TRANSALTA CORP (Form: 40-F, Received: 02/27/2019 07:34:05)

Year ended Dec. 31

GWh lost ⁽¹⁾

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F

[Check one]

o REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

x ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



For the fiscal year ended	Dec 31, 2018	Commission file number	001-15214

TRANSALTA CORPORATION

(Exact name of Registrant as specified in its charter)

Not applicable

(Translation of Registrant’s name into English (if applicable))

Canada

(Province or other jurisdiction of incorporation or organization)

4911

(Primary Standard Industrial Classification Code Number (if applicable))

Not Applicable

(I.R.S Employer Identification Number (if applicable))

110-12 th Avenue S.W., Box 1900, Station “M”,

Calgary, Alberta, Canada, T2P 2M1,

(403) 267-7110

(Address and telephone number of Registrant’s principal executive offices)

TransAlta Centralia Generation LLC

913 Big Hanaford Road, Centralia, Washington 98531, (360) 736-9901

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange
		on which registered


Common Shares, no par value		New York Stock Exchange

Common Share Purchase Rights		New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

Debt Securities

For annual reports, indicate by check mark the information filed with this form:



x Annual information form	x Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

At December 31, 2018 , 284,842,967 common shares were issued and outstanding.

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.



Yes x	No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).



Yes x	No o

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company ¨

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ¨

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

INCORPORATION BY REFERENCE

The documents, forming part of this Form 40-F, are incorporated by reference into the following registration statements under the Securities Act of 1933, as amended.



Form	Registration No.
S-8	333-72454
S-8	333-101470
F-10	333-215608

CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS

AND MANAGEMENT’S DISCUSSION & ANALYSIS

A. Consolidated Audited Annual Financial Statements

For consolidated audited annual financial statements, including the report of independent chartered accountants with respect thereto, see Exhibit 13.3 incorporated by reference herein.

B. Management’s Discussion and Analysis

For management’s discussion and analysis, see Exhibit 13.2 incorporated by reference herein.

DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15 under the Securities Exchange Act of 1934 (“Exchange Act”), management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act are recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act are accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management was required to apply its judgment in evaluating and implementing possible controls and procedures.

There has been no change in the internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2018 , the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting.

Internal control over financial reporting refers to a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:


•	pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;


•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and members of our board of directors; and


•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2018 using the Committee of Sponsoring Organizations of the Treadway Commission (COSO) 2013 framework. Management concluded that our internal control over financial reporting was effective as of December 31, 2018 . Certain matters relating to the scope of management’s evaluation and limitations of management’s conclusions are described below. See “Limitations and Scope of Management’s Report on Internal Control over Financial Reporting.”

Our independent registered public accounting firm, Ernst & Young LLP, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2018 . For Ernst & Young LLP’s report see page F3 of the Consolidated Audited Annual Financial Statements for the year ended December 31, 2018 filed as Exhibit 13.3 and incorporated by reference herein, under the heading “Report of Independent Registered Public Accounting Firm”.

LIMITATIONS AND SCOPE OF MANAGEMENT’S

REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper overrides. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process, and it is possible to design safeguards into the process to reduce, though not eliminate, this risk.

TransAlta Corporation (“TransAlta” or the “Company”) proportionately consolidates the accounts of the Sheerness and Genesee 3 joint operations (the “Excluded Entities”), in accordance with International Financial Reporting Standards (“IFRS”). Management does not have the contractual ability to assess the internal controls of these Excluded Entities. Management’s conclusion regarding the effectiveness of internal controls does not extend to the internal controls at the transactional level of these Excluded Entities. Accordingly, management’s evaluation of the Company’s internal control over financial reporting did not include an evaluation of the internal controls of any of the Excluded Entities, and management’s conclusion regarding the effectiveness of the Company’s internal control over financial reporting does not extend to the internal controls of any of the Excluded Entities.

The 2018 consolidated financial statements of TransAlta, in accordance with EITF 00-1, included CDN$ 588 million and CDN$ 521 million of total and net assets, respectively, as of December 31, 2018 , and CDN$ 244 million and CDN$ 27 million of revenues and net loss, respectively, for the year then ended related to Excluded Entities. Once the financial information is obtained from these Excluded Entities it falls within the scope of TransAlta’s internal control framework.

AUDIT COMMITTEE FINANCIAL EXPERT

TransAlta’s board of directors has determined that it has two audit committee financial experts serving on its Audit and Risk Committee (the “ARC”). Ms. Beverlee F. Park and Mr. Bryan D. Pinney have each been determined to be an audit committee financial expert, within the meaning of Section 407 of the United States Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”), and are independent, as that term is defined by the New York Stock Exchange’s (“NYSE”) listing standards applicable to the Registrant. Under Securities and Exchange Commission rules, the designation of persons as audit committee financial experts does not make them “experts” for any other purpose, impose any duties, obligations or liability on them that are greater than those imposed on members of their committee and the board of directors who do not carry this designation or affect the duties, obligations or liability of any other member of their committee.

CODE OF ETHICS

TransAlta has adopted a code of ethics as part of its “Corporate Code of Conduct” that applies to all employees and officers which has been filed with the Securities and Exchange Commission. In addition, the Registrant has adopted a code of conduct applicable to all directors of the Company, a separate financial code of conduct which applies to all financial management employees and an Energy Trading code of conduct for our employees working within energy marketing. Our codes of conduct are available on our Internet website at www.transalta.com . There has been no waiver of the codes granted during the 2018 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2018 and December 31, 2017 , Ernst & Young LLP and its affiliates were paid $3,303,359 and $2,799,884, respectively, as detailed below:

Ernst & Young LLP



Year Ended Dec. 31	2018		2017
Audit Fees	$	3,022,276	$	2,708,884
Audit-related fees	166,328		91,000
Tax fees	104,255		0
All other fees	10,500		0
Total	$	3,303,359	$	2,799,884

All amounts are in Canadian dollars unless otherwise stated.

No other audit firms provided audit services in 2018 or 2017 .

The nature of each category of fees is described below:

Audit Fees

Audit fees are for professional services rendered for the audit and review of our financial statements or services provided in connection with statutory and regulatory filings and providing comfort letters associated with securities documents.

Audit-Related Fees

Assurance and related services that are reasonably related to the performance of the audit or review of our financial statements that are not included under "Audit Fees" .

Tax Fees

Tax fees are tax-related services for review of tax returns, assistance with questions on tax audits, and tax planning.

All Other Fees

Products and services provided by the 'Corporation's auditor other than those services reported under "Audit Fees" , "Audit-Related Fees" and "Tax Fees" . This includes fees related to training services provided by the auditor.

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.

Percentage of Services Approved by the ARC

For the year ended December 31, 2018 , none of the services described above were approved by the ARC pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

OFF-BALANCE SHEET ARRANGEMENTS

TransAlta currently has no off-balance sheet arrangements. See page M33 of Exhibit 13.2, incorporated by reference herein under the heading “Unconsolidated Structured Entities or Arrangements”.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

See page M33 of Exhibit 13.2, incorporated by reference herein, under the heading “Capital Structure” and page F90 under the heading “Commitments and Contingencies” of Exhibit 13.3, all incorporated by reference herein.

IDENTIFICATION OF THE AUDIT COMMITTEE

We have a separately-designated standing ARC established in accordance with Section 3(a)58(A) of the Exchange Act, and made up of independent directors. The members of the ARC are:

Beverlee F. Park (Chair)

John P. Dielwart

Timothy W. Faithfull

Alan J. Fohrer

Bryan D. Pinney

MINE SAFETY

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 13.1, incorporated herein, under the heading “Business of TransAlta – U.S. Coal Business Segment”.

FORWARD-LOOKING INFORMATION

This Form 40-F, the documents incorporated herein by reference, and other reports and filings of the Company 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 Form 40-F (or a document incorporated herein by reference) contains forward-looking statements including, but not limited to statements pertaining to: our transformation, growth, capital allocation and debt reduction strategies; growth opportunities from 2018 to beyond 2031; potential for growth in renewables, and greenfield development acquisitions; the amount of capital allocated to new growth; 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 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, and the timing thereof; the form of any definitive agreement with Tidewater regarding the construction of a pipeline; the terms of the current or any further proposed Normal Course Issuer Bid, including timing, and number of shares to be repurchased pursuant to such Normal Course Issuer Bid; the mothballing of certain units; 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, including for clean energy, 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 and other fuel 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 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; 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. dollar 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; and our credit practices.

The forward-looking statements contained in this Form 40-F (or a document incorporated herein by reference) are based on many assumptions including, but not limited to, the following material assumptions: no significant changes to applicable laws, including any tax and regulatory changes in the markets in which we operate; no material adverse impacts to the investment and credit markets; assumptions related to 2019 guidance include: Alberta spot power price equal CDN$50 to CDN$60 per MWh; Alberta contracted power price equal to CDN$50 to CDN$55 per MWh; Mid-C spot power prices equal to US$20 to US$25 per MWh; Mid-C contracted power price of US$47 to US$53 per MWh; sustaining capital between CDN$160 million and CDN$190 million; productivity capital of CDN$10 to CDN$15 million; Sundance coal capacity factor of 30%; hydro and wind resource being approximately in-line with long-term average; our proportionate ownership of TransAlta Renewables not changing materially; no material decline in the dividends expected to be received from TransAlta Renewables; the expected life extension of the coal fleet and anticipated financial results generated on conversion; assumptions regarding the ability of the converted units to successfully compete in the Alberta capacity market; and assumptions regarding the our current strategy and priorities, including as it pertains to our current priorities relating to the coal-to-gas conversions, growing TransAlta Renewables, and being able to realize the full economic benefit from the capacity, energy and ancillary services from our Alberta hydro assets once the applicable power purchase arrangement has expired.

Forward-looking statements are subject to a number of significant risks, uncertainties and assumptions that could cause actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this Form 40-F (or a document incorporated herein by reference) include, but are not limited to, risks relating to: fluctuations in demand, market prices and the availability of fuel supplies required to generate electricity; changes in demand for electricity and capacity and our ability to contract our generation for prices that will provide expected returns and replace contracts as they expire; the legislative, 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 or market 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 and other climate-change related risks; unexpected increases in cost structure and disruptions in the source of fuels, water or wind required to operate our facilities; failure to meet financial expectations; natural and man-made disasters resulting in dam failures; 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; the need to engage or rely on certain stakeholder groups and third parties; fluctuations in the value of foreign currencies and foreign political risks; the need for and availability of additional financing; structural subordination of securities; counterparty credit risk; changes in credit and market conditions; changes to our relationship with, or ownership of, TransAlta Renewables Inc.; risks associated with development projects and acquisitions, including capital costs, permitting, labour and engineering risks; increased costs or delays in the construction or commissioning of pipelines to converted units; changes in expectations in the payment of future dividends, including from TransAlta Renewables Inc.; insurance coverage; credit ratings; our provision for income taxes; legal, regulatory, and contractual disputes and proceedings involving the Corporation, including as it pertains to establishing commercial operations at the South Hedland Power Station; outcomes of investigations and disputes; reliance on key personnel; labour relations matters; and development projects and acquisitions, including delays in the development of the Brazeau Pumped Storage Project. The foregoing risk factors, among others, are described in further detail under the heading "Risk Factors" in the documents incorporated by reference in this Form 40-F, including our

Management's Discussion and Analysis for the year ended December 31, 2018 and the Annual Information Form for the year ended December 31, 2018 .

Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this document are made only as of the date hereof and the Company does not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties and assumptions, the forward-looking events might occur to a different extent or at a different time than TransAlta has described or might not occur. TransAlta cannot assure that projected results or events will be achieved.

DOCUMENTS FILED AS PART OF THIS REPORT AND EXHIBITS

The following items are specifically incorporated by reference in, and form an integral part of, this filing on Form 40-F:



13.1		TransAlta Corporation Annual Information Form for the year ended December 31, 2018
13.2		Management’s Discussion and Analysis for the year ended December 31, 2018
13.3		Consolidated Audited Annual Financial Statements for the year ended December 31, 2018
13.4		Management’s Annual Report on Internal Control over Financial Reporting, (included on page F2 of Exhibit 13.3 filed herewith).
13.5		Independent Auditors’ Report of Registered Public Accounting Firm, (included on page F4 of Exhibit 13.3 filed herewith).
23.1		Consent of Ernst & Young LLP Chartered Accountants.
31.1		Certification of President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of President and Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101		Interactive Data File

UNDERTAKING

TransAlta undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

CONSENT TO SERVICES OF PROCESS

The registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises and is filing contemporaneously herewith an amendment to the Form F-X to report a change in the agent for service of process. Any change to the name or address of the agent for service of process of the registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the registrant.

EXHIBIT INDEX



13.1		TransAlta Corporation Annual Information Form for the year ended December 31, 2018
13.2		Management’s Discussion and Analysis for the year ended December 31, 2018
13.3		Consolidated Audited Annual Financial Statements for the year ended December 31, 2018
13.4		Management’s Annual Report on Internal Control over Financial Reporting, (included on page F2 of Exhibit 13.3 filed herewith).
13.5		Independent Auditors’ Report of Registered Public Accounting Firm, (included on page F4 of Exhibit 13.3 filed herewith).
23.1		Consent of Ernst & Young LLP Chartered Accountants.
31.1		Certification of President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of President and Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101		Interactive Data File

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized, in the City of Calgary, Province of Alberta, Canada.



	TRANSALTA CORPORATION



	/s/ Christophe Dehout
	Christophe Dehout
	Chief Financial Officer

Dated: February 26, 2019

TRANSALTA CORPORATION

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2018

February 26, 2019



TABLE OF CONTENTS
PRESENTATION OF INFORMATION	3
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	3
DOCUMENTS INCORPORATED BY REFERENCE	5
CORPORATE STRUCTURE	5
OVERVIEW	7
GENERAL DEVELOPMENT OF THE BUSINESS	8
BUSINESS OF TRANSALTA	14
Canadian Coal Business Segment	15
Canadian Gas Business Segment	17
Australian Gas Business Segment	18
Hydro Business Segment	19
Wind and Solar Business Segment	23
U.S. Coal Business Segment	26
Energy Marketing Segment	27
Corporate Segment	27
Non-Controlling Interests	28
PPAs	29
Competitive Environment	30
Regulatory Framework	32
Competitive Strengths	33
ENVIRONMENTAL RISK MANAGEMENT	34
Ongoing and Recently Passed Environmental Legislation	34
TransAlta Activities	36
RISK FACTORS	39
EMPLOYEES	51
CAPITAL STRUCTURE	52
Common Shares	52
First Preferred Shares	52
Credit Facilities	61
Long-Term Debt	61
Non-Recourse Debt	61
Tax Equity	61
Restrictions on Debt	61
CREDIT RATINGS	61
DIVIDENDS	64
Common Shares	65
Preferred Shares	65
MARKET FOR SECURITIES	67
Common Shares	68
Preferred Shares	69
DIRECTORS AND OFFICERS	73
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	84
INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS	84
CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS	85
CONFLICTS OF INTEREST	85
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	86
TRANSFER AGENT AND REGISTRAR	86
INTERESTS OF EXPERTS	86
ADDITIONAL INFORMATION	86
AUDIT AND RISK COMMITTEE	86
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, 2018. 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, including the documents incorporated herein by reference, includes "forward-looking information", within the meaning of applicable Canadian securities laws, and "forward-looking statements", within the meaning of applicable United States securities laws, including the United States Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements"). All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made and on management's experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may", "will", "can"; "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, events or results and are subject to risks, uncertainties and other important factors that could cause our actual performance, events or results to be materially different from that set out in the forward-looking statements.

In particular, this Annual Information Form (or a document incorporated by reference) contains forward-looking statements including, but not limited to: our transformation, growth, capital allocation and debt reduction strategies; growth opportunities from 2018 to 2031 and beyond; potential for growth in renewables, and greenfield development acquisitions; the amount of capital allocated to new growth or development projects; our business and anticipated future financial performance and anticipated results, including our outlook and performance targets; our expected success in executing on our growth and development projects; the timing and the completion of growth projects, including major projects such 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, and the timing thereof; the form of any definitive agreement with Tidewater regarding the construction of a pipeline; the terms of the current or any further proposed Normal Course Issuer Bid and the acceptance thereof by the Toronto Stock Exchange, including timing, and number of shares to be repurchased pursuant to the Normal Course Issuer Bid; the mothballing of certain units; the impact of certain hedges on future earnings, results and cash flows; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity, including for clean energy, 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 and other fuel 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 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; 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 and accounting policies; anticipated growth rates and competition 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 or at all; 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; and our credit practices.

- 3 -

The forward-looking statements contained in this Annual Information Form (or a document incorporated by reference) are based on many assumptions including, but not limited to, the following material assumptions: no significant changes to applicable laws, including any tax and regulatory changes in the markets in which we operate; no material adverse impacts to the investment and credit markets; assumptions related to 2019 guidance include: Alberta spot power price equal $50 to $60 per MWh; Alberta contracted power price equal to $50 to $55 per MWh; Mid-C spot power prices equal to US$20 to US$25 per MWh; Mid-C contracted power price of US$47 to US$53 per MWh; sustaining capital between $160 million and $190 million; productivity capital of $10 to $15 million; Sundance coal capacity factor of 30%; hydro and wind resource being approximately in-line with long-term average; our proportionate ownership of TransAlta Renewables not changing materially; no material decline in the dividends expected to be received from TransAlta Renewables; the expected life extension of the coal fleet and anticipated financial results generated on conversion; assumptions regarding the ability of the converted units to successfully compete in the Alberta capacity market; and assumptions regarding the our current strategy and priorities, including as it pertains to our current priorities relating to the coal-to-gas conversions, growing TransAlta Renewables, and being able to realize the full economic benefit from the capacity, energy and ancillary services from our Alberta hydro assets once the applicable power purchase arrangement has expired.

Forward-looking statements are subject to a number of significant risks, uncertainties and assumptions that could cause actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this AIF (or a document incorporated herein by reference) include, but are not limited to, risks relating to: fluctuations in demand, market prices and the availability of fuel supplies required to generate electricity; changes in demand for electricity and capacity and our ability to contract our generation for prices that will provide expected returns and replace contracts as they expire; the legislative, 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 or market 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 and other climate-change related risks; unexpected increases in cost structure and disruptions in the source of fuels, water or wind required to operate our facilities; failure to meet financial expectations; natural and man-made disasters resulting in dam failures; 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; the need to engage or rely on certain stakeholder groups and third parties; fluctuations in the value of foreign currencies and foreign political risks; the need for and availability of additional financing; structural subordination of securities; counterparty credit risk; changes in credit and market conditions; changes to our relationship with, or ownership of, TransAlta Renewables Inc.; risks associated with development projects and acquisitions, including capital costs, permitting, labour and engineering risks; increased costs or delays in the construction or commissioning of pipelines to converted units; changes in expectations in the payment of future dividends, including from TransAlta Renewables Inc.; insurance coverage; credit ratings; our provision for income taxes; legal, regulatory, and contractual disputes and proceedings involving the Corporation, including as it pertains to establishing commercial operations at the South Hedland Power Station; outcomes of investigations and disputes; reliance on key personnel; labour relations matters; and development projects and acquisitions, including delays in the development of the Brazeau Pumped Storage Project. The foregoing risk factors, among others, are described in further detail under the heading "Risk Factors" in this Annual Information Form or in a document incorporated by reference, including our management's discussion and analysis for the year ended December 31, 2018 (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 them, which reflect the Corporation's expectations only as of the date hereof. 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 statements might occur to a different extent or at a different time than we have described or might not occur at all. We cannot assure that projected results or events will be achieved.

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DOCUMENTS INCORPORATED BY REFERENCE

TransAlta's audited consolidated financial statements for the year ended December 31, 2018 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 is a corporation organized under the Canada Business Corporations Act (the "CBCA"). It was formed by Certificate of Amalgamation issued 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 then 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 a partnership agreement and a management services agreement. Immediately following the transfer of assets by TAU and TEC to TransAlta Generation Partnership, TransAlta Corporation amalgamated with TAU, TEC, and Keephills 3 GP Ltd. pursuant to the provisions of the CBCA.

TransAlta amended its articles on December 7, 2010, 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.

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

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Our Subsidiaries

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

Certain of our subsidiaries are not wholly-owned. The most significant of which is TransAlta Renewables Inc. ("TransAlta Renewables"), which completed its initial public offering in August 2013. 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. As at December 31, 2018, TransAlta Corporation owned, directly or indirectly, approximately 61 per cent of the outstanding voting equity in TransAlta Renewables. See " Business of TransAlta – Non-Controlling Interests – TransAlta Renewables ".

Notes:


(1)	Unless otherwise stated, ownership is 100 per cent. As noted elsewhere in this AIF, TransAlta Renewables has economic interests in a number of projects through preferred shares in the capital of TA Energy Inc. and TransAlta Power Ltd., which are both wholly-owned by TransAlta Corporation.


(2)	We own, directly or indirectly, an aggregate interest of approximately 61 per cent of TransAlta Renewables, which includes 38 per cent through direct ownership and 23 per cent through TransAlta Generation Partnership. The remaining 39 per cent interest in TransAlta Renewables is publicly owned.

(3) The remaining 1.56 per cent of TA Energy Inc. is owned by TransAlta.

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OVERVIEW

TransAlta

TransAlta and its predecessors have been engaged in the development, 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 in approximately 8,000 megawatts ("MW") of generating capacity ⁽¹⁾⁽²⁾ . We operate facilities having approximately 9,331 MW of aggregate generating capacity. 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.

Our Segments

The Canadian Coal segment has a net ownership interest of approximately 3,033 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, British Columbia, and Ontario.

The Wind and Solar segment has a net ownership interest of approximately 1,353 MW of electrical generating capacity and includes facilities located in Alberta, Ontario, New Brunswick, Québec, Wyoming, Massachusetts, and Minnesota.

The Canadian Gas segment has a net ownership interest of approximately 837 MW of electrical generating capacity and includes facilities held in Alberta and Ontario.

The Australian Gas segment has a net ownership interest of approximately 450 MW of electrical generating capacity.

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.

The Corporate Segment supports each of the above segments and includes the Corporation's central finance, legal, administrative, and investor relation functions.

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.

TransAlta Renewables

TransAlta Corporation is the majority owner of TransAlta Renewables, with an approximate 61 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.

We formed TransAlta Renewables in 2013 to realize specific strategic and financial benefits, including: (i) establishing a focused vehicle for pursuing and funding growth opportunities in the renewable power generation sector; (ii) unlocking the value of TransAlta’s renewable asset platform; (iii) retaining TransAlta’s majority ownership and operatorship of the underlying assets; (iv) providing proceeds of approximately $200-$250 million to repay debt and support TransAlta’s balance sheet; and (v) creating additional financial flexibility for TransAlta by providing another source of capital with a separate cost of capital. We continue to realize the benefit of having assets with different risk/return profiles in two different legal entities, including as it enables each company to secure appropriate financing and investors. TransAlta

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(1)

The net ownership interest of 7,939 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 61 per cent direct and indirect ownership interest in TransAlta Renewables.


(2)	MW information provided as of December 31, 2018.

holds mainly merchant assets in coal and hydro while TransAlta Renewables holds assets with long term contracts generating stable cash flows in wind, solar and gas. TransAlta’s majority ownership of TransAlta Renewables has facilitated the Corporation in its overall strategy of developing, constructing or acquiring additional renewable assets.

TransAlta Renewables, or one or more of its wholly-owned subsidiaries, directly own certain of our wind, hydro and natural gas facilities. TransAlta Renewables also owns an economic interest in a number of our other facilities. TransAlta Corporation provides all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets pursuant to the Management and Operational Services Agreement and the Governance and Cooperation Agreement between TransAlta Corporation and TransAlta Renewables. See " Business of TransAlta – Non-Controlling Interests – TransAlta Renewables ".

TransAlta's Map of Operations

The following map outlines TransAlta's operations as of December 31, 2018.

Note:


(1)	Includes facilities directly owned by TransAlta Renewables or its subsidiaries, as well as facilities in which TransAlta Renewables or one of its subsidiaries has an economic interest. We own, directly or indirectly, an aggregate interest of approximately 61 per cent of TransAlta Renewables.

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

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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 investor relation functions.

The past number of years have been marked by significant regulatory changes that have had extensive impacts on the Corporation's business and strategy. In 2015, the Government of Alberta announced the Alberta Climate Leadership Plan that set goals to reduce carbon emissions and phase out pollution from coal-generated electricity by 2030. TransAlta responded quickly and decisively to the Climate Leadership Plan to begin transforming itself into a leading clean energy company. We negotiated with the Government of Alberta, using a principles-based approach, to ensure that we have the certainty and capacity needed to invest in clean power and, 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.

The significant events and conditions affecting our business during the three most recently completed financial years, and during the current year to date, are summarized below. Certain of these events and conditions are discussed in greater detail under the heading " Business of TransAlta " .

Recent Developments

Generation and Business Development

2018

Pioneer Pipeline

On December 17, 2018, we exercised our option to acquire 50 per cent ownership in the Pioneer gas pipeline ("Pioneer Pipeline"). Tidewater Midstream and Infrastructure Ltd. ("Tidewater") will construct and operate the 120 km natural gas pipeline, which will have an initial throughput of 130 million cubic feet of gas per day ("MMcf/d") with the potential to expand to approximately 440 MMcf/d. The Pioneer Pipeline will allow us to increase the amount of natural gas that can be co-fired at the Sundance and Keephills coal-fired units, resulting in lower carbon emissions and costs. As well, the Pioneer Pipeline will provide a significant amount of the gas required for the full conversion of the coal units to natural gas. Our investment will amount to approximately $90 million. Construction of the pipeline commenced in November 2018 and the Pioneer Pipeline is expected to be fully operational by the second half of 2019. Our investment is subject to final regulatory approvals, which we are expecting to be finalized in the first half of 2019.

Alberta Renewable Energy Program Project – Windrise

Also on December 17, 2018, we announced that our 207 MW Windrise wind project was selected by the AESO as one of the two successful projects in the third round of the Alberta Renewable Electricity Program. The Windrise facility, which is located in the county of Willow Creek, is underpinned by a 20-year Renewable Electricity Support Agreement with the AESO. The project is expected to cost approximately $270 million and is targeted to reach commercial operation during the second quarter of 2021.

TransAlta Renewables' New Brunswick wind power expansion complete

On October 19, 2018 TransAlta Renewables announced that the 17.25MW expansion of the wind facility at Kent Hills, in New Brunswick reached commercial operation, bringing total generating capacity to 167 MW. Under the 17-year PPA, New Brunswick Power Corporation receives both energy to the province's electricity grid and renewable energy credits. The Kent Hills 3 expansion is located on approximately 20 acres of Crown Land and consists of five Vestas V126 turbines. Natural Forces Technologies Inc., a wind-energy developer based in Atlantic Canada, co-developed and co-owns the wind farm with TransAlta Renewables.

Retirement of Sundance Unit 1 and Unit 2 and Mothball Schedule Update

Effective July 31, 2018, we retired Sundance Unit 2 due to its shorter useful life relative to other units, age, size, and the capital requirements needed to return the unit to service. In addition to the retirement of Sundance

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Unit 2 our mothball outage schedule has been updated to provide for the following (Sundance Unit 1 has been permanently shutdown since January 1, 2018 and Sundance Unit 3 and Sundance Unit 5 have been mothballed since April 1, 2018): (i) Sundance Unit 3 will continue to be mothballed for a period of up to April 1, 2020; (ii) Sundance Unit 5 will now continue to be mothballed for a period of up to April 1, 2020; and (iii) Sundance Unit 4 is no longer expected to be mothballed on April 1, 2019, as had previously been scheduled.

Sale of Three Renewable Assets

On May 31, 2018, TransAlta Renewables acquired from us an economic interest in the 50 MW Lakeswind Wind Farm in Minnesota and 21 MW of solar projects located in Massachusetts. In addition, TransAlta Renewables acquired ownership of the 20 MW Kent Breeze Wind Farm located in Ontario. The total purchase price payable for the three assets, which have an average weighted contract life of 15 years, was $166 million, including the assumption by TransAlta Renewables of $62 million of tax equity obligations and project debt. TransAlta Renewables funded the equity portion of the acquisitions using its existing liquidity.

Acquisition of U.S. Wind Projects

On February 20, 2018, TransAlta Renewables entered into an arrangement to acquire two construction-ready projects in the Northeastern United States. The wind development projects consist of: (i) a 90 MW project located in Pennsylvania that has a 15-year PPA with Microsoft Corp. ("Big Level") and (ii) a 29 MW project located in New Hampshire with two 20-year PPAs ("Antrim") (collectively, the "US Wind Projects"). The acquisition of Antrim is subject to certain closing conditions, including the receipt of favourable regulatory ruling. We expect the Antrim acquisition to close in early 2019. The commercial operation date for both projects is expected during the second half of 2019.

2017

Acceleration of the Conversion from Coal-to-Gas

On December 6, 2017, we announced the acceleration of the conversion of Sundance Units 3 to 6 and Keephills Units 1 and 2 from coal-fired generation to gas-fired generation in 2021 or 2022, a year earlier than originally planned. We also announced the temporary mothballing of a combination of Sundance units in 2018 and 2019 to enable two Sundance coal units to operate at high capacity utilizations with lower costs through to 2020. As part of our optimization plan for the Sundance facility, we subsequently mothballed Sundance Units 3 and 5 on April 1, 2018.

Balancing Pool Terminates the Sundance Alberta Power Purchase Arrangements

On September 18, 2017, we received formal notice from the Balancing Pool for the termination of the Alberta Power Purchase Arrangements for Sundance Unit B and Unit C effective March 31, 2018. We subsequently received $157 million in the first quarter of 2018 as a result of the PPA termination. The Balancing Pool excluded certain mining assets that we believe should be included in the value calculation for an additional termination payment of $56 million. The dispute is currently proceeding through the PPA arbitration process.

Status of Commercial Operations at South Hedland Power Station

On August 1, 2017, we responded to Fortescue Metals Group Limited's ( " FMG " ) view that the South Hedland Power Station has not yet achieved commercial operation. In our view, all the conditions to establishing that commercial operations have been achieved under the terms of the power purchase agreement with FMG have been satisfied in full. These conditions include receiving a commercial operation certificate, successfully completing and passing certain test requirements, and obtaining all permits and approvals required from the North West Interconnected System and government agencies. On November 13, 2017, we received formal notice of termination of the South Hedland Power Purchase Agreement ( " South Headland PPA " ) from FMG. We commenced proceedings in the Supreme Court of Western Australia on December 4, 2017, to recover amounts invoiced under the South Hedland PPA. The South Hedland Power Station has been fully operational and able to meet FMG's requirements under the terms of the South Hedland PPA since July 2017.

Fortescue Metals Group's Notice to Repurchase the Solomon Power Station

On August 1, 2017, we received notice of FMG's intention to repurchase the Solomon Power Station from TEC Pipe Pty Ltd. ("TEC Pipe"), a wholly-owned subsidiary of the Corporation, for approximately US$335

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million. FMG completed its acquisition of the Solomon Power Station on November 1, 2017 and TEC Pipe received US$325 million as consideration. While FMG withheld approximately AU$43 million in tax applicable to the repurchase of the Solomon Power Station, TransAlta commenced court proceedings and was successful in recovering the total tax payable by FMG.

Sale of Interest in Wintering Hills Facility

On March 1, 2017, we sold our 51 per cent interest in the Wintering Hills merchant wind facility near Drumheller, Alberta for approximately $61 million. Proceeds from the sale were used for general corporate purposes, including to reduce debt and to fund future renewables growth, including potential contracted renewable opportunities in Alberta.

2016

Mississauga Recontracting

On December 22, 2016, we signed a Non-Utility Generator Enhanced Dispatch Contract (the " NUG Contract " ) with the Ontario Independent Electricity System Operator ( " IESO " ) for our Mississauga cogeneration 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 cogeneration facility's existing contract with the Ontario Electricity Financial Corporation ( " OEFC " ), which would have otherwise terminated in December 2018. In December 2018, TransAlta exercised its option to terminate its lease agreement with Boeing Canada Inc. effective December 31, 2021. TransAlta is required to remove the plant and restore the site within the three-year time frame.

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 for transition payments in consideration for our 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 are entitled to receive annual cash payments of approximately $37.4 million, net to the Corporation, commencing in 2017 and terminating in 2030. Our receipt of these payments is subject to our satisfaction of certain terms and conditions, including our cessation of all coal-fired emissions 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.

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 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. The buyer under this power purchase arrangement and the Balancing Pool are seeking to appeal or set the arbitration panel's decision aside, which we believe to be without merit. This application is scheduled from February 27, 2019 to March 1, 2019.

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.

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Corporate and Energy Marketing

2019

Retirement Plans for Directors

On January 25, 2019, we announced the retirement decisions of Timothy Faithfull and Ambassador Gordon Giffin. Earlier in 2018, Mr. Faithfull had indicated to the Board his intention to retire from the Board of Directors immediately following TransAlta’s 2019 Annual Shareholder Meeting and, also in 2018, Ambassador Gordon Giffin announced his intention to retire as director and Board Chair in 2020. The Board is undertaking a process to identify a new Chair through the course of 2019.

2018

Appointment of Chief Financial Officer

On November 13, 2018, we appointed Christophe Dehout as our Chief Financial Officer, replacing Brett Gellner (our then interim Chief Financial Officer), who continues to serve as Chief Strategy and Investment Officer of TransAlta. Our prior Chief Financial Officer, Donald Tremblay, resigned his position effective May 8, 2018.

Redemption of Medium Term Notes

On August 2, 2018 we redeemed all of our then outstanding 6.40 per cent Medium Term Notes, due November 18, 2019 in the aggregate principal amount of $400 million (the "Notes"). The redemption price for these Notes was $1,061.736 per $1,000 principal amount of the Notes (representing, in aggregate, $425 million) including a prepayment premium and accrued and unpaid interest on the Notes to the redemption date.

$345 Million Bond Offering

On July 20, 2018 our indirect wholly-owned subsidiary, TransAlta OCP LP (the "TransAlta OCP"), issued approximately $345 million of bonds, sold by way of a private placement, which are secured by, among other things, a first ranking charge over all but a nominal percentage of the equity interests in TransAlta OCP and its general partner, and a first ranking charge over all of the TransAlta OCP's accounts and certain other assets. The amortizing bonds bear interest from their date of issue at a rate of 4.509 per cent per annum, payable semi-annually and mature on August 5, 2030.

TransAlta Renewables Completes $150 Million Bought Deal Offering of Common Shares

On June 22, 2018, TransAlta Renewables issued, pursuant to an underwritten offering on a bought deal basis, 11,860,000 common shares in the capital of TransAlta Renewables at a price of $12.65 per share for gross proceeds to TransAlta Renewables of approximately $150 million. As a result of the offering, our interest in TransAlta Renewables was reduced from approximately 64 percent to 61 percent.

Voting Results of Board of Directors

At our 2018 annual and special meeting of shareholders held on April 20, 2018, Mr. Bryan Pinney was elected as a new member of the Board of Directors, replacing Thomas Jenkins. Mr. Pinney has over 30 years of experience serving many of Canada's largest corporations, primarily in energy and resources and construction. Mr. Pinney was a partner with Deloitte between 2002 and 2015. Mr. Pinney served as Calgary Managing Partner from 2002 through 2007 and as National Managing Partner of Audit & Assurance from 2007 to 2011 and Vice-Chair until June 2015.

Normal Course Issuer Bid

On March 9, 2018, the Toronto Stock Exchange ("TSX") accepted our notice to implement a normal course issuer bid ("NCIB"). Pursuant to the NCIB, we may purchase up to a maximum of 14,000,000 of our common shares. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which our common shares are traded, based on the prevailing market

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price and subject to certain limitations. Any common shares purchased under the NCIB will be cancelled. As at February 26, 2019 we purchased and cancelled a total of 3,264,500 common shares at an average price of $7.02 per common share for a total cost of approximately $23 million.

Redemption of Senior Notes

On March 15, 2018, we redeemed all of our then outstanding US$500 million 6.65 per cent senior notes maturing May 15, 2018. The redemption price for the notes was approximately $617 million, including a $5 million early redemption premium and accrued and unpaid interest on the notes to the redemption date.

2017

New Brunswick Wind Asset Project Financing

On October 2, 2017, TransAlta Renewables completed a $260 million bond offering on behalf of its indirect wholly-owned subsidiary, Kent Hills Wind LP, which is secured by a first ranking charge over all assets of Kent Hills Wind LP. The bonds are amortizing and bear interest from their date of issue at a rate of 4.454 per cent, payable quarterly and mature on November 30, 2033. Net proceeds were used to fund a portion of the construction costs for the 17.25 MW Kent Hills 3 expansion (upon meeting certain completion tests and other specified conditions) and to make advances to Canadian Hydro Developers, Inc. ("CHD") and to an affiliate of Natural Forces Technologies Inc., the Corporation's partner who owns approximately 17 per cent of Kent Hills Wind LP. The proceeds of the advances to CHD were used to redeem all of CHD's outstanding debentures.

TransAlta Appoints the Honourable Rona Ambrose to its Board of Directors

Effective July 13, 2017, our Board of Directors appointed the Honourable Rona Ambrose to our Board of Directors. The Honourable Rona Ambrose was the former Leader of Canada's Official Opposition in the House of Commons and former leader of the Conservative Party of Canada. She also acted as Minister of the Crown across nine government departments, including serving as Vice Chair of the Treasury Board and Chair of the cabinet committee for public safety, justice and aboriginal issues.

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 TAPC and its general partner, and a first ranking charge over all of TAPC's accounts and certain other assets. The bonds, which mature on December 31, 2030, 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.

Québec 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 LP ("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 per cent, payable semi-annually and mature on June 30, 2032. Proceeds were used to make advances to CHD 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. For further details, see " Capital Structure ".

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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 Plans.

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 Québec. 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.

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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.

As the Corporation transforms into a leading clean energy company, it is expected that the proportion of revenue attributable to the Canadian Coal and U.S. Coal business will decline relative to the other business units. In addition, the Corporation has been implementing Project Greenlight in order to facilitate the transition to a leaner organization with a reduced cost structure to support the new business model.

The following table identifies each business segment's contribution to revenues as at December 31, 2018:



	2018 Revenues ⁽¹⁾	2017 Revenues ⁽¹⁾

Canadian Coal	40%	43%
U.S. Coal	20%	19%
Canadian Gas	10%	11%
Australian Gas	7%	6%
Wind and Solar	13%	13%
Hydro	7%	5%
Energy Marketing	3%	3%
Corporate	0%	0%

Notes:


(1)	Includes 100% of the revenue of TransAlta Renewables or its subsidiaries, as well as facilities in which TransAlta Renewables or one of its subsidiaries has an economic interest. We own, directly or indirectly, an aggregate interest of approximately 61 per cent of TransAlta Renewables.

For further information on our segment earnings and assets, please refer to Note 34 of our audited consolidated financial statements for the year ended December 31, 2018, 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.

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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. 3 ⁽⁵⁾	AB	100	368	1976	Merchant	-
Sundance Unit No. 4 ⁽⁵⁾	AB	100	406	1977	Merchant	-
Sundance Unit No. 5 ⁽⁵⁾	AB	100	406	1978	Merchant	-
Sundance Unit No. 6 ⁽⁵⁾	AB	100	401	1980	Merchant	-
Total Canadian Coal Net Capacity			3,033

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)	The Balancing Pool elected to terminate the Sundance B PPA and Sundance C PPA effective on or before March 31, 2018.

The Genesee 3 facility, located approximately 50 kilometres west of Edmonton, Alberta, is jointly owned with Capital Power Corporation ("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 ("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 Unit 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 each have a maximum capacity of 395 MW. The Sheerness facility is located approximately 200 kilometres northeast of Calgary, Alberta and is jointly owned by TransAlta Cogeneration LP ("TA Cogen") and ATCO Power (2000) Ltd. ("ATCO Power"). See " Business of TransAlta – Non-Controlling Interests ".

On November 24, 2016, we entered into the Off-Coal Agreement with the Government of Alberta pertaining to our cessation of coal-fired emissions from the Keephills 3, Genesee 3, and Sheerness coal-fired facilities. The Off-Coal Agreement provides that we are entitled to receive annual cash payments of approximately $37.4 million, net to TransAlta, from the Government of Alberta commencing in 2017 and terminating in 2030, subject to satisfaction of certain terms and conditions including our cessation of all coal-fired emissions on or before December 31, 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, in each case as prescribed by the Off-Coal Agreement. See " General Development of the Business - Generation and Business Development ".

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. Prairie Mines & Royalty Ltd., 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

- 16 -

Mining Limited Partnership ("SunHills"). The decision to directly operate our facility was made 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. 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 operating the facility. Keephills 3 began commercial operations on September 1, 2011. Each partner independently dispatches and markets its share of the unit's electrical output. We provide the coal fuel to the facility from 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. See " Business of TransAlta – Non-Controlling Interests ".

On January 1, 2018 we retired Sundance Unit 1 and mothballed Sundance Unit 2. On April 1, 2018, we mothballed Sundance Unit 3 and Sundance Unit 5. On July 31, 2018, we permanently retired Sundance Unit 2 due to its shorter useful life relative to other units, age, size, and the capital requirements needed to return the unit to service. The retirement is consistent with our transition to clean power strategy.

During 2018, we updated our mothball outage schedule to provide for the following:


•	Sundance Unit 3 will continue to be mothballed for a period of up to April 1, 2020;


•	Sundance Unit 5 will continue to be mothballed for a period of up to April 1, 2020; and


•	Sundance Unit 4 is no longer expected to be mothballed on April 1, 2019, as had previously been scheduled. and we will perform maintenance during the first half of 2019.

The decision to mothball selected units ensures that the remaining units operate at strong capacity utilization factors which ensure competitive cost structures. See " General Development of the Business - Generation and Business Development ".

We have accelerated the conversion from coal to gas of Sundance Units 3 to 6 and Keephills Units 1 and 2 in the 2020 to 2023 time frame. The coal-fired plants we operate, once converted to gas, are anticipated to be able to run through to 2031 to 2039.

Canadian Gas Business Segment

The following table summarizes our Canadian natural gas-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	2029
Poplar Creek ⁽⁴⁾	AB	100	230	2001	LTC	2030
Ottawa ⁽⁵⁾	ON	50	37	1992	LTC/Merchant	2019-2033
Sarnia ⁽³⁾	ON	100	499	2003	LTC	2022-2025
Windsor ⁽⁵⁾	ON	50	36	1996	LTC/Merchant	2031
Total Cdn Gas Net Capacity			837

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, directly or indirectly, approximately 61 per cent of the common shares in TransAlta Renewables.


(2)	Where no contract expiry date is indicated, the facility operates as merchant.


(3)	Facility is owned by TransAlta Renewables.


(4)	The Poplar Creek plant is operated by Suncor and ownership of the facility will transfer to Suncor Energy Inc. in 2030.


(5)	Our interests in these facilities are through our ownership interest in TA Cogen.


(6)	As of January 2018, the Mississauga facility is no longer actively generating electricity.

We have a net ownership interest of 30 per cent in the Fort Saskatchewan facility. See " Business of TransAlta – Non-Controlling Interests ". The 118 MW natural gas-fired Combined-Cycle cogeneration Fort Saskatchewan plant is owned by TA Cogen and Prairie Boys Capital Corporation (previously known as Strongwater Energy Ltd). During the fourth quarter of 2017, we entered into a long-term contract for the Fort Saskatchewan facility providing for the delivery of energy and steam to the customer. The contract has an initial 10-year term, commencing on January 1, 2020, with the option for two five-year extensions. The contract allows our customer to continue to benefit from the operational flexibility of the plant.

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 cogeneration facility is owned by TA Cogen. See " Business of TransAlta – Non-Controlling Interests ". 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. As of January 2017, the Mississauga facility is no longer actively generating electricity and on December 31, 2018, the enhanced dispatch contract with Ontario's IESO expired. In December 2018, TransAlta exercised its option to terminate its lease agreement with Boeing Canada Inc. effective December 31, 2021. TransAlta is required to remove the plant and restore the site within the three-year time frame.

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 automatically renewed to December 31, 2019.

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The Sarnia plant is a 499 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. " In 2018 Sarnia’s capacity was reduced from 506 MW to 499 MW due to the lay up of one generator. The reduction in capacity does not impact the plant’s ability to meet its contractual requirements.

The Windsor plant is owned by TA Cogen. See " Business of TransAlta – Non-Controlling Interests ". 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 Fiat Chrysler Automobiles Canada Inc.'s minivan assembly facility in Windsor that expires in 2020.

Australian Gas Business Segment

The following table summarizes our Australian 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
Parkeston ^{(2) (3)}	WA ⁽⁴⁾	50	55	1996	LTC	2026
South Hedland ⁽²⁾	WA ⁽⁴⁾	100	150	2017	LTC	2042
Southern Cross Energy ^{(2) (5)}	WA ⁽⁴⁾	100	245	1996	LTC	2023
Total Aus Gas Net Capacity			450

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 at December 31, 2018, TransAlta owned approximately 61 per cent of the common shares in TransAlta Renewables.


(2)	TransAlta Renewables owns an economic interest in the facility.


(3)	Plant contracted to October 2026 with early termination options beginning in 2021.


(4)	Western Australia.


(5)	Comprised of four facilities.

All of our Australian assets are owned, directly or indirectly, by TransAlta Energy (Australia) Pty Ltd. ("TEA"), a wholly-owned subsidiary of TransAlta. On May 7, 2015, TransAlta Renewables acquired tracking preferred shares that entitle TransAlta Renewables to an economic interest based on the cash flows broadly equal to the underlying net distributable profits of TEA, in consideration for a payment equal to $1.78 billion, which amount included funding the remaining construction costs for South Hedland.

Pursuant to the terms of the preferred shares, TransAlta Renewables is entitled to receive, in priority to the common shares in the capital of TEA, quarterly preferential cash dividends. The preferred shares have no residual right to participate in the earnings of TEA. In the event of the liquidation, dissolution or winding-up of TEA or any other distribution of the assets of TEA among its shareholders for the purpose of winding up its affairs, TransAlta Renewables shall be entitled, subject to applicable law, to receive from TEA as the sole holder of preferred shares, before any distribution of TEA to the holders of the common shares or any other shares ranking junior to the preferred shares, an amount equal to the fair market value of the Australian assets.

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 ("WEM"). TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Parkeston facility on May 7, 2015.

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.

In 2014, we established the Fortescue River Gas Pipeline joint venture with DBP Development Group. The joint venture (of which TransAlta is a 43 per cent partner) was successfully awarded the contract to design, build, own and operate the 270 km Fortescue River Gas Pipeline to deliver natural gas to the 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 subsidiary of

- 18 -

FMG 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.

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 achieved commercial operation on July 28, 2017. The plant was fully contracted with two customers for a 25-year term. The majority of the plant's capacity remains contracted to Horizon Power, the state-owned electricity supplier in the region. The second customer is the port operations of FMG for 35 MW of capacity. In November 2017, we received a notice from FMG purporting to terminate their power purchase agreement. We are continuing to dispute the notice purporting to terminate and we continue to invoice FMG for the contracted capacity. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the South Hedland facility on May 7, 2015.

Hydro Business Segment

The Hydro business segment holds an interest in 926 net 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 at December 31, 2018, TransAlta owned, directly or indirectly, approximately 61 per cent of the voting equity common shares 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.

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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.

- 20 -

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.

- 21 -

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 Ontario's 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.

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

- 22 -

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; 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, Washington, 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, 2018, the Wind and Solar segment held interests in approximately 1,455 MW of gross wind generating capacity from 10 wind farms in Western Canada, four in Ontario, two in Québec, three in New Brunswick, and two in the United States, more specifically in the states of Wyoming and Minnesota. We also hold an interest in 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 the sale of the power generated, 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.

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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	‑
Mass Solar ⁽³⁾⁽⁸⁾	MA	100	21	2012-2015	LTC	2032-2045
Lakeswind ⁽³⁾	MN	100	50	2014	LTC	2034
Kent Hills 1 ^{(4) (5)}	NB	83	80	2008	LTC	2035
Kent Hills 2 ^{(4) (5)}	NB	83	45	2010	LTC	2035
Kent Hills 3 ⁽⁴⁾	NB	83	14	2018	LTC	2035
Kent Breeze ⁽⁴⁾	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			1,353

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 at December 31, 2018, TransAlta owned, directly and indirectly, approximately 61 per cent of the common shares 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.

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 totaling 4 MW located individually in the Cardston

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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.

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 indirectly 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.

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. On May 31, 2018 TransAlta Renewables acquired tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the solar farm. See " General Developments of the Business – Generation and Business Development " and " Business of TransAlta – Non-Controlling Interests – TransAlta Renewables ".

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. On May 31, 2018 TransAlta Renewables acquired tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind farm. See " General Developments of the Business – Generation and Business Development ".

The Kent Hills 1 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 PPA with New Brunswick Power. Natural Forces Technologies Inc.

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("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. On June 1, 2017, we extended the term of the Kent Hills 1 PPA by two years to 2035. The Kent Hills 1 facility is entitled to receive eERP payments until December 31, 2018.

The Kent Hills 2 facility is owned by TransAlta Renewables. This Kent Hills expansion is a 54 MW wind farm which also delivers power under a 25-year PPA with New Brunswick Power, expiring in 2035. Natural Forces exercised its option to purchase a 17 per cent interest in the Kent Hills 2 expansion project subsequent to the commencement of commercial operations. The facility commenced commercial operations in 2010. The Kent Hills 2 facility is owned by TransAlta Renewables and is entitled to receive eERP payments until 2020.

On June 1, 2017, we signed a PPA with New Brunswick Power for the further expansion of the Kent Hills wind farm. This expansion project, Kent Hills 3, reached commercial operations as of October 19, 2018 and adds five 3.45 MW turbines to the Kent Hills fleet for an additional 17.25 MW at the site, bringing total generating capacity of the three Kent Hills facilities to 167 MW. The Kent Hills 3 PPA expires in 2035. The Kent Hills 3 facility is owned by TransAlta Renewables. See " General Developments of the Business – Generation and Business Development ".

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. On May 31, 2018 this facility was acquired by TransAlta Renewables. See " General Developments of the Business – Generation and Business Development ".

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 was entitled to receive eERP payments until November 30, 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 Production. 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; 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 ".

The New Richmond facility is owned by TransAlta Renewables. New Richmond is a 68 MW wind project also located on the Gaspé Peninsula of Québec. 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. TransAlta Renewables holds tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind farm. See " – Non-Controlling Interests – TransAlta Renewables ".

All of the electricity generated and sold by our Wind segment within Canada, with the exception of Macleod Flats and Kent Breeze, 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

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 Transition Bill (chapter 180, Laws of 2011) (the "Bill'') allowing the Centralia Thermal plant to comply with the State's greenhouse gas ("GHG") emissions performance standards by ceasing coal generation in 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 stop burning coal. 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, we announced that we were moving ahead with plans to invest US$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 US$55 million community investment is part of the Bill passed in 2011. The Bill was an agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State, closing Centralia facility's two coal units, one in 2020 and the other in 2025. Approved funding for the three boards totals approximately US$21.0 million as at December 31, 2018.

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 a coal contract that expires at the end of 2020. 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 two per cent of the fuel use by the Centralia plant in 2019.

Under the U.S. Federal Mine Safety and Health Act, TransAlta must report all citations at its Centralia mine. The mine is currently not in operation. There were seven injury incidents and one fatality at the mine during 2018. The total dollar value of all Mine Safety and Health Administration ("MSHA") assessments are not material. There are no pending legal actions before the Federal Mine Safety and Health Review Commission involving the Centralia mine and none occurred or were pending during 2018.

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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	25	0	0	0	0	1,389	1	No	No	0

On December 29, 2018, we were notified of an incident that occurred and resulted in the fatality of an employee of Coalview Centralia LLC, which operates a fine coal recovery project within the Centralia mine site. Coalview Centralia LLC is a company that provides reclamation services to TransAlta and is not otherwise affiliated with the Corporation. We are all deeply saddened by this situation and our thoughts and prayers are with the families, co-workers and friends impacted. Safety is an integral value at TransAlta and we continue to work every day to make our work environments safe.

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.

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Corporate Segment

Our Corporate segment includes the Corporation's central financial, legal, administrative and investor relations functions.

Non-Controlling Interests

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

TransAlta Renewables

As of December 31, 2018, we held, directly and indirectly, approximately 61 per cent of the issued and outstanding common shares in TransAlta Renewables, which is a publicly traded entity. Our ownership interest was reduced from 64 per cent to 61 per cent following TransAlta Renewables' $150 million bought deal offering. 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 Corporation provides all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets pursuant to the Management, Administrative and Operational Services Agreement between TransAlta Corporation and TransAlta Renewables. In connection with the services provided under the Management, Administrative and Operational Services Agreement, TransAlta Renewables pays us an annual fee, which is meant to cover our management, administrative, accounting, planning and other head office costs we incur in connection with providing services to TransAlta Renewables under the Management, Administrative and Operational Services Agreement (the "G&A Reimbursement Fee"). The G&A Reimbursement Fee is payable in equal quarterly installments. As at December 31, 2018, the G&A Reimbursement Fee was approximately $16 million.

The Management, Administrative and Operational Services Agreement has an initial 20-year term; provided, however, that the agreement shall be automatically renewed for further successive terms of five years after the expiry of the initial term or any renewal term, unless terminated by either party not less than 180 days prior to the expiration of the initial term or any renewal term, as the case may be. The Management, Administrative and Operational Services Agreement may be terminated by: (a) mutual agreement; (b) TransAlta Renewables upon the occurrence of a material default by TransAlta; and (c) TransAlta (i) upon the occurrence of a material default by TransAlta Renewables or (ii) upon a "Change of Control" of TransAlta Renewables, being the acquisition by any person or group of persons acting jointly and in concert (other than us and our affiliates) of more than 50 per cent of the issued and outstanding common shares. In addition, the Management, Administrative and Operational Services Agreement may be terminated by TransAlta Renewables by a majority vote of our independent directors at any time if TransAlta's direct and indirect ownership in TransAlta Renewables falls below 20 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 US$102 million. The Wyoming wind farm is managed by TransAlta under the terms of the Management, Administrative and Operational Services Agreement and is operated by NextEra Energy Resources, LLC.

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 TEA, consists of six operating assets with an installed capacity of 450 MW 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 August 1, 2017, the Class B shares converted into common 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

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Assets consist of approximately 611 MW of contracted power generation assets located in Ontario and Québec. 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. The convertible debenture was redeemed on November 9, 2017.

On May 31, 2018, we sold to TransAlta Renewables an economic interest in the Corporation's 50 MW Lakeswind Wind Farm in Minnesota and 21 MW of solar projects located in Massachusetts. In addition, we sold to TransAlta Renewables the 20 MW Kent Breeze Wind Farm located in Ontario. The total purchase price payable to TransAlta for the three assets, which have an average weighted contract life of 15 years, was $166 million, including the assumption by TransAlta Renewables of $62 million of tax equity obligations and project debt.

Kent Hills

We indirectly 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. We also indirectly hold, through our ownership of TransAlta Renewables, an 83 per cent interest in the 17.25 MW expansion of the Kent Hills site which was completed on October 19, 2018 bringing the total generating capacity of the three Kent Hills facilities to 167 MW. See " General Developments of the Business – Generation and Business Development ".

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, currently in the process of decommissioning, see " General Developments of the Business – Generation and Business Development "; (ii) the 74 MW Ottawa plant; and (iii) the 72 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.

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 the Merchant Subsidiaries (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 2018 are $32.14/MWh for wind facilities and $48.36/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.

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.

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Alberta PPAs

A number of our Alberta thermal and hydroelectric facilities are operated under Alberta power purchase arrangements ("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.

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 terminations of the PPAs for Sundance A, B, C, and Sheerness in late 2016 and confirmed the termination of the Keephills PPA in late 2017. For those Alberta PPAs that were terminated, the Balancing Pool had assumed the role of buyer. On September 18, 2017, the Balancing Pool elected to terminate the Sundance B PPA and Sundance C PPA effective on or before March 31, 2018. In the first quarter of 2018 we received $157 million in termination payments and we are seeking a further $56 million in compensation from the Balancing Pool for the early termination. See " General Developments of the Business - Generation and Business Development ".

Our hydroelectric facilities, other than Belly River, Pocaterra, St. Mary, Taylor and Waterton, are aggregated through one Alberta PPA (the "Hydro 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.

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. 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 consistent but restrained due to advancing energy efficiency initiatives amongst corporate, industrial and residential customers. In the longer term, most markets are still expected to show growing demand for electricity. In addition to increased longer-term demand, new investment in natural gas and renewable generation is expected to replace expected coal and nuclear retirements as depressed wholesale prices make their economic viability questionable. 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 will require additional capacity, and will provide an opportunity to increase our generation capacity.

Alberta

Approximately 58 per cent of our gross capacity is located in Alberta and more than 50 per cent of this 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. The Sundance A PPA expired at the end of 2017, the Sundance B PPA and Sundance C PPA were terminated effective March 31, 2018 and the Keephills 1 and 2 PPA, Sheerness PPA, and the Hydro PPA will expire at the end of 2020.

Coal generated power sold under certain Alberta PPAs retains 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 PPA ("hydro peaking"). We actively monitor our exposure to Alberta variable power prices and evaluate hedging positions and opportunities based on price outlook, generation estimates, market conditions and other factors that contribute to the Corporation's hedging strategy. The Corporation's hedge plan is approved annually by the Board of Directors.

Alberta's annual demand increased approximately three per cent from 2017 to 2018. The increase in demand was reflected in the average pool price which increased from $22.19/MWh in 2017 to $50.29/MWh in 2018. The majority of the pool price increase was due to higher carbon compliance costs from thermal generation. The higher prices also positively impacted our merchant wind and hydro portfolio.

The Fair, Efficient and Open Competition Regulation (Alberta) generally provides that an electricity market participant shall not hold offer control in excess of 30% of the total maximum capability of generating units in Alberta. A market participant’s total offer control is measured as the ratio of megawatts under its control to the sum of maximum capability of generating units in Alberta. Our market share of offer control in Alberta in 2018 was approximately 22 per cent (16 per cent if the Sundance mothballed units are excluded from offer control).

In late November 2016, we announced that we had entered into an Off-Coal Agreement with the Government of Alberta that provides transition payments from the Government of Alberta in consideration 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

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plants are not, however, precluded from generating electricity at any time by any method other than the combustion of coal. We also entered into the Memorandum of Understanding (the "MOU") with the Government of Alberta to collaborate and co-operate in the development of a capacity market in Alberta that ensures both current and new electricity generators will have a level economic playing field to build, buy, and sell electricity, and to develop a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation.

We expect additional compliance costs as a result of the federal government's proposed framework in which each province is expected to implement a greenhouse gas policy equivalent to a carbon price of $50 per tonne by 2022. We believe that our extensive portfolio of assets provides us with brownfield development opportunities in wind, solar, hydro, and gas that give us a cost advantage over many of our competitors when constructing generation facilities that use these fuel types.

Coal-to-Gas Conversions

The Corporation's coal-to-gas conversion plan offers compelling economics and we believe it is an attractive value proposition that compares favourably to the risk/return metrics of greenfield or brownfield investments or compared to staying on coal. With lower capital investment and lower sustaining costs, and being able to operate significantly longer once converted, TransAlta will enhance and extend the cash flows from the Alberta coal fleet. Following the conversion to gas-fired generation, we will also significantly improve our environmental performance as GHG, air emissions, waste generation, and water usage will all significantly decline. A conversion of coal-fired power generation to gas-fired generation is also expected to eliminate all mercury emissions and the majority of sulphur dioxide emissions as well as halving nitrogen oxide emissions.

On December 18, 2018, the federal government published the Reg ulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity . The final regulation provides specific provisions for coal-to-gas conversions. The rules for converted units will allow converted plants to operate for a set number of years following the end-of-life for the unit under the coal regulations based on a one-time performance test at the time of conversion.

We are planning the conversion of some or all of the units at Sundance and Keephills to gas-fired generation in the 2020 to 2023 time frame. The conversions will provide competitive, reliable, low cost power to the Alberta market and is expected to position them well in the proposed capacity market. We expect the first capacity auction to occur in 2020 for delivery in November 2021.

In July 2018, we retired the then mothballed Sundance Unit 2 due to its shorter useful life relative to other units, age, size, and the capital requirements needed to return the unit to service.

U.S. Pacific Northwest

Our capacity in the U.S. Pacific Northwest is represented by our 1,340 MW Centralia coal plant. Half of the plant capacity is scheduled 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 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 during low-priced periods.

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

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Contracted Gas and Renewables

The market for developing or acquiring 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.

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 contracted life of our Ottawa plant (2033 expiry), Windsor (2031 expiry), and Parkeston (2026 expiry) and Fort Saskatchewan (2030 expiry) plants in this manner.

Australia

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 3.0 per cent to 3.75 per cent for the period from 2019 to 2022. The Australian Energy Market Operator ("AEMO") expects electricity demand growth to be slow in response to much lower industrial investment in the region and the continued uptake of rooftop PV installations. The AEMO forecasts the 10-year energy consumption growth rates at about 0.9 per cent (2018/19 to 2027/28), with peak demand growth rates being forecast at 0.6 per cent over the same period.

Regulatory Framework

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

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 decisions changed the coal plant closure requirements, which had previously been guided by federal regulations that became effective on July 1, 2015 which provided for up to 50 years of life for coal units. On February 16, 2018, Environment and Climate Change Canada announced draft regulations to phase out coal-fired generation by 2030, as well as draft regulations for gas-fired electricity generation including provisions for the conversion of boiler units from coal-fired generation to natural gas-fired generation. Please refer to the " Environmental Risk Management - Ongoing and Recently Passed Environmental Legislation " of this AIF for more information.

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 Alberta Electric System Operator ("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 Alberta Utilities Commission ("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, including the phase out of coal-fired electricity by 2030. Please refer to the " Environmental Risk Management - Ongoing and Recently Passed Environmental Legislation " of this AIF for more information.

On May 24, 2016, the Government of Alberta passed the Climate Leadership Implementation Act which established 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 was implemented on January 1, 2018.

On November 23, 2016, the Government of Alberta announced reforms to the electricity market and an intent to transition to a new capacity market structure. The AESO has been tasked with designing and implementing the capacity market. The AESO began the design development in 2017 and formed industry working groups to develop recommendations on the capacity market. The final comprehensive market design proposal was issued on June 29, 2018 and will be supported by an expected filing of capacity market provisional rules is expected to be filed in the first quarter of 2019. Approval of the market rules and implementation is anticipated to occur in 2019 and 2020. The first capacity auction procurement is planned to take place in the fourth quarter of 2019 with first delivery starting in November 2021.

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 IESO is the successor organization resulting from the merger of the former IESO and Ontario Power Authority (OPA) in 2015. The Ontario Ministry of Energy, Northern Development and Mines takes a lead role in defining the electricity mix to be procured by the IESO/OPA, which has the mandate to undertake long-term planning of the electric system, to procure the electricity generation in that plan and to manage contracts for privately owned generation. The IESO is

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responsible for managing the Ontario wholesale market and for ensuring the reliability of the electric system in Ontario. 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 apply to all fossil fuels used for electricity generation. The majority of our gas-fired generation in Ontario is not significantly impacted by virtue of change-in-law provisions within existing power purchase agreements. Ontario's cap-and-trade regulation was subsequently cancelled on July 3, 2018.

The IESO commenced a market renewal consultation which includes proposed fundamental changes to the electricity market. These include modifying the energy market, adding a capacity market and improving operability and reliability. The consultation is expected to last a few years as these are significant changes to the market with implementation expected between 2022 and 2023.

Australia

Australia has two separate major electricity markets, the National Electricity Market ("NEM") encompassing all the major population centres on the Eastern seaboard, and the Wholesale Electricity Market ("WEM") covering the South West of Western Australia including its capital city, Perth. A number of smaller, standalone electricity grids serve regional population centres including the North West Interconnected System ("NWIS") in the Pilbara region of Western Australia and the Darwin-Katherine System ("DKS") in the Northern Territory. AEMO is the market operator for both the WEM and the NEM.

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 – We continually benchmark ourselves against previous year performance in order to drive operating costs lower year over year, while also maintaining strong levels of generation performance. We have implemented a program to drive incremental value from our fleet through the development of initiatives to improve generating equipment efficiencies, refining processes and procedures, and optimizing cost structures. Our Sarnia Cogeneration Plant has demonstrated industry best practices through several O&M processes including the work management process and Environmental, Health & Safety scorecard. We believe the continued maturity of these programs will continue to drive further value in the operations of our facilities.

Stable cash flow base – Through the use of Alberta PPAs and long-term contracts, approximately 66 per cent of our capacity is contracted over the next two years and approximately 40 per cent is contracted after two-years. The net revenue received under these contractual arrangements helps to minimize short-term revenue fluctuations due to the variable price of electricity. Following the announcement by the Government of Alberta to reform the electricity market, we consider ourselves to be well positioned to compete in the capacity market which should provide an additional level of future cash flow certainty.

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. In 2018, we bolstered our management by attracting Christophe Dehout, as the Chief Financial Officer, Jane Fedoretz, as Chief Talent and Transformation Officer, and Kerry O'Reilly Wilks, as Chief Legal & Compliance Officer.

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.

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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 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. For further details, see below and " Risk Factors ".

Canadian Federal Government

Federal Carbon Pricing

On June 21, 2018, the Greenhouse Gas Pollution Pricing Act ("GGPPA") came into force. Under the GGPPA, the Canadian federal government implemented a national price on GHG emissions. The price will begin at $20 per tonne of carbon dioxide equivalent ("CO2e") emissions in 2019, rising by $10 per year until reaching $50 per tonne in 2022.

On January 1, 2019, the GGPPA's backstop mechanisms came into force in provinces and territories that did not have an independent carbon pricing program or where the existing program was not deemed equivalent to the federal system. These included Ontario, Manitoba, New Brunswick, Saskatchewan, Prince Edward Island, Yukon and Nunavut. The backstop mechanism has two components: a carbon levy for small emitters and regulation for large emitters called the Output-Based Pricing Standard ("OPBS"). The carbon levy sets a carbon price per tonne of GHG emissions related to transportation fuels, heating fuels and other small emission sources.

Gas Regulation

On December 18, 2018, the Federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity . Under the regulations, new and significantly modified natural gas fired electricity facilities with a capacity greater than 150 MW must meet a standard of 420 tCO2e per gigawatt hour ("tCO2e/GWh") to operate. For units with a capacity between 150 MW and 25 MW, their standard was set at 550 tCO2e/GWh.

Under the regulations, coal-to-gas conversions will also eventually have to meet a standard of 420 tCO2e/GWh. If the first year performance test after conversion meets certain emission standards it will not have to meet the 420 tCO2e/GWh standard for several additional years past the end of its useful life.

Coal Regulation

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. According to the Canadian federal requirements, our 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.

On February 16, 2018, Environment and Climate Change Canada announced draft regulations to phase out coal-fired generation by 2030, as well as draft regulations for gas-fired electricity generation including provisions for the conversion of boiler units from coal-fired generation to natural gas-fired generation. The draft regulations were published in Canada Gazette I on February 17, 2018. The rules for converted units will allow converted plants to operate for a set number of years following the end-of-life for the unit under the coal regulations based on a one-time

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performance test at the time of conversion. For our units, we expect these rules provide 8 or 10 additional years of operating life to each of our unit.

On December 18, 2018, amendments to the Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity Regulations came into force under the Canadian Environmental Protection Act, 1999 . The amended regulations will require coal units to meet an emission level of 420 tCO2e/GWh by the earlier of end-of-life under the 2012 regulations or December 31, 2029.

Alberta

On November 22, 2015, the Government of Alberta announced the Climate Leadership Plan. The government has now largely delivered on its commitments through legislature to require:


•	the elimination of coal generation by 2030;

•

the creation of Renewable Energy Program ("REP") to meet the commitment that renewables account for 30 per cent of Alberta’s electricity system by 2030. Under the REP, the AESO is tasked with running procurement processes for government approved volumes of renewable power. To date, the AESO has run three separate Requests for Proposals ("RFP"). The RFPs have resulted in 20 year contracts for approximately 1,360 megawatts of wind power projects. These projects are scheduled to be grid integrated between 2019 and 2021;


•	the Carbon Competitiveness Incentives Regulation ("CCIR") replaces the previous large emitters regulation, Specified Gas Emitters Regulation ("SGER"), moving from facility specific compliance standard to a product or sector performance compliance standard; and


•	a carbon levy was introduced on most carbon emissions not covered by the CCIR.

On January 1, 2018, the Alberta government transitioned from SGER to the CCIR. Under the CCIR, the regulatory compliance moved from a facility-specific compliance standard to a product or sectoral performance compliance standard. Currently, the provincial government has announced that the carbon price will remain at $30/tCO2e going forward and will not increase to the federally mandated price increase of $40/tCO2e in 2021 and $50/ tCO2e in 2022, however, increases may be implemented by the federal government under their program equivalency review. The electricity sector performance standard was set at 370 tCO2e/GWh, but will decline over time. All renewable assets that received crediting under the SGER will continue to receive credits under CCIR on a one-to-one basis. All other renewable assets that did not receive credits under the previous standard will now be able to opt in to the CCIR and get carbon crediting up to the electricity sector performance standard in perpetuity. Once wind projects' crediting standard under SGER protocol ends, these projects will also be able to opt in to the CCIR system and be credited up to the performance standard for the rest of their operational life.

British Columbia

Beginning April 1, 2018, BC increased its carbon tax rate to $35/tCO2e and committed to raise the price $5 per year until it reaches $50 per tonne in 2021.

BC Hydro has indicated there will be no additional contracts for independent power producer renewable projects with capacity above 15 MW. It has also suspended the purchase of energy from its Standing Offer Program for small projects up to 15 MW pending a review of the program.

Ontario

On October 31, 2018, the Ontario government passed the Cap and Trade Cancellation Act . This Act removed all existing provincial carbon emission regulations and costs on large emitters.

The Canadian Federal Greenhouse Gas Pollution Pricing Act requires Provinces to have GHG gas regulations and prices in place that align with the federal GGPPA. On October 23, the federal government announced that the federal program would be implemented in Ontario as of January 1, 2019. Small emitters will face a carbon levy and large emitters, under covered industries, with annual GHG emission greater than 50,000 tCO2e will be subject to the OBPS.

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Ontario is now subject to the federal government’s backstop carbon levy price for small emitters and the OBPS for large emitters.

On November 29, 2018, the Ontario government unveiled a new climate change policy called Preserving and Protecting our Environment for Future Generations: A Made-In-Ontario Environment Plan. The plan aims to keep the province working toward meeting the emissions-reduction goal of achieving 30 per cent reduction of 2005 levels by 2030. The plan commits to developing emission performance standards to achieve reductions from large emitters and references Saskatchewan’s policy as an example. The government will be consulting and developing the program in 2019. The plan's specifics related to the electricity sector have not yet been defined and will be determined through the program development process.

