory investigations, and disputes; expectations regarding the renewal of collective bargaining agreements; 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. and other currencies in locations where we do business; the monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment and growing scrutiny by investors relating to sustainability performance; our credit practices; and the estimated contribution of the Energy Marketing business segment to gross margin.

Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in demand, market prices and the availability of fuel supplies required to generate electricity; demand for electricity and 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 and man-made disasters; the threat of domestic terrorism and cyberattacks; equipment failure

and our ability to carry out or have completed the repairs in a cost-effective manner or timely manner; commodity risk management; 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, regulatory, and contractual proceedings involving the Corporation; outcomes of investigations and disputes; reliance on key personnel; labour relations matters; and development projects and acquisitions, including delays in the construction and commissioning of the South Hedland Power Project. 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, 2016 (the “Annual MD&A”).

Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this document are made only as of the date hereof and 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, 2016 and related annual management’s discussion and analysis are hereby specifically incorporated by reference in this AIF. Copies of these documents are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

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, 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 provisions of the CBCA.

On November 4, 2009, TransAlta completed its acquisition of Canadian Hydro Developers, Inc.

On December 7, 2010, TransAlta amended its articles to create the Series A Shares and Series B Shares; again on November 23, 2011 to create the Series C Shares and Series D Shares; again on August 3, 2012 to create the Series E Shares and Series F Shares; and then again on August 13, 2014 to create the Series G Shares and Series H Shares.

-3-

In August 2013, TransAlta Renewables Inc. (“TransAlta Renewables”) completed its initial public offering. In connection with the offering, TransAlta Corporation transferred to TransAlta Renewables certain wind and hydro power generation assets previously held directly or indirectly by TransAlta Corporation. TransAlta Corporation provides all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets. As of the date of this Annual Information Form, TransAlta Corporation owned, directly and indirectly, approximately 64 per cent of the outstanding voting equity in TransAlta Renewables.

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

As at the date of this AIF, the principal subsidiaries of TransAlta Corporation and their respective jurisdictions of formation are set out below(1):

Notes:

(1) | Unless otherwise stated, ownership is 100 per cent.
(2) | We own, directly and indirectly, an aggregate interest of approximately 64 per cent of TransAlta Renewables (including Class B share ownership), which includes 39.8 per cent through direct ownership and 24.2 per cent through TransAlta Generation Partnership. The remaining 36 per cent interest in TransAlta Renewables is publicly owned.
(3) | The remaining 1.56% of TA Energy Inc. is indirectly owned by TransAlta through its holding in Kenwind Energy Inc. (Canada).

-4-

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 8,716 megawatts (“MW”) of generating capacity(1)(2). We operate facilities having approximately 10,202 MW of aggregate generating capacity. In addition, we are in the process of constructing a 150 MW combined cycle power station near South Hedland, Western Australia which output is included in the numbers above. We are focused on generating and marketing electricity in Canada, the United States and Western Australia through our diversified portfolio of facilities fuelled by coal, natural gas, diesel, hydro, wind and solar.

The Canadian Coal segment has a net ownership interest of approximately 3,593 MW of electrical generating capacity. All of the facilities in this segment are located in Alberta.

The U.S. Coal segment holds our Centralia thermal plant, which represents a net ownership interest of 1,340 MW of electrical generating capacity.

The Hydro segment has a net ownership interest of approximately 926 MW of electrical generating capacity. The facilities that comprise this segment are predominantly located in Alberta, B.C., and Ontario.

The Wind and Solar segment has a net ownership interest of approximately 1,384 MW of electrical generating capacity and includes facilities located in Alberta, Ontario, New Brunswick, Quebec, Wyoming, Massachusetts, and Minnesota.

The Canadian Gas segment has a net ownership interest of approximately 898 MW of electrical generating capacity and includes facilities held in Alberta and Ontario.

The Australian Gas segment has a net ownership interest of approximately 575 MW of electrical generating capacity including our 150 MW South Hedland gas plant which is currently being constructed.

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 solar fuelled facilities.

In August, 2013, TransAlta Renewables completed its initial public offering of its common shares. TransAlta Corporation is the majority owner of TransAlta Renewables, with an approximate 64 per cent direct and indirect ownership interest as of the date of this Annual Information Form. TransAlta Renewables is one of the largest generators of wind power and among the largest publicly traded renewable power generation companies in Canada.

(1) The net ownership interest of 8,716 MW includes 100 per cent of the generating capacity of TransAlta Renewables. All references to “net ownership interest” in this Annual Information Form include 100 per cent of the generating capacity of TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns an approximate 64 per cent direct and indirect ownership interest in TransAlta Renewables.

(2) MW information provided as of December 31, 2016.

-5-

TransAlta’s Map of Operations

The following map outlines TransAlta’s operations as of December 31, 2016.

GENERAL DEVELOPMENT OF THE BUSINESS

TransAlta is organized into eight business segments: Canadian Coal, U.S. Coal, Canadian Gas, Australian Gas, Wind and Solar, Hydro, Energy Marketing and Corporate. The Canadian Coal, U.S. Coal, Canadian Gas, Australian Gas, Wind and Solar, and Hydro segments are responsible for constructing, operating and maintaining our electrical generation. The Canadian Coal segment is also responsible for the operation and maintenance of our related mining operations in Canada. The Energy Marketing segment is responsible for marketing our production through short-term and long-term contracts, for securing cost effective and reliable fuel supply, and for maximizing margins by optimizing our assets as market conditions change. In addition to serving our assets, our marketing team actively markets energy products and services to energy producers and customers. This segment also encompasses the management of available generating capacity as well as the fuel and transmission needs of the generation businesses. All the segments are supported by a Corporate segment which includes the Corporation’s central financial, legal, administrative, and investing functions.

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.

-6-

Recent Developments

2017

Sale of Interest in Wintering Hills Facility

On January 26, 2017, we announced the sale of our 51 per cent interest in the Wintering Hills merchant wind facility for approximately $61 million. Proceeds from the sale will be used for general corporate purposes, including to reduce debt and to fund future renewables growth, including potential contracted renewable opportunities in Alberta. The transaction closed on March 1, 2017.

Generation and Business Development

2016

Mississauga Recontracting

On December 22, 2016, we signed a Non-Utility Generator (NUG) Enhanced Dispatch Contract (the “NUG Contract”) with the Ontario Independent Electricity System Operator (“IESO”) for our Mississauga Cogeneration Facility (the “Mississauga Facility”). The NUG Contract came into effect on January 1, 2017. In conjunction with the execution of the NUG Contract, we terminated, effective December 31, 2016, the Mississauga Facility’s existing contract with the Ontario Electricity Financial Corporation (“OEFC”), which would have otherwise terminated in December 2018.

TransAlta Reaches Agreement with the Government of Alberta

On November 24, 2016, we entered into an agreement (the “Off-Coal Agreement”) with the Government of Alberta on transition payments for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before December 31, 2030. Under the terms of the Off-Coal Agreement, we will receive annual cash payments of approximately $37.4 million, net to the Corporation, commencing in 2017 and terminating in 2030. Receipt of the payments is subject to terms and conditions including the cessation of all coal-fired emissions in 2030. Other conditions include maintaining prescribed spending on investment and investment related activities in Alberta, maintaining a significant business presence in Alberta (including through the maintenance of prescribed employment levels), maintaining spending on programs and initiatives to support the communities surrounding the plants and the employees of the Corporation negatively impacted by the phase-out of coal generation, and the fulfillment of all obligations to affected employees. The affected plants are not, however, precluded from generating electricity at any time by any method other than the combustion of coal.

Additionally, we announced that we reached an understanding with the Government of Alberta pursuant to a Memorandum of Understanding to collaborate and cooperate in the development of a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation, facilitate existing and new renewable electricity development through supportive and enabling policy, and ensure existing generation and new electricity generation are able to effectively participate in the recently announced capacity market to be developed for the Province of Alberta.

Favourable Keephills 1 Force Majeure Ruling

On November 18, 2016, an independent arbitration panel confirmed that we were entitled to force majeure relief for the 2013 Keephills 1 forced outage. Our 395 MW Keephills 1 facility tripped off-line on March 5, 2013 due to a suspected winding failure within the generator. After extensive testing and analysis, it was determined a full rewind of the generator stator was required. The unit returned to service on October 6, 2013.

Decommissioning of Cowley Ridge

In February 2016, Cowley Ridge reached the end of its operating life and was decommissioned. Cowley Ridge, which began operating in 1993, was the first and oldest wind facility in Canada. Cowley Ridge had maximum capacity of 16 MW of renewable energy at its time of decommissioning.

-7-

2015

Parkeston Recontracting

During the last quarter of 2015, we executed an extension to the power purchase agreement to supply power to the Kalgoorlie Consolidated Gold Mine from the 55MW share of the Parkeston power station. The agreement extends the previous contract to October 2026 with options for early termination available to either party beginning in 2021. The risks associated with the extended power purchase agreement remain consistent with the original contract. The contract extension will continue to provide stable cash flow for the business.

Restructured Poplar Creek Contract and Acquisition of Two Wind Farms

On August 31, 2015, we restructured our prior arrangement with Suncor Energy (“Suncor”) in respect of its power generation operations near Fort McMurray. As part of the contract restructuring we acquired Suncor’s interest in two wind projects located in Alberta and Ontario.

Under the terms of the new arrangement, Suncor acquired from us two steam turbines with an installed capacity of 132 MW and certain transmission interconnection assets. In addition, Suncor assumed full operational control of the co-generation facility and will have the right to use the full 244 MW of capacity of our gas generators until 2030. We continue to provide Suncor with centralized monitoring, diagnostics and technical support to maximize performance and reliability of plant equipment. Ownership of the entire Poplar Creek co-generation facility will transfer to Suncor in 2030.

As part of the transaction, we acquired Suncor’s interest in two wind farms: the 20 MW Kent Breeze facility located in Ontario and a 51 per cent interest in the 88 MW Wintering Hills facility located in Alberta. We subsequently sold our interest in Wintering Hills on March 1, 2017. See “Business of TransAlta – Recent Developments” in this AIF.

Sundance Unit 7

During 2015, we received approval from the AUC to construct and operate an 856 MW combined-cycle natural-gas-fired power plant in Alberta. The Sundance 7 project has received all regulatory approvals after receiving the Environmental Protection and Enhancement Act approval from Alberta Environment and Parks on October 1, 2015. Construction of Sundance 7 will not commence until we have contracted a significant portion of the plant capacity. Following changes to market conditions in Alberta during the last few years, we do not anticipate that this condition will be met before the next decade. In December 2015, we repurchased our partner’s 50 per cent share in TransAlta MidAmerican Partnership (“TAMA Power”), the jointly controlled entity developing this project, for consideration of $10 million payable over five years, along with an option permitting the partner to buy back into this project or into other projects of TAMA Power during this period.

Community Development, Energy Efficiency Investment

On July 30, 2015, we announced that we were moving ahead with plans to invest $55 million over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State. The initiative is part of TransAlta Centralia’s transition from coal-fired operations in Washington, beginning in December 31, 2020.

The U.S.$55 million community investment is part of the TransAlta Energy Transition Bill, passed in 2011. This bill was a historic agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State, closing the Centralia facility’s two units, one in 2020 and the other in 2025. Approved funding for community investment included approximately U.S.$1.1 million incurred as at December 31, 2016.

Acquisition of Long-Term Contracted Solar and Wind Assets

On July 27, 2015, we announced the acquisition of 71 MW of long-term contracted renewable generation assets for a purchase price of US$75.8 million, together with the assumption of certain tax equity obligations and US$41.8 million of non-recourse project debt. The assets acquired include 21 MW of solar projects located in Massachusetts and a 50 MW wind facility in Minnesota. The assets are contracted under long-term power purchase agreements ranging from 20 to 30 years with several high quality counterparties.

-8-

This acquisition of the solar projects closed on September 1, 2015 and the acquisition of the wind facility closed on October 1, 2015.

Completion of Natural Gas Pipeline in Australia

On March 19, 2015, TransAlta’s joint venture partner DBP Development Group (a wholly owned subsidiary of DUET Group), announced the completion of the Fortescue River Gas Pipeline in Western Australia. The project, TransAlta’s first pipeline, was completed within a nine month timeframe and for an estimated total cost of AUD$183 million. It delivers gas to our Solomon power station which services Fortescue Metals Group’s mining operations at the Solomon Hub. The power station now operates on natural gas improving reliability and efficiency.

Keephills 1 Force Majeure

On March 17, 2015, an unplanned outage began at our 395 MW Keephills Unit 1 facility due to a damaged superheater. The unit returned to service on May 17, 2015. Following the establishment of the plan to return the unit to service and the review of the causes of the outage, we gave notice under the Alberta PPA to the buyer and the Balancing Pool of a “High Impact Low Probability” force majeure event. A force majeure event under the Alberta PPA entitles us to continue to receive our Alberta PPA capacity payment and exempts us from having to pay availability penalties.

Windsor Recontracting

During the first quarter of 2015, we executed a new 15-year power supply contract with the IESO for our Windsor facility, which became effective December 1, 2016. Under this new contract, the Windsor plant is dispatchable for up to 72 MW of capacity.

2014

Major Maintenance Agreement

On November 14, 2014, we entered into an agreement with Alstom Power Canada Inc. (“Alstom”) to provide major maintenance at our Alberta coal facilities. The agreement relates to ten major maintenance projects at our Keephills and Sundance plants.

South Hedland Power Project

On July 28, 2014, we announced that we had agreed to build, own, and operate a 150 MW combined cycle gas power station in South Hedland, Western Australia to supply power to Regional Power Corporation trading as Horizon Power (“Horizon Power”), a state owned utility, and to the Pilbara Infrastructure Pty Ltd., a wholly owned subsidiary of Fortescue Metals Group (“Fortescue”). The project is estimated to cost approximately AUD $570 million which includes the cost of acquiring existing equipment from Horizon Power. The project is being built on an existing site at Boodarie Industrial Estate and is anticipated to be one of the most efficient power stations in the region. The power station will supply Horizon Power’s customers in the Pilbara region as well as Fortescue’s port operations. IHI Engineering Australia has been selected as the contractor to construct the power station.

We continue to advance the construction of the South Hedland Power Project. Commissioning of the Open Cycle Gas Turbine (“OCGT”) was completed and hand over occurred on December 8, 2016. A commercial agreement was executed with Horizon Power to supply electricity generated from the OCGT in the interim. We continue to expect the project to be delivered on schedule and on budget in mid-2017.

TransAlta and Province Reach Agreement on Ghost Reservoir

On June 4, 2014, we announced that we had reached an agreement with the Alberta Government regarding modifying the operations of the Ghost Reservoir to provide part of a solution for flood mitigation. The revised operating pattern of the Ghost Reservoir involved holding the reservoir near its minimum low water level until July 31, 2014, approximately six weeks longer than the prior operating pattern. Following the success of this flood mitigation agreement in 2014, a similar agreement that provided increased flood storage was entered into for 2015. In 2016, we signed a five-year agreement with the Government of Alberta to aid in potential flood and drought mitigation efforts.

-9-

Sundance Unit 6 Agreement

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 Alberta PPA. During the third quarter of 2012, the Alberta PPA buyer informed us that they will be taking the matter to arbitration. On February 19, 2014, we reached an agreement with the Alberta PPA buyer related to this Sundance Unit 6 dispute.

Keephills Unit 2

On January 31, 2014, an outage commenced at Unit 2 of our Keephills facility to perform a rewind of the generator stator which arose due to the generator event at Keephills Unit 1 facility in 2013. We gave notice of a High Impact Low Probability (“HILP”) event and claimed force majeure relief under the Alberta PPA. The matter was disputed by the buyer and is currently sitting in abeyance.

Fort McMurray Transmission Project

On January 17, 2014, we announced that our strategic partnership with MidAmerican Transmission, TAMA Transmission (“TAMA Transmission”), which was formed on May 9, 2013, successfully qualified to participate as a proponent in the Fort McMurray West 500 kilovolt Transmission Project. TAMA Transmission submitted its bid and in December 2014, after completing its review of all bid submissions, the Alberta Electric System Operator (“AESO”) notified TAMA Transmission that the contract had been awarded to a competitor.

Australia Natural Gas Pipeline

On January 15, 2014, we announced that, through a wholly owned subsidiary, an unincorporated joint venture named Fortescue River Gas Pipeline was formed, of which we have a 43 per cent interest. The first project of the new joint venture was to build, own, and operate an AUD$183 million natural gas pipeline from the Dampier to Bunbury Natural Gas Pipeline to our Solomon power station. The pipeline was completed on March 19, 2015.

Corporate and Energy Marketing

2016

Poplar Creek Financing

On December 7, 2016, we completed a $202.5 million bond offering on behalf of our indirect wholly-owned subsidiary, TAPC Holdings LP (“TAPC”), which is secured by the equity interests in the Issuer and its general partner, and a first ranking charge over all of TAPC’s accounts and certain other assets. The bonds are amortizing and bear interest for each quarterly interest period at a rate per annum equal to the three-month Canadian Dollar Offered Rate in effect on the first day of such quarterly interest period plus 395 basis points. Proceeds were used to provide financing to certain of TAPC’s affiliates, reduce the indebtedness of certain of TAPC’s affiliates (including the Corporation) and for other general business purposes.

Quebec Wind Asset Project Financing

On June 3, 2016, TransAlta Renewables completed a $159 million bond offering on behalf of its indirect wholly-owned subsidiary, New Richmond Wind L.P. (“NR Wind”), which is secured by a first ranking charge over all assets of NR Wind. The bonds are amortizing and bear interest from their date of issue at a rate of 3.963%, payable semi-annually and mature on June 30, 2032. Proceeds were used to make advances to Canadian Hydro Developers, Inc. on a subordinated basis pursuant to an intercompany loan agreement, the proceeds of which were used to finance certain facilities of NR Wind’s affiliates and for other general business purposes.

Listing of Series B Preferred Shares

On March 31, 2016, 1,824,620 of our 12,000,000 cumulative redeemable rate reset first preferred shares, Series A (the “Series A Shares”) were converted, on a one-for-one basis, into cumulative redeemable floating rate first preferred shares, Series B (the “Series B Shares”). As a result of the conversion, TransAlta has 10,175,380 Series A Shares and 1,824,620 Series B Shares issued and outstanding.

-10-

Dividend Resizing and Dividend Reinvestment Program Suspension

On January 14, 2016, to support the Corporation’s transition from coal to gas-fired and renewable power generation in the province of Alberta and to maximize the Corporation’s financial flexibility, we announced the resizing of our dividend to $0.16 per share on an annualized basis and the suspension of the Premium Dividend TM, Dividend Reinvestment and Optional Common Share Purchase Plan.

Closing of $540 Million Transaction with TransAlta Renewables

On January 6, 2016, we announced the closing of the investment by TransAlta Renewables in the Corporation’s Sarnia cogeneration plant, Le Nordais wind farm and Ragged Chute hydro facility (the “Canadian Assets”) for a combined value of $540 million. The Canadian Assets consist of approximately 611 MW of contracted power generation assets located in Ontario and Quebec. The Corporation received cash proceeds of $172.5 million, a $215 million convertible unsecured subordinated debenture and approximately $152.5 million in common shares in the capital of TransAlta Renewables. The cash proceeds were used to reduce corporate debt.

2015

Moody’s Credit Rating Downgrade

On December 17, 2015, Moody’s Investor Services (“Moody’s”) announced that it was downgrading TransAlta Corporation’s credit rating. The Corporation’s outlook is stable. See “Credit Ratings” in this AIF.

AIMCo’s Purchase of Common Shares in TransAlta Renewables

On November 23, 2015 we announced that we had entered into an agreement with Alberta Investment Management Corporation (“AIMCo”) for the sale of $200 million of common shares of TransAlta Renewables (“AIMCo Investment”) at a price per share equal to $9.75. The AIMCo Investment closed on November 26, 2015.

Ontario Wind Assets Project Financing

On October 1, 2015, TransAlta Renewables completed a $442 million bond offering on behalf of its indirect wholly-owned subsidiary, Melancthon Wolfe Wind LP, which was secured by a first ranking charge over all assets of the indirect wholly-owned subsidiary. The bonds are non-recourse to TransAlta, and bear interest at an annual fixed interest rate of 3.8 per cent, payable semi-annually and mature on December 31, 2028. Proceeds were used to make advances to Canadian Hydro Developers, Inc. on a subordinated basis pursuant to an intercompany loan agreement and for other general corporate purposes of TransAlta Renewables.

Agreement with Market Surveillance Administrator

On September 30, 2015, we advised that we had reached an agreement with the Market Surveillance Administrator (the “MSA”) to settle all outstanding proceedings before the Alberta Utilities Commission (the “AUC”). The proceedings pertained to allegations that TransAlta manipulated the price of electricity in the Province of Alberta when it took outages at certain of its coal-fired generating units in late 2010 and early 2011. The AUC approved the settlement on October 29, 2015. Under the terms of the agreement, we paid a total amount of $56 million, including approximately $27 million as a repayment of “economic benefit” under the legislation, $4 million to cover the MSA’s legal and related costs, and a $25 million administrative penalty. The first payment of $31 million was made on November 29, 2015 and the final payment was made in the fourth quarter of 2016.