Australia

On December 13, 2014, the Australian government enacted legislation to implement the Emissions Reduction Fund (the "ERF"). The AU$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 and 26 to 28 per cent below 2005 emissions by 2030. The ERF's safeguard mechanism, commencing from July 1, 2016, is designed to 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 Australian 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. The ERF is not expected to have a material impact on our Australian assets as a result of the Australian assets being primarily composed of gas-fired generation. In addition, on June 23, 2015, the federal Australian government also reformed the Renewable Energy Target ("RET") scheme. The RET should add at least 33,000 GWh of renewable sources by 2020. This would double the amount of large-scale renewable energy being delivered compared to current levels and result in approximately 23.5 per cent of Australia's electricity generation being sourced from renewable projects.

Pacific Northwest

In 2010, the Washington Governor's office and Ecology negotiated agreements with TransAlta related to the operation of Centralia’s two coal power electricity generating units. TransAlta agreed to retire its two Centralia coal units one in 2020 and the other in 2025. This agreement is formally part of the state’s climate change program. We currently believe that there will be no additional GHG regulatory burden on U.S. Coal given these commitments. The related TransAlta Energy Transition Bill was signed into law in 2011 and provides a framework to transition from coal to other forms of generation in the State of Washington.

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 continue to 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 includes the elements summarized below:

Renewable Power

We continue to invest in and build renewable power resources.

The Brazeau Hydro Pumped Storage project is expected to have new capacity up to 900 MW, bringing the total Brazeau facility from 755 to 1,255 MW, post-completion. We estimate an investment in the range of $1.5 billion to $2.7 billion. During the first nine months of 2018, we invested approximately $2 million to advance the environmental study, work

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with stakeholders, and execute geotechnical work to help further our design and construction phase. Further advancement of the project is dependent on securing a long-term contract.

In May 2018, the AESO released a report stating that dispatchable renewable resources are not needed in the Alberta market before 2030. The value and benefit of the Brazeau Hydro Pumped Storage project would be well beyond the 2030 period. The Corporation still believes that generation from pumped storage should be part of future calls for power under the Alberta Renewables program. The Corporation is not spending additional development dollars on the project at this time but will continue to work with governments to find the appropriate financial mechanisms for bringing low cost, green, dispatchable renewables into the market to support low prices and emissions for Alberta customers.

On December 17, 2018 the AESO announced that our 207 MW Windrise wind project was selected as one of the two successful projects in the third round of Alberta's Renewable Electricity Program. The Windrise facility, which is in the county of Willow Creek, is underpinned by a 20-year Renewable Electricity Support Agreement with the AESO. The project is expected to cost approximately $270 million and is targeted to reach commercial operation during the second quarter of 2021.

Also on December 17, 2018, we exercised our option to acquire 50 percent ownership in the Pioneer Pipeline. Tidewater will construct and operate the 120 km natural gas pipeline, which will have an initial throughput of 130 MMcf/d with the potential to expand to approximately 440 MMcf/d. The Pioneer Pipeline will allow TransAlta to increase the amount of natural gas it co-fires at its Sundance and Keephills coal-fired units, resulting in lower carbon emissions and costs. As well, the Pioneer Pipeline will provide a significant amount of the gas required for the full conversion of the coal units to natural gas. Our investment will amount to approximately $90 million. Construction of the pipeline commenced in November 2018 and it is expected to be fully operational by the second half of 2019. The investment is subject to final regulatory approvals.

On June 1, 2017, a subsidiary of TransAlta Renewables signed a PPA with New Brunswick Power for the expansion of the Kent Hills wind farm. The PPA runs through to the end of 2035. At the same time, the Kent Hills 1 PPA was amended adding two years to its contract. The expiry dates of all three Kent Hills PPAs now coincide at a date of November 30, 2035. On October 19, 2018, we announced that the Kent Hills wind farm expansion was completed and is fully operational. The expansion adds five 3.45 MW turbines to the Kent Hills fleet for an additional 17.25 MW at the site. See " General Development of the Business – Generation and Business Development ".

On February 20, 2018, TransAlta Renewables announced it had entered into an arrangement to acquire two construction-ready projects in the Northeast United States. The wind development projects consist of: (i) a 90 MW project located in Pennsylvania which has a 15-year PPA and (ii) a 29 MW project located in New Hampshire with two 20-year PPAs. See " General Development of the Business – Generation and Business Development "

We believe 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.

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Environmental Controls and Efficiency

We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. We have installed mercury control equipment at all of our coal operations and we achieve an 80 per cent capture rate of mercury at all coal facilities. Our Keephills 3 and Genesee 3 plants use supercritical combustion technology to maximize thermal efficiency, as well as sulphur dioxide ("SO2") capture and low oxides of nitrogen ("NOx") combustion technology. Uprate or energy efficiency projects completed at our Keephills and Sundance plants, including a 15 MW uprate finalized in 2015 at Sundance 3, have improved the energy and emissions efficiency of those units. In 2018 we commenced co-firing with gas at our merchant coal facilities in Alberta. This has resulted in a material reduction in the volume of emissions of C0 ₂ per MWh from this fleet.

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, we negotiated with the Government of Alberta, using a principles-based approach, to ensure that we have 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 capacity market to be developed for the Province of Alberta. Specifically, the parties undertook collaboration to, among other things:


•	transition from the current energy-only market to a capacity market design that will procure capacity from generators on a forward basis to ensure system resource adequacy;


•	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.

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 or future changes to environmental laws or regulations may materially adversely affect us. As indicated under " Risk Factors " in this AIF and within the " Governance and 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 and obligations under these requirements, which may have a material adverse effect upon our consolidated financial results, operations or performance.

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RISK FACTORS

Readers should consider carefully the risk factors set forth below as well as the other information contained and incorporated by reference in this AIF. For a further discussion of risk factors affecting TransAlta, please refer to " Governance and Risk Management " 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 or 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.

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.

We may fail to meet financial expectations.

Our quarterly revenue, earnings, cash flows 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.

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 and obligations 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

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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 or standards on our business. These various compliance standards may result in additional costs 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 impose 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, curtail our operations, or require significant expenditures on compliance, new equipment or technology, reporting obligations and research and development.

In addition to environmental regulation, we could also face civil liability in the event that private parties seek to impose liability on us for property damage, personal injury or other costs and losses. We cannot guarantee that lawsuits or administrative or investigative actions will not be commenced against us and otherwise affect our operations and assets. If an action is filed against us or may otherwise affect our operations and assets, we could be required to make substantial expenditures to defend against 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, 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. The estimated reclamation costs applicable to the Corporation's operations may be inaccurate and could require greater financial resources than currently anticipated. 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 if it becomes more economical to do so.

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We may be unsuccessful in 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 or other legal proceedings. We may also bring legal actions against third parties as part of a commercial dispute through an arbitration or other legal proceeding. There can be no assurance that we will be successful in any such claim or defence 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 material to our operations due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse effect on our business. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. In addition, there can be no assurance that any applicable insurance coverage would be adequate to protect our business from material adverse effects.

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

Our generation facilities and their operations are exposed to potential damage and partial or complete loss, resulting from environmental disasters (e.g. floods, high winds, fires and earthquakes), equipment failures and other events beyond our control. Climate change can increase the frequency and severity of these extreme weather events. The occurrence of a significant event which disrupts the operation or 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 or dyke 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

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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.

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; increased adoption of energy efficiency and conservation initiatives, and weather conditions that impact electrical load. As a result, we cannot accurately predict future electricity prices and electricity price volatility could have a material adverse effect on us.

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


•	prevailing market prices for fuel;


•	global demand for energy products;


•	the cost of carbon and other environmental concerns;


•	weather‑related disruptions affecting the ability to deliver fuels or near‑term demand for fuels;


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


•	the extent of fuel transportation capacity or cost of fuel transportation service into our markets; and


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

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

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

Certain of our thermal facilities depend on third parties to supply fuel, including natural gas and coal. As a result, we face the risks of supply interruptions and fuel price volatility, as fuel deliveries may not exactly match those required for energy sales, due in part to our need to pre-purchase fuel inventories for reliability and dispatch requirements. Disruption of transportation services of fuel, whether because of weather-related problems, strikes, lock-outs, break-downs of locks and dams or other events could impair our ability to generate electricity and could adversely affect our results of operations. Significantly, the coal used to fuel the Centralia Thermal facility is sourced from the Powder River Basin in Montana and Wyoming through contracts to purchase and transport such coal to our Centralia Thermal facility. These existing coal contracts for the Centralia Thermal plant expire at the end of 2020. The loss of our suppliers or our inability to renew our existing coal contracts for Powder River Basin coal at favourable terms, or at all, could also significantly affect our ability to serve our customers and have an adverse impact on our financial condition and results of operations. Once the Tidewater pipeline is operational, we could face the risk of supply service interruptions beyond our control due to our reliance on Tidewater as the main provider of natural gas for our Sundance and Keephills Units.

Changes in general economic and market 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, or credit risk and counterparty risk, which could cause us to suffer a material adverse effect.

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: (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 [us or] our competitors; 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 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.

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 15 section C of our audited consolidated

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financial statements for the year ended December 31, 2018, which financial statements are incorporated by reference herein. Please also see " Documents Incorporated by Reference " in this AIF.

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 and timing of any dividends to be declared and paid to our shareholders. In addition, the payment of dividends on common shares is, in all cases, subject to prior satisfaction of preferential dividends applicable to each series of our first preferred shares. We may alter our dividend policy at any time. The Board's determination to declare 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 are 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. Such competition 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 not capable of generating electricity for 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 could result in us having less stable cash flows and 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 PPAs have run their course, the new contract may not be available at prices that permit

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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. Variations in weather may be impacted by climate change resulting in sustained higher temperatures and rising sea levels which could have an impact on our generating assets.

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.

Most 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. The impact of the intended capacity market expected to be implemented in Alberta on the Corporation is not yet known and may be material. The ability of the Corporation to successfully participate in the capacity market is not assured and may impact our capital allocation strategies, including as it pertains to the coal-to-gas conversions.

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

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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.

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 and could result in write-offs or give rise to reputational harm.

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, cyberattack 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, cyberattacks, breaches, 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, cyberattack and other similar disruptions.

Any damage or failure that causes an interruption in operations could have an adverse effect on our customers. Additionally, we actively protect our generation facility infrastructure against physical damage, security breaches and service disruption from any of a variety of causes. Cyberattacks, 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, disaster recovery and procedures designed to prevent, detect 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.

Cyberattacks 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 and data used for the safe operation of our assets. In today's continuously evolving cybersecurity threat landscape, any attacks or breaches of network or information systems may cause disruptions to our business operations or compromise proprietary, confidential or personal information of the Corporation, its customers, partners or others with whom the Corporation has dealings. Cyberattackers may use a range of techniques, from exploiting vulnerabilities within our user-base, to

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using sophisticated malicious code on a single or distributed basis to try to breach our network security controls. Attackers may also use a combination of techniques in their attempt to evade safeguards such as firewalls, intrusion prevention systems and antivirus software that exist on our network infrastructure systems. A successful cyberattack may allow for the unauthorized interception, destruction, use, or dissemination of proprietary, confidential or personal information and may cause disruptions to our operations.

We continuously take measures to secure our infrastructure against potential cyberattacks that may damage our infrastructure, systems and data. Our cybersecurity program aligns with industry best practices to ensure that a holistic approach to 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. We have also established security awareness programs to help educate our users on cybersecurity risks and their responsibilities in helping protect the business.

While we have systems, policies, hardware, practices, data backups and procedures designed to prevent or limit the effect of security breaches of our network and infrastructure, there can be no assurance that these measures will be sufficient and that such security breaches will not occur, if they do occur, that they will always be adequately addressed in a timely manner.

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 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

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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.

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 cash flows from those operations, the acquisition of equipment and services from foreign suppliers, and our U.S. dollar 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 operating cash flows 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.

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

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

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

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

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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.

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 growth projects (including the coal-to-gas conversions), 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, including TransAlta Renewables, 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 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.

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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. including TransAlta Renewables, 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 (and any future changes to) health, safety and environmental laws 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 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, injury, damage to third parties, 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 cyberattacks 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.

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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 tax 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 can have a material adverse impact on us.

We are subject to uncertainties regarding when we will become cash taxable.

Our anticipated cash tax horizon is subject to risks, uncertainties and other factors that could cause the cash tax horizon to occur sooner than currently projected. In particular, our anticipated cash tax horizon is subject to risks pertaining to changes in our operations, asset base, corporate structure or changes to tax legislation, regulations or interpretations. In the event we become cash taxable sooner than projected, our cash available for distribution and our dividend could decrease, which could in turn have a material adverse impact on the value of our shares.

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 475 of our employees, in 2019. Four collective bargaining agreements representing a total of approximately 220 employees are anticipated to be negotiated in 2020. 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.

EMPLOYEES

The Corporation is required to develop and retain skilled workforces for their operations. Many of the employees of the Corporation possess specialized skills and training and the Corporation must compete in the marketplace for these workers. As of December 31, 2018, we had 1,883 active employees, which includes full-time, part-time and temporary employees, of which 886 were employed in our Canadian Coal segment (including our SunHills mining operation), 202 were employed in our U.S. coal segment, 209 were employed in our Gas Segment, 80 were employed in our Wind and Solar business, 79 were employed in our Hydro business, 70 were employed in our Energy Marketing business, and the remaining 367 employees were employed in our Corporate segment. Approximately 50 per cent of our employees are represented by labour unions. We are currently a party to 10 different collective bargaining agreements. In 2018, we renewed four of the 10 collective bargaining agreements and we expect to re-negotiate four collective bargaining agreements in 2019.

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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 February 26, 2019, there were 284,638,967 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 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 March 9, 2018, the TSX accepted our notice filed to implement a normal course issuer bid for a portion of its common shares. The Board has authorized repurchases of up to 14,000,000 of its common shares, representing approximately five per cent of TransAlta's public float. Purchases under the NCIB are expected to be made through open market transactions on the TSX and any alternative Canadian trading platforms, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.

For the twelve months of 2018 we purchased and cancelled 3,264,500 common shares at an average price of $7.01 per share.

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

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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 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

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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 on a one-for-one basis.

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 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

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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 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.

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.

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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. Certain provisions of the Series C Shares are discussed below.

Dividends on Series C Shares

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

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

Redemption of Series C Shares

The Series C Shares were redeemable by TransAlta, at its option, in whole or in part, on June 30, 2017, and will be redeemable 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). On June 30, 2017, none of the Series C Shares were redeemed.

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 had 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 will again have the right to convert 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.

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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.

On June 15, 2017, 827,628 Series C Shares were tendered for conversion into Series D Shares which is less than the one million shares required to give effect to conversions into Series D Shares. As a result, none of the Series C Shares were converted into Series D Shares on June 30, 2017.

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.

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") were issued on August 10, 2012 for gross proceeds of $225 million. 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.

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Redemption of Series E Shares

The Series E Shares were redeemable by TransAlta Corporation, at its option, in whole or in part, on September 30, 2017, and will be redeemable 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). On September 30, 2017, none of the Class E Shares were redeemed.

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

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

On September 15, 2017, 133,969 Series E Shares were tendered for conversion into Series F Shares which is less than the one million shares required to give effect to conversions into Series F Shares. As a result, none of the Series E Shares were converted into Series F Shares on September 30, 2017.

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.

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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") were issued on August 15, 2014 for gross proceeds of $165 million. 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.

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

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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.

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.

Related Party Articles Provisions

The articles of the Corporation contain provisions restricting the ability of the Corporation to enter into a "Specified Transaction" with a "Major Shareholder". A Specified Transaction requires the approval of a majority of the votes cast by holders of voting shares of the Corporation, as well as the approval of a majority of the votes cast by holders of such voting shares, excluding any Major Shareholder. A Major Shareholder generally means the beneficial owner of more than 20% of the outstanding voting shares of the Corporation. The articles contain a broad definition of beneficial ownership, and in particular, a person is considered to beneficially own shares owned by its associates and affiliates, as those terms are defined in the articles. Transactions which are considered to be Specified Transactions include the following: a merger or amalgamation of the Corporation with a Major Shareholder; the furnishing of financial assistance by the Corporation to a Major Shareholder; certain sales of assets or provision of services by the Corporation to a Major Shareholder or vice versa; certain issuances of securities by the Corporation which increase the proportionate voting interest of a Major Shareholder; a reorganization or recapitalization of the Corporation which increases the proportionate voting interest of a Major Shareholder; and the creation of a class or series of non-voting shares of the Corporation which has a residual right to participate in earnings of the Corporation and assets of the Corporation upon dissolution or winding up.

Shareholder Rights Plan

The Corporation implemented a shareholder rights plan (the "Rights Plan") pursuant to a Shareholder Rights Plan Agreement (the "Rights Plan Agreement") dated as of October 13, 1992, as amended and restated as of April 22, 2016, between the Corporation and AST Trust Company (Canada) (the successor to CST Trust Company). The Shareholder Rights Plan was last confirmed at our annual and special meeting of shareholders on April 22, 2016 and will expire at the close of business on the date of our 2019 annual meeting of shareholders, unless ratified and extended by a further vote of the shareholders. For further particulars, reference should be made to the Rights Plan Agreement, as amended and restated. A copy of the Rights Plan Agreement may be obtained by contacting the Corporate Secretary, TransAlta Corporation, 110 - 12th Avenue S.W., Calgary, Alberta T2P 2M1; telephone: (403) 267-7110; or by email: corporate_secretary@transalta.com. A copy of the Rights Plan Agreement is also available electronically on SEDAR under our profile, which can be accessed at www.sedar.com, and on the SEC's EDGAR system at www.sec.gov.

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Credit Facilities

In 2018, we renewed and upsized our syndicated credit agreement giving us access to a $1.25 billion committed credit facility. The agreement is fully committed for four years, expiring in 2022. The credit facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. This credit facility has been made available for general corporate purposes including financing ongoing working capital requirements, providing financing for construction capital, growth opportunities and for the repayment of outstanding borrowings.

On July 24, 2017, TransAlta Renewables entered into a syndicated credit agreement giving it access to a $500 million committed credit facility. The credit agreement is fully committed for four years, expiring in 2022 with the 2018 renewal and extension. The credit facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. For further information please see Note 22 of our audited consolidated financial statements for the year ended December 31, 2018, which financial statements are incorporated by reference herein. Please also see " Documents Incorporated by Reference " in this AIF.

Long-Term Debt

The long-term debt of the Corporation consists of $651 million face value of debentures outstanding, which bear interest at fixed rates ranging from 5.0 per cent to 7.3 per cent and have maturity dates ranging from 2029 to 2030. In addition, we have US$700 million face value in senior notes outstanding that bear interest at fixed rates ranging from 4.5 per cent to 6.5 per cent and have maturity dates ranging from 2022 to 2040. For further information please see Note 22 of our audited consolidated financial statements for the year ended December 31, 2018, which financial statements are incorporated by reference herein. Please also see " Documents Incorporated by Reference " in this AIF.

Non-Recourse Debt

The Corporation has non-recourse debt outstanding in an amount equal to approximately $1,250 million face value, which are represented by bonds and debentures that bear interest at rates ranging from 3.83 per cent to 6.20 per cent and have maturity dates ranging from 2028 to 2032. For further information please see Note 22 of our audited consolidated financial statements for the year ended December 31, 2018, which financial statements are incorporated by reference herein. Please also see " Documents Incorporated by Reference " in this AIF.

Tax Equity

The Corporation assumed US$24 million in tax equity financing as part of the Lakeswind acquisition, which is included as debt in our consolidated financial statements. For further information on tax equity please see Note 22 of our audited consolidated financial statements for the year ended December 31, 2018, which financial statements are incorporated by reference herein. Please also see " Documents Incorporated by Reference " in this AIF.

Restrictions on Debt

The syndicated credit facilities include a number of customary covenants and restrictions in order to maintain access to the funding commitments. Non-recourse bonds are subject to customary financing conditions and covenants that may restrict the Corporation's ability to access funds generated by the facilities' operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution.

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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 (low)	BBB-	Not Applicable	BBB-
Corporate Family Rating	Not Applicable	Not Applicable	Ba1	Not Applicable
Preferred Shares	Pfd-3 (low) ⁽¹⁾	Not Applicable	Not Applicable	P-3 ⁽¹⁾
Unsecured Debt/MTNs	BBB (low)	BBB-	Ba1/LGD4	BBB-
Rating Outlook	Stable	Stable	Positive	Negative

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 has been stepped-up in line with contractual provisions. The Corporation maintains investment grade ratings from three credit rating agencies including BBB- (negative outlook) by S&P, BBB (low) (stable outlook) by DBRS and BBB- (stable 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, 2018, our issuer rating was BBB (low) (stable) 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 (low) (stable) 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 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

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credit quality. The capacity for the payment of financial obligations is considered acceptable, but may be vulnerable to future events. As of December 31, 2018, our senior unsecured long-term debt is rated BBB (low) (stable) by DBRS. The BBB rating category is the fourth highest of ten categories for long term obligations.

Fitch

As of December 31, 2018, our Fitch long term Issuer Default Rating (IDR) and senior unsecured rating was BBB- with a stable 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 , 2018 , 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, 2018, our Corporate Family Rating was Ba1 with a positive 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, 2018, our senior unsecured long-term debt is rated Ba1 (positive) / 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 per cent 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, 2018, our Loss Given Default Assessment from Moody's was LGD4 which represents a loss range of greater than or equal to 50 per cent and less than 70 per cent. LGD4 is the fourth highest assessment category out six categories.

S&P

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

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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, 2018, our issuer credit rating was BBB- with a negative 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, 2017, our senior unsecured rating was BBB- with a negative 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 DBRS for certain other services provided to the Corporation during the last two years.

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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

2016	First Quarter	$0.18
	Second Quarter	$0.04
	Third Quarter	$0.04
	Fourth Quarter	$0.04

2017	First Quarter Second Quarter Third Quarter Fourth Quarter	$0.04 $0.04 $0.04 $0.04
2018	First Quarter Second Quarter Third Quarter Fourth Quarter	$0.04 $0.04 $0.04 $0.04

Preferred Shares

Series A Shares



Period		Dividend per Series A Share

2016	First Quarter	$0.2875
	Second Quarter	$0.16931
	Third Quarter	$0.16931
	Fourth Quarter	$0.16931
2017	First Quarter	$0.16931
	Second Quarter	$0.16931
	Third Quarter	$0.16931
	Fourth Quarter	$0.16931
2018	First Quarter	$0.16931
	Second Quarter	$0.16931
	Third Quarter	$0.16931
	Fourth Quarter	$0.16931

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Series B Shares



Period		Dividend per Series B Share

2016	Second Quarter ⁽¹⁾	$0.15490
	Third Quarter	$0.16144
	Fourth Quarter	$0.15974

2017	First Quarter Second Quarter	$0.15651 $0.15645
	Third Quarter	$0.16125
	Fourth Quarter	$0.17467

2018	First Quarter	$0.17889
	Second Quarter	$0.19951
	Third Quarter	$0.20984
	Fourth Quarter	$0.22301

Note:


(1)	On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares on a one-for-one basis.

Series C Shares



Period		Dividend per Series C Share

2016	First Quarter	$0.2875
	Second Quarter	$0.2875
	Third Quarter	$0.2875
	Fourth Quarter	$0.2875
2017	First Quarter	$0.2875
	Second Quarter	$0.2875
	Third Quarter	$0.25169
	Fourth Quarter	$0.25169
2018	First Quarter	$0.25169
	Second Quarter	$0.25169
	Third Quarter	$0.25169
	Fourth Quarter	$0.25169

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Series E Shares



Period		Dividend per Series E Share

2016	First Quarter	$0.3125
	Second Quarter	$0.3125
	Third Quarter	$0.3125
	Fourth Quarter	$0.3125
2017	First Quarter	$0.3125
	Second Quarter	$0.3125
	Third Quarter	$0.3125
	Fourth Quarter	$0.32463
2018	First Quarter	$0.32463
	Second Quarter	$0.32463
	Third Quarter	$0.32463
	Fourth Quarter	$0.32463

Series G Shares



Period		Dividend per Series G Share

2016	First Quarter	$0.33125
	Second Quarter	$0.33125
	Third Quarter	$0.33125
	Fourth Quarter	$0.33125
2017	First Quarter	$0.33125
	Second Quarter	$0.33125
	Third Quarter	$0.33125
	Fourth Quarter	$0.33125
2018	First Quarter	$0.33125
	Second Quarter	$0.33125
	Third Quarter	$0.33125
	Fourth Quarter	$0.33125

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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

2018
March	7.55	6.88	17,597,382
April	7.00	6.70	8,347,063
May	7.00	6.51	10,130,939
June	6.72	6.36	8,309,916
July	7.50	6.53	16,752,842
August	7.90	7.27	17,751,039
September	7.69	7.10	10,377,877
October	7.31	6.57	11,292,500
November	7.27	6.75	8,276,883
December	7.19	5.44	16,024,404

2019
January	7.21	5.50	14,239,607
February 1-25	7.64	7.16	6,889,858

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Preferred Shares

Series A Shares

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



Date 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

Notes:


(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 on a one-for-one basis.



	Price ($)
Month	High	Low	Volume

2018
March	15.45	14.58	76,960
April	14.80	14.02	350,908
May	15.04	14.32	106,626
June	14.55	14.12	106,921
July	15.10	14.23	49,387
August	16.00	15.05	78,373
September	15.85	15.21	41,839
October	15.70	13.90	164,848
November	15.14	13.30	391,944
December	13.65	10.78	196,049

2019
January	12.38	11.36	119,970
February 1-25	12.08	11.48	95,915

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Series B Shares

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



Date 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 on a one-for-one basis.



	Price ($)
Month	High	Low	Volume

2018
March	15.41	15.01	35,102
April	15.15	14.87	12,806
May	15.41	15.00	114,723
June	15.05	14.81	58,375
July	15.66	14.90	12,142
August	16.01	15.33	3,225
September	16.20	15.50	24,852
October	16.00	14.96	64,020
November	15.39	14.28	33,586
December	14.60	12.04	19,440

2019
January	13.33	12.65	9,552
February 1-25	13.05	12.65	20,546

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Series C Shares

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



Date 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

2018
March	18.70	17.97	95,284
April	18.47	17.62	65,197
May	18.68	17.95	83,122
June	18.26	17.70	95,708
July	18.59	17.72	72,208
August	18.93	18.45	74,683
September	18.84	18.42	63,861
October	18.73	16.35	269,488
November	17.70	15.75	89,486
December	15.88	13.50	207,024

2019
January	15.68	14.38	77,085
February 1-25	15.15	13.90	81,626

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Series E Shares

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



Date 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

2018
March	21.85	21.10	251,722
April	21.50	20.67	48,033
May	21.87	21.10	64,241
June	21.44	20.84	91,491
July	21.56	20.87	37,062
August	21.92	21.50	56,075
September	21.68	21.32	43,844
October	21.48	19.13	96,427
November	20.25	17.83	189,405
December	18.50	15.45	343,592

2019
January	18.28	16.75	190,298
February 1-25	17.53	16.82	163,337

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Series G Shares

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



Date 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

2018
March	22.70	21.90	60,393
April	22.44	21.83	55,314
May	22.80	22.08	93,432
June	22.30	21.71	53,141
July	22.64	21.70	45,449
August	23.12	22.58	73,504
September	23.06	22.66	71,746
October	23.06	21.05	107,524
November	22.00	19.75	65,293
December	20.30	16.80	127,768

2019
January	19.34	17.80	69,528
February 1-25	18.63	17.62	33,216

DIRECTORS AND OFFICERS

The name, province or state and country of residence of each of our directors as at December 31, 2018, 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.

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

Rona H. Ambrose Alberta, Canada	2017	The Honourable Rona Ambrose is a national leader, former Leader of Canada's Official Opposition in the House of Commons and former leader of the Conservative Party of Canada. As a member of the federal cabinet for a decade, Ms. Ambrose acted as a minister of the Crown across nine government departments, including serving as Vice Chair of the Treasury Board for several years and Chair of the cabinet committee for public safety, justice and aboriginal issues. She is also the former environment minister responsible for overseeing the GHG regulatory regime across several industrial sectors. Ms. Ambrose was responsible for the development of several federal policies, ranging from industrial strategies in military procurement to health innovation to improvements to sexual assault laws. She is a passionate advocate for women in Canada and around the world and led the global movement to create the "International Day of the Girl" at the United Nations. She is responsible for ensuring that Aboriginal women in Canada were finally granted equal matrimonial rights and successfully fought for the creation of a Canadian refugee program to bring Yazidi women and girls who have been sexually enslaved by ISIS to safety in Canada. In addition to serving as an independent corporate director, Ms. Ambrose is a Global Fellow at the Wilson Centre Canada Institute in Washington DC focusing on key Canada-U.S. bilateral trade and competitiveness issues. Ms. Ambrose serves on the advisory board of the Canadian Global Affairs Institute and is a director of Manulife Financial Corporation. Ms. Ambrose has a BA from the University of Victoria and a MA from the University of Alberta. She is also a graduate of the Harvard Kennedy School of Government Senior Leaders Program. Ms. Ambrose brings to the Corporation and the Board significant experience in leadership, government affairs, public policy and environmental, climate change and regulatory matters. Ms. Ambrose also brings expertise in communications and human resources / compensation matters.

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Name, Province (State) and Country of Residence	Year first became Director	Principal Occupation
John P. Dielwart Alberta, Canada	2014	Mr. Dielwart is the Chair of the Governance, Safety and Sustainability Committee of the Board. 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 total capitalization of approximately $10 billion at the time of his retirement. 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. He is a member of ARC Financial's Investment and Governance committees, and currently represents ARC Financial on the boards 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 and in 2018 he received the Oil and Gas Council’s Canadian Lifetime Achievement Award. Mr. Dielwart is a director and former Co-Chair of the Calgary and Area Child Advocacy Centre. Effective March 7, 2018, Mr. Dielwart will become a director of Crescent Point Energy Corp. The Board believes that Mr. Dielwart is a diligent, independent director who provides the Company with a wealth of experience in leadership, finance and entrepreneurship along with a strong understanding of the commodity markets in which we operate, specifically the oil and gas markets.

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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 the Senior Independent Director and a member of the Risk and Audit Committee of ICE Futures Europe ("IFEU"), 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. In 2018, Mr. Timothy Faithfull indicated to the Board that he intended to retire from the Board immediately following the 2019 annual and special meeting of shareholders, and would not be standing for re-election.

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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. From 2006 to 2007, she served as BC Hydro’s 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 and the Business Council of Canada. She is a member of the Trilateral Commission and The Canada-U.S. Council for Advancement of Women Entrepreneurs and Business Leaders. 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. As the President and Chief Executive Officer of the Company, Mrs. Farrell has responsibility for the overall stewardship of TransAlta, including providing strategic leadership to the Company. She has proven herself to be a strong leader that is capable of transforming TransAlta into Canada's leading clean energy company.

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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 utilities industry from both a regulated and deregulated market perspective. He also holds expertise in banking, human resources/compensation and risk management matters.

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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 have assisted the Corporation in addressing the changing regulatory landscape. Mr. Giffin also brings strong leadership and strategy development skills to the Corporation. The Corporation previously announced in January 2019 that Ambassador Giffin intends to retire as a director and Board Chair of TransAlta Corporation in 2020, following a process to identify a new Chair and facilitate an orderly transition.

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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 per cent 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 U.S. 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. Mr. Mansour also has significant knowledge of risk management, engineering and technical and environmental matters.

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Name, Province (State) and Country of Residence	Year first became Director	Principal Occupation
Georgia Nelson Illinois, U.S.A.	2014	At TransAlta, Ms. Nelson is the Chair of the Human Resources Committee of the Board. 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), an independent power producer, from 1999 to her retirement in 2005 and General Manager of EME Americas, from 2002 to 2005. 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 was a director of CH2MHILL Corporation, a privately held company, until December 2017. 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 to 2015 and served as Chair from 2006 to 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 from Pepperdine University and a Master of Business Administration from the University of Southern California. Ms. Nelson brings to the Company and the Board specialized knowledge in the energy, independent power and coal and mining industries as well as human resources management / compensation, and engineering and technical expertise. As Chair of the Human Resources Committee of the Board, Ms. Nelson leads the Committee in effective decision-making.

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Name, Province (State) and Country of Residence	Year first became Director	Principal Occupation
Beverlee F. Park British Columbia, Canada	2015	Ms. Park is the Chair of the Audit and Risk Committee of the Board as of April 19, 2018. Ms. Park is currently a director of Teekay LNG Partners, a NYSE-listed public company, where she chairs the Audit Committee and Conflicts Committee. Teekay LNG Partners is one the world's largest independent owners of LNG and LPG carriers. She is also a director of SSR Mining Inc. (TSX/NASDAQ-listed), a public mining company, focused on the operation, development, exploration and acquisition of precious metals projects in North and South America. Ms. Park was a member of the Board of Governors at the University of British Columbia until June 30, 2018. In addition, until October 2018 she was a director of InTransit BC, a privately held light rapid transit company where she chaired the Audit Committee. Ms. Park was previously a director of the BC Transmission Corporation, where she also chaired the Audit Committee. Ms. Park has executive and board experience in a range of industries, including electricity transmission, forest products, shipping, mining, transportation and real estate. Ms. Park spent 17 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. 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 also a Fellow of the Chartered Professional Accountants (FCPA) and Fellow of the Institute of Chartered Accountants (FCA) of British Columbia. Ms. Park brings to the Company and to the Board over 30 years of experience in finance and accounting as well as senior leadership experience in organizational change. Ms. Park's extensive experience delivering shareholder value together with her strong financial expertise has made her a valuable contributor to the Board.

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Name, Province (State) and Country of Residence	Year first became Director	Principal Occupation
Bryan D. Pinney Alberta, Canada	2018	Bryan Pinney is the principal of Bryan D. Pinney Professional Corporation, which provides financial advisory and consulting services. Mr. Pinney is currently the lead director for North American Energy Partners Inc. He is also a director on a Hong Kong-listed oil and gas company, Persta Resources Inc. Mr. Pinney was also the recent chair of the Board of Governors of Mount Royal University and has previously served on a number of non-profit boards. He is also a director on one private company. He is a Fellow of the Institute of Chartered Accountants, a Chartered Business Valuator and is a graduate of the Ivey Business School at the University of Western Ontario with an honours degree in Business Administration. He is also a graduate of the Canadian Institute of Corporate Directors. Mr. Pinney has over 30 years of experience serving many of Canada's largest corporations, primarily in energy and resources and construction. Mr. Pinney was a partner with Deloitte between 2002 and 2015. Mr. Pinney served as Calgary Managing Partner from 2002 through 2007 and as National Managing Partner of Audit & Assurance from 2007 to 2011 and Vice-Chair until June 2015. Mr. Pinney was a past member of Deloitte's Board of Directors and chair of the Finance and Audit Committee. Prior to joining Deloitte, Mr. Pinney was a partner with Andersen LLP and served as Calgary Managing Partner from 1991 through May of 2002. Mr. Pinney's extensive leadership accomplishments, financial expertise, knowledge of regulatory and compliance matters and diverse range of industry experience make Mr. Pinney an important contributor to the Board.

Officers

The name, province or state and country of residence of each of our senior officers as at February 26, 2019, 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 Officer, Business and Operational Services	Alberta, Canada
Christophe Dehout	Chief Financial Officer	Alberta, Canada
Jane Fedoretz	Chief Talent and Transformation Officer	Alberta, Canada
Brett M. Gellner	Chief Strategy and Investment Officer	Alberta, Canada
John H. Kousinioris	Chief Growth Officer	Alberta, Canada
Kerry O'Reilly	Chief Legal and Compliance Officer	Alberta, Canada
Jennifer M. Pierce	Senior Vice-President, Business Development	Alberta, Canada
Todd J. Stack	Managing Director, Corporate Controller	Alberta, Canada
Brent Ward	Managing Director, Treasurer	Alberta, Canada
Aron J. Willis	Senior Vice-President, Commercial, Gas and Renewables	Alberta, Canada

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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 (electricity corporation) in Australia.


•	Prior to July 2018, Ms. de Lima was Chief Administrative Officer. 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 November 2018, Mr. Gellner was Interim Chief Financial Officer and Chief Strategy and Investment Officer of the Corporation. Prior to July 2018, Mr. Gellner was Chief Investment Officer of the Corporation. Prior to August 2013, Mr. Gellner was Chief Financial Officer of the Corporation.


•	Prior to November 2018, Mr. Dehout was Project Director and Deputy Head of Performance and Group Transformation of Engie SA (utilities).


•	Prior to July 2018, Mr. Kousinioris was Chief Legal and Compliance Officer and Corporate Secretary 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 April 2017, Mr. Ward was Manager, Treasury and Corporate Finance.


•	Prior to January 2017, Mr. Willis was 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.


•	Prior to November 2018, Ms. O'Reilly Wilks was Head of Legal, North Atlantic & UK, for Vale S.A. (Base Metal Business), one of the largest companies in the world.


•	Prior to November 2018, Ms. Fedoretz was Counsel, Energy Group at Blake, Cassels & Graydon LLP.

As of February 26, 2019, 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.

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 10 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 2019 or in any proposed transactions that has materially affected or will materially affect us.

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INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS

Since January 1, 2018, 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 10 years before the date hereof, a director or executive officer of any other issuer that, while that person was acting in that capacity:


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


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


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

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.

Personal Bankruptcies

No director, executive officer or controlling security holder of TransAlta Corporation has, within the 10 years before the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or became subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold such person's assets.

Penalties or Sanctions

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


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


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

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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 33 (I) of our audited consolidated financial statements for the year ended December 31, 2018 which financial statements are incorporated by reference herein. See " Documents Incorporated by Reference ".

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 AST Trust Company (Canada). AST Trust Company (Canada) changed its name from CST Trust Company effective July 20, 2017. 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 Trust Company at its principal office in Jersey City, New Jersey.

INTERESTS OF EXPERTS

The Corporation'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.

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 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, 2018 and in the related Annual MD&A, each of which is incorporated by reference in this AIF. See " Documents Incorporated by Reference ".

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 currently comprised of five independent members, Beverlee F. Park (Chair), John P. Dielwart, Alan J. Fohrer, Bryan D. Pinney, and Timothy Faithfull. As previously announced by the Corporation, Mr. Faithfull has indicated to the Board that he intends to retire from the Board following TransAlta's 2019 annual and special meeting of the shareholders.

All members of the committee are financially literate pursuant to both Canadian and U.S. securities requirements and Ms. Park and Mr. Pinney have each 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 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 summarized in its Charter, 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 the Corporation's management and the external auditors.

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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.

Audit and Risk Committee Charter

The Charter of the ARC is attached as Appendix "A".

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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 his or her 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.

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.

B. Park (Chair)	Ms. Park has executive 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.

Bryan D. Pinney	Mr. Pinney has more than 30 years of experience in financial auditing, valuation and advising companies in energy and natural resources. He has been an Independent Director of North America Energy Partners Inc. since 2015 and its Lead Director since October 31, 2017. He served as Member of Deloitte’s Board of Directors. He has been the Chair of the Board of Governors and Member of the Board of Governors of Mount Royal University from September 2014 and May 2009 respectively and has previously served on a number of nonprofit boards. He has been an Independent Non-Executive Director at Persta Resources Inc., a Hong Kong listed oil and gas exploration company. He has been a Chartered Accountant since December 1978, a Fellow of the Chartered Professional Accountants of Alberta since January 2009 and a Chartered Business Valuator of Canada since December 1990. Mr. Pinney obtained a Bachelor of Arts in Business Administration from the University of Western Ontario in 1975 and also completed the Directors Education Program offered by the Institute of Corporate Directors in Canada in 2012.

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Other Board Committees

In addition to the ARC, TransAlta has two other standing committees: the Governance, Safety and Sustainability Committee and the Human Resources Committee. The members of these committees as at December 31, 2018 are:



Governance, Safety and Sustainability Committee	Human Resources Committee

Chair: John P. Dielwart	Chair: Georgia R. Nelson
Rona Ambrose	Rona Ambrose
Timothy W. Faithfull	Alan Fohrer
Yakout Mansour	Yakout Mansour
Georgia Nelson	Bryan D. Pinney
Beverlee F. Park

The Charters of the Governance, Safety and Sustainability 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, 2018 and December 31, 2017, Ernst & Young LLP and its affiliates were paid $3,303,359 and $2,799,884, respectively, as detailed below:



Ernst & Young LLP
Year Ended December 31	2018		2017

Audit Fees	$	3,022,276	$	2,708,884
Audit-related fees		166,328		91,000
Tax fees		104,255		0
All other fees		10,500		0

Total	$	3,303,359	$	2,799,884

No other audit firms provided audit services in 2018 or 2017.

The nature of each category of fees is described below:

Audit Fees

Audit-Related Fees

Assurance and related services that are reasonably related to the performance of the audit or review of our financial statements that are not included under "Audit Fees".

Tax Fees

Tax fees are tax-related services for review of tax returns, assistance with questions on tax audits, and tax planning.

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All Other Fees

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. 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.

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APPENDIX "A"

AUDIT AND RISK COMMITTEE CHARTER

TRANSALTA CORPORATION

(the "Corporation")

A. Establishment of Committee and Procedures


1.	Composition of Committee

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


2.	Appointment of Committee Members

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


3.	Vacancies

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


4.	Committee Chair

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


5.	Absence of Committee Chair

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


6.	Secretary of Committee

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

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7.	Meetings

The Chair of the Committee may call a 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.


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.

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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 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.

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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 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:

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(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 and Corporate Secretary (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 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.

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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


(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.

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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;


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

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(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 Corporate Secretary, 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.


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,

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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 – Cybersecurity


(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 cybersecurity 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.

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APPENDIX "B"

GLOSSARY OF TERMS

This Annual Information Form includes the following defined terms:

AESO – Alberta Electric System Operator.

AEMO – Australian Energy Market Operator.

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.

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

AUC – Alberta Utilities Commission.

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.

eERP – ecoEnergy for Renewable Power program, a program established by the federal Government of Canada.

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.

GGPPA – Greenhouse Gas Pollution Pricing Act (Canada).

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.

IESO – Independent Electricity System Operator.

B- 1

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.

Million cubic feet of gas per day (MMcf/d) – A measure of natural gas one million cubic feet per day.

MOU – Memorandum of Understanding between the Corporation and the Government of Alberta to collaborate and co-operate in the development of a capacity market in Alberta that ensures both current and new electricity generators will have a level economic playing field to build, buy, and sell electricity, and to develop a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation.

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.

NOx – Nitrogen Oxide.

OBPS – Output Based Pricing Standard.

OEFC – Ontario Electricity Financial Corporation.

Off-Coal Agreement – Off-Coal Agreement dated November 24, 2016 between, among others, TransAlta and Her Majesty the Queen in Right of Alberta.

PPA – Purchase power agreement.

Renewables PPA - Long-term power purchase agreements with certain subsidiaries of TransAlta Renewables providing for the purchase by TransAlta, for a fixed price, of all of the power produced at such subsidiaries.

S02 – Sulphur Dioxide.

Supercritical Combustion – 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.

TA Cogen – TransAlta Cogeneration LP.

tCO2e/GWh – Tonnes of carbon dioxide equivalent per gigawatt hour.

TSX – Toronto Stock Exchange.

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

B- 2

Management’s Discussion and Analysis

Table of Contents



Forward-Looking Statements	M 2	Critical Accounting Policies and Estimates	M 34
Additional IFRS Measures and Non-IFRS Measures	M 4	Accounting Changes	M 41
Business Model	M 4	Competitive Forces	M 43
Highlights	M 5	TransAlta's Capital	M 45
Discussion of Consolidated Financial Results	M 7	2018 Sustainability Performance	M 69
Significant and Subsequent Events	M 22	2019 Sustainability Performance Targets	M 73
Financial Position	M 26	Governance and Risk Management	M 74
Cash Flows	M 27	Fourth Quarter	M 84
Financial Instruments	M 27	Discussion of Consolidated Financial Results	M 86
2019 Financial Outlook	M 29	Selected Quarterly Information	M 89
Other Consolidated Analysis	M 32	Disclosure Controls and Procedures	M 90

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual 2018 consolidated financial statements and our Annual Information Form for the year ended Dec. 31, 2018 . Our consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) for Canadian publicly accountable enterprises as issued by the International Accounting Standards Board (“IASB”) and in effect at Dec. 31, 2018 . All dollar amounts in the following discussion, including the tables, are in millions of Canadian dollars unless otherwise noted and except amounts per share which are in whole dollars to the nearest two decimals. This MD&A is dated February 26, 2019 . Additional information respecting TransAlta Corporation (“TransAlta”, “we”, “our”, “us” or the “Corporation”), including our Annual Information Form, is available on SEDAR at www.sedar.com , on EDGAR at www.sec.gov , and on our website at www.transalta.com . Information on or connected to our website is not incorporated by reference herein.

TRANSALTA CORPORATION M 1

Management’s Discussion and Analysis

Forward-Looking Statements

This MD&A includes "forward-looking information" within the meaning of applicable Canadian securities laws, and "forward-looking statements" within the meaning of applicable United States securities laws, including the United States Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements"). All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made and on management's experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may", "will", "can"; "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, events or results and are subject to risks, uncertainties and other important factors that could cause our actual performance, events or results to be materially different from that set out in or implied by the forward-looking statements.

In particular, this MD&A contains forward-looking statements including, but not limited to: our transformation, growth, capital allocation and debt reduction strategies; growth opportunities from 2018 to 2031 and beyond; potential for growth in renewables and greenfield development acquisitions; the amount of capital allocated to new growth or development projects; our business, anticipated future financial performance and anticipated results, including our outlook and performance targets; our expected success in executing on our growth projects; the timing and the completion of growth and development projects, and their attendant costs; our estimated spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations, capital spend and maintenance, and the variability of those costs; the conversion of our coal-fired units to natural gas, and the timing and costs thereof; the form and terms of any definitive agreement with Tidewater, as defined below, regarding the construction of a pipeline; the terms of the current or any further proposed normal course issuer bid, including timing and number of shares to be repurchased pursuant to the normal course issuer bid and the acceptance thereof by the Toronto Stock Exchange; the mothballing of certain units; the impact of certain hedges on future earnings, results and cash flows; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity, including for clean energy, 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 and other fuel 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 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; our marketing and trading strategy and the risks involved in these strategies; estimates of future tax rates, future tax expense and the adequacy of tax provisions; changes in accounting estimates and accounting policies; anticipated growth rates and competition in our markets; our expectations and obligations and anticipated liabilities 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 US dollar 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; and our credit practices.

The forward-looking statements contained in this MD&A are based on many assumptions including, but not limited to, the following: no significant changes to applicable laws and regulations, including any tax and regulatory changes in the markets in which we operate; no material adverse impacts to the investment and credit markets; assumptions related to 2019 guidance include: Alberta spot power price equal to $50 to $60 per megawatt hours ("MWh"); Alberta contracted power price equal to $50 to $55 per MWh; Mid-C spot power prices equal to US$20 to US$25 per MWh; Mid-C contracted power price of US$47 to US$53 per MWh; sustaining capital between $160 million and $190 million; productivity capital of $10 million to $15 million; Sundance coal capacity factor of 30% and hydro and wind resource being approximately in line with long-term averages; our proportionate ownership of TransAlta Renewables not changing materially; no decline in the dividends to be received from TransAlta Renewables; the expected life extension of the coal fleet and anticipated financial results generated on conversion; assumptions regarding the ability of the converted units to successfully compete in the Alberta capacity market; and assumptions regarding the our current strategy and priorities, including as it pertains to our current priorities relating to the coal-to-gas conversions, growing TransAlta Renewables and being able to realize the full economic benefit from the capacity, energy and ancillary services from our Alberta hydro assets once the applicable power purchase arrangement has expired.

TRANSALTA CORPORATION M 2

Management’s Discussion and Analysis

Forward-looking statements are subject to a number of significant risks, uncertainties and assumptions that could cause actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this MD&A include, but are not limited to, risks relating to: fluctuations in market prices; changes in demand for electricity and capacity and our ability to contract our generation for prices that will provide expected returns and replace contracts as they expire; the legislative, 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 or market 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 and other climate-change related risks; unexpected increases in cost structure and disruptions in the source of fuels, water or wind required to operate our facilities; failure to meet financial expectations; natural and man-made disasters, including those resulting in dam or dyke failures; 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 and energy trading risks; industry risk and competition; the need to engage or rely on certain stakeholder groups and third parties; fluctuations in the value of foreign currencies and foreign political risks; the need for and availability of additional financing; structural subordination of securities; counterparty credit risk; changes in credit and market conditions; changes to our relationship with, or ownership of, TransAlta Renewables; risks associated with development projects and acquisitions, including capital costs, permitting, labour and engineering risks, and delays in the construction or commissioning of projects or delays in the closing of acquisitions; increased costs or delays in the construction or commissioning of pipelines to converted units; changes in expectations in the payment of future dividends, including from TransAlta Renewables Inc.; inadequacy or unavailability of insurance coverage; downgrades in credit ratings; our provision for income taxes; legal, regulatory and contractual disputes and proceedings involving the Corporation, including as it pertains to establishing commercial operations at the South Hedland Power Station; reliance on key personnel; and labour relations matters. The foregoing risk factors, among others, are described in further detail in the Governance and Risk Management section of this MD&A and the Risk Factors section in our Annual Information Form for the year ended Dec. 31, 2018 .

Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on them, which reflect the Corporation's expectations only as of the date hereof. 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 statements might occur to a different extent or at a different time than we have described, or might not occur at all. We cannot assure that projected results or events will be achieved.

TRANSALTA CORPORATION M 3

Management’s Discussion and Analysis

Additional IFRS Measures and Non-IFRS Measures

An additional IFRS measure is a line item, heading or subtotal that is relevant to an understanding of the consolidated financial statements but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an understanding of the consolidated financial statements but is not presented elsewhere in the consolidated financial statements. We have included line items entitled gross margin and operating income (loss) in our Consolidated Statements of Earnings (Loss) for the years ended Dec. 31, 2018 , 2017 and 2016 . Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.

We evaluate our performance and the performance of our business segments using a variety of measures. Certain of the financial measures discussed in this MD&A are not defined under IFRS, are not standard measures under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. Comparable EBITDA, FFO, FCF, total consolidated net debt, adjusted net debt and segmented cash flow generated by the business, all as defined below, are non-IFRS measures that are presented in this MD&A. See the Discussion of Consolidated Financial Results, Segmented Comparable Results, Key Financial Ratios and TransAlta’s Capital sections of this MD&A for additional information, including a reconciliation of such non-IFRS measures to the most comparable IFRS measure.

Business Model

Our Business

We are one of Canada’s largest publicly traded power generators with over 108 years of operating experience. We own, operate and manage a highly contracted and geographically diversified portfolio of assets representing 8,273 MW ⁽¹⁾ of capacity and use a broad range of generation fuels comprised of coal, natural gas, water, solar and wind. Our energy marketing operations maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions.

Vision and Values

Our vision is to be a leader in clean energy using our expertise, scale and diversified fuel mix to capitalize on opportunities in our core markets and grow in areas where our competitive advantages can be employed. Our values are grounded in accountability, integrity, safety, respect for people, innovation and loyalty, which together create a strong corporate culture and allow all of our people to work on a common ground and understanding. These values are at the heart of our success.

Strategy for Value Creation

Our goals are to deliver shareholder value by delivering solid returns through a combination of dividend yield and disciplined growth in cash flow per share, while striving for a low to moderate risk profile over the long term, balancing capital allocation and maintaining financial strength to allow for financial flexibility. Our comparable cash flow growth is driven by optimizing and diversifying our existing assets and further expanding our overall portfolio and operations in Canada, the US and Australia. We are focusing on these geographic areas as our expertise, scale and diversified fuel mix allow us to create expansion opportunities in our core markets.

Material Sustainability Impacts

Sustainability means ensuring that our financial returns consider short- and long-term economics, environmental impacts and societal and community needs. We track the performance of 74 sustainability-related Key Performance Indicators (“KPIs”). We obtained a limited assurance report from Ernst & Young LLP over material KPIs. This MD&A integrates our financial and sustainability reporting.

(1) We measure capacity as maximum capacity (see the Glossary of Key Terms for definition of this and other key terms), which is consistent with industry standards. Capacity figures represent capacity owned and in operation unless otherwise stated, and reflect the basis of consolidation of underlying assets.

TRANSALTA CORPORATION M 4

Management’s Discussion and Analysis

Highlights

Consolidated Financial Highlights



Year ended Dec. 31	2018		2017		2016
Revenues	2,249		2,307		2,397
Net earnings (loss) attributable to common shareholders	(248	)	(190	)	117
Cash flow from operating activities	820		626		744
Comparable EBITDA ⁽¹⁾	1,123		1,062		1,144
FFO ⁽¹⁾	927		804		734
FCF ⁽¹⁾	524		328		257
Net earnings (loss) per share attributable to common shareholders, basic and diluted	(0.86	)	(0.66	)	0.41
FFO per share ⁽¹⁾	3.23		2.79		2.55
FCF per share ⁽¹⁾	1.83		1.14		0.89
Dividends declared per common share	0.20		0.12		0.20
Dividends declared per preferred share ⁽²⁾	1.29		0.77		1.36

As at Dec. 31	2018		2017		2016
Total assets	9,428		10,304		10,996
Total consolidated net debt ⁽¹⁾⁽³⁾	3,141		3,363		3,893
Total long-term liabilities	4,421		4,311		5,116

(1) These items are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Discussion of Consolidated Financial Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.

(2) Weighted average of the Series A, B, C, E, and G preferred share dividends declared. Dividends declared vary year over year due to timing of dividend declarations.

(3) Total consolidated net debt includes long-term debt, including current portion, amounts due under credit facilities, tax equity and finance lease obligations, net of available cash and the fair value of economic hedging instruments on debt. See the table in the Capital Structure section of this MD&A for more details on the composition of total consolidated net debt.

FCF, one of the Corporation's key financial metrics, totalled $ 524 million , up $ 196 million compared to last year. After adjusting for the one-time receipt for the termination of the Sundance B and C power purchase arrangements ("PPAs") in 2018 and the Ontario Electricity Financial Corporation ("OEFC") payment in 2017 (net of our partners share), FCF was $367 million or $56 million higher than 2017 . FFO was $ 927 million for 2018 , compared to $ 804 million for 2017 , an increase of $ 123 million .


▪	All generation segments had cash flows equal to or better than the same period last year.


▪	In Alberta, Canadian Coal, Hydro and our wind assets benefited from higher power prices. Average prices during the year in Alberta increased to $ 50 per MWh from $ 22 per MWh in 2017, mainly reflecting the impact of higher carbon pricing costs paid by certain generators and stronger market conditions.


▪	Canadian Coal cash flows were significantly higher in 2018 compared to 2017 as the cash flows in the first quarter included the one-time receipt for the termination of the Sundance B and C PPAs, which reflects the receipt of the capacity payments that would have been received over the 2018 to 2020 period had these PPAs not been terminated.


▪	Sustaining capital was lower in 2018 relative to 2017, primarily because of lower capital requirements in Canadian Coal as a result of the retirement of Sundance Units 1 and 2 and the mothballing of Sundance Units 3 and 5, and lower capital requirements in Canadian Gas and US Coal, mainly due to the timing of outages.

Revenues in 2018 were $2,249 million , down $58 million compared to 2017 , mainly as a result of lower production within the Canadian Coal segment due to the retirement of Sundance Units 1 and 2 and the mothballing of Sundance Units 3 and 5 resulting from the termination of the Sundance B and C PPAs. This was partially offset by increased prices in the Alberta market.

Comparable EBITDA for the year ended Dec. 31, 2018, was $1,123 million , up $61 million compared to 2017 , mainly due to the one-time receipt of $157 million for the termination of the Sundance B and C PPAs, partially offset by higher carbon compliance costs and reduced revenue relating to the termination of the Sundance B and C PPAs. Excluding unrealized mark-to-market losses, comparable EBITDA was $1,145 million . Beginning in the first quarter of 2019, unrealized mark-to-market gains or losses will be excluded from comparable EBITDA to be more comparable with other companies in the industry.

Net loss attributable to common shareholders in 2018 was $ 248 million ($ 0.86 net loss per share) compared to a net loss

TRANSALTA CORPORATION M 5

Management’s Discussion and Analysis

of $ 190 million ($ 0.66 net earnings per share) in 2017 . Earnings in 2018 were negatively impacted by higher mine depreciation and carbon compliance costs included in fuel and purchased power, higher impairments, lower finance lease income due to the sale of the Solomon facility, and higher preferred share dividends due to the timing of declarations, partially offset by the one-time receipt of $157 million for the termination of the Sundance B and C PPAs and lower income tax expense. Net loss attributable to common shareholders in 2017 was negatively impacted by lower comparable EBITDA of $82 million as well as the reduction of the US tax rate announced in December ($105 million). The US tax rate reduction was offset by an increase in other comprehensive income.

Significant Events

During 2018, our strategic focus continued to be on reducing our corporate debt, improving our operating performance and transitioning to clean power generation. The Corporation made the following progress in executing upon its strategy throughout the period:


▪	On Dec. 17, 2018, we exercised our option to acquire a 50 per cent ownership in the gas pipeline ("Pioneer Pipeline") connecting Tidewater Midstream and Infrastructure Ltd.'s ("Tidewater") Brazeau River Complex to TransAlta's generating units at Sundance and Keephills. Our investment is subject to regulatory approval.


▪	On Dec. 17, 2018, the Corporation announced that we will invest $270 million in our 207 MW Windrise wind project, which was selected by the Alberta Electric System Operator ("AESO") as one of the two successful projects in the Renewable Electricity Program Round 3.


▪	On Nov. 13, 2018, we appointed Christophe Dehout as our Chief Financial Officer, replacing Brett Gellner (our then interim Chief Financial Officer), who continues to serve as our Chief Strategy and Investment Officer. Mr. Dehout brings broad experience in power generation and extensive knowledge of capital markets, mergers and acquisitions, corporate finance and corporate transformations.


▪	On Oct. 19, 2018, TransAlta Renewables announced that the 17.25 MW expansion of the wind facility at Kent Hills, New Brunswick, is fully operational, bringing total generating capacity at the site to 167 MW.


▪	On Aug. 2, 2018, the Corporation redeemed all of our then outstanding 6.40 per cent debentures, due Nov. 18, 2019, for approximately $425 million, including the principal amount of $400 million, a prepayment premium and accrued and unpaid interest.


▪	On July 20, 2018, the Corporation monetized the payments under the Off-Coal Agreement ("OCA") with the Government of Alberta and closed an approximate $345 million bond offering bearing interest at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030.


▪	On June 22, 2018, TransAlta Renewables closed a bought deal offering of 11,860,000 common shares through a syndicate of underwriters. The shares were issued at a price of $12.65 per share for gross proceeds of approximately $150 million.

▪

On May 31, 2018, TransAlta Renewables acquired an economic interest in the 50 MW Lakeswind Wind Farm and 21 MW of solar projects located in the US ("Mass Solar") from TransAlta and acquired ownership of the 20 MW Kent Breeze Wind Farm located in Ontario. The total purchase price for the three assets was approximately $166 million, including the assumption of $62 million of tax equity obligations and project debt. On June 28, 2018, TransAlta Renewables subscribed for an additional $33 million (US$25 million) of tracking preferred shares of a subsidiary of the Corporation related to Mass Solar in order to fund the repayment of Mass Solar's project debt.


▪	On March 15, 2018, the Corporation redeemed the then outstanding 6.650 per cent US $500 million senior notes due May 15, 2018. The redemption price for the notes was approximately $617 million (US$516 million). Repayment of the US senior notes was funded by cash on hand and our credit facility.

▪

On Feb. 20, 2018, TransAlta Renewables entered into an arrangement to acquire two construction-ready wind projects in the Northeastern United States. The wind development projects consist of: i) a 90 MW project located in Pennsylvania that has a 15-year PPA with Microsoft Corp. ("Big Level") and ii) a 29 MW project located in New Hampshire with two 20-year PPAs ("Antrim") (collectively, the "US Wind Projects"). On April 20, 2018, TransAlta Renewables acquired an economic interest in the Big Level project. The Corporation expects the Antrim acquisition to close in early 2019.


▪	During the year, the Corporation purchased and cancelled 3,264,500 common shares at an average price of $7.02 per common share through our normal course issuer bid ("NCIB") program, for a total cost of $23 million .


▪	On March 31, 2018, the Corporation received approximately $157 million in compensation for the termination of the Sundance B and C PPAs from the Balancing Pool.


▪	On Jan. 1, 2018, the Corporation permanently shutdown Sundance Unit 1 and mothballed Sundance Unit 2. On April 1, 2018, we mothballed Sundance Unit 3 and Sundance Unit 5. On July 31, 2018, we decided to permanently shut down Sundance Unit 2.

See the Significant and Subsequent Events section of this MD&A for further details.

TRANSALTA CORPORATION M 6

Management’s Discussion and Analysis

Discussion of Consolidated Financial Results

We evaluate our performance and the performance of our business segments using a variety of measures. Certain of the financial measures discussed in this MD&A, including the comparable figures below, are not defined under IFRS. Those discussed below, and elsewhere in this MD&A, are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures are not necessarily comparable to a similarly titled measure of another company. Each business segment assumes responsibility for its operating results measured to comparable EBITDA and cash flows generated by the business. Gross margin is also a useful measure as it provides management and investors with a measurement of operating performance that is readily comparable from period to period.

Comparable EBITDA

EBITDA is a widely adopted valuation metric and an important metric for management that represents our core business profitability. Interest, taxes, and depreciation and amortization are not included, as differences in accounting treatments may distort our core business results. In addition, we reclassify certain transactions to facilitate the discussion of the performance of our business:


▪	Certain assets we own in Canada (and in 2016 and 2017 in Australia) are fully contracted and recorded as finance leases under IFRS. We believe it is more appropriate to reflect the payments we receive under the contracts as a capacity payment in our revenues instead of as finance lease income and a decrease in finance lease receivables. We depreciate these assets over their expected lives;


▪	We also reclassify the depreciation on our mining equipment from fuel and purchased power to reflect the actual cash cost of our business in our comparable EBITDA;

▪

In December 2016, we agreed to terminate our existing arrangement with the Independent Electricity System Operator (“IESO”) relating to our Mississauga cogeneration facility in Ontario and entered into a new Non-Utility Generator (“NUG”) Enhanced Dispatch Contract (the “NUG Contract”) effective Jan. 1, 2017. Under the new NUG Contract, we received fixed monthly payments until December 31, 2018 with no delivery obligations. Under IFRS, for our reported results in 2016, as a result of the NUG Contract, we recognized a receivable of $207 million (discounted), a pre-tax gain of approximately $191 million net of costs to mothball the units, and accelerated depreciation of $46 million. In 2017 and 2018, on a comparable basis, we recorded the payments we received as revenues as a proxy for operating income, and continued to depreciate the facility until Dec. 31, 2018; and


▪	On the commissioning of the South Hedland Power Station in July 2017, we prepaid approximately $74 million of electricity transmission and distribution costs. Interest income is recorded on the prepaid funds. We reclassify this interest income as a reduction in the transmission and distribution costs expensed each period to reflect the net cost to the business.

TRANSALTA CORPORATION M 7

Management’s Discussion and Analysis

A reconciliation of net earnings (loss) attributable to common shareholders to comparable EBITDA results is set out below:



Year ended Dec. 31	2018		2017		2016
Net earnings (loss) attributable to common shareholders	(248	)	(190	)	117
Net earnings attributable to non-controlling interests	108		42		107
Preferred share dividends	50		30		52
Net earnings (loss)	(90	)	(118	)	276
Adjustments to reconcile net income to comparable EBITDA
Income tax expense (recovery)	(6	)	64		38
Gain on sale of assets and other	(1	)	(2	)	(4	)
Foreign exchange (gain) loss	15		1		5
Net interest expense	250		247		229
Depreciation and amortization	574		635		601
Comparable reclassifications
Decrease in finance lease receivables	59		59		57
Mine depreciation included in fuel cost	140		75		65
Australian interest income	4		2		—
Adjustments to earnings to arrive at comparable EBITDA
Impacts to revenue associated with certain de-designated and economic hedges	—		2		26
Impacts associated with Mississauga recontracting ⁽¹⁾	105		77		(177	)
Asset impairment charge ⁽²⁾	73		20		28
Comparable EBITDA	1,123		1,062		1,144

(1) Impacts associated with Mississauga recontracting for the year ended Dec. 31, 2018 , are as follows: revenue ( $108 million ), and fuel and purchased power and de-designated hedges ( $3 million ). Impacts associated with Mississauga recontracting for the year ended Dec. 31, 2017, are as follows: revenue ($101 million), fuel and purchased power and de-designated hedges ($12 million), operations, maintenance and administration ($3 million), and recovery related to a renegotiated land lease ($9 million). Impacts associated with Mississauga recontracting for the year ended Dec. 31, 2016, are as follows: net other operating income ($191 million) and fuel and purchased power and de-designated hedges ($14 million).

(2) Asset impairment charges for 2018 include a $38 million charge related to the retirement of Sundance Unit 2, Lakeswind and Kent Breeze impairment of $12 million and a write-off of project development costs of $23 million ( 2017 - $20 million retirement of Sundance Unit 1, 2016 - $28 million for the Wintering Hills impairment).

Comparable EBITDA increased by $61 million for the year ended Dec. 31, 2018 , compared to 2017 . This was mainly due to:


▪	Our Canadian Coal and Hydro segments were up year over year, and together accounted for an increase of $110 million of comparable EBITDA.


◦	At Canadian Coal, the one-time receipt of $157 million for the termination of the Sundance B and C PPAs was partially offset by higher carbon compliance costs and reduced revenue relating to the termination of the Sundance B and C PPAs.


◦	Our Hydro operations benefited from higher market prices for Ancillary Services.


▪	Our US Coal, Canadian Gas and Australian Gas segments were down compared to 2017 for a combined decrease of $44 million .


◦	US Coal was down primarily due to non-cash mark-to-market losses.


◦	Our Canadian Gas segment was lower mainly because 2017 comparable EBITDA benefited from the settlement of the contract indexation dispute with the OEFC relating to the Ottawa and Windsor generating facilities, totalling $34 million, which was mostly offset by the positive impact of the Mississauga recontracting and cost reduction initiatives.


◦	Our Australian Gas segment was lower mainly due to lower finance income as a result of Fortescue Metals Group Ltd.'s ("FMG") repurchase of the Solomon Power Station partially offset by a full year of operations for the South Hedland Power Station.


▪	Our Wind and Solar segment benefited from higher merchant prices and insurance proceeds from a tower fire at Wyoming Wind Farm, which were offset by the unfavourable impact of the US non-cash mark-to-market losses relating to the fair value of the Big Level PPA contract, resulting in flat comparable EBITDA.


▪	Energy Marketing was down $2 million in 2018 compared to 2017 , but overall, largely consistent year over year.


▪	Corporate costs remained consistent with 2017 results.

Our overall results in 2018 included costs of approximately $ 16 million (2017 - $29 million) in operations, maintenance and administration (“OM&A”) and $21 million (2017 - $25 million) in productivity capital relating to Project Greenlight, our transformation initiative. We estimate that the Project Greenlight initiatives generated net $70 million in gross margin,

TRANSALTA CORPORATION M 8

Management’s Discussion and Analysis

OM&A expenses and capital savings. See the Power Generating Portfolio Capital and Strategic Growth and Corporate Transformation sections of this MD&A for further details regarding Project Greenlight.

Funds from Operations and Free Cash Flow

FFO is an important metric as it provides a proxy for cash generated from operating activities before changes in working capital, and provides the ability to evaluate cash flow trends in comparison with results from prior periods. FCF is an important metric as it represents the amount of cash that is available to invest in growth initiatives, make scheduled principal repayments on debt, repay maturing debt, pay common share dividends or repurchase common shares. Changes in working capital are excluded so FFO and FCF are not distorted by changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and timing of receipts and payments. FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period.

The table below reconciles our cash flow from operating activities to our FFO and FCF: . ⁽



Year ended Dec. 31	2018		2017		2016
Cash flow from operating activities	820		626		744
Change in non-cash operating working capital balances	44		114		(73	)
Cash flow from operations before changes in working capital	864		740		671
Adjustments
Decrease in finance lease receivable	59		59		57
Other	4		5		6
FFO	927		804		734
Deduct:
Sustaining capital	(168	)	(235	)	(272	)
Productivity capital	(21	)	(24	)	(8	)
Dividends paid on preferred shares	(40	)	(40	)	(42	)
Distributions paid to subsidiaries’ non-controlling interests	(169	)	(172	)	(151	)
Other	(5	)	(5	)	(4	)
FCF	524		328		257
Weighted average number of common shares outstanding in the year	287		288		288
FFO per share	3.23		2.79		2.55
FCF per share	1.83		1.14		0.89

The increase in FCF was driven by year-over-year stronger cash flow from operating activities of $194 million partially due to the payment for the termination of the Sundance B and C PPAs and lower sustaining and productivity capital expenditures. Higher FCF in 2017 compared to 2016 was also driven by strong cash flow from operations before changes in working capital and reduced sustaining and productivity capital expenditures. FCF in 2016 was lower due to payments made to the Market Surveillance Administrator of $25 million.

TRANSALTA CORPORATION M 9

Management’s Discussion and Analysis

The table below bridges our comparable EBITDA to our FFO and FCF:



Year ended Dec. 31	2018		2017		2016
Comparable EBITDA	1,123		1,062		1,144
Provisions	7		(7	)	(114	)
Unrealized (gains) losses from risk management activities	22		(28	)	4
Interest expense	(187	)	(218	)	(229	)
Current income tax expense	(28	)	(23	)	(23	)
Realized foreign exchange gain (loss)	5		15		(5	)
Decommissioning and restoration costs settled	(31	)	(19	)	(23	)
Other cash and non-cash items	16		22		(20	)
FFO	927		804		734
Deduct:
Sustaining capital	(168	)	(235	)	(272	)
Productivity capital	(21	)	(24	)	(8	)
Dividends paid on preferred shares	(40	)	(40	)	(42	)
Distributions paid to subsidiaries’ non-controlling interests	(169	)	(172	)	(151	)
Other	(5	)	(5	)	(4	)
FCF	524		328		257

Segmented Comparable Results

Segmented cash flows generated by the business measures the net cash generated by each of our segments after sustaining and productivity capital expenditures, reclamation costs, provisions, and non-cash mark-to-market gains or losses. This is the cash flow available to: pay our interest and cash taxes, make distributions to our non-controlling partners and pay dividends to our preferred shareholders, grow the business, pay down debt and return capital to our shareholders.



Year ended Dec. 31	2018		2017		2016
Segmented cash flow ⁽¹⁾
Canadian Coal ⁽²⁾	279		175		198
US Coal	63		33		21
Canadian Gas ⁽³⁾	228		221		235
Australian Gas	136		127		99
Wind and Solar	211		201		180
Hydro	96		61		53
Generation segmented cash flow	1,013		818		786
Energy Marketing	33		39		25
Corporate	(107	)	(108	)	(95	)
Total segmented cash flow	939		749		716

(1) Segmented cash flow is a non-IFRS measure.