Cost Savings Through Position Eliminations, Efficiency and Productivity Initiatives

On September 29, 2015, we announced further staff reductions to continue to focus on improving our competitive position and meeting the needs of our customers in a dynamic economic environment. The total number of position reductions throughout the Corporation in 2015, including position reductions that were achieved through lay-offs, attrition and a hiring freeze, was 486.

-11-

$1.78 Billion Transaction with TransAlta Renewables

On May 7, 2015, we announced the closing of the acquisition by TransAlta Renewables of an economic interest based on the cash flows of our Australian assets (the “Australian Transaction”). The portfolio, held by TransAlta Energy (Australia) Pty Ltd, consists of six operating assets with an installed capacity of 425 MW, the 150 MW South Hedland project currently under construction, as well as a 270 km gas pipeline. The combined value of the Australian Transaction was approximately $1.78 billion. The Australian Transaction was originally announced on March 23, 2015.

At the closing of the Australian Transaction, TransAlta Renewables paid us $216.9 million in cash as well as approximately $1,067 million through the issuance of a combination of common shares and Class B shares in the capital of TransAlta Renewables. Cash proceeds from the Australian Transaction were used to reduce indebtedness and strengthen our balance sheet, providing greater financial flexibility for future growth opportunities.

Issuance of Bond

On February 11, 2015, the Corporation and its project level partner issued a bond secured by their jointly owned Pingston facility. Our share of gross proceeds was $45 million. The bond bears interest at the annual fixed interest rate of 2.95 per cent, payable semi-annually with no principal repayments until maturity in May 2023. Proceeds were used to repay the $35 million secured debenture bearing interest at 5.28 per cent.

Investment Grade Credit Rating from Fitch Ratings

On January 8, 2015, we announced that Fitch Ratings (“Fitch”) has rated our debt securities. See “Credit Ratings” in this AIF.

2014

Board of Director Appointments

During the third quarter of 2014, we announced that Mr. P. Thomas Jenkins, OC, CD and Mr. John P. Dielwart had been appointed to our Board of Directors (“Board”), effective September 1, 2014 and October 1, 2014, respectively. The appointments are the result of our ongoing process of evaluating the skills and composition of the Board, planning for succession and aligning the skills of the Board with the strategic direction of the Corporation.

Sale of Preferred Shares

On August 15, 2014, we completed a public offering of 6.6 million Series G 5.3 per cent Cumulative Redeemable Rate Reset First Preferred Shares, for aggregate gross proceeds of $165 million. The proceeds from the offering were used for general corporate purposes in support of our business, including the funding of capital projects and the reduction of short-term indebtedness of the Corporation.

Senior Note Offering

On June 3, 2014, we completed an offering of U.S.$400 million aggregate principal amount of senior notes maturing in 2017 and bearing interest at 1.90 per cent. The net proceeds from the offering were used to repay borrowings under existing credit facilities and for general corporate purposes.

California Claim

On May 30, 2014, we announced that our settlement with California utilities, the California Attorney General and certain other parties (the “California Parties”) to resolve claims related to the 2000 to 2001 power crisis in the State of California had been approved by the U.S. Federal Energy Regulatory Commission (“FERC”). The settlement provided for the payment by us of U.S.$52 million in two equal payments and a credit of approximately U.S.$97 million for monies owed to us from accounts receivable. The first payment of U.S.$26 million was paid in 2014 and the second payment was made in 2015.

Secondary Offering of TransAlta Renewables Common Shares

On April 29, 2014, we completed a secondary offering of an aggregate of 11,950,000 common shares which we held directly and indirectly in TransAlta Renewables at a price of $11.40 per Common Share, resulting in gross proceeds to the Corporation of $136.2 million. The net proceeds from the offering were

-12-

used for general corporate purposes, including the funding of capital projects and the reduction of indebtedness of the Corporation.

Executive Leadership Team Appointments

On March 18, 2014, we announced three senior leadership appointments that enhanced our objectives of operational excellence from the base business and growth. Brett Gellner was appointed to the role of Chief Investment Officer, responsible for leading all growth aspects of the Corporation. Donald Tremblay joined TransAlta as Chief Financial Officer, effective March 31, 2014, and on July 3, 2014, Wayne Collins joined TransAlta as Executive Vice President, Coal and Mining Operations.

CE Generation Sale

On February 20, 2014, we announced the sale of our 50 per cent interest in CE Generation, the Blackrock development project (“Blackrock”) and Wailuku Holding Company, LLC (“Wailuku”) to MidAmerican Renewables for proceeds of U.S.$193.5 million. MidAmerican Renewables held the other 50 per cent interest in CE Generation, Blackrock and Wailuku. The sale of our interest in CE Generation and Blackrock closed on June 12, 2014 and the sale of our 50 per cent interest in Wailuku closed on November 25, 2014.

Dividend

On February 20, 2014, we announced the resizing of our dividend to a quarterly dividend of $0.18 per common share (or $0.72 per common share on an annualized basis) to align with our growth and financial objectives. On January 14, 2016, we announced the further resizing of our dividend to a quarterly dividend of $0.04 per common share (or $0.16 per common share on an annualized basis).

-13-

BUSINESS OF TRANSALTA

Our Canadian Coal, U.S. Coal, Wind and Solar, Hydro, Canadian Gas and Australian Gas business segments are responsible for constructing, operating and maintaining our electrical generation facilities as well as the related mining operations in Canada and the U.S. The Energy Marketing segment is responsible for marketing our production and securing cost effective and reliable fuel supply. All the segments are supported by a Corporate segment.

The following table identifies each business segment’s contribution to revenues:

| 2016 Revenues | 2015 Revenues
Canadian Coal | 44% | 40%
U.S. Coal | 15% | 17%
Canadian Gas | 17% | 20%
Australian Gas | 5% | 5%
Wind and Solar | 11% | 11%
Hydro | 5% | 5%
Energy Marketing | 3% | 2%
Corporate | 0% | 0%

For further information on TransAlta’s segment earnings and assets, please refer to Note 33 of our audited consolidated financial statements for the year ended December 31, 2016, which financial statements are incorporated by reference herein. See “Documents Incorporated by Reference” in this AIF.

The following sections of this Annual Information Form provide detailed information on facilities by geographic location and fuel type.

Canadian Coal Business Segment

The following table summarizes our Canadian Coal generation facilities:

Facility Name |  | Province |  | Ownership (%) |  | Net Capacity Ownership Interest (MW)(1) |  | Commercial Operation Date |  | Revenue Source |  | Contract Expiry Date(2)
Genesee 3 |  | AB |  | 50 |  | 233 |  | 2005 |  | Merchant |  | -
Keephills Unit No. 1(3) |  | AB |  | 100 |  | 395 |  | 1983 |  | Alberta PPA/Merchant |  | 2020
Keephills Unit No. 2(3) |  | AB |  | 100 |  | 395 |  | 1984 |  | Alberta PPA/Merchant |  | 2020
Keephills Unit No. 3 |  | AB |  | 50 |  | 232 |  | 2011 |  | Merchant |  | -
Sheerness Unit No. 1(4) |  | AB |  | 25 |  | 100 |  | 1986 |  | Alberta PPA/Merchant |  | 2020
Sheerness Unit No. 2 |  | AB |  | 25 |  | 98 |  | 1990 |  | Alberta PPA |  | 2020
Sundance Unit No. 1 |  | AB |  | 100 |  | 280 |  | 1970 |  | Alberta PPA |  | 2017
Sundance Unit No. 2 |  | AB |  | 100 |  | 280 |  | 1973 |  | Alberta PPA |  | 2017
Sundance Unit No. 3(5) |  | AB |  | 100 |  | 368 |  | 1976 |  | Alberta PPA/Merchant |  | 2020
Sundance Unit No. 4(5) |  | AB |  | 100 |  | 406 |  | 1977 |  | Alberta PPA/Merchant |  | 2020
Sundance Unit No. 5(5) |  | AB |  | 100 |  | 406 |  | 1978 |  | Alberta PPA/Merchant |  | 2020
Sundance Unit No. 6(5) |  | AB |  | 100 |  | 401 |  | 1980 |  | Alberta PPA/Merchant |  | 2020
Total Canadian Coal Net Capacity |  |  |  |  |  | 3,593 |  |  |  |  |  |

Notes:

(1) | MW are rounded to the nearest whole number. Column may not add due to rounding.
(2) | Where no contract expiry date is indicated, the facility operates as merchant.
(3) | Merchant capacity includes a 12 MW uprate on units 1 and 2, which began operation in the second quarter of 2012.
(4) | Merchant capacity includes a 10 MW uprate completed in the first quarter of 2016.
(5) | Merchant capacity includes uprates of 15 MW, 53 MW, 53 MW and 44 MW on Sundance units 3, 4, 5 and 6, respectively.

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 3 facility, 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 Westmoreland Coal Company

-14-

(“Westmoreland Coal”) and Capital Power. We have entered into coal supply agreements with Westmoreland Coal, which operates the mine, to supply coal for the life of the facility.

Keephills 1 and 2 and the Sundance facilities are located approximately 70 kilometres southwest of Edmonton, Alberta, and are both owned by TransAlta. Keephills unit 1 and unit 2 have a maximum capacity of 395 MW each. The Sheerness facility is located approximately 200 kilometres northeast of Calgary, Alberta and is jointly owned by TA Cogen and ATCO Power (2000) Ltd. (“ATCO Power”). See “Business of TransAlta – Non-Controlling Interests” in this AIF.

On November 24, 2016, we entered into the Off-Coal Agreement with the Government of Alberta pertaining to the cessation of coal-fired emissions from the Keephills 3, Genesee 3, and Sheerness coal-fired facilities. The Off-Coal Agreement provides that we will receive cash payments of approximately $37.4 million, net to TransAlta, commencing in 2017 and terminating in 2030, subject to satisfaction of certain terms and conditions including the cessation of all coal-fired emissions in 2030. See “See General Developments of the Business – Generation and Business Development” in this AIF.

Fuel requirements for the Western Canadian thermal generation facilities that we operate 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 that date, we assumed operating and management control of the Highvale mine through our wholly-owned subsidiary, SunHills. The decision to directly operate our facility was made in line with our operating model for operational excellence and to provide us with greater control over our costs and operations.

We estimate that the recoverable coal reserves contained in this mine are sufficient to supply the anticipated requirements for the life of the facilities it serves, including those running post Alberta PPA expiry. 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.

TransAlta and Capital Power formed a joint venture through which each has a 50 per cent ownership interest of the Keephills 3 facility. Capital Power was responsible for the construction of the facility and TransAlta is responsible for managing the joint venture. Keephills 3 began commercial operations on September 1, 2011. The facility is jointly operated by Capital Power and TransAlta. 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 Westmoreland Coal. TA Cogen and ATCO Power have entered into coal supply agreements with Westmoreland Coal, which operates the mine, to supply coal until 2026. See “Business of TransAlta – Non-Controlling Interests” in this AIF.

Canadian Gas Business Segment

The following table summarizes our natural gas-fired and diesel fired generation facilities:

Facility Name |  | Province/ State |  | Ownership (%) |  | Net Capacity Ownership Interest (MW)(1) |  | Commercial Operation Date |  | Revenue Source |  | Contract Expiry Date(2)
Fort Saskatchewan (5) |  | AB |  | 30 |  | 35 |  | 1999 |  | LTC |  | 2019
Poplar Creek (4) |  | AB |  | 100 |  | 230 |  | 2001 |  | LTC |  | 2030
Mississauga (5) |  | ON |  | 50 |  | 54 |  | 1992 |  | LTC |  | 2018
Ottawa (5) |  | ON |  | 50 |  | 37 |  | 1992 |  | LTC/Merchant |  | 2017-2033
Sarnia (3) |  | ON |  | 100 |  | 506 |  | 2003 |  | LTC |  | 2022-2025
Windsor (5) |  | ON |  | 50 |  | 36 |  | 1996 |  | LTC/Merchant |  | 2031
Total Cnd Gas Net Capacity |  |  |  |  |  | 898 |  |  |  |  |  |

Notes:

(1) | MW are rounded to the nearest whole number. Net Capacity Ownership Interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns approximately 64 per cent of the voting equity in TransAlta Renewables.
(2) | Where no contract expiry date is indicated, the facility operates as merchant.

-15-

(3) | Facility owned by TransAlta Renewables.
(4) | The Poplar Creek plant is operated by Suncor and ownership of the facility will transfer to Suncor in 2030.
(5) | Our interests in these facilities are through our ownership interest in TA Cogen.

Our interest in the Fort Saskatchewan facility is held through TA Cogen. See “Business of TransAlta – Non-Controlling Interests” in this AIF. The 118 MW natural gas-fired Combined-Cycle cogeneration Fort Saskatchewan plant 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. On August 31, 2015, the Corporation restructured its contractual arrangement for the power generation services of its Poplar Creek plant. The Poplar Creek co-generation facility had been built and contracted to provide steam and electricity to Suncor’s oil sands operations. Under the terms of the new arrangement, Suncor acquired from the Corporation two steam turbines with an installed capacity of 126 MW and certain transmission interconnection assets. In addition, Suncor assumed full operational control of the co-generation facility and has the right to use the full 230 MW capacity of the Corporation’s gas generators until December 31, 2030. Ownership of the entire Poplar Creek co-generation facility will transfer to Suncor in 2030.

The Mississauga Facility is owned by TA Cogen. See “Business of TransAlta – Non-Controlling Interests” in this AIF. It is a Combined-Cycle cogeneration facility designed to produce 108 MW of electrical energy. The capacity was contracted under a long-term contract with the OEFC which was terminated effective December 31, 2016. The Mississauga Facility entered into an enhanced dispatch contract with the IESO effective January 1, 2017 for a 2 year term. Prior to July 2005, the Mississauga Facility 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 or market based lease rates if the site discontinues electricity generation. On or prior to each of January 1, 2018 and 2023, Boeing must give notice of its intention to continue or discontinue cogeneration services. In addition, on those same dates, Boeing has the option to require the removal of the Mississauga plant from the leased lands or purchase the Mississauga plant at its net salvage value.

The Ottawa plant is owned by TA Cogen. See “Business of TransAlta – Non-Controlling Interests” in this AIF. It is a Combined-Cycle cogeneration facility designed to produce 74 MW of electrical energy. On August 30, 2013, the Corporation announced the recontracting of the plant with the IESO for a 20-year term, effective January 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 National Defence Medical Centre. The thermal energy contract with the Ottawa Health Sciences Centre expires January 1, 2024 and the thermal energy contract with the National Defence Medical Centre has an initial term which expires on December 31, 2017; however, pursuant to its terms, it has automatically renewed for two years to December 31, 2019.

The Sarnia plant is a 506 MW Combined-Cycle cogeneration facility that provides steam and electricity to nearby industrial facilities owned by ARLANXEO Canada Inc. (formerly LANXESS AG), Nova Chemicals (Canada) Ltd. (“NOVA”) (which in turn supplies Styrolution, a Styrene production facility formerly owned by NOVA) and Suncor Energy Products Inc. In September 2009, we signed a new contract with the IESO, effective as of July 1, 2009 and terminating on December 31, 2025. This agreement includes provisions for the parties to share in the impact and benefit of changes in customer steam load or loss of steam customer. The current steam contracts expire at the end of 2022. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Sarnia cogeneration facility on January 6, 2016, and subsequently on November 30, 2016, the economic interest was replaced with direct ownership of the entity that owns the Sarnia cogeneration plant. See “Business of TransAlta – Non-Controlling Interests.”

The Windsor plant is owned by TA Cogen. See “Business of TransAlta – Non-Controlling Interests” in this AIF. It is a Combined-Cycle cogeneration facility designed to produce 72 MW of electrical energy, of which, 50 MW was sold under a long-term contract to the OEFC. This agreement with the OEFC expired November 30, 2016. Effective December 1, 2016, the Windsor plant began operating under an agreement with the IESO with a 15 year term for up to 72 MW of capacity. The Windsor plant also provides thermal energy to Chrysler Canada Inc.’s minivan assembly facility in Windsor that expires in 2018.

-16-

Australian Gas Business Segment

The following table summarizes our natural gas-fired and diesel fired generation facilities:

Facility Name |  | Province/ State |  | Ownership (%) |  | Net Capacity Ownership Interest (MW)(1) |  | Commercial Operation Date |  | Revenue Source |  | Contract Expiry Date(2)
Parkeston (3) (6) |  | WA (7) |  | 50 |  | 55 |  | 1996 |  | LTC |  | 2026
Solomon (3) |  | WA (7) |  | 100 |  | 125 |  | 2014 |  | LTC |  | 2028
South Hedland (3) (5) |  | WA (7) |  | 100 |  | 150 |  | 2017 |  | LTC |  | 2042
Southern Cross Energy (3) (4) |  | WA (7) |  | 100 |  | 245 |  | 1996 |  | LTC |  | 2023
Total Aus Gas Net Capacity |  |  |  |  |  | 575 |  |  |  |  |  |

Notes:

(1) | MW are rounded to the nearest whole number. Net Capacity Ownership Interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns approximately 64 per cent of the voting equity in TransAlta Renewables.
(2) | Where no contract expiry date is indicated, the facility operates as merchant.
(3) | TransAlta Renewables owns an economic interest in the facility.
(4) | Comprised of four facilities.
(5) | Plant is under construction and expected to be fully commissioned in mid-2017.
(6) | Plant contracted to October 2026 with early termination options beginning in 2021.
(7) | Western Australia.

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 the initial supply contract ended in 2016. The plant has been re-contracted effective November 1, 2016, and the agreement extends the previous contract to October 2026, with options for early termination available to either party beginning in 2021. Any merchant capacity and energy are sold into Western Australia’s wholesale electricity market. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Parkeston facility on May 7, 2015. See “General Developments of the Business – Corporate and Energy Marketing” in this AIF.

We acquired the 125 MW natural gas and diesel fired Solomon power station in September 2012 from Fortescue. The Solomon facility is fully contracted with Fortescue under a long-term contract that is intended to support their iron ore mining operations. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Solomon facility on May 7, 2015. See “General Developments of the Business – Corporate and Energy Marketing” in this AIF.

Southern Cross Energy is composed of four natural gas and diesel-fired generation facilities with a combined capacity of 245 MW. Southern Cross Energy sells its output pursuant to a contract with BHP Billiton Nickel West which was renewed in October of 2013 for ten years. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Southern Cross Energy facilities on May 7, 2015. See “General Developments of the Business – Corporate and Energy Marketing” in this AIF.

In 2014, we established the Fortescue River Gas Pipeline joint venture with DBP Development Group. The joint venture (of which TransAlta is a 43% partner) was successfully awarded the contract to design, build, own and operate the 270 km Fortescue River Gas Pipeline to deliver natural gas to TransAlta’s Solomon Power Station. The pipeline was completed in the first quarter of 2015 and operates under a take-or-pay gas transport agreement with a Fortescue Metals Group subsidiary for an initial term of 20 years. The 16-inch diameter pipeline has an initial free-flow capacity of 64 TJ per day. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the pipeline on May 7, 2015. See “General Developments of the Business – Corporate and Energy Marketing” in this AIF.

In 2014, TransAlta was selected as the successful bidder to design, build, own and operate a 150 MW combined cycle power station near South Hedland, Western Australia. Construction began in early 2015 and the plant is expected to be fully commissioned in 2017. On December 8, 2016, the OCGT was commissioned and hand-over occurred. A commercial agreement was executed with Horizon Power to supply electricity generated from the OCGT in the interim. The plant is being constructed under an engineering, procurement and construction agreement with IHI Engineering Australia, a wholly owned subsidiary of IHI Corporation. The plant is fully contracted with

-17-

two customers for a 25-year term. The majority of the plant’s capacity is contracted to Horizon Power, the state owned electricity supplier in the region. The second customer is the port operations of Fortescue Metals Group. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the South Hedland facility on May 7, 2015. See “General Developments of the Business – Corporate and Energy Marketing” in this AIF.

All of our Australian assets are owned, directly or indirectly, by TransAlta Energy (Australia) Pty Ltd. (“TEA”). On May 7, 2015, TransAlta Renewables acquired from the Corporation tracking preferred shares that entitle TransAlta Renewables to an economic interest based on the cash flows of TEA, in consideration for a payment equal to $1.78 billion, which amount includes the cost of funding the remaining construction costs for South Hedland.

Hydro Business Segment

The Hydro business segment holds an interest in 948 gross MWs. The facilities are located in British Columbia, Alberta, Ontario, and Washington State.

As well as contracting for power, long-term and short-term contracts are entered into to sell the environmental attributes from the merchant hydro facilities. These activities help to ensure earnings consistency from these assets. 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 hydroelectric facilities:

Facility Name |  | Province/ State |  | Ownership (%) |  | Net Capacity Ownership Interest (MW)(1) |  | Commercial Operation Date |  | Revenue Source |  | Contract Expiry Date(2)
Barrier |  | AB |  | 100 |  | 13 |  | 1947 |  | Alberta PPA |  | 2020
Bearspaw |  | AB |  | 100 |  | 17 |  | 1954 |  | Alberta PPA |  | 2020
Cascade |  | AB |  | 100 |  | 36 |  | 1942, 1957 |  | Alberta PPA |  | 2020
Ghost |  | AB |  | 100 |  | 54 |  | 1929, 1954 |  | Alberta PPA |  | 2020
Horseshoe |  | AB |  | 100 |  | 14 |  | 1911 |  | Alberta PPA |  | 2020
Interlakes |  | AB |  | 100 |  | 5 |  | 1955 |  | Alberta PPA |  | 2020
Kananaskis |  | AB |  | 100 |  | 19 |  | 1913, 1951 |  | Alberta PPA |  | 2020
Pocaterra |  | AB |  | 100 |  | 15 |  | 1955 |  | Merchant |  | -
Rundle |  | AB |  | 100 |  | 50 |  | 1951, 1960 |  | Alberta PPA |  | 2020
Spray |  | AB |  | 100 |  | 112 |  | 1951, 1960 |  | Alberta PPA |  | 2020
Three Sisters |  | AB |  | 100 |  | 3 |  | 1951 |  | Alberta PPA |  | 2020
Belly River (3) (4) |  | AB |  | 100 |  | 3 |  | 1991 |  | Merchant |  | -
St. Mary (3) (4) |  | AB |  | 100 |  | 2 |  | 1992 |  | Merchant |  | -
Taylor (3) (4) |  | AB |  | 100 |  | 13 |  | 2000 |  | Merchant |  | -
Waterton (3) (4) |  | AB |  | 100 |  | 3 |  | 1992 |  | Merchant |  | -
Bighorn |  | AB |  | 100 |  | 120 |  | 1972 |  | Alberta PPA |  | 2020
Brazeau |  | AB |  | 100 |  | 355 |  | 1965, 1967 |  | Alberta PPA |  | 2020
Akolkolex (3) (4) |  | BC |  | 100 |  | 10 |  | 1995 |  | LTC |  | 2046
Pingston (3) (4) |  | BC |  | 50 |  | 23 |  | 2003, 2004 |  | LTC |  | 2023
Bone Creek (3) (4) |  | BC |  | 100 |  | 19 |  | 2011 |  | LTC |  | 2031
Upper Mamquam (3) (4) |  | BC |  | 100 |  | 25 |  | 2005 |  | LTC |  | 2025
Appleton (3) (4) |  | ON |  | 100 |  | 1 |  | 1994 |  | LTC |  | 2030
Galetta (3) (6) |  | ON |  | 100 |  | 2 |  | 1998 |  | LTC |  | 2030
Misema (3) |  | ON |  | 100 |  | 3 |  | 2003 |  | LTC |  | 2027
Moose Rapids (3) |  | ON |  | 100 |  | 1 |  | 1997 |  | LTC |  | 2030
Ragged Chute (3) (4) |  | ON |  | 100 |  | 7 |  | 1991 |  | LTC |  | 2029
Skookumchuck (5) |  | WA |  | 100 |  | 1 |  | 1970 |  | LTC |  | 2020
Total Hydroelectric Net Capacity |  |  |  |  |  | 926 |  |  |  |  |  |

Notes:

(1) | MW are rounded to the nearest whole number. Net Capacity Ownership Interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns approximately 64 per cent of the voting equity in TransAlta Renewables.
(2) | Where no contract expiry date is indicated, the facility operates as merchant.
(3) | Facility owned by TransAlta Renewables.
(4) | These facilities are EcoLogo® certified (“EcoLogo”). EcoLogo certification is granted to products with environmental performance that meet or exceed all government, industrial safety and performance standards.
(5) | This facility is used to provide a reliable water supply to Centralia Coal.
(6) | Galetta was originally built in 1907, but was retrofitted in 1998.

-18-

Bow River System

Barrier is a run-of-river hydroelectric facility with installed capacity of 13 MW located on the Kananaskis River in Seebe, Alberta. 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. 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 purchased this facility 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 54 MW located on the Bow River in Cochrane, Alberta. 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 on the Bow River in Seebe, Alberta. 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 at Kananaskis Lakes, Alberta. 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 on the Bow River in Seebe, Alberta. 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 at Kananaskis Lakes, Alberta. It has been operating since 1955. Generation from the facility is sold in the Alberta spot market.

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. It has been operating since 1951. The facility operates under an Alberta PPA.

Spray is a hydroelectric facility with installed capacity of 112 MW located in Canmore, Alberta on the Spray system. The plant uses water from the Spray Lakes Storage Reservoir. 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. It has been operating since 1951. The facility operates under an Alberta PPA.

Oldman River System

The Belly River facility is owned by TransAlta Renewables. 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. It has been operating since 1991. We acquire the generation from the facility pursuant to a Renewables PPA (as defined below), and subsequently sell such generation in the Alberta spot market.

The St. Mary facility is owned by TransAlta Renewables. 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. It has been operating since 1992. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

-19-

The Taylor facility is owned by TransAlta Renewables. 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. It has been operating since 2000. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

The Waterton facility is owned by TransAlta Renewables. 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. It has been operating since 1992. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

North Saskatchewan River System

Bighorn is a hydroelectric facility with installed capacity of 120 MW located in Nordegg, Alberta. 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. It has been operating since 1965. The facility operates under an Alberta PPA.

Akolkolex River System

The Akolkolex facility is owned by TransAlta Renewables. Akolkolex is a run-of-river hydroelectric facility with installed capacity of 10 MW located on the Akolkolex River, south of Revelstoke, British Columbia. It has been operating since 1995. In 2016, TransAlta entered into a new 30 year agreement to sell the output from the facility 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 the Akolkolex facility. It has been operating since 2003. TransAlta Renewables owns the facility equally with Brookfield Renewable Power Inc. The output from the facility is sold to BC Hydro.

Thompson River System

The Bone Creek facility is owned by TransAlta Renewables. 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. It has been operating since 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.

Mamquam River System

The Upper Mamquam facility is owned by TransAlta Renewables. 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. It has been operating since 2005. The output from the facility is sold to BC Hydro.

Mississippi River System

The Appleton facility is owned by TransAlta Renewables. Appleton is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Mississippi River, near Almonte, Ontario. The facility has been operating since 1994. Generation from this facility is sold to the IESO under a contract that terminates December 31, 2030.

The Galetta facility is owned by TransAlta Renewables. Galetta is a run-of-river hydroelectric facility with installed capacity of 2 MW located on the Mississippi River, near Galetta, Ontario. This facility was originally built in 1907 and retrofitted in 1998. Generation from this facility is sold to the IESO under a contract that terminates December 31, 2030.

-20-

Misema River System

The Misema facility is owned by TransAlta Renewables. 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. This facility has been operating since 2003. Generation from this facility is sold to the IESO under a contract that terminates May 3, 2027.

Wanapitei River System

The Moose Rapids facility is owned by TransAlta Renewables. 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. This facility has been operating since 1997. Generation from this facility is sold to the IESO under a contract that terminates December 31, 2030.

Montréal River System

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 Inc. and it has been operating since 1991. Generation from this facility is sold to the IESO under a contract that terminates June 30, 2029. On January 6, 2016 TransAlta Renewables acquired from the Corporation tracking preferred shares that entitle TransAlta Renewables to an economic interest based on the cash flows, in part, from the Ragged Chute Facility; and subsequently on November 30, 2016, the economic interest was replaced with direct ownership of the entity that owns the Ragged Chute hydro facility. See “Business of TransAlta – Non-Controlling Interests” in this AIF.

Centralia

We 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 generation facilities in Centralia. On December 10, 2010, we entered into an agreement with Puget Sound Energy (“PSE”) for Skookumchuck to provide power until 2020.

Wind and Solar Business Segment

As at December 31, 2016, the Wind and Solar segment held interests in approximately 1,505 MW of gross wind generating capacity from 11 wind farms in Western Canada, four in Ontario, two in Québec, two in New Brunswick, and two in the United States, more specifically in the states of Wyoming and Minnesota. We also own a 21 MW solar facility in the state of Massachusetts in the United States.

Wind and solar are not generally a dispatchable fuel; therefore, in merchant markets, wind and solar 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 or solar asset compared to a base load asset. If these price assumptions 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. For a wind farm, this includes wind farm design including wake and array losses, wind shear and the electrical losses within the site. For a solar plant, long-term energy production depends on panel angle and row spacing, amount of sun, ambient conditions such as temperature and wind speed and losses at 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 also enter into long-term and short-term contracts to sell the environmental attributes from the merchant wind facilities including offsets and renewable energy credits. These activities help to ensure earnings consistency from these assets. Generally, for facilities under long-term contract, the purchaser under such long-term contracts also has the benefit of any environmental attributes.

-21-

The following table summarizes our Wind and Solar generation facilities:

Facility Name |  | Province/ State |  | Ownership (%) |  | Net Capacity Ownership Interest (MW)(1) |  | Commercial Operation Date |  | Revenue Source |  | Contract Expiry Date(2)
Ardenville (4) (5) |  | AB |  | 100 |  | 69 |  | 2010 |  | Merchant |  | -
Blue Trail (4) (5) |  | AB |  | 100 |  | 66 |  | 2009 |  | Merchant |  | -
Castle River (4) (5) (6) |  | AB |  | 100 |  | 44 |  | 1997-2001 |  | Merchant |  | -
Cowley North (4) (5) |  | AB |  | 100 |  | 20 |  | 2001 |  | Merchant |  | -
Macleod Flats (4) |  | AB |  | 100 |  | 3 |  | 2004 |  | Merchant |  | -
McBride Lake (4) (5) |  | AB |  | 50 |  | 38 |  | 2004 |  | LTC |  | 2024
Sinnott (4) (5) |  | AB |  | 100 |  | 7 |  | 2001 |  | Merchant |  | -
Soderglen (4) (5) |  | AB |  | 50 |  | 35 |  | 2006 |  | Merchant |  | -
Summerview 1 (4) (5) |  | AB |  | 100 |  | 70 |  | 2004 |  | Merchant |  | -
Summerview 2 (4) (5) |  | AB |  | 100 |  | 66 |  | 2010 |  | Merchant |  | -
Wintering Hills (9) |  | AB |  | 51 |  | 45 |  | 2012 |  | Merchant |  | -
Mass Solar (8) |  | MA |  | 100 |  | 21 |  | 2012-2015 |  | LTC |  | 2032-2045
Lakeswind |  | MN |  | 100 |  | 50 |  | 2014 |  | LTC |  | 2034
Kent Hills (4) (5) |  | NB |  | 83 |  | 80 |  | 2008 |  | LTC |  | 2033
Kent Hills Expn. (4) (5) |  | NB |  | 83 |  | 45 |  | 2010 |  | LTC |  | 2035
Kent Breeze |  | ON |  | 100 |  | 20 |  | 2011 |  | LTC |  | 2031
Melancthon I (4) (5) |  | ON |  | 100 |  | 68 |  | 2006 |  | LTC |  | 2026
Melancthon II (4) (5) |  | ON |  | 100 |  | 132 |  | 2008 |  | LTC |  | 2028
Wolfe Island (4) (5) |  | ON |  | 100 |  | 198 |  | 2009 |  | LTC |  | 2029
Le Nordais (4) (5) (7) |  | QC |  | 100 |  | 98 |  | 1999 |  | LTC |  | 2033
New Richmond (4) (5) |  | QC |  | 100 |  | 68 |  | 2013 |  | LTC |  | 2033
Wyoming Wind (3) |  | WY |  | 100 |  | 144 |  | 2003 |  | LTC |  | 2028
Total Wind and Solar Net Capacity |  |  |  |  |  | 1,384 |  |  |  |  |  |

Notes:

(1) | MW are rounded to the nearest whole number. Column may not add due to rounding. Net Capacity Ownership Interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns approximately 64 per cent of the voting equity in TransAlta Renewables.
(2) | Where no contract expiry date is indicated, the facility operates as merchant.
(3) | TransAlta Renewables owns an economic interest in the facility.
(4) | Facility owned by TransAlta Renewables.
(5) | These facilities are EcoLogo® certified. EcoLogo certification is granted to products with environmental performance that meet or exceed all government, industrial safety and performance standards.
(6) | Includes seven additional turbines at other locations.
(7) | Comprised of two facilities.
(8) | Comprised of multiple facilities.
(9) | On January 16, 2017, we announced the sale of our 51% interest in Wintering Hills. The transaction closed on March 1, 2017. See “General Developments of the Business – Recent Developments” in this AIF.

The Ardenville facility is owned by TransAlta Renewables. 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 Ardenville wind farm is entitled to receive payments of $10/MWh until 2020 from NRCan, through the eERP program. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

The Blue Trail facility is owned by TransAlta Renewables. Blue Trail is a 66 MW wind farm located in southern Alberta which commenced commercial operations in November 2009. The Blue Trail wind farm is entitled to receive payments of $10/MWh until 2019 from NRCan, through the eERP program. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

The Castle River facility is owned by TransAlta Renewables. 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. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

-22-

The Cowley North facility is owned by TransAlta Renewables. Cowley North is a 20 MW wind farm, located in Pincher Creek, Alberta. It commenced commercial operations in the fall of 2001. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

The Macleod Flats facility is owned by TransAlta Renewables. 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. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

The McBride Lake facility is owned by TransAlta Renewables. McBride Lake is a 75 MW wind farm located at Fort Macleod, Alberta. We constructed the wind farm, which commenced commercial operations in 2004. McBride Lake is operated by us. TransAlta Renewables owns the facility equally with ENMAX Green Power Inc. The output from the facility is 100 per cent contracted in the form of a 20-year PPA with ENMAX Energy Corporation. We also own an interest in the 0.7 MW McBride Lake East facility in the same vicinity through our ownership interest in TransAlta Renewables.

The Sinnott facility is owned by TransAlta Renewables. Sinnott has a total installed capacity of 7 MW and is located in Pincher Creek, Alberta. It commenced commercial operations in the fall of 2001. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

The Soderglen facility is owned by TransAlta Renewables. Soderglen is a 71 MW facility located in southern Alberta, southwest of Fort Macleod and 40 kilometres from our wind operations near Pincher Creek. The facility began commercial operations in September 2006. TransAlta Renewables owns the facility equally with Nexen Energy ULC. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell 50 per cent of such generation in the Alberta spot market (which excludes that portion of generation that is owned by Nexen Energy ULC).

The Summerview 1 facility is owned by TransAlta Renewables. Summerview 1 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 1 facility, together with an existing 1.8 MW turbine in the area, brings the total wind generation capacity at that location to 70 MW. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

The Summerview 2 facility is owned by TransAlta Renewables. Summerview 2 is a 66 MW wind farm located northeast of Pincher Creek, Alberta. We constructed the facility, which began commercial operations in February 2010. The Summerview 2 wind farm expansion is entitled to receive payments of $10/MWh until 2020 from NRCan, through the eERP program. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

Wintering Hills is an 88 MW wind farm located in southern Alberta, north of Hussar, Alberta. The facility began commercial operations in June 2012. On December 31, 2016, TransAlta owned a 51 per cent interest in this facility and Teck Resources Limited held the remaining 49 per cent interest. On January 16, 2017, we announced the sale of our 51% interest in Wintering Hills. The transaction closed on March 1, 2017. See “General Developments of the Business – Recent Developments” in this AIF.

The Mass Solar Farm is a 21 MW solar project consisting of multiple facilities located in Massachusetts. The wind farm was acquired in 2015 from an affiliate of Rockland Capital LLC. The operational solar farm is contracted under a long-term PPA with several high quality counterparties. See “General Developments of the Business – Generation and Business Development.”

The Lakeswind Wind Farm is a 50 MW wind project located near Rollag, Minnesota. The wind farm was acquired in 2015 from an affiliate of Rockland Capital LLC. The wind farm is fully operational and contracted under a long-term PPA until 2034 with several high quality counterparties. See “General Developments of the Business – Generation and Business Development” in this AIF.

The Kent Hills facility is owned by TransAlta Renewables. 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

-23-

Technologies Inc. (“Natural Forces”), an Atlantic Canada-based wind developer, is our co-development partner in this project and exercised its option to purchase 17 per cent of the Kent Hills project in May 2009. Kent Hills commenced commercial operations in 2008. Kent Hills is entitled to receive eERP payments until 2018.

The Kent Hills expansion is owned by TransAlta Renewables. 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 2010. The Kent Hills expansion is entitled to receive eERP payments until 2020.

Kent Breeze is a 20 MW wind project located in Thamesville, Ontario. This facility commenced commercial operations in 2011. Generation from this facility is sold to the IESO. Kent Breeze is entitled to receive eERP payments until 2021.

The Melanchton I facility is owned by TransAlta Renewables. Melancthon I is a 68 MW wind project located in Melancthon Township near Shelburne, Ontario. It commenced commercial operations in 2006. Generation from this facility is sold to the IESO.

The Melancthon II facility is owned by TransAlta Renewables. Melancthon II is a 132 MW wind project located adjacent to Melancthon I, in Melancthon and Amaranth Townships. It commenced commercial operations in 2008. Generation from this facility is sold to the IESO. Melancthon II is entitled to receive eERP payments until 2018.

The Wolfe Island facility is owned by TransAlta Renewables. Wolfe Island is a 198 MW wind project located on Wolfe Island, near Kingston, Ontario. This facility commenced commercial operations in 2009. Generation from this facility is sold to the IESO. Wolfe Island is entitled to receive eERP payments until 2019.

Le Nordais is located at two sites on the Gaspé Peninsula of Québec: Cap-Chat and Matane with a combined 98 MW of installed capacity. It commenced commercial operations in 1999. Generation from this facility is sold to Hydro-Québec. On January 6, 2016, TransAlta Renewables acquired from the Corporation tracking preferred shares that entitle TransAlta Renewables to an economic interest based on the cash flows, in part, from the Le Nordais facilities; and subsequently on November 30, 2016, the economic interest was replaced with direct ownership of the entity that owns the Le Nordais wind farm. See “Business of TransAlta – Non-Controlling Interests” in this AIF.

The New Richmond facility is owned by TransAlta Renewables. New Richmond is a 68 MW wind project also located on the Gaspé Peninsula. New Richmond is contracted under a 20-year Electricity Supply Agreement with Hydro-Québec Distribution. It commenced commercial operations in 2013.

The Wyoming Wind Farm is a 144 MW wind project located near Evanston, Wyoming. The wind farm was acquired in December 2013 from an affiliate of NextEra Energy Resources, LLC. The wind farm is contracted under a long-term PPA until 2028 with an investment grade counterparty. Concurrent with closing, TransAlta Renewables acquired tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind farm.

All of the electricity generated and sold by our Wind segment within Canada, with the exception of Macleod Flats, Kent Breeze, and Wintering Hills, are from facilities that are EcoLogo certified. We are an EcoLogo certified distributor of Alternative Source Electricity through Environment Canada’s Environmental Choice program.

U.S. Coal Business Segment

Our U.S. Coal facilities are summarized in the following table:

Facility Name |  | Province/ State |  | Ownership (%) |  | Net Capacity Ownership Interest (MW) |  | Commercial Operation Date |  | Revenue Source |  | Contract Expiry Date
Centralia Thermal No. 1 |  | WA |  | 100 |  | 670 |  | 1971 |  | LTC/Merchant |  | 2020
Centralia Thermal No. 2 |  | WA |  | 100 |  | 670 |  | 1971 |  | LTC/Merchant |  | 2025
Total U.S. Coal Net Capacity |  |  |  |  |  | 1,340 |  |  |  |  |  |

-24-

We own a two-unit 1,340 MW thermal 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) (the “Bill’’) 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. The Bill 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 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 began in 2014 and runs until 2025 when the plant is scheduled to be shut down. Under the agreement, PSE bought 180 MW of firm, base-load power starting in December 2014. In December 2015, the contract increased 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.

On July 30, 2015, the Corporation announced that it was moving ahead with plans to invest U.S.$55 million over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State. The initiative is part of Centralia’s transition from coal-fired operations in Washington, beginning on December 31, 2020. The U.S.$55 million community investment is part of the Bill passed in 2011. This bill was an agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State, closing the Centralia facility’s two units, one in 2020 and the other in 2025. Approved funding for community investment included approximately U.S.$1.1 million incurred as at December 31, 2016.

We 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 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 sourced from the Powder River Basin in Montana and Wyoming. TransAlta is currently party to coal contracts with three suppliers which expire between 2017 and 2025. We expect to continue to source our future coal needs from the Powder River Basin. In December 2014, we began fine coal recovery operations at our Centralia mine. This operation recovers previously wasted coal as part of the mine reclamation process and is expected to provide roughly ten per cent of the fuel use by the Centralia plant.

Under the U.S. Federal Mine Safety and Health Act, TransAlta must report all “significant and substantial” citations at its Centralia mine. During 2016, 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 2016. 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 2016.

Reportable Events – Centralia Mine

Mine or Operating Name/MSHA Identification Number | Total Number of Section 104 Violations for which Citations Received (#) | Total Number of Orders Issued Under Section 104(b) (#) | Total Number of Citations and Orders for Unwarrantable Failure to Comply with Mandatory Health or Safety Standards Under Section 104(d) (#) | Total Number of Flagrant Violations Under Section 110(b)(2) (#) | Total Number of Imminent Danger Orders Issued Under Section 107(a) (#) | 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 | 7 | 0 | 0 | 0 | 0 | $798 | 0 | no | no | 0

-25-

Energy Marketing Segment

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

· gathering and analyzing market trends to enable more effective strategic planning and decision making;

· 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. This includes scheduling, billing and settlement of physical deliveries of natural gas and other fuels;

· the development and execution of our corporate hedging strategy within Board approved parameters; and

· the optimization of the asset fleet to maximize gross margin and mitigation of market risks.