(2) 2018 includes $157 million received from the Balancing Pool for the early termination of the Sundance B and C PPAs in the first quarter of 2018.

(3) 2017 includes $34 million from the OEFC relating to the 2017 indexation dispute.

Cash flow generated by the business totalled $939 million in 2018 , up $190 million over 2017 , mainly due to the one-time receipt of $157 million for the termination of the Sundance B and C PPAs, lower sustaining capital expenditures and higher Ancillary Services revenue from our hydro facilities. Cash flow in 2017 was $33 million higher than 2016 due to disciplined cost control and sustaining capital expenditure allocation.

TRANSALTA CORPORATION M 10

Management’s Discussion and Analysis

Canadian Coal



Year ended Dec. 31	2018		2017		2016
Availability (%)	91.6		82.0		85.3
Contract production (GWh)	8,936		18,683		19,823
Merchant production (GWh)	5,304		3,786		3,787
Total production (GWh)	14,240		22,469		23,610
Gross installed capacity (MW) ⁽¹⁾	3,231		3,791		3,791
Revenues	912		999		1,048
Fuel and purchased power	526		510		386
Comparable gross margin	386		489		662
Operations, maintenance and administration	171		192		178
Taxes, other than income taxes	13		13		13
Net other operating expense (income) ⁽²⁾	(198	)	(40	)	(2	)
Comparable EBITDA	400		324		473
Deduct:
Sustaining capital:
Routine capital	17		22		33
Mine capital	42		28		23
Finance leases	14		14		13
Planned major maintenance	15		54		100
Total sustaining capital expenditures	88		118		169
Productivity capital	12		12		1
Total sustaining and productivity capital	100		130		170

Provisions	(10	)	5		85
Unrealized gains (losses) on risk management activities	11		3		7
Decommissioning and restoration costs settled	19		11		13
Other	1		—		—
Canadian Coal cash flow	279		175		198

(1) On Jan. 1, 2018, 560 MW Sundance Units 1 and 2 were shut down and mothballed, respectively. On April 1, 2018, 774 MW Sundance Units 3 and 5 were mothballed. On July 31, 2018 Sundance Unit 2 was shut down permanently.

(2) In 2018, this includes the $157 million payment for the termination of the Sundance B and C PPAs. In both 2018 and 2017, this includes the $40 million OCA payment.

2018

Availability for the year improved compared to 2017 , mainly due to lower planned outages and unplanned outages and derates in 2018 .

Production for the year ended Dec. 31, 2018 , decreased 8,229 gigawatt hours (“GWh”) compared to 2017 , primarily due to the retirement and mothballing of certain Sundance units and less dispatching, partially offset by lower planned and unplanned outages.

Revenue for the year ended Dec. 31, 2018 , decreased by $87 million compared to 2017 , mainly due to lower production offset by higher prices. Revenue per MWh of production rose to approximately $64 per MWh in 2018 from $44 per MWh in 2017 , which more than offset the increase in carbon compliance costs and resulted in higher gross margin per MWh in 2018 .

Fuel, carbon compliance costs and purchased power costs per MWh were higher in 2018 compared to 2017 . Coal costs on a dollar per MWh were higher due to fixed costs and lower tonnage. Pit development work commenced in 2018 at the Highvale mine and is expected to provide the lowest cost fuel for the remaining life of the facilities. Carbon compliance costs were higher in 2018 , reflecting the regulated increase in the carbon price and due to the fact that carbon compliance costs are no longer recoverable on the Sundance units as the PPAs have been terminated. Both the fuel and carbon pricing cost increases were as expected.

During the year we commenced co-firing with natural gas. Natural gas combustion produces fewer greenhouse gas ("GHG") emissions than coal combustion, which lowers our GHG compliance costs. The combined impact of relatively low Alberta

TRANSALTA CORPORATION M 11

Management’s Discussion and Analysis

gas prices and lower GHG compliance costs made this economically viable on the merchant plants for a substantial part of the year.

OM&A costs were lower in 2018 compared to 2017 . There are certain fixed and common costs that are required to maintain the remaining operational Sundance units and some one-time OM&A costs were incurred in association with the mothballing and retirement of Sundance Units 1 and 2. We continue to optimize the operations of the facility in response to the merchant market.

Comparable EBITDA for the year ended Dec. 31, 2018 , increased $76 million compared to 2017 , as a result of the one-time receipt of $157 million for the termination of the Sundance B and C PPAs, partially offset by higher carbon compliance costs and reduced revenue relating to the termination of the Sundance B and C PPAs.

For the year ended Dec. 31, 2018 , sustaining capital expenditures decreased by $30 million compared to 2017 , mainly due to lower planned outages and mothballing of units, partially offset by increased mine pit development work. Establishing a new pit provides the lowest cost fuel for the remaining life of the facilities. In 2017 , four planned outages were performed throughout the year, while during 2018 there was only one planned major outage at one of our non-operated plants. Overall, for 2018 , there are four fewer units in the fleet to maintain, which significantly reduced our sustaining capital costs.

2017

Availability in 2017 was down compared to 2016 due to higher unplanned outages and derates due to coal supply disruptions at our mine during the last half of the year, which also resulted in lower production of 1,141 GWh year over year.

Comparable EBITDA for the year ended Dec. 31, 2017, decreased $149 million compared to 2016, due to the $80 million reversal of the Keephills 1 provision in the fourth quarter of 2016. As expected, fuel and purchased power were impacted by higher coal costs related to the expected higher strip ratio and higher environmental compliance costs in 2017. In addition, we incurred additional costs in the third quarter to mitigate the impact of lower productivity at our mine.

OM&A increased $14 million year over year due mostly to contractor spend on Project Greenlight improvement initiatives ($20 million) and higher material and operating expenses ($5 million), and was partially offset by lower compensation ($11 million). See the Strategic Growth and Corporate Transformation section of this MD&A for further details.

The 2017 results also included $40 million related to OCA payments included in net other operating income. We received our OCA payment in the third quarter.

Sustaining and productivity capital expenditures for the year ended Dec. 31, 2017, were lower by $40 million compared to 2016, mainly due to the timing of major outages in 2017 and pit stops executed in 2016 on our Sundance 1 and 2 units.

TRANSALTA CORPORATION M 12

Management’s Discussion and Analysis

US Coal



Year ended Dec. 31	2018		2017		2016
Availability (%)	60.2		66.3		88.1
Adjusted availability (%) ⁽¹⁾	84.6		86.2		88.9
Contract sales volume (GWh)	3,329		3,609		3,535
Merchant sales volume (GWh)	5,704		5,488		4,896
Purchased power (GWh)	(3,665	)	(3,625	)	(3,854	)
Total production (GWh)	5,368		5,472		4,577
Gross installed capacity (MW)	1,340		1,340		1,340
Revenues	442		437		380
Fuel and purchased power	314		293		281
Comparable gross margin	128		144		99
Operations, maintenance and administration	61		51		54
Taxes, other than income taxes	5		4		4
Comparable EBITDA	62		89		41
Deduct:
Sustaining capital:
Routine capital	2		3		3
Finance leases	4		3		3
Planned major maintenance	11		29		11
Total sustaining capital expenditures	17		35		17
Productivity capital	—		3		—
Total sustaining and productivity capital	17		38		17

Provisions	—		—		7
Unrealized gains (losses) on risk management activities	(29	)	10		(13	)
Decommissioning and restoration costs settled	11		8		9
US Coal cash flow	63		33		21

(1) Adjusted for dispatch optimization.

2018

Availability for the year was down compared to 2017 due to the timing of dispatch optimization and unplanned outages and derates in the last half of 2018 , slightly offset by forced outages at Centralia Unit 1 in January 2017. In 2017 and 2018 , both Centralia Units were taken out of service in February as a result of seasonally lower prices in the Pacific Northwest. In both years, we performed major maintenance during that time.

Production was down 104 GWh in 2018 compared to 2017 , due mainly to dispatch optimization and increased unplanned outages in the last half of the year.

OM&A costs were $10 million higher in 2018 compared to 2017 , due to employee gainshare, annual incentive compensation and retention bonuses, as well as increased disbursements paid to the community fund.

Comparable EBITDA decreased by $27 million compared to 2017 primarily due to unfavourable changes on unrealized mark-to-market positions recorded within fuel and purchased power offset by reduced coal costs and favourable market prices.

Sustaining and productivity capital expenditures for 2018 were $21 million lower than 2017 , due to lower planned outages.

US Coal's 2018 cash flow improved by $30 million compared to the prior year, mainly due to stronger operating results excluding unrealized mark-to-market impacts and lower sustaining and productivity capital spend.

2017

Availability was down compared to 2016 due to a forced outage on Centralia Unit 1 in January. Both Centralia Units were taken out of service in February due to low prices in the Pacific Northwest market. We performed major maintenance on both units during that time. The lower availability was not material to our results as our contractual obligations were supplied with less expensive power purchased in the market during the first half of the year.

TRANSALTA CORPORATION M 13

Management’s Discussion and Analysis

Production was up 895 GWh in 2017 compared to 2016 due mainly to lower dispatch optimization caused by higher prices in the fourth quarter of 2017. The increased generation was partially offset by higher unplanned and planned maintenance.

Comparable EBITDA increased by $48 million compared to 2016 due to increased sales volumes that led to increased margins from higher market prices and higher contract rates. Lower coal transportation costs and the favourable impact of mark-to-market (year-over-year gain of $13 million) on certain forward financial contracts that do not qualify for hedge accounting also positively impacted comparable EBITDA.

Sustaining and productivity capital expenditures for the year ended Dec. 31, 2017, increased by $21 million compared to 2016 due to planned outages executed during the second quarter of 2017. Productivity capital was invested in the installation of inspection equipment to optimize heat rates on coal and improve air distribution systems.

Canadian Gas



Year ended Dec. 31	2018	2017	2016
Availability (%)	93.3	91.6	95.7
Contract production (GWh)	1,620	1,504	2,784
Merchant production (GWh)	93	244	288
Total production (GWh)	1,713	1,748	3,072
Gross installed capacity (MW) ⁽¹⁾	945	952	1,057
Revenues	407	430	470
Fuel and purchased power	99	113	171
Comparable gross margin	308	317	299
Operations, maintenance and administration	48	53	54
Taxes, other than income taxes	1	1	1
Comparable EBITDA	259	263	244
Deduct:
Sustaining capital:
Routine capital	4	8	7
Planned major maintenance	16	22	5
Total sustaining capital expenditures	20	30	12
Productivity capital	2	2	—
Total sustaining and productivity capital	22	32	12

Provisions	—	3	(2	)
Unrealized gains (losses) on risk management activities	9	7	(2	)
Decommissioning and restoration costs settled	—	—	1
Canadian Gas cash flow	228	221	235

(1) 2018 and 2017 excludes capacity of Mississauga, which was mothballed in early 2017. All years include production capacity for the Fort Saskatchewan power station, which has been accounted for as a finance lease. During 2015, operational control of our Poplar Creek facility was transferred to Suncor Energy (“Suncor”). We continue to own a portion of the facility and have included our portion as a part of gross capacity measures.

2018

Availability for the year ended Dec. 31, 2018 , increased 1.7 per cent compared to 2017 , mainly due to the 2017 base cycling conversion project at Windsor and lower planned and unplanned outages at Sarnia and Windsor in 2018.

Production for the year decreased 35 GWh compared to 2017 , as lower market demand at Sarnia was partially offset by higher production at the Fort Saskatchewan, Ottawa and Windsor facilities.

Comparable EBITDA for 2018 decreased by $ 4 million compared to 2017 , mainly due to the retroactive contract indexation dispute settlement with the OEFC in 2017 ($34 million) offset by the positive impact from the Mississauga recontracting, higher realized pricing at Sarnia and cost reduction initiatives. The Mississauga, Ottawa, Windsor, and our 60 per cent share of Fort Saskatchewan, generating facilities are owned through our 50.01 per cent interest in TransAlta Cogeneration L.P. ("TA Cogen"). The Mississauga recontracting ended in December 2018 and was not renewed.

TRANSALTA CORPORATION M 14

Management’s Discussion and Analysis

Sustaining capital totalled $ 20 million in 2018 , a decrease of $ 10 million mainly due to higher capital spend in 2017, when we completed the scheduled maintenance at Sarnia and the base cycling conversion project at Windsor to increase its flexibility to respond to market prices.

Cash flow at Canadian Gas improved by $7 million for the year ended Dec. 31, 2018 , compared to the prior year mainly due to lower sustaining capital spend in 2018, partially offset by lower EBITDA. In 2017, one-time sustaining capital expenditures were incurred for the Windsor base cycling conversion project.

2017

Availability decreased approximately four per cent compared to 2016, primarily due to a planned major inspection at our Sarnia plant, the conversion to the peaking plant at Windsor and an unplanned steam turbine outage at Windsor.

Production in 2017 decreased 1,324 GWh compared to 2016, primarily due to changes in contracts at Mississauga and Windsor at the end of 2016.

Comparable EBITDA for 2017 increased by $19 million compared to 2016, primarily due to the settlement with the OEFC of the retroactive adjustment to price indices at Ottawa and Windsor and the positive impact from the temporary shutdown at our Mississauga gas facility, partially offset by unfavourable changes on unrealized mark-to-market positions in gas contracts that do not qualify for hedge accounting and the reduction in earnings from the change to a peaking contract at our Windsor facility.

Sustaining capital for the year ended Dec. 31, 2017, increased $18 million compared to the same period in 2016, primarily due to the planned major inspection at Sarnia and the base to cycling conversion project at Windsor, which was undertaken to increase its flexibility to respond to market prices.

In December 2018, TransAlta exercised its option to terminate its agreement with Boeing Canada Inc. in Mississauga effective Dec. 31, 2021. TransAlta is required to remove the Mississauga plant and restore the site within the three-year time frame.

Australian Gas



Year ended Dec. 31	2018		2017	2016
Availability (%)	94.0		93.4	93.1
Contract production (GWh)	1,814		1,803	1,529
Gross installed capacity (MW) ⁽¹⁾	450		450	425
Revenues	165		180	174
Fuel and purchased power	4		12	20
Comparable gross margin	161		168	154
Operations, maintenance and administration	37		31	25
Taxes, other than income taxes	—		—	1
Comparable EBITDA	124		137	128
Deduct:
Sustaining capital:
Routine capital	2		9	3
Planned major maintenance	—		1	11
Total sustaining and productivity capital	2		10	14

Other	(14	)	—	15
Australian Gas cash flow	136		127	99

(1) The 2016 figures include production capacity for the Solomon Power Station, which was accounted for as a finance lease. In 2017, FMG repurchased the Solomon Power Station and therefore was removed from 2017 capacity, which was offset by adding capacity for the South Hedland Power Station, which achieved commercial operations on July 28, 2017.

TRANSALTA CORPORATION M 15

Management’s Discussion and Analysis

2018

Availability for the year ended Dec. 31, 2018 , increased compared to 2017 , mainly due to a full year of operation from the South Hedland Power Station, which was offset by FMG's repurchase of the Solomon Power Station.

Production for 2018 was comparable to 2017 , due to the addition of the South Hedland Power Station, which was offset by FMG’s repurchase of the Solomon Power Station. Due to the nature of our contracts, changes in production do not have a significant financial impact as our contracts are structured as capacity payments with a pass-through of fuel costs.

Comparable EBITDA for the year decreased by $13 million compared to 2017 mainly due to FMG's repurchase of Solomon Power Station, higher OM&A costs due to the addition of the South Hedland Power Station and ongoing legal costs associated with our dispute with FMG, which were partially offset by higher EBITDA from the South Hedland Power Station.

Sustaining and productivity capital for 2018 decreased by $8 million compared to 2017 , due to major maintenance incurred at our Southern Cross facility in August 2017 that was not required in 2018 .

Cash flow at Australian Gas increased by $ 9 million in 2018 mainly due to lower sustaining capital requirements and an increase in cash flow from the collection of a long-term receivable, largely offset by lower EBITDA.

2017

Production for 2017 increased by 274 GWh compared to 2016 due to the commissioning of our South Hedland Power Station in July 2017, and an increase in customer load, partially offset by the early termination of our lease for our Solomon Power Station in November 2017. As a result of the early termination, we received US$325 million ($417 million) in the fourth quarter of 2017. Due to the nature of our contracts, the increase in customer load did not have a significant financial impact on our results as our contracts are structured as capacity payments with a pass-through of fuel costs.

Comparable EBITDA was up $9 million for 2017 compared to 2016 due to the commissioning of our South Hedland Power Station in July 2017, which was partially offset by the early termination of our lease for our Solomon Power Station in November 2017.

TRANSALTA CORPORATION M 16

Management’s Discussion and Analysis

Wind and Solar



Year ended Dec. 31	2018		2017	2016
Availability (%)	95.4		95.8	94.9
Contract production (GWh)	2,363		2,362	2,301
Merchant production (GWh)	1,005		1,098	1,212
Total production (GWh)	3,368		3,460	3,513
Gross installed capacity (MW) ⁽¹⁾	1,382		1,363	1,408
Revenues	282		287	272
Fuel and purchased power	17		17	18
Comparable gross margin	265		270	254
Operations, maintenance and administration	50		48	52
Taxes, other than income taxes	8		8	8
Net other operating income	(6	)	—	(1	)
Comparable EBITDA	213		214	195
Deduct:
Sustaining capital:
Routine capital	5		1	2
Planned major maintenance	8		10	11
Total sustaining capital expenditures	13		11	13
Productivity capital	2		2	3
Total sustaining and productivity capital	15		13	16

Provisions	—		—	(1	)
Unrealized gains (losses) on risk management activities	(20	)	—	—
Decommissioning and restoration costs settled	1		—	—
Other (insurance proceeds)	6		—	—
Wind and Solar cash flow	211		201	180

(1) The 2017 figure excludes capacity for the Wintering Hills wind facility, which was sold on March 1, 2017.

2018

Availability for the year ended Dec. 31, 2018 , was comparable to 2017 , which was expected.

Production for 2018 decreased by 92 GWh compared to 2017 , mainly due to lower wind resources across Alberta and the United States combined with the sale of the Wintering Hills merchant facility on March 1, 2017. This lower production was partially offset by higher wind resources in Eastern Canada.

Comparable EBITDA for 2018 was comparable with 2017 , as higher merchant prices in Alberta and insurance proceeds from the tower fire at Wyoming Wind Farm were offset by the unfavourable impact of the US non-cash mark-to-market losses relating to the fair value of the Big Level PPA contract and the unfavourable impact of lower wind resources.

Wind and Solar's cash flow improved by $ 10 million for the year ended Dec. 31, 2018, compared to the prior year, due mainly to the addback of the US non-cash mark-to-market losses relating to the fair value of the Big Level PPA contract.

2017

Production for 2017 decreased by 53 GWh compared to 2016 as we sold the Wintering Hills wind facility in the first quarter of 2017. Generation from our other facilities was slightly higher than in 2016.

Comparable EBITDA for 2017 increased $19 million compared to 2016, primarily driven by higher volumes at contracted facilities, price increases on our contracted assets, higher prices in Alberta on our uncontracted assets and lower costs in our long-term service agreements.

TRANSALTA CORPORATION M 17

Management’s Discussion and Analysis

Hydro



Year ended Dec. 31	2018		2017		2016
Production
Energy contracted
Alberta hydro PPA assets (GWh) ⁽¹⁾	1,519		1,530		1,410
Other hydro energy (GWh) ⁽¹⁾	306		336		358
Energy merchant
Other hydro energy (GWh)	81		82		88
Total energy production (GWh)	1,906		1,948		1,856
Ancillary service volumes (GWh) ⁽²⁾	3,265		3,044		2,623
Gross installed capacity (MW)	926		926		926
Revenues
Alberta hydro PPA assets energy	90		36		28
Alberta hydro PPA assets ancillary	104		36		30
Capacity payments received under Alberta hydro PPA ⁽³⁾	56		54		55
Other revenue ⁽⁴⁾	41		43		50
Total gross revenues	291		169		163
Net payment relating to Alberta hydro PPA	(135	)	(48	)	(37	)
Revenues	156		121		126

Fuel and purchased power	6		6		8
Comparable gross margin	150		115		118
Operations, maintenance and administration	38		37		33
Taxes, other than income taxes	3		3		3
Net other operating income	—		—		—
Comparable EBITDA	109		75		82
Deduct:
Sustaining capital:
Routine capital, excluding hydro life extension	4		8		8
Hydro life extension	—		—		9
Planned major maintenance	8		5		10
Total before flood-recovery capital	12		13		27
Flood-recovery capital	—		—		2
Total sustaining capital expenditures	12		13		29
Productivity capital	1		1		—
Total sustaining and productivity capital	13		14		29

Hydro cash flow	96		61		53

(1) Alberta hydro PPA assets include 12 hydro facilities on the Bow and North Saskatchewan river systems included under the PPA legislation. Other hydro facilities include our hydro facilities in BC, Ontario and the hydro facilities in Alberta not included in the legislated PPAs.

(2) Ancillary services as described in the AESO Consolidated Authoritative Document Glossary.

(3) Capacity payments include the annual capacity charge as described in the Power Purchase Arrangements Determination Regulation AR 175/2000, available from Alberta Queen's Printer.

(4) Other revenue includes revenues from our non-PPA hydro facilities, our transmission business and other contractual arrangements including the flood mitigation agreement with the Alberta government and black start services.

2018

Production for 2018 decreased by 42 GWh over 2017 , primarily due to lower water resources.

Comparable EBITDA for 2018 increased $34 million compared to 2017 . Alberta Hydro benefited from stronger energy prices and a higher demand for Ancillary Services.

Hydro's cash flow improved by $35 million for 2018 , compared to 2017 , due mainly to higher comparable EBITDA.

TRANSALTA CORPORATION M 18

Management’s Discussion and Analysis

2017

Production for 2017 increased by 92 GWh compared to 2016, primarily due to stronger water resources from spring run-off during the first nine months of 2017 in Alberta.

However, comparable EBITDA for the year ended Dec. 31, 2017, decreased by $7 million compared to 2016, due to higher OM&A costs and a $3 million positive adjustment relating to a prior year metering issue at one of our facilities recorded in 2016.

Sustaining capital expenditures for 2017 decreased $16 million compared to 2016 due to lower expenditures on major overhauls. Life extension projects at Bighorn and Brazeau and flood recovery capital spend occurred in 2016.

Energy Marketing



Year ended Dec. 31	2018	2017		2016
Revenues and comparable gross margin	67	69		76
Operations, maintenance and administration	24	24		24
Comparable EBITDA	43	45		52
Deduct:
Provisions	3	(2	)	24
Unrealized gains (losses) on risk management activities	7	8		3
Energy Marketing cash flow	33	39		25

2018

Comparable EBITDA for 2018 remained fairly consistent with 2017 results, which was expected.

Energy Marketing's cash flows for 2018 decreased by $ 6 million compared to 2017 , mainly due to the settlement of trading positions adversely affected by cold weather in the first quarter and the removal of non-cash mark-to-market gains driven by a number of long-term trades that are expected to settle in 2019.

2017

Comparable EBITDA results were lower by $7 million compared to 2016, due to unfavourable first quarter of 2017 results impacted by warm winter weather in the Northeast, significant precipitation in the Pacific Northwest and reduced margins from our customer business.

Corporate

2018

Our Corporate overhead costs of $ 87 million were consistent in 2018 compared to 2017 as we realized benefits from cost-efficiency initiatives that were offset by the addition of the Supply Chain Management team, which will provide future cost savings by leveraging our buying power. Corporate cash flow also includes $ 20 million ( 2017 - $22 million) in sustaining and productivity capital spend.

2017

Our Corporate overhead costs of $85 million were $14 million higher for the year ended Dec. 31, 2017, compared to 2016 mostly due to higher annual incentive compensation and Project Greenlight initiative fees. See the Strategic Growth and Corporate Transformation section of this MD&A for further details. The first quarter of 2017 also includes the reclassification of incentives for 2016 between our operational segments and our Corporate segment.

TRANSALTA CORPORATION M 19

Management’s Discussion and Analysis

Key Financial Ratios

The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and ratios are not defined under IFRS and may not be comparable to those used by other entities or by rating agencies. We strengthened our financial position and flexibility and met most of our target ranges in 2018.

Funds from Operations before Interest to Adjusted Interest Coverage



As at Dec. 31	2018		2017	2016
FFO	927		804	734
Less: Early termination of the Sundance PPAs received during the first quarter of 2018	(157	)	—	—
Add: Interest on debt and finance leases, net of interest income and capitalized interest	174		205	203
FFO before interest	944		1,009	937
Interest on debt and finance leases, net of interest income	176		214	219
Add: 50 per cent of dividends paid on preferred shares	20		20	21
Adjusted interest	196		234	240
FFO before interest to adjusted interest coverage (times)	4.8		4.3	3.9

Our target for FFO before interest to adjusted interest coverage is four to five times. The ratio improved compared to 2017 due to lower interest on debt as we continued to execute our deleveraging plan.

Adjusted FFO to Adjusted Net Debt



As at Dec. 31	2018		2017		2016
FFO	927		804		734
Less: Early termination of the Sundance PPAs received during the first quarter of 2018	(157	)	—		—
Less: 50 per cent of dividends paid on preferred shares	(20	)	(20	)	(21	)
Adjusted FFO	750		784		713
Period-end long-term debt ⁽¹⁾	3,267		3,707		4,361
Less: Cash and cash equivalents	(89	)	(314	)	(305	)
Less: Principal portion of TransAlta OCP restricted cash	(27	)	—		—
Add: 50 per cent of issued preferred shares	471		471		471
Fair value asset of hedging instruments on debt ⁽²⁾	(10	)	(30	)	(163	)
Adjusted net debt	3,612		3,834		4,364
Adjusted FFO to adjusted net debt (%)	20.8		20.4		16.3

(1) Includes finance lease obligations and tax equity financing.

(2) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2018 , Dec. 31, 2017 , and Dec. 31, 2016 .

Our adjusted FFO to adjusted net debt of 20.8 per cent remained consistent with 2017 , as the significant reduction in our net debt was offset by a decline in adjusted FFO. We reached the low end of our target range of 20 to 25 per cent in 2017 and maintained that level in 2018.

TRANSALTA CORPORATION M 20

Management’s Discussion and Analysis

Adjusted Net Debt to Comparable EBITDA



As at Dec. 31	2018		2017		2016
Period-end long-term debt ⁽¹⁾	3,267		3,707		4,361
Less: Cash and cash equivalents	(89	)	(314	)	(305	)
Less: Principal portion of TransAlta OCP restricted cash	(27	)	—		—
Add: 50 per cent of issued preferred shares	471		471		471
Fair value asset of hedging instruments on debt ⁽²⁾	(10	)	(30	)	(163	)
Adjusted net debt	3,612		3,834		4,364
Comparable EBITDA	1,123		1,062		1,144
Less: Early termination of the Sundance PPAs received during the first quarter of 2018	(157	)	—		—
Adjusted comparable EBITDA	966		1,062		1,144
Adjusted net debt to comparable EBITDA (times)	3.7		3.6		3.8

(1) Includes finance lease obligations and tax equity financing.

(2) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2018 , Dec. 31, 2017 , and Dec. 31, 2016 .

Our adjusted net debt to comparable EBITDA ratio increased compared to 2017 , mainly due to the decrease in adjusted comparable EBITDA during the year, after adjusting for the payment for the early termination of the Sundance B and C PPAs. Our target for adjusted net debt to comparable EBITDA is 3.0 to 3.5 times.

Ability to Deliver Financial Results

The metrics we use to track our performance are comparable EBITDA, FFO and FCF. The following table compares target to actual amounts for each of the three past fiscal years:



Year ended Dec. 31		2018	2017	2016
Comparable EBITDA	Target ⁽¹⁾	1,000-1,050	1,025-1,100	990-1,100
	Actual	1,123	1,062	1,144
	Adjusted Actual ⁽²⁾	988	1,000	1,068
FFO	Target ⁽¹⁾	750-800	765-820	755-835
	Actual	927	804	734
	Adjusted Actual ⁽³⁾	770	770	734
FCF	Target ⁽¹⁾	300-350	270-310	250-300
	Actual	524	328	257
	Adjusted Actual ⁽³⁾	367	311	257

(1) Represents our revised outlook. As a result of strong performance in the first quarter of 2018, we revised the following 2018 targets: comparable EBITDA from the previously announced target range of $950 million to $1,050 million to $1,000 to $1,050 million, FFO from the target range of $725 million to $800 million to $750 million to $800 million FCF target range from $275 million to $350 million to the target range of$300 million to $350 million. In the second quarter of 2017 we reduced the following 2017 targets: Comparable EBITDA from target range of $1,025 million to $1,135 million to $1,025 to $1,100 million, FFO from the target range of $765 million to $855 million to $765 million to $820 million FCF target range from $300 million to $365 million to the target range of $270 million to $310 million.

(2) Comparable EBITDA for all periods was adjusted to remove the impact of unrealized mark-to-market gains or losses. Additionally, 2018 was adjusted to remove the $157 million for the termination of the Sundance B and C PPAs as this was not included in the target. 2017 was also adjusted to remove the $34 million related to the OEFC indexation dispute. 2016 was adjusted for the $80 million impact for non-cash adjustments related to the Keephills 1 provision.

(3) 2018 amounts were adjusted to remove the $157 million for the termination of the Sundance B and C PPAs as this was not included in the targets. 2017 amounts were adjusted to remove the OEFC indexation dispute: FFO was reduced by $34 million and FCF was reduced by $17 million.

TRANSALTA CORPORATION M 21

Management’s Discussion and Analysis

Significant and Subsequent Events

Transition to Clean Power in Alberta

Alberta Renewable Energy Program Project - Windrise

In the fourth quarter of 2018, TransAlta's 207 MW Windrise wind project was selected by the AESO as one of the two successful projects in the third round of the Renewable Electricity Program. The Windrise facility, which is in the county of Willow Creek, is underpinned by a 20-year Renewable Electricity Support Agreement with the AESO. The project is expected to cost approximately $ 270 million and is targeted to reach commercial operation during the second quarter of 2021.

Gas Supply for Coal-to-Gas Conversions

On Dec. 17, 2018, the Corporation exercised its option to acquire 50 per cent ownership in the Pioneer Pipeline. Tidewater will construct and operate the 120 km natural gas pipeline, which will have an initial throughput of 130 MMcf/d with the potential to expand to approximately 440 MMcf/d. The Pioneer Pipeline will allow TransAlta to increase the amount of natural gas it co-fires at its Sundance and Keephills coal-fired units, resulting in lower carbon emissions and costs. As well, the Pioneer Pipeline will provide a significant amount of the gas required for the full conversion of the coal units to natural gas. The investment for TransAlta will amount to approximately $90 million. Construction of the pipeline commenced in November 2018 and the Pioneer Pipeline is expected to be fully operational by the second half of 2019. TransAlta’s investment is subject to final regulatory approvals, which are expected to be finalized in the first half of 2019.

The decision to work with Tidewater advances the time frame for the construction of the Pioneer Pipeline and permits the acceleration of plant conversions. TransAlta remains of the view that having at least two pipelines supplying natural gas would reduce operational risks and continues to advance discussions with other parties to construct additional pipelines to meet the remaining gas supply requirements for the facilities.

Sundance and Keephills Units 1 and 2 Coal-to-Gas Conversion Strategy

On Dec. 6, 2017, the Corporation updated its strategy to accelerate its transition to gas and renewables generation. During 2018, the Corporation mothballed and retired the following Sundance Units:


▪	retired Sundance Unit 1 on Jan. 1, 2018;


▪	retired Sundance Unit 2 on July 31, 2018;


▪	temporarily mothballed Sundance Unit 3 on April 1, 2018, for a period of up to two years; and


▪	temporarily mothballed Sundance Unit 5 on April 1, 2018, for a period of up to one year, which has recently been extended to two years.

TransAlta is no longer planning to temporarily mothball Sundance Unit 4 and will perform maintenance during the first half of 2019.

On December 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity . The regulations provide rules for new gas-fired electricity facilities, as well as specific provisions for coal-to-gas conversions. In addition to extending their operating lives, the benefits of converting units to gas generation include: significantly lowering carbon emissions and costs; significantly lowering operating and sustaining capital costs; and increasing operating flexibility. TransAlta expects to convert its Sundance Units 3 to 6 and Keephills Units 1 to 3 in the 2020 to 2023 time frame.

Sundance Units 1 and 2

Canadian federal regulations stipulate that all coal plants built before 1975 must cease to operate on coal by the end of 2019, which includes Sundance Units 1 and 2. Given that Sundance Unit 1 was shut down two years early, the federal Minister of Environment and Climate Change agreed to extend the life of Sundance Unit 2 from 2019 to 2021. This provided the Corporation with the flexibility to respond to the regulatory environment for coal-to-gas conversions and the new upcoming Alberta capacity market. However, in July 2018, TransAlta retired Sundance Unit 2. This decision was driven largely by Sundance Unit 2's age, size and short useful life relative to other units, and the capital requirements needed to return the unit to service.

Sundance Units 1 and 2 collectively made up 560 MW of the 2,141 MW capacity of the Sundance power plant, which served as a baseload provider for the Alberta electricity system. The PPA with the Balancing Pool relating to Sundance Units 1 and 2 expired on Dec. 31, 2017.

TRANSALTA CORPORATION M 22

Management’s Discussion and Analysis

In the third quarter of 2018, the Corporation recognized an impairment charge of $38 million ($28 million after-tax) relating to the retirement of Sundance Unit 2. During the second quarter of 2017, the Corporation recognized an impairment charge on Sundance Unit 1 of $20 million ($15 million after-tax) due to the Corporation’s decision to early retire Sundance Unit 1.

Kent Hills 3 Wind Project

During 2017, a subsidiary of TransAlta Renewables Inc., Kent Hills Wind LP ("KHWLP"), entered into a long-term contract with New Brunswick Power Corporation (“NB Power”) for the sale of all power generated by an additional 17.25 MW of capacity from the Kent Hills 3 expansion wind project. At the same time, the term of the Kent Hills 1 contract with NB Power was extended from 2033 to 2035, matching the life of the Kent Hills 2 and Kent Hills 3 wind projects.

On Oct. 19, 2018, TransAlta Renewables announced that the expansion was fully operational, bringing the total generating capacity of the Kent Hills wind farm to 167 MW.

Acquisition of Two US Wind Projects

On Feb. 20, 2018, TransAlta Renewables announced it had entered into an arrangement to acquire two construction-ready projects in the Northeastern United States. The wind development projects consist of: i) a 90 MW project located in Pennsylvania that has a 15-year PPA with Microsoft Corp. ("Big Level"), and ii) a 29 MW project located in New Hampshire with two 20-year PPAs ("Antrim") (collectively, the "US Wind Projects"), with counterparties that have Standard & Poor's credit ratings of A+ or better. The commercial operation date for both projects is expected during the second half of 2019. A subsidiary of TransAlta acquired Big Level on Feb. 20, 2018, whereas the acquisition of Antrim remains subject to certain closing conditions, including the receipt of a favourable regulatory ruling. The Corporation expects the Antrim acquisition to close in early 2019.

On April 20, 2018, TransAlta Renewables completed the acquisition of an economic interest in the US Wind Projects from a subsidiary of TransAlta (“TA Power”). Pursuant to the arrangement, a TransAlta subsidiary owns the US Wind Projects directly and TA Power issued to TransAlta Renewables tracking preferred shares that pay quarterly dividends based on the pre-tax net earnings of the US Wind Projects. The tracking preferred shares have preference over the common shares of TA Power held by TransAlta, in respect of dividends and the distribution of assets in the event of the liquidation, dissolution or winding-up of TA Power. The construction and acquisition costs of the two US Wind Projects are expected to be funded by TransAlta Renewables and a $25 million promissory note receivable and are estimated to be US$240 million. TransAlta Renewables will fund these costs either by acquiring additional preferred shares issued by TA Power or by subscribing for interest-bearing notes issued by the project entity. The proceeds from the issuance of such preferred shares or notes will be used exclusively in connection with the acquisition and construction of the US Wind Projects. TransAlta Renewables expects to fund these acquisition and construction costs using its existing liquidity and tax equity.

During the year ended Dec. 31, 2018 , TransAlta Renewables funded approximately $61 million (US$48 million) of construction costs for Big Level. On Jan. 2, 2019, TransAlta Renewables funded an additional $45 million (US$33 million) of construction costs.

TransAlta Renewables Acquires Three Renewable Assets from the Corporation

On May 31, 2018, TransAlta Renewables acquired from a subsidiary of the Corporation an economic interest in the 50 MW Lakeswind wind farm in Minnesota and 21 MW of solar projects located in Massachusetts ("Mass Solar") through the subscription of tracking preferred shares of a subsidiary of the Corporation. In addition, TransAlta Renewables acquired from a subsidiary of the Corporation ownership of the 20 MW Kent Breeze wind farm located in Ontario. The total purchase price for the three assets was approximately $166 million, including the assumption of $62 million of tax equity obligations and project debt, for net cash consideration of $104 million. The Corporation continues to operate these assets on behalf of TransAlta Renewables.

On June 28, 2018, TransAlta Renewables subscribed for an additional $33 million of tracking preferred shares of a subsidiary of the Corporation related to Mass Solar, in order to fund the repayment of Mass Solar's project debt.

In connection with these acquisitions, the Corporation recorded a $12 million impairment charge, of which $11 million was recorded against property, plant and equipment ("PP&E") and $1 million against intangibles.

TransAlta Renewables Closes $150 Million Offering of Common Shares

On June 22, 2018, TransAlta Renewables closed a bought deal offering of 11,860,000 common shares through a syndicate of underwriters. The common shares were issued at a price of $12.65 per common share for gross proceeds of approximately $150 million ($144 million of net proceeds).

TRANSALTA CORPORATION M 23

Management’s Discussion and Analysis

The net proceeds were used to partially repay drawn amounts under TransAlta Renewables' credit facility, which was drawn in order to fund recent acquisitions. The additional liquidity under the credit facility is to be used for general corporate purposes, including ongoing construction costs associated with the US Wind Projects, described above.

The Corporation did not purchase any additional common shares under the offering and, following the closing, owned 161 million common shares, representing approximately 61 per cent of the outstanding common shares of TransAlta Renewables.

$345 Million Financing

On July 20, 2018, the Corporation monetized the payments under the OCA with the Government of Alberta by closing a $345 million bond offering through its indirect wholly owned subsidiary, TransAlta OCP LP ("TransAlta OCP"). The offering was a private placement that was secured by, among other things, a first ranking charge over the OCA payments payable by the Government of Alberta. The amortizing bonds bear interest at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030. The bonds have a rating of BBB, with a stable trend, by DBRS. Under the terms of the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million , net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030. The net proceeds were used to partially repay the 6.40 per cent debentures, as described below.

Early Redemption of $400 million of Debentures

On Aug. 2, 2018, the Corporation early redeemed all of its then outstanding 6.40 per cent debentures, due Nov. 18, 2019, for the principal amount of $400 million . The redemption price was approximately $425 million in aggregate, including a prepayment premium and accrued and unpaid interest.

Normal Course Issuer Bid

On March 9, 2018 the Corporation announced that the Toronto Stock Exchange ("TSX") accepted the notice filed by the Corporation to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, the Corporation may repurchase up to a maximum of 14,000,000 common shares, representing approximately 4.86 per cent of issued and outstanding common shares as at March 2, 2018. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.

The period during which TransAlta is authorized to make purchases under the NCIB commenced on March 14, 2018, and ends on March 13, 2019, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Corporation's election.

Under TSX rules, not more than 102,039 common shares (being 25 per cent of the average daily trading volume on the TSX of 408,156 common shares for the six months ended February 28, 2018) can be purchased on the TSX on any single trading day under the NCIB, with the exception that one block purchase in excess of the daily maximum is permitted per calendar week.

During the year ended Dec. 31, 2018 , the Corporation purchased and cancelled 3,264,500 common shares at an average price of $ 7.02 per common share, for a total cost of $ 23 million . Further transactions under the NCIB, if any, will depend on market conditions. The Corporation retains discretion whether to make purchases under the NCIB, and to determine the timing, amount and acceptable price of any such purchases, subject at all times to applicable TSX and other regulatory requirements.

Early Redemption of Senior Notes

On March 15, 2018, the Corporation early redeemed all of its outstanding 6.650 per cent US $500 million senior notes due May 15, 2018, for approximately $617 million (US$516 million). A $5 million early redemption premium was recognized in net interest expense for the three months ended March 31, 2018.

Management and Board of Directors Changes

Donald Tremblay, the former Chief Financial Officer ("CFO"), left the Corporation, effective May 9, 2018. Brett Gellner, Chief Strategy and Investment Officer, acted as Interim CFO, in addition to his current role, during the interim period.

During the fourth quarter of 2018, we appointed Christophe Dehout as our CFO. Mr. Dehout brings broad experience in power generation and extensive knowledge of capital markets, mergers and acquisitions, corporate finance and corporate transformations.

TRANSALTA CORPORATION M 24

Management’s Discussion and Analysis

On January 25, 2019, we announced the retirement decisions of Timothy Faithfull and Ambassador Gordon Giffin. Earlier in 2018, Mr. Faithfull had indicated to the Board his intention to retire from the Board of Directors immediately following TransAlta's 2019 Annual Shareholders Meeting and, also in 2018, Ambassador Gordon Giffin announced his intention to retire as director and Board Chair in 2020. The Board is undertaking a process to identify a new Chair through the course of 2019.

Balancing Pool Provides Notice to Terminate the Alberta Sundance Power Purchase Arrangements

On Sept. 18, 2017, the Corporation received formal notice from the Balancing Pool for the termination of the Sundance B and C PPAs effective March 31, 2018.

The termination of the Sundance B and C PPAs by the Balancing Pool was expected and the Corporation is working to ensure it receives the termination payment that it believes it is entitled to under the Sundance B and C PPAs and applicable legislation. The Balancing Pool paid the Corporation approximately $157 million on March 29, 2018, as part of the net book value payment required on termination of the Sundance B and C PPAs. The Balancing Pool, however, excluded certain mining and corporate assets that the Corporation believes should be included in the net book value calculation, which amounts to an additional $56 million. The dispute is currently proceeding through arbitration.

Please refer to Note 4 of the audited annual 2018 consolidated financial statements for significant events impacting prior year results.

TRANSALTA CORPORATION M 25

Management’s Discussion and Analysis

Financial Position

The following chart highlights significant changes in the Consolidated Statements of Financial Position from Dec. 31, 2017 , to Dec. 31, 2018 :



	Increase/
Assets	(decrease)		Primary factors explaining change
Cash and cash equivalents	(225	)	Timing of receipts and payments.
Restricted cash (current & long-term)	36		Restricted cash related to the TransAlta OCP bonds ($35 million)
Trade and other receivables	(177	)	Timing of customer receipts, collection of Mississauga recontracting receivable ($108 million), partially offset by the Antrim promissory note receivable ($25 million)
Inventory	23		Increase in Canadian Coal ($50 million) partially offset by a reduction in purchased emission credits ($13 million) and a reduction in parts and materials inventory ($5 million)
Finance lease receivables (long term)	(24	)	Principal repayments
Property, plant, and equipment, net	(414	)	Depreciation for the period ($649 million), revisions to decommissioning and restoration costs ($32 million) and asset impairments ($49 million), partially offset by additions ($294 million) and favourable changes in foreign exchange rates ($39 million)
Intangible assets	9		Additions of ($53 million) and net transfers from PP&E ($6 million), partially offset by amortization ($50 million)
Risk management assets (current and long term)	(95	)	Contract settlements and unfavourable market price movements, partially offset by favourable changes in foreign exchange rates
Other	(9	)
Total change in assets	(876	)

	Increase/
Liabilities and equity	(decrease)		Primary factors explaining change
Accounts payable and accrued liabilities	(98	)	Timing of payments and accruals
Income taxes payable	(54	)	Primarily due to the payment of taxes on FMG's repurchase of the Solomon Power Station
Credit facilities, long term debt, and finance lease obligations (including current portion)	(440	)	Repayment of long-term debt ($1,179 million), partially offset by drawings on the credit facility ($312 million), long-term debt issued ($345 million) and unfavourable changes in foreign exchange ($95 million)
Decommissioning and other provisions (current and long term)	(14	)	Liabilities settled ($41 million) and an increase in risk-adjusted discount rates ($37 million), partially offset by accretion ($24 million), new liabilities incurred ($22 million), remaining payment for Big Level acquisition ($8 million) and unfavourable changes in foreign exchange ($10 million)
Contract liabilities	25		Increased due to IFRS 15 transition adjustment ($17 million), consideration received ($13 million) and interest accrued and expensed during the period ($6 million), partially offset by transfers to revenue ($10 million)
Defined benefit obligation and other long term liabilities	(10	)	Decrease in the defined benefit obligation ($8 million) and reduced employee incentive plan liability ($7 million), partially offset by increased other long-term liabilities ($5 million)
Deferred income tax liabilities	(48	)	Decrease in taxable temporary differences
Equity attributable to shareholders	(329	)	Net loss ($198 million), net other comprehensive loss ($12 million) common share dividends ($57 million), preferred share dividends ($50 million), shares purchased under NCIB ($23 million), impact of changes in our accounting policies ($14 million), partially offset by changes in non-controlling interests in TransAlta Renewables ($24 million)
Non-controlling interests	78		Net earnings ($108 million), changes in non-controlling interests in TransAlta Renewables from share issuance ($133 million) and intercompany FVOCI investments ($16 million), partially offset by distributions paid and payable ($180 million)
Other	14
Total change in liabilities and equity	(876	)

TRANSALTA CORPORATION M 26

Management’s Discussion and Analysis

Cash Flows

The following chart highlights significant changes in the Consolidated Statements of Cash Flows for the years ended Dec. 31, 2017 , and Dec. 31, 2016 , compared to the year ended Dec. 31, 2018 :



Year ended Dec. 31	2018		2017		Increase/ (decrease)		Primary factors explaining change
Cash and cash equivalents, beginning of year	314		305		9
Provided by (used in):
Operating activities	820		626		194		Higher cash flow from operations before working capital ($124 million) and a favourable change in non-cash working capital ($70 million)
Investing activities	(394	)	87		(481	)	Lower proceeds on sale of Wintering Hills wind facility and Solomon ($476 million), unfavourable change in non-cash investing capital ($153 million) and the acquisition of Big Level and Antrim ($30 million), partially offset by lower additions to property, plant, and equipment ($63 million), lower tax expense relating to investing activities ($56 million), lower additions to intangibles ($31 million), and the lower issuance of loan receivable ($39 million)
Financing activities	(651	)	(703	)	52		Increase in borrowings under credit facilities ($286 million), higher issuance of long-term debt ($85 million), and higher proceeds on the sale of non-controlling interest in a subsidiary ($144 million), partially offset by higher repayments of long-term debt ($365 million), lower realized gains on financial instruments ($58 million) and repurchase of common shares ($23 million)
Translation of foreign currency cash	—		(1	)	1
Cash and cash equivalents, end of year	89		314		(225	)

Year ended Dec. 31	2017		2016		Increase/ (decrease)		Primary factors explaining change
Cash and cash equivalents, beginning of year	305		54		251
Provided by (used in):
Operating activities	626		744		(118	)	Unfavourable change in non-cash working capital of ($187 million), partially offset by higher cash earnings ($69 million)
Investing activities	87		(327	)	414		Proceeds on sale of Wintering Hills wind facility and Solomon power station disposition ($478 million), net loan receivable ($38 million), and restricted cash ($30 million)
Financing activities	(703	)	(163	)	(540	)	Higher repayment of long-term debt ($726 million), lower issuance of long-term debt ($101 million), and lower proceeds on sale of non-controlling interest in subsidiary ($162 million), partially offset by lower borrowings under credit facility ($341 million), higher realized gains on financial instruments ($108 million), and lower dividends paid on common shares ($23 million)
Translation of foreign currency cash	(1	)	(3	)	2
Cash and cash equivalents, end of year	314		305		9

Financial Instruments

Financial instruments are used for proprietary trading purposes and to manage our exposure to interest rates, commodity prices, and currency fluctuations, as well as other market risks. We may currently use physical and financial swaps, forward sale and purchase contracts, futures contracts, foreign exchange contracts, interest rate swaps, and options to achieve our risk management objectives. Some of our physical commodity contracts have been entered into and are held for the purposes of meeting our expected purchase, sale, or usage requirements (“own use”) and as such, are not considered financial instruments and are not recognized as a financial asset or financial liability. Other physical commodity contracts that are not held for normal purchase or sale requirements and derivative financial instruments are recognized on the Consolidated Statements of Financial Position and are accounted for using the fair value method of accounting. The initial

TRANSALTA CORPORATION M 27

Management’s Discussion and Analysis

recognition of fair value and subsequent changes in fair value can affect reported earnings in the period the change occurs if hedge accounting is not elected. Otherwise, changes in fair value will generally not affect earnings until the financial instrument is settled.

Some of our financial instruments and physical commodity contracts qualify for, and are recorded under, hedge accounting rules. The accounting for those contracts for which we have elected to apply hedge accounting depends on the type of hedge. Our financial instruments are mainly used for cash flow hedges or non-hedges. These categories and their associated accounting treatments are explained in further detail below.

For all types of hedges, we test for effectiveness at the end of each reporting period to determine if the instruments are performing as intended and hedge accounting can still be applied. The financial instruments we enter into are designed to ensure that future cash inflows and outflows are predictable. In a hedging relationship, the effective portion of the change in the fair value of the hedging derivative does not impact net earnings, while any ineffective portion is recognized in net earnings.

We have certain contracts in our portfolio that, at their inception, do not qualify for, or we have chosen not to elect to apply, hedge accounting. For these contracts, we recognize in net earnings mark-to-market gains and losses resulting from changes in forward prices compared to the price at which these contracts were transacted. These changes in price alter the timing of earnings recognition, but do not necessarily determine the final settlement amount received. The fair value of future contracts will continue to fluctuate as market prices change.

The fair value of derivatives that are not traded on an active exchange, or extend beyond the time period for which exchange-based quotes are available, are determined using valuation techniques or models.

Cash Flow Hedges

Cash flow hedges are categorized as project, foreign exchange, interest rate, or commodity hedges and are used to offset foreign exchange, interest rate, and commodity price exposures resulting from market fluctuations.

Foreign currency forward contracts may be used to hedge foreign exchange exposures resulting from anticipated contracts and firm commitments denominated in foreign currencies, primarily related to capital expenditures, and currency exposures related to US-denominated debt.

Physical and financial swaps, forward sale and purchase contracts, futures contracts, and options may be used primarily to offset the variability in future cash flows caused by fluctuations in electricity and natural gas prices. Foreign exchange forward contracts and cross-currency swaps may be used to offset the exposures resulting from foreign-denominated long-term debt. Interest rate swaps may be used to convert the fixed interest cash flows related to interest expense at debt to floating rates and vice versa.

In a cash flow hedge, changes in the fair value of the hedging instrument (a forward contract or financial swap, for example) are recognized in risk management assets or liabilities, and the related gains or losses are recognized in other comprehensive income ("OCI"). These gains or losses are subsequently reclassified from OCI to net earnings in the same period as the hedged forecast cash flows impact net earnings, and offset the losses or gains arising from the forecast transactions. For project hedges, the gains and losses reclassified from OCI are included in the carrying amount of the related PP&E.

Under IFRS 9, which we adopted on Jan. 1, 2018, hedge accounting requirements were simplified, to introduce a more principles based approach for qualifying hedges, aligned with an entity's approach to risk management, and to revise and simplify the hedge effectiveness requirements.

When we do not elect hedge accounting or when the hedge is no longer effective and does not qualify for hedge accounting, the gains or losses as a result of changes in prices, interest, or exchange rates related to these financial instruments are recorded in net earnings in the period in which they arise.

Net Investment Hedges

Foreign-denominated long-term debt is used to hedge exposure to changes in the carrying values of our net investments in foreign operations that have a functional currency other than the Canadian dollar. Our net investment hedges using US-denominated debt remain effective and in place. Gains or losses on these instruments are recognized and deferred in OCI and reclassified to net earnings on the disposal of the foreign operation. We also manage foreign exchange risk by matching

TRANSALTA CORPORATION M 28

Management’s Discussion and Analysis

foreign-denominated expenses with revenues, such as offsetting revenues from our US operations with interest payments on our US dollar debt.

Non-Hedges

Financial instruments not designated as hedges are used for proprietary trading and to reduce commodity price, foreign exchange, and interest rate risks. Changes in the fair value of financial instruments not designated as hedges are recognized in risk management assets or liabilities, and the related gains or losses are recognized in net earnings in the period in which the change occurs.

Fair Values

The majority of fair values for our project, foreign exchange, interest rate, commodity hedges, and non-hedge derivatives are calculated using adjusted quoted prices from an active market or inputs validated by broker quotes. We may enter into commodity transactions involving non-standard features for which market-observable data is not available. These transactions are defined under IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable from the market, and fair value is therefore determined using valuation techniques. Fair values are validated by using reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in the notes to the consolidated financial statements. At Dec. 31, 2018 , Level III instruments had a net asset carrying value of $ 695 million ( 2017 - $ 771 million ). Refer to the Critical Accounting Policies and Estimates section of this MD&A for further details regarding valuation techniques. Our risk management profile and practices have not changed materially from Dec. 31, 2017 .

2019 Financial Outlook

The following table outlines our expectation on key financial targets and related assumptions for 2019 :



Measure	Target
Comparable EBITDA	$875 million to $975 million
FCF	$270 million to $330 million
Dividend	$0.16 per share annualized, 14 to 17 per cent payout of FCF



Range of key power price assumptions
Market	Power Prices ($/MWh)
Alberta Spot	$50 to $60
Alberta Contracted	$50 to $55
Mid-C Spot (US$)	$20 to $25
Mid-C Contracted (US$)	$47 to $53



Other assumptions relevant to 2019 financial outlook
Sustaining Capital	$160 million to $190 million
Productivity Capital	$10 million to $15 million
Sundance coal capacity factor	30%
Hydro/ Wind Resource	Long term average

Operations

Availability and Capacity

Availability of our coal fleet is expected to be in the range of 87 to 89 per cent in 2019 . Availability of our other generating assets (gas, renewables) is expected to be in the range of 92 to 96 per cent in 2019 . We will be accelerating our transition to gas and renewables generation, and continue on our coal-to-gas conversion strategy as set out in the Significant and Subsequent Events section of this MD&A.

Market Pricing and Hedging Strategy

For 2019 , power prices in Alberta are expected to be slightly higher than 2018 due to a full year of lower supply as a result of the mothballing and shutdown of certain coal-fired units in 2018. Pacific Northwest power prices for 2019 are expected to be lower than 2018 as 2018 prices were impacted by specific events that are not expected to occur in the future. Ontario power prices are expected to remain consistent with 2018 prices.

TRANSALTA CORPORATION M 29

Management’s Discussion and Analysis

The objective of our portfolio management strategy is to deliver a high confidence for annual FCF which also provides for positive exposure to price volatility in Alberta. Given our cash operating costs, we can be more or less hedged in a given period, and we expect to realize our annual FCF targets through a combination of forward hedging and selling generation into the spot market.

Fuel Costs

In Alberta, we expect the 2019 cash fuel costs for coal to be slightly lower than the 2018 costs and total fuel costs to be lower due to increased co-firing with natural gas among the merchant units.

In the Pacific Northwest, our US Coal mine, adjacent to our power plant, is in the reclamation stage. Fuel at US Coal has been purchased primarily from external suppliers in the Powder River Basin and delivered by rail. In 2017 we amended our fuel and rail contract such that our costs fluctuate partly with gas prices. The delivered fuel cost in 2019 is expected to be consistent with 2018 costs.

Most of our generation from gas is sold under contracts with pass-through provisions for fuel. For gas generation with no pass-through provisions, we purchase natural gas from outside companies coincident with production, thereby minimizing our risk to changes in prices.

We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risks.

Energy Marketing

EBITDA from our Energy Marketing segment is affected by prices and volatility in the market, overall strategies adopted, and changes in regulation and legislation. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our 2019 objective for Energy Marketing is for the segment to contribute between $75 million to $85 million in gross margin for the year.

Exposure to Fluctuations in Foreign Currencies

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the US dollar, and Australian dollar by offsetting foreign-denominated assets with foreign-denominated liabilities and by entering into foreign exchange contracts. We also have foreign-denominated expenses, including interest charges, which largely offset our net foreign-denominated revenues.

Net Interest Expense

Net interest expense for 2019 is expected to be lower than in 2018 largely due to lower levels of debt. However, changes in interest rates and in the value of the Canadian dollar relative to the US dollar can affect the amount of net interest expense incurred. In addition, interest expense will increase as a result of implementing IFRS 16. See the Accounting Changes section of this MD&A for further details.

Liquidity and Capital Resources

We expect to maintain adequate available liquidity under our committed credit facilities. We currently have access to $ 1.0 billion in liquidity including $89 million in cash. Our continued focus will be toward repositioning our capital structure and we expect to be well positioned to address the upcoming debt maturity in 2020 .

TRANSALTA CORPORATION M 30

Management’s Discussion and Analysis

Capital Expenditures

Our major projects are focused on sustaining our current operations and supporting our growth strategy in our renewables platform.

A summary of the significant growth and major projects that are in progress is outlined below:



	Total project		2019	Target completion date
	Estimated spend	Spent to date ⁽¹⁾	Estimated spend	Target completion date	Details
Project
Big Level wind development project ⁽²⁾	214	84	130	Q3 2019	90 MW wind project with a 15-year PPA
Antrim wind development project ⁽³⁾	97	25	72	Q3 2019	29 MW wind project with two 20-year PPAs
Pioneer gas pipeline partnership	90	15	75	Q4 2019	50 per cent ownership in the 120 km natural gas pipeline to supply gas to Sundance and Keephills
Windrise wind development project	270	—	47	Q2 2021	207 MW wind project with a 20-year Renewable Electricity Support Agreement with AESO
Total	671	124	324

(1) Represents amounts spent as of Dec. 31, 2018 .

(2) The numbers reflected above are in CAD but the actual cash spend on this project is in USD and therefore these amounts will fluctuate with changes in foreign exchange rates. The estimated total spend is USD$165 million, spent to date is USD$65 million and estimated total spend in 2019 is USD$100 million. TransAlta Renewables will fund the construction costs using its existing liquidity and tax equity.

(3) The numbers reflected above are in CAD but the actual cash spend on this project is in USD and therefore these amounts will fluctuate with changes in foreign exchange rates. The estimated total spend is USD$75 million, spent to date is USD$19 million and expected total spend in 2019 is USD$56 million. TransAlta Renewables will fund the acquisition and construction costs using its existing liquidity and tax equity. The project remains subject to certain closing conditions, including the receipt of a favourable regulatory ruling.

A significant portion of our sustaining and productivity capital is planned major maintenance, which includes inspection, repair and maintenance of existing components, and the replacement of existing components. Planned major maintenance costs are capitalized as part of PP&E and are amortized on a straight-line basis over the term until the next major maintenance event. It excludes amounts for day-to-day routine maintenance, unplanned maintenance activities, and minor inspections and overhauls, which are expensed as incurred.

Our estimate for total sustaining and productivity capital is allocated among the following:



Category	Description	Spent in 2017	Spent in 2018		Expected spend in 2019
Routine capital ⁽¹⁾	Capital required to maintain our existing generating capacity	69	50		50 - 60
Planned major maintenance	Regularly scheduled major maintenance	121	58		70 - 80
Mine capital	Capital related to mining equipment and land purchases	28	42		20 - 25
Finance leases	Payments on finance leases	17	18		20 - 25
Total sustaining capital		235	168		160 - 190
Insurance recoveries of sustaining capital expenditures	Insurance proceeds related to the fire at Wyoming Wind and Canadian Coal equipment	—	(7	)	—
Total sustaining capital		235	161		160 - 190
Productivity capital	Projects to improve power production efficiency and corporate improvement initiatives	24	21		10 - 15
Total sustaining and productivity capital		259	182		170 - 205

(1) Includes hydro life extension expenditures.

Significant planned major outages at TransAlta's operated units for 2019 include the following:


▪	two outages for major maintenance at Keephills Unit 1 and Sundance Unit 4 within our Canadian Coal segment during Q1 and Q2 2019;


▪	one major outage in our Canadian Gas segment related to our Sarnia facility during Q2 2019;


▪	distributed planned maintenance expenditures across the entire Hydro fleet; and


▪	distributed expenditures across our wind fleet, focusing on planned component replacements.

TRANSALTA CORPORATION M 31

Management’s Discussion and Analysis

Lost production as a result of planned major maintenance, excluding planned major maintenance for US Coal, which is scheduled during a period of dispatch optimization, is estimated as follows for 2019 :



	Coal	Gas and renewables	Total
GWh lost	500 - 550	400 - 450	900 - 1,000

Funding of Capital Expenditures

Funding for these planned capital expenditures is expected to be provided by cash flow from operating activities and existing liquidity. We have access to approximately $ 1.0 billion in liquidity, if required. The funds required for committed growth, sustaining capital, and productivity projects are not expected to be significantly impacted by the current economic environment.

Other Consolidated Analysis

Asset Impairment Charges and Reversals

As part of our monitoring controls, long-range forecasts are prepared for each Cash Generating Unit (“CGU”). The long-range forecast estimates are used to assess the significance of potential indicators of impairment and provide a criteria to evaluate adverse changes in operations. When indicators of impairment are present, we estimate a recoverable amount for each CGU by calculating an approximate fair value less costs of disposal using discounted cash flow projections based on the Corporation’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to our long-range forecast, including changes to fuel costs, operating costs, capital expenditures, external power prices, and useful lives of the assets.

Alberta Merchant CGU

During 2018 , 2017 , and 2016 , uncertainty continued to exist within the province of Alberta regarding the Government's Climate Leadership Plan, the future design parameters of the Alberta electricity market, and federal policies on the carbon levy and GHG emissions. Economic conditions also contributed to continued oversupply conditions and depressed market prices throughout 2015 to 2017. The Corporation assessed whether these factors, and events arising during the latter part of 2016, which are more fully discussed below, presented an indicator of impairment for its Alberta Merchant CGU. In consideration of the composition of this CGU, the Corporation determined that no indicators of impairment were present with respect to the Alberta Merchant CGU. Due to this determination, the Corporation did not perform an in-depth impairment analysis for any of these years, but for all years, a sensitivity analysis associated with these factors was performed to confirm the continued existence of adequate excess of estimated recoverable amount over book value. This analysis of the Alberta Merchant CGU continued to demonstrate a substantial cushion at the Alberta Merchant CGU in each of 2018 , 2017 , and 2016 , due to the Corporation’s large merchant renewable fleet in the province.

2018

Sundance Unit 2

In the third quarter of 2018, the Corporation recognized an impairment charge on Sundance Unit 2 in the amount of $38 million , due to the Corporation’s decision to retire Sundance Unit 2. Previously, the Corporation had expected Sundance Unit 2 to remain mothballed for a period of up to two years and therefore remain within the Alberta Merchant CGU where significant cushion exists. The impairment assessment was based on value in use and included the estimated future cash flows expected to be derived from the Unit until its retirement on July 31, 2018. Discounting did not have a material impact.

Lakeswind and Kent Breeze

On May 31, 2018, TransAlta Renewables acquired an economic interest in Lakeswind through the subscription of tracking preferred shares of a subsidiary of the Corporation and also purchased Kent Breeze. In connection with these acquisitions, the assets were fair valued using discount rates that average approximately 7 per cent. Accordingly, the Corporation has recorded an impairment charge of $12 million using the valuation in the agreement as the indicator of fair value less cost of disposal in 2018. The impairment charge had an $11 million impact on PP&E, and a $1 million impact on Intangible assets.

2017

Sundance Unit 1

In the second quarter of 2017, the Corporation recognized an impairment charge on Sundance Unit 1 in the amount of $20 million , due to the Corporation’s decision to early retire Sundance Unit 1. Previously, the Corporation had expected Sundance Unit 1 to operate in the merchant market in 2018 and 2019 and therefore remain within the Alberta Merchant CGU where significant cushion exists. The impairment assessment was based on value in use and included the estimated

TRANSALTA CORPORATION M 32

Management’s Discussion and Analysis

future cash flows expected to be derived from the Unit until its retirement on Jan. 1, 2018. Discounting did not have a material impact.

No separate stand-alone impairment test was required for Sundance Unit 2, as mothballing the Unit maintained the Corporation’s flexibility to operate the Unit as part of the Corporation’s Alberta Merchant CGU to 2021.

2016

Wintering Hills

On Jan. 26, 2017, the Corporation announced the sale of its 51 per cent interest in the Wintering Hills merchant wind facility for approximately $61 million . In connection with this sale, the Wintering Hills assets were accounted for as held for sale at Dec. 31, 2016. As required, the Corporation assessed the assets for impairment prior to classifying them as held for sale. Accordingly, the Corporation has recorded an impairment charge of $28 million using the purchase price in the sale agreement as the indicator of fair value less cost of disposal in 2016.

Project Development Costs

During 2018, the Corporation wrote-off $23 million in project development costs related to projects that are no longer proceeding.

Unconsolidated Structured Entities or Arrangements

Disclosure is required of all unconsolidated structured entities or arrangements such as transactions, agreements, or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities, or variable interest entities that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. We currently have no such unconsolidated structured entities or arrangements.

Guarantee Contracts

We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, construction projects, and purchase obligations. At Dec. 31, 2018 , we provided letters of credit totaling $720 million ( 2017 - $677 million ) and cash collateral of $105 million ( 2017 - $67 million). These letters of credit and cash collateral secure certain amounts included on our Consolidated Statements of Financial Position under risk management liabilities and decommissioning and other provisions.

Commitments

Contractual commitments are as follows:



	2019	2020	2021	2022	2023	2024 and thereafter	Total
Natural gas, transportation, and other purchase contracts	28	15	13	11	12	157	236
Transmission	9	10	6	4	3	—	32
Coal supply and mining agreements ⁽¹⁾	158	160	27	24	24	95	488
Long-term service agreements	64	86	32	17	8	34	241
Non-cancellable operating leases ⁽²⁾	8	8	8	7	4	45	80
Long-term debt ⁽³⁾	130	486	91	947	141	1,439	3,234
Principal payments on finance lease obligations	18	16	9	5	5	10	63
Interest on long-term debt and finance lease obligations ⁽⁴⁾	161	152	129	123	84	694	1,343
Growth	324	79	144	—	—	—	547
TransAlta Energy Transition Bill	6	7	6	6	6	—	31
Total	906	1,019	465	1,144	287	2,474	6,295

(1) Commitments related to Sheerness and Genesee 3 may be impacted by the cessation of coal-fired emissions on or before Dec. 31, 2030.

(2) Includes amounts under certain evergreen contracts on the assumption of the Corporation’s continued operations.

(3) Excludes impact of derivatives.

(4) Interest on long-term debt is based on debt currently in place with no assumption as to refinancing on maturity.

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Management’s Discussion and Analysis

As part of the TransAlta Energy Transition Bill signed into law in the State of Washington and the subsequent Memorandum of Agreement ("MoA"), we have committed to fund US $55 million in total over the remaining life of the US Coal plant to support economic and community development, promote energy efficiency, and develop energy technologies related to the improvement of the environment. The MoA contains certain provisions for termination and in the event of the termination and certain circumstances, this funding or part thereof would no longer be required. As at Dec. 31, 2018, the Corporation has funded approximately US$ 33 million of the commitment.

Contingencies

Line Loss Rule Proceeding

TransAlta has been participating in a line loss rule proceeding before the Alberta Utilities Commission ("AUC"). The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed the AESO to, among other things, perform such retroactive calculations. The various decisions by the AUC are, however, subject to appeal and challenge. A recent decision by the AUC determined the methodology to be used retroactively and it is now possible to estimate the total retroactive potential exposure faced by TransAlta for its non-PPA MWs. The current estimate of exposure based on known data is $15 million and therefore the Corporation increased the provision from $7.5 million to $15 million in 2018.

FMG Disputes

The Corporation is currently engaged in two disputes with FMG. The first arose as a result of FMG’s purported termination of the South Hedland PPA. TransAlta has sued FMG, seeking payment of amounts invoiced and not paid under the South Hedland PPA, as well as a declaration that the PPA is valid and in force. FMG, on the other hand, seeks a declaration that the PPA was lawfully terminated.

The second matter involves FMG’s claims against TransAlta related to the transfer of the Solomon Power Station to FMG. FMG claims certain amounts related to the condition of the facility while TransAlta claims certain outstanding costs that should be reimbursed.

Balancing Pool Dispute

Pursuant to a written agreement, the Balancing Pool paid the Corporation approximately $157 million on March 29, 2018 as part of the net book value payment required on termination of the Sundance B and C PPAs. The Balancing Pool, however, excluded certain mining and corporate assets that the Corporation believes should be included in the net book value calculation, which amounts to an additional $56 million. The dispute is currently proceeding through arbitration.

Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules and guidance have changed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment relative to the circumstances existing in the business. Every effort is made to comply with all applicable rules on or before the effective date, and we believe the proper implementation and consistent application of accounting rules is critical.

However, not all situations are specifically addressed in the accounting literature. In these cases, our best judgment is used to adopt a policy for accounting for these situations. We draw analogies to similar situations and the accounting guidelines governing them, consider foreign accounting standards, and consult with our independent auditors about the appropriate interpretation and application of these policies. Each of the critical accounting policies involves complex situations and a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our consolidated financial statements.

Our significant accounting policies are described in Note 2 to our annual audited 2018 consolidated financial statements. The most critical of these policies are those related to revenue recognition, financial instruments, valuation of PP&E and associated contracts, project development costs, useful life of PP&E, valuation of goodwill, leases, income taxes, employee future benefits, decommissioning and restoration provisions, and other provisions. Each policy involves a number of estimates and assumptions to be made about matters that are uncertain at the time the estimate is made. Different estimates, with respect to key variables used for the calculations, or changes to estimates, could potentially have a material impact on our financial position or results of operations.

We have discussed the development and selection of these critical accounting estimates with our Audit and Risk Committee ("ARC") and our independent auditors. The ARC has reviewed and approved our disclosure relating to critical accounting estimates in this MD&A.

TRANSALTA CORPORATION M 34

Management’s Discussion and Analysis

These critical accounting estimates are described as follows:

Revenue Recognition

Revenue from Contracts with Customers

The Corporation has adopted IFRS 15 Revenue from Contracts with Customers (IFRS 15) with an initial adoption date of Jan. 1, 2018. The Corporation has elected to adopt IFRS 15 retrospectively with the modified retrospective method of transition practical expedient and has elected to apply IFRS 15 only to contracts that are active at the date of initial application. Comparative information has not been restated and is reported under IAS 18 Revenue (IAS 18). The Corporation's accounting policies for the current and prior periods for revenue recognition are outlined in Note 2 of the annual audited 2018 consolidated financial statements. The significant judgments and estimates have been highlighted below.

The majority of our revenues from contracts with customers are derived from the sale of generation capacity, electricity, thermal energy, renewable attributes and byproducts of power generation. The Corporation evaluates whether the contracts it enters into meet the definition of a contract with a customer at the inception of the contract and on an ongoing basis if there is an indication of significant changes in facts and circumstances. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the good or services is transferred to the customer. For certain contracts, revenue may be recognized at the invoiced amount, as permitted using the invoice practical expedient, if such amount corresponds directly with the Corporation’s performance to date. The Corporation excludes amounts collected on behalf of third parties from revenue.

Identification of Performance Obligations

Each promised good or service is accounted for separately as a performance obligation if it is distinct. The Corporation’s contracts may contain more than one performance obligation.

Where contracts contain multiple promises for goods or services, management exercises judgment in determining whether goods or services constitute distinct goods or services or a series of distinct goods or services that are substantially the same and that have the same pattern of transfer to the customer. The determination of a performance obligation affects whether the transaction price is recognized at a point in time or over time. Management considers both the mechanics of the contract and the economic and operating environment of the contract in determining whether the goods or services in a contract are distinct.

Transaction Price

The Corporation allocates the transaction price in the contract to each performance obligation. Transaction price allocated to performance obligations may include variable consideration. Variable consideration is included in the transaction price for each performance obligation when it is highly probable that a significant reversal of the cumulative variable revenue will not occur. Variable consideration is assessed at each reporting period to determine whether the constraint is lifted. The consideration contained in some of the Corporation's contracts with customers is primarily variable, and may include both variability in quantity and pricing, such as: revenues can be dependent upon future production volumes which are driven by customer or market demand or by the operational ability of the plant; revenues can be dependent upon the variable cost of producing the energy; revenues can be dependent upon market prices; and revenues can be subject to various indices and escalators.

In determining the transaction price and estimates of variable consideration, management considers past history of customer usage and capacity requirements, in estimating the goods and services to be provided to the customer. The Corporation also considers the historical production levels and operating conditions for its variable generating assets.

Allocation of Transaction Price to Performance Obligations

The Corporation’s contracts generally outline a specific amount to be invoiced to a customer associated with each performance obligation in the contract. Where contracts do not specify amounts for individual performance obligations, the Corporation estimates the amount of the transaction price to allocate to individual performance obligations based on their standalone selling price, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions.

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Management’s Discussion and Analysis

Satisfaction of Performance Obligations

The satisfaction of performance obligations requires management to use judgment as to when control of the underlying good or service transfers to the customer. Determining when a performance obligation is satisfied affects the timing of revenue recognition. Management considers both customer acceptance of the good or service, and the impact of laws and regulations such as certification requirements, in determining when this transfer occurs. Management also applies judgment in determining whether the invoice practical expedient can be relied upon in measuring progress toward complete satisfaction of performance obligations. The invoice practical expedient permits recognition of revenue at the invoiced amount, if that invoiced amount corresponds directly with the entity's performance to date.

The Corporation recognizes a significant financing component where the timing of payment from the customer differs from the Corporation’s performance under the contract and where that difference is the result of the Corporation financing the transfer of goods and services.

Revenue from Other Sources

Lease Revenue

In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Revenues associated with non-lease elements are recognized as goods or services revenues as outlined above. Where the terms and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income. Where we retain the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including contingent rents where applicable, is recognized over the term of the contract.

Revenue from Derivatives

Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales contracts, futures contracts, and options, which are used to earn revenues and to gain market information. These derivatives are accounted for using fair value accounting. The initial recognition and subsequent changes in fair value affect reported net earnings in the period the change occurs and are presented on a net basis in revenue. The fair values of instruments that remain open at the end of the reporting period represent unrealized gains or losses and are presented on the Consolidated Statements of Financial Position as risk management assets or liabilities.

The determination of the fair value of commodity risk management contracts and derivative instruments is complex and relies on judgments concerning future prices, volatility and liquidity, among other factors. Some of our derivatives are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available, requiring us to use internal valuation techniques or models described below.

Financial Instruments

The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by reference to prices for instruments in active markets to which we have access. In the absence of an active market, we determine fair values based on valuation models or by reference to other similar products in active markets.

Fair values determined using valuation models require the use of assumptions. In determining those assumptions, we look primarily to external readily observable market inputs. However, if not available, we use inputs that are not based on observable market data.

Level Determinations and Classifications

The Level I, II and III classifications in the fair value hierarchy utilized by the Corporation are defined below. The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the lowest level input that is significant to the derivation of the fair value.

Level I

Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access. In determining Level I fair values, we use quoted prices for identically traded commodities obtained from active exchanges such as the New York Mercantile Exchange.

Level II

Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.

TRANSALTA CORPORATION M 36

Management’s Discussion and Analysis

Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation and location differentials. Our commodity risk management Level II financial instruments include over-the-counter derivatives with values based on observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and regression or extrapolation formulas, where the inputs are readily observable, including commodity prices for similar assets or liabilities in active markets, and implied volatilities for options.

In determining Level II fair values of other risk management assets and liabilities, we use observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, we rely on similar interest or currency rate inputs and other third-party information such as credit spreads.

Level III

Fair values are determined using inputs for the asset or liability that are not readily observable.

We may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair values are determined using valuation techniques such as the Black-Scholes, mark-to-forecast and historical bootstrap models with inputs that are based on historical data such as unit availability, transmission congestion, demand profiles for individual non-standard deals and structured products, and/or volatilities and correlations between products derived from historical prices. We also have various contracts with terms that extend beyond a liquid trading period. As forward market prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these contracts are classified in Level III.

Our Commodity Exposure Management Policy, governs both the commodity transactions undertaken in our proprietary trading business and those undertaken to manage commodity price exposures in our generation business. This Policy defines and specifies the controls and management responsibilities associated with commodity trading activities, as well as the nature and frequency of required reporting of such activities.

Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by our risk management department. Level III fair values are calculated within our energy trading risk management system based on underlying contractual data as well as observable and non-observable inputs. Development of non-observable inputs requires the use of judgment. To ensure reasonability, system-generated Level III fair value measurements are reviewed and validated by the risk management and finance departments. Review occurs formally on a quarterly basis or more frequently if daily review and monitoring procedures identify unexpected changes to fair value or changes to key parameters.

The effect of using reasonably possible alternative assumptions as inputs to valuation techniques for contracts included in the Level III fair value measurements at Dec. 31, 2018 , is an estimated total upside of $ 150 million ( 2017 - $ 156 million upside) and total downside of $ 150 million ( 2017 - $ 157 million ) impact to the carrying value of the financial instruments. Fair values are stressed for volumes and prices. The amount of $ 116 million upside ( 2017 - $ 130 million upside) and $ 116 million downside ( 2017 - $ 130 million downside) in the stress values stems from a long-dated power sale contract in the Pacific Northwest that is designated as a cash flow hedge utilizing assumed power prices ranging from US$ 20 -US$ 35 ( Dec. 31, 2017 - US $25 -US $34 ) for the period from 2019 to 2025, while the remaining amounts account for the rest of the portfolio. The variable volumes are stressed up and down one standard deviation from historically available production data. Prices are stressed for longer-term deals where there are no liquid market quotes using various internal and external forecasting sources to establish a high and a low price range.

Valuation of PP&E and Associated Contracts

At the end of each reporting period, we assess whether there is any indication that a PP&E or intangible asset is impaired. Impairment exists when the carrying amount of the asset or CGU to which it belongs exceeds its recoverable amount, which is the higher of fair value less costs of disposal and value in use.

Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected operating results; significant changes in the manner in which an asset is used or in our overall business strategy; or significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations

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Management’s Discussion and Analysis

where we are not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.

Our operations, the market and business environment are routinely monitored, and judgments and assessments are made to determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is made of the recoverable amount of the PP&E or CGU to which it belongs. The recoverable amount is the higher of an asset’s fair value less costs of disposal and its value in use. Fair value is the price that would be received to sell an asset in an orderly transaction between market participants at the measurement date. In determining fair value less costs of disposal, information about third-party transactions for similar assets is used and if none is available, other valuation techniques, such as discounted cash flows, are used. Value in use is computed using the present value of management’s best estimates of future cash flows based on the current use and present condition of the asset. In estimating either fair value less costs of disposal or value in use using discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel consumed, retirement costs and other related cash inflows and outflows over the life of the facilities, which can range from 30 to 60 years. In developing these assumptions, management uses estimates of contracted and future market prices based on expected market supply and demand in the region in which the plant operates, anticipated production levels, planned and unplanned outages, and transmission capacity or constraints for the remaining life of the facilities. Appropriate discount rates reflecting the risks specific to the asset under review are used in the assessments. These estimates and assumptions are susceptible to change from period to period and actual results can, and often do, differ from the estimates, and can have either a positive or negative impact on the estimate of the impairment charge, and may be material.

The impairment outcome can also be impacted by the determination of CGUs or groups of CGUs for asset and goodwill impairment testing. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets, and goodwill is allocated to each CGU or group of CGUs that is expected to benefit from the synergies of the acquisition from which the goodwill arose. The allocation of goodwill is reassessed upon changes in the composition of segments, CGUs or groups of CGUs. In respect of determining CGUs, significant judgment is required to determine what constitutes independent cash flows between power plants that are connected to the same system. We evaluate the market design, transmission constraints and the contractual profile of each facility, as well as our commodity price risk management plans and practices, in order to inform this determination. With regard to the allocation or reallocation of goodwill, significant judgment is required to evaluate synergies and their impacts. Minimum thresholds also exist with respect to segmentation and internal monitoring activities. We evaluate synergies with regard to opportunities from combined talent and technology, functional organization, and future growth potential, and we consider our own performance measurement processes in making this determination. No changes arose in our CGUs in 2018 .

Impairment charges can be reversed in future periods if circumstances improve. No assurances can be given if any reversal will occur or the amount or timing of any such reversal. As a result of our review in 2018 and other specific events, various analyses were completed to assess the significance of possible impairment indicators. Refer to the Asset Impairment Charges and Reversals section of this MD&A for further details.

Project Development Costs

Deferred project development costs include external, direct and incremental costs that are necessary for completing an acquisition or construction project. These costs are recognized in operating expenses until construction of a plant or acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable, and that efforts will result in future value to us, at which time the costs incurred subsequently are included in PP&E or investments. The appropriateness of capitalization of these costs is evaluated each reporting period, and amounts capitalized for projects no longer probable of occurring are charged to net earnings.

Useful Life of PP&E

Each significant component of an item of PP&E is depreciated over its estimated useful life. A component is a tangible asset that can be separately identified as an asset and is expected to provide a benefit of greater than one year. Estimated useful lives are determined based on current facts and past experience, and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological obsolescence, and regulations. The useful lives of PP&E and depreciation rates used are reviewed at least annually to ensure they continue to be appropriate.

In 2018 , total depreciation and amortization expense was $710 million ( 2017 - $708 million , 2016 - $664 million ), of which $136 million ( 2017 - $73 million , 2016 - $63 million ) relates to mining equipment and is included in fuel and purchased power.

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Management’s Discussion and Analysis

As a result of the OCA with the Government of Alberta described in the Significant and Subsequent Events section of this MD&A, we will cease coal-fired emissions by the end of 2030. On Jan. 1, 2017, the useful lives of the PP&E and amortizable intangibles associated with some of our Alberta coal assets were reduced to 2030. See the Accounting Changes section of this MD&A for further details.

Valuation of Goodwill

We evaluate goodwill for impairment at least annually, or more frequently if indicators of impairment exist. If the carrying amount of a CGU or group of CGUs, including goodwill, exceeds the unit’s fair value, the excess represents a goodwill impairment loss. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets.

For purposes of the 2018 , 2017 and 2016 annual goodwill impairment reviews, the Corporation determined the recoverable amounts of the CGUs by calculating the fair value less costs of disposal using discounted cash flow projections based on the Corporation’s long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair value measurement is categorized within Level III of the fair value hierarchy.

We reviewed the carrying amount of goodwill prior to year-end and determined that the fair values of the related CGUs or groups of CGUs to which goodwill relates, based on estimates of future cash flows, exceeded their carrying amounts, and no goodwill impairments existed.

Determining the fair value of the CGUs or group of CGUs is susceptible to changes from period to period as management is required to make assumptions about future cash flows, production and trading volumes, margins, and fuel and operating costs. No reasonably possible change in the assumptions would have resulted in an impairment of goodwill.

Leases

In determining whether the Corporation’s PPAs and other long-term electricity and thermal sales contracts contain, or are, leases, management must use judgment in assessing whether the fulfilment of the arrangement is dependent on the use of a specific asset and the arrangement conveys the right to use the asset. For those agreements considered to contain, or be, leases, further judgment is required to determine whether substantially all of the significant risks and rewards of ownership are transferred to the customer or remain with TransAlta, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant to how we classify amounts related to the arrangement as either PP&E or as a finance lease receivable on the Consolidated Statements of Financial Position, and therefore the value of certain items of revenue and expense is dependent upon such classifications.

Income Taxes

In accordance with IFRS, we use the liability method of accounting for income taxes. Under the liability method, deferred income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and their respective income tax basis.

Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of the jurisdictions in which we operate. The process also involves making an estimate of taxes currently payable and taxes expected to be payable or recoverable in future periods, referred to as deferred income taxes. Deferred income taxes result from the effects of temporary differences due to items that are treated differently for tax and accounting purposes. The tax effects of these differences are reflected in the Consolidated Statements of Financial Position as deferred income tax assets and liabilities. An assessment must also be made to determine the likelihood that our future taxable income will be sufficient to permit the recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be reduced. The reduction of the deferred income tax asset can be reversed if the estimated future taxable income improves. No assurances can be given if any reversal will occur or the amount or timing of any such reversal. Management must exercise judgment in its assessment of continually changing tax interpretations, regulations, and legislation to ensure deferred income tax assets and liabilities are complete and fairly presented. Differing assessments and applications than our estimates could materially impact the amount recognized for deferred income tax assets and liabilities. Our tax filings are subject to audit by taxation authorities. The outcome of some audits may change our tax liability, although we believe that we have adequately provided for income taxes in accordance with IFRS based on all information currently available. The outcome of pending audits is not known nor is the potential impact on the consolidated financial statements determinable.

Deferred income tax assets of $28 million ( 2017 - $24 million ) have been recorded on the Consolidated Statements of Financial Position as at Dec. 31, 2018 . These assets primarily relate to net operating loss carryforwards. We believe there

TRANSALTA CORPORATION M 39

Management’s Discussion and Analysis

will be sufficient taxable income that will permit the use of these loss carryforwards in the tax jurisdictions where they exist.

Deferred income tax liabilities of $501 million ( 2017 - $549 million ) have been recorded on the Consolidated Statements of Financial Position as at Dec. 31, 2018 . These liabilities are comprised primarily of taxes on unrealized gains from risk management transactions and income tax deductions in excess of related depreciation of PP&E.

Employee Future Benefits

We provide selected pension and post-employment benefits to employees. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future experience.

The liabilities for future benefits and associated pension costs included in annual compensation expenses are impacted by employee demographics, including age, compensation levels, employment periods, the level of contributions made to the plans and earnings on plan assets.

Changes to the provisions of the plans may also affect current and future pension costs. Pension costs may also be significantly impacted by changes in key actuarial assumptions, including, for example, the discount rates used in determining the defined benefit obligation and the net interest cost on the net defined benefit liability. The discount rate used to estimate our obligation reflects high-quality corporate fixed income securities currently available and expected to be available during the period to maturity of the pension benefits.

The plan assets are comprised primarily of equity and fixed income investments. Fluctuations in the return on plan assets as a result of actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.

Decommissioning and Restoration Provisions

We recognize decommissioning and restoration provisions for PP&E in the period in which they are incurred if there is a legal or constructive obligation to reclaim the plant or site. The amount recognized as a provision is the best estimate of the expenditures required to settle the provision. Expected values are probability weighted to deal with the risks and uncertainties inherent in the timing and amount of settlement of many decommissioning and restoration provisions. Expected values are discounted at the risk-free interest rate adjusted to reflect the market’s evaluation of our credit standing.

As at Dec. 31, 2018 , the decommissioning and restoration provisions recorded on the Consolidated Statements of Financial Position were $407 million ( 2017 - $437 million ). During 2017, mainly as a result of the OCA, the discount rates used for the Canadian coal and mining operations decommissioning provisions were changed to use the 5 to 15-year rates. The use of lower, shorter-term discount rates increased the corresponding liabilities. On average, these rates decreased by approximately 1.60 to 2.10 per cent. Additionally, the amount and timing of cash outflows for certain Canadian coal plants and mining operations was also revised, resulting in an increase to the corresponding liabilities.

We estimate the undiscounted amount of cash flow required to settle the decommissioning and restoration provisions is approximately $ 1 billion , which will be incurred between 2019 and 2073. The majority of these costs will be incurred between 2020 and 2050. Some of the facilities that are co-located with mining operations do not currently have any decommissioning obligations recorded as the obligations associated with the facilities are indeterminate at this time.

Sensitivities for the major assumptions are as follows:



Factor	Increase or decrease (%)	Approximate impact on net earnings
Discount rate	1	4
Undiscounted decommissioning and restoration provision	10	2

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Management’s Discussion and Analysis

Other Provisions

Where necessary, we recognize provisions arising from ongoing business activities, such as interpretation and application of contract terms and force majeure claims. These provisions, and subsequent changes thereto, are determined using our best estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially from the amount recognized.

Accounting Changes

Current Accounting Changes

IFRS 15 Revenue from Contracts with Customers

We adopted IFRS 15 Revenue from Contracts with Customers with an initial adoption date of Jan. 1, 2018.

We elected to apply the modified retrospective method of transition. Under this method, the comparative periods presented in the annual audited 2018 consolidated financial statements will not be restated, and comparative period revenues continue to be reported as recognized following IAS 18 Revenue . Instead of restating prior years' revenues, we recognized the cumulative impact of the initial application of the standard in the deficit as at Jan. 1, 2018. The cumulative impact of applying the significant financing component requirements of IFRS 15 to an impacted contract resulted in a $13 million (net of tax impacts) increase to the deficit, an increase to the contract liability of $17 million, and a decrease in deferred income tax liabilities of $4 million.

IFRS 15 requires that, in determining the transaction price, the promised amount of consideration is to be adjusted for the effects of the time value of money if the timing of payments specified in a contract provides either party with a significant benefit of financing the transfer of goods or services to the customer (“significant financing component”). The objective when adjusting the promised amount of consideration for a significant financing component is to recognize revenue at an amount that reflects the price that the customer would have paid, had they paid cash in the future when the goods or services are transferred to them. We were required to apply this to one of our contracts with a customer. The application of the significant financing component requirements results in the recognition of interest expense over the financing period and a higher amount of revenue.

Additionally, we no longer recognize revenue (or fuel costs) related to non-cash consideration for natural gas supplied by a customer at one of our gas plants, as it was determined under IFRS 15 that we do not obtain control of the customer-supplied natural gas. This change had no impact on the cumulative impact of initial adoption as recognized in Deficit at Jan. 1, 2018.

Note 2 and Note 3, respectively, of our annual audited 2018 consolidated financial statements include a more detailed discussion of our accounting policies under IFRS 15 and our adoption of IFRS 15.

IFRS 9 Financial Instruments

Effective Jan. 1, 2018, we adopted IFRS 9, which introduces new requirements for:


▪	the classification and measurement of financial assets and financial liabilities;


▪	the recognition and measurement of impairment of financial assets; and


▪	a new hedge accounting model.

In accordance with the transition provisions of the standard, we elected to not restate prior periods' comparative financial statements.

Under the new classification and measurement requirements, financial assets must be classified and measured at either amortized cost, at fair value through profit or loss, or at fair value through other comprehensive income. The classification and measurement depends on the contractual cash flow characteristics of the financial asset and the entity’s business model for managing the financial asset. The classification requirements for financial liabilities are largely unchanged. While the Corporation had no direct impact of adoption the IFRS 9 classification and measurement requirements, a $1 million increase in the deficit resulted from the increase in equity attributable to non-controlling interests due to the IFRS 9 classification and measurement impacts at TransAlta Renewables.

IFRS 9 introduces a new impairment model for financial assets measured at amortized cost. The expected credit loss model requires entities to account for expected credit losses on financial assets at the date of initial recognition, and to account for changes in expected credit losses at each reporting date to reflect changes in credit risk. The loss allowance for a financial

TRANSALTA CORPORATION M 41

Management’s Discussion and Analysis

asset is measured at an amount equal to the lifetime expected credit loss if its credit risk has increased significantly since initial recognition. If the credit risk on a financial asset has not increased significantly since initial recognition, its loss allowance is measured at an amount equal to the 12-month expected credit loss. The Corporation’s management reviewed and assessed its existing financial assets for impairment using reasonable and supportable information in accordance with the requirements of IFRS 9 to determine the credit risk of the respective items at the date they were initially recognized, and compared that to the credit risk as at Jan. 1, 2018. There were no significant increases in credit risk determined upon application of IFRS 9.

The new general hedge accounting model is intended to be simpler and more closely focused on how an entity manages its risks and introduces new effectiveness testing requirements focused on the principle of an economic relationship and eliminates the requirement for retrospective assessment of hedge effectiveness. The Corporation's qualifying hedging relationships in place as at Jan. 1, 2018, also qualified for hedge accounting in accordance with IFRS 9 and were therefore regarded as continuing hedging relationships. No rebalancing of any of the hedging relationships was necessary on Jan. 1, 2018.

Note 2 and Note 3, respectively, of our annual audited 2018 consolidated financial statements include a more detailed discussion of our accounting policies under IFRS 9 and our adoption of IFRS 9.

Change in Estimates – Useful Lives

As a result of the OCA with the Government of Alberta described in the Significant and Subsequent Events section of this MD&A, we will cease coal-fired emissions by the end of 2030. On Jan. 1, 2018, the useful lives of some of the Corporation's mine assets were adjusted to align with the Corporation's coal-to-gas conversion plans. As a result, depreciation expense included in fuel and purchased power increased in total by approximately $38 million . On Jan. 1, 2017, the useful lives of the PP&E and amortizable intangibles associated with some of our Alberta coal assets were reduced to 2030. As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2017, increased in total by approximately $58 million. The useful lives may be revised or extended in compliance with the Corporation’s accounting policies, dependent upon future operating decisions and events, such as coal-to-gas conversions.

Due to our decision to retire Sundance Unit 1 effective Jan. 1, 2018 (see the Significant and Subsequent Events section of this MD&A for further details), the useful lives of the Sundance Unit 1 PP&E and amortizable intangibles were reduced in the second quarter of 2017 by two years to Dec. 31, 2017. As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2017, increased by approximately $26 million.

Since Sundance Unit 1 was shut down two years early, the Canadian federal Minister of Environment and Climate Change agreed to extend the life of Sundance Unit 2 from 2019 to 2021. As such, during the third quarter of 2017, we extended the life of Sundance Unit 2 to 2021. As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2017, decreased in total by approximately $4 million.

Future Accounting Changes

Accounting standards that have been previously issued by the IASB, but are not yet effective and have not been applied by us, include:

IFRS 16 Leases

In January 2016, the IASB issued IFRS 16 Leases , which replaces the current IFRS guidance on leases. Under current guidance, lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are recognized on the statement of financial position, while operating leases are not. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for virtually all lease contracts. In addition, the nature and timing of expenses related to leases will change, as IFRS 16 replaces the straight-line operating leases expense with the depreciation expense for the assets and interest expense on the lease liabilities. For lessors, the accounting remains essentially unchanged.

IFRS 16 is effective for annual periods beginning on or after Jan. 1, 2019. The standard is required to be adopted either retrospectively or using a modified retrospective approach. On transition, TransAlta has elected to apply IFRS 16 using the modified retrospective approach effective Jan. 1, 2019. In applying IFRS 16 for the first time, the Corporation has used the following practical expedients permitted by the standard:


▪	Exemption for short-term leases that have a remaining lease term of less than 12 months as at Jan. 1, 2019 and low value leases;


▪	Excluding initial direct costs for the measurement of the right-of-use asset at the date of initial application;


▪	Using hindsight in determining the lease term where the contract contains options to extend or terminate the lease;

TRANSALTA CORPORATION M 42

Management’s Discussion and Analysis


▪	Adjusting the right-of-use assets by the amount of IAS 37 onerous contract provision immediately before the date of initial application; and


▪	Measuring the right-of-use assets at an amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognized in the statement of financial position immediately before the date of initial application.

The Corporation has substantially completed its assessment of existing operating leases. The Corporation estimates that we will recognize right-of-use lease assets and related lease liabilities for existing operating leases where we are the lessee in the range of $42 million to $52 million. These changes will be partially offset by the derecognition of a finance lease asset and a finance lease liability related to a contractual arrangement that was accounted for as a finance lease under IAS 17 but is no longer considered a lease under IFRS 16.

Competitive Forces

Demand and supply balances are the fundamental drivers of prices for electricity. Underlying economic growth is the main driver of longer-term changes in the demand for electricity, whereas system capacity, natural gas prices, GHG pricing, government subsidies and renewable resource availability are key drivers to the supply. Growth in behind-the-fence generation for mining investments is key to developing our Australian gas segment.

Renewable capacity addition has been strong for the past several years due to government incentives. New supply in the near term and intermediate term is expected to come primarily from investment in renewable energy as well as natural-gas-fired generation. This expectation is driven by the low prices in the natural gas market combined with public policies that favour carbon emission reductions.

We have substantial merchant capacity in Alberta and the Pacific Northwest. In those regions, we enter into contracts and business relationships with commercial and industrial customers to sell power on a long-term basis, up to our available capacity in the markets. We further reduce the portion of production not sold in advance through short-term physical and financial contracts, and we optimize production in real time against our position and market conditions.

We also compete for long-term contracted opportunities in renewable and gas power generation, including cogeneration, across Canada, the United States and Australia. Our target customers in this area are incumbent utility providers and large industrial and mining operators.

Alberta

Approximately 58 per cent of our gross installed capacity is located in Alberta and approximately 50 per cent of this 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. The Sundance 1 and 2 Alberta PPAs expired at the end of 2017, the Sundance 3 to 6 PPAs were terminated effective March 31, 2018, and the Keephills 1 and 2, Sheerness and Hydro PPAs will expire at the end of 2020. The Balancing Pool acts as buyer for the Keephills and Sheerness PPAs as a result of the terminations in 2016 by the original buyers.

In the fourth quarter of 2017, we announced our strategy of mothballing certain facilities as well as our plan to convert our coal-fired generation to gas-fired generation, and we announced updates to this in December 2018. See the Significant and Subsequent Events section of this MD&A for further details.

Coal generation sold under certain Alberta PPAs retains 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 a significant portion of our remaining generation.

Alberta's annual demand increased approximately 3 per cent from 2017 to 2018. The increase in demand was reflected in the average pool price, which increased from $ 22.19 /MWh in 2017 to $ 50.29 /MWh in 2018 . The majority of the pool price increase was due to higher carbon compliance costs from thermal generation. The higher prices also positively impacted our merchant wind and hydro portfolio.

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Management’s Discussion and Analysis

Our market share of offer control in Alberta in 2018 was approximately 22 per cent (16 per cent if the Sundance mothballed units are excluded from offer control).

In late November 2016, we announced that we had entered into an OCA with the Government of Alberta that provides transition payments for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030. The affected plants are not, however, precluded from generating electricity at any time by any method other than the combustion of coal. We also entered into a Memorandum of Understanding with the Government of Alberta to collaborate and co-operate in the development of a capacity market in Alberta that ensures both current and new electricity generators will have a level economic playing field to build, buy and sell electricity, and to develop a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation.

We expect additional compliance costs as a result of the federal government’s proposed framework in which each province is expected to implement a GHG policy equivalent to a carbon price of $50 per tonne by 2022. We believe that our extensive portfolio of assets provides us with brownfield development opportunities in wind, solar, hydro and gas that give us a cost advantage over competitors when constructing generation facilities that use these fuel types.

Pursuant to the Electric Utilities Act (Alberta), the Balancing Pool announced the complete termination of the Sundance 3 to 6 PPAs, effective March 31, 2018. As of April 1, 2018, the Sundance plant has been operated as a merchant facility. There has been no announcement yet concerning the Keephills PPA.

TransAlta continues to operate the Keephills PPA generating units in their ordinary course and receives the capacity and energy payments due to TransAlta under the PPAs.

Coal-to-Gas Conversions

On December 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity. The final regulation provides specific provisions for coal-to-gas conversions. The rules for converted units will allow converted plants to operate for a set number of years following the end-of-life for the unit under the coal regulations based on a one-time performance test at the time of conversion.

We are planning the conversion of the units at Sundance and Keephills to gas-fired generation in the 2020 to 2023 time frame. The conversions will provide competitive, reliable, low-cost power to the Alberta market and are expected to position them well in the proposed capacity market. We expect the first capacity auction to occur in 2020 for delivery in November 2021.

In July 2018, we retired the then mothballed Sundance Unit 2 due to its shorter useful life relative to other units, age, size and the capital requirements needed to return the unit to service.

US Pacific Northwest

Our capacity in the US Pacific Northwest is represented by our 1,340 MW Centralia coal plant. Half of the plant capacity is scheduled 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 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.

Contracted Gas and Renewables

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Management’s Discussion and Analysis

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.

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 recontracting these plants with limited life extending capital expenditures. We have recently extended the life of our Ottawa (2033 expiry), Windsor (2031 expiry), Parkeston (2026 expiry) and Fort Saskatchewan (2030 expiry) plants in this manner.

TransAlta’s Capital

The following discusses TransAlta’s main categories of capital: Financial, Power-Generating Portfolio, Human, Intellectual, Social and Relationship, and Natural.

Financial Capital

Our goal over the last few years was to build financial flexibility by using multiple sources of funding to reposition our capital structure. Over the last few years, the rating of our unsecured debt was put under pressure by all the rating agencies. We responded to this pressure by taking significant action starting in 2014 to reduce our indebtedness and strengthen our financial metrics.

Moody’s lowered the rating of our senior unsecured debt to Ba1 with a stable outlook in December 2015. The direct financial impact of this downgrade has been limited. In June 2018 Moody’s revised its rating outlook to positive from stable. During 2018, Fitch Ratings reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating of BBB- with a stable outlook; DBRS Limited reaffirmed the Corporation’s Unsecured Debt rating and Medium-Term Notes rating of BBB (low), the Preferred Shares rating of Pfd-3 (low) and Issuer Rating of BBB (low) with a stable outlook; and Standard and Poor’s reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating of BBB- with a negative outlook. The Corporation is focused on strengthening its financial position and cash flow coverage ratios to achieve stable investment grade credit ratings. Credit ratings provide information relating to the Corporation's financing costs, liquidity and operations and affect the Corporation's ability to obtain short-term and long-term financing and/or the cost of such financing. Strengthening the Corporation’s financial position allows its commercial team to contract the Corporation’s portfolio with a variety of counterparties on terms and prices that are favourable to the Corporation’s financial results and provides the Corporation with better access to capital markets through commodity and credit cycles. Risks associated with our credit ratings are discussed in the Liquidity Risk section of this MD&A.

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Management’s Discussion and Analysis

Capital Structure

Our capital structure consists of the following components as shown below:



As at Dec. 31	2018				2017				2016
	$		%		$		%		$		%
TransAlta Corporation
Recourse debt - CAD debentures	647		9		1,046		14		1,045		12
Recourse debt - US senior notes	943		13		1,499		19		2,151		25
Credit facilities	174		2		—		—		—		—
US tax equity financing	28		—		31		—		39		—
Other	11		—		13		—		15		—
Less: cash and cash equivalents	(16	)	—		(294	)	(4	)	(290	)	(3	)
Less: principal portion of restricted cash on TransAlta OCP	(27	)	—		—		—		—		—
Less: fair value asset of economic hedging instruments on debt ⁽¹⁾	(10	)	—		(30	)	—		(163	)	(2	)
Net recourse debt	1,750		24		2,265		29		2,797		32
Non-recourse debt	469		6		208		3		245		3
Finance lease obligations	63		1		69		1		73		1
Total consolidated net debt - TransAlta Corporation	2,282		31		2,542		33		3,115		36
TransAlta Renewables
Credit facility	165		2		27		—		—		—
Less: cash and cash equivalents	(73	)	(1	)	(20	)	—		(15	)	—
Net recourse debt	92		1		7		—		(15	)	—
Non-recourse debt	767		11		814		11		793		9
Total consolidated net debt - TransAlta Renewables	859		12		821		11		778		9
Total consolidated net debt	3,141		43		3,363		44		3,893		45
Non-controlling interests	1,137		16		1,059		14		1,152		14
Equity attributable to shareholders
Common shares	3,059		42		3,094		40		3,094		36
Preferred shares	942		13		942		12		942		11
Contributed surplus, deficit and accumulated other comprehensive income	(1,004	)	(14	)	(710	)	(9	)	(525	)	(6	)
Total capital	7,275		100		7,748		100		8,556		100

(1) During the first quarter of 2017, we discontinued hedge accounting on certain US-denominated debt hedges. The foreign currency derivatives remain in place as economic hedges. See the Financial Instruments section of this MD&A for further details.

We continued strengthening our financial position during 2018 and have reduced our total consolidated net debt by almost $800 million since the end of 2016 and enhanced shareholder value by:

2018:


▪	early redeeming our outstanding 6.650 per cent US$500 million senior notes due May 15, 2018, for approximately $617 million (US$516 million) using proceeds from the Sundance B and C PPAs termination payment and existing liquidity;


▪	early redeeming our outstanding 6.40 per cent $400 million debentures due Nov. 2019, for approximately $425 million;


▪	paying out the US$25 million non-recourse debt related to the Mass Solar projects;


▪	purchasing and cancelling 3,264,500 common shares at an average price of $7.02 per share through our NCIB program, for a total cost of $23 million ;

2017:


▪	making a scheduled US$400 million senior note repayment using existing liquidity. This repayment was hedged with a cross-currency swap entered into on issuance of the debt that effectively reduced our Canadian dollar repayment by approximately $107 million; and


▪	early redeeming all of Canadian Hydro Developers Inc.’s ("CHD") outstanding non-recourse debentures.

See the Significant and Subsequent Events section of this MD&A for further details.

TRANSALTA CORPORATION M 46

Management’s Discussion and Analysis

Throughout 2016, 2017 and 2018, we continued implementing our strategy to raise debt secured by our contracted cash flows and completed the following debt offerings:


▪	a non-recourse bond in the amount of $345 million on July 20, 2018, with principal and interest payable semi-annually, maturing on Aug. 5, 2030, secured by the payments we receive under the OCA;


▪	a project-level bond in the amount of $260 million on Oct. 2, 2017, with principal and interest payable quarterly, maturing on Nov. 30, 2033, secured by our Kent Hills wind farm;


▪	a non-recourse bond in the amount of $202.5 million on Dec. 7, 2016, with principal and interest payable quarterly, maturing on Dec. 31, 2030, secured by our Poplar Creek finance lease contract; and


▪	a non-recourse bond in the amount of $159 million on June 3, 2016, with principal and interest payable semi-annually, and maturing on June 30, 2032, secured by our New Richmond Wind project in Quebec.

These actions align with our strategy of issuing project-level amortizing debt to proactively manage upcoming debt maturities.

Between 2019 and 2021, we have approximately $ 707 million of debt maturing. We expect to continue our deleveraging strategy over the next three years as part of our balanced capital allocation plan.

The strengthening of the US dollar has increased our long-term debt balances by $ 76 million as at Dec. 31, 2018 . Almost all our US-denominated debt is hedged either through financial contracts or net investments in our US operations. During the period, these changes in our US-denominated debt were offset as follows:



As at Dec. 31	2018	2017
Effects of foreign exchange on carrying amounts of US operations (net investment hedge) ⁽¹⁾ and finance lease receivable	42	(43	)
Foreign currency cash flow hedges on debt	11	(45	)
Economic hedges and other	21	(18	)
Unhedged	2	(7	)
Total	76	(113	)

Our credit facilities provide us with significant liquidity. At Dec. 31, 2018 , we had $ 2.0 billion ( 2017 - $2.0 billion) of committed credit facilities, of which $ 0.9 billion ( 2017 - $1.4 billion) was available for use. We are in compliance with the terms of the credit facilities. At Dec. 31, 2018 , the $ 1.1 billion ( 2017 - $0.6 billion) of credit utilized under these facilities was comprised of actual drawings of $0.3 billion ( 2017 - nil) and letters of credit of $ 0.7 billion ( 2017 - $0.6 billion). These facilities are comprised of a $ 1.3 billion committed syndicated bank facility expiring in 2022, TransAlta Renewables $500 million committed syndicated bank credit facility expiring in 2022, and three bilateral credit facilities, totalling $ 240 million , expiring in 2020.

The Melancthon Wolfe Wind, Pingston, TAPC Holdings LP, New Richmond, KHWLP and OCP non-recourse bonds with a carrying value of $1,235 million ( Dec. 31, 2017 - $1,022 million ) are subject to customary financing conditions and covenants that may restrict the Corporation’s ability to access funds generated by the facilities’ operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds can be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the fourth quarter. However, funds in these entities that have accumulated since the fourth quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2019 . At Dec. 31, 2018 , $33 million ( Dec. 31, 2017 - $35 million ) of cash was subject to these financial restrictions.

Additionally, certain non-recourse bonds require that certain reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit. The Corporation has elected to use letters of credit as at Dec. 31, 2018 .

Working Capital

Including the current portion of long-term debt, the excess of current assets over current liabilities was $439 million as at Dec. 31, 2018 ( 2017 - $101 million ). Our working capital increased year over year mainly due to a decrease in long-term debt due within the next year (last year, we had a US$500 million senior note due). Excluding the current portion of long-term debt of $148 million , the excess of current assets over liabilities was $587 million as at Dec. 31, 2018 ( 2017 - $848 million ), a decrease of $261 million , mainly due to the lower cash and cash equivalents and trade and other receivables.

TRANSALTA CORPORATION M 47

Management’s Discussion and Analysis

Share Capital

Our Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares reset in 2016 at a coupon rate of 2.709 per cent. As permitted under the terms of the Preferred Shares, some shareholders elected to convert to a floating rate and 1,824,620 of our 12 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares were tendered for conversion, on a one-for-one basis, into the Series B Cumulative Redeemable Floating Rate Preferred Shares. Our Series C and Series E Cumulative Redeemable Rate Reset Preferred Shares failed to receive the required number of minimum votes in 2017 to give effect to conversions into Series D and Series F, respectively; accordingly, both the Series C and Series E Preferred Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The Series G preferred shares will reset in 2019.

The following tables outline the common and preferred shares issued and outstanding:



As at	Feb. 26, 2019	Dec. 31, 2018	Dec. 31, 2017
	Number of shares (millions)
Common shares issued and outstanding, end of period	284.6	284.6	287.9
Preferred shares
Series A	10.2	10.2	10.2
Series B	1.8	1.8	1.8
Series C	11.0	11.0	11.0
Series E	9.0	9.0	9.0
Series G	6.6	6.6	6.6
Preferred shares issued and outstanding, end of period	38.6	38.6	38.6

Non-Controlling Interests

As of Dec. 31, 2018 , we own 60.9 per cent ( 2017 – 64.0 per cent) of TransAlta Renewables. In 2018, our ownership percent decreased due to TransAlta Renewables issuing approximately 12 million common shares under a bought deal offering and approximately one million common shares under their Dividend Reinvestment Plan. We did not participate in either of these issuances.

In 2017, the South Hedland Power Station achieved commercial operation on July 28, 2017, and on Aug. 1, 2017, the Corporation converted its 26.1 million Class B shares held in TransAlta Renewables into 26.4 million common shares of TransAlta Renewables. At that time, the Corporation’s common share equity participation percentage in TransAlta Renewables increased to 64 per cent from 59.8 per cent.

In January 2016, we completed the sale to TransAlta Renewables of an economic interest in the 506 MW Sarnia cogeneration facility and of two renewable energy facilities with total capacity of 105 MW for $540 million. Consideration received from TransAlta Renewables consisted of gross proceeds from a public offering of 17,692,750 common shares at $9.75 per share for gross proceeds of $173 million, 15.6 million common shares of TransAlta Renewables with a value of $152 million, and a $215 million unsecured subordinated debenture convertible into common shares of TransAlta Renewables at a price of $13.16 per common share upon maturity on Dec 31, 2020. On Nov. 9, 2017, TransAlta Renewables paid the debentures early, for $218 million in total, comprised of principal of $215 million and accrued interest of $3 million. In November 2016, the economic interest was converted to direct ownership of Sarnia, Ragged Chute and Le Nordais by TransAlta Renewables.

TransAlta Renewables is a publicly traded company whose common shares are listed on the TSX under the symbol “RNW”. TransAlta Renewables holds a diversified, highly contracted portfolio of assets with comparatively lower carbon intensity.

We remain committed to maintaining our position as the majority shareholder and sponsor of TransAlta Renewables, with a stated goal of maintaining our interest between 60 to 80 per cent.

We also own 50.01 per cent of TA Cogen, which owns, operates or has an interest in three natural-gas-fired facilities and one coal-fired generating facility. In 2016, we recontracted our Mississauga cogeneration, which resulted in a pre-tax gain of approximately $191 million, accelerated depreciation of $46 million and recognized a fuel charge for the de-designation of gas hedges of $14 million. The Mississauga, Ottawa, Windsor and Fort Saskatchewan facilities are owned through our 50.01 per cent interest in TA Cogen. Since we own a controlling interest in TA Cogen and TransAlta Renewables, we consolidate the entire earnings, assets and liabilities in relation to those assets.

TRANSALTA CORPORATION M 48

Management’s Discussion and Analysis

Returns to Providers of Capital

Net Interest Expense

The components of net interest expense are shown below:



Year ended Dec. 31	2018		2017		2016
Interest on debt	184		218		218
Interest income	(11	)	(7	)	(2	)
Capitalized interest	(2	)	(9	)	(16	)
Loss on redemption of bonds	24		6		1
Interest on finance lease obligations	3		3		3
Credit facility fees, bank charges, and other interest	13		18		19
Keephills 1 outage interest accruals (reversals)	—		—		(10	)
Other ⁽¹⁾	15		(3	)	(4	)
Accretion of provisions	24		21		20
Net interest expense	250		247		229

(1) During 2018 , approximately $5 million of costs were expensed due to project level financing that is no longer practicable and approximately $7 million relates to the significant financing component required under IFRS 15.

Although interest on debt was down due to lower debt levels, net interest expense was higher in 2018 due to the $5 million prepayment premium relating to the early redemption of the US$500 million senior notes, $5 million of costs expensed in connection to a project-level financing that is no longer practicable, the $19 million prepayment premium relating to the early redemption of the $400 million debenture and lower capitalized interest.

Net interest expense increased during 2017 compared to 2016, due to lower capitalized interest and the redemption premium recognized on the early redemption of the CHD debentures, which more than offset higher interest income. During 2016, reversals of interest previously accrued relating to our Keephills 1 outage arbitration reduced interest expense.

Dividends to Shareholders

On Jan. 14, 2016, we announced a reduction of our common share dividend from $0.72 annually to $0.16 annually. This action was taken as part of a plan to improve our long-term financial flexibility. The declaration of dividends is at the discretion of the Board.

The following are the common and preferred shares dividends declared each quarter during 2018 :



			Common	Preferred Series dividends per share
	Payable date		dividends
Declaration date	Common shares	Preferred shares	per share	A	B	C	E	G
Feb. 2, 2018	Apr 1, 2018	Mar 31, 2018	0.04	0.16931	0.17889	0.25169	0.32463	0.33125
Apr 19, 2018	Jul 3, 2018	Jul 3, 2018	0.04	0.16931	0.19951	0.25169	0.32463	0.33125
Jul 19, 2018	Oct. 1, 2018	Sept. 30, 2018	0.04	0.16931	0.20984	0.25169	0.32463	0.33125
Oct. 10, 2018	Jan. 1, 2019	Dec. 31, 2018	0.04	0.16931	0.22301	0.25169	0.32463	0.33125
Dec. 14, 2018	Apr 1, 2019	Mar 31, 2019	0.04	0.16931	0.23073	0.25169	0.32463	0.33125

Non-Controlling Interests

Reported earnings attributable to non-controlling interests for the year ended Dec. 31, 2018 , increased $ 66 million to $108 million compared to 2017 . Earnings were up at TransAlta Renewables in 2018 due to higher finance income from its investment in the Australian business and the 2017 impairment of an investment. Earnings from TA Cogen were lower in 2018 mainly due to the settlement of the contract indexation dispute with the OEFC relating to the Ottawa and Windsor facilities positively impacting 2017 earnings.

Reported earnings attributable to non-controlling interests for the year ended Dec. 31, 2017 , decreased by $65 million compared to 2016. Net earnings were negatively impacted by the impairment of TransAlta Renewables’ investment in the Australian business recognized as a result of the sale of the Solomon Power Station to FMG and the purported termination of its South Hedland PPA and by higher net interest expense due to higher outstanding borrowings. The Mississauga recontracting has also impacted net earnings, as we recognized a $191 million gain in 2016’s results.

TRANSALTA CORPORATION M 49

Management’s Discussion and Analysis

Power-Generating Portfolio Capital

We monitor availability closely as a key metric to achieving our financial targets. We adjust our maintenance and sustaining capital expenditures to optimize financial returns on our investments and to align with our strategic orientations.

Availability and Production

Our availability target for our Canadian Coal fleet was 87 to 89 per cent for 2018 . We achieved 93 per cent availability in Canadian Coal. Our availability target for our other generating assets (gas and renewables) was in the range of 95 per cent in 2018 . Canadian Gas achieved 93 per cent, Australian Gas 94 per cent and Wind and Solar exceeded 95 per cent at 95.4 per cent.

Our availability for the entire fleet in 2018 , after adjusting for dispatch optimization at US Coal, was 91.3 per cent ( 2017 - 86.8 per cent, 2016 - 89.2 per cent) and was improved over last year. Lower outages and derates at Canadian Coal and higher availability at Canadian Gas due to lower outages were partially offset by the impact of unplanned outages and derates at US Coal in the latter half of the year.

Production for the year ended Dec. 31, 2018 , decreased 8,491 GWh compared to 2017 . The decrease was mainly at Canadian Coal where production decreased 8,229 GWh primarily due to the mothballing and retirement of certain Sundance units. Production at US Coal was down 104 GWh due to the timing of dispatch optimization. Production at Wind and Solar was also down by 92 GWh mainly due to lower wind resources in Alberta and the United States, partially offset by higher wind resources in Eastern Canada.

Operational

In the generation segments, our OM&A costs reflect the cost of operating our facilities. These costs can fluctuate due to the timing and nature of planned and unplanned maintenance activities. In 2017, we initiated Project Greenlight across the entire organization with the intent to deliver committed improvements across the Corporation. Savings achieved in Canadian Coal, Mining and Canadian Gas were offset by increased costs from US Coal and Australian Gas. Increases in OM&A are detailed in the Segmented Comparable Results section of this MD&A.

The following table outlines our generation comparable OM&A over the last three years:



Year ended Dec. 31	2018		2017		2016
Generation comparable OM&A	405		412		396

Greenlight transformation costs included in OM&A:
Canadian Coal	(6	)	(20	)	—
US Coal	(2	)	(2	)	—
Gas, Wind and Solar, and Hydro	(5	)	(7	)	—
Adjusted generation comparable OM&A	392		383		396

TRANSALTA CORPORATION M 50

Management’s Discussion and Analysis

Sustaining Capital

We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake sustaining capital that ensures our facilities operate reliably and safely over a long period of time. Sustaining capital also includes capital required following the 2013 flood in Alberta, most of which has been recovered from third parties.



Year ended Dec. 31	2018		2017	2016
Routine capital	50		69	83
Mine capital	42		28	23
Planned major maintenance	58		121	148
Finance leases	18		17	16
Total sustaining capital expenditures	168		235	270
Productivity capital	21		24	8
Flood-recovery capital	—		—	2
Total sustaining and productivity capital expenditures	189		259	280
Insurance recoveries of sustaining capital expenditures	(7	)	—	(1	)
Net amount	182		259	279

Lost production as a result of planned major maintenance is as follows:

(1) Lost production excludes periods of planned major maintenance at US Coal, which occur during periods of dispatch optimization.

Total sustaining capital expenditures were $ 67 million lower compared to 2017 and total productivity capital was $3 million lower in 2018 compared to 2017. The productivity capital expenditures relate to the funding of some Project Greenlight transformation initiatives. In certain cases, payback is expected to be achieved within three years. We also completed planned major outages at Genessee Unit 3, Centralia Unit 2 and Sarnia.

Strategic Growth and Corporate Transformation

Acquisition of Two US Wind Projects

On Feb. 20, 2018, TransAlta Renewables announced that it had entered into an arrangement to acquire two wind construction-ready projects in the United States. Construction of the projects has started. The wind development projects consist of: i) a 90 MW project located in Pennsylvania that has a 15-year PPA with Microsoft Corp. ("Big Level") and ii) a 29 MW project located in New Hampshire with two 20-year PPAs ("Antrim") (collectively, the "US Wind Projects"), with counterparties that have Standard & Poor's credit ratings of A+ or better. The acquisition of Antrim remains subject to certain closing conditions, including the receipt of a favourable regulatory ruling. The Corporation expects the acquisition to close in early 2019. See the Significant and Subsequent Events section of this MD&A for further details.

Kent Hills Wind Farm

During 2017, TransAlta Renewables entered into a 17-year power purchase agreement with NB Power for the sale of all power generated by an additional 17.25 MW of capacity from the Kent Hills wind farm. On Oct. 19, 2018, TransAlta Renewables announced that the expansion is fully operational, bringing total generating capacity of the Kent Hills wind farm to 167 MW.

Pioneer Gas Pipeline Partnership

On Dec. 17, 2018, the Corporation exercised its option to acquire 50 per cent ownership in the Pioneer Pipeline. Tidewater will construct and operate the 120 km natural gas pipeline, which will have an initial throughput of 130 MMcf/d with the potential to expand to approximately 440 MMcf/d. The Pioneer Pipeline will allow TransAlta to increase the amount of natural gas it co-fires at its Sundance and Keephills coal-fired units, resulting in lower carbon emissions and costs. As well, the Pioneer Pipeline is expected to provide a significant amount of the gas required for the full conversion of the coal units to natural gas. The investment for TransAlta will amount to approximately $90 million. Construction of the pipeline commenced in November 2018 and it is expected to be fully operational by the second half of 2019. TransAlta’s investment is subject to final regulatory approvals.

TRANSALTA CORPORATION M 51

Management’s Discussion and Analysis

Windrise Wind Project

On Dec. 17, 2018, TransAlta's 207 MW Windrise wind project was selected by the AESO as one of the two successful projects in the third round of the Renewable Electricity Program. The Windrise project is situated on 11,000 acres of land located in the county of Willow Creek, Alberta. The project is underpinned by a 20-year Renewable Electricity Support Agreement with the AESO and is expected to cost approximately $ 270 million and is targeted to reach commercial operation during the second quarter of 2021.

Brazeau Hydro Pumped Storage

The Brazeau Hydro Pumped Storage project will generate and support clean electricity in the Province of Alberta. It will store water that can be used to both generate power when it is needed and store excess power supply when demand is low. The Brazeau Hydro Pumped Storage project is a priority for us, as it has existing infrastructure that reduces the cost and environmental footprint of the project, is situated close to existing transmission infrastructure and allows for increased renewables development by balancing intermittent generation from wind and solar.

The Brazeau Hydro Pumped Storage project is expected to have new capacity up to 900 MW, bringing the total Brazeau facility from 755 MW to 1,255 MW, post-completion. We estimate an investment in the range of $1.5 billion to $2.7 billion. During the first nine months of 2018, we invested approximately $2 million to advance the environmental study, work with stakeholders and execute geotechnical work to help further our design and construction phase. Further advancement of the project is dependent on securing a long-term contract.

In May 2018, the AESO released a report stating that dispatchable renewable resources are not needed in the Alberta market before 2030. The value and benefit of the Brazeau Hydro Pumped Storage project would be well beyond the 2030 period. The Corporation still believes that generation from pumped storage should be part of future calls for power under the Alberta Renewables program. The Corporation is not spending additional development dollars on the project at this time but will continue to work with governments to find the appropriate financial mechanisms for bringing low-cost, green, dispatchable renewables into the market to support low prices and emissions for Alberta customers.

Project Greenlight

Project Greenlight is a multi-year program to transform our business and the delivery of the Corporation’s strategy. Business units are focusing both on cash flow improvements and the way the Corporation is delivering sustainable value.

Through this program we delivered on projects that improved performance by improving generation efficiency, improving heat rates, lowering fuel costs, reducing GHG emissions, reducing operating and maintenance costs, optimizing our capital spend, avoiding new costs, reducing overhead costs and financing costs, improving working capital, monetizing assets, streamlining processes and achieving efficiencies. Value savings were offset by current year program costs and project costs, made up of mostly capital expenditures. We estimate that the Project Greenlight initiatives generated net $70 million in gross margin, OM&A expense and capital savings. This enabled financial flexibility for new investments. We invested approximately $ 16 million (2017 - $29 million) in this program and an additional $ 21 million (2017 - $25 million) in productivity capital in 2018.

Contractual Profile

Approximately 70 per cent of our capacity over the next two years is sold under long-term contracts. Excluding Alberta PPAs for our coal and hydro facilities, the majority of these contracts have maturities in excess of 10 years. During the fourth quarter of 2017, we entered into a long-term contract for the Fort Saskatchewan natural gas facility, commencing Jan. 1, 2020. The contract has an initial 10-year term. In 2016, we entered into a long-term contract for the Akolkolex hydro facility in B.C., expiring in 2045. Our South Hedland Power Station reached commercial operations on July 28, 2017, and is contracted until 2042.

Human Capital

Engaging our workforce, developing our employees and minimizing safety incidents are the keys to human capital value creation at TransAlta. The most material impacts on our human capital performance are having an engaged workforce and keeping our employees safe.

As at Dec. 31, 2018 , we had 1,883 (2017 - 2,228) active employees. This number has decreased by fifteen per cent over 2017, following reduction in positions at our coal fleet and restructuring initiatives to reduce costs and increase efficiency. A number of unfilled positions have also been eliminated.

TRANSALTA CORPORATION M 52

Management’s Discussion and Analysis

With approximately 50 per cent of our employees being unionized, we strive to maintain open and positive relationships with union representatives and regularly meet to exchange information, listen to concerns and share ideas that further our mutual objectives. Collective bargaining is conducted in good faith, and we respect the rights of all employees to participate in collective bargaining.

Organizational Culture and Structure

Our employees are central to value creation. Our corporate culture has been cultivated throughout our more than 100-year heritage of pioneering innovative ways to safely and responsibly generate reliable and affordable electricity. In 2016, we formalized our core values to help provide strategic clarity for our employees. We want our people to align with and live our core values, which are: innovation, respect, loyalty, accountability, integrity and safety. We seek to challenge our employees to maximize their potential. We encourage alignment with our values and work ethic, while providing a foundation for leadership, collaboration, community support, growth and work/life balance.

Our organizational structure consists of six levels, which helps facilitate pace and decision-making in our organization. Our business operates as a business-centric model, with Coal & Mining, Gas & Renewables, Australia, and Energy Marketing & Trading defined as our four primary businesses. Our Corporate function oversees our business and provides strategic alignment.

Gender Diversity

A number of case studies have highlighted the link between gender diversity and additional business value. TransAlta is an active supporter of gender diversity as a driver for value, but also as an ethical business practice. Our commitment to increased female participation in our business is evidenced by our female participation rates on both our executive and Board. As at Dec. 31, 2018, women made up 50 per cent of our executive team and 40 per cent of our Board. This is well above our peers in the electricity sector. The Canadian Electricity Association reported that averages for women in executive and on Boards in 2017 was 25.5 and 31.5, per cent respectively. This is also well above the Catalyst Accord, which is signed by a number of leading organizations in Canada, that all support targets to ensure women comprise 30 per cent of executive and Board roles by 2022.

Employee Benefits

TransAlta is an attractive employer in all three countries in which we operate. We provide compensation to our employees at levels that are competitive in relation to their respective location. We strive to be an employer of choice through our total rewards program, which includes various incentive plans designed to align performance with our annual and mid-term targets, as determined annually by the Board.

Also included in compensation are various retirement savings plans. We have registered pension plans in Canada and the US, as well as a superannuation plan in Australia. The plans cover substantially all employees of the Corporation, its domestic subsidiaries, and specific named employees working internationally. These plans have defined benefit (“DB”) and defined contribution (“DC”) options, and in Canada there was an additional DB supplemental pension plan (“SPP”) for members whose annual earnings exceeded the Canadian income tax limit. The DB SPP was closed as of Dec. 31, 2015, and a new DC SPP commenced for only executive members effective Jan. 1, 2016. Current executives as of Dec. 31, 2015, were grandfathered in the DB SPP. The Australian superannuation plan is compulsory for employers with contributions required at a rate set by the government, currently 9.5 per cent of employees’ wages and salaries.

The Canadian and US defined benefit pension plans are closed to new entrants, with the exception of the Highvale pension plan acquired in 2013. The US defined benefit pension plan was frozen effective Dec. 31, 2010, resulting in no future benefits being earned. The defined benefit plans are funded by the Corporation in accordance with governing regulations and actuarial valuations. We provide other health and dental benefits for disabled members and retired members, typically up to the age of 65. The Canadian retiree benefits plan was closed for all new hired employees as of March 1, 2017. The supplemental pension plan is non-registered and an obligation of the Corporation. We are not obligated to fund the supplemental pension plan but are obligated to pay benefits under the terms of the plan as they come due.

Talent and Employee Development

Talent and employee development is viewed as a key pillar of organizational health. In 2018, we extended our Change Leadership Forum to our managers, building upon senior management training in 2017. The two-day session is focused on organizational transformation with an emphasis on identifying root causes of barriers related to driving change.

TRANSALTA CORPORATION M 53

Management’s Discussion and Analysis

In 2018, we completed a six-month peer lead leadership training program, called Elevate, for our professionals and subject matter experts. This builds on training of 75 middle management professionals in 2017. The program is focused on establishing a learner’s mindset, building trust and influence, strengths-based leadership, being transparent, providing feedback, collaboration as a team and innovation.

In addition to Elevate, we continued our two-day leadership program in 2018 for all of our employees. The program, called Execution Engine, was designed to build capabilities for our people to create an organization that is both efficient and adaptive, while living our values. The training program was built on research into what is needed for our people to help drive and sustain change. To date, approximately 830 employees (or 44 per cent) have taken this course. Employees learn project management (i.e., idea generation, planning, problem solving and prioritization), effective communication (i.e., presentations, meetings and emails), how to get the best out of people (coaching and influencing) and health (organizational health and personal resilience).

In addition, we seek unique ways to expose employees to energy transformation and disruption. Employees are encouraged to target development in areas to support this. In 2018, we sent 25 of our employees to the Energy Disruptors conference in Calgary, which was highlighted by Richard Branson as a keynote. Learning from global leaders working on the energy transition, this group returned to integrate ideas and solutions into our business, through our Project Greenlight program.

Safety

The safety of our people, communities and environment is one of our seven core values. At TransAlta we operate large and complex facilities. The environments in which we work, including Canadian winters and the Australian outback, often add an additional challenge to keep our employees safe. The safety of our staff, contractors and visitors is the top priority of our social performance. Our safety culture is further embedded into TransAlta culture each year. Every meeting of more than four people starts with a “safety moment,” which helps share key safety learnings across the Corporation.

Our approach to safety was revised in 2015 when we added to our work on occupational safety with a renewed focus on process safety. In collaboration with ScottishPower, an organization known for achieving leading safety performance, we launched our Total Safety Management System. The management system builds on our occupational safety program, Target Zero, which is focused on protecting our workers on site, through personal protection equipment, inspections, safety controls, job safety analyses, field-level hazard assessments and safety communications. Our Total Safety Management System adds a focus on preventing incidents from our equipment and processes through definition and measurement of safety-critical performance measures and operating limits.

In 2018, the first full year of implementation of a safety culture transformation within our Coal and Mining business was completed. The bulk of the Canadian Coal employees were provided with new tools and capability to improve their own personal safety and that of their workmates. In addition there have been improvements in safety standards, amenities, housekeeping and safety leadership implemented in parallel.

This combination of initiatives has led to progress and results. In 2018 our Injury Frequency Rate (“IFR”) was 0.54 (2017 - 0.72). IFR is defined as the number of injuries (lost-time and medical) for every 200,000 hours worked. Our ultimate goal is to achieve zero injury incidents, but annually we seek improvement over the prior year. Our target IFR in 2019 is 0.43, a 20 per cent reduction over 2018 performance.

In 2017, we introduced a new key performance indicator to help us further improve our safety performance. Total Incident Frequency (“TIF”) tracks the total number of injuries (medical aids, lost-time injuries, restricted works and first aids) relative to employee hours worked. First aids can be minor (such as a cut or scratch); nevertheless, incident awareness and understanding provide us with preventative safety knowledge, which translates into education for employees and injury avoidance. Our TIF in 2018 was 1.98, which was a 44 per cent improvement over 2017 performance. We are targeting a TIF of 1.58 in 2019, a 20 per cent reduction over 2017 performance. As noted above, our long-term goal is zero.



Year ended Dec. 31	2018	2017	2016
IFR	0.54	0.72	0.85
TIF	1.98	3.54	—

TRANSALTA CORPORATION M 54

Management’s Discussion and Analysis

deeply saddened by this situation and our thoughts and prayers are with the families, co-workers and friends impacted. Safety is an integral value at TransAlta and we continue to work every day to make our work environments safe.

We reward our business units for safety leadership annually at our President's Awards. This year the award for Safety Leadership and Performance was given to our Hydro fleet for achieving target zero in 2018. No medical aids and injuries occurred in 2018, despite 145,000 exposure hours while operating 27 facilities. It was a fantastic achievement from our Hydro business unit and provides inspiration for our other business units.

Intellectual Capital

At TransAlta we define intellectual capital as our knowledge-based assets. Measuring these assets serves two purposes. First, we seek to understand our knowledge-based assets to improve our management and performance of these assets. Second, we seek to understand these assets to communicate their real value. The following highlights some of our knowledge-based assets, which we believe provide us with a competitive edge and that contribute to shareholder value.

Brand Recognition

Our employee culture is supported by a purpose-based, long-term and sustainable business strategy, which is growth in affordable and clean power generation. TransAlta has operated power generation assets for over 100 years, which reflects this approach to long-term and sustainable business. A long-term commitment to business and partnerships lends itself to goodwill and brand recognition, something we value and don’t take for granted. We believe our low-cost and clean power strategy, supported by our internal values and sustainable approach to business, will help support and continue to increase our brand recognition positively.

Diversified Knowledge

The experience and acumen of our employees further enhances our capital value creation. Our business has been operating for over 100 years, and many of our employees have been with us for 30 plus years.

Our experience in developing and operating power generation technologies is highlighted below. The transition of our coal assets to natural gas is a natural fit with our operating experience. Relative to coal, gas operations have lower operating costs, have increased operating reliability and flexibility, require less manpower and reduce GHG and air emissions. Our trading and marketing business complements our knowledge of operating power generation assets.



Power generation type	Operating experience (years)
Hydro	107
Natural Gas	68
Coal	68
Wind	16
Solar	3

Innovation: Idea Generation and Project Management

We believe that global marketplace disruption is a new normal and we recognize that to adapt to the pace of change and remain competitive, our employees and processes must be nimble, adaptive and supporting working more efficiently, while at speed. For further details on our investment in our workforce, please see the Talent and Employee Development discussion in the Human Capital subsection of this MD&A.

This is evidenced by our ongoing internal transformation, called Project Greenlight, which is entering its third year since implementation. This project is focused on bottom-up innovation, specifically fostering a culture of idea generation, development of ideas into projects with defined KPIs, milestones and execution or delivery dates, and ongoing project management to ensure success. Where we fail, we idea generate, build and test again. Since inception, we have spent considerable time educating and training our employees to both think differently and then manage their business case from idea to delivering sustained value. Year three is the final year of the project and we plan to transition Project Greenlight into the business as a sustained process.

For further details on our investment in our workforce, please see the Talent and Employee Development discussion in the Human Capital subsection of this MD&A.

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Management’s Discussion and Analysis

Innovation: Applied Technologies

TransAlta has been at the forefront of innovation in the power generation sector since the early 1900s when we developed hydro assets. To add context, these assets were developed at the same time as the automobile. We have been an early adopter and developer of wind technology in Canada and are now one of the largest wind generators in the country. Today we run a Wind Control Centre, the only one of its kind in Canada, that monitors, to the second, each and every wind turbine we operate across North America. In 2015, we made our first investment in solar technology with the purchase of a 21 MW solar facility in Massachusetts.

As we move towards our vision of becoming the leading clean power corporation in Canada by 2025, we continue to seek solutions to innovate and create value for investors, society and the environment. This is evidenced by our announcements of the accelerated coal-to-gas conversion plans, the expansion of our Kent Hills wind farm in New Brunswick, the 90 MW Big Level and 29 MW Antrim wind development projects in the US, the 207 MW Windrise wind development project in Alberta, proposed solar development on our reclaimed mine site at our Centralia facility in Washington State, and the exploration of hydro expansion.

We are keeping up to date with power technologies that have the potential to redefine power markets today and in the future. Innovation is constantly happening on a more micro scale at TransAlta. For more information on innovation at TransAlta, please visit www.transalta.com/about-us/innovation.

In addition, our teams continuously explore the use of applied or new technologies to find solutions to expand or adapt our fleet in an ever-changing world, which helps protect our shareholder value and maintain delivery of reliable and affordable electricity. The following are further examples of how we have developed innovative solutions to optimize and maximize value from our fleet:

Operations Diagnostic Centre

TransAlta has run its Operations Diagnostic Centre (“ODC”) since 2008. The ODC monitors coal-fired, gas-fired and wind-generating assets across Canada, the United States and Australia. A centralized team of engineers and operations specialists remotely monitors our power plants for emerging equipment reliability and performance issues. ODC staff are trained in the development and use of specialized equipment monitoring software and can apply their experience in power plant operations. If an equipment issue is detected, the ODC notifies plant operations to investigate and remedy the issue before there is an impact to operations. The monitoring, analysis and diagnostics completed by the ODC are focused on early identification of equipment issues based on longer-term trend analysis and complements day-to-day plant operations.

Operational Integrity Program

Our Operational Integrity program is the integration of sustainability, specifically safety, into asset management. It is a program designed to achieve process and equipment safety by understanding and monitoring key operational risks and implementing mitigation measures. Consider it proactive safety. In 2017, we put into place our Total Safety Management System, which integrates our work in process safety with our existing strength in occupational safety programs. We continue to see a positive increase in self-reporting and addressing process safety hazards as awareness and new tools are being introduced. This is evidenced by our trend in safety incidents, which decreased in 2018 to an IFR of 0.54 (2017 - 0.72). This was one of our best safety performance years in our history. Our goal is zero and the Operational Integrity program is a tried and tested tool to help propel us closer to this goal.

Social and Relationship Capital

Creating shared value for our stakeholders is the key to social and relationship value creation at TransAlta. The most material impacts on our social and relationship performance are public health and safety, anti-competitive behaviour and fostering better relationships with Indigenous neighbours, communities, stakeholders, governments, industry and landowners where we operate.

Public Health and Safety

We seek to ensure public health and safety through measures that include restricting physical access to our operating sites and minimizing our environmental impact. It is our goal to keep safe our employees and the peoples and communities where we operate.

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Management’s Discussion and Analysis

We specifically look to minimize the following risks:


▪	harm to person(s),


▪	damage to property,


▪	increased liability due to negligence, and


▪	loss of organizational reputation and integrity.

We actively monitor air emissions from our coal and gas plants. Our large coal facilities have Continuous Emissions Monitoring Systems in place, which help us monitor our pollutant emission levels to ensure they are in line with acceptable limits. When we are in breach of regulatory limits we report this to regulatory bodies and conduct a root cause analysis to understand how we can eliminate future breaches from occurring. In 2018, we had two mercury exceedance events at our Centralia coal plant and one NOx stack breach at our Sundance facility. All of the events were captured through our monitoring systems and resolved quickly as a result. These incidents were all reported to regulatory bodies and were deemed to be minor.

Of note, our coal plants currently capture 80 per cent of mercury emissions and the majority of particulate matter emissions. Both mercury and particulate matter emissions have been deemed harmful to human health, which we recognize and work to minimize through capture. The health impact risk from emissions that do reach our environment is minimized due to the location of our plants, which are located away from urban environments. Independent studies dated Nov. 19, 2015, and conducted by University of Alberta scientist Dr. Warren Kindzierski, using provincial government monitoring data over nine years, also show that approximately 10 per cent or less of all particulate matter in the airshed in the largest urban environment close to our facilities, Edmonton, can be attributed to coal combustion emissions. Chemical “signatures” for emissions pointed to several sources of air quality concern in Edmonton, including local industry, vehicles and wood-burning fireplaces.

Assuming reasonably anticipated growth and operating scenarios, we expect future GHG emissions and air pollution emissions performance will be dramatically reduced in respect of our existing assets as we execute our coal-to-gas conversion strategy. GHG emissions from coal are expected to be cut within the range of 60 per cent or 12 million tonnes carbon dioxide equivalent (CO ₂ e). We currently capture 80 per cent of mercury emissions at our coal plants and mercury emissions will be eliminated following the coal-to-gas conversion. Particulate matter and sulphur dioxide emissions will be virtually eliminated or considered negligible post-coal-to-gas conversion and diesel burn. Our nitrogen dioxide emissions will also be reduced in the range of approximately 50 per cent.

Indigenous Relationships and Partnerships

The focus of our efforts in this area is to fulfill TransAlta’s principles for engagement and ensure we live up to its commitments with Indigenous neighbours. Efforts are focused on building and maintaining solid relationships and establishing strong communication channels that enable TransAlta to share information on operations and growth initiatives, gather feedback to inform project planning and understand priorities and interests to better address concerns.

Specifically, our Aboriginal Relations team continues to develop and enhance aboriginal relations in areas of employment, economic development, community engagement, and investment.

Each year, TransAlta provides seven $3,000 bursaries for post-secondary and three $1,000 bursaries for trades students to support the success of Indigenous students in their educational programs. TransAlta’s criteria for accessing the bursary includes any educational pursuit that will support the wellbeing of Indigenous peoples and communities. The bursary is open to all Indigenous applicants that have completed high school. Through agreements and ongoing relationship commitments TransAlta makes information on employment positions available to Indigenous communities and provides sub-contractors terms and conditions to include Indigenous content considerations for procurement initiatives.