The Energy Marketing segment also derives additional revenue by providing fee based asset management services to third parties, by earning margins on third party gas and power transactions, and by trading electricity and other energy commodities (i.e. fuels). The origination and trading activities are focused on the existing asset and customer footprint of the Corporation.

The segment seeks to measure and manage a number of risks for the assets and for our trading books. The key risk control activities of the Energy Marketing segment include the measurement and management of market, credit, operational, reputational, compliance, and legal risks.

The segment uses Value at Risk (“VaR”), Gross Margin at Risk (“GMaR”), and tail risk measures to monitor and manage the risks within our asset and trading portfolios. VaR and GMaR measure the potential losses that could occur over a given time period due to changes in market risk factors. Back tests are used to provide further sensitivities to the market risks within the portfolio. Compliance, reputational, and legal risks are managed within our legal and compliance policies, and monitoring tools are used to flag compliance risks. The Energy Marketing segment actively manages the risks within approved limits and our policies.

Corporate Segment

Our Corporate segment includes the Corporation’s central financial, legal, administrative and investing functions.

Non-Controlling Interests

Our subsidiaries and operations that have non-controlling interests are as follows:

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 held by Canadian Power Holdings Inc., a subsidiary of Cheung Kong Infrastructure Holdings Limited.

TA Cogen holds an interest in the 790 MW Sheerness thermal generation facility in Alberta and the 118 MW Fort Saskatchewan natural gas-fired cogeneration facility in Alberta. TA Cogen also holds an interest in three natural gas-fired cogeneration facilities located in Ontario: (i) the 108 MW Mississauga Facility; (ii) the 74 MW Ottawa plant; and (iii) the 68 MW Windsor plant. Descriptions of these facilities, ownership levels and contract expiry dates are provided under the headings “Canadian Gas Business Segment” and “Canadian Coal Business Segment” in this AIF.

-26-

Kent Hills

We hold, through our ownership of TransAlta Renewables, an 83 per cent interest in the 150 MW Kent Hills wind farm located in New Brunswick. Description of the facility is provided under the heading “Wind and Solar Business Segment” in this AIF.

TransAlta Renewables

As of December 31, 2016, we hold an approximate 64 per cent interest in TransAlta Renewables, which is a publicly traded entity. We remain committed to maintaining our position as the majority shareholder of TransAlta Renewables with a goal of maintaining our ownership interest between 60 to 80 per cent.

TransAlta Renewables completed its initial public offering in August of 2013. In connection with the offering, we transferred to TransAlta Renewables certain wind and hydro power generation assets.

On December 20, 2013, we sold to TransAlta Renewables an economic interest in a 144 MW wind farm located in the State of Wyoming for payment equal to U.S.$102 million. The Wyoming wind farm is managed by TransAlta under the terms of the Management and Operational Services Agreement and is operated by NextEra Energy.

On May 7, 2015, we sold to TransAlta Renewables an economic interest based on the cash flows of our Australian assets. The portfolio, held by TransAlta Energy (Australia) Pty Ltd, consists of six operating assets with an installed capacity of 425 MW, the 150 MW South Hedland project currently under construction, as well as a 270 km gas pipeline. The combined value of the Australian Transaction was approximately $1.78 billion. At the closing of the Australian Transaction, TransAlta Renewables paid us $216.9 million in cash as well as approximately $1,067 million through the issuance of a combination of common shares and Class B shares in the capital of TransAlta Renewables.

On January 6, 2016, we sold to TransAlta Renewables an economic interest in the Corporation’s Sarnia cogeneration plant, Le Nordais wind farm and Ragged Chute hydro facility for a combined value of $540 million. The Canadian Assets consist of approximately 611 MW of contracted power generation assets located in Ontario and Quebec. The Corporation received cash proceeds of $172.5 million, a $215 million convertible unsecured subordinated debenture and approximately $152.5 million in common shares of TransAlta Renewables. In November 2016, the economic interest was converted to direct ownership of the entities that own the Sarnia cogeneration plant, Le Nordais wind farm and Ragged Chute hydro facility.

We provide all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets.

PPAs

Renewables PPAs

In August of 2013, we entered into long-term power purchase agreements with certain subsidiaries of TransAlta Renewables (each a “Merchant Subsidiary”) providing for the purchase by TransAlta, for a fixed price, of all of the power produced at certain merchant facilities (the “Renewables PPAs”). The initial price payable in 2013 by TransAlta for output under the Renewables PPAs was $30.00/MWh for wind facilities and $45.00/MWh for hydroelectric facilities, which amounts are adjusted annually for changes in the Canadian consumer price index. The Canadian consumer price index adjusted prices for 2017 are $31.82/MWh for wind facilities and $47.731/MWh for hydroelectric facilities. Under the terms of each Renewables PPA, the Merchant Subsidiary is under no obligation to deliver any specified amount of energy and, in no event, shall any penalties or curtailment payments be payable under the Renewables PPA. The Merchant Subsidiary will assume all operating and generating risk and TransAlta will only be required to purchase power that is actually produced.

-27-

Each Renewables PPA has a term of 20 years or end of asset life, where end of asset life is less than 20 years. Each Renewables PPA may be terminated by: (a) the mutual agreement of the parties; (b) the Merchant Subsidiary upon the occurrence of a material default by TransAlta; and (c) TransAlta (i) upon the occurrence of a material default by the Merchant Subsidiary; (ii) upon a change of control of TransAlta Renewables; or (iii) upon a change of control of the Merchant Subsidiary.

Alberta PPAs

All of our Alberta thermal and hydroelectric facilities, other than the Keephills 3, Genesee 3, Belly River, Pocaterra, 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 Alberta 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, Pocaterra, 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.

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 2017 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 buyers under the Alberta PPAs are permitted to return their respective PPAs in certain circumstances to the Balancing Pool. In early 2016, the buyers gave notice to the Balancing Pool of the termination of the PPAs for Sundance A, B, and C, Sheerness, and Keephills. The Balancing Pool confirmed the terminations of the PPAs for Sundance A, B, C, and Sheerness in late 2016 but has not confirmed the termination of the Keephills PPA. For those PPAs that are terminated, the Balancing Pool has assumed the role of buyer and continues to make the energy payment and the capacity payment to TransAlta. It is not known if or when the Keephills PPA will be terminated.

In addition, the Balancing Pool may elect to fully terminate any PPA that has been returned to it, with the result that TransAlta would no longer be bound by the PPA. In such circumstances, the Balancing Pool must provide

-28-

TransAlta with notice of the termination and a lump-sum payment, related to the closing net book value of the generating unit, in connection with such termination. 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.

Competitive Environment

We are the largest generator of electricity in Alberta, measured by capacity. In addition, we own and operate generating assets in British Columbia, Ontario, Québec, New Brunswick, the State of Washington, the State of Wyoming, the State of Minnesota, the State of Massachusetts, and Western Australia.

The power generation industry in North America is highly competitive and includes a large number of power producers. We compete against independent power producers, utilities that produce power for sale in the merchant market, both public and private investors, and financial intermediaries. We compete in Alberta in a deregulated wholesale power market, and in other jurisdictions that range from partially-regulated to fully regulated wholesale power markets. In Alberta, a large portion of our capacity is subject to Alberta PPAs. Please see the section entitled “Alberta PPAs” above in this AIF for a description of these contracts. The ability to compete in deregulated or partially regulated markets is often driven by our cost to produce power and our reliability.

We expect electricity demand growth to be relatively restrained in the current economic environment, but in the longer 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 longer term demand, new investment in natural gas and renewable generation is expected to replace expected coal retirements in response to government policy initiatives. 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

Approximately 60 to 65 per cent of our capacity is located in Alberta and more than 65 per cent of it is subject to legislated Alberta PPAs, which were put in place in 2001 to facilitate the transition from regulated generation to the current energy market in the province. Alberta PPAs expire at the end of 2017 (Sundance 1 and 2) and the end of 2020 (Keephills 1 and 2, Sundance 3 to 6, Sheerness, and Hydro). Coal generation sold under Alberta PPAs retain some exposure to market prices as we pay penalties or receive payments for production below or above, respectively, targeted availability based upon a rolling 30-day average of spot prices. We can also retain proceeds from the sale of energy and ancillary services in excess of obligations on our Hydro Alberta PPAs (“hydro peaking”). We enter into financial contracts to reduce our exposure to variable power prices for the significant portion of our remaining generation.

Following the decrease in oil prices, Alberta’s annual average demand growth decreased by approximately 1.1 per cent in 2016 compared to 2015. Concurrently over 2015 and 2016, approximately 127 MW of gas generation capacity was added to the market. Power pool prices trended to their lowest levels in the last 10 years, dropping to an average of $18/MWh from $33/MWh in 2015. The decline impacted merchant wind and hydro peaking, which are the portions of our portfolio we cannot effectively hedge due to the intermittency of wind generation and resource uncertainty and the notional size of the PPA pertaining to hydro.

Our current share of offer control in the province is approximately 12 per cent. After expiry of the PPAs in 2021, our share of offer control is forecast to increase to approximately 28 per cent depending on load and supply growth in the province.

Alberta’s Climate Leadership Plan, may alter Alberta’s competitive landscape. Currently, the marginal cost of generating power from coal is generally most competitive over alternate sources, excluding renewables and must-run cogeneration. If implemented as planned, after the carbon pricing and allowance rules enter into effect in 2018, we expect the incremental cost to coal generation could increase significantly and the production from coal plants could be dispatched after highly efficient combined-cycle gas sources, potentially resulting in lower coal production

-29-

and reduced margins. Power demand growth could also decrease as a result of energy efficiency initiatives. We expect that the financial impact of the anticipated decrease in our coal production volumes and higher compliance costs could be partially offset by power price increases, as well as higher benefits from allowances generated by our renewable sources. Until 2020, the impact of carbon prices is limited due to the pass-through of compliance costs to buyers under the legislated Alberta PPAs at contracted plants.

We expect that the elimination of current excess system capacity and future growth in Alberta will be primarily driven by the retirement of coal units over the next 15 years. Alberta’s Climate Leadership Plan projects the replacement of two-thirds of coal production through renewable sources and one-third through gas. We believe that our extensive portfolio of assets provides us with brownfield development opportunities in wind, solar, hydro, and gas that provides us a cost advantage over competitors for construction of new builds. In addition, pursuant to our Memorandum of Understanding (“MOU”) with the Government of Alberta, we expect to work collaboratively to enable our coal plants to transform to natural gas and to begin to develop our Brazeau Pumped Storage project, one of the leading hydro power projects on the drawing board in Canada.

U.S. Pacific Northwest

Our capacity in the U.S. Pacific Northwest is comprised of our 1,340 MW Centralia coal plant. Half of the plant capacity is set to retire at the end of 2020, and the other half at the end of 2025.

System capacity in the region is primarily comprised of hydro and gas generation, with some wind additions over the last few years in response to government programs favouring renewable generation. Demand growth in the region has been limited, and further constrained by emphasis on energy efficiency. Our Centralia coal plant can effectively compete against gas generation, although depressed gas prices following the expansion of shale gas production in North America has added to the downward pressure on power prices.

Our competitiveness is enhanced by our long-term contract with Puget Sound Energy for up to 380 MW over the remaining life of the facility. The contract and our hedges allow us to satisfy power requirements from the market when prices fall below our marginal costs of production.

We maintain an opportunity to redevelop Centralia as a gas plant after coal capacity retires, with permitting provided by our agreement for coal transition established with the State of Washington in 2011.

Contracted Gas and Renewables

The market for development or acquisition of gas and renewable generation facilities is highly competitive in all markets in which we operate. Our solid record as operator and developer supports our competitive position. We expect, where possible, to reduce our cost of capital and improve our competitive profile by using project financing and leveraging the lower cost of capital with TransAlta Renewables. In the United States, our substantial tax attributes further increase our competitiveness.

While depressed commodity prices have reduced sectoral growth in the oil, gas, and mining industries, the change is also creating opportunities for us as a service provider as some of our potential customers are more carefully evaluating non-core activities and driving for operational efficiencies. In renewables, we are primarily evaluating greenfield opportunities in Western Canada or acquisitions in other markets in which we have existing operations. We maintain highly qualified and experienced development teams to identify and develop these opportunities. During the fourth quarter of 2016, we entered into a NUG Contract with the IESO for our Mississauga Facility. The NUG Contract takes effect on January 1, 2017, and we have agreed to terminate the prior contract with the OEFC early, which would have otherwise terminated in 2018. See “General Developments of the Business – Generation and Business Development.” The NUG Contract provides us with additional financial flexibility to pay down upcoming debt maturities in this AIF.

Some of our older gas plants are now reaching the end of their original contract life. The plants generally have a substantial cost advantage over new builds and we have been able to add value by re-contracting these plants with limited life-extending capital expenditures. We have recently extended the life of our Ottawa, Windsor, and Parkeston plants in this manner.

Australia

-30-

The Department of Treasury for Western Australia expects that the gross state product will continue to grow at relatively low rates by historical standards. The Department of Treasury for Western Australia has forecasted Western Australia’s annual growth in gross state product to range from 1.0 per cent to 3.25 per cent for the period from 2017 to 2020. Electricity demand growth is expected to be slow in response to much lower industrial investment in the region. The Australian Energy Market Operator (“AEMO”) forecasts the 10 year energy consumption growth rates at about 1.8 per cent (2013/14 to 2023/24), with peak demand growth rates being forecast at 2.1%.

Regulatory Framework

Below is a description of the regulatory framework of the markets which are material to the Corporation.

Alberta

Since January 1, 1996, new generating capacity initiatives in Alberta have been undertaken by independent power producers (“IPP”) and have been subject to market forces, rather than rate regulation. Power from commercial generation is cleared through a wholesale electricity market. Power is dispatched in accordance with an economic merit order administered by the AESO, based upon offers by generators to sell power. The Market Surveillance Administrator for the Province of Alberta is an independent entity responsible for monitoring and investigating the market behaviour of market participants, including the AESO and the Balancing Pool, and enforcing compliance with all applicable legislation, regulations, AESO and AUC rules. The AUC oversees electricity industry matters, including new power plant and transmission facilities, the distribution and sale of electricity and retail natural gas. The AUC is also responsible for approving the AESO’s rules and for determining penalties and sanctions on any participant found to have contravened market rules.

On November 22, 2015, the Government of Alberta announced its Climate Leadership Plan. The Climate Leadership Plan established several environmental and energy targets for Alberta. Please refer to the “Environmental Risk Management - Ongoing and Recently Passed Environmental Legislation” of this Annual Information Form for more information.

On May 24, 2016, the Government of Alberta passed the Climate Leadership Implementation Act which establishes the carbon tax framework for its application to fuels. It is expected that additional regulations will be developed governing the treatment of large industrial emitters. The Climate Leadership Plan will be implemented for the electricity sector on January 1, 2018.

On November 23, 2016, the Government of Alberta announced reforms to the electricity market which is to include a capacity market. The details of the capacity market design elements have yet to be completed. The AESO has been tasked with designing and implementing the capacity market. The process is expected to take three years with the first procurement expected in 2019.

Ontario

Ontario’s electricity market is a hybrid market that includes a wholesale spot electricity market, as well as regulated prices for certain electricity consumers and long-term contracts for the purchase of power issued by the IESO. The Ontario Ministry of Energy takes a lead role in defining the electricity mix to be procured by the IESO, which has the mandate to develop a detailed integrated power supply plan, to procure the electricity generation in that plan and to manage contracts for privately owned generation. The IESO is responsible for managing the Ontario wholesale market and for ensuring the reliability of the electric system in Ontario. As of January 2015, the Ontario Power Authority and the IESO merged into a single entity and continue as IESO. The IESO’s mandate, which is to increase the amount of clean and renewable energy in Ontario’s electric system, remains unchanged. The electricity sector is regulated by the Ontario Energy Board.

On February 25, 2016, Ontario released draft regulations for its GHG cap-and-trade program that were finalized on May 19, 2016. The regulations became effective January 1, 2017, and will apply to all fossil fuels used for electricity generation. The majority of our gas-fired generation in Ontario will not be significantly impacted by virtue of change-in-law provisions within existing power purchase agreements.

Australia

Australia has two separate electricity markets, the National Electricity Market and the Wholesale Electricity Market (“WEM”), as well as two smaller vertically integrated utilities. The WEM, where our Australian assets are located, includes the South West Interconnected System.

-31-

On September 30, 2015, the Minister for Energy announced that the Australian Government had decided to transfer several operational and market functions in the WEM to the Australian Energy Market Operator (“AEMO”). Functions previously performed by the Independent Market Operator, including administering the Gas Bulletin Board and developing the annual Gas Statement of Opportunities, have been transferred to AEMO. The residual functions of the Independent Market Operator were to be reallocated to other entities and, thereafter, the Independent Market Operator would be abolished.

On November 23, 2016, Energy Industry (Rule Change Panel) Regulations 2016, Electricity Industry (Wholesale Electricity Market) Amendment Regulations (No.2) 2016 and Gas Services Information Amendment Regulations (No.2) 2016 were published. These provisions enable the establishment of the Rule Change Panel, transfer rule-making functions from the Independent Market Operator to the Rule Change Panel and implement a new function for the Economic Regulation, which is to support the Rule Change Panel through the provision of secretariat services. Compliance and enforcement functions have also been transferred from the Independent Market Operator to the Economic Regulation Authority.

Competitive Strengths

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

Operating strength – Our gas, wind and hydro fleet performance and our cost structure have outperformed industry standards. Our Canadian gas fleet outperformed the average forced outage rate of our competitors for the time period 2013 to 2014. Based on the North American benchmark database of IHS Inc., our wind farms installed between 2006 to 2008 are in-line with other owners, and for wind farms installed between 2009 to 2010, we are performing slightly better than peers based on our $/MW-year cost structure. The majority of our hydro operations have performed better than or in-line with peers based on the 2015 Navigant Consulting benchmark for their respective size and age. We continue to strive to be leading performers in the operation of our facilities. In addition, availability at our operated Alberta coal facilities beat the 2014 Solomon benchmark for comparable plants.

Stable cash flow base – Through the use of Alberta PPAs and long-term contracts, approximately 73 per cent of our capacity is contracted over the next two 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 an interest in a diverse mix of fuels used for the generation of electricity, including coal, natural gas, hydro, wind, and solar. 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, investment and market experience.

Energy Marketing expertise – We believe that our Energy Marketing 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.

Wind Generation – Through our ownership interest in TransAlta Renewables, we are one of the largest owners and operators 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.

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

-32-

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.

Canadian Federal Government

In November 2016, the Canadian federal government announced that coal-fired generation would be phased out by 2030, following a similar commitment by the Alberta provincial government in November 2015. These two decisions changed the coal plant closure requirements, which had previously been guided by the federal regulations that became effective on July 1, 2015 which provided for up to 50 years of life for coal units. According to the new shut-down requirements, the Corporation’s older coal units (which retire prior to 2030) will be guided by the 50-year life rule, while newer units (which were previously scheduled to retire post-2030) will face the new 2030 shutdown date. In November 2016, the Corporation signed the Off-Coal Agreement with the Government of Alberta that confirmed the 2030 shutdown commitment for the impacted units.

On November 21, 2016, the Canadian federal government announced that the Department of Environment and Climate Change will be developing regulations for gas-fired generation. The announcement confirmed plans to include specific rules for coal-to-gas converted units, including a proposed 15-year life and a separate emissions intensity standard. The Canadian federal government will conduct consultations on the proposed regulation in the first two quarters of 2017. Finalized regulations are currently expected by the end of 2018.

On October 3, 2016, the Canadian federal government announced its intention to implement a national price on GHG emissions. Under this proposal, beginning in 2018, there would be a price of $10 per tonne of carbon dioxide equivalent emitted, rising to $50 per tonne by 2022, or a comparable reduction in GHGs under a cap-and-trade program. The application of the price would be co-ordinated with provincial jurisdictions. We do not yet know how such a price mechanism will affect our operations.

Alberta

On November 22, 2015, the Government of Alberta announced through the Climate Leadership Plan its intent, among other things, to phase out emissions from coal-fired generation by 2030, replace two-thirds of the retiring coal-fired generation with renewable generation, and impose a new carbon price of $30 per tonne of CO2 emissions based on an industry-wide performance standard. On March 16, 2016, the Government of Alberta announced the appointment of a coal phase-out facilitator (the “Facilitator”) to work with coal-fired electricity generators, the AESO, and the Government of Alberta to develop options to phase out emissions from coal-fired generation by 2030. The Facilitator was tasked with presenting options to the Government of Alberta that will strive to maintain the reliability of Alberta’s electricity grid, maintain stability of prices for consumers, and avoid unnecessarily stranding capital.

In March 2016, the Government of Alberta began development of its renewable energy procurement process design for the Alberta Electric System Operator to procure a first block of renewable generation projects to be in-service by mid-2019.

On May 24, 2016, the Government of Alberta passed the Climate Leadership Implementation Act which establishes the carbon tax framework for its application to fuels. It is expected that additional regulations will be developed in 2017 governing the treatment of large industrial emitters. The Climate Leadership Plan will be implemented for the electricity sector on January 1, 2018. On September 14, 2016, the Government of Alberta reconfirmed its commitment to achieve 30 per cent renewables in Alberta’s electricity energy mix by 2030.