In 2017, we once again achieved the Canadian Council for Aboriginal Business’s silver-level Progressive Aboriginal Relations (PAR) certification. Certification occurs ever three years. In 2016, we introduced our STAR tracking program, which functions as a communication record-keeping and engagement measurement tool. This capacity fulfills our requirements for consultation with stakeholders and aboriginal groups alike, and is capable of producing reports (notably, government reports) as proof of engagement and consultation efforts.

In 2018, to further support access to education TransAlta created an Indigenous Gap program with the Southern Alberta Institute of Technology (SAIT) to provide support to Indigenous students who need high school upgrading in order to enter a trade program.

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Management’s Discussion and Analysis

In 2017, we supported an Indigenous Leadership Program at Banff Centre for Arts and Creativity. Approximately 250 Indigenous leaders from over 120 communities attended the leadership programs with help from TransAlta and other supporters.

Over the past five years, TransAlta’s support has provided 39 scholarships for members of Indigenous communities to attend the programs and take that learning back to their communities. Those participants have come from communities across Alberta and British Columbia including the First Nations of Alexis Nakota Sioux, Bearspaw, Chiniki, Enoch Cree, Ermineskin Cree, Fort McKay, Kainai, Montana, Paul, Piikani, Samson Cree, Siksika, Squamish, Tsuu T’ina, and Wesley.

Stakeholder Relationships

Relationships matter to TransAlta. Driven by our values, we seek to maximize value creation for our stakeholders and TransAlta.

TransAlta Stakeholders

Regardless of who our stakeholders are or who they represent, our goal is to act in the best interests of the Corporation and to create either financial, environmental or social value for both our stakeholders and TransAlta. Major stakeholder categories can be summarized as shareholders, debt holders, business partners, contractors, consultants, customers, community organizations, employees, governments, Indigenous groups, industry and professional bodies, media, NGOs, public and regulatory affairs, residents and suppliers. This too encompasses our value chain. Our mindset is value creation across this chain through the development of relationships and partnerships.

Engagement Framework

Our stakeholder engagement framework is modelled and closely tied to the stakeholder engagement aspect of ISO 14001, which is an internationally recognized environmental management standard. This framework is a streamlined corporate-wide approach to ensure that engagement and relationship-building practices are consistent across TransAlta’s locations and types of work.

Methods of Engagement

In order to run our business successfully, we are in consistent two-way communication with the majority of our stakeholders, some more than others. As an example, our dialogue with customers is daily, iterative and takes on many forms including meetings (in-person, virtual, and one-one), calls, emails, newsletters and feedback systems (online loops). It is both proactive and reactive. Our approach and our goal is to be proactive, which is communicating consistent messaging and information, while being transparent. There are often times we will need to be reactive, such as to a customer complaint, and we commit to timely and professional resolution using values-based dialogue. We then work to identify how to mitigate further issues, moving back to our proactive approach.

Part of our business is growth, which we achieve by developing or purchasing new assets. We proactively engage with many stakeholders in all of our geographic operating areas in Australia, Canada and the United States in order to develop and maintain relationships; assess needs and fit; and to seek out collaborative and sustainable value creation opportunities.

Recently we completed construction of our South Hedland 150 MW combined-cycle plant in Western Australia. The project took four years from RFP to commercial operation. Achieving construction and commercial operation was the outcome of successful stakeholder engagement and collaboration. We recently announced our coal-to-gas transition plan, secured by way of collaborative stakeholder engagement. This plan involved signing a Memorandum of Understanding with the Alberta government, which highlights the project fit for Alberta, not just TransAlta. The coal-to-gas project is expected to significantly reduce the environmental impact from coal (a reduction in air pollution and GHG emissions) while enabling the transition and addition of 5,000 MW of renewable energy by 2030.

More details on our stakeholder engagement activities can be found via our social media channels.

Engagement Tracking and Reporting

Our Stakeholder and Indigenous Relations tracking program functions as a Corporation-wide communication record-keeping tool, which is managed by our Stakeholder and Indigenous Relations team. This capacity fulfills our requirements for consultation with stakeholders and aboriginal groups alike, and is capable of producing reports (notably, government reports) as proof of engagement and consultation efforts. Built as an in-house application, this tool has no operating cost or fees and has the ability to grant different levels of access to information. Furthermore, the tool can store email conversations, documents and voice-mail messages related to any project, event or issue, and use them in reports. It can also produce an array of statistical reports showing frequencies and volumes of engagement based on project, stakeholder, stakeholder group, issue or keywords.

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Management’s Discussion and Analysis

Engagement and Board Communication

The Board believes that it is important to have constructive engagement with its shareholders and other stakeholders and has established means for the shareholders of the Corporation and other stakeholders to communicate with the Board. For example, employees and other stakeholders may communicate with the Board, through the Audit and Risk Committee ("ARC"), by writing to the ARC; employees and other stakeholders may also communicate with the Board, through the ARC, by making submissions via the Corporation’s toll-free telephone or online Ethic Helpline (see the Whistleblower System below for more details). Shareholders are also invited to communicate directly with the Board under the Corporation’s Shareholder Engagement Policy, which outlines the Corporation’s approach to proactive director-shareholder engagement at and in between the Corporation’s annual shareholders meetings. Under the Shareholder Engagement Policy, shareholders can request meetings with members of the Board and can submit questions or inquiries to the Board, which the Corporation will respond to. A copy of the Shareholder Engagement Policy is available on our website at https://www.transalta.com/about-us/governance/shareholder-engagement-policy/. Shareholders and other stakeholders may, at their option, communicate with the Board on an anonymous basis. In addition, the Board has adopted an annual non-binding advisory vote on the Corporation’s approach to executive compensation (say-on-pay). The Corporation is committed to ensuring continued good relations and communications with its shareholders and other stakeholders and regularly evaluates its practices in light of any new governance initiatives or developments in order to maintain sound corporate governance practices.

Customers

In early 2018 we launched our new energy services for customers. Our customer solutions team has partnered with best-in-class energy service providers to help businesses achieve:


▪	energy consumption and energy cost management;


▪	market price risks and volume exposure mitigation;


▪	sustainability initiatives such as self-generated electricity; and


▪	monitoring of energy market design changes, price signals and applicable and available incentives.

Our energy services include solar, energy-efficiency audits, distributed generation and building automation. To learn more, please visit the Energy Services customer page on our website at https://www.transalta.com/customers/.

Supply Chain

We continue to seek solutions to advance supply chain sustainability. In 2017 we partnered with Ivalua Inc. to optimize our global supply chain management operations. After an exhaustive review of all leading vendors, Ivalua was selected for its comprehensive Source-to-Pay platform, flexible architecture and overall ability to give TransAlta a competitive advantage. Key business values that we expect include increased supply chain efficiency, reduced lead times, lower costs and improved supplier performance.

We continue to offer our business units optional sustainability terms and conditions for inclusion within supplier agreements. These terms and conditions include suppliers communicating their sustainability policies, strategy and performance; documented systems for labour practices; environmental management systems; disclosure of environmental infringements; disclosure of anti-competitive behaviour; disclosure on climate change management; third-party certifications on products; and demonstration of community investments. Furthermore, as we explore major projects, we are assessing vendors both at the RFP evaluation stage and in up-front information requests on such elements as safe work practices, environmental practices and Indigenous spend. This means, for example, getting information on:


▪	estimated value of services that will be procured though local Indigenous businesses (in RFP template);


▪	estimated number of local Indigenous persons that will be employed (in RFP template);


▪	understanding overall community spend and engagement; and


▪	understanding through interview processes and stakeholder work the state of community relations.

In addition, in early 2019, the Board of Directors adopted a Supplier Code of Conduct that applies to all vendors and suppliers of TransAlta. Under the Code, suppliers of goods and services to TransAlta are required to adhere to our core values, including as it pertains to health and safety, ethical business conduct and environmental leadership. The Code also allows suppliers to report ethical or legal concerns related to the Code via TransAlta’s Ethics Helpline.

Local Communities

TransAlta creates value for local communities through the generation of an essential service. We provide reliable, cost-efficient and clean power in Australia, Canada and the United States.

With the phase-out of coal, communities surrounding our plants will be impacted as our workforce will substantially decline. However, our proposed coal-to-gas conversions provide the opportunity to maintain some jobs at the power plants for substantially longer than would have been possible if the plants continued to only burn coal. Electricity and energy have

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Management’s Discussion and Analysis

always been at the heart of the economy in Alberta, and any changes in the industry must therefore support our communities. Conversion will also help keep municipal, provincial and federal tax revenues supporting these communities. TransAlta advocates for a smart and long-term energy transition in Alberta to minimize disruption and negative economic impact, and to provide support for facility redevelopment, funds for retraining and economic diversification in the province.

Community Investments

During 2018, TransAlta contributed $2.4 million in donations and sponsorships (2017 - $2.6 million). One of our major community investments is to United Way campaigns across Canada and the US. This year, TransAlta employees, retirees, contractors and the Corporation raised over $1.1 million for the United Way.

In 2018, we had a focus on youth education and achieved our target to direct $0.75 million of community investment to this cause. Some of our partnerships included the University of Calgary, Southern and Northern Alberta Institutes of Technology, Mount Royal University, Banff Centre for Arts and Creativity (Indigenous leadership scholarships), Mother Earth Children's Charter School (Indigenous kindergarten to Grade 9), Calgary Stampede (The Young Canadians - ages seven to 18), national Canada and US Indigenous scholarships (post-secondary for trades and academic) and the Alberta Council for Environmental Education.

On July 30, 2015, we announced a US$55 million community investment over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State. The US$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 by closing the Centralia facility’s two units, one in 2020 and the other in 2025. In order to invest the $55 million, three funding boards were formed: The Weatherization Board ($10 million), the Economic & Community Development Board ($20 million) and the Energy Technology Board ($25 million). To date, the Weatherization Board has invested $5.9 million, the Economic & Community Development Board $12 million and the Energy Technology Board $3.9 million.

Natural Capital

We continue to increase financial value from natural or environmental capital-related business activities, while reducing our carbon footprint. Comparable EBITDA from renewable energy generation in 2018 was $322 million (2017 - $289 million). Our revenue in 2018 from carbon-related offsets was $21.6 million (2017 - $27.7 million). In addition, in 2018 the sale of coal byproducts and waste-related recycling generated financial value in the range of $25 million to $35 million.

The following are key natural capital KPI trends:



Year ended Dec. 31	2018	2017	2016
Renewable energy comparable EBITDA	322.0	289.0	277.0
Carbon offsets revenue	21.6	27.7	29.0
GHG emissions (million tonnes CO ₂ e)	20.8	29.9	30.7

Natural Capital Management

All energy sources used to generate electricity have some impact on the environment. While we are pursuing a business strategy that includes investing in renewable energy resources such as wind, hydro and solar, we also believe that natural gas will continue to play an important role in meeting energy needs as part of a clean energy transition. We are planning the conversion of our Alberta coal units to natural gas in the 2020 to 2023 time frame.

Regardless of the fuel type, we place significant importance on environmental compliance and continued environmental impact mitigation, while seeking to deliver low-cost electricity. Currently the most material natural or environmental capital impacts to our business are GHG emissions, air emissions (pollutants, metals), and energy use. Other material impacts that we manage and track performance on includes our environmental management systems, environmental incidents and spills, land use, water usage and waste management.

We maintain procedures for environmental incidents similar to our safety practices, with tracking, analyzing and active management to eliminate occurrence, and ongoing support from our Operational Integrity program. With respect to biodiversity management, we seek to establish robust environmental research and data collection to establish scientifically sound baselines of the natural environment around our facilities and closely monitor the air, land and water in these areas to identify and curtail potential impacts.

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Management’s Discussion and Analysis

Environmental Performance

Reducing the environmental impact of our activities benefits not only our operations and financial results, but also the communities in which we operate. We expect that increased scrutiny will be placed on environmental emissions and compliance, and we therefore have a proactive approach to minimizing risks to our results. Our Board provides oversight with respect to the Corporation’s monitoring of environmental regulations and public policy changes and to the establishment and adherence to environmental practices, procedures and polices in response to legal/regulatory and industry compliance or best practices.

Our performance on managing environmental impacts, reducing our environmental impact and capitalizing on environmental initiatives includes the following.

Renewable Energy

Over the last 10 years, we have added approximately 1,200 MW in renewable energy capacity. Over 1,000 MW has been wind energy development and today we are positioned as an industry leader in wind energy. We continue to operate over 900 MW of hydro energy and our experience with hydro operations is over 100 years. In 2015 we made our first solar investment, 21 MW in Massachusetts, and we continue to look for opportunities to develop and operate solar energy. Our production from renewable energy in 2018 offset the equivalent of approximately 2.9 million tonnes of CO ₂ e or the removal of approximately 620,000 cars from the roads in 2018.

Carbon Offsets

In 2018, 200 MW of our Alberta wind capacity was eligible to generate offsets at a rate of $30 tonne CO ₂ e. Annual revenue generation from these offsets was in the range of $10 million to $15 million. In 2019, as per rules associated with the new Alberta Carbon Competitiveness Incentive Regulation , our offset eligibility capacity will expand to include additional capacity from our wind fleet and hydro fleet. As a result we anticipate offset revenue to rise to approximately $25 million in 2019.

Coal Transition

Our coal-to-gas conversion plan in Alberta is expected to vastly improve our environmental performance. Energy use, GHG emissions, air emissions, waste generation and water usage is expected to significantly decline. A conversion of coal-fired power generation to gas-fired generation is expected to eliminate all mercury emissions, the majority of sulphur dioxide emissions ("SO ₂ ") and significantly reduce our nitrogen dioxide emissions ("NO _X ") .

Environmental Management Systems

All of our 73 facilities have Environmental Management Systems (“EMS”) in place, the majority of which closely align with the internationally recognized ISO 14001 EMS standard. We have operated our facilities in line with ISO 14001 for 19 years, and our systems and knowledge of management systems are therefore mature. We no longer certify our Alberta coal plants as ISO 14001, but the plants continue to run best practice EMS. Only two of our facilities do not closely track ISO 14001, which is due to commercial arrangements (we are not the primary operator), but these facilities still have EMS.

Environmental Incidents and Spills

We recorded seven significant environmental incidents in 2018 (2017 - five incidents), which was below our target of nine. We categorize significant as violations or non-compliance to regulations or exceedance of limits in company operating approvals that resulted in or had the potential to result in enforcement action. This was another year of excellent performance that reflects our continuous improvement in tracking, reporting and identifying potential hazards. Five of our incidents occurred at our coal facilities and two incidents occurred at our gas facilities. None of these incidents resulted in a material environmental impact.

The following are the environmental incidents by fuel types:

Incident types in 2018 were primarily regulatory in nature, whereby we had minor infringements on set regulatory requirements. These included two mercury exceedances at our Centralia coal facility, a nitrogen dioxide stack exceedance at our Sundance coal facility, failure to properly notify the regulator of un-salvaged topsoil, per EPEA Approval Condition 3.2.1, at our Sunhills mine, and a pH exceedance on an oil/water separator at our Sarnia gas facility. We also had two releases, one liquid and one gas. These included a secondary mine drainage water excursion from our Sunhills mine and a refrigerant release at our Ottawa gas facility. All incidents were managed in line with our EMS practice and resolved quickly. We

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Management’s Discussion and Analysis

continue to target improvement and our corporate-wide 2019 target is five or fewer incidents. We also continue to track and manage all non-reportable (minor) environmental incidents, which helps us identify what causes an incident. Understanding the root cause of incidents helps with incident prevention planning and education.

Typical spills at TransAlta are hydrocarbon spills, which happen in low environmental impact areas and are almost always contained and recovered. It is extremely rare that we experience large spills with impact on the environment. Spills that do occur that we must report are typically just above acceptable regulatory spill limits and these are always addressed with a critical time factor. The estimated volume of spills in 2018 was 5 m ³ ( 2017 - 15 m ³ ).

Air Emissions

Air emissions in 2018 decreased significantly compared with 2017 levels. The reduction was due to a significant reduction in coal power generation from our Sundance coal facility and increased generation from co-firing with gas at our merchant facilities. SO ₂ emissions decreased by 47 per cent, NOx emissions decreased by 37 per cent, particulate matter emissions decreased by 62 per cent and mercury emissions decreased by 41 per cent. These reductions highlight our commentary in our 2017 annual integrated report, which noted that we will dramatically reduce air emissions through our planned conversion of two coal units at Sundance, Alberta and the three coal units at Keephills, Alberta to gas-fired generation in the 2020 to 2023 time frame.

We continue to capture 80 per cent of mercury emissions at our coal plants and by 2025 our post-coal era, mercury emissions will be eliminated. Particulate matter and SO ₂ emissions will also be virtually eliminated or considered negligible post-coal power generation. NOx emissions will also be reduced to levels under 20,000 tonnes annually.

We are well underway and remain on track to achieve our target of 95 per cent SO ₂ emission reductions by 2030. Since 2005, we have reduced SO ₂ emissions by 72 per cent. As noted above, we are on track to achieve our SO ₂ target by 2025, well ahead of our 2030 goal. In 2018 we revised our NOx reduction target to 2030 from 95 per cent to 50 per cent. This allows flexibility as we convert coal facilities to natural gas and expand our natural gas fleet.



Year ended Dec. 31	2018	2017	2016
Sulphur dioxide (tonnes)	19,300	36,200	39,600
Nitrogen dioxide (tonnes)	28,000	44,400	48,400
Particulate matter (tonnes)	7,800	14,500	13,800
Mercury (kilograms)	70	110	130

Water

Our principal water uses are for cooling and steam generation in coal and gas plants, and for hydro power production. Typically, TransAlta withdraws in the range of 220-240 million m ³ of water across our fleet. In 2018 we withdrew 245 million m ³ and returned approximately 208 million m ³ back to its source. Water is withdrawn primarily from rivers where we hold permits to withdraw water and adhere to regulations on water quality. We return or discharge approximately 70 per cent of water back to the source, meeting the regulatory quality levels that exist in the various locations in which we operate. The difference between withdraw and discharge, representing consumption, is largely due to evaporation loss.

The following represents our total water consumption (million m ³ ) over the last three years:



Year ended Dec. 31	2018	2017	2016
Water from environment	245	213	239
Water to environment	208	172	197
Total water consumption	37	41	42

Our areas of higher water risk are situated east of Perth in our simple-cycle gas plants in Western Australia and in our southern Alberta hydro operations. We monitor and manage water risk in our operating areas east of Perth. In southern Alberta, following the flood of 2013, our hydro facilities are being used for a greater water management role than they have played in the past. In 2016, we signed a five-year agreement with the Government of Alberta to manage water on the Bow River at our Ghost reservoir facility to aid in potential flood mitigation efforts, as well as at our Kananaskis Lakes System (which includes Interlakes, Pocaterra and Barrier) for drought mitigation efforts.

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Management’s Discussion and Analysis

Land Use

The largest land use associated with our operations is for surface mining of coal. Of the three mines we have operated, the Whitewood mine in Alberta is completely reclaimed and the land certification process is ongoing. Our Centralia mine in Washington State is currently in the reclamation phase (35 per cent reclaimed), and our Highvale mine in Alberta is actively mined with certain sections undergoing reclamation. Our reclamation plans are set out on a life-cycle basis and include contouring disturbed areas, re-establishing drainage, replacing topsoil and subsoil, re-vegetation and land management. Our mining practice incorporates progressive reclamation where the final end use of the land is considered at all stages of planning and development.

In 2018 , we reclaimed 28 acres (11 hectares) at our Highvale mine, which was below our target of 74 acres (30 hectares). This was due to weather conditions limiting the amount of final placement of topsoil. Topsoil placement is the final stage of reclamation. We reallocated resources to other stages of reclamation (such as ground leveling) to move us closer to final reclamation in following years, which keeps us on track with our long-range reclamation plan. The Centralia mine is no longer actively used for coal operations, but reclamation activity is ongoing. In 2018 we reclaimed 113 acres (46 hectares) of land. Since 1991, over 3,000 acres have been reclaimed and approximately 1.7 million seedlings have been planted as part of the reclamation work.

In 2016, we decommissioned our Cowley Ridge wind plant, which was Canada’s first commercial wind plant when it was constructed in 1993 and reached its end of life in 2016. During this process, our wind operations team recycled:


▪	54 towers weighing over 9,000 kilograms ("kg");


▪	61 nacelles, which is the housing of the turbine generating components, weighing 10,000 kg;


▪	19 transformers weighing over 4,000 kg; and


▪	32,000 litres of oil.

Our recycling efforts meant that we diverted close to 1,200,000 kg from the land fill. This job was completed safely, and in addition generated around $0.15 million of value from the recycled components. This work reflects TransAlta’s values of innovation and safety, while maintaining a positive environmental impact at our operations.

Waste

In 2018 our operations generated approximately 1.3 million tonnes of waste. Waste volumes are all primarily non-hazardous. Only 0.1 per cent of waste volumes are hazardous materials. In 2018, only 0.1 per cent of waste was directed to landfill. From the remaining 99.9 per cent, 56 per cent was returned to the mine (ash from coal combustion), 43 per cent was reused and the remaining 0.3 per cent was recycled.

Our reuse waste or byproduct waste is resold in to markets. Byproduct sales and associated annual revenue generation typically ranges from $25 million to $35 million. Our operating teams are diligent at not only minimizing waste, but also maximizing recoverable value from waste. Over the years, we have invested in equipment to capture byproducts from the combustion of coal, such as fly ash, bottom ash, gypsum and cenospheres, for subsequent sale. These non-hazardous materials add value to products like cement and asphalt, wallboard, paints and plastics.

Energy Use

TransAlta uses energy in a number of different ways. We burn coal, gas and diesel to generate electricity. We harness the kinetic energy of water and wind to generate electricity. We also use the sun to generate electricity. In addition to combustion of fuel sources we also track combustion of fuel in the vehicles we use and energy use in the buildings we occupy. Knowledge of how much energy we use allows us to optimize and create energy efficiencies. As an energy corporation, we naturally look for ways to optimize or create efficiencies related to the use of energy. Our coal-to-gas conversions display one innovative way we intend to reduce a significant amount of energy use and significantly reduce our environmental impact, while returning the generation of reliable and low-cost power supply to Albertan customers.

The following captures our energy use (millions of gigajoules). On a comparable basis, our energy use declined by 30 per cent over 2017 as a result of coal retirements and reduced coal generation from our Sundance facility. Our coal-to-gas conversions will significantly reduce our energy usage as gas uses less energy for generation of a MWh.



Year ended Dec. 31	2018	2017	2016
Coal	309.8	447.4	469.1
Gas and renewables	48.6	49.4	59.2
Corporate	0.1	0.1	0.1
Total energy use	358.5	496.9	528.4

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Management’s Discussion and Analysis

Weather

Abnormal weather events can impact our operations and give rise to risks. In addition, normal year-over-year variations in wind, solar, water and temperatures give rise to various levels of volume risk depending on the input fuel of each facility; events outside the design parameters of our facilities give rise to equipment risk; and fluctuations in temperatures can cause commodity price risk through impact on customer demand for heating or cooling. Refer to the Governance and Risk Management section of this MD&A for further discussion of each risk and our related management strategy.

During the past five years, some deviations from expected weather patterns have negatively impacted our annual financial results:


▪	the southern Alberta flood of 2013 disrupted our hydro operations and caused us to invest in substantial repair work. Our losses have been largely covered through insurance;


▪	warm weather in Alberta in 2015 increased derates at our coal facilities due to its impact on the Sundance cooling ponds. These cooling ponds are susceptible to warm weather; however, we anticipate that decreased coal production from the retirement of Sundance Units 1 and 2, respectively, in the medium term will reduce the stress from such occurrence; and


▪	our Alberta mine was susceptible to significant rain starting in August 2016, which resulted in several weeks of flooding and threatened our coal deliveries. We focused on improving drainage infrastructure and using stockpiles to mitigate future risks.

Climate Change

We believe in open and transparent reporting on climate change. Our climate change reporting is structured as per guidance from the Financial Stability Board's Task Force on Climate-Related Financial Disclosures ("TCFD") recommendations. The following highlights our management, performance and leadership of climate change related impacts. For more detailed information, please visit our Climate Change Management webpage: https://www.transalta.com/sustainability/climate-change-management/

Governance

The highest level of oversight on climate change related business impacts is at our Board level, specifically by our Governance Safety and Sustainability Committee (“GSSC”) of the Board and the Audit and Risk Committee ("ARC") of the Board. Business impacts related to climate change are assessed by our executive team quarterly and reported to the Board GSSC and ARC, as applicable.

Strategy

Our corporate vision is to be a leading clean power company by 2025. To support this vision our strategic goals include growth in renewable energy and gas, while reducing a significant amount of emissions from our coal fleet by way of coal-to-gas conversions and coal retirements.

Our corporate goal is to reduce our GHG emissions by 19.7 million tonnes by 2030 compared to 2015 levels, while we grow renewable energy and gas. Our modeling shows that our target aligns us, under many scenarios, with science-based target setting, which highlights the resilience of our business to 2 degrees of global warming. We have not officially validated a science-based target, but continue to monitor and model our future performance with the Sectoral Decarbonization Approach from the Science Based Target Initiative.

Aligned with our corporate strategy, our business units or operations consistently seek energy-efficiency improvements, development of emissions offset portfolios to achieve emissions reductions at competitive costs, and development of clean combustion technologies.

We seek investment in climate change related mitigation solutions, such as renewable energy development, where we can maximize value creation for our shareholders, local communities and the environment. Conversion of our large coal fleet to gas-fired generation highlights this approach, which will allow us to run our assets longer than the federally mandated coal retirement schedule. Our goals for undertaking such actions are to enhance value for our shareholders, ensure low-cost and reliable power for Albertans, and reduce the environmental impact from coal-fired generation.

Our investment and growth in renewable energy is highlighted by our diverse portfolio of renewable energy-generating assets. We currently operate over 2,200 MW of hydro, wind and solar power. We are one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta. Production from renewable energy in 2018 resulted in avoidance of approximately 2.9 million tonnes of CO ₂ e, which is equivalent to removing over 620,000 vehicles from North American roads over the same year. For further details on governance and risk, see the Governance and Risk Management section of this MD&A.

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Management’s Discussion and Analysis

Risk Management

Risks and opportunities are identified at the business unit level and through corporate functions (government relations, regulatory, emissions trading and sustainability). Furthermore, risks and opportunities are monitored through our Corporation-wide risk management processes and actively managed on a priority basis. As noted above risks and opportunities are reviewed by our executive team quarterly and reported to the Board GSSC and ARC, as applicable.

The following highlights identified climate change risk or opportunities, which have been assessed and integrated into business operations.



Risk or opportunity	Management approach
Policy requirements	TransAlta supports smart regulation and carbon pricing that ensures economic growth and certainty for investment. We have also demonstrated co-operation and collaboration on climate-related policy, while ensuring we protect value for employees and shareholders. This is evidenced by our Off-Coal Agreement with the Alberta Government, totallng $524 million and MOU to convert coal plants to gas. Further climate-related policy updates can be found in the Regional Regulation and Compliance subsection of this MD&A
Carbon pricing	Our Corporate function attributes regionally specific carbon pricing, both current and anticipated, as a mechanism to manage future risks pertaining to uncertainty in the carbon market and as a safeguard to anticipate future impacts of regulatory changes on facilities. This information is directed to the business unit level for further integration. Identified climate change risks or opportunities and carbon pricing are recognized in the annual TransAlta long-and-medium range forecasting processes. We capture economic profit from carbon markets through generation of renewable energy credits or offsets and via our emission trading function, which seeks to commoditize and profit from carbon trading.
New technology	We have demonstrated upside in growing renewables and gas-powered generation. From 2000 to 2018 we have grown renewables capacity from approximately 900 MW to over 2,200 MW. We have recently announced development of three wind projects, totaling over 330 MW of future capacity.
Adaptation and mitigation	Our clean power strategy means that all new investment must meet clean standards in order to mitigate potential future risk related to carbon policy and pricing. Our target is for 100 per cent of net generation capacity to be from gas and renewables capacity by 2025. Our coal-to-gas conversion plan in Alberta is an adaptive measure to climate change related policy. Using existing infrastructure significantly reduces capital costs compared with new gas builds and also results in the avoidance of approximately $15/MW in carbon-related pricing (assuming a $30 per tonne carbon price). Our new gas facility at South Hedland Power Station is built with adaptation in mind. The facility will operate with a best-in-class emission intensity, and the facility uses less water than traditional gas plants as we use dry cooling towers as opposed to the normal wet cooling towers (wet cooling towers have heavy water consumption). The plant is designed to withstand a category 5 cyclone, which can frequent the northwest region of Western Australia. Category 5 is the highest cyclone rating. Floods, which can occur in the area, have been mitigated by constructing the facility above the normal flood levels.
Water stress	Our thermal plants require water for operation. The majority of our thermal facilities are operated in low water stress environments. Our most water-stressed area of operation is at Sarnia; however, due to the nature of the operation, 98 per cent of water is recycled. The plant is a cogeneration facility. At all of our coal facilities we hold licences to pull water from low stressed areas. In Australia we purchase water for operations, and despite operating in remote locations, these areas are not currently water-stressed. Water purchasing will allow us to minimize local water stress if this becomes an issue. Our operating cost increase exposure due to water in Australia is low as our thermal operations are small.

Greenhouse Gas Emissions

In 2018, we estimate that 20.8 million tonnes of GHGs with an intensity of 0.77 tonnes per MWh (2017-29.9 million tonnes of GHGs with an intensity of 0.86 tonnes per MWh) were emitted as a result of normal operating activities. Our significant reduction in GHG emissions is the result of coal closures and reduced coal power generation from our Sundance facility in Alberta and increased co-firing with gas at our merchant coal facilities. Notably, our 2018 emissions reductions, supported achieving our 2021 target to reduce GHG emissions by 30 per cent over 2015 levels of 32.2 million tonnes CO ₂ e. This target was achieved well ahead of schedule and supports our clean power transition.

Our 2018 data are estimates based on best available data at the time of report production. GHGs include water vapour, CO ₂ , methane, nitrous oxide, sulphur hexafluoride, hydrofluorocarbons and perfluorocarbons. The majority of our estimated GHG emissions are comprised of CO ₂ emissions from stationary combustion. Emissions intensity data has been aligned with the “Setting Organizational Boundaries: Operational Control” methodology set out in The Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard developed by the World Resources Institute and the World Business Council for Sustainable Development. As per the methodology, TransAlta reports emissions on an operation control basis, which means that we report 100 per cent of emissions at facilities in which we are the operator. Emissions intensity is calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated facilities, regardless of financial ownership.

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Management’s Discussion and Analysis

The following are our GHG emissions in million tonnes CO ₂ :



Year ended Dec. 31	2018	2017	2016
Coal	18.3	27.4	27.7
Gas and renewables	2.4	2.5	3.0
Total GHG emissions	20.8	29.9	30.7

Our total GHG emissions include both scope 1 and scope 2 emissions. The GHG Protocol Corporate Standard classifies a company’s GHG emissions into three ‘scopes’. Scope 1 emissions are direct emissions from owned or controlled sources. Scope 2 emissions are indirect emissions from the generation of purchased energy. Scope 3 emissions are all indirect emissions (not included in scope 2) that occur in the value chain of the reporting company, including both upstream and downstream emissions. Scope 1 emissions in 2018 were estimated to be 20.6 million tonnes CO ₂ e. Scope 2 emissions were estimated to be 0.2 million tonnes CO ₂ e. We estimate our scope 3 emissions to be in the range of six million tonnes.

Future performance on GHG emissions will reduce as we retire or convert coal plants to gas and grow our renewable energy and gas fleet, while optimizing our existing fleet. Our target to is to reduce 60 per cent or 19.7 million tonnes of GHG emissions by 2030 over 2015 levels, which is line with UN Sustainable Development Goal ("SDG") Goal 13, Climate Action. Since 2015 we have reduced 9.1 million tonnes, which represents a reduction of 35 per cent.

The following highlights our longer-term track record on GHG emission reductions since 2005 and our projected emissions in 2030.

In 2018, TransAlta maintained its scoring on the Carbon Disclosure Project Climate Change investor request. Our overall score was a B, which places us as ahead of our peers when it comes to carbon disclosure, management, performance and leadership. In 2017 we were highlighted by the Chartered Professional Accountants of Canada (“CPA Canada”) as the only company in Canada, out of 75 companies, that reports on climate change across all levels of disclosure: the Annual Information Form, this MD&A and our information circular. Our 2016 Integrated Report was selected as a finalist for CPA Canada’s Award of Excellence in Corporate Reporting - of note, our Climate Change disclosure was highlighted as “outstanding” by CPA Canada judges.

Regional Regulation and Compliance

Climate change related legislation will continue to have an impact on our business. We work with governments and the public to develop appropriate frameworks that support our business, protect the environment and promote sustainable development. We are committed to complying with legislative and regulatory requirements and to minimizing the environmental impact of our operations.

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

Canadian Federal Government

On June 21, 2018, the Greenhouse Gas Pollution Pricing Act (GGPPA) was passed. Under this Act, the Canadian federal government implemented a national price on GHG emissions. The price will begin at $20 per tonne of CO ₂ e for emissions in 2019, rising by $10 per year, until reaching $50 per tonne in 2022.

On Jan. 1, 2019, the GGPPA’s “backstop” mechanisms came into effect for large emitters in jurisdictions that did not have an independent carbon pricing program or where the existing program was not deemed equivalent to the federal system - Ontario, Manitoba, New Brunswick, Saskatchewan, Prince Edward Island, Yukon and Nunavut. The backstop mechanism has two components: a carbon levy for small emitters and regulation for large emitters called the Output-Based Pricing System (OBPS). The carbon levy sets a carbon price per tonne of GHG emissions related to transportation fuels, heating fuels and other small emission sources.

The OBPS is an intensity-based standard where large emitters must meet an industry specific emission intensity performance standard per unit of production. A large emitter’s emission intensity per unit of product must meet their

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Management’s Discussion and Analysis

industry’s OBPS intensity performance standard. If the facility's emission intensity is below or above the performance standard, the facility will generate carbon credits or carbon obligations equal to the difference between the industry’s emission intensity performance standard and the regulated facility’s emission intensity.

Federal Gas R egulation

On Dec. 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity . Under the regulation, new and significantly modified natural-gas-fired electricity facilities with a capacity greater than 150 MWs must meet a standard of 420 tCO ₂ e per gigawatt hour (tCO ₂ e/GWh) to operate. Units with a capacity of between 25 MW and 150 MW must meet a standard of 550 tCO ₂ e/GWh.

The rules for converted units will allow the plants to operate for a set number of years following the end-of-life for the unit under the coal regulations based on a one-time performance test at the time of conversion. For our units, these rules are expected to provide 8 or 10 additional years of operating life to each of our units.

Federal Coal R egulation

On Dec. 18, 2018, amendments to the Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity Regulations came into force under the Canadian Environmental Protection Act , 1999. The amended regulations will require coal units to meet an emission level of 420 tCO2e/GWh by the earlier of end-of-life under the 2012 regulations or Dec. 31, 2029.

Alberta

On November 22, 2015, the Government of Alberta announced the Alberta Climate Leadership Plan. The government has now largely delivered on its commitments through legislation to require:


▪	the elimination of coal generation by 2030;

▪

the creation of the Renewable Energy Program (REP) to meet the commitment that renewables account for 30 per cent of Alberta's electricity system by 2030. Under the REP, the system operator, the AESO, is tasked with running procurement processes for government approved volumes of renewable power. To date, the AESO has run three separate Requests for Proposals (RFP). The RFPs have resulted in 20-year contracts for approximately 1,360 MWs of wind power projects. These projects are scheduled to be grid integrated between 2019 and 2021;


▪	the Carbon Competitiveness Incentive Regulation (CCIR) replaces the previous large emitters regulation, Specified Gas Emitters Regulation (SGER), moving from a facility-specific compliance standard to a product or sector performance compliance standard; and


▪	a carbon levy was introduced on most carbon emissions not covered by the CCIR.

On Jan. 1, 2018, the Alberta government transitioned from the SGER to the CCIR. Under the CCIR, the regulatory compliance moved from a facility-specific compliance standard to a product or sector performance compliance standard. Currently, the provincial government has announced that the carbon price will remain at $30/tCO ₂ e going forward and will not increase to the federally mandated price increase of $40/tCO ₂ e in 2021 and $50/tCO2e in 2022; however, increases may be implemented by the federal government under their program equivalency review. The electricity sector performance standard was set at 370 tCO ₂ e/GWh but will decline over time. All renewable assets that received crediting under the SGER will continue to receive credits under CCIR on a one-to-one basis. All other renewables that did not receive credits under the previous standards will now be able to opt in to the CCIR and get carbon crediting up to the electricity sector performance standard in perpetuity. Once wind projects' crediting under SGER protocol ends, these projects will also be able to opt in to the CCIR system and be credited up to the performance standard for the rest of their operational life.

British Columbia

Beginning April 1, 2018, BC increased its carbon tax rate to $35/tCO ₂ e and committed to raise the price $5 per year until it reaches $50 per tonne in 2021.

Ontario

On Oct. 31, 2018, the Ontario government passed the Cap and Trade Cancellation Act . This Act removed all existing provincial carbon emission regulations and costs on large emitters.

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Management’s Discussion and Analysis

The Canadian federal Greenhouse Gas Pollution Pricing Act requires provinces to have GHG gas regulations and prices in place that align with the federal GGPPA. On Oct. 23, the federal government announced that the federal program would be implemented in Ontario as of Jan. 1, 2019. Small em itters will face a carbon levy and large emitters, under covered industries, with annual GHG emission greater than 50,000 tCO ₂ e will be subject to the OBPS. Ontario is now subject to the federal government’s backstop carbon levy price for small emitters and the OBPS for large emitters.

On Nov. 29th, 2018, the Ontario government unveiled a new climate change policy called Preserving and Protecting our Environment for Future Generations: A Made-In-Ontario Environment Plan. The plan aims to keep the province working toward meeting the emissions-reduction goal of achieving 30 per cent reduction of 2005 levels by 2030. The plan commits to developing emission performance standards to achieve reductions from large emitters and references Saskatchewan’s OBPS as an example. The government has indicated that it will be consulting and developing the program in 2019. The plan's specifics related to the electricity sector have not yet been defined and are expected to be determined through the program development process.

Australia

On Dec. 13, 2014, the Australian government enacted legislation to implement the Emissions Reduction Fund (the "ERF"). The AUD 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 and 26 to 28 per cent below 2005 emissions by 2030.

The ERF's safeguard mechanism, commencing from July 1, 2016, is designed to 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.

In addition, on June 23, 2015, the federal Australian government also reformed the Renewable Energy Target ("RET") scheme. The RET should add at least 33,000 gigawatt-hours (GWh) of renewable sources by 2020. This would double the amount of large-scale renewable energy being delivered compared to current levels and result in approximately 23.5 per cent of Australia's electricity generation being sourced from renewable projects.

Pacific Northwest

In 2010, the Washington Governor's office and Ecology negotiated agreements with TransAlta related to the operation of Centralia’s two coal power electricity generating units. TransAlta agreed to retire its two Centralia coal units - one in 2020 and the other in 2025. This agreement is formally part of the state’s climate change program. We currently believe that there will be no additional GHG regulatory burden on US Coal given these commitments. The related TransAlta Energy Transition Bil l was signed into law in 2011 and provides a framework to transition from coal to other forms of generation in the State of Washington.

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Management’s Discussion and Analysis

2018 Sustainability Performance

Stakeholder Communication and Value Creation

The information in this section seeks to highlight our ability to create value for investors, stakeholders and society in the short, medium and long term. The selection of key information and key metrics disclosed in this integrated report and our full sustainability disclosures follow a materiality assessment process, which identifies key impact areas to our stakeholders. We subsequently are guided by, and place focus on, reporting on these key areas.

Sustainability Targets and Results

Sustainability targets are strategic goals that support the long-term success of our business. Targets are set in line with business unit goals to manage key areas of concern for stakeholders and ultimately improve our environmental and social performance in these areas.



2018 Sustainability Targets
	Financial	Results	Comments
1. Maintain our investment grade rating	Achieve and maintain investment grade credit metrics	Partly achieved	TransAlta maintains investment grade ratings from three out of four rating agencies: S&P (BBB-) negative outlook, DBRS (BBB low) stable outlook, and Fitch (BBB-) stable outlook.

2. Increase focus on FFO and EBITDA	Deliver comparable EBITDA and FFO in the range of $1,000 million to $1,050 million and $750 million to $800 million, respectively ⁽¹⁾	Achieved	For the year ended Dec. 31, 2018, adjusted comparable EBITDA was $988 million and adjusted FFO was $770 million. Comparable EBITDA was adjusted to remove the impact of unrealized mark-to-market gains or losses. Additionally, Comparable EBITDA and FFO were adjusted to remove the $157 million for the termination of Sundance B and C PPAs as this was not included in the targets.



	Human and Intellectual	Results	Comments
3. Reduce safety incidents	Achieve an Injury Frequency Rate below 0.53	Mostly Achieved	Although we narrowly missed our target, we achieved one of our lowest IFRs in our history. Our 2018 IFR was 0.54, a 25 per cent improvement over 2017 performance
	Achieve a Total Incident Frequency rate below 2.83	Achieved	Our 2018 TIF was 1.98, a 25 per cent improvement over 2017 performance

4. Human resources	Maintain voluntary turnover percentage under eight per cent	Not achieved	Our voluntary turnover in 2018 was 20 per cent. We seek to maintain voluntary turnover or attrition under eight per cent as this is considered a healthy amount of attrition for a corporation. As we transition away from coal-fired generation and its associated jobs we face significant workforce challenges with retention

5. Support employee development	Continue development plans for all high-potential employees at the top three levels of the organization	Achieved	In 2018, we completed a six-month (peer-led) leadership training program, called Elevate, for our high-potential employees at the top three levels of the organization. The program was focused on establishing a learner’s mindset, building trust and influence, strengths-based leadership, being transparent, providing feedback, collaboration as a team and innovation

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Management’s Discussion and Analysis



	Natural	Results	Comments
6. Minimize fleet-wide environmental incidents	Keep recorded incidents (including spills and air infractions) below 9	Achieved	We recorded seven significant environmental incidents in 2018, none of which had a material environmental impact. This was below our target of nine, but was a 40 per cent increase over 2017 performance

7. Increase mine reclaimed acreage	Replace annual topsoil rate at Highvale mine at a rate of 74 acres/year	Not achieved	Due to weather conditions, not all topsoil was placed to fully meet our target. Top Soil is the last stage of reclamation, despite weather constraints, we did manage to complete 28 acres. Instead, we reallocated resources to other stages of reclamation to move other areas closer to final reclamation (such as ground leveling). Overall we reduced reclamation spend by $2.1 million and maintained progress towards our long-range reclamation plan


9. Reduce air emissions	Achieve a 95 per cent reduction from 2005 levels of TransAlta coal facility NOx and SO ₂ emissions by 2030	On track	We are well underway and on track to achieve our target of 95 per cent emission reductions of SO ₂ and NOx by 2030. Since 2005, we have reduced NOx emissions by 58 per cent and SO ₂ emissions by 72 per cent. In 2018 we reduced approximately 16,000 tonnes of NOx emissions and 17,000 tonnes of SO ₂ emissions over 2017 levels

10. Reduce GHG emissions	a) Our goal is to reduce our total GHG emissions in 2021 to 30 per cent below 2015 levels, in line with a commitment to the UN SDGs	Achieved	We achieved this target in 2018, well ahead of our target for 2021. In 2018 we reduced approximately 9.1 million tonnes of CO ₂ e over 2017 levels due to reduced coal power generation from our Sundance facility and co-firing at our merchant coal facilities

	b) Our goal is to reduce our total GHG emissions in 2030 to 60 per cent below 2015 levels, in line with a commitment to the UN SDGs and to prevent two degrees Celsius of global warming	On track	We are well underway and on track to achieve our target of 60 per cent GHG emission reductions by 2030. Since 2015, we have reduced emissions by 36 per cent. In 2018 we reduced approximately 9.1 million tonnes of CO ₂ e over 2017 levels

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Management’s Discussion and Analysis



	Social and Relationship	Results	Comments
11. Support quality education for youth	Support equal access to all levels of education for youth and Indigenous peoples	Achieved	TransAlta provides an Aboriginal bursary to support education for Indigenous peoples that includes bursaries for both trades and post-secondary. TransAlta’s criteria for accessing the bursary are open to any educational pursuit that will support the well being of Indigenous peoples and communities. The bursary is open to all Indigenous applicants that have completed high school. TransAlta has also created a Indigenous Gap program with SAIT to give support to Indigenous students where it is needed.
Our education goal and targets support UN SDG Goal 4: Quality Education related to ensuring “inclusive and equitable quality education” and related to “eliminating gender disparities in education”	Direct approximately $0.75 million of community investment spending to youth education	Achieved	Our community investments have supported the University of Calgary, Southern and Northern Alberta Institute of Technology, Mount Royal University, Banff Centre for Arts and Creativity (Indigenous leadership scholarships), Mother Earth Children's Charter School (Indigenous kindergarten to Grade 9), Calgary Stampede (The Young Canadians - ages 7 to 18), national Canada and US Indigenous scholarships (post-secondary for trades and academic) and the Alberta Council for Environmental Education
12. Increase internal best practice Aboriginal engagement awareness	Develop sustainability and Indigenous engagement materials for integration within our developmental leadership programs at TransAlta	Achieved	An Indigenous Awareness presentation was developed, that includes historical facts and basic concepts around consultation and engagement, which will be shared with all employees. The same presentation will be used at the Schulich School of Engineering at the University of Calgary in 2018 for one of their ethics courses

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Management’s Discussion and Analysis



	Comprehensive	Results	Comments
13. TransAlta will be a leading clean power company by 2030	By 2022, we will convert six coal plant units from coal-fired generation to gas-fired generation	On track	In 2018 we exercised our option to acquire a 50 per cent ownership in the Pioneer Pipeline connecting Tidewater's Brazeau River Complex to TransAlta's generating units at Sundance and Keephills. Our investment is subject to regulatory approval
Our clean power goal and targets support the UN SDG Goal 7: Affordable and Clean Energy related to ensuring “access to affordable, reliable, sustainable and modern energy”	By 2025, 100 per cent of our owned asset company-wide net generation capacity will be from gas and renewables	On track	We continued our coal-to-gas transition plans in 2018, while announcing new renewable energy growth projects. Please see above and below for more detail.
	We will continue to seek new opportunities to grow our portfolio of 2,265 MW wind, hydro and solar assets	Achieved	In 2018 we announced development of three wind development projects, totaling over 320 MW of additional renewable energy capacity. Projects include a 90 MW wind facility in Pennsylvania (US), a 29 MW wind facility in New Hampshire (US) and a 207 MW wind facility in Alberta (Canada)
	Continue to explore viability of the Brazeau 900 MW pumped hydro expansion – doubling our hydro capacity in Alberta	Not achieved	In May 2018, the AESO released a report stating that dispatchable renewable resources are not needed in the Alberta market before 2030. The value and benefit of the Brazeau Hydro Pumped Storage project would be well beyond the 2030 period. The Corporation still believes that generation from pumped storage should be part of future calls for power under the Alberta Renewable Electricity Program . The Corporation is not spending additional development dollars on the project at this time, but will continue to work with governments to find the appropriate financial mechanisms for bringing low-cost, green, dispatchable renewables into the market to support low prices and emissions for Alberta customers

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Management’s Discussion and Analysis

2019 Sustainable Development Targets

Our 2019 and longer-term sustainability targets support the long-term success of our business. Targets are set in line with business unit goals to manage key areas of concern for stakeholders and ultimately improve our environmental and social performance in these areas. We continue to evolve and adapt targets to focus on anticipated key areas of materiality to stakeholders. Targets are outlined below:



	Human and Intellectual	Annual Performance Status
1. Reduce safety incidents	Achieve an Injury Frequency Rate below 0.43	20 per cent improvement over 2018 performance (0.54)
1. Reduce safety incidents	Achieve a Total Incident Frequency Rate below 1.58	20 per cent improvement over 2018 performance (1.98)

		Annual Performance Status
2. Minimize fleet-wide environmental incidents	Keep recorded incidents (including spills and air infractions) below five	44 per cent improvement over 2018 target
3. Increase mine reclaimed acreage	Replace annual topsoil at Highvale mine at a rate of 110 acres/year	57 per cent increase over 2018 target (70 acres)
4. Reduce air emissions	Achieve a 95 per cent reduction from 2005 levels of TransAlta SO ₂ emissions and 50 per cent reduction in NOx emissions by 2030	Revised NOx target to align with coal-to-gas conversion strategy and growth in gas estimations
5. Reduce GHG emissions Our GHG goal and targets support UN SDG Goal 13: Climate Action related to ensuring “integrate climate change measures into national policies, strategies and planning."	Our goal is to reduce our total GHG emissions in 2030 to 60 per cent below 2015 levels, in line with a commitment to the UN SDGs and prevention of two degrees Celsius of global warming (our GHG and clean power targets assume reasonably anticipated growth and operating scenarios)	Consistent with 2018


	Social and Relationship	Annual Performance Status
6. Support quality education for youth	Support equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunities	Consistent with 2018 target
Our education goal and target support UN SDG Goal 4: Quality Education related to ensuring “inclusive and equitable quality education” and related to “eliminating gender disparities in education”

	Comprehensive	Annual Performance Status
7. TransAlta will be a leading clean power company by 2025	Convert at least two coal units at Sundance, Alberta and three coal units at Keephills, Alberta to gas-fired generation in the 2020 to 2023 time frame	Revised 2018 target
Our clean power goal and targets support the UN SDG Goal 7: Affordable and Clean Energy related to ensuring “access to affordable, reliable, sustainable and modern energy”	Aim that by 2025, 100 per cent of our owned net generation capacity will be from clean power (renewables and gas)	Consistent with 2018 target
	Seek new opportunities to grow our renewable portfolio of 2,265 MW wind, hydro and solar assets	Consistent with 2018 target

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Management’s Discussion and Analysis

Governance and Risk Management

Our business activities expose us to a variety of risks and opportunities including, but not limited to, regulatory changes, rapidly changing market dynamics, and increased volatility in our key commodity markets. Our goal is to manage these risks and opportunities so that we are in position to develop our business and achieve our goals while remaining reasonably protected from an unacceptable level of risk or financial exposure. We use a multilevel risk management oversight structure to manage the risks and opportunities arising from our business activities, the markets in which we operate, and the political environments and structures with which we interface.

Governance

The key elements of our governance practices are:


▪	employees, management and the Board are committed to ethical business conduct, integrity, and honesty;


▪	we have established key policies and standards to provide a framework for how we conduct our business;


▪	the Chair of our Board and all directors, other than our President and Chief Executive Officer (“CEO”) are independent;


▪	the Board is comprised of individuals with a mix of skills, knowledge and experience that are critical for our business and our strategy;


▪	the effectiveness of the Board is achieved through robust annual evaluations and continuing education of our directors; and


▪	our management and Board facilitate and foster an open dialogue with shareholders and community stakeholders.

Commitment to ethical conduct is the foundation of our corporate governance model. We have adopted the following codes of conduct to guide our business decisions and everyday business activities:


▪	Corporate Code of Conduct, which applies to all employees and officers of TransAlta and its subsidiaries,


▪	Directors’ Code of Conduct,


▪	Supplier's Code of Conduct,


▪	Finance Code of Ethics, which applies to all financial employees of the Corporation, and


▪	Energy Trading Code of Conduct, which applies to all of our employees engaged in energy marketing.

Our codes of conduct outline the standards and expectations we have for our employees, officers, directors, consultants and suppliers with respect to, among other things, the protection and proper use of our assets. The codes also provide guidelines with respect to securing our assets, avoiding conflicts of interest, respect in the workplace, social responsibility, privacy, compliance with laws, insider trading, environment, health and safety, and our commitment to ethical and honest conduct. Our Corporate Code of Conduct and Directors' Code of Conduct each goes beyond the laws, rules, and regulations that govern our business in the jurisdictions in which we operate; it outlines the principal business practices with which all employees and directors must comply.

Our employees, officers and directors are reminded annually about the importance of ethics and professionalism in their daily work, and must certify annually that they have reviewed and understand their responsibilities as set forth in the respective codes of conduct. This certification also requires our employees, officers and directors to acknowledge that they have complied with the standards set out in the respective code during the last calendar year.

The Board provides stewardship of the Corporation and ensures that the Corporation establishes key policies and procedures for the identification, assessment and management of principal risks and strategic plans. The Board monitors and assesses the performance and progress of the Corporation’s goals through candid and timely reports from the CEO and the senior management team. We have also established an annual evaluation process whereby our directors are provided with an opportunity to evaluate the Board, Board committees, individual directors and the Chair’s performance.

In order to allow the Board to establish and manage the financial, environmental, and social elements of our governance practices, the Board has established the Audit and Risk Committee (“ARC”), the Governance, Safety and Sustainability Committee ("GSSC"), and the Human Resources Committee (the “HRC”).

The ARC , consisting of independent members of the Board, provides assistance to the Board in fulfilling its oversight responsibility relating to the integrity of our consolidated financial statements and the financial reporting process; the systems of internal accounting and financial controls; the internal audit function; the external auditors’ qualifications and terms and conditions of appointment, including remuneration; independence; performance and reports; and the legal and risk compliance programs as established by management and the Board. The ARC approves our Commodity and Financial Exposure Management policies and reviews quarterly Enterprise Risk Management reporting.

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Management’s Discussion and Analysis

The GSSC is responsible for developing and recommending to the Board a set of corporate governance principles applicable to the Corporation and for monitoring the compliance with these principles. The GSSC is also responsible for Board recruitment, succession planning and for the nomination of directors to the Board and its committees. In addition, the GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Corporation’s monitoring of environmental, health and safety regulations and public policy changes and the establishment and adherence to environmental, health and safety practices, procedures and policies. The GSSC also receives an annual report on the annual codes of conduct certification process.

In regards to overseeing and seeking to ensure that the Corporation consistently achieves strong environment, health and safety (“EH&S”) performance, the GSSC undertakes a number of actions that include: i) receiving regular reports from management regarding environmental compliance, trends, and TransAlta’s responses; ii) receiving reports and briefings on management’s initiatives with respect to changes in climate change legislation, policy developments as well as other draft initiatives and the potential impact such initiatives may have on our operations; iii) assessing the impact of the GHG policies implementation and other legislative initiatives on the Corporation’s business; iv) reviewing with management the EH&S policies of the Corporation; v) reviewing with management the health and safety practices implemented within the Corporation, as well as the evaluation and training processes put in place to address problem areas; vi) receiving reports from management on the near-miss reporting program and discussing with management ways to improve the EH&S processes and practices; and vi) reviewing the effectiveness of our response to EH&S issues and any new initiatives put in place to further improve the Corporation’s EH&S culture.

The HRC is empowered by the Board to review and approve key compensation and human resources policies of the Corporation that are intended to attract, recruit, retain and motivate employees of the Corporation. The HRC also makes recommendations to the Board regarding the compensation of the Corporation’s CEO, including the review and adoption of equity-based incentive compensation plans, the adoption of human resources policies that support human rights and ethical conduct, and the review and approval of executive management succession and development plans.

The responsibilities of other stakeholders within our risk management oversight structure are described below:

The CEO and senior management review and report on key risks quarterly. Specific Trading Risk Management reviews are held monthly by the Commodity and Compliance Risk Committee, and weekly by the Managing Director Commodity Risk, the commercial managing directors in Trading and Marketing, and the Senior Vice-President Trading and Marketing.

The Investment Committee is chaired by our Chief Financial Officer and is comprised of the CEO, Chief Financial Officer, Chief Legal and Compliance Officer and Corporate Secretary, and Chief Investment Officer. It reviews and approves all major capital expenditures including growth, productivity, life extensions and major coal outages. Projects that are approved by the Committee will then be put forward for approval by the Board, if required.

The Commodity Risk & Compliance Committee is chaired by our Senior Vice-President of Business Development and is comprised of the Chief Financial Officer, Chief Legal and Compliance Officer, Senior Vice-President of Business Development and Managing Director & Corporate Controller. It oversees the risk and compliance program in trading and ensures that this program is adequately resourced to monitor trading operations from a risk and compliance perspective. It also ensures the existence of appropriate controls, processes, systems and procedures to monitor adherence to policy.

TransAlta is listed on the TSX and the New York Stock Exchange and is subject to the governance regulations, rules and standards applicable under both exchanges. Our corporate governance practices meet the following governance rules of the TSX and Canadian Securities Administrators: i) Multilateral Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings; ii) National Instrument 52-110 Audit Committees; iii) National Policy 58-201 Corporate Governance Guidelines; and iv) National Instrument 58-101 Disclosure of Corporate Governance Practices. As a “foreign private issuer” under US securities laws, we are generally permitted to comply with Canadian corporate governance requirements. Additional information regarding our governance practices can be found in our management information circular.

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Management’s Discussion and Analysis

Risk Controls

Our risk controls have several key components:

Enterprise Tone

We strive to foster beliefs and actions that are true to, and respectful of, our many stakeholders. We do this by investing in communities where we live and work, operating and growing sustainably, putting safety first, and being responsible to the many groups and individuals with whom we work.

Policies

We maintain a comprehensive set of enterprise-wide policies. These policies establish delegated authorities and limits for business transactions, as well as allow for an exception approval process. Periodic reviews and audits are performed to ensure compliance with these policies. All employees and directors are required to sign a code of conduct on an annual basis.

Reporting

On a regular basis, residual risk exposures are reported to key decision-makers including the Board, the ARC, senior management, and/or the Commodity Risk & Compliance Committee, as applicable. Reporting to this latter committee includes analysis of new risks, monitoring of status to risk limits, review of events that can affect these risks, and discussion and review of the status of actions to minimize risks. This quarterly reporting provides for effective and timely risk management and oversight.

Whistleblower System

We have a process in place where employees, contractors, shareholders or other stakeholders may confidentially or anonymously report any potential legal or ethical concerns, including concerns relating to accounting, internal control accounting, auditing or financial matters or relating to alleged violations of our codes of conduct. These concerns can be submitted confidentially and anonymously, either directly to the ARC or through TransAlta’s toll-free telephone or online Ethics Helpline. The ARC Chair is immediately notified of any material complaints and, otherwise, the ARC receives a report at every quarterly committee meeting on all findings related to any material complaints or complaints relating to accounting or financial reporting or alleged breaches in internal controls over financial reporting.

Value at Risk and Trading Positions

Value at risk (“VaR”) is one of the primary measures used to manage our exposure to market risk resulting from commodity risk management activities. VaR is calculated and reported on a daily basis. This metric describes the potential change in the value of our trading portfolio over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations.

VaR is a commonly used metric that is employed by industry to track the risk in commodity risk management positions and portfolios. Two common methodologies for estimating VaR are the historical variance/covariance and Monte Carlo approaches. We estimate VaR using the historical variance/covariance approach. An inherent limitation of historical variance/covariance VaR is that historical information used in the estimate may not be indicative of future market risk. Stress tests are performed periodically to measure the financial impact to the trading portfolio resulting from potential market events, including fluctuations in market prices, volatilities of those prices and the relationships between those prices. We also employ additional risk mitigation measures. VaR at Dec. 31, 2018 , associated with our proprietary commodity risk management activities was $2 million ( 2017 - $5 million). Refer to the Commodity Price Risk section of this MD&A for further discussion.

Risk Factors

Risk is an inherent factor of doing business. The following section addresses some, but not all, risk factors that could affect our future plans, performance, results or outcomes and our activities in mitigating those risks. These risks do not occur in isolation, but must be considered in conjunction with each other. For a further discussion of risk factors affecting the Corporation, readers are encouraged to read the Risk Factors section of our Annual Information Form for the year ended Dec. 31, 2018 , available on our website at www.transalta.com and under our profile on SEDAR at www.sedar.com and on EDGAR at www.edgar.gov.

For some risk factors we show the after-tax effect on net earnings of changes in certain key variables. The analysis is based on business conditions and production volumes in 2018 . Each item in the sensitivity analysis assumes all other potential variables are held constant. While these sensitivities are applicable to the period and the magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances, or for a greater magnitude of changes. The changes in rates should also not be assumed to be proportionate to earnings in all instances.

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Management’s Discussion and Analysis

Volume Risk

Volume risk relates to the variances from our expected production. For example, the financial performance of our Hydro, Wind and Solar operations is partially dependent upon the availability of their input resources in a given year. Where we are unable to produce sufficient quantities of output in relation to contractually specified volumes, we may be required to pay penalties or purchase replacement power in the market.

We manage volume risk by:


▪	actively managing our assets and their condition in order to be proactive in plant maintenance so that our plants are available to produce when required;


▪	monitoring water resources throughout Alberta to the best of our ability and optimizing this resource against real-time electricity market opportunities;


▪	placing our facilities in locations we believe to have adequate resources to generate electricity to meet the requirements of our contracts. However, we cannot guarantee that these resources will be available when we need them or in the quantities that we require; and


▪	diversifying our fuels and geography to mitigate regional or fuel-specific events.

The sensitivity of volumes to our net earnings is shown below:



Factor	Increase or decrease (%)	Approximate impact on net earnings
Availability/production	1	9

Generation Equipment and Technology Risk

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 the Corporation. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. Our plants are exposed to operational risks such as failures due to cyclic, thermal, and corrosion damage in boilers, generators, and turbines, and other issues that can lead to outages and increased volume risk. If plants do not meet availability or production targets specified in their PPA or other long-term contracts, we may be required to compensate the purchaser for the loss in the availability of production or record reduced energy or capacity payments. For merchant facilities, an outage can result in lost merchant opportunities. Therefore, an extended outage could have a material adverse effect on our business, financial condition, results of operations or our cash flows.

As well, we are exposed to procurement risk for specialized parts that may have long lead times. If we are unable to procure these parts when they are needed for maintenance activities, we could face an extended period where our equipment is unavailable to produce electricity.

We manage our generation equipment and technology risk by:


▪	operating our generating facilities within defined and proven operating standards that are designed to maximize the availability of our generating facilities for the longest period of time;


▪	performing preventive maintenance on a regular basis;


▪	adhering to a comprehensive plant maintenance program and regular turnaround schedules;


▪	adjusting maintenance plans by facility to reflect the equipment type and age;


▪	having sufficient business interruption coverage in place in the event of an extended outage;


▪	having force majeure clauses in our thermal and other PPAs and other long-term contracts;


▪	using proven technology in our generating facilities;


▪	monitoring technological advances and evaluating their impact upon our existing generating fleet and related maintenance programs;


▪	negotiating strategic supply agreements with selected vendors to ensure key components are available in the event of a significant outage;


▪	entering into long-term arrangements with our strategic supply partners to ensure availability of critical spare parts; and


▪	developing a long-term asset management strategy with the objective of maximizing the life cycles of our existing facilities and/or replacing of selected generating assets.

Commodity Price Risk

We have exposure to movements in certain commodity prices, including the market price of electricity and fuels used to produce electricity in both our electricity generation and proprietary trading businesses.

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Management’s Discussion and Analysis

We manage the financial exposure associated with fluctuations in electricity price risk by:


▪	entering into long-term contracts that specify the price at which electricity, steam and other services are provided;


▪	maintaining a portfolio of short-, medium- and long-term contracts to mitigate our exposure to short-term fluctuations in commodity prices;


▪	purchasing natural gas coincident with production for merchant plants so spot market spark spreads are adequate to produce and sell electricity at a profit; and


▪	ensuring limits and controls are in place for our proprietary trading activities.

In 2018 , we had approximately 85 per cent ( 2017 - 92 per cent) of production under short-term and long-term contracts and hedges. In the event of a planned or unplanned plant outage or other similar event, however, we are exposed to changes in electricity prices on purchases of electricity from the market to fulfil our supply obligations under these short- and long-term contracts.

We manage the financial exposure to fluctuations in the cost of fuels used in production by:


▪	entering into long-term contracts that specify the price at which fuel is to be supplied to our plants;


▪	hedging emissions costs by entering into various emission trading arrangements; and


▪	selectively using hedges, where available, to set prices for fuel.

In 2018 , 67 per cent ( 2017 - 57 per cent) of our cost of gas used in generating electricity was contractually fixed or passed through to our customers and 85 per cent ( 2017 - 83 per cent) of our purchased coal costs were contractually fixed.

Actual variations in net earnings can vary from calculated sensitivities and may not be linear due to optimization opportunities, co-dependencies and cost mitigations, production, availability and other factors.

Coal Supply Risk

Having sufficient fuel available when required for generation is essential to maintaining our ability to produce electricity under contracts and for merchant sale opportunities. At our coal-fired plants, input costs such as diesel, tires, the price and availability of mining equipment, the volume of overburden removed to access coal reserves, rail rates and the location of mining operations relative to the power plants are some of the exposures in our operations. Additionally, the ability of the mines to deliver coal to the power plants can be impacted by weather conditions and labour relations. At US Coal, interruptions at our supplier’s mine, the availability of trains to deliver coal and the financial viability of our coal suppliers could affect our ability to generate electricity.

We manage coal supply risk by:


▪	ensuring that the majority of the coal used in electrical generation in Alberta is from reserves permitted through coal rights we have purchased or for which we have long-term supply contracts, thereby limiting our exposure to fluctuations in the supply of coal from third parties;


▪	using longer-term mining plans to ensure the optimal supply of coal from our mines;


▪	sourcing the majority of the coal used at US Coal under a mix of short-, medium-, and long-term contracts and from multiple mine sources to ensure sufficient coal is available at a competitive cost;


▪	contracting sufficient trains to deliver the coal requirements at US Coal;


▪	ensuring coal inventories on hand at Canadian Coal and US Coal are at appropriate levels for usage requirements;


▪	ensuring efficient coal handling and storage facilities are in place so that the coal being delivered can be processed in a timely and efficient manner;


▪	monitoring and maintaining coal specifications, and carefully matching the specifications mined with the requirements of our plants;


▪	co-firing natural gas with coal;


▪	monitoring the financial viability of US coal suppliers; and


▪	hedging diesel exposure in mining and transportation costs.

Environmental Compliance Risk

Environmental compliance risks are risks to our business associated with existing and/or changes in environmental regulations. New emission reduction objectives for the power sector are being established by governments in Canada (including as set forth in the Alberta Climate Leadership Plan) and the US. We anticipate continued and growing scrutiny by investors and other stakeholders relating to sustainability performance. These changes to regulations may affect our earnings by reducing the operating life of generating facilities, imposing additional costs on the generation of electricity, such as emission caps or tax, requiring additional capital investments in emission capture technology, or requiring us to

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Management’s Discussion and Analysis

invest in offset credits. It is anticipated that these compliance costs will increase due to increased political and public attention to environmental concerns.

We manage environmental compliance risk by:


▪	seeking continuous improvement in numerous performance metrics such as emissions, safety, land and water impacts, and environmental incidents;


▪


▪	having an International Organization for Standardization and Occupational Health and Safety Assessment Series-based environmental health and safety management system in place that is designed to continuously improve performance;


▪


▪	committing significant experienced resources to work with regulators in Canada and the US to advocate that regulatory changes are well designed and cost effective;


▪


▪	developing compliance plans that address how to meet or surpass emission standards for GHGs, mercury, SO 2 , and NOx, which will be adjusted as regulations are finalized;


▪


▪	purchasing emission reduction offsets;


▪


▪	investing in renewable energy projects, such as wind, solar and hydro generation; and


▪


▪	incorporating change-in-law provisions in contracts that allow recovery of certain compliance costs from our customers.

We strive to be in compliance with all environmental regulations relating to operations and facilities. Compliance with both regulatory requirements and management system standards is regularly audited through our performance assurance policy and results are reported quarterly to the GSSC.

Credit Risk

Credit risk is the risk to our business associated with changes in the creditworthiness of entities with which we have commercial exposures. This risk results from the ability of a counterparty to either fulfil its financial or performance obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect cash due to us or to receive products or services may have an adverse impact upon our net earnings and cash flows.

We manage our exposure to credit risk by:


▪	establishing and adhering to policies that define credit limits based on the creditworthiness of counterparties, contract term limits and the credit concentration with any specific counterparty;


▪


▪	requiring formal sign-off on contracts that include commercial, financial, legal and operational reviews;


▪


▪	requiring security instruments, such as parental guarantees, letters of credit, and cash collateral or third-party credit insurance if a counterparty goes over its limits. Such security instruments can be collected if a counterparty fails to fulfil its obligation; and


▪


▪	reporting our exposure using a variety of methods that allow key decision-makers to assess credit exposure by counterparty. This reporting allows us to assess credit limits for counterparties and the mix of counterparties based on their credit ratings.

If established credit exposure limits are exceeded, we take steps to reduce this exposure, such as by requesting collateral, if applicable, or by halting commercial activities with the affected counterparty. However, there can be no assurances that we will be successful in avoiding losses as a result of a contract counterparty not meeting its obligations.

Our credit risk management profile and practices have not changed materially from Dec. 31, 2017 . We had no material counterparty losses in 2018 . We continue to keep a close watch on changes and trends in the market and the impact these changes could have on our energy trading business and hedging activities, and will take appropriate actions as required, although no assurance can be given that we will always be successful.

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Management’s Discussion and Analysis

The following table outlines our maximum exposure to credit risk without taking into account collateral held or right of set-off, including the distribution of credit ratings, as at Dec. 31, 2018 :



	Investment grade (Per cent)	Non-investment grade (Per cent)	Total (Per cent)	Total amount
Trade and other receivables ⁽¹⁾	86	14	100	731
Long-term finance lease receivables	100	—	100	191
Risk management assets ⁽¹⁾	99	1	100	808
Loan receivable ⁽²⁾	—	100	100	77
Total				1,807

(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.

(2) The counterparties have no external credit ratings.

The maximum credit exposure to any one customer for commodity trading operations, including the fair value of open trading positions net of any collateral held, is $13 million ( 2017 - $40 million ).

Currency Rate 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 and foreign-denominated commodities from foreign suppliers, and our US-denominated debt. Our exposures are primarily to the US and Australian currencies. Changes in the values of these currencies in relation to the Canadian dollar may affect our earnings or the value of our foreign investments to the extent that these positions or cash flows are not hedged or the hedges are ineffective.

We manage our currency rate risk by establishing and adhering to policies that include:


▪	hedging our net investments in US operations using US-denominated debt;


▪


▪	entering into forward foreign exchange contracts to hedge future foreign-denominated expenditures including our US-denominated debt that is outside the net investment portfolio; and


▪

▪

hedging our expected foreign operating cash flows. Our target is to hedge a minimum of 60 per cent of our forecasted foreign operating cash flows over a four-year period, with a minimum of 90 per cent in the current year, 70 per cent in the next year, 50 per cent in the third year and 30 per cent in the fourth year. The US exposure will be managed with a combination of interest expense on our US-denominated debt and forward foreign exchange contracts; the Australian exposure will be managed with forward foreign exchange contracts.

The sensitivity of our net earnings to changes in foreign exchange rates has been prepared using management’s assessment that an average four cent increase or decrease in the US or Australian currencies relative to the Canadian dollar is a reasonable potential change over the next quarter, and is shown below:



Factor	Increase or decrease		Approximate impact on net earnings
Exchange rate	$	0.04	$27 million before tax

Liquidity Risk

Liquidity risk relates to our ability to access capital to be used to engage in trading and hedging activities, capital projects, debt refinancing and payment of liabilities, capital structure and general corporate purposes. Investment grade credit ratings support these activities and provide a more reliable and cost-effective means to access capital markets through commodity and credit cycles. Changes in credit ratings may also affect our ability and/or the cost of establishing normal course derivative or hedging transactions, including those undertaken by our Energy Marketing segment. Counterparties enter into certain electricity and natural gas purchase and sale contracts for the purposes of asset-backed sales and proprietary trading. The terms and conditions of these contracts require the counterparties to provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may challenge our ability to enter into these contracts or any ordinary course contract, decrease the credit limits granted, and increase the amount of collateral that may have to be provided. Certain existing contracts contain credit rating contingent clauses, that, when triggered, automatically increase costs under the contract or require additional collateral to be posted. Where the contingency is based on the lowest single rating, a one-level downgrade from a credit rating agency with an originally higher rating may not, however, trigger additional direct adverse impact.

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Management’s Discussion and Analysis

We are focused on strengthening our financial position and flexibility and achieving stable investment grade credit ratings with rating agencies. Credit ratings issued for TransAlta, as well as the corresponding rating agency outlooks, are set out in the Financial Capital section of this MD&A. Credit ratings are subject to revision or withdrawal at any time by the rating organization, and there can be no assurance that TransAlta’s credit ratings and the corresponding outlook will not be changed, resulting in the adverse possible impacts identified above.

As at Dec. 31, 2018 , we have liquidity of $ 1.0 billion comprised of amounts not drawn under our committed credit facilities and cash on hand that is available to draw on for projects in 2019 .

We manage liquidity risk by:


▪	monitoring liquidity on trading positions;


▪	preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital;


▪	reporting liquidity risk exposure for commodity risk management activities on a regular basis to the Commodity Risk & Compliance Committee, senior management and the ARC;


▪	maintaining investment grade credit ratings; and


▪	maintaining sufficient undrawn committed credit lines to support potential liquidity requirements.

Interest Rate Risk

Changes in interest rates can impact our borrowing costs and the capacity revenues we receive from our Alberta PPA plants. Changes in our cost of capital may also affect the feasibility of new growth initiatives.

We manage interest rate risk by establishing and adhering to policies that include:


▪	employing a combination of fixed and floating rate debt instruments; and


▪	monitoring the mixture of floating and fixed rate debt and adjusting where necessary to ensure a continued efficient mixture of these types of debt.

At Dec. 31, 2018 , approximately 14 per cent ( 2017 - six per cent) of our total debt portfolio was subject to changes in floating interest rates through a combination of floating rate debt and interest rate swaps.

The sensitivity of changes in interest rates upon our net earnings is shown below:



Factor	Increase or decrease (%)		Approximate impact on net earnings
Interest rate	15	%	$1 million before tax

Project Management Risk

On capital projects, we face risks associated with cost overruns, delays and performance.

We manage project risks by:


▪	ensuring all projects are reviewed to see that established processes and policies are followed, risks have been properly identified and quantified, input assumptions are reasonable and returns are realistically forecasted prior to senior management and Board of Director approvals;


▪	using consistent and disciplined project management methodologies and processes;


▪	performing detailed analysis of project economics prior to construction or acquisition and by determining our asset contracting strategy to ensure the right mix of contracted and merchant capacity before starting construction;


▪	developing and following through with comprehensive plans that include critical paths identified, key delivery points and backup plans;


▪	managing project closeouts so that any learnings from the project are incorporated into the next significant project,


▪	fixing the price and availability of the equipment, foreign currency rates, warranties and source agreements as much as is economically feasible before proceeding with the project; and


▪	entering into labour agreements to provide security around cost and productivity.

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Management’s Discussion and Analysis

Human Resource Risk

Human resource risk relates to the potential impact upon our business as a result of changes in the workplace. Human resource risk can occur in several ways:


▪	potential disruption as a result of labour action at our generating facilities;


▪	reduced productivity due to turnover in positions;


▪	inability to complete critical work due to vacant positions;


▪	failure to maintain fair compensation with respect to market rate changes; and


▪	reduced competencies due to insufficient training, failure to transfer knowledge from existing employees or insufficient expertise within current employees.

We manage this risk by:


▪	monitoring industry compensation and aligning salaries with those benchmarks,


▪	using incentive pay to align employee goals with corporate goals,


▪	monitoring and managing target levels of employee turnover, and


▪	ensuring new employees have the appropriate training and qualifications to perform their jobs.

In 2018 , 50 per cent ( 2017 - 52 per cent) of our labour force was covered by 10 ( 2017 - 11) collective bargaining agreements. In 2018 , four ( 2017 - four) agreements were renegotiated. We anticipate the successful negotiation of five collective agreements in 2019 .

Regulatory and Political Risk

Regulatory and political risk is the risk to our business associated with potential changes to the existing regulatory structures and the political influence upon those structures. This risk can come from market regulation and re-regulation, increased oversight and control, structural or design changes in markets, or other unforeseen influences. Market rules are often dynamic and we are not able to predict whether there will be any material changes in the regulatory environment or the ultimate effect of changes in the regulatory environment on our business. This risk includes, among other things, uncertainties associated with the development of capacity markets for electricity in the provinces of Alberta and Ontario, uncertainties associated with the development of carbon pricing policies, the qualification of our renewable facilities in Alberta to the generation of tradable GHG allowances as part of the transition from the Specified Gas Emitters Regulation to the new regulation to be formulated to give effect to the Alberta Climate Leadership Plan in 2020 , as well as the influence of regulation on the value of allowances or credits generated.

We manage these risks systematically through our Legal and Regulatory groups and our Compliance program, which is reviewed periodically to ensure its effectiveness. We work with governments, regulators, electricity system operators and other stakeholders to resolve issues as they arise. We are actively monitoring changes to market rules and market design, and we engage in industry and government agency led stakeholder engagement processes. Through these and other avenues, we engage in advocacy and policy discussions at a variety of levels. These stakeholder negotiations have allowed us to engage in proactive discussions with governments and regulatory agencies over the longer term.

International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the respective country and such country’s regulatory regime. We mitigate this risk through the use of non-recourse financing and insurance.

Transmission Risk

Access to transmission lines and transmission capacity for existing and new generation are key to our ability to deliver energy produced at our power plants to our customers. The risks associated with the aging existing transmission infrastructure in markets in which we operate continue to increase because new connections to the power system are consuming transmission capacity quicker than it is being added by new transmission developments.

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Management’s Discussion and Analysis

Reputation Risk

Our reputation is one of our most valued assets. 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.

We manage reputation risk by:


▪	striving as a neighbour and business partner in the regions where we operate to build viable relationships based on mutual understanding leading to workable solutions with our neighbours and other community stakeholders;


▪	clearly communicating our business objectives and priorities to a variety of stakeholders on a routine and transparent basis;


▪	applying innovative technologies to improve our operations, work environment and environmental footprint;


▪	maintaining positive relationships with various levels of government;


▪	pursuing sustainable development as a longer-term corporate strategy;


▪	ensuring that each business decision is made with integrity and in line with our corporate values;


▪	communicating the impact and rationale of business decisions to stakeholders in a timely manner; and


▪	maintaining strong corporate values that support reputation risk management initiatives, including the annual code of conduct sign-off.

Corporate Structure Risk

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.

Cybersecurity Risk

We rely on our information technology to process, transmit and store electronic information and data used for the safe operation of our assets. In today's ever evolving cybersecurity landscape, any attacks or other breaches of network or information systems may cause disruptions to our business operations. Cyberattackers may use a range of techniques, from exploiting vulnerabilities within our user-base, to using sophisticated malicious code on a single or distributed basis to try to breach our network security controls. Attackers may also use a combination of techniques in their attempt to evade safeguards such as firewalls, intrusion prevention systems and antivirus software that exist on our network infrastructure systems. A successful cyberattack may allow for the unauthorized interception, destruction, use or dissemination of our information and may cause disruptions to our business operations.

We continuously take measures to secure our infrastructure against potential cyberattacks that may damage our infrastructure, systems and data. Our cybersecurity program aligns with industry best practices to ensure that a holistic approach to 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. We have also established security awareness programs to help educate our users on cybersecurity risks and their responsibilities in helping protect 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 facilities and infrastructure and data, there can be no assurance that these measures will be sufficient or 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.

General Economic Conditions

Changes in general economic conditions impact product demand, revenue, operating costs, the timing and extent of capital expenditures, the net recoverable value of PP&E, financing costs, credit and liquidity risk, and counterparty risk.

Income Taxes

Our operations are complex and located in several countries. The computation of the provision for income taxes involves tax interpretations, regulations and legislation that are continually changing. Our tax filings are subject to audit by taxation authorities. Management believes that it has adequately provided for income taxes as required by IFRS, based on all information currently available.

The Corporation is 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

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Management’s Discussion and Analysis

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 that could have a material adverse impact on the Corporation.

The sensitivity of changes in income tax rates upon our net earnings is shown below:



Factor	Increase or decrease (%)	Approximate impact on net earnings
Tax rate	1	$1 million

Legal Contingencies

We are occasionally named as a party in various disputes, claims and legal or regulatory proceedings that arise during the normal course of our 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 dispute, claim or proceeding will be resolved in our favour or our liabilities with respect to such claims will not have a material adverse effect on us or our business, operations or financial results.

Other Contingencies

We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our insurance coverage during renewal of the insurance policies on Dec. 31, 2018 . Our insurance coverage may not be available in the future on commercially reasonable terms. There can be no assurance that our insurance coverage will be fully adequate to compensate for potential losses incurred. In the event of a significant economic event, the insurers may not be capable of fully paying all claims. All insurance policies are subject to standard exclusions. Cyber coverage is not currently purchased.

Fourth Quarter

Consolidated Financial Highlights



Three months ended Dec. 31	2018		2017
Revenues	622		638
Net earnings (loss) attributable to common shareholders	(122	)	(145	)
Cash flow from operating activities	132		81
Comparable EBITDA ⁽¹⁾	233		275
FFO ⁽¹⁾	217		219
FCF ⁽¹⁾	98		101
Net earnings (loss) per share attributable to common shareholders, basic and diluted	(0.43	)	(0.50	)
FFO per share ⁽¹⁾	0.76		0.76
FCF per share ⁽¹⁾	0.34		0.35
Dividends declared per common share ⁽²⁾	0.08		0.04
Dividends declared per preferred share ⁽²⁾	0.52		0.26

(2) Dividends declared vary year over year due to timing of dividend declarations.

Financial Highlights

We delivered consistent results in the fourth quarter with FCF of $ 98 million , compared to $ 101 million last year. FFO was $ 217 million , which was comparable to the fourth quarter of 2017 , as the business continues to deliver solid performance.

Net loss attributable to common shareholders in the fourth quarter of 2018 was $ 122 million ($ 0.43 net loss per share) compared to a net loss of $ 145 million ($ 0.50 net earnings per share) in the same period of 2017 , an improvement of $ 23 million compared to last year. This was driven by an income tax recovery of $16 million compared to income tax expense of $105 million in 2017, which was high due to the US tax rate reduction. This improvement was partially offset by lower comparable EBITDA of $ 42 million and the write-off of project development costs of $23 million in the fourth quarter of 2018.

TRANSALTA CORPORATION M 84

Management’s Discussion and Analysis

Segmented Cash Flows Generated by the Business and Operational Performance

Segmented cash flows generated by the business measures the net cash generated by each of our segments after sustaining and productivity capital expenditures, reclamation costs and provisions. It also excludes non-cash mark-to-market gains or losses. This is the cash flows available to pay our interest and cash taxes, distributions to our non-controlling partners and dividends to our preferred shareholders, grow the business, pay down debt and return capital to our shareholders.

Segmented cash flows and operational performance for the business during the quarter is as follows:



Three months ended Dec. 31	2018		2017
Availability (%) ⁽¹⁾	91.5		88.4
Production (GWh) ⁽¹⁾	8,276		10,374
Segmented cash inflow (outflow) ⁽²⁾
Canadian Coal	16		11
US Coal	21		15
Canadian Gas	59		56
Australian Gas ⁽³⁾	35		33
Wind and Solar	74		73
Hydro	11		10
Generation cash inflow	216		198
Energy Marketing	10		15
Corporate	(34	)	(28	)
Total comparable cash inflow	192		185

(1) Availability and production includes all generating assets under generation operations that we operate and finance leases and excludes hydro assets and equity investments. Production includes all generating assets, irrespective of investment vehicle and fuel type.

(2) This is not defined under IFRS. Presenting this item from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Discussion of Consolidated Financial Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.

(3) 2017 cash flow revised to reflect the impacts of the change in the long-term receivable in Australian Gas.

Adjusted availability for the three months ended Dec. 31, 2018 , improved compared with the same period in 2017 . Lower production for the three months ended Dec. 31, 2018 , compared to the same period in 2017 is primarily due to the termination of the Sundance B and C PPAs and derates, partially offset by higher dispatch optimization in US Coal and higher Ancillary Services within our Hydro segment.

Cash flows generated by the business totalled $ 192 million in the fourth quarter, an increase of $7 million compared with last year’s performance. Increased cash flows are largely due to the strong merchant prices in the Alberta market, lower sustaining capital spend and the settlement of a long-term receivable in Australian Gas, partially offset by higher carbon compliance costs.

TRANSALTA CORPORATION M 85

Management’s Discussion and Analysis

Discussion of Consolidated Financial Results

We evaluate our performance and the performance of our business segments using a variety of measures. Certain of the financial measures discussed in this MD&A, including the comparable figures below are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures are not necessarily comparable to a similarly titled measure of another company. Each business segment assumes responsibility for its operating results measured to comparable EBITDA and cash flows generated by the business. Gross margin is also a useful measure as it provides management and investors with a measurement of operating performance that is readily comparable from period to period.

Comparable EBITDA

A reconciliation of net earnings (loss) attributable to common shareholders to comparable EBITDA results is set out below:



Three months ended Dec. 31	2018		2017
Net earnings (loss) attributable to common shareholders	(122	)	(145	)
Net earnings attributable to non-controlling interests	43		19
Preferred share dividends	20		10
Net earnings (loss)	(59	)	(116	)
Adjustments to reconcile net income to comparable EBITDA
Income tax expense	(16	)	105
Gain on sale of assets and other	—		(1	)
Foreign exchange (gain) loss	—		(6	)
Net interest expense	50		57
Depreciation and amortization	152		180
Comparable reclassifications
Decrease in finance lease receivables	15		15
Mine depreciation included in fuel cost	37		20
Australian interest income	1		1
Adjustments to earnings to arrive at comparable EBITDA
Impacts associated with Mississauga recontracting ⁽¹⁾	30		20
Asset impairment charge (reversal)	23		—
Comparable EBITDA	233		275

(1) Impacts associated with Mississauga recontracting for the three months ended Dec. 31, 2018 , are as follows: revenue $30 million (2017 - $29 million) and recovery related to renegotiated land lease of nil (2017 - $9 million).

(2) Asset impairment charges for the three months ended Dec. 31, 2018 , include a write-off of project development costs of $23 million.

A summary of our comparable EBITDA by segments for the three months ended Dec. 31, 2018 and 2017 is as follows:



Three months ended Dec. 31	2018		2017
Comparable EBITDA
Canadian Coal	56		66
US Coal	(1	)	21
Canadian Gas	73		62
Australian Gas	32		29
Wind and Solar	72		78
Hydro	17		14
Energy Marketing	12		25
Corporate	(28	)	(20	)
Total comparable EBITDA	233		275

TRANSALTA CORPORATION M 86

Management’s Discussion and Analysis

Comparable EBITDA decrease d by $ 42 million for the fourth quarter 2018 , compared to 2017 , primarily as a result of:


▪	Our Canadian Coal results were down $ 10 million mainly due to higher carbon compliance costs in 2018.


▪	US Coal results were down $22 million primarily due to unfavourable changes on unrealized mark-to-market positions.


▪	Our Canadian Gas business was up $ 11 million period-over-period due to higher market price impacts.


▪	Australian Gas was up $ 3 million and was fairly consistent with prior year results.


▪	Wind and Solar results were down $ 6 million period-over-period mainly due to lower production, partially offset by higher prices in Alberta.


▪	Hydro results were $ 3 million higher period-over-period due to higher Ancillary Service revenues.


▪	Energy Marketing’s comparable EBITDA was down $ 13 million during the fourth quarter of 2018 compared to 2017 mainly because the 2017 results were very strong in the Alberta market.


▪	Corporate costs increased by $8 million in the fourth quarter mainly due to higher contractor costs.

Funds from Operations and Free Cash Flow

FFO per share and FCF per share are calculated as follows using the weighted average number of common shares outstanding during the period. FFO, FFO per share, FCF and FCF per share are non-IFRS measures, are not defined under IFRS, and therefore, should not be considered in isolation or as an alternative to or to be more meaningful than cash flow from operating activities as determined in accordance with IFRS, when assessing our financial performance or liquidity. See the Additional IFRS Measures and Non-IFRS Measures section above and elsewhere in this MD&A for further details. The table below reconciles our cash flow from operating activities to our FFO and FCF:



Three months ended Dec. 31	2018		2017
Cash flow from operating activities	132		81
Change in non-cash operating working capital balances	69		121
Cash flow from operations before changes in working capital	201		202
Adjustments
Decrease in finance lease receivable	15		15
Other	1		2
FFO	217		219
Deduct:
Sustaining capital	(56	)	(62	)
Productivity capital	(9	)	(9	)
Dividends paid on preferred shares	(10	)	(10	)
Distributions paid to subsidiaries’ non-controlling interests	(43	)	(36	)
Other	(1	)	(1	)
FCF	98		101
Weighted average number of common shares outstanding in the period	286		288
FFO per share	0.76		0.76
FCF per share	0.34		0.35

FFO was down $ 2 million during the fourth quarter of 2018 compared to the same period in 2017 . FCF decreased by $ 3 million period-over-period as we continued to reduce our sustaining capital spend as a result of our decision to mothball certain Sundance units.

TRANSALTA CORPORATION M 87

Management’s Discussion and Analysis

The table below provides a reconciliation of our comparable EBITDA to our FFO and FCF:



Three months ended Dec. 31	2018		2017
Comparable EBITDA	233		275
Provisions	—		(10	)
Unrealized (gains) losses from risk management activities	27		(8	)
Interest expense	(40	)	(52	)
Current income tax expense	(10	)	(6	)
Realized foreign exchange gain (loss)	1		8
Decommissioning and restoration costs settled	(8	)	(7	)
Other non-cash items	14		19
FFO	217		219
Deduct:
Sustaining capital	(56	)	(62	)
Productivity capital	(9	)	(9	)
Dividends paid on preferred shares	(10	)	(10	)
Distributions paid to subsidiaries’ non-controlling interests	(43	)	(36	)
Other	(1	)	(1	)
Comparable FCF	98		101
Weighted average number of common shares outstanding in the period	286		288
Comparable FFO per share	0.76		0.76
Comparable FCF per share	0.34		0.35

TRANSALTA CORPORATION M 88

Management’s Discussion and Analysis

Selected Quarterly Information

Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are usually incurred in the spring and fall when electricity prices are expected to be lower, as electricity prices generally increase in the peak winter and summer months in our main markets due to increased heating and cooling loads. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting from spring runoff and rainfall in the Pacific Northwest, which impacts production at US Coal. Typically, hydro facilities generate most of their electricity and revenues during the spring months when melting snow starts feeding watersheds and rivers. Inversely, wind speeds are historically greater during the cold winter months and lower in the warm summer months.



	Q1 2018	Q2 2018		Q3 2018		Q4 2018

Revenues	588	446		593		622
Comparable EBITDA	416	225		249		233
FFO	318	188		204		217
Net earnings (loss) attributable to common shareholders	65	(105	)	(86	)	(122	)
Net earnings (loss) per share attributable to common shareholders, basic and diluted ⁽¹⁾	0.23	(0.36	)	(0.30	)	(0.43	)

	Q1 2017	Q2 2017		Q3 2017		Q4 2017

Revenues	578	503		588		638
Comparable EBITDA	274	268		245		275
FFO	202	187		196		219
Net earnings (loss) attributable to common shareholders	—	(18	)	(27	)	(145	)
Net earnings (loss) per share attributable to common shareholders, basic and diluted ⁽¹⁾	—	(0.06	)	(0.09	)	(0.50	)

(1) Basic and diluted earnings per share attributable to common shareholders and comparable earnings per share are calculated each period using the weighted average common shares outstanding during the period. As a result, the sum of the earnings per share for the four quarters making up the calendar year may sometimes differ from the annual earnings per share.

Reported net earnings, comparable EBITDA, and FFO are generally higher in the first and fourth quarters due to higher demand associated with winter cold in the markets in which we operate and lower planned outages.

Net earnings attributable to common shareholders has also been impacted by the following variations and events:


▪	effects of impairment charges during the second, third and fourth quarters of 2018 and second quarter of 2017;


▪	recognition of the $157 million early termination payment received regarding Sundance B and C PPAs during the first quarter of 2018;


▪	a recovery of a writedown of deferred tax assets in the second quarter of 2017;


▪	change in income tax rates in the US in the fourth quarter of 2017;


▪	effects of non-comparable unrealized gains on intercompany financial instruments that are attributable only to the

non-controlling interests in the first quarter of 2017;


▪	effects of changes in useful lives of certain Canadian Coal assets during the first, second and third quarters of 2017; and


▪	effects of an impairment of $137 million in 2017 on intercompany financial instruments that is attributable only to the non-controlling interests.

TRANSALTA CORPORATION M 89

Management’s Discussion and Analysis

Disclosure Controls and Procedures

Management is responsible for establishing and maintaining adequate internal control over financial reporting (‘‘ICFR’’) and disclosure controls and procedures (“DC&P’’). There have been no changes in our ICFR or DC&P during the year ended Dec. 31, 2018 , that have materially affected, or are reasonably likely to materially affect, our ICFR or DC&P.

ICFR is a framework designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with IFRS. Management has used the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) in order to assess the effectiveness of the Corporation’s ICFR.

DC&P refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under securities legislation are recorded, processed, summarized and reported within the time frame specified in securities legislation. DC&P include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under securities legislation is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure.

Together, the ICFR and DC&P frameworks provide internal control over financial reporting and disclosure. In designing and evaluating our ICFR and DC&P, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and as such may not prevent or detect all misstatements, and management is required to apply its judgment in evaluating and implementing possible controls and procedures. Further, the effectiveness of ICFR is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may change.

Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our ICFR and DC&P as of the end of the period covered by this report. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as at Dec. 31, 2018 , the end of the period covered by this report, our ICFR and DC&P were effective.

TRANSALTA CORPORATION M 90

Consolidated Financial Statements

Management's Report

To the Shareholders of TransAlta Corporation

The Consolidated Financial Statements and other financial information included in this annual report have been prepared by management. It is management’s responsibility to ensure that sound judgment, appropriate accounting principles and methods, and reasonable estimates have been used to prepare this information. They also ensure that all information presented is consistent.

Management is also responsible for establishing and maintaining internal controls and procedures over the financial reporting process. The internal control system includes an internal audit function and an established business conduct policy that applies to all employees. In addition, TransAlta Corporation has a code of conduct that applies to all employees and is signed annually. The code of conduct can be viewed on TransAlta’s website (www.transalta.com). Management believes the system of internal controls, review procedures and established policies provides reasonable assurance as to the reliability and relevance of financial reports. Management also believes that TransAlta’s operations are conducted in conformity with the law and with a high standard of business conduct.

The Board of Directors (the “Board”) is responsible for ensuring that management fulfils its responsibilities for financial reporting and internal controls. The Board carries out its responsibilities principally through its Audit and Risk Committee (the “Committee”). The Committee, which consists solely of independent directors, reviews the financial statements and annual report and recommends them to the Board for approval. The Committee meets with management, internal auditors and external auditors to discuss internal controls, auditing matters and financial reporting issues. Internal and external auditors have full and unrestricted access to the Committee. The Committee also recommends the firm of external auditors to be appointed by the shareholders.





	Dawn L. Farrell	Christophe Dehout
	President and Chief Executive Officer	Chief Financial Officer

February 26, 2019

TRANSALTA CORPORATION F 1

Consolidated Financial Statements

Management’s Annual Report on Internal Control over Financial Reporting

To the Shareholders of TransAlta Corporation

The following report is provided by management in respect of TransAlta Corporation’s (“TransAlta”) internal control over financial reporting (as defined in Rules 13a-15f and 15d-15f under the United States Securities Exchange Act of 1934 and National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings).

TransAlta’s management is responsible for establishing and maintaining adequate internal control over financial reporting for TransAlta.

Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) 2013 framework to evaluate the effectiveness of TransAlta’s internal control over financial reporting. Management believes that the COSO 2013 framework is a suitable framework for its evaluation of TransAlta’s internal control over financial reporting because it is free from bias, permits reasonably consistent qualitative and quantitative measurements of TransAlta’s internal controls, is sufficiently complete so that those relevant factors that would alter a conclusion about the effectiveness of TransAlta’s internal controls are not omitted, and is relevant to an evaluation of internal control over financial reporting.

TransAlta proportionately consolidates the accounts of the Sheerness and Genesee Unit 3 joint operations in accordance with International Financial Reporting Standards. Management does not have the contractual ability to assess the internal controls of these joint arrangements. Once the financial information is obtained from these joint arrangements it falls within the scope of TransAlta’s internal controls framework. Management’s conclusion regarding the effectiveness of internal controls does not extend to the internal controls at the transactional level of these joint arrangements. The 2018 Consolidated Financial Statements of TransAlta included $ 588 million and $ 521 million of total and net assets, respectively, as of December 31, 2018 , and $ 244 million and $ 27 million of revenues and net loss, respectively, for the year then ended related to these joint arrangements.

Management has assessed the effectiveness of TransAlta’s internal control over financial reporting, as at December 31, 2018 , and has concluded that such internal control over financial reporting is effective.

Ernst & Young LLP, who has audited the consolidated financial statements of TransAlta for the year ended December 31, 2018 , has also issued a report on internal control over financial reporting under the standards of the Public Company Accounting Oversight Board (United States). This report is located on the following page of this Annual Report.





	Dawn L. Farrell	Christophe Dehout
	President and Chief Executive Officer	Chief Financial Officer

February 26, 2019

TRANSALTA CORPORATION F 2

Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

To the Shareholders and Directors of TransAlta Corporation

Opinion on Internal Control over Financial Reporting

We have audited TransAlta Corporation’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSO criteria”). In our opinion, TransAlta Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Consolidated Statements of Financial Position of TransAlta Corporation as of December 31, 2018 and 2017, and the related Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss), Changes in Equity and Cash Flows for each of the three years in the period ended December 31, 2018 and the related notes and our report dated February 26, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

TransAlta Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on TransAlta Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to TransAlta Corporation in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the corporation; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and that receipts and expenditures of the corporation are being made only in accordance with authorizations of management and directors of the corporation; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the corporation’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As indicated in the accompanying Management’s Annual Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the Sheerness and Genesee Unit 3 joint arrangements, which are included in the 2018 consolidated financial statements of TransAlta and constituted $ 588 million and $ 521 million of total and net assets, respectively, as of December 31, 2018 , and $ 244 million and $ 27 million of revenues and net loss, respectively, for the year then ended. Our audit of internal control over financial reporting of TransAlta Corporation did not include an evaluation of the internal control over financial reporting of the Sheerness and Genesee Unit 3 joint arrangements.

Chartered Professional Accountants

Calgary, Canada

February 26, 2019

TRANSALTA CORPORATION F 3

Consolidated Financial Statements

Independent Auditors’ Report of Registered Public Accounting Firm

To the Shareholders and Directors of TransAlta Corporation

Opinion on the Consolidated Financial Statements

We have audited the accompanying Consolidated Statements of Financial Position of TransAlta Corporation as of December 31, 2018 and 2017, the related Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss), Changes in Equity and Cash Flows, for each of the years then ended, and the related notes (collectively referred to as the “Consolidated Financial Statements“). In our opinion, the Consolidated Financial Statements present fairly, in all material respects, the financial position of TransAlta Corporation at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Report on internal control over financial reporting

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), TransAlta Corporation’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 26, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of TransAlta Corporation‘s management. Our responsibility is to express an opinion on TransAlta Corporation‘s Consolidated Financial Statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to TransAlta Corporation in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements. We believe that our audits provide a reasonable basis for our opinion.

Chartered Professional Accountants

We have served as TransAlta Corporation and its predecessor entities' auditor since 1947

Calgary, Canada

February 26, 2019

TRANSALTA CORPORATION F 4

Consolidated Financial Statements

Consolidated Statements of Earnings (Loss)



Year ended Dec. 31 (in millions of Canadian dollars except where noted)	2018		2017		2016

Revenues (Note 5)	2,249		2,307		2,397
Fuel and purchased power (Note 6)	1,100		1,016		963
Gross margin	1,149		1,291		1,434
Operations, maintenance and administration (Note 6)	515		517		489
Depreciation and amortization	574		635		601
Asset impairment charges (reversals) (Note 7)	73		20		28
Taxes, other than income taxes	31		30		31
Net other operating expense (income) (Note 9)	(204	)	(49	)	(193	)
Operating income	160		138		478
Finance lease income	8		54		66
Net interest expense (Note 10)	(250	)	(247	)	(229	)
Foreign exchange gain (loss)	(15	)	(1	)	(5	)
Gain on sale of assets and other	1		2		4
Earnings (loss) before income taxes	(96	)	(54	)	314
Income tax expense (recovery) (Note 11)	(6	)	64		38
Net earnings (loss)	(90	)	(118	)	276

Net earnings (loss) attributable to:
TransAlta shareholders	(198	)	(160	)	169
Non-controlling interests (Note 12)	108		42		107
	(90	)	(118	)	276

Net earnings (loss) attributable to TransAlta shareholders	(198	)	(160	)	169
Preferred share dividends (Note 25)	50		30		52
Net earnings (loss) attributable to common shareholders	(248	)	(190	)	117
Weighted average number of common shares outstanding in the year (millions)	287		288		288

Net earnings (loss) per share attributable to common shareholders, basic and diluted (Note 24)	(0.86	)	(0.66	)	0.41

See accompanying notes.

TRANSALTA CORPORATION F 5

Consolidated Financial Statements

Consolidated Statements of Comprehensive Income (Loss)



Year ended Dec. 31 (in millions of Canadian dollars)	2018		2017		2016
Net earnings (loss)	(90	)	(118	)	276
Other comprehensive income (loss)
Net actuarial gains (losses) on defined benefit plans, net of tax ⁽¹⁾	15		(6	)	8
Gains (losses) on derivatives designated as cash flow hedges, net of tax ⁽²⁾	—		(1	)	(1	)
Total items that will not be reclassified subsequently to net earnings	15		(7	)	7
Gains (losses) on translating net assets of foreign operations, net of tax ⁽³⁾	84		(80	)	(71	)
Reclassification of translation gains on net assets of divested foreign operations ⁽⁴⁾ (Note 4)	—		(9	)	—
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax ⁽⁵⁾	(41	)	50		18
Reclassification of losses on financial instruments designated as hedges of divested foreign operations, net of tax ⁽⁶⁾ (Note 4)	—		14		—
Gains (losses) on derivatives designated as cash flow hedges, net of tax ⁽⁷⁾	(8	)	214		179
Reclassification of gains on derivatives designated as cash flow hedges to net earnings, net of tax ⁽⁸⁾	(46	)	(107	)	(48	)
Total items that will be reclassified subsequently to net earnings	(11	)	82		78
Other comprehensive income	4		75		85
Total comprehensive income (loss)	(86	)	(43	)	361

Total comprehensive income (loss) attributable to:
TransAlta shareholders	(210	)	(74	)	215
Non-controlling interests (Note 12)	124		31		146
	(86	)	(43	)	361

(1) Net of income tax expense of 5 million for the year ended Dec. 31, 2018 ( 2017 - 4 million recovery, 2016 - 4 million expense).

(2) Net of income tax of nil for the year ended Dec. 31, 2018 ( 2017 - nil , 2016 - nil ).

(3) Net of income tax of nil for the year ended Dec. 31, 2018 ( 2017 - nil , 2016 - 11 million expense).

(4) Net of reclassification of income tax of nil for the year ended Dec. 31, 2018 ( 2017 - 11 million expense, 2016 - nil ).

(5) Net of income tax of nil for the year ended Dec. 31, 2018 ( 2017 - 2 million expense, 2016 - 5 million expense).

(6) Net of reclassification of income tax of nil for the year ended Dec. 31, 2018 ( 2017 - 2 million recovery, 2016 - nil ).

(7) Net of income tax recovery of 1 million for the year ended Dec. 31, 2018 ( 2017 - 77 million recovery, 2016 - 92 million expense).

(8) Net of reclassification of income tax expense of 11 million for the year ended Dec. 31, 2018 ( 2017 - 31 million expense, 2016 - 41 million expense).

See accompanying notes.

TRANSALTA CORPORATION F 6

Consolidated Financial Statements

Consolidated Statements of Financial Position



As at Dec. 31 (in millions of Canadian dollars)	2018		2017
Cash and cash equivalents	89		314
Restricted cash (Note 22)	66		—
Trade and other receivables (Note 13)	756		933
Prepaid expenses	13		24
Risk management assets (Note 14 and 15)	146		219
Inventory (Note 16)	242		219
	1,312		1,709
Restricted cash (Note 22)	—		30
Long-term portion of finance lease receivables (Note 8)	191		215
Property, plant and equipment (Note 17)
Cost	13,202		12,973
Accumulated depreciation	(7,038	)	(6,395	)
	6,164		6,578

Goodwill (Note 18)	464		463
Intangible assets (Note 19)	373		364
Deferred income tax assets (Note 11)	28		24
Risk management assets (Note 14 and 15)	662		684
Other assets (Note 20)	234		237
Total assets	9,428		10,304

Accounts payable and accrued liabilities	497		595
Current portion of decommissioning and other provisions (Note 21)	70		67
Risk management liabilities (Note 14 and 15)	90		101
Income taxes payable	10		64
Dividends payable (Note 24 and 25)	58		34
Current portion of long-term debt and finance lease obligations (Note 22)	148		747
	873		1,608
Credit facilities, long-term debt and finance lease obligations (Note 22)	3,119		2,960
Decommissioning and other provisions (Note 21)	386		403
Deferred income tax liabilities (Note 11)	501		549
Risk management liabilities (Note 14 and 15)	41		40
Contract liabilities (Note 5)	87		62
Defined benefit obligation and other long-term liabilities (Note 23)	287		297
Equity
Common shares (Note 24)	3,059		3,094
Preferred shares (Note 25)	942		942
Contributed surplus	11		10
Deficit	(1,496	)	(1,209	)
Accumulated other comprehensive income (Note 26)	481		489
Equity attributable to shareholders	2,997		3,326
Non-controlling interests (Note 12)	1,137		1,059
Total equity	4,134		4,385
Total liabilities and equity	9,428		10,304

Commitments and contingencies (Note 33)





On behalf of the Board:	Gordon D. Giffin Director	Beverlee F. Park Director

See accompanying notes.

TRANSALTA CORPORATION F 7

Consolidated Financial Statements

Consolidated Statements of Changes in Equity

(in millions of Canadian dollars)



	Common shares		Preferred shares	Contributed surplus	Deficit		Accumulated other comprehensive income ⁽¹⁾		Attributable to shareholders		Attributable to non-controlling interests		Total
Balance, Dec. 31, 2016	3,094		942	9	(933	)	399		3,511		1,152		4,663
Net earnings	—		—	—	(160	)	—		(160	)	42		(118	)
Other comprehensive income (loss):
Net losses on translating net assets of foreign operations, net of hedges and of tax	—		—	—	—		(25	)	(25	)	—		(25	)
Net gains on derivatives designated as cash flow hedges, net of tax	—		—	—	—		106		106		—		106
Net actuarial gains on defined benefits plans, net of tax	—		—	—	—		(6	)	(6	)	—		(6	)
Intercompany available-for-sale investments	—		—	—	—		11		11		(11	)	—
Total comprehensive income					(160	)	86		(74	)	31		(43	)
Common share dividends	—		—	—	(34	)	—		(34	)	—		(34	)
Preferred share dividends	—		—	—	(30	)	—		(30	)	—		(30	)
Changes in non-controlling interests in TransAlta Renewables (Note 4)	—		—	—	(52	)	4		(48	)	48		—
Effect of share-based payment plans	—		—	1	—		—		1		—		1
Distributions paid, and payable, to non-controlling interests	—		—	—	—		—		—		(172	)	(172	)
Balance, Dec. 31, 2017	3,094		942	10	(1,209	)	489		3,326		1,059		4,385
Impact of change in accounting policy (Note 3)	—		—	—	(14	)	—		(14	)	1		(13	)
Adjusted balance as at Jan. 1, 2018	3,094		942	10	(1,223	)	489		3,312		1,060		4,372
Net earnings (loss)	—		—	—	(198	)	—		(198	)	108		(90	)
Other comprehensive income (loss):
Net losses on translating net assets of foreign operations, net of hedges and of tax	—		—	—	—		43		43		—		43
Net gains on derivatives designated as cash flow hedges, net of tax	—		—	—	—		(54	)	(54	)	—		(54	)
Net actuarial gains on defined benefits plans, net of tax	—		—	—	—		15		15		—		15
Intercompany fair value through other comprehensive income investments	—		—	—	—		(16	)	(16	)	16		—
Total comprehensive income					(198	)	(12	)	(210	)	124		(86	)
Common share dividends	—		—	—	(57	)	—		(57	)	—		(57	)
Preferred share dividends	—		—	—	(50	)	—		(50	)	—		(50	)
Shares purchased under NCIB	(35	)	—	—	12		—		(23	)	—		(23	)
Changes in non-controlling interests in TransAlta Renewables (Note 4)	—		—	—	20		4		24		133		157
Effect of share-based payment plans	—		—	1	—		—		1		—		1
Distributions paid, and payable, to non-controlling interests	—		—	—	—		—		—		(180	)	(180	)
Balance, Dec.31, 2018	3,059		942	11	(1,496	)	481		2,997		1,137		4,134

(1) Refer to Note 26 for details on components of, and changes in, accumulated other comprehensive income (loss).

See accompanying notes.

TRANSALTA CORPORATION F 8

Consolidated Financial Statements

Consolidated Statements of Cash Flows



Year ended Dec. 31 (in millions of Canadian dollars)	2018		2017		2016
Operating activities
Net earnings (loss)	(90	)	(118	)	276
Depreciation and amortization (Note 34)	710		708		664
Gain (loss) on sale of assets (Note 4)	—		(1	)	(1	)
Accretion of provisions (Note 21)	24		23		20
Decommissioning and restoration costs settled (Note 21)	(31	)	(19	)	(23	)
Deferred income tax expense (recovery) (Note 11)	(34	)	(15	)	15
Unrealized (gain) loss from risk management activities	30		(48	)	58
Unrealized foreign exchange (gain) loss	28		22		(1	)
Provisions	7		(7	)	(123	)
Asset impairment charges (reversals) (Note 7)	73		20		28
Other non-cash items	147		175		(242	)
Cash flow from operations before changes in working capital	864		740		671
Change in non-cash operating working capital balances (Note 30)	(44	)	(114	)	73
Cash flow from operating activities	820		626		744
Investing activities
Additions to property, plant and equipment (Note 17 and 34)	(277	)	(338	)	(358	)
Additions to intangibles (Note 19 and 34)	(20	)	(51	)	(21	)
Restricted cash (Note 22)	(35	)	(30	)	—
Loan receivable (Note 20)	1		(38	)	—
Acquisition of renewable energy facilities, net of cash acquired (Note 4)	(30	)	—		—
Proceeds on sale of property, plant and equipment	2		3		6
Proceeds on sale of Wintering Hills facility and Solomon disposition (Note 4)	2		478		—
Income tax expense on Solomon disposition (Note 4 and 11)	—		(56	)	—
Realized gains (losses) on financial instruments	2		6		(6	)
Decrease in finance lease receivable	59		59		56
Other	(2	)	(3	)	2
Change in non-cash investing working capital balances	(96	)	57		(6	)
Cash flow from (used in) investing activities	(394	)	87		(327	)
Financing activities
Net increase (decrease) in borrowings under credit facilities (Note 22)	312		26		(315	)
Repayment of long-term debt (Note 22)	(1,179	)	(814	)	(88	)
Issuance of long-term debt (Note 22)	345		260		361
Dividends paid on common shares (Note 24)	(46	)	(46	)	(69	)
Dividends paid on preferred shares (Note 25)	(40	)	(40	)	(42	)
Net proceeds on sale of non-controlling interest in subsidiary (Note 4)	144		—		162
Repurchase of common shares under NCIB (Note 24)	(23	)	—		—
Realized gains (losses) on financial instruments	48		106		(2	)
Distributions paid to subsidiaries' non-controlling interests (Note 12)	(165	)	(172	)	(151	)
Decrease in finance lease obligations (Note 22)	(18	)	(17	)	(16	)
Other	(31	)	(6	)	(3	)
Change in non-cash financing working capital balances	2		—		—
Cash flow from (used in) financing activities	(651	)	(703	)	(163	)
Cash flow from (used in) operating, investing, and financing activities	(225	)	10		254
Effect of translation on foreign currency cash	—		(1	)	(3	)
Increase (decrease) in cash and cash equivalents	(225	)	9		251
Cash and cash equivalents, beginning of year	314		305		54
Cash and cash equivalents, end of year	89		314		305
Cash income taxes paid	87		14		27
Cash interest paid	188		230		235

See accompanying notes.

TRANSALTA CORPORATION F 9

Notes to Consolidated Financial Statements

(Tabular amounts in millions of Canadian dollars, except as otherwise noted)

1. Corporate Information

A. Description of the Business

TransAlta Corporation (“TransAlta” or the “Corporation”) was incorporated under the Canada Business Corporations Act in March 1985. The Corporation became a public company in December 1992. Its head office is located in Calgary, Alberta.

I. Generation Segments

The six generation segments of the Corporation are as follows: Canadian Coal, US Coal, Canadian Gas, Australian Gas, Wind and Solar, and Hydro. The Corporation directly or indirectly owns and operates hydro, wind and solar, natural gas and coal-fired facilities, and related mining operations in Canada, the United States (“US”), and Australia. Revenues are derived from the availability and production of electricity and steam as well as ancillary services such as system support. Electricity sales made by the Corporation’s commercial and industrial group are assumed to be sourced from the Corporation’s production and have been included in the Canadian Coal segment.

II. Energy Marketing Segment

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

Energy Marketing manages available generating capacity as well as the fuel and transmission needs of the generation segments by utilizing contracts of various durations for the forward sales of electricity and for the purchase of natural gas and transmission capacity. Energy Marketing is also responsible for recommending portfolio optimization decisions. The results of these other activities are included in each generation segment.

III. Corporate

The Corporate segment includes the Corporation’s central financial, legal, administrative, investor relation functions and corporate development. Charges directly or reasonably attributable to other segments are allocated thereto.

B. Basis of Preparation

These consolidated financial statements have been prepared by management in compliance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

The consolidated financial statements have been prepared on a historical cost basis except for financial instruments and assets held for sale, which are measured at fair value, as explained in the following accounting policies.

These consolidated financial statements were authorized for issue by TransAlta's Board of Directors (the "Board") on February 26, 2019 .

C. Basis of Consolidation

The consolidated financial statements include the accounts of the Corporation and the subsidiaries that it controls. Control exists when the Corporation is exposed, or has rights, to variable returns from its involvement with the subsidiary and has the ability to affect the returns through its power over the subsidiary. The financial statements of the subsidiaries are prepared for the same reporting period and apply consistent accounting policies as the parent company.

TRANSALTA CORPORATION F 10

Notes to Consolidated Financial Statements

2. Significant Accounting Policies

A. Revenue Recognition

I. Revenue from Contracts with Customers

The Corporation has adopted IFRS 15 Revenue from Contracts with Customers (IFRS 15) with an initial adoption date of Jan. 1, 2018. As a result, the Corporation has changed its accounting policy for revenue recognition, which is outlined below.

The Corporation has elected to adopt IFRS 15 retrospectively with the modified retrospective method of transition practical expedient and has elected to apply IFRS 15 only to contracts that are active at the date of initial adoption. Comparative information has not been restated and is reported under IAS 18 Revenue (IAS 18). Refer to section III below for the accounting policy for prior years.

The majority of the Corporation’s revenues from contracts with customers are derived from the sale of generation capacity, electricity, thermal energy, renewable attributes and byproducts of power generation. The Corporation evaluates whether the contracts it enters into meet the definition of a contract with a customer at the inception of the contract and on an ongoing basis if there is an indication of significant changes in facts and circumstances. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the good or services is transferred to the customer. For certain contracts, revenue may be recognized at the invoiced amount, as permitted using the invoice practical expedient, if such amount corresponds directly with the Corporation’s performance to date. The Corporation excludes amounts collected on behalf of third parties from revenue.

Performance Obligations

Each promised good or service is accounted for separately as a performance obligation if it is distinct. The Corporation’s contracts may contain more than one performance obligation.

Transaction Price

When multiple performance obligations are present in a contract, transaction price is allocated to each performance obligation in an amount that depicts the consideration the Corporation expects to be entitled to in exchange for transferring the good or service. The Corporation estimates the amount of the transaction price to allocate to individual performance obligations based on their relative standalone selling prices, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions.

TRANSALTA CORPORATION F 11

Notes to Consolidated Financial Statements

Recognition

The nature, timing of recognition of satisfied performance obligations, and payment terms for the Corporation’s goods and services are described below:



Good or Service	Description
Capacity	Capacity refers to the availability of an asset to deliver goods or services. Customers typically pay for capacity for each defined time period (i.e., monthly) in an amount representative of availability of the asset for the defined time period. Obligations to deliver capacity are satisfied over time and revenue is recognized using a time-based measure. Contracts for capacity are typically long term in nature. Payments are typically received from customers on a monthly basis.
Contract Power	The sale of contract power refers to the delivery of units of electricity to a customer under the terms of a contract. Customers pay a contractually specified price for the output at the end of predefined contractual periods (i.e., monthly). Obligations to deliver electricity are satisfied over time and revenue is recognized using a units-based output measure (i.e., megawatt hours). Contracts for power are typically long term in nature and payments are typically received on a monthly basis.
Thermal Energy	Thermal energy refers to the delivery of units of steam to a customer under the terms of a contract. Customers pay a contractually specified price for the output at the end of predefined contractual periods (i.e., monthly). Obligations to deliver steam are satisfied over time and revenue is recognized using a units-based output measure (i.e., gigajoules). Contracts for thermal energy are typically long term in nature. Payments are typically received from customers on a monthly basis.
Renewable Attributes	Renewable attributes refers to the delivery of renewable energy certificates, green attributes and other similar items. Customers may contract for renewable attributes in conjunction with the purchase of power, in which case the customer pays for the attributes in the month subsequent to the delivery of the power. Alternatively, customers pay upon delivery of the renewable attributes. Obligations to deliver renewable attributes are satisfied at a point in time, generally upon delivery of the item.
Generation byproducts	Generation byproducts refers to the sale of byproducts from the use of coal in the Corporation’s Canadian and US coal operations, and the sale of coal to third parties. Obligations to deliver byproducts are satisfied at a point in time, generally upon delivery of the item. Payments are received upon satisfaction of delivery of the byproducts.

The Corporation recognizes a contract asset or contract liability for contracts where either party has performed. A contract liability is recorded when the Corporation receives consideration before the performance obligations have been satisfied. A contract asset is recorded when the Corporation has rights to consideration for the completion of a performance obligation before it has invoiced the customer. The Corporation recognizes unconditional rights to consideration separately as a receivable. Contract assets and receivables are evaluated at each reporting period to determine whether there is any objective evidence that they are impaired.

Significant Judgments

Identification of performance obligations

Transaction price

TRANSALTA CORPORATION F 12

Notes to Consolidated Financial Statements

Allocation of transaction price to performance obligations

Satisfaction of performance obligations

II. Revenue from Other Sources

Lease revenue

In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Revenues associated with non-lease elements are recognized as goods or services revenues as outlined above. Where the terms and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income. Where the Corporation retains the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including contingent rents where applicable, is recognized over the term of the contract.

Revenue from derivatives

Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales contracts, futures contracts and options, which are used to earn revenues and to gain market information. These derivatives are accounted for using fair value accounting. The initial recognition and subsequent changes in fair value affect reported net earnings in the period the change occurs and are presented on a net basis in revenue. The fair values of instruments that remain open at the end of the reporting period represent unrealized gains or losses and are presented on the Consolidated Statements of Financial Position as risk management assets or liabilities. Some of the derivatives used by the Corporation in trading activities are not traded on an active exchange or have terms that extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives are determined using internal valuation techniques or models.

III. Revenue Recognition Policy in Prior Years

The majority of the Corporation’s revenues are derived from the sale of physical power, the leasing of power facilities and from energy marketing and trading activities. Revenues are measured at the fair value of the consideration received or receivable.

Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components: fixed capacity payments for availability, energy payments for generation of electricity, incentives or penalties for exceeding or not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary services. Each component is recognized when: i) output, delivery or satisfaction of specific targets is achieved, all as governed by contractual terms; ii) the amount of revenue can be measured reliably; iii) it is probable that the economic benefits will flow to the Corporation; and iv) the costs incurred or to be incurred in respect of the transaction can be measured reliably. Revenue from the rendering of services is recognized when criteria ii), iii) and iv) above are met and when the stage of completion of the transaction at the end of the reporting period can be measured reliably.

Revenues from non-contracted capacity are comprised of energy payments, at market prices, for each megawatt hour (“MWh”) produced, and are recognized upon delivery.

TRANSALTA CORPORATION F 13

Notes to Consolidated Financial Statements

that remain open at the end of the reporting period represent unrealized gains or losses and are presented on the Consolidated Statements of Financial Position as risk management assets or liabilities. Some of the derivatives used by the Corporation in trading activities are not traded on an active exchange or have terms that extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives are determined using internal valuation techniques or models.

B. Foreign Currency Translation

The Corporation, its subsidiary companies and joint arrangements each determine their functional currency based on the currency of the primary economic environment in which they operate. The Corporation’s functional currency is the Canadian dollar, while the functional currencies of its subsidiary companies and joint arrangements are the Canadian, US or Australian dollar. Transactions denominated in a currency other than the functional currency of an entity are translated at the exchange rate in effect on the transaction date. The resulting exchange gains and losses are included in each entity’s net earnings in the period in which they arise.

The Corporation’s foreign operations are translated to the Corporation’s presentation currency, which is the Canadian dollar, for inclusion in the consolidated financial statements. Foreign-denominated monetary and non-monetary assets and liabilities of foreign operations are translated at exchange rates in effect at the end of the reporting period, and revenue and expenses are translated at exchange rates in effect on the transaction date. The resulting translation gains and losses are included in other comprehensive income (loss) (“OCI”) with the cumulative gain or loss reported in accumulated other comprehensive income (loss) (“AOCI”). Amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in a foreign net investment as a result of a disposal, partial disposal or loss of control.

C. Financial Instruments and Hedges

I. Financial Instruments

Effective Jan. 1, 2018, the Corporation adopted IFRS 9. In accordance with the transition provisions of the standard, the Corporation has elected to not restate prior periods. Refer to section III below for information on its prior accounting policy. The Corporation's accounting policies under IFRS 9 are outlined below.

Classification and Measurement

IFRS 9 introduces the requirement to classify and measure financial assets based on their contractual cash flow characteristics and the Corporation’s business model for the financial asset. All financial assets and financial liabilities, including derivatives, are recognized at fair value on the Consolidated Statements of Financial Position when the Corporation becomes party to the contractual provisions of a financial instrument or non-financial derivative contract. Financial assets must be classified and measured at either amortized cost, at fair value through profit or loss (“FVTPL”), or at fair value through other comprehensive income (“FVTOCI”).

Financial assets with contractual cash flows arising on specified dates, consisting solely of principal and interest, and that are held within a business model whose objective is to collect the contractual cash flows are subsequently measured at amortized cost. Financial assets measured at FVTOCI are those that have contractual cash flows arising on specific dates, consisting solely of principal and interest, and that are held within a business model whose objective is to collect the contractual cash flows and to sell the financial asset. All other financial assets are subsequently measured at FVTPL.

Financial liabilities are classified as FVTPL when the financial liability is held for trading. All other financial liabilities are subsequently measured at amortized cost.

The Corporation enters into a variety of derivative financial instruments to manage its exposure to commodity price risk, interest rate risk, and foreign currency exchange risk, including fixed price financial swaps, long-term physical power sale contracts, foreign exchange forward contracts and designating foreign currency debt as a hedge of net investments in foreign operations.

Derivatives are initially recognized at fair value at the date the derivative contracts are entered into and are subsequently remeasured to their fair value at the end of each reporting period. The resulting gain or loss is recognized in net earnings immediately, unless the derivative is designated and effective as a hedging instrument, in which case the timing of the recognition in net earnings is dependent on the nature of the hedging relationship.

Derivatives embedded in non-derivative host contracts that are not financial assets within the scope of IFRS 9 (e.g., financial liabilities) are treated as separate derivatives when they meet the definition of a derivative, their risks and characteristics are not closely related to those of the host contracts and the host contracts are not measured at FVTPL. Derivatives

TRANSALTA CORPORATION F 14

Notes to Consolidated Financial Statements

embedded in hybrid contracts that contain financial asset hosts within the scope of IFRS 9 are not separated and the entire contract is measured at either FVTPL or amortized cost, as appropriate.

Financial assets are derecognized when the contractual rights to receive cash flows expire. Financial liabilities are derecognized when the obligation is discharged, cancelled or expired.

Financial assets are also derecognized when the Corporation has transferred its rights to receive cash flows from the asset or has assumed an obligation to pay the received cash flows to a third party under a "pass-through" arrangement and either transferred substantially all the risks and rewards of the asset, or transferred control of the asset. TransAlta will continue to recognize the asset and any associated liability if TransAlta retains substantially all of the risks and rewards of the asset, or retains control of the asset. Continuing involvement that takes the form of a guarantee over the transferred asset is measured at the lower of the original carrying amount of the asset and the maximum amount of consideration that TransAlta could be required to repay.

Financial assets and financial liabilities are offset and the net amount is reported in the Consolidated Statements of Financial Position if there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis or to realize the assets and settle the liabilities simultaneously.

Transaction costs are expensed as incurred for financial instruments classified or designated as at fair value through profit or loss. For other financial instruments, such as debt instruments, transaction costs are recognized as part of the carrying amount of the financial instrument. The Corporation uses the effective interest method of amortization for any transaction costs or fees, premiums or discounts earned or incurred for financial instruments measured at amortized cost.

Impairment of Financial Assets

TransAlta recognizes an allowance for expected credit losses for financial assets measured at amortized cost as well as certain other instruments. The loss allowance for a financial asset is measured at an amount equal to the lifetime expected credit loss if its credit risk has increased significantly since initial recognition, or if the financial asset is a purchased or originated credit-impaired financial asset. If the credit risk on a financial asset has not increased significantly since initial recognition, its loss allowance is measured at an amount equal to the 12-month expected credit loss.

For trade receivables, lease receivables and contract assets recognized under IFRS 15, TransAlta applies a simplified approach for measuring the loss allowance. Therefore, the Corporation does not track changes in credit risk but instead recognizes a loss allowance at an amount equal to the lifetime expected credit losses at each reporting date.

The assessment of the expected credit loss is based on historical data and adjusted by forward-looking information. Forward-looking information utilized includes third-party default rates over time, dependent on credit ratings.

II. Hedges

A relationship qualifies for hedge accounting if, at inception, it is formally designated and documented as a hedge, and the hedging instrument and the hedged item have values that generally move in opposite direction because of the hedged risk. The documentation includes identification of the hedging instrument and hedged item or transaction, the nature of the risk being hedged, the Corporation’s risk management objectives and strategy for undertaking the hedge, and how hedge effectiveness will be assessed. The process of hedge accounting includes linking derivatives to specific recognized assets and liabilities or to specific firm commitments or highly probable anticipated transactions.

The Corporation formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives used are highly effective in offsetting changes in fair values or cash flows of hedged items. If hedge criteria are not met or the Corporation does not apply hedge accounting, the derivative is accounted for on the Consolidated Statements of Financial Position at fair value, with subsequent changes in fair value recorded in net earnings in the period of change.

Fair Value Hedges

TRANSALTA CORPORATION F 15

Notes to Consolidated Financial Statements

For fair value hedges relating to items carried at amortized cost, any adjustment to carrying value is amortized through profit or loss over the remaining term of the hedge using the effective interest rate ("EIR") method. The EIR amortization may begin as soon as an adjustment exists and no later than when the hedged item ceases to be adjusted for changes in its fair value attributable to the risk being hedged.

If the hedged item is derecognized, the unamortized fair value is recognized immediately in profit or loss.

Cash Flow Hedges

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in OCI while any ineffective portion is recognized in net earnings. The cash flow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item.

If cash flow hedge accounting is discontinued, the amounts previously recognized in AOCI must remain in AOCI if the hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately reclassified to net earnings as a reclassification adjustment. After discontinuation, once the hedged cash flow occurs, any amount remaining in AOCI must be accounted for depending on the nature of the underlying transaction.

Hedges of Foreign Currency Exposures of a Net Investment in a Foreign Operation

III. Financial Instruments and Hedges Accounting Policy for Prior Years

Financial Instruments

Financial assets and financial liabilities, including derivatives and certain non-financial derivatives, are recognized on the Consolidated Statements of Financial Position when the Corporation becomes a party to the contract. All financial instruments, except for certain non-financial derivative contracts that meet the Corporation’s own use requirements, are measured at fair value upon initial recognition. Measurement in subsequent periods depends on whether the financial instrument has been classified as: at fair value through profit or loss, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities. Classification of the financial instrument is determined at inception depending on the nature and purpose of the financial instrument.

Financial assets and financial liabilities classified or designated as at fair value through profit or loss are measured at fair value with changes in fair values recognized in net earnings. Financial assets classified as either held-to-maturity or as loans and receivables, and other financial liabilities, are measured at amortized cost using the effective interest method of amortization. Other financial assets are those non-derivative financial assets that are designated as such or that have not been classified as another type of financial asset, and are measured at fair value through OCI. Other financial assets are measured at cost if fair value is not reliably measurable.

Financial assets are assessed for impairment on an ongoing basis and at reporting dates. An impairment may exist if an incurred loss event has arisen that has an impact on the recoverability of the financial asset. Factors that may indicate an incurred loss event and related impairment may exist include, for example, if a debtor is experiencing significant financial difficulty, or a debtor has entered or it is probable that they will enter, bankruptcy or other financial reorganization. The carrying amount of financial assets, such as receivables, is reduced for impairment losses through the use of an allowance account, and the loss is recognized in net earnings.

Financial assets are derecognized when the contractual rights to receive cash flows expire. Financial liabilities are derecognized when the obligation is discharged, cancelled or expired.

Derivative instruments that are embedded in financial or non-financial contracts that are not already required to be recognized at fair value are treated and recognized as separate derivatives if their risks and characteristics are not closely related to their host contracts and the contract is not measured at fair value. Changes in the fair values of these and other derivative instruments are recognized in net earnings with the exception of the effective portion of i) derivatives designated

TRANSALTA CORPORATION F 16

Notes to Consolidated Financial Statements

as cash flow hedges and ii) hedges of foreign currency exposure of a net investment in a foreign operation, each of which is recognized in OCI.

Hedges

Where hedge accounting can be applied and the Corporation chooses to seek hedge accounting treatment, a hedge relationship is designated as a fair value hedge, a cash flow hedge or a hedge of foreign currency exposures of a net investment in a foreign operation. A hedging relationship qualifies for hedge accounting if, at inception, it is formally designated and documented as a hedge, and the hedge is expected to be highly effective at inception and on an ongoing basis. The documentation includes identification of the hedging instrument and hedged item or transaction, the nature of the risk being hedged, the Corporation’s risk management objectives and strategy for undertaking the hedge, and how hedge effectiveness will be assessed. The process of hedge accounting includes linking derivatives to specific recognized assets and liabilities or to specific firm commitments or highly probable anticipated transactions.

Fair Value Hedges

In a fair value hedging relationship, the carrying amount of the hedged item is adjusted for changes in fair value attributable to the hedged risk, with the changes being recognized in net earnings. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging derivative, which is also recorded in net earnings. Hedge effectiveness for fair value hedges is achieved if changes in the fair value of the derivative are highly effective at offsetting changes in the fair value of the item hedged. If hedge accounting is discontinued, the carrying amount of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying amount of the hedged item are amortized to net earnings over the remaining term of the original hedging relationship.

The Corporation primarily uses interest rate swaps as fair value hedges to manage the ratio of floating rate versus fixed rate debt. Interest rate swaps require the periodic exchange of payments without the exchange of the notional principal amount on which the payments are based. Interest expense on the debt is adjusted to include the payments made or received under the interest rate swaps.

Cash Flow Hedges

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in OCI while any ineffective portion is recognized in net earnings. Hedge effectiveness is achieved if the derivative’s cash flows are highly effective at offsetting the cash flows of the hedged item and the timing of the cash flows is similar. All components of each derivative’s change in fair value are included in the assessment of cash flow hedge effectiveness. If hedge accounting is discontinued, the amounts previously recognized in AOCI are reclassified to net earnings during the periods when the variability in the cash flows of the hedged item affects net earnings. Gains and losses on derivatives are reclassified to net earnings from AOCI immediately when the forecasted transaction is no longer expected to occur within the time period specified in the hedge documentation.

The Corporation primarily uses physical and financial swaps, forward sales contracts, futures contracts and options as cash flow hedges to hedge the Corporation’s exposure to fluctuations in electricity and natural gas prices. If hedging criteria are met, the fair values of the hedges are recorded in risk management assets or liabilities with changes in value being reported in OCI. Gains and losses on these derivatives are recognized, on settlement, in net earnings in the same period and financial statement caption as the hedged exposure.

The Corporation also uses foreign currency forward contracts as cash flow hedges to hedge the foreign exchange exposures resulting from highly probable forecasted project-related costs denominated in foreign currencies. If the hedging criteria are met, changes in fair value are reported in OCI with the fair value being reported in risk management assets or liabilities, as appropriate. Upon settlement of the derivative, any gain or loss on the forward contracts is included in the cost of the asset acquired or liability incurred.

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Notes to Consolidated Financial Statements

The Corporation uses forward starting interest rate swaps as cash flow hedges to hedge exposures to anticipated changes in interest rates for forecasted issuances of debt. If the hedging criteria are met, changes in fair value are reported in OCI with the fair value being reported in risk management assets or liabilities, as appropriate. When the swaps are closed out on issuance of the debt, the resulting gains or losses recorded in AOCI are amortized to net earnings over the term of the swap. If no debt is issued, the gains or losses are recognized in net earnings immediately.

Hedges of Foreign Currency Exposures of a Net Investment in a Foreign Operation

In hedging a foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instrument is recognized in OCI and the ineffective portion is recognized in net earnings. The related fair values are recorded in risk management assets or liabilities, as appropriate. The amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in the hedged net investment as a result of a disposal, partial disposal or loss of control. The Corporation primarily uses foreign currency forward contracts and foreign-denominated debt to hedge exposure to changes in the carrying values of the Corporation’s net investments in foreign operations that result from changes in foreign exchange rates.

D. Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash and highly liquid investments with original maturities of three months or less.

E. Collateral Paid and Received

The terms and conditions of certain contracts may require the Corporation or its counterparties to provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may decrease the credit limits granted and accordingly increase the amount of collateral that may have to be provided.

F. Inventory

I. Fuel

The Corporation’s inventory balance is comprised of coal and natural gas used as fuel, which is measured at the lower of weighted average cost and net realizable value.

The cost of internally produced coal inventory is determined using absorption costing, which is defined as the sum of all applicable expenditures and charges directly incurred in bringing inventory to its existing condition and location. Available coal inventory tends to increase during the second and third quarters as a result of favourable weather conditions and lower electricity production as maintenance is performed. Due to the limited number of processing steps incurred in mining coal and preparing it for consumption and its relatively low value on a per-unit basis, management does not distinguish between work in process and coal available for consumption. The cost of natural gas and purchased coal inventory includes all applicable expenditures and charges incurred in bringing the inventory to its existing condition and location.

II. Energy Marketing

Commodity inventories held in the Energy Marketing segment for trading purposes are measured at fair value less costs to sell. Changes in fair value less costs to sell are recognized in net earnings in the period of change.

III. Parts, Materials and Supplies

Parts, materials and supplies are recorded at the lower of cost, measured at moving average costs, and net realizable value.

G. Property, Plant and Equipment

The Corporation’s investment in property, plant and equipment (“PP&E”) is initially measured at the original cost of each component at the time of construction, purchase or acquisition. A component is a tangible portion of an asset that can be separately identified and depreciated over its own expected useful life, and is expected to provide a benefit for a period in excess of one year. Original cost includes items such as materials, labour, borrowing costs and other directly attributable costs, including the initial estimate of the cost of decommissioning and restoration. Costs are recognized as PP&E assets if it is probable that future economic benefits will be realized and the cost of the item can be measured reliably. The cost of major spare parts is capitalized and classified as PP&E, as these items can only be used in connection with an item of PP&E.

Planned maintenance is performed at regular intervals. Planned major maintenance includes inspection, repair and maintenance of existing components, and the replacement of existing components. Costs incurred for planned major maintenance activities are capitalized in the period maintenance activities occur and are amortized on a straight-line basis

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Notes to Consolidated Financial Statements

over the term until the next major maintenance event. Expenditures incurred for the replacement of components during major maintenance are capitalized and amortized over the estimated useful life of such components.

The cost of routine repairs and maintenance and the replacement of minor parts are charged to net earnings as incurred.

Subsequent to initial recognition and measurement at cost, all classes of PP&E continue to be measured using the cost model and are reported at cost less accumulated depreciation and impairment losses, if any.

An item of PP&E or a component is derecognized upon disposal or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition is included in net earnings when the asset is derecognized.

The estimate of the useful lives of each component of PP&E is based on current facts and past experience, and takes into consideration existing long-term sales agreements and contracts, current and forecasted demand, and the potential for technological obsolescence. The useful life is used to estimate the rate at which the component of PP&E is depreciated. PP&E assets are subject to depreciation when the asset is considered to be available for use, which is typically upon commencement of commercial operations. Capital spares that are designated as critical for uninterrupted operation in a particular facility are depreciated over the life of that facility, even if the item is not in service. Other capital spares begin to be depreciated when the item is put into service. Each significant component of an item of PP&E is depreciated to its residual value over its estimated useful life, generally using straight-line or unit-of-production methods. Estimated useful lives, residual values and depreciation methods are reviewed annually and are subject to revision based on new or additional information. The effect of a change in useful life, residual value or depreciation method is accounted for prospectively.

Estimated useful lives of the components of depreciable assets, categorized by asset class, are as follows:



Coal generation	2-12 years
Gas generation	2-30 years
Hydro generation	3-60 years
Wind generation	3-30 years
Mining property and equipment	2-12 years
Capital spares and other	2-30 years

TransAlta capitalizes borrowing costs on capital invested in projects under construction (see Note 2(S)). Upon commencement of commercial operations, capitalized borrowing costs, as a portion of the total cost of the asset, are depreciated over the estimated useful life of the related asset.

H. Intangible Assets

Intangible assets acquired in a business combination are recognized separately from goodwill at their fair value at the date of acquisition. Intangible assets acquired separately are recognized at cost. Internally generated intangible assets arising from development projects are recognized when certain criteria related to the feasibility of internal use or sale, and probable future economic benefits of the intangible asset, are demonstrated.

Intangible assets are initially recognized at cost, which is comprised of all directly attributable costs necessary to create, produce and prepare the intangible asset to be capable of operating in the manner intended by management.

Subsequent to initial recognition, intangible assets continue to be measured using the cost model, and are reported at cost less accumulated amortization and impairment losses, if any. Amortization is included in depreciation and amortization and fuel and purchased power in the Consolidated Statements of Earnings (Loss).

Amortization commences when the intangible asset is available for use, and is computed on a straight-line basis over the intangible asset’s estimated useful life, except for coal rights, which are amortized using a unit-of-production basis, based on the estimated mine reserves. Estimated useful lives of intangible assets may be determined, for example, with reference to the term of the related contract or licence agreement. The estimated useful lives and amortization methods are reviewed annually with the effect of any changes being accounted for prospectively.

Intangible assets consist of power sale contracts with fixed prices higher than market prices at the date of acquisition, coal rights, software and intangibles under development. Estimated useful lives of intangible assets are as follows:



Software	2-7 years
Power sale contracts	5-20 years

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Notes to Consolidated Financial Statements

I. Impairment of Tangible and Intangible Assets Excluding Goodwill

At the end of each reporting period, the Corporation assesses whether there is any indication that PP&E and finite life intangible assets are impaired.

Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected operating results; significant changes in the manner in which an asset is used, or in the Corporation’s overall business strategy; or significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations where the Corporation is not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.

The Corporation’s operations, the market and business environment are routinely monitored, and judgments and assessments are made to determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is made of the recoverable amount of the asset or cash-generating unit (“CGU”) to which the asset belongs. Recoverable amount is the higher of an asset’s fair value less costs of disposal and its value in use. Fair value is the price that would be received to sell an asset in an orderly transaction between market participants at the measurement date. In determining fair value, recent market transactions are taken into account. If no such transactions can be identified, an appropriate valuation model such as discounted cash flows is used. Value in use is the present value of the estimated future cash flows expected to be derived from the asset from its continued use and ultimate disposal by the Corporation. If the recoverable amount is less than the carrying amount of the asset or CGU, an asset impairment loss is recognized in net earnings, and the asset’s carrying amount is reduced to its recoverable amount.

At each reporting date, an assessment is made whether there is any indication that an impairment loss previously recognized may no longer exist or may have decreased. If such indication exists, the recoverable amount of the asset or CGU to which the asset belongs is estimated, and, if there has been an increase in the recoverable amount, the impairment loss previously recognized is reversed. Where an impairment loss is subsequently reversed, the carrying amount of the asset is increased to the lesser of the revised estimate of its recoverable amount or the carrying amount that would have been determined (net of depreciation) had no impairment loss been recognized previously. A reversal of an impairment loss is recognized in net earnings.

J. Goodwill

Goodwill arising in a business combination is recognized as an asset at the date control is acquired. Goodwill is measured as the cost of an acquisition plus the amount of any non-controlling interest in the acquiree (if applicable) less the fair value of the related identifiable assets acquired and liabilities assumed.