On November 24, 2016, we entered into an agreement with the Government of Alberta on transition payments for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before December 31, 2030. The affected plants are not, however, precluded from generating electricity at any time by any method other than the combustion of coal. Under the terms of the Off-Coal Agreement, we will receive annual cash payments of approximately $37.4 million, net to the Corporation, commencing in 2017 and terminating in 2030. Receipt of the payments is subject to terms and conditions including the cessation of all coal-fired emissions in 2030. Other conditions include maintaining prescribed spending on investment and investment related activities in Alberta, maintaining a significant business presence in Alberta (including through the maintenance of prescribed employment levels), and maintaining spending on programs and initiatives to support the communities surrounding the plants, and the employees of the Corporation negatively impacted by the phase-out of coal generation and the fulfillment of all obligations to affected employees.

Additionally, we announced that we had reached an understanding with the Government pursuant to a Memorandum of Understanding to collaborate and cooperate in the development of a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation, facilitate existing and new renewable electricity development through supportive and enabling policy, and ensure existing generation and new electricity generation are able to effectively participate in the recently announced capacity market to be developed for the Province of Alberta.

Since 2007, we have incurred costs as a result of GHG legislation in Alberta. On June 29, 2015, the Alberta Government announced an increase to the Specified Gas Emitters Regulation as follows:

· on January 1, 2016, an increase in the GHG reduction obligation for large emitters from 12 per cent to 15 per cent of emissions, with the compliance price of the technology fund rising from $15 per tonne to $20 per tonne; and

· on January 1, 2017, a further increase to a 20 per cent reduction requirement and a $30 per tonne compliance price.

-33-

Our exposure to increased costs as a result of environmental legislation in Alberta is mitigated to some extent through change-in-law provisions in our PPAs that allow us the opportunity to recover capital and operating compliance costs from our PPA customers. The GHG offsets created by our Alberta wind facilities are expected to increase in value through 2017, as GHG emitters can use them as compliance instruments in place of contributing to the technology fund. As part of the Climate Leadership Plan, the government has stated its intention to establish a new system of obligations and allowances, benchmarked against highly efficient gas generation, beginning in 2018. The initial compliance price would be set at $30 per tonne, escalating annually.

In Alberta there are additional requirements for coal-fired generation units to implement additional air emission controls for oxides of NOx and SO 2 once the units reach the end of their respective PPAs, in most cases in 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”). The release of the federal regulations in 2012 adopted by the Government of Canada and the Government of Alberta, and the accelerated coal-fired generation retirement schedule, creates a potential misalignment between the CASA air pollutant requirements and schedules, and the retirement schedules for the coal plants, which in themselves will result in significant reductions of NOx, SO2, and particulate emissions, something which has been identified as a matter yet to be addressed in the MOU.

The Government of Alberta’s Renewable Electricity Program is intended to encourage the development of 5,000 MW of new renewable electricity capacity by 2030. The AESO is currently soliciting interest in the first competitive procurement for 400 MW under the program. Proponents must submit an expression of interest by late March 2017. The process will be followed by a request for qualification in late April 2017, request for proposal in mid-September 2017 and successful proponents announced in December 2017. Eligible projects must be 5 MW or larger and can be hydro, wind, solar, and certain biomass. The successful projects will be awarded a Renewable Electricity Supply Agreements that utilizes an indexed renewable energy credit or contract for difference mechanism that will fix the price to the proponent over 20 years. The contracts are expected to require the facility to be operational by 2019.

The Government of Alberta has tasked the AESO with transitioning Alberta’s energy-only market to a capacity market structure. The capacity market will help to ensure that there is sufficient supply adequacy as over 6,000 MW of coal generation retires by 2030. The new market structure is expected to reduce the reliance on scarcity pricing, which drives energy price volatility and the price signal for new investment, and compensate resource owners with monthly capacity payments for making their capacity available in the energy and ancillary services market. The AESO plans to engage stakeholders in determining the design and implementation of the capacity market over 2017 and 2018 and conduct the first auction in 2019 with a contract delivery year targeted for 2021. The AESO has suggested they will need new capacity in 2021.

Ontario

On February 25, 2016, Ontario released draft regulations for its GHG cap-and-trade program that were finalized on May 19, 2016. The regulations became effective January 1, 2017, and will apply to all fossil fuels used for electricity generation. The majority of our gas-fired generation in Ontario will not be significantly impacted by virtue of change-in-law provisions within existing power purchase agreements.

United States

On August 3, 2015, President Obama announced the Clean Power Plan. The plan sets GHG emission standards for new fossil-fuel based power plants and emission limits for individual states. States will have the option of interpreting their limits in mass-based (tonnes) or rate-based (pounds per megawatt hour) terms. The plan is intended to achieve an overall reduction in GHG emissions of 32 per cent from 2005 levels by 2030. It will be implemented in two stages: (i) 2022 to 2029, and (ii) 2030 and beyond. The recent administration change in the executive branch of the United States is expected to result in a de-emphasis of the Clean Power Plan.

In December 2016, Washington State Governor Jay Inslee released a budget tax proposal that included a carbon tax, where our U.S. Coal plant is located. Under the Governor’s proposal, Centralia would be exempted from any carbon tax due to the TransAlta Energy Bill agreed to between TransAlta and the Washington State Government in 2011. The Washington Government brought into force in 2016 the Clean Air Rule to limit carbon emissions from in state GHG emitters.

These additional regulations for existing power plants are not expected to significantly affect our U.S. operations. TransAlta has agreed with Washington State to retire units in 2020 and 2025. This agreement is formally part of the State’s climate change program. We believe that there will be no additional GHG regulatory

-34-

burden on our U.S. Coal segment given these commitments. The related TransAlta Energy Bill was signed into law in 2011 and provides a framework to transition from coal to other forms of generation.

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 Bill passed in 2011.

Effective January 2013, direct deliveries of power to the California Independent System Operator are subject to Cap and Trade Regulations established by the California Air Resource Board. We continue to monitor our GHG inventory into California.

In September 2016, Wyoming’s Interim Joint Revenue committee voted down, by a significant margin, a suggested increase to taxes on wind generation. The bill would have increased the current wind tax from $1/MWh to $5/MWh. In January, a private member of the House of Representatives resubmitted a similar bill to Wyoming’s Revenue Committee. This bill was also defeated by a significant margin at committee.

Australia

On December 13, 2014, the Australian government enacted legislation to implement the Emissions Reduction Fund (the “ERF”). The $2.55 billion ERF is the centrepiece of the Australian government’s policy and provides a policy framework to cut emissions by five per cent below 2000 levels by 2020. The first auction was held in April 2015 and contracts for 47 million tonnes of emissions reductions were awarded at an average price of $13.95 per tonne. The ERF’s safeguard mechanism, commencing from July 1, 2016, will ensure emissions reductions purchased by the Australian government through the ERF are not displaced by significant increases in emissions elsewhere in the economy. The ERF and its safeguard mechanism provide incentives to reduce emissions across the Australian economy. The Government has also committed to develop a National Energy Productivity Plan with a target to improve Australia’s energy productivity by 40 per cent between 2015 and 2030.

On June 23, 2015, the Australian government reformed the Renewable Energy Target scheme, which is expected to double the amount of large-scale renewable energy being delivered compared to current levels and would result in approximately 23.5 per cent of Australia’s electricity generation in 2020 being generated from renewable sources. The scheme was initially introduced in 2001 with three objectives: (i) to establish a mandatory renewable energy target to be achieved in 2020; (ii) to provide incentives for large-scale renewable energy generators in the form of one large-scale generation certificate earned for each MWh of generation; and, (iii) to require retailers and wholesale industrial customers to purchase a specified volume of their electricity from large-scale renewable sourced electricity or incur a penalty of AUD$65/MWh on any shortfall. The amendments reduced the annual targets for large-scale renewable sourced electricity down from 41,000 GWh in 2020 to 33,000 GWh in 2020, held constant at this level until 2030. It is estimated that this will require an additional 5,000 to 6,000 MW of new capacity to be installed to add to the slightly more than 4,000 MW already operating.

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.

-35-

On July 27, 2015, we announced the acquisition of 71 MW of long-term contracted renewable generation assets. The assets acquired include 21 MW of solar projects located in Massachusetts and a 50 MW wind facility in Minnesota. The assets are contracted under long-term power purchase agreements ranging from 20 to 30 years with several high quality counterparties.

On August 31, 2015, as part of the Poplar Creek contract restructuring, we acquired Suncor’s interest in two wind farms: the 20 MW Kent Breeze facility located in Ontario and a 51 per cent interest in the 88 MW Wintering Hills facility located in Alberta. On March 1, 2017, we sold our 51% interest in Wintering Hills. See “General Developments of the Business – Recent Developments” in this AIF.

Our 68 MW New Richmond wind facility was commissioned in March 2013 and in December 2013 TransAlta acquired a 144 MW wind farm in Wyoming. The Wyoming Wind Farm is fully operational and contracted under a long-term PPA until 2028 with an investment grade counterparty. The economic interest in the wind farm was subsequently acquired by TransAlta Renewables from a subsidiary of the Corporation in consideration for a payment equal to the original purchase price of the acquisition.

TransAlta believes that a larger renewable portfolio provides increased flexibility in generation and creates incremental environmental value through renewable energy certificates or through emission offsets. In addition, we have developed policies and procedures in order to comply with regulatory guidance and to lessen any environmental disruption caused by our renewable power resources, which includes monitoring noise and the avian impacts at our wind generation facilities.

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 to meet the Province’s 70 per cent reduction objectives and have carried out additional testing to allow for further mercury control if necessary. At our Centralia coal plant we have been achieving 70 per cent mercury capture since 2012 on a voluntary basis. Our 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 technology, which is consistent with the technology that is currently in use at Genesee 3. Uprate projects at our Keephills, Sundance and Sheerness plants have improved the energy and emissions efficiency of those units.

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

Policy Participation

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

Following the announcement of Alberta Climate Leadership Plan, TransAlta has negotiated with the Government of Alberta, using a principles based approach, to ensure the Corporation has the certainty and capacity needed to invest in clean power. An important aspect of these negotiations was the Government of Alberta’s commitment to treat coal-fired generators fairly and not unnecessarily strand capital. In November 2016, the Government of Alberta and TransAlta entered into a binding Off-Coal Agreement that provides compensation for the stranded value on the Keephills 3, Genesee 3 and Sheerness coal plants that had useful lives beyond 2030.

Additionally, we reached an understanding with the Government of Alberta pursuant to the MOU to collaborate and cooperate in the development of a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation, facilitate existing and new renewable electricity development through supportive and enabling policy, and ensure existing generation and new electricity generation are able to effectively participate in the recently announced capacity market to be developed for the Province of Alberta. Specifically, the parties undertook collaboration to, among other things:

-36-

· move toward a Capacity Market, commencing 2021, compared to the current Energy-only market. Under a Capacity Market, generators are compensated for their available capacity;

· develop a policy and facilitate the economic conversion of some coal-fired generation to natural gas-fired generation in Alberta, including securing regulatory cooperation from the Federal Government; and

· develop a policy to address the value of carbon reductions in the generation of electricity from existing wind and hydro production.

The MOU does not create any legally binding obligations between the Government of Alberta and the Corporation and does not impose any obligations on, or constrain the discretion and authority of the Government. The details of the capacity market design elements have yet to be completed. TransAlta will be advocating to ensure that the new market design will improve market reliability and provide greater revenue certainty for generators which will drive needed investment in Alberta.

Offsets Portfolio

TransAlta maintains a GHG emissions offset portfolio with a variety of instruments that 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.

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 they cannot perform the maintenance themselves. 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.

-37-

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.

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 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 additional cost 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 which in themselves may not be aligned and may imposed varying obligations on us in the jurisdictions in which we operate and which could increase the amount of our 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.

On November 22, 2015, the Government of Alberta announced the Alberta Climate Leadership Plan. In respect of the power generation sector, the Climate Leadership Plan targets the retirement of coal generation in Alberta by 2030, replacement of two-thirds of the retiring coal-fired generation with renewable generation (to achieve a 30 per cent share of the provincial electrical system by 2030), and establishment of a new system of GHG obligations and allowances benchmarked against highly efficient gas-fired generation beginning in 2018, at the increased price of $30 per tonne. Additionally, the Government of Alberta has announced the intention to transition the energy-only market to a capacity market. We are carefully reviewing the climate change policy announced by the Government of Alberta to assess how it will impact our business and strategy moving forward. Given this uncertainty in policy, it could have a material adverse effect upon our consolidated financial results.

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

-38-

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 in both Canada and the United States. 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. 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. In terms of TransAlta’s existing gas-fired facilities, we currently have change-in-law provisions allowing flow-through of 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.

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.

Unexpected changes in the cost of maintenance or in the cost and durability of components for the Corporation’s facilities may adversely affect its results of operations.

Unexpected increases in the Corporation’s cost structure that are beyond the control of the Corporation could materially adversely impact its financial performance. Examples of such costs include, but are not limited to: unexpected increases in the cost of procuring materials and services required for maintenance activities, and unexpected replacement or repair costs associated with equipment underperformance or lower-than-anticipated durability.

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.

-39-

We may fail to meet financial expectations.

Our quarterly revenue and results of operations are difficult to predict and fluctuate from quarter to quarter. Our quarterly results of operations are influenced by a number of factors, including the risks described in this AIF, many of which are outside of our control, which may cause such results to fall below market expectations.

Although we base our planned operating expenses in part on our expectations of future revenue, a significant portion of our expenses are relatively fixed in the short-term. If revenue for a particular quarter is lower than expected, we likely will be unable to proportionately reduce our operating expenses for that quarter, which will adversely affect our results of operations for that quarter.

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 or man-made disasters and other 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 and dyke 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, including natural or induced seismic activity, could potentially cause dam failures at our hydroelectric facilities. The occurrence of dam or dyke failures at any of our hydroelectric or coal 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 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. Reinforcing all dams or dykes 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 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 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 produced 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, degradation, site access, wake and wind shear line losses and wind shear; and the potential impact of topographical variations.

-40-

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 related to that production 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.

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 between 2017 and 2025. The loss of our suppliers or our inability to renew our existing coal contracts for Powder River Basin coal at favourable terms could also significantly affect our ability to serve our customers and have an adverse impact on our financial condition and results of operations.

-41-

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

Adverse changes in general economic and market conditions and, more specifically, in the markets in which we operate 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.

There are risks associated with our 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 Alberta PPAs 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 Alberta 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 in 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 from 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. In addition, there can be no assurance that we will realize sufficient returns under the Alberta PPAs to cover the capital costs we are required to invest under such PPAs.

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.

A power purchaser under an Alberta PPA is permitted to return the Alberta PPA to the Balancing Pool in certain circumstances, including as a result of a change in law that renders the Alberta PPA unprofitable to the power purchaser. In early 2016, the buyers gave notice to the Balancing Pool of the termination of the Alberta PPAs for Sundance A, B and C, Sheerness and Keephills. The Balancing Pool confirmed the termination of such Alberta PPAs, with the exception of Keephills. Following such terminations the Balancing Pool is able to resell, hold or terminate such Alberta PPA in certain circumstances. If the Balancing Pool exercises its ability to terminate an Alberta PPA in respect of a unit that we own, we would be entitled to receive payment equal to the remaining closing net book value of the generating unit. The termination payment by the Balancing Pool could be less than the economic value of the generating unit, which could have a material adverse effect on the Corporation.

The market price for our common shares may be volatile.

The market price for our common shares may be volatile and subject to wide fluctuations in response to numerous factors, many of which are beyond our control, including the following: (a) actual or anticipated fluctuations in our results of operations; (b) recommendations by securities research analysts; (c) changes in the economic performance or market valuations of other companies that investors deem comparable; (d) the loss or resignation of executive officers and other key personnel; (e) sales or perceived sales of additional common shares; (f) significant acquisitions or business combinations, strategic partnerships, joint ventures or capital commitments by or involving our competitors which prove to be ill considered; and (g) trends, concerns, technological or competitive developments, regulatory changes and other related issues in the power generation industry or our target markets.

Financial markets have experienced significant price and volume fluctuations in recent years that have particularly affected the market prices of equity securities of companies and such fluctuations have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the market price of our common shares may decline even if our operating results, underlying asset values or prospects

-42-

have not changed. Additionally, these factors, as well as other related factors, may cause decreases in asset values which may result in impairment losses. Certain institutional investors may base their investment decisions on consideration of our environmental, governance and social practices and performance against such institutions’ respective investment guidelines and criteria, and failure to meet such criteria may result in a limited or no investment in our common shares by those institutions, which could adversely affect the trading price of our common shares.

Our cash dividend payments are not guaranteed.

The payment of dividends is not guaranteed and could fluctuate. The Board has the discretion to determine the amount of dividends to be declared and paid to shareholders. We may alter our dividend policy at any time and the payment of dividends will depend on, among other things, results of operations; financial condition; current and expected future levels of earnings; operating cash flow; liquidity requirements; market opportunities; income taxes; maintenance and growth capital expenditures; debt repayments; legal, regulatory and contractual constraints; working capital requirements; tax laws and other relevant factors. Our short and long-term borrowings may prohibit us from paying dividends at any time at which a default or event of default would exist under such debt, or if a default or event of default would exist as a result of paying the dividend.

Over time, our capital and other cash needs may change significantly from our current needs, which could affect whether we pay dividends and the amount of any dividends we may pay in the future. If we continue to pay dividends at the current level, we may not retain a sufficient amount of cash to finance growth opportunities, meet any large unanticipated liquidity requirements or fund our operations in the event of a significant business downturn. The Board, subject to the requirements of our bylaws and other governance documents, may amend, revoke or suspend our dividend policy at any time. A decline in the market price or liquidity, or both, of our common shares could result if the Board establishes large reserves that reduce the amount of quarterly dividends paid or if we reduce or eliminate the payment of dividends.

We will be dependent on the operations of our facilities for our cash availability. The actual amount of cash available for dividends to holders of our common shares will depend upon numerous factors relating to each of our generation facilities including: operating performance of our generation facilities, profitability, changes in revenues, fluctuations in working capital, capital expenditure levels, applicable laws, compliance with contracts and contractual restrictions contained in the instruments governing any indebtedness. Any reduction in the amount of cash available for distribution from our generation facilities will reduce the amount of cash available to pay dividends to holders of our common shares.

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.

We could suffer lost revenues or increased expenses and penalties if we are unable to operate our generation facilities at a level necessary to comply with our PPAs.

The ability of our facilities to generate the maximum amount of power which can be sold under PPAs is an important determinant of our revenues. Under certain PPAs, if the facility is made available less than the required Availability in a given contract year, penalty payments may be payable to the relevant purchaser by us. The payment of any such penalties could adversely affect our revenues and profitability.

Our revenues may be reduced upon expiration or termination of PPAs.

We sell power under PPAs that expire at various times. In addition, these PPAs may be subject to termination in certain circumstances, including default by the facility or plant owner or operator. When a PPA expires or is terminated, it is possible that the price received by the relevant facility or plant for power under subsequent selling arrangements may be reduced significantly. It is also possible that to the extent a PPA is negotiated after the initial

-43-

PPAs have run their course, the new contract may not be available at prices that permit the continued operation of the affected facility or plant on a profitable basis. If this occurs, the affected facility or plant may be forced to permanently cease operations.

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. Also, variations in sunlight conditions can have an effect on energy production levels from our solar farm.

Ice can accumulate on wind turbine blades in the winter months. The accumulation of ice on wind turbine blades depends on a number of factors, including temperature, and ambient humidity. The accumulation of ice on wind turbine blades can have a significant impact on energy yields, and could result in the wind turbine experiencing more down time. Extreme cold temperatures can also impact the ability of wind turbines to operate effectively and this could result in more downtime and reduced production.

In addition, climate change could result in increased variability to our water and wind resources.

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, regulations and reliability standards are often dynamic and may be revised or re-interpreted 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 audit or investigate our activities in the markets in which we operate or pursue trading. Such audits or investigations may result in sanctions or penalties which may materially affect our future activities, our reputation or our 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.

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. Reputational 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.

-44-

We depend on certain partners that may have interests or objectives which conflict with our objectives and such differences could have a negative impact on us.

We have entered into various types of arrangements with communities or joint venture partners for the operation of our facilities. Certain of these partners may have or develop interests or objectives which are different from or even in conflict with our objectives. Any such differences could have a negative impact on the success of our facilities. We are sometimes required through the permitting and approval process to notify and consult with various stakeholder groups, including landowners, First Nations and municipalities. Any unforeseen delays in this process may negatively impact our ability to complete any given facility on time or at all.

We are dependent on access to parts and equipment from certain key suppliers and we may be adversely affected if these relationships are not maintained.

Our ability to compete and expand will be dependent on having access, at a reasonable cost, to equipment, parts and components which are technologically and economically competitive with those utilized by our competitors. Although we have individual framework agreements with various suppliers, there can be no assurance that these relationships with suppliers will be maintained. If they are not maintained, our ability to compete may be impaired due to lack of access to these sources of equipment, parts or components.

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 rely on technology, mainly on computer, telephone, satellite, cellular and related networks and infrastructure, to conduct our business and monitor the production of our generation facilities. These systems and infrastructure could be vulnerable to unforeseen problems including, but not limited to, vandalism and theft. We have put in place a number of systems, processes, practices and data backups 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 information technology systems are vulnerable to damages from computer viruses, natural disasters, unauthorized access, cyber-attack and other similar disruptions.