Goodwill is not subject to amortization, but is tested for impairment at least annually, or more frequently, if an analysis of events and circumstances indicate that a possible impairment may exist. These events could include a significant change in financial position of the CGUs or groups of CGUs to which the goodwill relates or significant negative industry or economic trends. For impairment purposes, goodwill is allocated to each of the Corporation’s CGUs or groups of CGUs that are expected to benefit from the synergies of the business combination in which the goodwill arose. To test for impairment, the recoverable amount of the CGUs or groups of CGUs to which the goodwill relates is compared to its carrying amount. If the recoverable amount is less than the carrying amount, an impairment loss is recognized in net earnings immediately, by first reducing the carrying amount of the goodwill, and then by reducing the carrying amount of the other assets in the unit. An impairment loss recognized for goodwill is not reversed in subsequent periods.

K. Project Development Costs

Project development costs include external, direct and incremental costs that are necessary for completing an acquisition or construction project. These costs are recognized as operating expenses until construction of a plant or acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable, and that efforts will result in future value to the Corporation, at which time the costs incurred subsequently are included in other assets. The appropriateness of capitalization of these costs is evaluated each reporting period, and amounts capitalized for projects no longer probable of occurring are charged to net earnings.

L. Income Taxes

The Corporation uses the liability method of accounting for income taxes. Under the liability method, deferred income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and their respective income tax basis (temporary differences). A deferred income tax asset may also be recognized for the benefit expected from unused tax credits and losses available for carryforward, to the extent that it is probable that future taxable

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Notes to Consolidated Financial Statements

earnings will be available against which the tax credits and losses can be applied. Deferred income tax assets and liabilities are measured based on income tax rates and tax laws that are enacted or substantively enacted by the end of the reporting period and that are expected to apply in the years in which temporary differences are expected to be realized or settled. Deferred income tax is charged or credited to net earnings, except when related to items charged or credited to either OCI or directly to equity. The carrying amount of deferred income tax assets is evaluated at the end of each reporting period and is reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be realized.

Deferred income tax liabilities are recognized for taxable temporary differences arising on investments in subsidiaries, except where the Corporation is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

M. Employee Future Benefits

The Corporation has defined benefit pension and other post-employment benefit plans. The current service cost of providing benefits under the defined benefit plans is determined using the projected unit credit method pro-rated based on service. The net interest cost is determined by applying the discount rate to the net defined benefit liability. The discount rate used to determine the present value of the defined benefit obligation, and the net interest cost, is determined by reference to market yields at the end of the reporting period on high-quality corporate bonds with terms and currencies that match the estimated terms and currencies of the benefit obligations. Remeasurements, which include actuarial gains and losses and the return on plan assets (excluding net interest), are recognized through OCI in the period in which they occur. Actuarial gains and losses arise from experience adjustments and changes in actuarial assumptions. Remeasurements are not reclassified to profit or loss, from OCI, in subsequent periods.

Gains or losses arising from either a curtailment or settlement of a defined benefit plan are recognized when the curtailment or settlement occurs. When the restructuring of a benefit plan gives rise to a curtailment and a settlement of obligations, the curtailment is accounted for prior to the settlement.

In determining whether statutory minimum funding requirements of the Corporation’s defined benefit pension plans give rise to recording an additional liability, letters of credit provided by the Corporation as security are considered to alleviate the funding requirements. No additional liability results in these circumstances.

Contributions payable under defined contribution pension plans are recognized as a liability and an expense in the period in which the services are rendered.

N. Provisions

Provisions are recognized when the Corporation has a present obligation (legal or constructive) as a result of a past event, it is probable that the Corporation will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation. A legal obligation can arise through a contract, legislation or other operation of law. A constructive obligation arises from an entity’s actions whereby through an established pattern of past practice, published policies or a sufficiently specific current statement, the entity has indicated it will accept certain responsibilities and has thus created a valid expectation that it will discharge those responsibilities. The amount recognized as a provision is the best estimate, remeasured at each period-end, of the expenditures required to settle the present obligation, considering the risks and uncertainties associated with the obligation. Where expenditures are expected to be incurred in the future, the obligation is measured at its present value using a current market-based, risk-adjusted interest rate.

The Corporation records a decommissioning and restoration provision for all generating facilities and mine sites for which it is legally or constructively required to remove the facilities at the end of their useful lives and restore the plant or mine sites. For some hydro facilities, the Corporation is required to remove the generating equipment, but is not required to remove the structures. Initial decommissioning provisions are recognized at their present value when incurred. Each reporting date, the Corporation determines the present value of the provision using the current discount rates that reflect the time value of money and associated risks. The Corporation recognizes the initial decommissioning and restoration provisions, as well as changes resulting from revisions to cost estimates and period-end revisions to the market-based, risk-adjusted discount rate, as a cost of the related PP&E (see Note 2(G)). The accretion of the net present value discount is charged to net earnings each period and is included in net interest expense. Where the Corporation expects to receive reimbursement from a third party for a portion of future decommissioning costs, the reimbursement is recognized as a separate asset when it is virtually certain that the reimbursement will be received. Decommissioning and restoration obligations for coal mines are incurred over time as new areas are mined, and a portion of the provision is settled over time as areas are reclaimed prior to final pit reclamation. Reclamation costs for mining assets are recognized on a unit-of-production basis.

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Notes to Consolidated Financial Statements

Changes in other provisions resulting from revisions to estimates of expenditures required to settle the obligation or period-end revisions to the market-based, risk-adjusted discount rate are recognized in net earnings. The accretion of the net present value discount is charged to net earnings each period and is included in net interest expense.

O. Share-Based Payments

The Corporation measures share-based awards compensation expense at grant date fair value and recognizes the expense over the vesting period based on the Corporation’s estimate of the number of units that will eventually vest. Any award that vests in installments is accounted for as a separate award with its own distinct fair value measurement.

Compensation expense associated with equity-settled and cash-settled awards are recognized within equity and liability, respectively. The liability associated with cash-settled awards is remeasured to fair value at each reporting date up to, and including, the settlement date, with changes in fair value recognized within compensation expense.

P. Emission Credits and Allowances

Emission credits and allowances are recorded as inventory at cost. Those purchased for use by the Corporation are recorded at cost and are carried at the lower of weighted average cost and net realizable value. Credits granted to, or internally generated by, TransAlta are recorded at nil. Emission liabilities are recorded using the best estimate of the amount required by the Corporation to settle its obligation in excess of government-established caps and targets. To the extent compliance costs are recoverable under the terms of contracts with third parties, the amounts are recognized as revenue in the period of recovery.

Emission credits and allowances that are held for trading and that meet the definition of a derivative are accounted for using the fair value method of accounting. Emission credits and allowances that do not satisfy the criteria of a derivative are accounted for using the accrual method.

Q. Assets Held for Sale

Assets are classified as held for sale if their carrying amount will be recovered primarily through a sale as opposed to continued use by the Corporation. Assets classified as held for sale are measured at the lower of their carrying amount and fair value less costs of disposal. Any impairment is recognized in net earnings. Depreciation and equity accounting ceases when an asset or equity investment, respectively, is classified as held for sale. Assets classified as held for sale are reported as current assets in the Consolidated Statements of Financial Position.

R. Leases

A lease is an arrangement whereby the lessor conveys to the lessee, in return for a payment or series of payments, the right to use an asset for an agreed period of time.

Power purchase arrangements (“PPA”) and other long-term contracts may contain, or may be considered, leases where the fulfilment of the arrangement is dependent on the use of a specific asset (e.g., a generating unit) and the arrangement conveys to the customer the right to use that asset.

Where the Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the customer assuming the principal risks and rewards of ownership of the asset, the arrangement is a finance lease. Assets subject to finance leases are not reflected as PP&E and the net investment in the lease, represented by the present value of the amounts due from the lessee, is recorded in the Consolidated Statements of Financial Position as a financial asset, classified as a finance lease receivable. The payments considered to be part of the leasing arrangement are apportioned between a reduction in the lease receivable and finance lease income. The finance lease income element of the payments is recognized using a method that results in a constant rate of return on the net investment in each period and is reflected in finance lease income on the Consolidated Statements of Earnings (Loss).

Where the Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the Corporation retaining the principal risks and rewards of ownership of the asset, the arrangement is an operating lease. For operating leases, the asset is, or continues to be, capitalized as PP&E and depreciated over its useful life. Rental income, including contingent rent, from operating leases is recognized over the term of the arrangement and is reflected in revenue on the Consolidated Statements of Earnings (Loss). Contingent rent may arise when payments due under the contract are not fixed in amount but vary based on a future factor such as the amount of use or production.

Leasing or other contractual arrangements that transfer substantially all of the risks and rewards of ownership to the Corporation are considered finance leases. A leased asset and lease obligation are recognized at the lower of the fair value or the present value of the minimum lease payments. Lease payments are apportioned between interest expense and a

TRANSALTA CORPORATION F 22

Notes to Consolidated Financial Statements

reduction of the lease liability. Contingent rents are charged as expenses in the periods incurred. The leased asset is depreciated over the shorter of the estimated useful life of the asset and the lease term.

S. Borrowing Costs

TransAlta capitalizes borrowing costs that are directly attributable to, or relate to general borrowings used for, the construction of qualifying assets. Qualifying assets are assets that take a substantial period of time to prepare for their intended use and typically include generating facilities or other assets that are constructed over periods of time exceeding 12 months. Borrowing costs are considered to be directly attributable if they could have been avoided if the expenditure on the qualifying asset had not been made. Borrowing costs that are capitalized are included in the cost of the related PP&E component. Capitalization of borrowing costs ceases when substantially all the activities necessary to prepare the asset for its intended use are complete.

All other borrowing costs are expensed in the period in which they are incurred.

T. Non-Controlling Interests

Non-controlling interests arise from business combinations in which the Corporation acquires less than a 100 per cent interest. Non-controlling interests are initially measured at either fair value or at the non-controlling interest’s proportionate share of the acquiree’s identifiable net assets. The Corporation determines on a transaction by transaction basis which measurement method is used. Non-controlling interests also arise from other contractual arrangements between the Corporation and other parties, whereby the other party has acquired an interest in a specified asset or operation, and the Corporation retains control.

Subsequent to acquisition, the carrying amount of non-controlling interests is increased or decreased by the non-controlling interest’s share of subsequent changes in equity and payments to the non-controlling interest. Total comprehensive income is attributed to the non-controlling interests even if this results in the non-controlling interests having a negative balance.

U. Joint Arrangements

A joint arrangement is a contractual arrangement that establishes the terms by which two or more parties agree to undertake and jointly control an economic activity. TransAlta’s joint arrangements are generally classified as two types: joint operations and joint ventures.

A joint operation arises when the parties that have joint control have rights to the assets and obligations for the liabilities relating to the arrangement. Generally, each party takes a share of the output from the asset and each bears an agreed upon share of the costs incurred in respect of the joint operation. The Corporation reports its interests in joint operations in its consolidated financial statements using the proportionate consolidation method by recognizing its share of the assets, liabilities, revenues and expenses in respect of its interest in the joint operation.

In a joint venture, the venturers do not have rights to individual assets or obligations of the venture. Rather, each venturer has rights to the net assets of the arrangement. The Corporation reports its interests in joint ventures using the equity method. Under the equity method, the investment is initially recognized at cost and the carrying amount is increased or decreased to recognize the Corporation’s share of the joint venture’s net earnings or loss after the date of acquisition. The impact of transactions between the Corporation and joint ventures is eliminated based on the Corporation’s ownership interest. Distributions received from joint ventures reduce the carrying amount of the investment. Any excess of the cost of an acquisition less the fair value of the recognized identifiable assets, liabilities and contingent liabilities of an acquired joint venture is recognized as goodwill and is included in the carrying amount of the investment and is assessed for impairment as part of the investment.

Investments in joint ventures are evaluated for impairment at each reporting date by first assessing whether there is objective evidence that the investment is impaired. If such objective evidence is present, an impairment loss is recognized if the investment’s recoverable amount is less than its carrying amount. The investment’s recoverable amount is determined as the higher of value in use and fair value less costs of disposal.

V. Government Incentives

Government incentives are recognized when the Corporation has reasonable assurance that it will comply with the conditions associated with the incentive and that the incentive will be received. When the incentive relates to an expense item, it is recognized in net earnings over the same period in which the related costs or revenues are recognized. When the

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Notes to Consolidated Financial Statements

incentive relates to an asset, it is recognized as a reduction of the carrying amount of PP&E and released to earnings as a reduction in depreciation over the expected useful life of the related asset.

W. Earnings per Share

Basic earnings per share is calculated by dividing net earnings attributable to common shareholders by the weighted average number of common shares outstanding in the year.

Diluted earnings per share is calculated by dividing net earnings attributable to common shareholders, adjusted for the after-tax effects of dividends, interest or other changes in net earnings that would result from potential dilutive instruments, by the weighted average number of common shares outstanding in the year, adjusted for additional common shares that would have been issued on the conversion of all potential dilutive instruments.

X. Business Combinations

Transactions in which the acquisition constitutes a business are accounted for using the acquisition method. Identifiable assets acquired and liabilities assumed are measured at their acquisition date fair values. Goodwill is measured as the excess of the fair value of consideration transferred less the fair value of the identifiable assets acquired and liabilities assumed.

Acquisition-related costs to effect the business combination, with the exception of costs to issue debt or equity securities, are recognized in net earnings as incurred.

Y. Stripping Costs

A mine stripping activity asset is recognized when all of the following are met: i) it is probable that the future benefit associated with improved access to the coal reserves associated with the stripping activity will be realized; ii) the component of the coal reserve to which access has been improved can be identified; and iii) the costs related to the stripping activity associated with that component can be measured reliably. Costs include those directly incurred to perform the stripping activity as well as an allocation of directly attributable overheads. The resulting stripping activity asset is amortized on a unit-of-production basis over the expected useful life of the identified component that it relates to. The amortization is recognized as a component of the standard cost of coal inventory.

Z. Significant Accounting Judgments and Key Sources of Estimation Uncertainty

The preparation of financial statements requires management to make judgments, estimates and assumptions that could affect the reported amounts of assets, liabilities, revenues, expenses and disclosures of contingent assets and liabilities during the period. These estimates are subject to uncertainty. Actual results could differ from those estimates due to factors such as fluctuations in interest rates, foreign exchange rates, inflation and commodity prices, and changes in economic conditions, legislation and regulations.

In the process of applying the Corporation’s accounting policies, management has to make judgments and estimates about matters that are highly uncertain at the time the estimate is made and that could significantly affect the amounts recognized in the consolidated financial statements. Different estimates with respect to key variables used in the calculations, or changes to estimates, could potentially have a material impact on the Corporation’s financial position or performance. The key judgments and sources of estimation uncertainty are described below:

I. Impairment of PP&E and Goodwill

Impairment exists when the carrying amount of an asset, CGU or group of CGUs to which goodwill relates exceeds its recoverable amount, which is the higher of its fair value less costs of disposal and its value in use. An assessment is made at each reporting date as to whether there is any indication that an impairment loss may exist or that a previously recognized impairment loss may no longer exist or may have decreased. In determining fair value less costs of disposal, information about third-party transactions for similar assets is used and if none is available, other valuation techniques, such as discounted cash flows, are used. Value in use is computed using the present value of management’s best estimates of future cash flows based on the current use and present condition of the asset.

In estimating either fair value less costs of disposal or value in use using discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel consumed, capital expenditures, retirement costs and other related cash inflows and outflows over the life of the facilities, which can range from 30 to 60 years. In developing these assumptions, management uses estimates of contracted and future market prices based on expected market supply and demand in the region in which the plant operates, anticipated production levels, planned and unplanned outages, changes to regulations and transmission capacity or constraints for the remaining life of the facilities.

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Notes to Consolidated Financial Statements

Discount rates are determined by employing a weighted average cost of capital methodology that is based on capital structure, cost of equity and cost of debt assumptions based on comparable companies with similar risk characteristics and market data as the asset, CGU or group of CGUs subject to the test. These estimates and assumptions are susceptible to change from period to period and actual results can, and often do, differ from the estimates, and can have either a positive or negative impact on the estimate of the impairment charge, and may be material.

With regard to the allocation or reallocation of goodwill, significant judgment is required to evaluate synergies and their impacts. Minimum thresholds also exist with respect to segmentation and internal monitoring activities. The Corporation evaluates synergies with regards to opportunities from combined talent and technology, functional organization and future growth potential, and considers its own performance measurement processes in making this determination. Information regarding significant judgments and estimates in respect of impairment during 2016 to 2018 is found in Notes 7 and 18 .

II. Leases

In determining whether the Corporation’s PPAs and other long-term electricity and thermal sales contracts contain, or are, leases, management must use judgment in assessing whether the fulfilment of the arrangement is dependent on the use of a specific asset and the arrangement conveys the right to use the asset. For those agreements considered to contain, or be, leases, further judgment is required to determine whether substantially all of the significant risks and rewards of ownership are transferred to the customer or remain with the Corporation, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant and impact how the Corporation classifies amounts related to the arrangement as either PP&E or as a finance lease receivable on the Consolidated Statements of Financial Position, and therefore the amount of certain items of revenue and expense is dependent upon such classifications.

III. Income Taxes

Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of the jurisdictions in which the Corporation operates. The process also involves making an estimate of income taxes currently payable and income taxes expected to be payable or recoverable in future periods, referred to as deferred income taxes. Deferred income taxes result from the effects of temporary differences due to items that are treated differently for tax and accounting purposes. The tax effects of these differences are reflected in the Consolidated Statements of Financial Position as deferred income tax assets and liabilities. An assessment must also be made to determine the likelihood that the Corporation’s future taxable income will be sufficient to permit the recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be reduced. Management uses the Corporation’s long-range forecasts as a basis for evaluation of recovery of deferred income tax assets. Management must exercise judgment in its assessment of continually changing tax interpretations, regulations and legislation to ensure deferred income tax assets and liabilities are complete and fairly presented. Differing assessments and applications than the Corporation’s estimates could materially impact the amounts recognized for deferred income tax assets and liabilities. See Note 11 for further details on the impacts of the Corporation’s tax policies.

IV. Financial Instruments and Derivatives

The Corporation’s financial instruments and derivatives are accounted for at fair value, with the initial and subsequent changes in fair value affecting earnings in the period the change occurs. The fair values of financial instruments and derivatives are classified within three levels, with Level III fair values determined using inputs for the asset or liability that are not readily observable. These fair value levels are outlined and discussed in more detail in Note 14 . Some of the Corporation’s fair values are included in Level III because they are not traded on an active exchange or have terms that extend beyond the time period for which exchange-based quotes are available and require the use of internal valuation techniques or models to determine fair value.

The determination of the fair value of these contracts and derivative instruments can be complex and relies on judgments and estimates concerning future prices, volatility and liquidity, among other factors. These fair value estimates may not necessarily be indicative of the amounts that could be realized or settled, and changes in these assumptions could affect

TRANSALTA CORPORATION F 25

Notes to Consolidated Financial Statements

the reported fair value of financial instruments. Fair values can fluctuate significantly and can be favourable or unfavourable depending on current market conditions. Judgment is also used in determining whether a highly probable forecasted transaction designated in a cash flow hedge is expected to occur based on the Corporation’s estimates of pricing and production to allow the future transaction to be fulfilled.

V. Project Development Costs

Project development costs are capitalized in accordance with the accounting policy in Note 2(K). Management is required to use judgment to determine if there is reason to believe that future costs are recoverable, and that efforts will result in future value to the Corporation, in determining the amount to be capitalized. Information on the write-off of project development costs is disclosed in Note 7 (B).

VI. Provisions for Decommissioning and Restoration Activities

TransAlta recognizes provisions for decommissioning and restoration obligations as outlined in Note 2(N) and Note 21 . Initial decommissioning provisions, and subsequent changes thereto, are determined using the Corporation’s best estimate of the required cash expenditures, adjusted to reflect the risks and uncertainties inherent in the timing and amount of settlement. The estimated cash expenditures are present valued using a current, risk-adjusted, market-based, pre-tax discount rate. A change in estimated cash flows, market interest rates or timing could have a material impact on the carrying amount of the provision.

VII. Useful Life of PP&E

Each significant component of an item of PP&E is depreciated over its estimated useful life. Estimated useful lives are determined based on current facts and past experience, and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological obsolescence and regulations. The useful lives of PP&E are reviewed at least annually to ensure they continue to be appropriate. Information on changes in useful lives of facilities is disclosed in Note 3(A)(III).

VIII. Employee Future Benefits

The Corporation provides pension and other post-employment benefits, such as health and dental benefits, to employees. The cost of providing these benefits is dependent upon many factors, including actual plan experience and estimates and assumptions about future experience.

The liability for pension and post-employment benefits and associated costs included in annual compensation expenses are impacted by estimates related to:


▪	employee demographics, including age, compensation levels, employment periods, the level of contributions made to the plans and earnings on plan assets, ;


▪	the effects of changes to the provisions of the plans; and


▪	changes in key actuarial assumptions, including rates of compensation and health-care cost increases, and discount rates.

Due to the complexity of the valuation of pension and post-employment benefits, a change in the estimate of any one of these factors could have a material effect on the carrying amount of the liability for pension and other post-employment benefits or the related expense. These assumptions are reviewed annually to ensure they continue to be appropriate. See Note 28 for disclosures on employee future benefits.

IX. Other Provisions

Where necessary, TransAlta recognizes provisions arising from ongoing business activities, such as interpretation and application of contract terms, ongoing litigation and force majeure claims. These provisions, and subsequent changes thereto, are determined using the Corporation’s best estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially from the amount recognized. More information is disclosed in Notes 4 and 21 with respect to other provisions.

TRANSALTA CORPORATION F 26

Notes to Consolidated Financial Statements

3. Accounting Changes

A. Current Accounting Changes

I. IFRS 15 Revenue from Contracts with Customers

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"), which replaces existing revenue recognition guidance with a single comprehensive accounting model. The model specifies that an entity recognizes revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. In April 2016, the IASB issued an amendment to IFRS 15 to clarify the identification of performance obligations, principal versus agent considerations, licenses of intellectual property and transition practical expedients. IFRS 15, including the amendment, is required to be adopted either retrospectively or using a modified retrospective approach for annual periods beginning on or after Jan. 1, 2018, with earlier adoption permitted.

The Corporation has adopted IFRS 15 with an initial adoption date of Jan. 1, 2018. As a result, the Corporation has changed its accounting policy for revenue recognition, which is outlined in Note 2(A).

The Corporation has elected to adopt IFRS 15 retrospectively with the modified retrospective method of transition practical expedient and has elected to apply IFRS 15 only to contracts that are not completed contracts at the date of initial application. Comparative information has not been restated and is reported under IAS 18 Revenue ("IAS 18"), which is outlined in Note 2(A)(iii).

The Corporation recognized the cumulative impact of the initial application of the standard in the deficit as at Jan. 1, 2018. Applying the significant financing component requirements to a specific contract resulted in an increase to the contract liability of $ 17 million , a decrease in deferred income tax liabilities of $4 million and an increase to the deficit of $13 million . IFRS 15 requires that, in determining the transaction price, the promised amount of consideration is to be adjusted for the effects of the time value of money if the timing of payments specified in a contract provides either party with a significant benefit of financing the transfer of goods or services to the customer (“significant financing component”). The objective when adjusting the promised amount of consideration for a significant financing component is to recognize revenue at an amount that reflects the price that the customer would have paid, had they paid cash in the future when the goods or services are transferred to them. The application of the significant financing component requirement results in the recognition of interest expense over the financing period and a higher amount of revenue.

Additionally, the Corporation no longer recognizes revenue (or fuel costs) related to non-cash consideration for natural gas supplied by a customer at one of its gas plants , as it was determined under IFRS 15 that the Corporation does not obtain control of the customer-supplied natural gas.

Refer to the discussion in Note 2(A) and in Note 5 for a breakdown of the Corporation's revenues from contracts with customers and revenues from other sources.

The following tables summarize the financial statement line items impacted by adopting IFRS 15 as at and for the year ended Dec. 31, 2018 :

Condensed Consolidated Statement of Earnings (Loss)



Year ended Dec. 31, 2018	Reported in accordance with IAS 18 and IAS 11		Adjustments		As reported under IFRS 15
Revenues	2,253		(4	)	2,249
Fuel, carbon costs and purchased power	(1,109	)	9		(1,100	)
Net interest expense	(243	)	(7	)	(250	)
Net earnings impact	(88	)	(2	)	(90	)

TRANSALTA CORPORATION F 27

Notes to Consolidated Financial Statements

Condensed Consolidated Statements of Financial Position



As at Dec. 31, 2018	Reported in accordance with IAS 18 and IAS 11		Adjustments		As reported under IFRS 15
Deferred income tax liabilities	505		(4	)	501
Contract liability	68		19		87
Deficit	(1,481	)	(15	)	(1,496	)

There were no impacts to the statement of cash flows as a result of adopting IFRS 15.

II. IFRS 9 Financial Instruments

Effective Jan. 1, 2018, the Corporation adopted IFRS 9, which introduces new requirements for:


▪	the classification and measurement of financial assets and liabilities;


▪	the recognition and measurement of impairment of financial assets; and


▪	general hedge accounting.

In accordance with the transition provisions of the standard, the Corporation has elected to not restate prior periods. The impact of adopting IFRS 9 was recognized in the deficit at Jan. 1, 2018. While the Corporation had no direct impact of adopting IFRS 9, a $1 million increase in the deficit resulted from the increase in equity attributable to non-controlling interests due to IFRS 9 impacts at TransAlta Renewables Inc. ("TransAlta Renewables").

The Corporation's accounting policies under IFRS 9 are outlined in Note 2(C) and the key impacts are outlined below. For more information on the Corporation's accounting policies under IAS 39 for the period ended Dec. 31, 2017, refer to note 2 of the Corporation’s 2017 annual consolidated financial statements.

a. Classification and Measurement

IFRS 9 introduces the requirement to classify and measure financial assets based on their contractual cash flow characteristics and the Corporation’s business model for the financial asset. All financial assets and financial liabilities, including derivatives, are recognized at fair value on the Consolidated Statements of Financial Position when the Corporation becomes party to the contractual provisions of a financial instrument or non-financial derivative contract. Financial assets must be classified and measured at either amortized cost, at FVTPL, or at FVTOCI. Refer to Note 2 (C) for further details.

The Corporation’s management reviewed and assessed the classifications of its existing financial instruments as at Jan. 1, 2018, based on the facts and circumstances that existed at that date, as shown below. None of the reclassifications had a significant impact on the Corporation’s financial position, earnings (loss), other comprehensive income (loss) or total comprehensive income (loss) after the date of initial application.



Financial instrument	IAS 39 category	IFRS 9 classification
Cash and cash equivalents	Loans and receivables	Amortized cost
Restricted cash	Loans and receivables	Amortized cost
Trade and other receivables	Loans and receivables	Amortized cost
Long-term portion of finance lease receivables	Loans and receivables	Amortized cost
Loan receivable (other assets)	Loans and receivables	Amortized cost
Risk management assets (current and long-term) - derivatives held for trading	Held for trading	FVTPL
Risk management assets (current and long-term) - derivatives designated as hedging instruments	Derivatives designated as hedging instruments	FVOCI
Accounts payable and accrued liabilities	Other financial liabilities	Amortized cost
Dividends payable	Other financial liabilities	Amortized cost
Risk management liabilities (current and long-term) - derivatives held for trading	Held for trading	FVTPL
Risk management liabilities (current and long-term) - derivatives designated as hedging instruments	Derivatives designated as hedging instruments	FVOCI
Credit facilities and long-term debt	Other financial liabilities	Amortized cost

TRANSALTA CORPORATION F 28

Notes to Consolidated Financial Statements

b. Impairment of Financial Assets

IFRS 9 introduces a new impairment model for financial assets measured at amortized cost as well as certain other instruments. The expected credit loss model requires entities to account for expected credit losses on financial assets at the date of initial recognition, and to account for changes in expected credit losses at each reporting date to reflect changes in credit risk.

The Corporation’s management reviewed and assessed its existing financial assets for impairment using reasonable and supportable information in accordance with the requirements of IFRS 9 to determine the credit risk of the respective items at the date they were initially recognized, and compared that to the credit risk as at Jan. 1, 2018. There were no significant increases in credit risk determined upon application of IFRS 9 and no loss allowance was recognized.

c. General Hedge Accounting

IFRS 9 retains the three types of hedges from IAS 39 (fair value hedges, cash flow hedges and hedges of a net investment in a foreign operation), but increases flexibility as to the types of transactions that are eligible for hedge accounting.

The effectiveness test of IAS 39 is replaced by the principle of an “economic relationship”, which requires that the hedging instrument and the hedged item have values that generally move in opposite direction because of the hedged risk. Additionally, retrospective hedge effectiveness testing is no longer required under IFRS 9.

In accordance with IFRS 9’s transition provisions for hedge accounting, the Corporation has applied the IFRS 9 hedge accounting requirements prospectively from the date of initial application on Jan. 1, 2018, and comparative figures have not been restated. The Corporation’s qualifying hedging relationships under IAS 39 in place as at Jan. 1, 2018 also qualified for hedge accounting in accordance with IFRS 9, and were therefore regarded as continuing hedging relationships. No rebalancing of any of the hedging relationships was necessary on Jan. 1, 2018. As the critical terms of the hedging instruments match those of their corresponding hedged items, all hedging relationships continue to be effective under IFRS 9’s effectiveness assessment. The Corporation has not designated any hedging relationships under IFRS 9 that would not have met the qualifying hedge accounting criteria under IAS 39. Further details of the Corporation's hedging activities are disclosed in Notes 14 and 15 .

The Corporation’s risk management objective and strategy, including risk management instruments and their key terms, are detailed in Notes 15 A and 15 C.

In certain cases, the Corporation purchases non-financial items in a foreign currency, for which it may enter into forward contracts to hedge foreign currency risk on the anticipated purchases. Both IAS 39 and IFRS 9 require hedging gains and losses to be basis adjusted to the initial carrying amount of non-financial hedged items once recognized (such as PP&E), but under IFRS 9, these adjustments are no longer considered reclassification adjustments and do not affect OCI. Under IFRS 9, these amounts will be directly transferred to the asset and will be reflected in the statement of changes in equity as a reclassification from AOCI.

The application of IFRS 9 hedge accounting requirements has no other impact on the results and financial position of the Corporation for the current or prior years.

III. Change in Estimates - Useful Lives

As a result of the Off-Coal Agreement (“OCA”) with the Government of Alberta described in Note 4(O), the Corporation has adjusted the useful lives of some of its mine assets to align with the Corporation's coal-to-gas conversion plans. In addition, on Jan. 1, 2017, the useful lives of the PP&E and amortizable intangibles associated with some of the Corporation’s Alberta coal assets were reduced to 2030. As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2018 , increased by approximately $38 million ( 2017 - $58 million ). The useful lives may be revised or extended in compliance with the Corporation’s accounting policies, dependent upon future operating decisions and events, such as coal-to-gas conversions.

Due to the Corporation’s decision to retire Sundance Unit 1 effective Jan. 1, 2018 (see Note 4(A) for further details), the useful lives of the Sundance Unit 1 PP&E and amortizable intangibles were reduced in the second quarter of 2017 by two years to Dec. 31, 2018 . As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2017, increased by approximately $26 million .

Since Sundance Unit 1 was shut down two years early, the Canadian federal Minister of Environment & Climate Change agreed to extend the life of Sundance Unit 2 from 2019 to 2021. As such, during the third quarter of 2017, the Corporation extended the life of Sundance Unit 2 to 2021 (see Note 4(A) for further details). As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2017, decreased in total by approximately $4 million . However, in the

TRANSALTA CORPORATION F 29

Notes to Consolidated Financial Statements

third quarter of 2018, the Corporation retired Sundance Unit 2 and recorded an impairment loss for the remaining net book value of the asset (see Note 4(A) and Note 7 for further details).

B. Future Accounting Changes

Accounting standards that have been previously issued by the IASB, but are not yet effective and have not been applied by the Corporation include IFRS 16 Leases. In January 2016, the IASB issued IFRS 16 Leases , which replaces the current IFRS guidance on leases. Under current guidance, lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are recognized on the statement of financial position, while operating leases are not. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for virtually all lease contracts. An optional exemption to not recognize certain short-term leases and leases of low value can be applied by lessees. In addition, the nature and timing of expenses related to leases will change, as IFRS 16 replaces the straight-line operating leases expense with the depreciation expense for the assets and interest expense on the lease liabilities. For lessors, the accounting remains essentially unchanged.


▪	Exemption for short-term leases that have a remaining lease term of less than 12 months as at Jan. 1, 2019 and low value leases;


▪	Excluding initial direct costs for the measurement of the right-of-use asset at the date of initial application;


▪	Using hindsight in determining the lease term where the contract contains options to extend or terminate the lease;


▪	Adjusting the right-of-use assets by the amount of IAS 37 onerous contract provision immediately before the date of initial application; and


▪	Measuring the right-of-use assets at an amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognized in the statement of financial position immediately before the date of initial application.

The Corporation has substantially completed its assessment of existing operating leases. The Corporation estimates that we will recognize right-of-use lease assets and related lease liabilities for existing operating leases where we are the lessee in the range of $42 million to $52 million . These changes will be partially offset by the derecognition of a finance lease asset and a finance lease liability related to a contractual arrangement that was accounted for as a finance lease under IAS 17 but is no longer considered a lease under IFRS 16.

C. Comparative Figures

Certain comparative figures have been reclassified to conform to the current period’s presentation. These reclassifications did not impact previously reported net earnings.

4. Significant Events

A. Transition to Clean Power in Alberta

I. Alberta Renewable Energy Program Project - Windrise

In the fourth quarter of 2018, TransAlta's 207 MW Windrise wind project was selected by the Alberta Electric System Operator ("AESO") as one of the three successful projects in the third round of the Renewable Electricity Program. The Windrise facility, which is in the county of Willow Creek, is underpinned by a 20 -year Renewable Electricity Support Agreement with the AESO. The project is expected to cost approximately $270 million and is targeted to reach commercial operation during the second quarter of 2021.

II. Gas Supply for Coal-to-Gas Conversions

On Dec. 17, 2018, the Corporation exercised its option to acquire 50 percent ownership in the Pioneer gas pipeline ("Pioneer Pipeline"). Tidewater Midstream and Infrastructure Ltd. ("Tidewater") will construct and operate the 120 km natural gas pipeline, which will have an initial throughput of 130 MMcf/d with the potential to expand to approximately 440 MMcf/d. The Pioneer Pipeline will allow TransAlta to increase the amount of natural gas it co-fires at its Sundance and Keephills coal-fired units, resulting in lower carbon emissions and costs. As well, the Pioneer Pipeline will provide a significant amount of the gas required for the full conversion of the coal units to natural gas. The investment for TransAlta will amount to approximately $90 million . Construction of the pipeline commenced in November 2018 and the Pioneer Pipeline is expected to be fully operational by the second half of 2019. TransAlta’s investment is subject to final regulatory approvals, which are expected to be received in the first half of 2019.

TRANSALTA CORPORATION F 30

Notes to Consolidated Financial Statements

III. Sundance and Keephills Units 1 and 2 Coal-to-Gas Conversion Strategy

On Dec. 6, 2017, the Corporation updated its strategy to accelerate its transition to gas and renewables generation. During 2018, the Corporation mothballed and retired the following Sundance Units:


▪	retired Sundance Unit 1 on Jan. 1, 2018;


▪	retired Sundance Unit 2 on July 31, 2018;


▪	temporarily mothballed Sundance Unit 3 on April 1, 2018, for a period of up to two years; and


▪	temporarily mothballed Sundance Unit 5 on April 1, 2018, for a period of up to one year, which has now been extended to two years.

TransAlta is no longer planning to temporarily mothball Sundance Unit 4 and will perform maintenance during the first half of 2019.

On December 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity . The regulations provide rules for new gas-fired electricity facilities, as well as specific provisions for coal-to-gas conversions. In addition to extending their operating lives, the benefits of converting units to gas generation include: significantly lowering carbon emissions and costs; significantly lowering operating and sustaining capital costs; and increasing operating flexibility. TransAlta expects to convert some or all of its Sundance Units 3 to 6 and Keephills Units 1 to 3 in the 2020 to 2023 period.

IV. Sundance Units 1 and 2

Canadian federal regulations stipulate that all coal plants built before 1975 must cease to operate on coal by the end of 2019, which includes Sundance Units 1 and 2. Given that Sundance Unit 1 was shut down two years early, the federal Minister of Environment & Climate Change agreed to extend the life of Sundance Unit 2 from 2019 to 2021. This provided the Corporation with the flexibility to respond to the regulatory environment for coal-to-gas conversions and the new upcoming Alberta capacity market. However, in July 2018, TransAlta retired Sundance Unit 2. This decision was driven largely by Sundance Unit 2's age, size and short useful life relative to other units, and the capital requirements needed to return the unit to service.

Sundance Units 1 and 2 collectively made up 560 MW of the 2,141 MW capacity of the Sundance power plant, which serves as a baseload provider for the Alberta electricity system. The PPA with the Balancing Pool relating to Sundance Units 1 and 2 expired on Dec. 31, 2017.

In the third quarter of 2018, the Corporation recognized an impairment charge of $38 million ( $28 million after-tax) relating to the retirement of Sundance Unit 2. During the second quarter of 2017, the Corporation recognized an impairment charge on Sundance Unit 1 of $20 million ( $15 million after-tax) due to the Corporation’s decision to early retire Sundance Unit 1. See Note 7 for further details.

B. Kent Hills 3 Wind Project

During 2017, a subsidiary of TransAlta Renewables, Kent Hills Wind LP ("KHWLP"), entered into a long-term contract with New Brunswick Power Corporation (“NB Power”) for the sale of all power generated by an additional 17.25 MW of capacity from the Kent Hills 3 expansion wind project. At the same time, the term of the Kent Hills 1 contract with NB Power was extended from 2033 to 2035, matching the life of the Kent Hills 2 and Kent Hills 3 wind projects.

On Oct. 19, 2018, TransAlta Renewables announced that the expansion is fully operational, bringing total generating capacity of the Kent Hills wind farm to 167 MW.

TRANSALTA CORPORATION F 31

Notes to Consolidated Financial Statements

C. Acquisition of Two US Wind Projects

On Feb. 20, 2018, TransAlta Renewables announced it had entered into an arrangement to acquire two construction-ready projects in the Northeastern United States. The wind development projects consist of: i) a 90 MW project located in Pennsylvania that has a 15 -year PPA with Microsoft Corp. ("Big Level"), and ii) a 29 MW project located in New Hampshire with two 20 -year PPAs ("Antrim") (collectively, the "US Wind Projects"), with counterparties that have Standard & Poor's credit ratings of A+ or better. The commercial operation date for both projects is expected during the second half of 2019. A subsidiary of TransAlta acquired Big Level on Feb. 20, 2018,and the acquisition of Antrim remains subject to certain closing conditions, including the receipt of a favourable regulatory ruling. The Corporation expects the Antrim acquisition to close in early 2019.

On April 20, 2018, TransAlta Renewables completed the acquisition of an economic interest in the US Wind Projects from a subsidiary of TransAlta (“TA Power”). Pursuant to the arrangement, a TransAlta subsidiary owns the US Wind Projects directly and TA Power issued to TransAlta Renewables tracking preferred shares that pay quarterly dividends based on the pre-tax net earnings of the US Wind Projects. The tracking preferred shares have preference over the common shares of TA Power held by TransAlta, in respect of dividends and the distribution of assets in the event of the liquidation, dissolution or winding-up of TA Power. The construction and acquisition costs of the two US Wind Projects are expected to be funded by TransAlta Renewables and a $25 million promissory note receivable and are estimated to be US $240 million . TransAlta Renewables will fund these costs either by acquiring additional preferred shares issued by TA Power or by subscribing for interest-bearing notes issued by the project entity. The proceeds from the issuance of such preferred shares or notes will be used exclusively in connection with the acquisition and construction of the US Wind Projects. TransAlta Renewables expects to fund these acquisition and construction costs using its existing liquidity and tax equity.

During the year ended Dec. 31, 2018 , TransAlta Renewables funded approximately $61 million (US $48 million ) of construction costs. On Jan. 2, 2019, TransAlta Renewables funded an additional $45 million (US $33 million ) of construction costs.

D. TransAlta Renewables Acquires Three Renewable Assets from the Corporation

On May 31, 2018, TransAlta Renewables acquired from a subsidiary of the Corporation an economic interest in the 50 MW Lakeswind wind farm in Minnesota and 21 MW of solar projects located in Massachusetts ("Mass Solar") through the subscription of tracking preferred shares of a subsidiary of the Corporation. In addition, TransAlta Renewables acquired from a subsidiary of the Corporation ownership of the 20 MW Kent Breeze wind farm located in Ontario. The total purchase price for the three assets was approximately $166 million , including the assumption of $62 million of tax equity obligations and project debt, for net cash consideration of $104 million . The Corporation continues to operate these assets on behalf of TransAlta Renewables.

The acquisition of Kent Breeze was accounted for by TransAlta Renewables as a business combination under common control, requiring the application of the pooling of interests method of accounting, whereby the assets and liabilities acquired were recognized at the book values previously recognized by TransAlta at May 31, 2018, and not at their fair values. As a result, the Corporation recognized a transfer of equity from the non-controlling interests in the amount of $1 million in 2018.

On June 28, 2018, TransAlta Renewables subscribed for an additional $33 million of tracking preferred shares of a subsidiary of the Corporation related to Mass Solar, to fund the repayment of Mass Solar's project debt.

In connection with these acquisitions, the Corporation recorded a $12 million impairment charge, of which $11 million was recorded against PP&E and $1 million against intangibles. See Note 7 for further details.

E. TransAlta Renewables Closes $150 Million Offering of Common Shares

On June 22, 2018, TransAlta Renewables closed a bought deal offering of 11,860,000 common shares through a syndicate of underwriters (the "Offering"). The common shares were issued at a price of $12.65 per common share for gross proceeds of approximately $150 million ( $144 million of net proceeds).

The Corporation did not purchase any additional common shares under the Offering and, following the closing, owned 161 million common shares, representing approximately 61 per cent of the outstanding common shares of TransAlta Renewables. See Note 12 for further details of TransAlta's ownership of TransAlta Renewables.

TRANSALTA CORPORATION F 32

Notes to Consolidated Financial Statements

F. $345 Million Financing

On July 20, 2018, the Corporation monetized the payments under the OCA with the Government of Alberta by closing a $345 million bond offering through its indirect wholly owned subsidiary, TransAlta OCP LP ("TransAlta OCP"). The offering was a private placement that was secured by, among other things, a first ranking charge over the OCA payments payable by the Government of Alberta. The amortizing bonds bear interest at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030. The bonds have a rating of BBB, with a Stable trend, by DBRS. Under the terms of the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million , net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030.

The net proceeds were used to partially repay the 6.40 per cent debentures, as described below.

G. Early Redemption of $400 Million of Debentures

H. Normal Course Issuer Bid

On March 9, 2018 the Corporation announced that the Toronto Stock Exchange ("TSX") accepted the notice filed by the Corporation to implement a normal course issuer bid ("NCIB") for a portion of its common shares. Pursuant to the NCIB, the Corporation may repurchase up to a maximum of 14,000,000 common shares, representing approximately 4.86 per cent of issued and outstanding common shares as at March 2, 2018. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Common shares purchased under the NCIB are cancelled.

During the year ended Dec. 31, 2018 , the Corporation purchased and cancelled 3,264,500 common shares at an average price of $ 7.02 per common share, for a total cost of $ 23 million . See Note 24 for further details. Further transactions, if any, under the NCIB will depend on market conditions. The Corporation retains discretion whether to make purchases under the NCIB, and to determine the timing, amount and acceptable price of any such purchases, subject at all times to applicable TSX and other regulatory requirements.

I. Early Redemption of Senior Notes

On March 15, 2018, the Corporation early redeemed all of its outstanding 6.650 per cent US $500 million senior notes due May 15, 2018, for approximately $617 million (US $516 million ). A $5 million early redemption premium was recognized in net interest expense. See Note 22 for further details.

J. Balancing Pool Provides Notice to Terminate the Alberta Sundance Power Purchase Arrangements

On Sept 18. 2017, the Corporation received formal notice from the Balancing Pool for the termination of the Sundance B and C PPAs effective March 31, 2018.

This announcement was expected and the Corporation took steps to re-take dispatch control for the units effective March 31, 2018. Pursuant to a written agreement, the Balancing Pool paid the Corporation approximately $157 million on March 29, 2018. The Corporation is disputing the termination payment it received. The Balancing Pool excluded certain mining assets that the Corporation believes should be included in the net book value calculation for an additional termination payment of $56 million . The dispute is currently proceeding through the PPA arbitration process.

TRANSALTA CORPORATION F 33

Notes to Consolidated Financial Statements

K. Notice of Termination of South Hedland Power Purchase Agreement from Fortescue Metals Group Limited

On Nov. 13, 2017, the Corporation announced that TEC Hedland Pty Ltd ("TEC Hedland"), a subsidiary of the Corporation, received formal notice of termination of the South Hedland Power Purchase Agreement ("South Hedland PPA") from a subsidiary of Fortescue Metals Group Limited ("FMG"). The South Hedland PPA allows FMG to terminate the agreement if the power station has not reached commercial operation within a specified time period. FMG continues to be of the view that South Hedland Power Station has yet to achieve commercial operation.

The Corporation believes that all conditions required to establish commercial operations, including all performance conditions, have been achieved under the terms of the South Hedland PPA. These conditions include receiving a commercial operation certificate, successfully completing and passing certain test requirements, and obtaining all permits and approvals required from the North West Interconnected System and government agencies. Confirmation of commercial operation has been provided by independent engineering firms, as well as by Horizon Power, the state-owned utility. The Corporation is taking all steps necessary to protect its interests in the facility and ensure all cash flows promised under the South Hedland PPA are realized. The South Hedland Power Station has been fully operational and able to meet FMG’s requirements under the terms of the South Hedland PPA since July 2017.

TEC Hedland commenced proceedings in the Supreme Court of Western Australia on Dec. 4, 2017, to recover amounts invoiced under the South Hedland PPA.

L. Re-acquisition of Solomon Power Station

On Aug. 1, 2017, the Corporation received notice of FMG’s intention to repurchase the Solomon Power Station from TEC Pipe Pty Ltd. ("TEC Pipe"), a wholly owned subsidiary of the Corporation, for approximately US $335 million . FMG completed its acquisition of the Solomon Power Station on Nov. 1, 2017, and TEC Pipe received US $325 million as consideration. FMG has held back the balance from the purchase price. It is the Corporation’s view that this should not have been held back and the Corporation is taking action in the Supreme Court of Western Australia to recover all, or a significant portion of, this amount from FMG.

M. TransAlta Renewables' $260-Million Project Financing of New Brunswick Wind Assets and Early Redemption of Outstanding Debentures

On Oct. 2, 2017, TransAlta Renewables announced that its indirect majority-owned subsidiary, KHWLP, closed an approximate $260 million bond offering, secured by, among other things, a first ranking charge over all assets of KHWLP. The bonds are amortizing and bear interest at a rate of 4.454 per cent, payable quarterly, and mature on Nov. 30, 2033. A portion of the net proceeds was used to fund a portion of the construction costs for the 17.25 MW Kent Hills 3 wind project. The remaining proceeds were advanced to its subsidiary Canadian Hydro Developers, Inc. ("CHD") and to Natural Forces Technologies Inc., KHWLP’s partner, which owns approximately 17 per cent of KHWLP. Proceeds of $31 million are classified as restricted cash as at Dec. 31, 2018 , relating to the construction reserve account, and will be released upon certain conditions being met, which are expected to be finalized in Q1 2019.

At the same time, CHD, a wholly owned subsidiary of TransAlta Renewables, provided notice that it would be early redeeming all of its unsecured debentures. The debentures were scheduled to mature in June 2018. On Oct. 12, 2017, CHD redeemed the unsecured debentures for $201 million , which included the principal of $191 million , an early redemption premium of $6 million and accrued interest of $4 million . The $6 million early redemption premium was recognized in net interest expense for the year ended Dec. 31, 2017.

N. Series E and C Preferred Share Conversion Results and Dividend Rate Reset

On Sept. 17, 2017, the Corporation announced that the minimum election notices received did not meet the requirements to give effect to the conversion of its Series E Preferred Shares into Series F Preferred Shares. As a result, none of the Series E Preferred Shares were converted into Series F Preferred Shares on Sept. 30, 2017, and the dividend rate remains fixed for the subsequent five-year period. See Note 25 for further details.

On June 16, 2017, the Corporation announced that the minimum election notices received did not meet the requirements to give effect to the conversion of its Series C Preferred Shares into the Series D Preferred Shares. As a result, none of the Series C Preferred Shares were converted into Series D Preferred Shares on June 30, 2017, and the dividend remains fixed for the subsequent five-year period. See Note 25 for further details.

TRANSALTA CORPORATION F 34

Notes to Consolidated Financial Statements

O. Alberta Off-Coal Agreement

On Nov. 24, 2016, the Corporation announced that it had entered into an agreement with the Government of Alberta (the “Government”) on transition payments for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030.

Under the terms of the OCA, the Corporation will receive annual cash payments of approximately $37 million , net to the Corporation, commencing in 2017 and terminating in 2030. Receipt of the payments is subject to certain terms and conditions. The OCA’s main condition is the cessation of all coal-fired emissions on or before Dec. 31, 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, the employees of the Corporation negatively impacted by the phase-out of coal generation and fulfilling 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.

The Corporation also entered into a Memorandum of Understanding with the Government to collaborate and co-operate in the development of a policy framework to facilitate coal-to-gas fired conversions and renewable electricity development, and ensure existing generation is able to effectively participate in a future capacity market to be developed for the Province of Alberta.

P. Force Majeure Relief - Keephills 1

Keephills 1 tripped off-line on March 5, 2013, due to a suspected winding failure within the generator. After extensive testing and analysis, it was determined that a full rewind of the generator stator was required. After completing the repairs, the unit returned to service on Oct. 6, 2013. The Corporation claimed force majeure relief on March 26, 2013. The buyer, ENMAX, disputed the claim of force majeure, which triggered the need for an arbitration hearing that took place in May 2016. On Nov. 18, 2016, the Corporation announced that the independent arbitration panel confirmed the Corporation’s claim for force majeure relief. Accordingly, the Corporation reversed a provision of approximately $94 million in 2016. The buyer and the Balancing Pool are seeking to set the arbitration panel’s decision aside in the Court of Queen’s Bench of Alberta. This application is scheduled to be heard from Feb. 27, 2019 to Mar. 1, 2019.

Q. Poplar Creek Financing

On Dec. 7, 2016, the Corporation announced that its indirect wholly owned subsidiary, TAPC Holdings LP, which holds the Corporation’s interest in the Poplar Creek cogeneration facility, completed the private placement of a $202.5 million aggregate principal amount of senior secured floating rate bonds. The bonds, which mature on Dec. 31, 2030, are secured by a first ranking charge over the equity interests of the issuer of such bonds. 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.

R. Mississauga Cogeneration Facility NUG Contract

On Dec. 22, 2016, the Corporation announced it had signed the Non-Utility Generator Contract (the "NUG Contract") with the Ontario Independent Electricity System Operator (the “IESO”) for its Mississauga cogeneration facility. The NUG Contract was effective on Jan. 1, 2017, and, in conjunction with the execution of the NUG Contract, the Corporation agreed to terminate, effective Dec. 31, 2016, the facility’s existing contract with the Ontario Electricity Financial Corporation, which would have otherwise terminated in December 2018. In December 2018, TransAlta exercised its option to terminate its agreement with Boeing Canada Inc. effective Dec. 31, 2021. TransAlta is required to remove the plant and restore the site within the three-year time frame.

The NUG Contract provided the Corporation with fixed monthly payments until Dec. 31, 2018, with no delivery obligations. Further details on the NUG Contract and its impact to these financial statements can be found in Note 9 (C).

S. Wintering Hills Assets Held for Sale

The Corporation acquired its interest in Wintering Hills in 2015 in connection with the restructuring of the arrangements associated with its Poplar Creek cogeneration facility. At Dec. 31, 2016, the criteria for Wintering Hills to be classified as held for sale were met. The assets held for sale are measured at the lower of carrying amount and fair value less costs to sell. Accordingly, the Corporation recorded an impairment charge of $28 million in 2016, included in the Wind and Solar segment. Wintering Hills was sold on March 1, 2017, for net proceeds to the Corporation of $61 million .

TRANSALTA CORPORATION F 35

Notes to Consolidated Financial Statements

T. Project Financing of a Quebec Wind Asset by TransAlta Renewables

On June 3, 2016, TransAlta Renewables' indirect wholly owned subsidiary, New Richmond Wind L.P. (the “NRWLP”), closed a bond offering of approximately $159 million , which is secured by a first ranking charge over all assets of the NRWLP. The bonds are amortizing and bear interest at a rate of 3.963 per cent, payable semi-annually, and mature on June 30, 2032.

U. Investment in, and Acquisition by, TransAlta Renewables of the Sarnia Cogeneration Plant, Le Nordais Wind Farm and Ragged Chute Hydro Facility (the “Canadian Assets”)

On Jan. 6, 2016, TransAlta Renewables completed its investment in an economic interest based on the cash flows of the Corporation’s Canadian Assets for a combined aggregate value of approximately $540 million . The Canadian Assets consist of approximately 611 MW of highly contracted power generation assets located in Ontario and Québec.

As consideration, TransAlta Renewables provided to the Corporation $173 million in cash, issued 15,640,583 common shares with an aggregate value of $152 million and issued a $215 million convertible unsecured subordinated debenture. On Nov. 9, 2017, TransAlta Renewables repaid the debentures early, for $218 million in total, comprised of principal of $215 million and accrued interest of $3 million . The convertible debenture was scheduled to mature on Dec. 31, 2020.

TransAlta Renewables funded the cash proceeds through the public issuance of 17,692,750 subscription receipts at a price of $9.75 per subscription receipt. Upon the closing of the transaction, each holder of subscription receipts received, for no additional consideration, one common share of TransAlta Renewables and a cash dividend equivalent payment of $0.07 for each subscription receipt held. As a result, TransAlta Renewables issued 17,692,750 common shares and paid a total dividend equivalent of $1 million . Share issuance costs amounted to $8 million , net of $2 million income tax recovery.

On Nov. 30, 2016, TransAlta Renewables acquired direct ownership of the Canadian Assets from the Corporation for a purchase price of $520 million by issuing a promissory note. At the same time, the Corporation’s subsidiary redeemed the preferred shares that it had issued to TransAlta Renewables in January 2016 when TransAlta Renewables acquired an economic interest in the Canadian Assets as described above for $520 million . The two transactions were subject to a set-off arrangement and resulted in no cash payments. TransAlta Renewables also acquired working capital and certain capital spares totalling $19 million through the issuance of a non-interest bearing loan payable to the Corporation.

The acquisition of the Canadian Assets was accounted for by TransAlta Renewables as a business combination under common control, requiring the application of the pooling of interests method of accounting, whereby the Canadian Assets’ assets and liabilities acquired were recognized at the book values previously recognized by TransAlta at Nov. 30, 2016, and not at their fair values. As a result, the Corporation recognized a transfer of equity from the non-controlling interests in the amount of $38 million in 2016.

TRANSALTA CORPORATION F 36

Notes to Consolidated Financial Statements

5 . Revenue

A. Disaggregation of Revenue

The majority of the Corporation's revenues are derived from the sale of physical power, capacity and green attributes, leasing of power facilities, and from energy marketing and trading activities, which the Corporation disaggregates into the following groups for the purpose of determining how economic factors affect the recognition of revenue.



Year ended Dec. 31, 2018	Canadian Coal		US Coal	Canadian Gas	Australian Gas	Wind and Solar		Hydro	Energy Marketing	Corporate		Total
Revenues from contracts with customers	517		9	224	91	206		132	—	—		1,179
Revenue from leases ⁽¹⁾	68		—	—	68	27		7	—	—		170
Revenue from derivatives	(1	)	115	4	—	(20	)	—	67	—		165
Government incentives	—		—	—	—	16		—	—	—		16
Revenue from other ⁽²⁾	328		318	4	6	53		17	—	(7	)	719
Total revenue	912		442	232	165	282		156	67	(7	)	2,249

Revenues from contracts with customers
Timing of revenue recognition
At a point in time	38		9	—	—	18		—	—	—		65
Over time	479		—	224	91	188		132	—	—		1,114
Total revenue from contracts with customers	517		9	224	91	206		132	—	—		1,179

(1) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. 2017 - $247 million , 2016 - $221 million .

(2) Includes merchant revenue and other miscellaneous.

B. Contract Balances

The Corporation has recognized the following revenue-related contract assets and liabilities:



Contract liabilities
Dec. 31, 2017	62
IFRS 15 transition adjustment	17
Amounts transferred to revenue included in opening balance	(10	)
Consideration received	13
Increases due to interest accrued and expensed during the period	6
Amounts transferred to payables	(1	)
Dec. 31, 2018	87

Contract liabilities are primarily comprised of consideration received from the Corporation’s Keephills Unit 3 joint operation partner for which the Corporation has a future obligation to transfer goods and services to the partner under the contract. Consideration received is dependent upon the Corporation’s mine capital replacement plan and revenue is recognized as the Corporation satisfies its performance obligations under the contract of being available to deliver coal and the delivery of coal.

C. Remaining Performance Obligations

As required by the new revenue standard, the Corporation is required to disclose the aggregate amount of the transaction price allocated to remaining performance obligation (contract revenues that have not yet been recognized) for contracts in place at the end of the reporting period. The following disclosures exclude revenues related to contracts that qualify for the following practical expedients:


▪	The Corporation recognizes revenue from the contract in an amount that is equal to the amount invoiced where the amount invoiced represents the value to the customer of the service performed to date. Certain of the Corporation’s contracts at some of its wind, hydro, gas and solar facilities, and within its commercial and industrial business, qualify

TRANSALTA CORPORATION F 37

Notes to Consolidated Financial Statements

for this practical expedient. For these contracts, the Corporation is not required to disclose information about the remaining unsatisfied performance obligations.


▪	Contracts with an original expected duration of less than 12 months.

Additionally, in many of the Corporation’s contracts, elements of the transaction price are considered constrained, such as for variable revenues dependent upon future production volumes that are driven by customer or market demand or market prices that are subject to factors outside the Corporation’s influence. Future revenues that are related to constrained variable consideration are not included in the disclosure of remaining performance obligations until the constraints are resolved. Further, adjustments to revenue to recognize a significant financing component in a contract are not included in the amounts disclosed for remaining performance obligations.

As a result, the amounts of future revenues disclosed below represent only a portion of future revenues that are expected to be realized by the Corporation from its contractual portfolio.

Canadian Coal

At Dec. 31, 2018 , the Corporation has PPAs with the Balancing Pool for capacity and electricity from two of its coal plants, as dispatched, with contract end dates of Dec. 31, 2020. All generation produced is delivered to the customer. Certain sources of revenue under one PPA contract are accounted for as a lease, and are excluded from these disclosures. Pricing is comprised of multiple components, of both fixed and variable nature, consisting of a capacity payment based on a return of capital , availability payments (from or to the customer) based on the 30-day rolling average pool price and actual availability of the plant as compared to targeted availability specified in the PPAs, recovery of regulatory pass-through costs, and payments for delivery of energy based on the variable cost of producing the energy. Energy-related payments are variable depending on output from the plant, which is dependent upon market demand and the operational ability of the plant. Revenues are generally recognized over time, on a monthly basis. Future revenues that are based upon variable consideration are considered to be fully constrained and are excluded from these disclosures.

The Corporation also has several contracts for sale of byproducts of coal combustion from certain of its coal plants. The contracts range in duration from one to three years. Generally, revenues vary based on market prices that are subject to factors outside of the Corporation’s control, and the quantities delivered and sold, which are ultimately dependent upon customer demand. These variable revenues are considered to be fully constrained, and will be recognized at a point in time as the performance obligation, the delivery of byproducts, is satisfied. Accordingly, these revenues are excluded from these disclosures.

The Corporation has a contract at its Alberta coal mine that requires it to be available to deliver coal as required, and to provide byproduct disposal services for the plant. The duration of the contract is largely dependent upon the Corporation’s coal-to-gas transition plans and decisions. Pricing terms are based on actual costs incurred to provide the coal, and will vary over the life of the contract. Revenue will be recognized on the basis of the costs incurred and based on volumes of coal delivered, which are variable and depend upon market demand for electricity, which is subject to factors outside of the Corporation’s control. Accordingly, revenues related to remaining performance obligations associated with this component of the contract are excluded from these disclosures as they are variable and considered to be fully constrained. The customer also funds a portion of the required mine capital as part of the transaction price, which the Corporation has determined constitutes a significant financing component. Revenues are dependent upon the Corporation’s mine capital replacement plan and the recoveries, along with the significant financing component, and are amortized into revenue as the Corporation satisfies its performance obligations of being available to deliver coal and the delivery of coal. The significant financing component of these revenues is excluded from these disclosures.

Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are approximately $330 million , of which the Corporation expects to recognize approximately $245 million in total over the next two fiscal years and on average, between approximately $7 million to $10 million annually thereafter for the duration of the contracts.

US Coal

The Corporation’s long-term contract for the sale of electricity produced at its US Coal plant is considered a derivative and is designated as an all-in-one hedge. Accordingly, while revenues for electricity delivered to the customer are recognized pursuant to the contractual terms, the revenues are not accounted for under IFRS 15 and the contract has been excluded from any required IFRS 15 disclosures.

The Corporation also has a contract for the sale of byproducts of coal combustion from its US Coal plant. Generally, revenues vary based on market prices that are subject to factors outside of the Corporation’s control, and the quantities delivered and sold, which are ultimately dependent upon customer demand. These variable revenues are considered to be fully

TRANSALTA CORPORATION F 38

Notes to Consolidated Financial Statements

constrained, and will be recognized at a point in time as the performance obligation, the delivery of byproducts, is satisfied. Accordingly, these revenues are excluded from these disclosures.

Canadian Gas

At Dec. 31, 2018 , the Corporation has contracts with customers to deliver energy services from one of its gas plants in Ontario. The contracts all consist of a single performance obligation requiring the Corporation to stand ready to deliver electricity and steam. The following is a summary of the key terms:

The energy supply agreements require specified amounts of steam to be delivered to each customer, and have pricing terms that include fixed and variable charges for electricity, capacity and steam, as well as a true-up based on contractual minimum volumes of steam. The steam reconciliation is based on an estimate of the customer’s steam volume taken and the contractual minimum volume, and various factors including the annual average market price of electricity and the average locally posted and index prices of natural gas, as well as transportation. For steam volumes not taken by the customer, a revenue-sharing mechanism provides for sharing of revenues earned by the Corporation using that steam to generate and sell electricity. Capacity and electricity pricing vary from contract to contract and are subject to annual indexation at varying rates. Electricity and steam delivered is ultimately dependent upon customer requirements, which is outside of the Corporation’s control, These variable revenues under the contracts are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Corporation expects to recognize revenue as it delivers electricity and steam until the completion of the contract in late 2022.

At the same gas plant, the Corporation has a contract with the local power authority with fixed capacity charges that are adjusted for seasonal fluctuations, steam demand from the plant’s other customers, and for deemed net revenue related to production of electricity into the market. As a result, revenues recognized in the future will vary as they are dependent upon factors outside of the Corporation’s control and are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Corporation expects to recognize such revenue as it stands ready to deliver electricity until the completion of the contract term on Dec. 31, 2025.

At Dec. 31, 2018, the Corporation has contracts with customers to deliver steam, hot water and chilled water from one of its other gas plants in Ontario, extending through 2023. Prices under these contracts are at fixed base amounts per gigajoule and are subject to escalation annually for both gas prices and inflation. The contracts include minimum annual take-or-pay volumes.

Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are approximately $25 million in total, of which the Corporation expects to be on average, between approximately $4 million to $6 million annually thereafter for the duration of the contracts.

The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount invoiced is applied to some of the Corporation’s other gas facilities’ contracts in Ontario; accordingly, disclosures related to remaining performance obligations are not provided for these contracts.

Australian Gas

At Dec. 31, 2018 , the Corporation has PPAs with customers to deliver electricity from its gas plants located in Australia. One contract is considered to be a lease and is excluded from these disclosures. The PPAs generally call for all available generation to be provided to customers. Pricing terms include fixed and variable price components for delivered electricity and fixed capacity payments. Prices may be subject to true-up adjustments for deviations from expected heat rates and are subject to various escalators to reflect inflation. Electricity delivered is ultimately dependent upon customer requirements, which is outside of the Corporation’s control. These variable revenues for electricity delivered are considered to be fully constrained, and will be recognized at a point in time as the performance obligation, the delivery of electricity, is satisfied. Accordingly, these revenues are excluded from these disclosures. The contracts have durations that range from 2021 to 2042.

Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are approximately $2,280 million , of which the Corporation expects to recognize approximately $230 million in total over the next three fiscal years and on average, between approximately $80 million to $110 million annually thereafter for the duration of the contracts.

Wind and Solar

At Dec. 31, 2018 , the Corporation had long-term contracts with customers to deliver electricity and the associated renewable energy credits from two wind farms located in Alberta and Minnesota, for which the invoice practical expedient is not applied. The PPAs generally require all available generation to be provided to customers at fixed prices, with certain

TRANSALTA CORPORATION F 39

Notes to Consolidated Financial Statements

pricing subject to annual escalations for inflation. The Corporation expects to recognize such amounts as revenue as it delivers electricity over the remaining terms of the contracts, until 2024 and 2034. Electricity delivered is ultimately dependent upon the wind resource, which is outside of the Corporation’s control. Amounts delivered, and therefore revenue recognized, in the future will vary. These variable revenues for electricity delivered are considered to be fully constrained, and will be recognized at a point in time as the performance obligation, the delivery of electricity, is satisfied. Accordingly, these revenues are excluded from these disclosures. The Corporation also has contracts to sell renewable energy certificates generated at merchant wind facilities and expects to recognize revenues as it delivers the renewable energy certificates to the purchaser over the remaining terms of the contracts, from 2019 through 2024.

Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are approximately $9 million , of which the Corporation expects to recognize between approximately $1 million to $2 million annually through to contract expiry.

The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount invoiced is applied to wind energy contracts in Ontario, New Brunswick, Quebec and Wyoming, and for all solar contracts; accordingly, disclosures related to remaining performance obligations are not provided for these contracts.

Hydro

At Dec. 31, 2018 , the Corporation has a PPA with the Balancing Pool to provide the capacity of 12 hydro plants throughout the province of Alberta. The capacity payment is fixed on an annual basis. As part of the PPA, the Corporation also has a financial obligation to the Balancing Pool determined on the basis of notional quantities of electricity delivered and the pool price for the period. The Corporation expects to recognize revenue as it makes capacity available to the customer until completion of the contract term at Dec. 31, 2020. The Corporation also has contracts for blackstart services at specific hydro plants and a contract with the Government of Alberta to manage water on the Bow River for flood and drought mitigation purposes, which all conclude within 2020.

Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are approximately $130 million , which the Corporation expects to recognize over the next two fiscal years.

The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount invoiced is applied to all hydro energy contracts in Ontario, British Columbia and Washington; accordingly, disclosures related to remaining performance obligations are not provided for these contracts.

6 . Expenses by Nature

Expenses classified by nature are as follows:



Year ended Dec. 31	2018		2017		2016
	Fuel and purchased power	Operations, maintenance and administration	Fuel and purchased power	Operations, maintenance and administration	Fuel and purchased power		Operations, maintenance and administration
Fuel ⁽¹⁾	656	—	685	—	665		—
Coal inventory writedown (recovery)	—	—	—	—	(4	)	—
Purchased power	210	—	162	—	143		—
Mine depreciation	136	—	73	—	63		—
Salaries and benefits ⁽¹⁾	98	245	96	248	96		249
Other operating expenses	—	270	—	269	—		240
Total	1,100	515	1,016	517	963		489

(1) $90 million in both 2017 and 2016 was reclassified from fuel to salaries and benefits to be consistent with the 2018 classification.

7. Asset Impairment Charges and Reversals

As part of the Corporation’s monitoring controls, long-range forecasts are prepared for each CGU. The long-range forecast estimates are used to assess the significance of potential indicators of impairment and provide criteria to evaluate adverse changes in operations. The Corporation also considers the relationship between its market capitalization and its book value, among other factors, when reviewing for indicators of impairment. When indicators of impairment are present, the

TRANSALTA CORPORATION F 40

Notes to Consolidated Financial Statements

Corporation estimates a recoverable amount for each CGU by calculating an approximate fair value less costs of disposal using discounted cash flow projections based on the Corporation’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to the Corporation’s long-range forecast, including changes to fuel costs, operating costs, capital expenditures, external power prices and useful lives of the assets extending to the last planned asset retirement in 2073.

A. Alberta Merchant CGU

During 2018 , 2017 and 2016 , uncertainty continued to exist within the province of Alberta regarding the Government's Climate Leadership Plan, the future design parameters of the Alberta electricity market, and federal policies on the carbon levy and greenhouse gas ("GHG") emissions. Economic conditions also contributed to continued oversupply conditions and depressed market prices throughout 2015 to 2017. The Corporation assessed whether these factors, and events arising during the latter part of 2016, which are more fully discussed below, presented an indicator of impairment for its Alberta Merchant CGU. In consideration of the composition of this CGU, the Corporation determined that no indicators of impairment were present with respect to the Alberta Merchant CGU. Due to this determination, the Corporation did not perform an in-depth impairment analysis for any of these years, but for all years, a sensitivity analysis associated with these factors was performed to confirm the continued existence of adequate excess of estimated recoverable amount over book value. This analysis of the Alberta Merchant CGU continued to demonstrate a substantial cushion at the Alberta Merchant CGU in each of 2018 , 2017 and 2016 , due to the Corporation’s large merchant renewable fleet in the province.

I. 2018

Sundance Unit 2

Lakeswind and Kent Breeze

On May 31, 2018, TransAlta Renewables acquired an economic interest in Lakeswind through the subscription of tracking preferred shares of a subsidiary of the Corporation and also purchased Kent Breeze (see Note 4(D)). In connection with these acquisitions, the assets were fair valued using discount rates that average approximately 7 per cent. Accordingly, the Corporation has recorded an impairment charge of $12 million using the valuation in the agreement as the indicator of fair value less cost of disposal in 2018. The impairment charge had an $11 million impact on PP&E and a $1 million impact on intangible assets (See Note 17 and 19 ).

II. 2017

Sundance Unit 1

III. 2016

Wintering Hills

On Jan. 26, 2017, the Corporation announced the sale of its 51 per cent interest in the Wintering Hills merchant wind facility for approximately $61 million (see Note 4(S)). In connection with this sale, the Wintering Hills assets were accounted for as held for sale at Dec. 31, 2016. As required, the Corporation assessed the assets for impairment prior to classifying them as held for sale. Accordingly, the Corporation has recorded an impairment charge of $28 million using the purchase price in the sale agreement as the indicator of fair value less cost of disposal in 2016.

B. Project Development Costs

During 2018, the Corporation wrote off $23 million in project development costs related to projects that are no longer proceeding.