Any damage or failure that causes an interruption in operations could have an adverse effect on our customers. Additionally, we protect our generation facility infrastructure against physical damage, security breaches and service disruption from any of a variety of causes. Theft, vandalism, and other disruptions could jeopardize the security of information stored in and transmitted through our systems and network infrastructure, and could result in significant set-backs, potential liabilities, and deter future customers. While we have systems, policies, hardware, practices, data backups and procedures designed to prevent or limit the effect of the failure, interruptions or security breaches of our generation facility and infrastructure, there can be no assurance that these measures will be sufficient and that such failures, interruptions or security breaches will not occur or, if they do occur, that they will be adequately addressed in a timely manner. We closely monitor both preventive and detective measures to manage these risks.

Cyber-attacks may cause disruptions to our operations and could have a material adverse effect on our business.

We rely on our information technology to process, transmit and store electronic information, including information we use to safely operate our assets. Cyber-attacks or other breaches of network or information technology systems security may cause disruptions to our operations. Cyber attackers may use a range of techniques, from manipulating people to using sophisticated malicious software and hardware on a single or distributed basis. Some cyber attackers use a combination or techniques in their attempt to evade safeguards, such as firewalls, intrusion prevention systems and antivirus software found in our systems and networks. A successful attack on our systems, networks and infrastructure may allow for the unauthorized interception, destruction, use or dissemination of our information and may cause disruptions to our operations.

We take measures to secure our infrastructure against potential cyber-attacks that may damage our infrastructure, systems and data. Our cyber security program aligns with industry best practices to ensure that a holistic approach to

-45-

security is maintained. We have implemented security controls to help secure our data and business operations including: access control measures, intrusion detection and prevention systems, logging and monitoring of network activities, and implementing policies and procedures to ensure the secure operations of the business.

While we have systems, policies, hardware, practices, data backups and procedures designed to prevent or limit the effect of the security breaches of our generation facility and infrastructure, there can be no assurance that these measures will be sufficient and that such security breaches will not occur or, if they do occur, that they will be adequately addressed in a timely manner. We closely monitor both preventive and detective measures to manage these risks.

Our facilities rely on national and regional transmission systems and related facilities that are owned and operated by third parties and have both regulatory and physical constraints that could impede access to electricity markets.

Our power generation facilities depend on electric transmission systems and related facilities owned and operated primarily by third parties to deliver the electricity that we generate to delivery points where ownership changes and we are paid. These grids operate with both regulatory and physical constraints which in certain circumstances may impede access to electricity markets. There may be instances in system emergencies in which our power generation facilities are physically disconnected from the power grid, or our production curtailed, for short periods of time. Most of our electricity sales contracts do not provide for payments to be made if electricity is not delivered.

Our power generation facilities may also be subject to changes in regulations governing the cost and characteristics of use of the transmission and distribution systems to which our power generation facilities are connected. Our power generation facilities in the future may not be able to secure access to this interconnection or transmission capacity at reasonable prices, in a timely fashion or at all, which could then cause delays and additional costs in attempting to negotiate or renegotiate PPAs or to construct new projects. In addition, we may not benefit from preferential arrangements in the future. Any such increased costs and delays could delay the commercial operation dates of any new projects and negatively impact our revenues and financial condition.

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.

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.

We use a number of risk management controls conducted by our independent Risk Management group in order to limit our exposure to risks arising from our trading activities. These controls include risk capital limits, VaR, GMaR, tail risk scenarios, position limits, concentration limits, credit limits, and approved product controls. We cannot guarantee that losses will not occur and such losses may be outside the parameters of our risk controls.

-46-

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. and Australian 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 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.

Recovery of the capital investment in power projects generally occurs over a long period of time. As a result, we must obtain funds from equity or debt financings, including tax equity transactions, or from government grants, to help finance the acquisition of projects and to help pay the general and administrative costs of operating our business. Our ability to arrange financing, either at the corporate level or at the subsidiary level (including non-recourse project debt), and the costs of such capital are dependent on numerous factors, including: (a) general economic and capital market conditions; (b) credit availability from banks and other financial institutions; (c) investor confidence and the markets in which we conduct operations; (d) our financial performance; (e) our level of indebtedness and compliance with covenants in our debt agreements; and (f) our cash flow.

An increase in interest rates or a reduction in the availability of project debt financing could reduce the number of projects that we are able to finance. If we are unable to raise additional funds when needed, we could be required to delay acquisition and construction of projects, reduce the scope of projects, abandon or sell some or all of our projects or generation facilities, or default on our contractual commitments in the future, any of which could adversely affect our business, financial condition and results of operations.

TransAlta Corporation’s 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, 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.

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

-47-

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 and the corresponding outlook will not be changed. 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, please see Note 14 section C. III of our audited consolidated financial statements for the year ended December 31, 2016, which financial statements are incorporated by reference herein. Please also see “Documents Incorporated by Reference” in this AIF.

Changes in statutory or contractual restrictions may have an adverse effect on our ability to service debt obligations.

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.

The power generation industry has certain inherent risks related to worker health and safety and the environment that could cause us to suffer unanticipated expenditures or to incur fines, penalties or other consequences material to its business and operations.

The ownership and operation of our power generation assets carry an inherent risk of liability related to worker health and safety and the environment, including the risk of government imposed orders to remedy unsafe conditions and/or to remediate or otherwise address environmental contamination, potential penalties for contravention of health, safety and environmental laws, licenses, permits and other approvals, and potential civil liability. Compliance with health, safety and environmental laws (and any future changes) and the requirements of licenses, permits and other approvals are expected to remain material to our business. The occurrence of any of these events or any changes, additions to, or more rigorous enforcement of, health, safety and environmental laws, licenses, permits or other approvals could have a significant impact on our operations and/or result in additional material expenditures. As a consequence, no assurances can be given that additional environmental and workers’ health and safety issues relating to presently known or unknown matters will not require unanticipated expenditures, or result in fines, penalties or other consequences (including changes to operations) material to our business and operations.

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 hedging 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

-48-

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.

We are not able to insure against all potential risks and may become subject to higher insurance premiums.

Our business is exposed to the risks inherent in the construction and operation of electricity generation facilities, such as breakdowns, manufacturing defects, natural disasters, theft, terrorist attacks and sabotage. We are also exposed to environmental risks. We maintain insurance policies, covering usual and customary risks associated with our business, with credit worthy insurance carriers. Our insurance policies, however, do not cover losses as a result of force majeure, natural disasters, terrorist or cyber attacks or sabotage, among other things. In addition, we generally do not maintain insurance for certain environmental risks, such as environmental contamination. Our insurance policies are subject to annual review by the respective insurers and may not be renewed at all or on similar or favourable terms. A significant uninsured loss or a loss significantly exceeding the limits of our insurance policies or the failure to renew such insurance policies on similar or favourable terms could have a material adverse effect on our business, financial condition and results of operations.

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.

The Corporation and its subsidiaries are subject to changing laws, treaties and regulations in and between countries. Various tax proposals in the countries we operate in could result in changes to the basis on which deferred taxes are calculated or could result in changes to income or non-income tax expense. There has recently been an increased focus on issues related to the taxation of multinational corporations. A change in tax laws, treaties or regulations, or in the interpretation thereof, could result in a materially higher income or non-income tax expense which could have a material adverse impact on the Corporation.

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 four collective bargaining agreements, involving 385 of our employees, in 2017. Four collective bargaining agreements representing a total of 160 employees are anticipated to be negotiated in 2018. 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,

-49-

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.

We may pursue acquisitions in new markets that are subject to regulation by various foreign governments and regulatory authorities and to the application of foreign laws. Such foreign laws or regulations may not provide for the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to us currently, which may adversely affect our ability to receive revenues or enforce our rights in connection with any such foreign operations. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may acquire, thus limiting our ability to control the operation of such projects. Any existing or new operations may also be subject to significant political, economic and financial risks, which vary by country, and may include: (a) changes in government policies or personnel; (b) changes in general economic conditions; (c) restrictions on currency transfer or convertibility; (d) changes in labour relations; (e) political instability and civil unrest; (f) regulatory or other changes in the local electricity market; and (g) breach or repudiation of important contractual undertakings by governmental entities and expropriation and confiscation of assets and facilities for less than fair market value.

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.

EMPLOYEES

As of December 31, 2016, we had 2,341 active employees, which figure includes full-time, part-time and temporary employees, of which 1,197 were employed in our Canadian Coal segment (including our SunHills mining operation), 208 were employed in our U.S. coal segment, 240 were employed in our Gas Segment, 96 were employed in our Wind and Solar business, 97 were employed in our Hydro business, 70 were employed in our Energy Marketing business, and the remaining employees were employed in our Corporate segment. Approximately 53 per cent of our employees are represented by labour unions. We are currently a party to 11 different collective bargaining agreements. In 2016, we renewed three of the collective bargaining agreements.

CAPITAL STRUCTURE

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 March 2, 2017, there were 287,903,467 common shares outstanding and 10,175,380 Series A Shares, 1,824,620 Series B Shares, 11,000,000 Series C Shares, 9,000,000 Series E Shares and 6,600,000 Series G Shares outstanding. The Corporation does not have any escrowed securities.

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

-50-

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.

On January 14, 2016, we announced the suspension of the Premium Dividend TM, Dividend Reinvestment and Optional Common Share Purchase Plan.

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 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

12.0 million Series A Shares were issued on December 10, 2010 with a coupon of 4.60 per cent, for gross proceeds of $300 million. On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares. 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

-51-

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, at its option, in whole or in part, on 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 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 (the “T-Bill Rate”) (which means, the average yield expressed as an annual rate on the 90 day Government of Canada treasury bill, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable Floating Rate Calculation Date) 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.

On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares.

Voting Rights

The holders of the Series A Shares are not entitled to any voting rights or to receive notice of or to attend shareholders’ meetings unless dividends on the Series A Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series A Shares will be entitled to receive notice of and to attend all shareholders’ meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series A Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required

-52-

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

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 B Shares

1,824,620 Series B Shares were issued on March 31, 2016. Certain provisions of the Series B Shares are discussed below.

Dividends on Series B Shares

The holders of Series B Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, floating rate 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 conversion, the holders of Series B Shares shall be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends, payable quarterly 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 (the “T-Bill Rate”) (which means, the average yield expressed as an annual rate on the 90 day Government of Canada treasury bill, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable Floating Rate Calculation Date) 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. This spread will apply to both the Series A Shares described above and the Series B Shares and will remain unchanged over the life of the Series B Shares.

Redemption of Series B Shares

The Series B Shares are redeemable by TransAlta, at its option, in whole or in part, on March 31, 2021 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 B Shares of the redemption of all of the Series B Shares, the right of a holder of Series B Shares to convert such Series B Shares shall terminate and we shall not be required to give notice to the registered holders of the Series B Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series B Shares.

Conversion of Series B Shares into Series A Shares

The holders of the Series B Shares have the right to convert all or any of their shares into cumulative redeemable fixed rate first preferred shares, Series A of TransAlta (the “Series A Shares”), subject to certain conditions, on March 31, 2021 and on March 31 in every fifth year thereafter. The holders of the Series A Shares will be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends payable on the last day

-53-

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.

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.

Voting Rights

The holders of the Series B Shares are not entitled to any voting rights or to receive notice of or to attend shareholders’ meetings unless dividends on the Series B Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series B Shares will be entitled to receive notice of and to attend all shareholders’ meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series B Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation

Modification

The provisions attaching to the Series B Shares as a class may be amended with the written approval of all the holders of Series B 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

11.0 million cumulative redeemable rate reset first preferred shares, Series C (the “Series C Shares”) were issued on November 30, 2011, with a coupon of 4.60 per cent, for gross proceeds of $275 million 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.

-54-

Redemption of Series C Shares

The Series C Shares are redeemable by TransAlta, at its option, in whole or in part, on 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 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.

Voting Rights

The holders of the Series C Shares are not entitled to any voting rights or to receive notice of or to attend shareholders’ meetings unless dividends on the Series C Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series C Shares will be entitled to receive notice of and to attend all shareholders’ meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series C Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.

-55-

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

9.0 million cumulative redeemable rate reset first preferred shares, Series E (the “Series E Shares”) for gross proceeds of $225 million, 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 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, at its option, in whole or in part, on 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

-56-

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.

Voting Rights

The holders of the Series E Shares are not entitled to any voting rights or to receive notice of or to attend shareholders’ meetings unless dividends on the Series E Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series E Shares will be entitled to receive notice of and to attend all shareholders’ meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series E Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.

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.

Series G Shares

6.6 million cumulative redeemable rate reset first preferred shares, Series G (the “Series G Shares”) for gross proceeds of $165 million, as discussed in the section entitled “General Development of the Business”. Certain provisions of the Series G Shares are discussed below.

Dividends on Series G Shares

The holders of Series G 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 G 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 the Fixed Rate Calculation Date plus a spread of 3.80 per cent. This spread will apply to both the Series G Shares and the Series H Shares described below, and will remain unchanged over the life of the Series G Shares.

-57-

Redemption of Series G Shares

The Series G Shares are redeemable by TransAlta Corporation, at its option, in whole or in part, on September 30, 2019, 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 G Shares of the redemption of all of the Series G Shares, the right of a holder of Series G Shares to convert such Series G Shares shall terminate and we shall not be required to give notice to the registered holders of the Series G Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series G Shares.

Conversion of Series G Shares into Series H Shares

The holders of the Series G Shares have the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series H of TransAlta (the “Series H Shares”), subject to certain conditions, on September 30, 2019 and on September 30 in every fifth year thereafter. The holders of the Series H 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 3.80 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 3.80 per cent.

The Series G Shares and Series H 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 G Shares and Series H Shares are identical in all material respects.

Voting Rights

The holders of Series G Shares are not entitled to any voting rights or to receive notice of or to attend shareholders’ meetings unless dividends on the Series G Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series G Shares will be entitled to receive notice of and to attend all shareholders’ meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series G Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.

-58-

Modification

The provisions attaching to the Series G Shares as a class may be amended with the written approval of all the holders of Series G 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.

CREDIT RATINGS

The following information concerning 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.

| DBRS | Fitch | Moody’s | S&P
Issuer Rating | BBB | BBB- | Not Applicable | BBB-
Corporate Family Rating | Not Applicable | Not Applicable | Ba1 | Not Applicable
Preferred Shares | Pfd-3(1) | Not Applicable | Not Applicable | P-3(1)
Unsecured Debt/MTNs | BBB | BBB- | Ba1/LGD4 | BBB-
Rating Outlook | Negative | Negative | Stable | Stable

Note:

(1) The outstanding Preferred Shares all have the same rating.

On December 17, 2015, TransAlta Corporation was downgraded to Ba1 (stable) by Moody’s and Moody’s also assigned the Corporation a Ba1 Corporate Family rating. As expected, the direct financial impact of this downgrade has been limited. We have posted additional collateral to certain counterparties, and the cost of borrowing under US$400 million of debt and our credit facilities has been stepped-up in line with contractual provisions. The Corporation maintains investment grade ratings from three credit rating agencies including BBB- (stable outlook) by S&P, BBB (negative outlook) by DBRS and BBB- (negative outlook) by Fitch.

DBRS

DBRS Corporate rating analysis begins with an evaluation of the fundamental creditworthiness of the issuer, which is reflected in an “issuer rating”. Issuer ratings address the overall credit strength of the issuer. Unlike ratings on individual securities or classes of securities, issuer ratings are based on the entity itself and do not include consideration for security or ranking. Ratings that apply to actual securities (secured or unsecured) may be higher, lower or equal to the issuer rating for a given entity. As of December 31, 2016, our issuer rating was BBB (negative) from DBRS. A BBB rating is the fourth highest out of ten categories.

The DBRS preferred share rating scale is used in the Canadian securities market and is meant to give an indication of the risk that a borrower will not fulfill its full obligations in a timely manner, with respect to both dividend and principal commitments. Every DBRS rating is based on quantitative and qualitative considerations relevant to the borrowing entity. Each rating category is denoted by the subcategories “high” and “low”. The absence of either a “high” or “low” designation indicates the rating is in the middle of the category. Preferred shares rated Pfd-3 are of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adverse conditions present which detract from debt protection. Each of the Series A Shares, Series B Shares, Series C Shares, Series E Shares and Series G Shares have been rated Pfd-3 (negative) by DBRS. The Pfd-3 rating is the third highest out of six categories.

The DBRS long-term rating scale provides an opinion on the risk of default. That is, the risk that an issuer will fail to satisfy its financial obligations in accordance with the terms under which an obligation has been issued. Ratings

-59-

are based on quantitative and qualitative considerations relevant to the issuer, and the relative ranking of claims. All rating categories other than AAA and D also contain subcategories “(high)” and “(low)”. The absence of either a “(high)” or “(low)” designation indicates the rating is in the middle of the category. Debt securities rated BBB are of adequate credit quality. The capacity for the payment of financial obligations is considered acceptable, but may be vulnerable to future events. As of December 31, 2016, our senior unsecured long-term debt is rated BBB (negative) by DBRS. The BBB rating category is the third highest of ten categories for long term obligations.

Fitch

As of December 31, 2016, our Fitch long term Issuer Default Rating (IDR) and senior unsecured rating was BBB- with a negative outlook. The Fitch rating system describes a BBB rating as good credit quality. ‘BBB’ ratings indicate that expectations of default risk are currently low. The capacity for payment of financial commitments is considered adequate but adverse business or economic conditions are more likely to impair this capacity. The modifiers + or - may be appended to a rating to denote relative status within major rating categories. Such suffixes are added to Long-Term Issuer Default Ratings between AA and B. A BBB rating is the fourth highest of 11 rating categories.

Ratings of individual securities or financial obligations of a corporate issuer address relative vulnerability to default on an ordinal scale. As of December 31, 2016, our senior unsecured rating was BBB-. The Fitch rating system describes a BBB rating as good credit quality. ‘BBB’ ratings indicate that expectations of default risk are currently low. The capacity for payment of financial commitments is considered adequate but adverse business or economic conditions are more likely to impair this capacity. The modifiers + or - may be appended to a rating to denote relative status within major rating categories. Such suffixes are added to obligation rating categories, or to corporate finance obligation ratings between AA and CCC. A BBB rating is the fourth highest of nine rating categories.

Moody’s

Moody’s Corporate Family Ratings (CFRs) are long-term ratings that reflect the relative likelihood of a default on a corporate family’s debt and debt-like obligations and the expected financial loss suffered in the event of default. A CFR is assigned to a corporate family as if it had a single class of debt and a single consolidated legal entity structure. A CFR does not reference an obligation or class of debt and thus does not reflect priority of claim. As at December 31, 2016, our Corporate Family Rating was Ba1 with a stable outlook. Obligations rated Ba are judged to be speculative and are subject to substantial credit risk. Moody’s appends numerical modifiers 1, 2, and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category. The Ba rating category is the fifth highest rating out of nine rating categories.

Moody’s long-term ratings are assigned to issuers or obligations with an original maturity of one year or more and reflect both on the likelihood of a default on contractually promised payments and the expected financial loss suffered in the event of default. As of December 31, 2016, our senior unsecured long-term debt is rated Ba1 (stable) / LGD4 by Moody’s. The Ba rating category is the fifth highest rating out of nine rating categories. Obligations rated Ba are judged to be speculative and are subject to substantial credit risk. Moody’s appends numerical modifiers 1, 2, and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.

Moody’s Loss Given Default (LGD) assessments are opinions about expected loss given default expressed as a percent of principal and accrued interest at the resolution of the default. One of the six LGD assessments are assigned to individual loan, bond, and preferred stock issues. The firm-wide or enterprise expected LGD rate generally approximates a weighted average of the expected LGD rates on the firm’s liabilities (excluding preferred stock), where the weights equal each obligation’s expected share of the total liabilities at default. As of December 31, 2016, our Loss Given Default Assessment from Moody’s was LGD4 which represents a loss range of greater than or equal to 50% and less than 70%. LGD4 is the fourth highest assessment category out six categories.

S&P

-60-

A Standard & Poor’s issuer credit rating is a forward-looking opinion about an obligor’s overall creditworthiness. This opinion focuses on the obligor’s capacity and willingness to meet its financial commitments as they come due. It does not apply to any specific financial obligation, as it does not take into account the nature of and provisions of the obligation, its standing in bankruptcy or liquidation, statutory preferences, or the legality and enforceability of the obligation. As at December 31, 2016, our issuer credit rating was BBB- with a stable outlook with S&P. This is the fourth highest of 11 ratings categories. An obligor rated ‘BBB’ has adequate capacity to meet its financial commitments. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments. 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.

A Standard & Poor’s issue credit rating is a forward-looking opinion about the creditworthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the creditworthiness of guarantors, insurers, or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion reflects Standard & Poor’s view of the obligor’s capacity and willingness to meet its financial commitments as they come due, and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. As at December 31, 2016, our senior unsecured rating was BBB- with a stable outlook with S&P. An obligation rated ‘BBB’ exhibits 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 the obligation. This is the fourth highest of 11 ratings 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.

The Standard & Poor’s Canadian preferred share rating scale serves issuers, investors, and intermediaries in the Canadian financial markets by expressing preferred share ratings (determined in accordance with global rating criteria) in terms of rating symbols that have been actively used in the Canadian market over a number of years. A Standard & Poor’s preferred share rating on the Canadian scale is a forward-looking opinion about the creditworthiness of an obligor with respect to a specific preferred share obligation issued in the Canadian market, relative to preferred shares issued by other issuers in the Canadian market. There is a direct correspondence between the specific ratings assigned on the Canadian preferred share scale and the various rating levels on the global debt rating scale of Standard & Poor’s. Each of our outstanding Preferred Shares Series have been rated P-3 by S&P. The P-3 rating is the third highest of eight categories. A P-3 rating corresponds to a BB rating on the global preferred share rating scale. Obligors rated ‘BB’, ‘B’, ‘CCC’, and ‘CC’ are regarded as having significant speculative characteristics, of which ‘BB’ indicates the least degree of speculation and ‘CC’ the highest. While such obligors will likely have some quality and protective characteristics, these may be outweighed by large uncertainties or major exposures to adverse conditions. An obligor rated ‘BB’ is less vulnerable in the near term than other lower-rated obligors. However, it faces major ongoing uncertainties and exposure to adverse business, financial, or economic conditions which could lead to the obligor’s inadequate capacity to meet its financial commitments.

We are focused on maintaining a strong financial position and cash flow coverage ratios to support our business. Our available credit facilities, funds from operations, and debt financing options 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.

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, DBRS and Fitch, as applicable, are not recommendations to purchase, hold or sell such securities. 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, DBRS or Fitch in the future if, in its judgement, circumstances so warrant.

We have paid fees for rating services to S&P, DBRS, Moody’s and Fitch during the last two years. We have also paid fees to S&P, DBRS, and Moody’s for certain other services provided to the Corporation during the last two years.

-61-

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
2014 |  | First Quarter |  | $0.29
|  | Second Quarter |  | $0.18
|  | Third Quarter |  | $0.18
|  | Fourth Quarter |  | $0.18
2015 |  | First Quarter |  | $0.18
|  | Second Quarter |  | $0.18
|  | Third Quarter |  | $0.18
|  | Fourth Quarter |  | $0.18
2016 |  | First Quarter |  | $0.18
|  | Second Quarter |  | $0.04
|  | Third Quarter |  | $0.04
|  | Fourth Quarter |  | $0.04
2017 |  | First Quarter |  | $0.04

On December 19, 2016, the Board declared a cash dividend of $0.04 per common share, payable on April 1, 2017 to shareholders of record on March 1, 2017.

-62-

Preferred Shares

Series A Shares

Period |  |  |  | Dividend per Series A Share
2014 |  | First Quarter |  | $0.2875
|  | Second Quarter |  | $0.2875
|  | Third Quarter |  | $0.2875
|  | Fourth Quarter |  | $0.2875
2015 |  | First Quarter |  | $0.2875
|  | Second Quarter |  | $0.2875
|  | Third Quarter |  | $0.2875
|  | Fourth Quarter |  | $0.2875
2016 |  | First Quarter |  | $0.2875
|  | Second Quarter |  | $0.16931
|  | Third Quarter |  | $0.16931
|  | Fourth Quarter |  | $0.16931

On December 19, 2016, the Board declared a cash dividend of $0.16931 per Series A Share, payable on March 31, 2017 to shareholders of record on March 1, 2017.

Series B Shares

Period |  |  |  | Dividend per Series B Share
2016 |  | Second Quarter (1) |  | $0.15490
|  | Third Quarter |  | $0.16144
|  | Fourth Quarter |  | $0.15974

Note:

(1) On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares.

On December 19, 2016, the Board declared a cash dividend of $0.15651 per Series B Share, payable on March 31, 2017 to shareholders of record on March 1, 2017.

-63-

Series C Shares

Period |  |  |  | Dividend per Series C Share
2014 |  | First Quarter |  | $0.2875
|  | Second Quarter |  | $0.2875
|  | Third Quarter |  | $0.2875
|  | Fourth Quarter |  | $0.2875
2015 |  | First Quarter |  | $0.2875
|  | Second Quarter |  | $0.2875
|  | Third Quarter |  | $0.2875
|  | Fourth Quarter |  | $0.2875
2016 |  | First Quarter |  | $0.2875
|  | Second Quarter |  | $0.2875
|  | Third Quarter |  | $0.2875
|  | Fourth Quarter |  | $0.2875

On December 19, 2016, the Board declared a cash dividend of $0.2875 per Series C Share, payable on March 31, 2017 to shareholders of record on March 1, 2017.

Series E Shares

Period |  |  |  | Dividend per Series E Share
2014 |  | First Quarter |  | $0.3125
|  | Second Quarter |  | $0.3125
|  | Third Quarter |  | $0.3125
|  | Fourth Quarter |  | $0.3125
2015 |  | First Quarter |  | $0.3125
|  | Second Quarter |  | $0.3125
|  | Third Quarter |  | $0.3125
|  | Fourth Quarter |  | $0.3125
2016 |  | First Quarter |  | $0.3125
|  | Second Quarter |  | $0.3125
|  | Third Quarter |  | $0.3125
|  | Fourth Quarter |  | $0.3125

On December 19, 2016, the Board declared a cash dividend of $0.3125 per Series E Share, payable on March 31, 2017 to shareholders of record on March 1, 2017.

-64-

Series G Shares

Period |  |  |  | Dividend per Series G Share
2014 |  | Fourth Quarter (1) |  | $0.501
2015 |  | First Quarter |  | $0.33125
|  | Second Quarter |  | $0.33125
|  | Third Quarter |  | $0.33125
|  | Fourth Quarter |  | $0.33125
2016 |  | First Quarter |  | $0.33125
|  | Second Quarter |  | $0.33125
|  | Third Quarter |  | $0.33125
|  | Fourth Quarter |  | $0.33125

Note:

(1) On October 29, 2014, the Board approved an initial dividend of $0.501 per Series G Share for the period from issuance on August 15, 2014 to December 31, 2014.

On December 19, 2016, the Board declared a cash dividend of $0.33125 per Series G Share, payable on March 31, 2017 to shareholders of record on March 1, 2017.

MARKET FOR SECURITIES

Common Shares

Our common shares are listed on the Toronto Stock Exchange (the “TSX”) under the symbol “TA” and the New York Stock Exchange (the “NYSE”) 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
2016 |  |  |  |  |  |
January |  | 4.95 |  | 3.60 |  | 29,765,528
February |  | 6.07 |  | 4.67 |  | 25,268,680
March |  | 6.20 |  | 5.54 |  | 30,217,831
April |  | 6.85 |  | 5.82 |  | 21,151,921
May |  | 7.20 |  | 6.20 |  | 25,638,554
June |  | 7.13 |  | 6.19 |  | 17,041,471
July |  | 6.91 |  | 6.09 |  | 13,224,097
August |  | 6.42 |  | 5.60 |  | 11,284,388
September |  | 6.21 |  | 5.55 |  | 16,633,890
October |  | 6.24 |  | 5.65 |  | 10,125,084
November |  | 7.39 |  | 5.11 |  | 24,600,911
December |  | 7.66 |  | 7.03 |  | 14,964,416
2017 |  |  |  |  |  |
January |  | 8.12 |  | 7.26 |  | 12,182,667
February |  | 7.98 |  | 7.02 |  | 14,818,463
March 1 - 2 |  | 7.14 |  | 7.00 |  | 2,089,842

-65-

Preferred Shares

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 (2) |  | 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 by way of a prospectus supplement dated December 3, 2010 to a short form base shelf prospectus dated October 19, 2009.

(2) On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares.

|  | Price ($) |  |
Month |  | High |  | Low |  | Volume
2016 |  |  |  |  |  |
January |  | 9.90 |  | 7.02 |  | 197,292
February |  | 8.90 |  | 7.12 |  | 329,439
March |  | 8.99 |  | 7.98 |  | 286,692
April |  | 9.55 |  | 8.44 |  | 284,789
May |  | 9.89 |  | 9.30 |  | 236,821
June |  | 9.68 |  | 9.20 |  | 166,894
July |  | 9.58 |  | 9.27 |  | 159,769
August |  | 9.95 |  | 9.34 |  | 337,311
September |  | 10.13 |  | 9.35 |  | 324,420
October |  | 10.65 |  | 9.80 |  | 178,472
November |  | 11.90 |  | 10.37 |  | 396,123
December |  | 13.10 |  | 11.56 |  | 858,024
2017 |  |  |  |  |  |
January |  | 13.24 |  | 12.13 |  | 868,789
February |  | 13.36 |  | 13.07 |  | 1,499,985
March 1 - 2 |  | 13.23 |  | 13.07 |  | 162,597

-66-

Series B Shares

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

Date(s) of Issuance |  | Number of Securities |  | Issue Price per Security |  | Description of Transaction
March 31, 2016(1) |  | 1,824,620 Series B Shares |  | N/A |  | Conversion of Series A Shares

Note:

(1) On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares.

|  | Price ($) |  |
Month |  | High |  | Low |  | Volume
2016 |  |  |  |  |  |
April |  | 9.45 |  | 8.10 |  | 18,700
May |  | 9.73 |  | 8.70 |  | 26,390
June |  | 9.40 |  | 8.21 |  | 33,300
July |  | 9.50 |  | 8.99 |  | 34,406
August |  | 9.94 |  | 9.13 |  | 18,830
September |  | 9.61 |  | 8.96 |  | 31,187
October |  | 10.28 |  | 9.45 |  | 84,440
November |  | 11.40 |  | 10.17 |  | 23,590
December |  | 13.56 |  | 11.30 |  | 213,280
2016 |  |  |  |  |  |
January |  | 13.86 |  | 12.99 |  | 135,119
February |  | 13.27 |  | 12.60 |  | 167,962
March 1 - 2 |  | 13.15 |  | 12.92 |  | 600

-67-

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 by way of a prospectus supplement dated November 23, 2011 to a short form base shelf prospectus dated November 15, 2011.

|  | Price ($) |  |
Month |  | High |  | Low |  | Volume
2016 |  |  |  |  |  |
January |  | 12.34 |  | 8.70 |  | 178,084
February |  | 11.40 |  | 9.05 |  | 245,057
March |  | 12.28 |  | 10.28 |  | 290,237
April |  | 13.04 |  | 11.50 |  | 210,630
May |  | 12.93 |  | 11.98 |  | 184,263
June |  | 12.26 |  | 11.10 |  | 235,431
July |  | 11.68 |  | 11.05 |  | 163,428
August |  | 12.18 |  | 11.31 |  | 244,810
September |  | 12.35 |  | 11.73 |  | 266,241
October |  | 13.54 |  | 12.15 |  | 257,680
November |  | 14.98 |  | 13.12 |  | 348,026
December |  | 17.26 |  | 14.80 |  | 985,032
2017 |  |  |  |  |  |
January |  | 17.57 |  | 16.64 |  | 483,683
February |  | 17.39 |  | 16.55 |  | 741,081
March 1 - 2 |  | 17.04 |  | 16.88 |  | 227,365

-68-

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 by way of a prospectus supplement dated August 3, 2012 to a short form base shelf prospectus dated November 15, 2011.

|  | Price ($) |  |
Month |  | High |  | Low |  | Volume
2016 |  |  |  |  |  |
January |  | 13.80 |  | 10.00 |  | 244,643
February |  | 12.58 |  | 10.53 |  | 208,378
March |  | 13.47 |  | 11.42 |  | 233,138
April |  | 14.29 |  | 13.03 |  | 156,194
May |  | 14.54 |  | 13.84 |  | 184,707
June |  | 14.17 |  | 12.90 |  | 189,542
July |  | 13.51 |  | 12.75 |  | 115,151
August |  | 14.19 |  | 13.35 |  | 173,277
September |  | 13.75 |  | 13.14 |  | 137,455
October |  | 14.61 |  | 13.45 |  | 280,310
November |  | 16.30 |  | 14.26 |  | 285,270
December |  | 19.85 |  | 16.22 |  | 521,963
2017 |  |  |  |  |  |
January |  | 19.49 |  | 18.76 |  | 449,851
February |  | 19.15 |  | 18.28 |  | 921,419
March 1 - 2 |  | 18.95 |  | 18.69 |  | 21,470

-69-

Series G Shares

Our Series G Shares are listed on the TSX under the symbol “TA.PR.J”.

Date(s) of Issuance |  | Number of Securities |  | Issue Price per Security |  | Description of Transaction
August 15, 2014(1) |  | 6,600,000 Series G Shares |  | $25.00 |  | Public Offering

Note:

(1) Series G Shares were issued pursuant to a public offering by way of a prospectus supplement dated August 8, 2014 to a short form base shelf prospectus dated December 9, 2013.

|  | Price ($) |  |
Month |  | High |  | Low |  | Volume
2016 |  |  |  |  |  |
January |  | 14.63 |  | 11.30 |  | 165,035
February |  | 14.50 |  | 12.30 |  | 123,327
March |  | 14.89 |  | 13.29 |  | 127,284
April |  | 15.61 |  | 14.05 |  | 129,215
May |  | 15.97 |  | 15.30 |  | 103,825
June |  | 15.74 |  | 14.76 |  | 132,121
July |  | 15.35 |  | 14.65 |  | 138,784
August |  | 16.00 |  | 15.00 |  | 142,470
September |  | 15.99 |  | 15.21 |  | 133,955
October |  | 16.73 |  | 15.65 |  | 174,693
November |  | 17.52 |  | 15.84 |  | 239,037
December |  | 20.13 |  | 17.31 |  | 413,476
2017 |  |  |  |  |  |
January |  | 20.42 |  | 19.52 |  | 324,539
February |  | 20.38 |  | 19.55 |  | 487,589
March 1 - 2 |  | 20.31 |  | 19.87 |  | 50,744

-70-

DIRECTORS AND OFFICERS

The name, province or state and country of residence of each of our directors as at March ·, 2017, 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 on the Board is also set out below. Each director is appointed to serve until the next annual meeting of TransAlta or until his or her successor is elected or appointed.

Name, Province (State) and Country of Residence |  | Year first became Director |  | Principal Occupation
John P. Dielwart Alberta, Canada |  | 2014 |  | Mr. Dielwart was formerly Chief Executive Officer of ARC Resources Ltd., which owns and operates oil and gas properties in Western Canada. He oversaw the growth of ARC Resources Ltd. from start-up in 1996 to a company with a market capitalization of approximately $10 billion. After his retirement from ARC Resources Ltd. on January 1, 2013, Mr. Dielwart re-joined ARC Financial Corp. (“ARC Financial”) as Vice-Chairman. ARC Financial is Canada’s leading energy-focused private equity manager. Mr. Dielwart provides leadership support for the executive team in the areas of internal governance and investment decision-making. With his extensive background in creating, building and leading one of Canada’s most successful oil and gas companies, mentorship of ARC Financial employees as well as management of ARC Financial’s investee companies is a primary responsibility. He is a member of ARC Financial’s Investment and Strategy committees, and currently represents ARC Financial on the board of Modern Resources Ltd. and Aspenleaf Energy Limited. Prior to joining ARC Financial in 1994, Mr. Dielwart spent 12 years with a major Calgary-based oil and natural gas engineering consulting firm, as senior vice-president and a director, where he gained extensive technical knowledge of oil and natural gas properties in western Canada. Mr. Dielwart has a Bachelor of Science with distinction (civil engineering) degree from the University of Calgary. He is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA) and is a Past-Chairman of the Board of Governors of the Canadian Association of Petroleum Producers (CAPP). In 2015, Mr. Dielwart was inducted into the Calgary Business Hall of Fame. Mr. Dielwart is also the Co-Chair of the Sheldon Kennedy Child Advocacy Centre. Mr. Dielwart brings to the Company and the Board many years’ experience in leadership, entrepreneurship and knowledge of the commodity markets in which we operate, specifically oil and gas markets.

-71-

Name, Province (State) and Country of Residence |  | Year first became Director |  | Principal Occupation
Timothy W. Faithfull London, U.K. |  | 2003 |  | 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 Chief Executive Officer 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 mining and upgrading 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 Chief Executive Officer of Shell Eastern Petroleum in Singapore from 1996 to 1999, including Shell’s largest refinery, and its oil products trading business in Asia Pacific. In the United Kingdom, he is a director and member of the Risk and Audit Committee of ICE Futures Europe (“IFEU”) and LIFFE Administration and Management, a leading global electronic exchange for energy, commodities, and financial futures. He is a member of the Oversight Committee of the ICE Brent Index, used in settlement of Brent Crude oil futures contracts, for which IFEU is the regulated benchmark administrator. He is a past director of Enerflex Systems Income Fund, Canadian Pacific Railway, AMEC plc, and Shell Pension Trust Limited. In Calgary, he served on the board of the Calgary Health Trust and the Epcor Arts Centre. In the United Kingdom, he is Chairman of the trustees of Starehe UK, which supports schools for disadvantaged children in Nairobi, Kenya, and a trustee of Canada UK Colloquium, all non-public entities. He serves on the Committee to Review Donations to the University of Oxford. Mr. Faithfull holds a Master of Arts (Philosophy, Politics and Economics) from the University of Oxford, U.K. He is a Distinguished Friend of the University of Oxford and of the London Business School. Mr. Faithfull brings to the Corporation and the Board many years of experience in leadership and, in particular, knowledge of large project development and commodity risk management in the oil and gas industry.

-72-

Name, Province (State) and Country of Residence |  | Year first became Director |  | Principal Occupation
Dawn L. Farrell Alberta, Canada |  | 2012 |  | Mrs. Farrell became President and Chief Executive Officer 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 30 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 Chemours Company, a NYSE-listed chemical company, the Conference Board of Canada, the Business Council of Canada and is a member of the Trilateral Commission. Her past boards include the Calgary Stampede, the Mount Royal College Board of Governors, Fording Coal Income Fund, New Relationship Trust Fund, Mount Royal College Foundation and Vision Quest Windelectric. Mrs. Farrell holds a Bachelor of Commerce with a major in Finance and a Master’s degree in Economics from the University of Calgary. She has also attended the Advanced Management Program at Harvard University.

-73-

Name, Province (State) and Country of Residence |  | Year first became Director |  | Principal Occupation
Alan J. Fohrer California, U.S.A. |  | 2013 |  | Mr. Fohrer was Chairman and Chief Executive Officer of Southern California Edison Company (“SCE”), a subsidiary of Edison International (“Edison”) and one of the largest electric utilities in the United States. He was elected Chief Executive Officer in 2002 and Chairman in 2007. In 2000, Mr. Fohrer was elected as President and Chief Executive Officer of Edison Mission Energy (“EME”), a subsidiary of Edison that owns and operates independent power facilities. During his tenure at EME, Mr. Fohrer restructured a number of the international projects, which enhanced the value of the assets sold in subsequent years. Mr. Fohrer also served as Executive Vice-President, Treasurer and Chief Financial Officer of both Edison and SCE from 1995 to 1999. After 37 years with Edison, Mr. Fohrer retired in December 2010. Mr. Fohrer currently sits on the boards of PNM Resources, Inc., a publicly held energy holding company, Blue Shield of California, a non-profit health insurance provider, and Synagro, a waste management company. Mr. Fohrer has served on boards of directors of the Institute of Nuclear Power Operations, the California Chamber of Commerce, Duratek, Inc., and Osmose Utilities Services, Inc. He is also a member of the Viterbi School of Engineering Board of Councilors for the University of Southern California and Chair of the California Science Centre Foundation. Mr. Fohrer holds a Master of Science in civil engineering from the University of Southern California, Los Angeles, as well as a Master of Business Administration from California State University in Los Angeles. Mr. Fohrer brings to the Corporation and the Board experience in accounting, finance and the power industry from both a regulated and deregulated market perspective.

-74-

Name, Province (State) and Country of Residence |  | Year first became Director |  | Principal Occupation
Amb. Gordon D. Giffin Georgia, U.S.A. |  | 2002 |  | Ambassador Giffin is Senior Partner of the law firm of Dentons (formerly McKenna Long & Aldridge LLP), 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 40 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. Ambassador Giffin has spent three decades as an attorney in the energy industry as an advisor, trying multiple energy regulatory cases before state and federal tribunals and courts, and handling transactions including mergers and acquisitions. During a decade in public service, he was a senior attorney and advisor in the United States Senate where, among other matters, he worked on major energy public policy initiatives. During his four years as United States Ambassador to Canada, he was Chief Executive Officer of a large government enterprise with in excess of a thousand people across Canada. His substantive responsibilities included the entire array of policy matters in the Canada-U.S. context including energy policy. He has substantial experience in dealing with issues at the intersection of industry and public policy. Since leaving public office, he resumed his continental law practice and remains actively engaged in public policy initiatives and international affairs through membership in the Council on Foreign Relations and the Trilateral Commission. Ambassador Giffin holds a Bachelor of Arts from Duke University (Durham, NC) and a Juris Doctorate from Emory University School of Law (Atlanta, GA). Ambassador Giffin brings to the Corporation and the Board experience in law, regulatory and governmental affairs that will assist the Company as it addresses continuous change in environmental law and other compliance matters.

-75-

Name, Province (State) and Country of Residence |  | Year first became Director |  | Principal Occupation
P. Thomas Jenkins Alberta, Canada |  | 2014 |  | Mr. Jenkins has been active for more than 30 years in innovation and economic development in both the private and public sectors. He is currently the Chairman of the Board of Open Text Corporation, a multinational enterprise software firm. He is also the Chancellor of the University of Waterloo. He has served as a director of Open Text Corporation since 1994 and as its Chairman since 1998. From 1994 to 2005, Mr. Jenkins was President and Chief Executive Officer, and then from 2005 to 2013, Executive Chairman and Chief Strategy Officer of Open Text Corporation. Prior thereto, he was employed in technical and managerial capacities at a variety of technology companies. Mr. Jenkins is also a director of the C.D. Howe Institute, and a director of the Business Council of Canada. Mr. Jenkins was also a member of the board of BMC Software, Inc., a software corporation based in Houston, Texas. Mr. Jenkins received a Master of Business Administration from the Schulich School of Business at York University (Toronto, ON), a Master of Applied Science from the University of Toronto and a Bachelor of Mechanical Engineering and Management from McMaster University (Hamilton, ON). Mr. Jenkins received an honorary doctorate of laws from the University of Waterloo and an honorary doctorate of Military Science from the Royal Military College of Canada. He is a recipient of the 2009 Ontario Entrepreneur of the Year, the 2010 McMaster Engineering L. W. Shemilt Distinguished Alumni Award and the Schulich School of Business 2012 Outstanding Executive Leadership award. He is a Fellow of the Canadian Academy of Engineering. Mr. Jenkins was awarded the Canadian Forces Decoration and the Queen’s Diamond Jubilee Medal. Mr. Jenkins is an Officer of the Order of Canada. Mr. Jenkins brings to the Corporation and the Board several years of experience as an entrepreneur, innovator and leader in information technology which will assist the Company as it addresses both technological and innovative changes in the industry.

-76-

Name, Province (State) and Country of Residence |  | Year first became Director |  | Principal Occupation
Yakout Mansour California, U.S.A. |  | 2011 |  | 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 Chief Executive Officer 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, the California market structure was completely redesigned, and 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. Mr. Mansour holds a Bachelor of Science in electrical engineering from the University of Alexandria (Alexandria, Egypt) and a Master of Science from the University of Calgary (Calgary, AB). Mr. Mansour brings to the Corporation and the Board decades of experience in our industry in generation, transmission and energy competitive markets in both a regulated and deregulated market environment.

-77-

Name, Province (State) and Country of Residence |  | Year first became Director |  | Principal Occupation
Georgia Nelson Illinois, U.S.A. |  | 2014 |  | Ms. Nelson is President and Chief Executive Officer of PTI Resources, LLC, an independent consulting firm established in 2005. Ms. Nelson has had a 35-year career in the power generation industry, serving in various senior executive capacities for Edison International and its subsidiaries between 1971 and 2005. She was President of Midwest Generation Edison Mission Energy (EME), from 1999 to her retirement in 2005 and General Manager of EME Americas from 2002 to 2005. Her business responsibilities included management of regulated and unregulated power operations and a large energy trading subsidiary as well as the construction and operation of power generation projects in the United States, Puerto Rico, the United Kingdom, Turkey, Thailand, Indonesia, Australia and Italy. Ms. Nelson has extensive experience in international business negotiations, environmental policy matters and human resources. Ms. Nelson is currently a director of Cummins Inc., Ball Corporation, and Sims Metal Management Ltd. She is also a director of CH2MHILL Corporation, a privately held company. Ms. Nelson is a past director of Nicor, Inc. Ms. Nelson was a member of the Executive Committee of the National Coal Council from 2000-2015 and served as Chair from 2006-2008. She serves on the advisory committee of the Center for Executive Women at Northwestern University. Ms. Nelson was named to the 2012 National Association of Corporate Directors (“NACO”) Directorship 100. She is an NACO Board Fellow. Ms. Nelson holds a Bachelor of Science form Pepperdine University and a Master of Business Administration from the University of Southern California. Ms. Nelson brings to the Corporation and the Board specialized knowledge in the energy, coal and mining industry as well as human resources management.

-78-

Name, Province (State) and Country of Residence |  | Year first became Director |  | Principal Occupation
Beverlee F. Park British Columbia, Canada |  | 2015 |  | Ms. Park is a senior executive with management and board experience in a range of industries, including forest products, shipping, mining, transportation, real estate, and electricity transmission. Ms. Park spent seventeen years of her career with TimberWest Forest Corp. where she was most recently Chief Operations Officer until her retirement in 2013. Over that time, she also held the roles of Interim Chief Executive Officer, President of the real estate division (Couverdon Real Estate) and Executive Vice President and Chief Financial Officer. Having provided strong leadership at the Board, Chief Executive Officer, Chief Operations Officer and Chief Financial Officer level in publicly-traded, private and Crown corporations, Ms. Park has a breadth of experience in an array of operating environments and domestic and offshore markets with specific experience leading shareholder value creation, long term strategic repositioning, operational excellence, risk management, regulatory issues, restructuring and acquisitions and divestitures. Ms. Park is currently a director of Teekay LNG Partners, a public company, where she chairs the Audit Committee. Teekay LNG Partners is one the world’s largest independent owners of LNG and LPG carriers. She is also a director of Silver Standard Resources Inc., a public mining company, focused on the operation, development, exploration and acquisition of precious metals projects in North and South America. Most recently, Ms. Park was appointed to the Board of Governors at the University of British Columbia. In addition, she is a director of InTransit BC. Ms. Park was previously a director of the BC Transmission Corporation, where she chaired the Audit Committee. Ms. Park holds a Bachelor of Commerce with distinction from McGill University (Montreal, QB), a Master of Business Administration from the Simon Fraser University Executive program and is a Fellow Chartered Accountant. She is also a Fellow of the Institute of Chartered Accountants of British Columbia. Ms. Park brings to the Corporation and to the Board 30 years of experience in finance and accounting as well as leadership experience in organizational change.

-79-

Officers

The name, province or state and country of residence of each of our senior officers as at March 2, 2017, their respective position and office and their respective principal occupation are set out below.

Name |  | Principal Occupation |  | Residence
Dawn L. Farrell |  | President and Chief Executive Officer |  | Alberta, Canada
Wayne Collins |  | Executive Vice-President, Coal and Mining Operations |  | Alberta, Canada
Dawn E. de Lima |  | Chief Administrative Officer |  | Alberta, Canada
Brett M. Gellner |  | Chief Investment Officer |  | Alberta, Canada
John H. Kousinioris |  | Chief Legal and Compliance Officer and Corporate Secretary |  | Alberta, Canada
Jennifer M. Pierce |  | Senior Vice-President, Trading and Marketing |  | Alberta, Canada
Todd J. Stack |  | Managing Director and Corporate Controller |  | Alberta, Canada
Donald Tremblay |  | Chief Financial Officer |  | Alberta, Canada
Aron J. Willis |  | Senior Vice-President, Gas and Renewables |  | Alberta, Canada

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

· | Prior to May 2014, Mr. Collins was Chief Operating Officer of Stanwell Corporation Limited (electrics corporation) in Australia.
· | Prior to July 2015, Ms. de Lima was Chief Human Resources Officer of TransAlta. Prior to April 2012, Ms. de Lima was Chief Human Resources Officer and Executive Vice-President, Communications of TransAlta.
· | Prior to August 2013, Mr. Gellner was Chief Financial Officer of the Corporation.
· | Prior to October 2015, Mr. Kousinioris was Chief Legal and Compliance Officer of TransAlta. Prior to December 2012, Mr. Kousinioris was a Partner and co-head of the Corporate Commercial Group at Bennett Jones LLP, Barristers and Solicitors (law firm).
· | Prior to October 2015, Ms. Pierce was Vice-President, Commercial Management of TransAlta. Prior to April 2014, Ms. Pierce was Vice-President, Commercial Management — Alberta Coal and PPAs of TransAlta.
· | Prior to February 2017, Mr. Stack was Managing Director and Treasurer of TransAlta. Prior to October 2015, Mr. Stack was Vice-President and Treasurer of TransAlta. Prior to November 2012, Mr. Stack was Treasurer of TransAlta.
· | Prior to March 2014, Mr. Tremblay was Executive Vice President at Brookfield Renewable Energy LP (utilities).
· | Prior to January 2017, Mr. Willis was the Managing Director, Australia of TransAlta. Prior to September 2015, Mr. Willis was Vice-President, Australia of TransAlta. Prior to October 2014, he was Country Manager, Australia of TransAlta.

As of March 2, 2017, the directors and executive officers of TransAlta, as a group, beneficially owned, directly or indirectly, or exercised control or direction over less than one per cent of our outstanding common shares.

-80-

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 2016 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, 2016, 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 and Bankruptcies

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

(i) | was the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or
(ii) | was subject to an event that resulted, after the person ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or
(iii) | within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

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.

Ms. Nelson was a director of Tower International (“Tower”) from 2000 to 2007. In February 2005, Tower began a voluntarily reorganization under Chapter 11 of the United States Bankruptcy Code. In July 2007, Tower completed the sale of substantially all of its assets to Tower Automotive, LLC, an affiliate of Cerberus Capital Management, L.P., and emerged from bankruptcy court protection.

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.

-81-

Penalties or Sanctions

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

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

CONFLICTS OF INTEREST

Circumstances may arise where members of the Board serve as directors or officers of corporations which are in competition to the interests of TransAlta. No assurances can be given that opportunities identified by such member of the Board will be provided to us. However, our policies provide that each director and executive officer must comply with the disclosure requirements of the CBCA regarding any material interest. If a declaration of material interest is made, the declaring director shall not vote on the matter if put to a vote of the Board. In addition, the declaring director and executive officer may be requested to recuse himself or herself from the meeting when such matter is being discussed.

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 Note 32 (I) of our audited consolidated financial statements for the year ended December 31, 2016 which financial statements are incorporated by reference herein. See “Documents Incorporated by Reference” in this AIF.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common shares and Series A Shares, Series B Shares, Series C Shares, Series E Shares and Series G Shares is CST Trust Company. CST Trust Company succeeded CIBC Mellon Trust Company as our transfer agent. On November 1, 2010, CIBC Mellon Trust Company sold its issuer services business to Canadian Stock Transfer Company Inc. which operated the business on their behalf until August 30, 2013, at which time CST Trust Company, an affiliate of Canadian Stock Transfer Company Inc., received federal approval to commence business. Common shares are transferable in Vancouver, Calgary, Toronto, Montréal, and Halifax. Series A Shares, Series B Shares, Series C Shares, Series E Shares and Series G Shares are transferable in Calgary and Toronto. 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

The Company’s auditors are Ernst & Young LLP, Chartered Professional Accountants, 2200, 215 – 2 nd Street, S.W., Calgary, Alberta, T2P 1M4.

Our auditors, Ernst & Young LLP, are independent within the meaning of the Chartered Professional Accountants of Alberta Rules of Professional Conduct 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 and EDGAR at www.sec.gov.

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

-82-

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 from our Investor Relations department, or as filed on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

Additional financial information is provided in our audited consolidated financial statements as at and for the year ended December 31, 2016 and in the related Annual MD&A, each of which is incorporated by reference in this AIF. See “Documents Incorporated by Reference” in this AIF.

AUDIT AND RISK COMMITTEE

General

The members of TransAlta’s Audit and Risk Committee (“ARC”) satisfy the requirements for independence under the provisions of Canadian Securities Regulators, National Instrument 52-110 Audit Committees, Section 303A of the NYSE 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. The ARC is comprised of five independent members, Alan J. Fohrer (Chair), John P. Dielwart, Timothy Faithfull, Yakout Mansour, and Beverlee F. Park.

All members of the committee are financially literate pursuant to both Canadian and U.S. securities requirements and Ms. Park has 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 ARC 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 and disclosure controls established by management of TransAlta (“Management”), iii) the risk identification and assessment process conducted by Management including the programs established by Management to respond to such risks, iv) the internal audit function, v) compliance with financial, legal and regulatory requirements and vi) the external auditors’ qualifications, independence and performance. In so doing, it is the ARC’s responsibility to maintain an open avenue of communication between it and the external auditors, the internal auditors and the Management.

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

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

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 ARC. 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 another member of the ARC 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 ARC’s role is to provide oversight in order to ensure that the Corporation’s assets are protected and safeguarded within reasonable business limits. The ARC reports to the Board on its risk oversight responsibilities.

-83-

Audit and Risk Committee Charter

The Charter of the ARC 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
J. P. Dielwart |  | Mr. Dielwart is currently the Vice-Chairman of ARC Financial Corp., an energy focused private equity manager. Mr. Dielwart served as the chief executive officer of a Canadian publicly listed company for sixteen years during which time he had extensive experience actively supervising the finance and accounting functions and public accountants. Mr. Dielwart also serves on the audit committee of Tesco Corporation, a public company.
T. W. Faithfull |  | 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.
A. J. Fohrer |  | Prior to his retirement in December 2010, Mr. Fohrer was Chairman and CEO of SCE, a subsidiary of Edison and one of the largest electric utilities in the United States. Prior to that, Mr. Fohrer served as Executive Vice-President, Treasurer and Chief Financial Officer of both Edison and SCE. Mr. Fohrer also serves on the audit committee of PNM Resources Inc., a public company.
Y. Mansour |  | Mr. Mansour has over 40 years of experience as an executive in the electric utility business. He served as President and CEO of the CAISO 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.
B. Park |  | Ms. Park is a senior executive with management and board experience in a range of industries, including forest products, shipping, mining, transportation, real estate, and electricity transmission. Ms. Park spent seventeen years of her career with TimberWest Forest Corp. where she was most recently Chief Operations Officer. Over that time, she also held the roles of Interim Chief Executive Officer, President of the real estate division (Couverdon Real Estate) and Executive Vice President and Chief Financial Officer. Ms. Park is currently a director of Teekay LNG Partners, a public company, where she chairs the Audit Committee. Ms. Park holds a Bachelor of Commerce with distinction from McGill University (Montreal, QB), a Master of Business Administration from the Simon Fraser University Executive program and is a Chartered Accountant. She is also a Fellow of the Institute of Chartered Accountants of British Columbia.

-84-

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 March 2, 2017 are:

Governance and Environment Committee |  | Human Resources Committee
Chair: P. Thomas Jenkins |  | Chair: Georgia R. Nelson
John P. Dielwart |  | P. Thomas Jenkins
Timothy W. Faithfull |  | Beverlee F. Park
Yakout Mansour |  |

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 and EDGAR at www.sec.gov.

For the years ended December 31, 2016 and December 31, 2015, Ernst & Young LLP and its affiliates were paid $3,083,145 and $3,989,814 respectively, as detailed below:

Ernst & Young LLP

Year Ended December 31 |  | 2016 |  |  | 2015 |
Audit Fees | $ | 2,680,186 |  | $ | 3,549,473 |
Audit-related fees |  | 363,959 |  |  | 440,341 |
Tax fees |  | 39,000 |  |  | 0 |
All other fees |  | 0 |  |  | 0 |
Total | $ | 3,083,145 |  | $ | 3,989,814 |

No other audit firms provided audit services in 2016 or 2015.

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 2016 include payments of 1,384,384 related to 2015 and total audit fees for 2015 include payments related to 2014 in the amount of $1,607,423.

Audit-Related Fees

The audit-related fees in 2016 were primarily for work performed by Ernst & Young LLP in relation to compliance and regulatory reporting and miscellaneous accounting advice provided to the Corporation. The audit-related fees in 2015 primarily for work performed by Ernst & Young LLP in relation to compliance and regulatory reporting, debt issuances, the issuance of an economic interest in certain assets owned by the Corporation to TransAlta Renewables Inc. and miscellaneous accounting advice provided to the Corporation.

Tax Fees

The tax fees for 2016 relate to various tax related matters in our domestic and foreign operations.

All Other Fees

-85-

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 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 of 2002. This 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.

-86-

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 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.

A-1

5. Absence of Committee Chair

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

6. Secretary of Committee

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

7. Meetings

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

The Committee shall also meet in separate executive session.

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 the President and Chief Executive Officer (“CEO”), other 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. All changes proposed by the Committee are reviewed and approved by the Governance and Environment Committee and the Board.

A-2

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:

1. Chairing meetings of the Committee and 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 the CEO, the Chief Financial Officer (the “CFO”), the Corporate Secretary and Assistant Corporate Secretary, as applicable, on the development of agendas and related materials for the meetings.

4. Providing leadership to the Committee and assisting the Committee in ensuring the proper and timely discharge of its responsibilities.

5. Reporting to the Board on the recommendations and decisions 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 and disclosure controls established by Management, iii) the risk identification and assessment process conducted by Management including the programs established by Management to respond to such risks, iv) the internal audit function, v) compliance with financial, 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 disclosure controls and procedures to comply with accounting standards, applicable laws and regulations which provide reasonable assurance that the assets of the Corporation are safeguarded and transactions are authorized, executed, recorded and properly reported.

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 Committee must also designate at least one member as an “audit committee financial expert”. 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

A-3

duties, obligations and liability that are greater than the duties, obligations and liability imposed on another 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.

D. Duties and Responsibilities of the Committee

1. Financial Reporting, External Auditors and Financial Planning

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

(a) Review with Management and the external auditors the Corporation’s financial reporting process the work to be conducted in conjunction 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;

(b) Review with Management and the external auditors the Corporation’s audited annual financial statements, including the notes thereto, “Management’s Discussion and Analysis”, the related earnings release, and recommend their approval to the Board for release to the public;

(c) 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;

(d) In reviewing the financial statements and related financial disclosure, the Committee shall review and discuss with Management and the external auditors:

(i) any changes in accounting principles, practices or policies considering their applicability to the business and financial impact;

(ii) Management’s processes for formulating sensitive accounting estimates and the reasonableness of the estimates;

(iii) the use of “pro forma” or “non-comparable” information and the applicable reconciliation;

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

(v) disclosures made to the Committee by the CEO and CFO during their certification process for the relevant periodic/annual report 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

A-4

Management or other employees who have a significant role in the Corporation’s internal controls is reported to the Committee.

(e) In reviewing the financial statements and related financial disclosure, the Committee shall also, with the external auditors:

(i) discuss the cooperation they received from Management during the course of their review and their access to all records, data and information requested; and

(ii) 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.

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

(g) Review with Management and the external auditors the processes relating to the assessment of potential fraud, programs and controls to mitigate the risk of fraud, and the processes put in place for monitoring the risks within the targeted areas; and

(h) 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.

B) Duties and Responsibilities Related to the External Auditors

(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 and approve annually the external auditors audit plan;

(ii) 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;

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

(iv) review and discuss annually 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, (a) 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 their independence with the Corporation; (b) discussing with the external auditors any relationships or services that the external auditors believe may affect their objectivity and professional

A-5

skepticism; (c) reviewing with the external auditors the experience and qualifications of the senior personnel who are providing audit services to the Corporation; (d) reviewing 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; and (e) evaluating the communication and interaction with the external auditor including quality of service considerations;

(v) in the year preceding the change of the lead (or coordinating) audit partner (having primary responsibility for the audit), and in any event not less than every five years, perform a comprehensive review of the external auditor which takes into consideration (a) the impact of the tenure of the audit firm on audit quality, trends in the audit firm’s performance and expertise in the industry, incidences of independence threats and the effectiveness of safeguards to mitigate those threats, (b) the responsiveness of the audit firm to changes in the entity’s business and suggestions for improvement from regulators, the audit committee and/or management, (c) the consistency and rigour of the professional skepticism applied by the external auditor, and the quality of the engagement team and its communications, review of Canadian Public Accountability Board (CPAB) inspection findings since the previous comprehensive review and how the audit firm responded to these findings, and following this comprehensive review, determine whether the audit firm should be nominated to the Board as the external auditors for appointment by the shareholders at the Corporation’s next general annual meeting;

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

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

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

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;

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

(d) Review annually with Management the Corporation’s overall financing plan in support of the Corporation’s capital expenditure plan and overall budget/medium range forecast; and

A-6

(e) Review with Management at least annually the approach and nature of earnings guidance and financial information to be disclosed to analysts and rating agencies.

2. Internal Audit

(a) Approve whether the internal audit function should be outsourced and if outsourced, approve the audit firm to perform such internal audit service; provided that in no event shall the external auditor be retained to also perform the internal audit function;

(b) 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;

(c) Review annually 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;

(d) 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;

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

(f) Review with the Corporation’s senior financial Management and the internal audit group the adequacy of the Corporation’s systems of internal control and procedures; and

(g) Recommend to the Human Resources Committee the appointment, termination or transfer of the lead individual responsible for internal audit, provided that if the internal audit function has been, or is being, outsourced to an audit firm, the Committee itself shall approve the appointment, termination or transfer of such audit firm.

3. 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, and evaluation, of the Corporation’s principal 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;

A-7

(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 review with the Board:

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

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

(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 and program.

4. Governance

A) Public Disclosure, Legal and Regulatory Reporting

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

(b) Review quarterly with the Chief Legal and Compliance 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;

(c) 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;

(d) Review with Management, the external auditors and internal legal counsel (external counsel if necessary), 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;

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

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

A-8

B) Pension Plan Governance

(a) 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 and reporting thereon to the Board annually; and

(b) 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.

C) Information Technology – Cyber Security

(a) Receive bi-annually a system status update with respect to the Corporation’s core IT operating systems; and

(b) 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.

D) Administrative Responsibilities

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

(b) 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;

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

(d) 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;

(e) 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

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

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.

(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.

A-9

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.

Balancing Pool – The Balancing Pool was established in 1999 by the Government of Alberta to help manage the transition to competition in Alberta’s electric industry. Their current obligations and responsibilities are governed by the Electric Utilities Act (effective June 1, 2003) and the Balancing Pool Regulation. For more information go to www.balancing pool.ca

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.

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.

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

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.

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

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

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

LTC – Long term contract.

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.

B-1

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

Supercritical Conbustion – 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.

B-2