TRANSALTA CORPORATION F 41

Notes to Consolidated Financial Statements

8. Finance Lease Receivables

Amounts receivable under the Corporation’s finance leases associated with the Fort Saskatchewan cogeneration facility and the Poplar Creek cogeneration facility are as follows:



As at Dec. 31	2018		2017
	Minimum lease payments	Present value of minimum lease payments	Minimum lease payments	Present value of minimum lease payments
Within one year	30	29	68	66
Second to fifth years inclusive	80	74	110	82
More than five years	140	112	140	126
	250	215	318	274
Less: unearned finance lease income	35	—	44	—
Total finance lease receivables	215	215	274	274

Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease receivables (Note 13)	24		59
Long-term portion of finance lease receivables	191		215
	215		274

9 . Net Other Operating Expense (Income)

Net other operating expense (income) includes the following:



Year ended Dec. 31	2018		2017		2016
Alberta Off-Coal Agreement	(40	)	(40	)	—
Termination of the Sundance B and C PPAs	(157	)	—		—
Mississauga cogeneration facility NUG Contract	—		(9	)	(191	)
Insurance recoveries	(7	)	—		(3	)
Restructuring provision	—		—		1
Net other operating expense (income)	(204	)	(49	)	(193	)

A. Alberta Off-Coal Agreement

The Corporation receives payments from the Government of Alberta for the cessation of coal-fired emissions from its interest in the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030.

Under the terms of the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million ( $37 million , net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030. The Corporation recognizes the off-coal payments evenly throughout the year. Receipt of the payments is subject to certain terms and conditions. The OCA’s main condition is the cessation of all coal-fired emissions on or before Dec. 31, 2030. The affected plants are not, however, precluded from generating electricity at any time by any method, other than generation resulting in coal-fired emissions after Dec. 31, 2020. In July 2018, the Corporation obtained financing against the OCA payments (See Note 4(O) and 22 ).

B. Termination of the Sundance B and C PPAs

On Sept. 18, 2017, the Corporation received formal notice from the Balancing Pool of the termination of the Sundance B and C PPAs effective March 31, 2018, and received a termination payment of $157 million during the first quarter of 2018. See Note 4(J) for further details.

TRANSALTA CORPORATION F 42

Notes to Consolidated Financial Statements

C. Mississauga Cogeneration Facility Contract

2016

On Dec. 22, 2016, the Corporation announced it had signed a NUG Contract with the IESO for its Mississauga cogeneration facility. The contract was effective on Jan. 1, 2017. The Corporation has agreed to terminate the prior contract with the IESO early, which would have otherwise terminated in December 2018.

As a result of the NUG Contract, the Corporation recognized a pre-tax gain of approximately $191 million . The predominant components of the gain relate to recognition of a one-time discounted revenue amount of approximately $207 million , offset by onerous contract expenses and other termination charges totalling approximately $16 million . The Corporation also recognized $46 million in accelerated depreciation resulting from the change in useful life of the asset. The Corporation released and recognized in earnings unrealized pre-tax net losses of $14 million from AOCI due to cash flow hedges de-designated for accounting purposes.

2017

During the fourth quarter of 2017, the Corporation renegotiated the facility's land lease agreement at a lower cost than previously estimated in 2016, and accordingly, recognized a gain of $9 million .

2018

In December 2018, TransAlta exercised its option to terminate its agreement with Boeing Canada Inc. effective Jan. 1, 2021. TransAlta is required to remove the plant and restore the site within the three-year time frame.

D. Insurance Recoveries

During 2018 , the Corporation received $7 million in insurance recoveries, of which $6 million related insurance proceeds for the tower fire at Wyoming Wind and a $1 million claim related to equipment repairs within Canadian Coal. There were no insurance recoveries in 2017 .

During 2016, the Corporation received $3 million in insurance recoveries, of which $2 million related to business interruption insurance claims and $1 million related to claims for replacement and refurbishment of equipment for certain wind facilities.

10 . Net Interest Expense

The components of net interest expense are as follows:



Year ended Dec. 31	2018		2017		2016
Interest on debt	184		218		218
Interest income	(11	)	(7	)	(2	)
Capitalized interest (Note 17)	(2	)	(9	)	(16	)
Loss on redemption of bonds (Note 22)	24		6		1
Interest on finance lease obligations	3		3		3
Credit facility fees, bank charges and other interest	13		18		19
Keephills 1 outage interest (reversals) (Note 4(P))	—		—		(10	)
Other ⁽¹⁾	15		(3	)	(4	)
Accretion of provisions (Note 21)	24		21		20
Net interest expense	250		247		229

(1) During 2018 , approximately $5 million of costs were expensed due to project-level financing that is no longer practicable and approximately $7 million for the significant financing component required under IFRS 15 (see Note 3).

TRANSALTA CORPORATION F 43

Notes to Consolidated Financial Statements

11 . Income Taxes

A. Consolidated Statements of Earnings

I. Rate Reconciliations



Year ended Dec. 31	2018		2017		2016
Earnings before income taxes	(96	)	(54	)	314
Net earnings attributable to non-controlling interests not subject to tax	(19	)	(35	)	(109	)
Adjusted earnings before income taxes	(115	)	(89	)	205
Statutory Canadian federal and provincial income tax rate (%)	26.8		26.8		26.7
Expected income tax expense (recovery)	(31	)	(24	)	55
Increase (decrease) in income taxes resulting from:
Lower effective foreign tax rates	(3	)	(11	)	(16	)
Deferred income tax expense related to temporary difference on investment in subsidiary	—		—		11
Writedown (reversal of writedown) of deferred income tax assets	27		(15	)	(10	)
Statutory and other rate differences	—		110		1
Other	1		4		(3	)
Income tax expense (recovery)	(6	)	64		38
Effective tax rate (%)	5		72		19

TRANSALTA CORPORATION F 44

Notes to Consolidated Financial Statements

II. Components of Income Tax Expense

The components of income tax expense are as follows:



Year ended Dec. 31	2018		2017		2016
Current income tax expense ⁽¹⁾	28		79		23
Adjustments in respect of deferred income tax of previous years	—		—		(3	)
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences	(61	)	(110	)	16
Deferred income tax expense related to temporary difference on investment in subsidiary ⁽²⁾	—		—		11
Deferred income tax expense resulting from changes in tax rates or laws ⁽³⁾	—		110		1
Deferred income tax expense (recovery) arising from the writedown (reversal of writedown) of deferred income tax assets ⁽⁴⁾	27		(15	)	(10	)
Income tax expense (recovery)	(6	)	64		38

Year ended Dec. 31	2018		2017		2016
Current income tax expense	28		79		23
Deferred income tax expense (recovery)	(34	)	(15	)	15
Income tax expense (recovery)	(6	)	64		38

(1) During 2017, the Corporation recognized current tax expense of $56 million due to the disposition of the Solomon Power Station on Nov. 1, 2017.

(2) In 2016, reorganizations of certain TransAlta subsidiaries were completed in connection with the New Richmond project financing and the disposition of the Canadian Assets to TransAlta Renewables. The reorganizations resulted in the recognition of deferred tax liabilities of $3 million and $8 million , respectively. The deferred tax liabilities had not been recognized previously, as prior to the reorganizations, the taxable temporary differences were not expected to reverse in the foreseeable future.

(3) On Dec. 22, 2017, the US government enacted H.R.1, originally known as the Tax Cuts and Jobs Act , which includes legislation to decrease its federal corporate income tax rate from 35 per cent to 21 per cent. The Corporation's net deferred tax liability associated with its directly owned US operations is made up of a deferred tax asset and a deferred tax liability that net to $6 million . The decrease in the US federal corporate income tax rate resulted in a decrease to the deferred tax asset of $104 million , all of which is recorded as deferred tax expense in the Consolidated Statement of Earnings, offset by a decrease to the deferred tax liability of $110 million , of which $1 million is recorded as deferred tax expense in the Consolidated Statement of Earnings with an offsetting $111 million deferred tax recovery recorded in the Consolidated Statement of Other Comprehensive Income. 2016 relates to the impact of increase in the New Brunswick corporate income tax rate from 12 per cent to 14 per cent, enacted Feb. 3, 2016.

(4) During the year ended Dec. 31, 2018 , the Corporation recorded a writedown of deferred income tax assets of $27 million ( 2017 - $15 million writedown reversal, 2016 - $10 million writedown reversal). The deferred income tax assets relate mainly to the tax benefits of losses associated with the Corporation’s directly owned US operations. The Corporation had written these assets off as it was no longer considered probable that sufficient future taxable income would be available from the Corporation’s directly owned US operations to utilize the underlying tax losses, due to reduced price growth expectations. Net operating losses expire between 2021 and 2037 for losses generated prior to 2018.

B. Consolidated Statements of Changes in Equity

The aggregate current and deferred income tax related to items charged or credited to equity are as follows:



Year ended Dec. 31	2018		2017		2016
Income tax expense (recovery) related to:
Net impact related to cash flow hedges	(12	)	(108	)	51
Net impact related to net investment hedges	—		(7	)	16
Net actuarial gains (losses)	5		(4	)	4
Income tax expense reported in equity	(7	)	(119	)	71

TRANSALTA CORPORATION F 45

Notes to Consolidated Financial Statements

C. Consolidated Statements of Financial Position

Significant components of the Corporation’s deferred income tax assets (liabilities) are as follows:



As at Dec. 31	2018		2017
Net operating loss carryforwards	547		541
Future decommissioning and restoration costs	113		117
Property, plant and equipment	(896	)	(1,009	)
Risk management assets and liabilities, net	(145	)	(160	)
Employee future benefits and compensation plans	68		74
Interest deductible in future periods	48		50
Foreign exchange differences on US-denominated debt	35		42
Deferred coal revenues	23		16
Other deductible temporary differences	—		22
Net deferred income tax liability, before writedown of deferred income tax assets	(207	)	(307	)
Writedown of deferred income tax assets	(266	)	(218	)
Net deferred income tax liability, after writedown of deferred income tax assets	(473	)	(525	)

The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows:



As at Dec. 31	2018		2017
Deferred income tax assets ⁽¹⁾	28		24
Deferred income tax liabilities	(501	)	(549	)
Net deferred income tax liability	(473	)	(525	)

(1) The deferred income tax assets presented on the Consolidated Statements of Financial Position are recoverable based on estimated future earnings and tax planning strategies. The assumptions used in the estimate of future earnings are based on the Corporation’s long-range forecasts.

D. Contingencies

As of Dec. 31, 2018 , the Corporation had recognized a net liability of nil ( 2017 - $4 million ) related to uncertain tax positions.

12 . Non-Controlling Interests

The Corporation’s subsidiaries and operations that have non-controlling interests are as follows:



Subsidiary/Operation	Non-controlling interest as at Dec. 31, 2018
TransAlta Cogeneration L.P.	49.99% - Canadian Power Holdings Inc.
TransAlta Renewables	39.1% - Public shareholders
Kent Hills Wind LP ⁽¹⁾	17% - Natural Forces Technologies Inc.

(1) Owned by TransAlta Renewables.

TransAlta Cogeneration, L.P. (“TA Cogen”) operates a portfolio of cogeneration facilities in Canada and owns 50 per cent of a coal facility. TransAlta Renewables owns and operates a portfolio of gas and renewable power generation facilities in Canada and owns economic interests in various other gas and renewable facilities of the Corporation.

TRANSALTA CORPORATION F 46

Notes to Consolidated Financial Statements

Summarized financial information relating to subsidiaries with significant non-controlling interests is as follows:

A. TransAlta Renewables

The net earnings, distributions and equity attributable to non-controlling interests include the 17 per cent non-controlling interest in the 167 MW Kent Hills wind farm located in New Brunswick.

The South Hedland Power Station achieved commercial operation on July 28, 2017. On Aug. 1, 2017, the Corporation converted its 26.1 million Class B shares held in TransAlta Renewables into 26.4 million common shares of TransAlta Renewables. At that time, the Corporation’s equity participation percentage in TransAlta Renewables increased to 64 per cent from 59.8 per cent. The Class B shares were converted at a ratio greater than 1:1 because the construction and commissioning costs for the project were below the referenced costs agreed to with TransAlta Renewables.

On May 31, 2018, TransAlta Renewables implemented a dividend reinvestment plan ("DRIP") for Canadian holders of common shares of TransAlta Renewables. Commencing with the dividend paid on July 31, 2018, eligible shareholders may elect to automatically reinvest monthly dividends into additional common shares of the Corporation.

As a result of the conversion of Class B shares, the DRIP and the transactions described in Note 4, the Corporation’s share of ownership and equity participation in TransAlta Renewables has fluctuated since its formation as follows:



Period	Ownership and voting rights percentage	Equity participation percentage
April 29, 2014 to May 6, 2015	70.3	70.3
May 7, 2015 to Nov. 25, 2015	76.1	72.8
Nov. 26, 2015 to Jan. 5, 2016	66.6	62.0
Jan. 6, 2016 to July 31, 2017	64.0	59.8
Aug. 1, 2017 to June 21, 2018	64.0	64.0
June 22, 2018 to July 30, 2018	61.1	61.1
July 31, 2018 to Nov. 29, 2018	61.0	61.0
Nov. 30, 2018 to Dec. 31, 2018	60.9	60.9



Year ended Dec. 31	2018	2017		2016
Revenues	462	459		259
Net earnings	241	13		1
Total comprehensive income	281	(24	)	40
Amounts attributable to the non-controlling interests:
Net earnings	94	11		2
Total comprehensive income	110	—		18
Distributions paid to non-controlling interests	79	85		83



As at Dec. 31	2018		2017
Current assets	250		145
Long-term assets	3,497		3,483
Current liabilities	(159	)	(356	)
Long-term liabilities	(1,192	)	(1,075	)
Total equity	(2,396	)	(2,197	)
Equity attributable to non-controlling interests	(961	)	(812	)
Non-controlling interests’ share (per cent)	39.1		36.0

TRANSALTA CORPORATION F 47

Notes to Consolidated Financial Statements

B. TA Cogen



Year ended Dec. 31	2018	2017	2016
Results of operations
Revenues	185	175	274
Net earnings	29	61	211
Total comprehensive income	29	61	258
Amounts attributable to the non-controlling interest:
Net earnings	14	31	105
Total comprehensive income	14	31	128
Distributions paid to Canadian Power Holdings Inc.	86	87	68



As at Dec. 31	2018		2017
Current assets	82		193
Long-term assets	354		404
Current liabilities	(54	)	(73	)
Long-term liabilities	(28	)	(26	)
Total equity	(354	)	(498	)
Equity attributable to Canadian Power Holdings Inc.	(176	)	(247	)
Non-controlling interest share (per cent)	49.99		49.99

13 . Trade and Other Receivables



As at Dec. 31	2018	2017
Trade accounts receivable	597	693
Mississauga recontracting receivable	—	108
Net trade receivables	597	801
Promissory note receivable ⁽¹⁾	25	—
Collateral paid (Note 15)	105	67
Current portion of finance lease receivables (Note 8)	24	59
Current portion of loan receivable (Note 20)	—	5
Income taxes receivables	5	1
Trade and other receivables	756	933

(1) The promissory note receivable relates to funding provided for the Antrim wind development project (see Note 4(C) for further details).

TRANSALTA CORPORATION F 48

Notes to Consolidated Financial Statements

14 . Financial Instruments

A. Financial Assets and Liabilities – Classification and Measurement

Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost (see Note 2(C)). The following table outlines the carrying amounts and classifications of the financial assets and liabilities:



Carrying value as at Dec. 31, 2018
	Derivatives used for hedging	Derivatives held for trading (FVTPL)	Amortized cost	Other financial assets (FVTPL)	Total
Financial assets
Cash and cash equivalents ⁽¹⁾	—	—	89	—	89
Restricted cash	—	—	66	—	66
Trade and other receivables	—	—	731	25	756
Long-term portion of finance lease receivables	—	—	191	—	191
Risk management assets
Current	60	86	—	—	146
Long-term	629	33	—	—	662
Other assets	—	—	37	15	52
Financial liabilities
Accounts payable and accrued liabilities	—	—	497	—	497
Dividends payable	—	—	58	—	58
Risk management liabilities
Current	1	89	—	—	90
Long-term	1	40	—	—	41
Credit facilities, long-term debt and finance lease obligations ⁽²⁾	—	—	3,267	—	3,267

(1) Includes cash equivalents of nil .

(2) Includes current portion.



Carrying value as at Dec. 31, 2017
	Derivatives used for hedging	Derivatives classified as held for trading	Loans and receivables	Other financial liabilities	Total
Financial assets
Cash and cash equivalents ⁽¹⁾	—	—	314	—	314
Restricted cash	—	—	30	—	30
Trade and other receivables	—	—	933	—	933
Long-term portion of finance lease receivables	—	—	215	—	215
Risk management assets
Current	82	137	—	—	219
Long-term	638	46	—	—	684
Other assets	—	—	33	—	33
Financial liabilities
Accounts payable and accrued liabilities	—	—	—	595	595
Dividends payable	—	—	—	34	34
Risk management liabilities
Current	8	93	—	—	101
Long-term	2	38	—	—	40
Credit facilities, long-term debt and finance lease obligations ⁽²⁾	—	—	—	3,707	3,707

(1) Includes cash equivalents of nil .

(2) Includes current portion.

TRANSALTA CORPORATION F 49

Notes to Consolidated Financial Statements

B. Fair Value of Financial Instruments

The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by reference to prices for that instrument in active markets to which the Corporation has access. In the absence of an active market, the Corporation determines fair values based on valuation models or by reference to other similar products in active markets.

Fair values determined using valuation models require the use of assumptions. In determining those assumptions, the Corporation looks primarily to external readily observable market inputs. However, if not available, the Corporation uses inputs that are not based on observable market data.

I. Level I, II and III Fair Value Measurements

a. Level I

Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Corporation has the ability to access at the measurement date. In determining Level I fair values, the Corporation uses quoted prices for identically traded commodities obtained from active exchanges such as the New York Mercantile Exchange.

b. Level II

Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.

The Corporation’s commodity risk management Level II financial instruments include over-the-counter derivatives with values based on observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and regression or extrapolation formulas, where the inputs are readily observable, including commodity prices for similar assets or liabilities in active markets, and implied volatilities for options.

In determining Level II fair values of other risk management assets and liabilities, the Corporation uses observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, the Corporation relies on similar interest or currency rate inputs and other third-party information such as credit spreads.

c. Level III

Fair values are determined using inputs for the assets or liabilities that are not readily observable.

The Corporation may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair values are determined using valuation techniques such as the Black-Scholes, mark-to-forecast and historical bootstrap models with inputs that are based on historical data such as unit availability, transmission congestion, demand profiles for individual non-standard deals and structured products, and/or volatilities and correlations between products derived from historical prices.

The Corporation also has various commodity contracts with terms that extend beyond a liquid trading period. As forward market prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these contracts are classified in Level III.

The Corporation has a Commodity Exposure Management Policy, that governs both the commodity transactions undertaken in its proprietary trading business and those undertaken to manage commodity price exposures in its generation business. This Policy defines and specifies the controls and management responsibilities associated with commodity trading activities, as well as the nature and frequency of required reporting of such activities.

TRANSALTA CORPORATION F 50

Notes to Consolidated Financial Statements

Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by the Corporation’s risk management department. Level III fair values are calculated within the Corporation’s energy trading risk management system based on underlying contractual data as well as observable and non-observable inputs. Development of non-observable inputs requires the use of judgment. To ensure reasonability, system-generated Level III fair value measurements are reviewed and validated by the risk management and finance departments. Review occurs formally on a quarterly basis or more frequently if daily review and monitoring procedures identify unexpected changes to fair value or changes to key parameters.

Information on risk management contracts or groups of risk management contracts that are included in Level III measurements and the related unobservable inputs and sensitivities, is as follows, and excludes the effects on fair value of certain unobservable inputs such as liquidity and credit discount (described as “base fair values”), as well as inception gains or losses. Sensitivity ranges for the base fair values are determined using reasonably possible alternative assumptions for the key unobservable inputs, which may include forward commodity prices, commodity volatilities and correlations, delivery volumes, and shapes.



As at Dec. 31	2018			2017
Description	Base fair value		Sensitivity	Base fair value		Sensitivity
Long-term power sale - US	801		+116 -116	853		+130 -130
Long-term power sale - Alberta	4		+1 -1	(1	)	+2 -2
Unit contingent power purchases	18		+4 -4	44		+7 -9
Structured products - Eastern US	6		+5 -5	17		+8 -7
Long-term wind energy sale - Eastern US	(39	)	+21 -21	—		—
Others	4		+3 -3	5		+9 -9

i. Long-Term Power Sale - US

The Corporation has a long-term fixed price power sale contract in the US for delivery of power at the following capacity levels: 380 MW through Dec. 31, 2024, and 300 MW through Dec. 31, 2025. The contract is designated as an all-in-one cash flow hedge.

For periods beyond 2020 , market forward power prices are not readily observable. For these periods, fundamental-based forecasts and market indications have been used to determine proxies for base, high and low power price scenarios. The base price forecast has been developed by using a fundamental-based forecast (the provider is an independent and widely accepted industry expert for scenario and planning views). Prior to the second quarter of 2018, the base price forecast was developed using an additional independent industry forecast. Forward power price ranges per MWh used in determining the Level III base fair value at Dec. 31, 2018 , are US $20 -US $35 ( Dec. 31, 2017 - US $25 -US $34 ). The sensitivity analysis has been prepared using the Corporation’s assessment that a US $6 ( Dec. 31, 2017 - US $6 ) price increase or decrease in the forward power prices is a reasonably possible change.

The contract is denominated in US dollars. With the strengthening of the US dollar relative to the Canadian dollar from Dec. 31, 2017 to Dec. 31, 2018 , the base fair value and the sensitivity values have increased by approximately $62 million and $9 million , respectively.

ii. Long-Term Power Sale - Alberta

The Corporation has a long-term 12.5 MW fixed price power sale contract (monthly shaped) in the Alberta market through December 2024. The contract is accounted for as FVTPL.

For periods beyond 2023, market forward power prices are not readily observable. For these periods, fundamental-based price forecasts and market indications have been used as proxies to determine base, high and low power price scenarios. The base scenario uses the most recent price view from an independent external forecasting service that is accepted within industry as an expert in the Alberta market. Forward power prices per MWh used in determining the Level III base fair value at Dec. 31, 2018 , are $40 ( Dec. 31, 2017 - $63 - $67 ). The sensitivity analysis has been prepared using the Corporation’s assessment that a 20 per cent increase or decrease in the forward power prices is a reasonably possible change.

TRANSALTA CORPORATION F 51

Notes to Consolidated Financial Statements

iii. Unit Contingent Power Purchases

Under the unit contingent power purchase agreements, the Corporation has agreed to purchase power contingent upon the actual generation of specific units owned and operated by third parties. Under these types of agreements, the purchaser pays the supplier an agreed upon fixed price per MWh of output multiplied by the pro rata share of actual unit production (nil if a plant outage occurs). The contracts are accounted for as FVTPL.

The key unobservable inputs used in the valuations are delivered volume expectations and hourly shapes of production. Hourly shaping of the production will result in realized prices that may be at a discount (or premium) relative to the average settled power price. Reasonably possible alternative inputs were used to determine sensitivity on the fair value measurements.

This analysis is based on historical production data of the generation units for available history. Price and volumetric discount ranges per MWh used in the Level III base fair value measurement at Dec. 31, 2018 , are nil ( Dec. 31, 2017 - nil ) and 2.2 per cent to 16.9 per cent ( Dec. 31, 2017 – 2.2 per cent to 2.8 per cent), respectively. The sensitivity analysis has been prepared using the Corporation’s assessment of a reasonably possible change in price discount ranges of approximately 1.1 per cent to 1.9 per cent ( Dec. 31, 2017 - 1.1 per cent to 1.9 per cent) and a change in volumetric discount rates of approximately 8.6 per cent to 27.3 per cent ( Dec. 31, 2017 - 7.8 per cent and 10.5 per cent), which approximate one standard deviation for each input.

iv. Structured Products - Eastern US

The Corporation has fixed priced power and heat rate contracts in the eastern United States. Under the fixed priced power contracts, the Corporation has agreed to buy or sell power at non-liquid locations or during non-standard hours. The Corporation has also bought and sold heat rate contracts at both liquid and non-liquid locations. Under a heat rate contract, the buyer has the right to purchase power at times when the market heat rate is higher than the contractual heat rate.

The key unobservable inputs in the valuation of the fixed priced power contracts are market forward spreads and non-standard shape factors. A historical regression analysis has been performed to model the spreads between non-liquid and liquid hubs. The non-standard shape factors have been determined using the historical data. Basis relationship and non-standard shape factors used in the Level III base fair value measurement at Dec. 31, 2018 , are 75 per cent to 109 per cent and 63 per cent to 104 per cent ( Dec. 31, 2017 – 75 per cent to 159 per cent and 71 per cent to 88 per cent), respectively. The sensitivity analysis has been prepared using the Corporation’s assessment of a reasonably possible change in market forward spreads of approximately 4 per cent to 7 per cent ( Dec. 31, 2017 - 7 per cent) and a change in non-standard shape factors of approximately 4 per cent to 9 per cent ( Dec. 31, 2017 - 6 per cent), which approximate one standard deviation for each input.

The key unobservable inputs in the valuation of the heat rate contracts are implied volatilities and correlations. Implied volatilities and correlations used in the Level III base fair value measurement at Dec. 31, 2018 , are 25 per cent to 84 per cent and 70 per cent ( Dec. 31, 2017 – 18 per cent to 54 per cent and 70 per cent), respectively. The sensitivity analysis has been prepared using the Corporation’s assessment of a reasonably possible change in implied volatilities ranges and correlations of approximately 37 per cent to 49 per cent and 30 per cent, respectively ( 2017 - 27 per cent to 32 per cent and 10 per cent, respectively).

v. Long-Term Wind Energy Sale - Eastern US

In relation to the acquisition of Big Level (See Note 4(C)), the Corporation has a long-term contract for differences whereby the Corporation receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh as well as the physical delivery of renewable energy credits ("RECs") based on proxy generation. Commercial operation of the facility is expected to occur in the second half of 2019, with the contract extending for 15 years after commercial operation. The contract is accounted for at fair value through profit or loss.

The key unobservable inputs used in the valuation of the contract are expected proxy generation volumes and forward prices for power and RECs beyond 2023 and 2022, respectively. Forward power and REC price ranges per MWh used in determining the Level III base fair value at Dec. 31, 2018 , are US $42 -US $68 and US $7 -US $8 , respectively. The sensitivity analysis has been prepared using the Corporation’s assessment that a change in expected proxy generation volumes of 10 per cent, a change in energy prices of US $6 and a change in REC prices of US $1 as reasonably possible changes.

TRANSALTA CORPORATION F 52

Notes to Consolidated Financial Statements

II. Commodity Risk Management Assets and Liabilities

Commodity risk management assets and liabilities include risk management assets and liabilities that are used in the energy marketing and generation businesses in relation to trading activities and certain contracting activities. To the extent applicable, changes in net risk management assets and liabilities for non-hedge positions are reflected within earnings of these businesses.

Commodity risk management assets and liabilities classified by fair value levels as at Dec. 31, 2018 , are as follows: Level I - $3 million net asset ( Dec. 31, 2017 - $1 million net liability), Level II - $19 million net liability ( Dec. 31, 2017 - $42 million net liability) and Level III - $695 million net asset ( Dec. 31, 2017 - $771 million net asset).

Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2018 , are primarily attributable to the settlement of contracts, partially offset by favourable foreign exchange rates.

The following tables summarize the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification level during the years ended Dec. 31, 2018 and 2017 , respectively:



	Year ended Dec. 31, 2018						Year ended Dec. 31, 2017
	Hedge		Non-hedge		Total		Hedge		Non-hedge		Total
Opening balance	719		52		771		726		32		758
Changes attributable to:
Market price changes on existing contracts	(7	)	(9	)	(16	)	100		(2	)	98
Market price changes on new contracts	—		4		4		—		33		33
Contracts settled	(90	)	(42	)	(132	)	(57	)	(10	)	(67	)
Change in foreign exchange rates	67		5		72		(50	)	(2	)	(52	)
Transfers into (out of) Level III	—		(4	)	(4	)	—		1		1
Net risk management assets at end of period	689		6		695		719		52		771
Additional Level III information:
Gains recognized in other comprehensive income	60		—		60		50		—		50
Total gains included in earnings before income taxes	90		—		90		57		29		86
Unrealized gains (losses) included in earnings before income taxes relating to net assets held at period end	—		(42	)	(42	)	—		19		19

III. Other Risk Management Assets and Liabilities

Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in managing exposures on non-energy marketing transactions such as interest rates, the net investment in foreign operations and other foreign currency risks. Hedge accounting is not always applied.

Other risk management assets and liabilities with a total net liability fair value of $2 million as at Dec. 31, 2018 ( Dec. 31, 2017 - $34 million net asset) are classified as Level II fair value measurements. The significant changes in other net risk management assets during the year ended Dec. 31, 2018 , are primarily attributable to the settlement of contracts.

IV. Other Financial Assets and Liabilities

The fair value of financial assets and liabilities measured at other than fair value is as follows:



	Fair value ⁽¹⁾				Total carrying
	Level I	Level II	Level III	Total	value ⁽¹⁾
Long-term debt - Dec. 31, 2018	—	3,181	—	3,181	3,204
Long-term debt - Dec. 31, 2017	—	3,708	—	3,708	3,638

(1) Includes current portion.

The fair values of the Corporation’s debentures and senior notes are determined using prices observed in secondary markets. Non-recourse and other long-term debt fair values are determined by calculating an implied price based on a current assessment of the yield to maturity.

TRANSALTA CORPORATION F 53

Notes to Consolidated Financial Statements

The carrying amount of other short-term financial assets and liabilities (cash and cash equivalents, trade accounts receivable, collateral paid, accounts payable and accrued liabilities, collateral received and dividends payable) approximates fair value due to the liquid nature of the asset or liability . The fair values of the loan receivable (see Note 20 ) and the finance lease receivables (see Note 8 ) approximate the carrying amounts.

C. Inception Gains and Losses

The majority of derivatives traded by the Corporation are based on adjusted quoted prices on an active exchange or extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives are determined using inputs that are not readily observable. Refer to section B of this note for fair value Level III valuation techniques used. In some instances, a difference may arise between the fair value of a financial instrument at initial recognition (the “transaction price”) and the amount calculated through a valuation model. This unrealized gain or loss at inception is recognized in net earnings (loss) only if the fair value of the instrument is evidenced by a quoted market price in an active market, observable current market transactions that are substantially the same, or a valuation technique that uses observable market inputs. Where these criteria are not met, the difference is deferred on the Consolidated Statements of Financial Position in risk management assets or liabilities, and is recognized in net earnings (loss) over the term of the related contract. The difference between the transaction price and the fair value determined using a valuation model, yet to be recognized in net earnings, and a reconciliation of changes is as follows:



As at Dec. 31	2018		2017		2016
Unamortized net gain at beginning of year	105		148		202
New inception gains (losses)	(14	)	12		10
Change in foreign exchange rates	5		(7	)	(4	)
Amortization recorded in net earnings during the year	(47	)	(48	)	(60	)
Unamortized net gain at end of year	49		105		148

15 . Risk Management Activities

A. Risk Management Strategy

The Corporation is exposed to market risk from changes in commodity prices, foreign exchange rates, interest rates, credit risk and liquidity risk. These risks affect the Corporation’s earnings and the value of associated financial instruments that the Corporation holds. In certain cases, the Corporation seeks to minimize the effects of these risks by using derivatives to hedge its risk exposures. The Corporation’s risk management strategy, policies and controls are designed to ensure that the risks it assumes comply with the Corporation’s internal objectives and its risk tolerance.

The Corporation has two primary streams of risk management activities: i) financial exposure management and ii) commodity exposure management. Within these activities, risks identified for management include commodity risk, interest rate risk, liquidity risk, equity price risk and foreign currency risk.

The Corporation seeks to minimize the effects of commodity risk, interest rate risk and foreign currency risk by using derivative financial instruments to hedge risk exposures. Of these derivatives, the Corporation may apply hedge accounting to those hedging commodity price risk and foreign currency risk.

The use of financial derivatives is governed by the Corporation’s policies approved by the Board, which provide written principles on commodity risk, interest rate risk, liquidity risk, equity price risk and foreign currency risk, as well as the use of financial derivatives and non-derivative financial instruments.

Liquidity risk, credit risk and equity price risk are managed through means other than derivatives or hedge accounting.

The Corporation enters into various derivative transactions as well as other contracting activities that do not qualify for hedge accounting or where a choice was made not to apply hedge accounting. As a result, the related assets and liabilities are classified as derivatives at fair value through profit and loss . The net realized and unrealized gains or losses from changes in the fair value of these derivatives are reported in net earnings in the period the change occurs.

The Corporation designates certain derivatives as hedging instruments to hedge commodity price risk, foreign currency exchange risk in cash flow hedges, and hedges of net investments in foreign operations. Hedges of foreign exchange risk on firm commitments are accounted for as cash flow hedges.

TRANSALTA CORPORATION F 54

Notes to Consolidated Financial Statements

At the inception of the hedge relationship, the Corporation documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. At the inception of the hedge and on an ongoing basis, the Corporation also documents whether the hedging instrument is effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk, which is when the hedging relationships meet all of the following hedge effectiveness requirements:


▪	There is an economic relationship between the hedged item and the hedging instrument;


▪	The effect of credit risk does not dominate the value changes that result from that economic relationship; and


▪	The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Corporation actually hedges and the quantity of the hedging instrument that the entity actually uses to hedge that quantity of hedged item.

If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio, but the risk management objective for that designated hedging relationship remains the same, the Corporation adjusts the hedge ratio of the hedging relationship so that it continues to meet the qualifying criteria.

B. Net Risk Management Assets and Liabilities

Aggregate net risk management assets and (liabilities) are as follows:



As at Dec. 31, 2018
	Cash flow hedges	Not designated as a hedge		Total
Commodity risk management
Current	59	—		59
Long-term	628	(8	)	620
Net commodity risk management assets	687	(8	)	679
Other
Current	—	(3	)	(3	)
Long-term	—	1		1
Net other risk management assets (liabilities)	—	(2	)	(2	)

Total net risk management assets (liabilities)	687	(10	)	677



As at Dec. 31, 2017
	Cash flow hedges	Not designated as a hedge		Total
Commodity risk management
Current	74	7		81
Long-term	636	11		647
Net commodity risk management assets	710	18		728
Other
Current	—	37		37
Long-term	—	(3	)	(3	)
Net other risk management assets (liabilities)	—	34		34

Total net risk management assets (liabilities)	710	52		762

TRANSALTA CORPORATION F 55

Notes to Consolidated Financial Statements

I. Netting Arrangements

Information about the Corporation’s financial assets and liabilities that are subject to enforceable master netting arrangements or similar agreements is as follows:



As at Dec. 31	2018						2017
	Current financial assets	Long-term financial assets	Current financial liabilities		Long-term financial liabilities		Current financial assets		Long-term financial assets	Current financial liabilities		Long-term financial liabilities
Gross amounts recognized	210	666	(121	)	(50	)	281		637	(159	)	(38	)
Gross amounts set-off	—	—	—		—		(43	)	—	43		—
Net amounts as presented in the Consolidated Statements of Financial Position	210	666	(121	)	(50	)	238		637	(116	)	(38	)

C. Nature and Extent of Risks Arising from Financial Instruments

I. Market Risk

a. Commodity Price Risk Management

The Corporation has exposure to movements in certain commodity prices in both its electricity generation and proprietary trading businesses, including the market price of electricity and fuels used to produce electricity. Most of the Corporation’s electricity generation and related fuel supply contracts are considered to be contracts for delivery or receipt of a non-financial item in accordance with the Corporation’s expected own use requirements and are not considered to be financial instruments. As such, the discussion related to commodity price risk is limited to the Corporation’s proprietary trading business and commodity derivatives used in hedging relationships associated with the Corporation’s electricity generating activities.

To mitigate the risk of adverse commodity price changes, the Corporation uses three tools:


▪	a framework of risk controls;


▪	a pre-defined hedging plan, including fixed price financial power swaps and long-term physical power sale contracts to hedge commodity price for electricity generation; and


▪	a committee dedicated to overseeing the risk and compliance program in trading and ensuring the existence of appropriate controls, processes, systems and procedures to monitor adherence to the program.

The Corporation has executed commodity price hedges for its Centralia coal plant and for its portfolio of merchant power exposure in Alberta, including a long-term physical power sale contract at Centralia and fixed price financial swaps for the Alberta portfolio to hedge the prices. Both hedging strategies fall under the Corporation’s risk management strategy used to hedge commodity price risk.

There is no source of hedge ineffectiveness for the merchant power exposure in Alberta.

Market risk exposures are measured using Value at Risk (VaR) supplemented by sensitivity analysis. There has been no change to the Corporation’s exposure to market risks or the manner in which these risks are managed or measured.

i. Commodity Price Risk Management – Proprietary Trading

The Corporation’s Energy Marketing segment conducts proprietary trading activities and uses a variety of instruments to manage risk, earn trading revenue and gain market information.

In compliance with the Commodity Exposure Management Policy, proprietary trading activities are subject to limits and controls, including Value at Risk (“VaR”) limits. The Board approves the limit for total VaR from proprietary trading activities. VaR is the most commonly used metric employed to track and manage the market risk associated with trading positions. A VaR measure gives, for a specific confidence level, an estimated maximum pre-tax loss that could be incurred over a specified period of time. VaR is used to determine the potential change in value of the Corporation’s proprietary trading portfolio, over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations. VaR is estimated using the historical variance/covariance approach. VaR is a measure that has certain inherent limitations. The use of historical information in the estimate assumes that price movements in the past will be indicative of future market risk. As such, it may only be meaningful under normal market conditions. Extreme market events are not addressed by this risk measure. In addition, the use of a three-day measurement period implies that positions can be unwound or hedged within three days, although this may not be possible if the market becomes illiquid.

TRANSALTA CORPORATION F 56

Notes to Consolidated Financial Statements

Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes occur. VaR at Dec. 31, 2018 , associated with the Corporation’s proprietary trading activities was $2 million ( 2017 - $5 million , 2016 - $2 million ).

ii. Commodity Price Risk - Generation

The generation segments utilize various commodity contracts to manage the commodity price risk associated with electricity generation, fuel purchases, emissions and byproducts, as considered appropriate. A Commodity Exposure Management Policy is prepared and approved annually, which outlines the intended hedging strategies associated with the Corporation’s generation assets and related commodity price risks. Controls also include restrictions on authorized instruments, management reviews on individual portfolios and approval of asset transactions that could add potential volatility to the Corporation’s reported net earnings.

TransAlta has entered into various contracts with other parties whereby the other parties have agreed to pay a fixed price for electricity to TransAlta. While not all of the contracts create an obligation for the physical delivery of electricity to other parties, the Corporation has the intention and believes it has sufficient electrical generation available to satisfy these contracts and, where able, has designated these as cash flow hedges for accounting purposes. As a result, changes in market prices associated with these cash flow hedges do not affect net earnings in the period in which the price change occurs. Instead, changes in fair value are deferred until settlement through AOCI, at which time the net gain or loss resulting from the combination of the hedging instrument and hedged item affects net earnings.

VaR at Dec. 31, 2018 , associated with the Corporation’s commodity derivative instruments used in generation hedging activities was $18 million ( 2017 - $16 million , 2016 - $19 million ). For positions and economic hedges that do not meet hedge accounting requirements or for short-term optimization transactions such as buybacks entered into to offset existing hedge positions, these transactions are marked to the market value with changes in market prices associated with these transactions affecting net earnings in the period in which the price change occurs. VaR at Dec. 31, 2018 , associated with these transactions was $13 million ( 2017 - $5 million , 2016 - $7 million ).

iii. Commodity Price Risk Management - Hedges

The Corporation’s outstanding commodity derivative instruments designated as hedging instruments are as follows:



As at Dec. 31	2018		2017
Type (thousands)	Notional amount sold	Notional amount purchased	Notional amount sold	Notional amount purchased
Electricity (MWh)	2,128	—	1,997	44

During 2018 , unrealized pre-tax gains of $4 million ( 2017 - $2 million , 2016 - $0 million ) related to certain power hedging relationships that were previously de-designated and deemed ineffective for accounting purposes were released from AOCI and recognized in net earnings.

iv. Commodity Price Risk Management - Non-Hedges

The Corporation’s outstanding commodity derivative instruments not designated as hedging instruments are as follows:



As at Dec. 31	2018		2017
Type (thousands)	Notional amount sold	Notional amount purchased	Notional amount sold	Notional amount purchased
Electricity (MWh)	58,885	37,023	14,688	7,348
Natural gas (GJ)	80,413	110,488	74,195	103,805
Transmission (MWh)	29	11,163	1	3,455
Emissions (tonnes)	3,134	2,948	516	717

b. Interest Rate Risk Management

Interest rate risk arises as the fair value or future cash flows of a financial instrument can fluctuate because of changes in market interest rates. Changes in interest rates can impact the Corporation’s borrowing costs and the capacity payments received under the Alberta coal PPAs. Changes in the cost of capital may also affect the feasibility of new growth initiatives.

The Corporation's credit facility and the Poplar Creek non-recourse bond are the only debt instruments subject to floating interest rates, which represents 14 per cent of the Corporation’s debt as at Dec. 31, 2018 ( 2017 - 6 per cent).

TRANSALTA CORPORATION F 57

Notes to Consolidated Financial Statements

Interest rate risk is managed with the use of derivatives. No derivatives related to interest rate risk were outstanding as at Dec. 31, 2018 , 2017 or 2016 .

c. Currency Rate Risk

The Corporation has exposure to various currencies, such as the US dollar, the Japanese yen and the Australian dollar (“AUD”), as a result of investments and operations in foreign jurisdictions, the net earnings from those operations and the acquisition of equipment and services from foreign suppliers.

The Corporation may enter into the following hedging strategies to mitigate currency rate risk, including:


•	Foreign exchange forward contracts to mitigate adverse changes in foreign exchange rates on project-related expenditures and distributions received in foreign currencies.


•	Foreign exchange forward contracts and cross-currency swaps to manage foreign exchange exposure on foreign-denominated debt not designated as a net investment hedge.


•	Designating foreign currency debt as a hedge of the net investment in foreign operations to mitigate the risk due to fluctuating exchange rates related to certain foreign subsidiaries.

i. Net Investment Hedges

When designating foreign currency debt as a hedge of the Corporation’s net investment in foreign subsidiaries, the Corporation has determined that the hedge is effective as the foreign currency of the net investment is the same as the currency of the hedge, and therefore an economic relationship is present.

The Corporation’s hedges of its net investment in foreign operations were comprised of US-dollar-denominated long-term debt with a face value of US$ 400 million ( 2017 - US $480 million ). During 2016, the Corporation de-designated its foreign currency forward contracts from its net investment hedges. The cumulative unrealized losses on these contracts are deferred in AOCI until the disposal of the related foreign operation.

ii. Cash Flow Hedges

The Corporation had no significant foreign currency cash flow hedges outstanding at Dec. 31, 2018 or 2017 .

iii. Non-Hedges

As part of the sale of the economic interest in Australian Assets to TransAlta Renewables, the Corporation agreed to mitigate the risks to TransAlta Renewables shareholders of adverse changes in the USD and AUD in respect of cash flows from the Australian Assets in relation to the Canadian dollar to June 30, 2020. The financial effects of the agreements eliminate on consolidation.

In order to mitigate some of the risk that is attributable to non-controlling interests, the Corporation entered into foreign currency contracts with third parties to the extent of the non-controlling interest percentage of the expected cash flow over five years to June 30, 2020. Hedge accounting was not applied to these foreign currency contracts. In early 2017, the Corporation revised its hedging strategies related to cash flows from its foreign operations. These foreign currency contracts became part of the Corporation's revised strategy, as opposed to a separate hedge program.

The Corporation also uses foreign currency contracts to manage its expected foreign operating cash flows. Hedge accounting is not applied to these foreign currency contracts.



As at Dec. 31		2018			2017
Notional amount sold	Notional amount purchased	Fair value asset (liability)		Maturity	Notional amount purchased	Fair value asset (liability)		Maturity
Foreign exchange forward contracts - foreign-denominated receipts/expenditures
AUD218	CAD205	(5	)	2019-2022	CAD157	(9	)	2018-2021
USD164	CAD214	(7	)	2019-2022	CAD104	11		2018-2021
Foreign exchange forward contracts - foreign-denominated debt
CAD124	USD100	10		2022	USD230	(4	)	2018
Cross currency swaps - foreign-denominated debt
—	—	—			USD270	35		2018

TRANSALTA CORPORATION F 58

Notes to Consolidated Financial Statements

During the first quarter of 2017, the Corporation discontinued hedge accounting for certain foreign currency cash flow hedges on US$690 million of debt. Changes in the risk management assets and liabilities related to these discontinued hedge positions have been reflected within net earnings prospectively.

iv. Impacts of currency rate risk

The possible effect on net earnings and OCI, due to changes in foreign exchange rates associated with financial instruments denominated in currencies other than the Corporation’s functional currency, is outlined below. The sensitivity analysis has been prepared using management’s assessment that an average four cent ( 2017 and 2016 - four cent) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter.



Year ended Dec. 31	2018			2017			2016
Currency	Net earnings increase (decrease) ⁽¹⁾		OCI gain ^(1),(2)	Net earnings increase ⁽¹⁾		OCI gain ^(1),(2)	Net earnings decrease ⁽¹⁾		OCI gain ^(1),(2)
USD	(13	)	—	(5	)	—	(5	)	—
AUD	(7	)	—	(7	)	—	(7	)	—
Total	(20	)	—	(12	)	—	(12	)	—

(1) These calculations assume an increase in the value of these currencies relative to the Canadian dollar. A decrease would have the opposite effect.

(2) The foreign exchange impact related to financial instruments designated as hedging instruments in net investment hedges has been excluded.

II. Credit Risk

Credit risk is the risk that customers or counterparties will cause a financial loss for the Corporation by failing to discharge their obligations, and the risk to the Corporation associated with changes in creditworthiness of entities with which commercial exposures exist. The Corporation actively manages its exposure to credit risk by assessing the ability of counterparties to fulfil their obligations under the related contracts prior to entering into such contracts. The Corporation makes detailed assessments of the credit quality of all counterparties and, where appropriate, obtains corporate guarantees, cash collateral, third-party credit insurance and/or letters of credit to support the ultimate collection of these receivables. For commodity trading and origination, the Corporation sets strict credit limits for each counterparty and monitors exposures on a daily basis. TransAlta uses standard agreements that allow for the netting of exposures and often include margining provisions. If credit limits are exceeded, TransAlta will request collateral from the counterparty or halt trading activities with the counterparty.

The Corporation uses external credit ratings, as well as internal ratings in circumstances where external ratings are not available, to establish credit limits for customers and counterparties. The following table outlines the Corporation’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at Dec. 31, 2018 :



	Investment grade (Per cent)	Non-investment grade (Per cent)	Total (Per cent)	Total amount
Trade and other receivables ⁽¹⁾	86	14	100	731
Long-term finance lease receivables	100	—	100	191
Risk management assets ⁽¹⁾	99	1	100	808
Loans and notes receivable ⁽²⁾	—	100	100	77
Total				1,807

(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.

(2) Includes the promissory note receivable for $25 million (see Note 13 ), the loan receivable of $37 million and the note receivable for $15 million (see Note 20 ). The counterparties have no external credit ratings.

An impairment analysis is performed at each reporting date using a provision matrix to measure expected credit losses. The provision rates are based on historical rates of default by segment of trade receivables as well as forward-looking credit ratings and forecasted default rates. In addition to the calculation of expected credit losses, TransAlta monitors key forward looking information as potential indicators that historical bad debt percentages, forward-looking S&P credit ratings and forecasted default rates would no longer be representative of future expected credit losses. The calculation reflects the probability-weighted outcome, the time value of money and reasonable and supportable information that is available at the reporting date about past events, current conditions and forecasts of future economic conditions. TransAlta evaluates the concentration of risk with respect to trade receivables as low, as its customers are located in several jurisdictions and industries. The Corporation did not have significant expected credit losses as at Dec. 31, 2018 .

TRANSALTA CORPORATION F 59

Notes to Consolidated Financial Statements

The Corporation’s maximum exposure to credit risk at Dec. 31, 2018 , without taking into account collateral held or right of set-off, is represented by the current carrying amounts of receivables and risk management assets as per the Consolidated Statements of Financial Position. Letters of credit and cash are the primary types of collateral held as security related to these amounts. The maximum credit exposure to any one customer for commodity trading operations and hedging, including the fair value of open trading, net of any collateral held, at Dec. 31, 2018 , was $13 million ( 2017 - $40 million ).

III. Liquidity Risk

Liquidity risk relates to the Corporation’s ability to access capital to be used for proprietary trading activities, commodity hedging, capital projects, debt refinancing and general corporate purposes. In December 2015, Moody’s downgraded the senior unsecured rating on TransAlta’s US bonds one notch from Baa3 to Ba1. As at Dec. 31, 2018 , TransAlta maintains investment grade ratings from three credit rating agencies. TransAlta is focused on strengthening its financial position and maintaining investment grade credit ratings with these major rating agencies.

Counterparties enter into certain commodity agreements, such as electricity and natural gas purchase and sale contracts, for the purposes of asset-backed sales and proprietary trading. The terms and conditions of these agreements may contain credit-contingent features (such as downgrades in creditworthiness), which if triggered may result in the Corporation having to post collateral to its counterparties.

TransAlta manages liquidity risk by monitoring liquidity on trading positions; preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital; reporting liquidity risk exposure for proprietary trading activities on a regular basis to the Risk Management Committee, senior management and the Board; maintaining investment grade credit ratings; and maintaining sufficient undrawn committed credit lines to support potential liquidity requirements. The Corporation does not use derivatives or hedge accounting to manage liquidity risk.

A maturity analysis of the Corporation’s financial liabilities is as follows:



	2019		2020		2021		2022	2023	2024 and thereafter	Total
Accounts payable and accrued liabilities	497		—		—		—	—	—	497
Long-term debt ⁽¹⁾	130		486		91		947	141	1,439	3,234
Commodity risk management assets	58		89		137		125	113	157	679
Other risk management (assets) liabilities	(3	)	(3	)	(3	)	7	—	—	(2	)
Finance lease obligations	18		16		9		5	5	10	63
Interest on long-term debt and finance lease obligations ⁽²⁾	161		152		129		123	84	694	1,343
Dividends payable	58		—		—		—	—	—	58
Total	919		740		363		1,207	343	2,300	5,872

(1) Excludes impact of hedge accounting.

(2) Not recognized as a financial liability on the Consolidated Statements of Financial Position.

IV. Equity Price Risk

a. Total Return Swaps

The Corporation has certain compensation, deferred and restricted share unit programs, the values of which depend on the common share price of the Corporation. The Corporation has fixed a portion of the settlement cost of these programs by entering into a total return swap for which hedge accounting has not been applied. The total return swap is cash settled every quarter based upon the difference between the fixed price and the market price of the Corporation’s common shares at the end of each quarter.

TRANSALTA CORPORATION F 60

Notes to Consolidated Financial Statements

D. Hedging Instruments - Uncertainty of Future Cash Flows

The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount, timing and uncertainty of future cash flows:



	Maturity
	2019	2020	2021	2022	2023	2024 and thereafter
Cash flow hedges
Commodity Derivative Instruments
Electricity
Notional amount (thousands MWh)	3,950	3,465	3,424	3,329	3,329	5,966
Average Price ($ per MWh)	66.86	70.75	74.16	76.81	78.74	81.59

E. Effects of Hedge Accounting on the Financial Position and Performance

I. Effect of Hedges

The impact of the hedging instruments on the statement of financial position is, as follows:



As at Dec. 31, 2018
	Notional amount	Carrying amount	Line item in the statement of financial position	Change in fair value used for measuring ineffectiveness
Commodity price risk
Cash flow hedges
Physical power sales	23 MMWh	687	Risk management assets	60
Foreign currency risk
Net investment hedges
Foreign-denominated debt	USD400	CAD546	Credit facilities, long-term debt and finance lease obligations	41

The impact of the hedged items on the statement of financial position is, as follows:



As at Dec. 31, 2018
	Change in fair value used for measuring ineffectiveness	Cash flow hedge reserve
Commodity price risk
Cash flow hedges
Power forecast sales - Centralia	60	508

	Change in fair value used for measuring ineffectiveness	Foreign currency translation reserve
Net investment hedges
Net investment in foreign subsidiaries	41	84

The hedging gain recognized in OCI before tax is equal to the change in fair value used for measuring effectiveness. There is no ineffectiveness recognized in profit or loss.

TRANSALTA CORPORATION F 61

Notes to Consolidated Financial Statements

The impact of hedged items designated in hedging relationships on OCI and net earnings is:



Year ended Dec. 31, 2018
			Effective portion			Ineffective portion
Derivatives in cash flow hedging relationships	Pre-tax gain (loss) recognized in OCI		Location of (gain) loss reclassified from OCI	Pre-tax (gain) loss reclassified from OCI		Location of (gain) loss reclassified from OCI	Pre-tax (gain) loss recognized in earnings
Commodity contracts	(9	)	Revenue	(67	)	Revenue	—
			Fuel and purchased power	—		Fuel and purchased power	—
Foreign exchange forwards on commodity contracts	—		Revenue	—		Revenue	—
Foreign exchange forwards on project hedges	—		Property, plant and equipment	—		Foreign exchange (gain) loss	—
Foreign exchange forwards on US debt	—		Foreign exchange (gain) loss	3		Foreign exchange (gain) loss	—
Cross-currency swaps	—		Foreign exchange (gain) loss	—		Foreign exchange (gain) loss	—
Forward starting interest rate swaps	—		Interest expense	7		Interest expense	—
OCI impact	(9	)	OCI impact	(57	)	Net earnings impact	—

Over the next 12 months, the Corporation estimates that approximately $68 million of after-tax gains will be reclassified from AOCI to net earnings. These estimates assume constant natural gas and power prices, interest rates, and exchange rates over time; however, the actual amounts that will be reclassified may vary based on changes in these factors.



Year ended Dec. 31, 2017 (as reported under IAS 39)
			Effective portion			Ineffective portion
Derivatives in cash flow hedging relationships	Pre-tax gain (loss) recognized in OCI		Location of (gain) loss reclassified from OCI	Pre-tax (gain) loss reclassified from OCI		Location of (gain) loss reclassified from OCI	Pre-tax (gain) loss recognized in earnings
Commodity contracts	163		Revenue	(172	)	Revenue	—
			Fuel and purchased power	—		Fuel and purchased power	—
Foreign exchange forwards on commodity contracts	—		Revenue	—		Revenue	—
Foreign exchange forwards on project hedges	(1	)	Property, plant and equipment	—		Foreign exchange (gain) loss	—
Foreign exchange forwards on US debt	—		Foreign exchange (gain) loss	3		Foreign exchange (gain) loss	—
Cross-currency swaps	(26	)	Foreign exchange (gain) loss	24		Foreign exchange (gain) loss	—
Forward starting interest rate swaps	—		Interest expense	7		Interest expense	—
OCI impact	136		OCI impact	(138	)	Net earnings impact	—

During December 2016, the Corporation entered into a new contract with the Ontario IESO relating to the Mississauga cogeneration facility that principally terminates the generation effective Jan. 1, 2017. Accordingly, in 2017 the Corporation reclassified unrealized pre-tax cash flow commodity hedge losses of $31 million and $15 million of unrealized pre-tax cash flow foreign exchange hedge gains from AOCI to net earnings due to hedge de-designations for accounting purposes. The cash flow hedges were in respect of future gas purchases expected to occur between 2017 and 2018. See Note 9 (C) for further details.

TRANSALTA CORPORATION F 62

Notes to Consolidated Financial Statements



Year ended Dec. 31, 2016 (as reported under IAS 39)
			Effective portion			Ineffective portion
Derivatives in cash flow hedging relationships	Pre-tax gain (loss) recognized in OCI		Location of (gain) loss reclassified from OCI	Pre-tax (gain) loss reclassified from OCI		Location of (gain) loss reclassified from OCI	Pre-tax (gain) loss recognized in earnings
Commodity contracts	304		Revenue	(169	)	Revenue	—
			Fuel and purchased power	44		Fuel and purchased power	31
Foreign exchange forwards on commodity contracts	(5	)	Revenue	(16	)	Revenue	(15	)
Foreign exchange forwards on project hedges	(1	)	Property, plant, and equipment	—		Foreign exchange (gain) loss	—
Foreign exchange forwards on US debt	(2	)	Foreign exchange (gain) loss	53		Foreign exchange (gain) loss	—
Cross-currency swaps	(25	)	Foreign exchange (gain) loss	(23	)	Foreign exchange (gain) loss	—
Forward starting interest rate swaps	—		Interest expense	6		Interest expense	—
OCI impact	271		OCI impact	(105	)	Net earnings impact	16

II. Effect of Non-Hedges

For the year ended Dec. 31, 2018 , the Corporation recognized a net unrealized loss of $29 million ( 2017 - gain of $45 million , 2016 - loss of $63 million ) related to commodity derivatives.

For the year ended Dec. 31, 2018 , a gain of $3 million ( 2017 - gain of $28 million , 2016 - gain of $9 million ) related to foreign exchange and other derivatives was recognized, which is comprised of net unrealized gains of $4 million ( 2017 - losses of $2 million , 2016 - gains of $4 million ) and net realized losses of $1 million ( 2017 - gains of $30 million , 2016 - gains of $5 million ).

F. Collateral

I. Financial Assets Provided as Collateral

At Dec. 31, 2018 , the Corporation provided $105 million ( 2017 - $67 million ) in cash and cash equivalents as collateral to regulated clearing agents as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents. Collateral provided is included in accounts receivable in the Consolidated Statements of Financial Position.

II. Financial Assets Held as Collateral

At Dec. 31, 2018 , the Corporation held $17 million ( 2017 - $21 million ) in cash collateral associated with counterparty obligations. Under the terms of the contracts, the Corporation may be obligated to pay interest on the outstanding balances and to return the principal when the counterparties have met their contractual obligations or when the amount of the obligation declines as a result of changes in market value. Interest payable to the counterparties on the collateral received is calculated in accordance with each contract. Collateral held is included in accounts payable in the Consolidated Statements of Financial Position.

III. Contingent Features in Derivative Instruments

Collateral is posted in the normal course of business based on the Corporation’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Corporation’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs. If a material adverse event resulted in the Corporation’s senior unsecured debt falling below investment grade, the counterparties to such derivative instruments could request ongoing full collateralization.

As at Dec. 31, 2018 , the Corporation had posted collateral of $120 million ( Dec. 31, 2017 - $131 million ) in the form of letters of credit on derivative instruments in a net liability position. Certain derivative agreements contain credit-risk-contingent features, which if triggered could result in the Corporation having to post an additional $120 million ( Dec. 31, 2017 - $96 million ) of collateral to its counterparties.

TRANSALTA CORPORATION F 63

Notes to Consolidated Financial Statements

16 . Inventory

Inventory held in the normal course of business, which includes coal, emission credits, parts and materials, and natural gas, is valued at the lower of cost and net realizable value. Inventory held for trading, which includes natural gas and emission credits and allowances, is valued at fair value less costs to sell.

The components of inventory are as follows:



As at Dec. 31	2018	2017
Parts and materials	113	118
Coal	108	58
Deferred stripping costs	7	11
Natural gas	4	9
Purchased emission credits	10	23
Total	242	219

The change in inventory is as follows:



Balance, Dec. 31, 2016	213
Net addition	11
Change in foreign exchange rates	(5	)
Balance, Dec. 31, 2017	219
Net addition	20
Change in foreign exchange rates	3
Balance, Dec. 31, 2018	242

No inventory is pledged as security for liabilities.

TRANSALTA CORPORATION F 64

Notes to Consolidated Financial Statements

17 . Property, Plant and Equipment

A reconciliation of the changes in the carrying amount of PP&E is as follows:



	Land		Coal generation		Gas generation		Renewable generation		Mining property and equipment		Assets under construction		Capital spares and other ⁽¹⁾		Total
Cost
As at Dec. 31, 2016	95		5,876		1,525		3,212		1,265		407		393		12,773
Additions	—		—		—		—		—		334		4		338
Additions - finance lease	—		—		—		—		14		—		—		14
Disposals	—		—		(16	)	(1	)	(1	)	—		(1	)	(19	)
Impairment charge - Sundance Unit 1 (Note 4)	—		(20	)	—		—		—		—		—		(20	)
Revisions and additions to decommissioning and restoration costs	—		82		12		15		42		—		—		151
Retirement of assets	—		(84	)	(3	)	(4	)	(22	)	—		(6	)	(119	)
Change in foreign exchange rates	(1	)	(87	)	3		(23	)	(7	)	(2	)	(2	)	(119	)
Transfers ⁽²⁾⁽³⁾	1		121		461		29		24		(644	)	(18	)	(26	)
As at Dec. 31, 2017	95		5,888		1,982		3,228		1,315		95		370		12,973
Additions ⁽⁴⁾	—		—		—		1		—		275		8		284
Additions - finance lease	—		—		—		—		10		—		—		10
Disposals	(3	)	—		—		—		(1	)	—		(3	)	(7	)
Impairment charges (Note 7)	—		(38	)	—		(11	)	—		—		—		(49	)
Revisions and additions to decommissioning and restoration costs	—		(12	)	(1	)	(3	)	(16	)	—		—		(32	)
Retirement of assets	—		(47	)	(17	)	(6	)	(16	)	—		(4	)	(90	)
Change in foreign exchange rates	2		105		(13	)	26		7		4		—		131
Transfers	—		41		13		51		39		(174	)	12		(18	)
As at Dec. 31, 2018	94		5,937		1,964		3,286		1,338		200		383		13,202

Accumulated depreciation
As at Dec. 31, 2016	—		3,212		1,027		922		659		—		129		5,949
Depreciation	—		351		67		123		76		—		18		635
Retirement of assets	—		(62	)	(2	)	(3	)	(18	)	—		(5	)	(90	)
Disposals	—		—		(11	)	(1	)	—		—		—		(12	)
Change in foreign exchange rates	—		(67	)	(1	)	(4	)	(4	)	—		—		(76	)
Transfers ⁽²⁾	—		(3	)	(8	)	—		—		—		—		(11	)
As at Dec. 31, 2017	—		3,431		1,072		1,037		713		—		142		6,395
Depreciation	—		306		79		123		125		—		16		649
Retirement of assets	—		(56	)	(13	)	(2	)	(12	)	—		—		(83	)
Disposals	—		—		—		—		(1	)	—		(4	)	(5	)
Change in foreign exchange rates	—		84		(3	)	6		5		—		—		92
Transfers	—		—		(7	)	(3	)	—		—		—		(10	)
As at Dec. 31, 2018	—		3,765		1,128		1,161		830		—		154		7,038

Carrying amount
As at Dec. 31, 2016	95		2,664		498		2,290		606		407		264		6,824
As at Dec. 31, 2017	95		2,457		910		2,191		602		95		228		6,578
As at Dec. 31, 2018	94		2,172		836		2,125		508		200		229		6,164

(1) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance, and the Australian gas pipeline.

(2) In 2017, net transfers of $14 million relate to the transfer of gas equipment to finance lease receivables.

(3) During the second quarter of 2017, the Corporation reclassified approximately $13 million of capital spares and other assets to inventory.

(4) Includes $7 million related to the acquisition of Big Level.

The Corporation capitalized $2 million of interest to PP&E in 2018 ( 2017 - $9 million ) at a weighted average rate of 4.454 per cent ( 2017 – 5.87 per cent). Finance lease additions in 2018 and 2017 are for mining equipment at the Highvale mine. The carrying amount of total assets under finance leases as at Dec. 31, 2018 , was $65 million ( 2017 - $65 million ).

TRANSALTA CORPORATION F 65

Notes to Consolidated Financial Statements

18 . Goodwill

Goodwill acquired through business combinations has been allocated to CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments are as follows:



As at Dec. 31	2018	2017
Hydro	259	259
Wind and Solar	175	174
Energy Marketing	30	30
Total goodwill	464	463

For the purposes of the 2018 annual goodwill impairment review, the Corporation determined the recoverable amounts of the Wind and Solar segment by calculating the fair value less costs of disposal using discounted cash flow projections based on the Corporation's long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair value measurement is categorized within Level III of the fair value hierarchy. In 2018 , the Corporation relied on the recoverable amounts determined in 2016 for the Hydro and Energy Marketing segments in performing the 2018 annual goodwill impairment review. No impairment of goodwill arose for any segment.

The key assumption impacting the determination of fair value for the Wind and Solar and Hydro segments are electricity production and sales prices. Forecasts of electricity production for each facility are determined taking into consideration contracts for the sale of electricity, historical production, regional supply-demand balances and capital maintenance and expansion plans. Forecasted sales prices for each facility are determined by taking into consideration contract prices for facilities subject to long- or short-term contracts, forward price curves for merchant plants and regional supply-demand balances. Where forward price curves are not available for the duration of the facility’s useful life, prices are determined by extrapolation techniques using historical industry and company-specific data. Electricity prices used in these 2018 models ranged between $6 to $179 per MWh during the forecast period ( 2017 - $22 to $218 per MWh). Discount rates used for the goodwill impairment calculation in 2018 ranged from 5.3 per cent to 6.2 per cent ( 2017 – 5.5 per cent to 6.0 per cent). No reasonable possible change in the assumptions would have resulted in an impairment of goodwill.

TRANSALTA CORPORATION F 66

Notes to Consolidated Financial Statements

19 . Intangible Assets

A reconciliation of the changes in the carrying amount of intangible assets is as follows:



	Coal rights		Software and other		Power sale contracts		Intangibles under development		Total
Cost
As at Dec. 31, 2016	178		268		223		24		693
Additions	—		31		—		20		51
Change in foreign exchange rates	—		(3	)	—		—		(3	)
Transfers	—		18		—		(15	)	3
As at Dec. 31, 2017	178		314		223		29		744
Additions ⁽¹⁾	—		—		—		53		53
Retirements and disposals ⁽²⁾	—		(2	)	—		—		(2	)
Change in foreign exchange rates	—		3		—		—		3
Transfers	7		24		14		(36	)	9
As at Dec. 31, 2018	185		339		237		46		807

Accumulated amortization
As at Dec. 31, 2016	115		163		60		—		338
Amortization	8		24		9		—		41
Change in foreign exchange rates	—		1		—		—		1
Transfers	2		—		(2	)	—		—
As at Dec. 31, 2017	125		188		67		—		380
Amortization	9		32		9		—		50
Retirements and disposals	—		(1	)	—		—		(1	)
Change in foreign exchange rates	—		2		—		—		2
Transfers	(17	)	—		20		—		3
As at Dec. 31, 2018	117		221		96		—		434

Carrying amount
As at Dec. 31, 2016	63		105		163		24		355
As at Dec. 31, 2017	53		126		156		29		364
As at Dec. 31, 2018	68		118		141		46		373

(1) Includes $33 million related to the acquisition of Big Level.

(2) Includes the impairment charge of $1 million relating to Kent Breeze. See Note 7 for further details.

TRANSALTA CORPORATION F 67

Notes to Consolidated Financial Statements

20 . Other Assets

The components of other assets are as follows:



As at Dec. 31	2018	2017
South Hedland prepaid transmission access and distribution costs	72	75
Deferred licence fees	11	13
Project development costs	47	53
Deferred service costs	12	15
Long-term prepaids and other assets	53	44
Loan receivable	37	33
Keephills Unit 3 transmission deposit	2	4
Total other assets	234	237

South Hedland prepaid electricity transmission and distribution costs are costs that are amortized on a straight-line basis over the South Hedland PPA contract life.

Deferred licence fees consist primarily of licences to lease the land on which certain generating assets are located, and are amortized on a straight-line basis over the useful life of the generating assets to which the licences relate.

Project development costs are primarily comprised of the Corporation’s Sundance 7 project in Alberta and project costs for the Pioneer Pipeline project (Note 4(A)). In December 2015, the Corporation repurchased its partner’s 50 per cent share in TAMA Power, the jointly controlled entity developing the Sundance 7 project, for consideration of $10 million , payable in four years and an option for its partner to re-enter the development projects of TAMA Power at accumulated cost during this period. Some projects were written off in 2018 as they are no longer proceeding (see Note 7 (B)).

Deferred service costs are TransAlta’s contracted payments for shared capital projects required at the Genesee Unit 3 and Keephills Unit 3 sites. These costs are amortized over the life of these projects.

Long-term prepaids and other assets include the funded portion of the TransAlta Energy Transition Bill commitments discussed in Note 33 .

The loan receivable relates to the advancement by the Corporation's subsidiary, Kent Hills Wind LP, of $37 million ( 2017 - $38 million ) (net) of the Kent Hills Wind bond financing proceeds to its 17 per cent partner. The loan bears interest at 4.55 per cent, with interest payable quarterly, commencing on Dec. 31, 2017, is unsecured and matures on Oct. 2, 2022. The current portion of nil ( 2017 - $5 million ) is included in accounts receivable and the long-term portion of the $37 million (2017 - $33 million ) is included in other assets.

The Keephills Unit 3 transmission deposit is TransAlta’s proportionate share of a provincially required deposit. The full amount of the deposit is anticipated to be reimbursed over the next four years to 2021, as long as certain performance criteria are met.

TRANSALTA CORPORATION F 68

Notes to Consolidated Financial Statements

21 . Decommissioning and Other Provisions

The change in decommissioning and other provision balances is as follows:



	Decommissioning and restoration		Other		Total
Balance, Dec. 31, 2016	293		50		343
Liabilities incurred	3		19		22
Liabilities settled	(19	)	(31	)	(50	)
Liabilities disposed ⁽¹⁾	(8	)	—		(8	)
Accretion	23		—		23
Revisions in estimated cash flows ⁽²⁾	41		1		42
Revisions in discount rates ⁽²⁾	110		—		110
Reversals	—		(4	)	(4	)
Change in foreign exchange rates	(6	)	(2	)	(8	)
Balance, Dec. 31, 2017	437		33		470
Liabilities incurred	5		17		22
Liabilities settled	(31	)	(10	)	(41	)
Accretion	24		—		24
Acquisition of liabilities (Big Level)			8		8
Revisions in estimated cash flows	2		3		5
Revisions in discount rates	(37	)	—		(37	)
Reversals	—		(5	)	(5	)
Change in foreign exchange rates	7		3		10
Balance, Dec. 31, 2018	407		49		456

(1) Relates to the disposition of the Solomon power station and the sale of the Wintering Hills wind facility.

(2) During 2017, mainly as a result of the OCA (see Note 4(O)), the discount rates used for the Canadian coal and mining operations decommissioning provisions were changed to the use of 5 to 15 -year rates. The use of lower, shorter-term discount rates increased the corresponding liabilities. On average, these rates decreased by approximately 1.60 to 2.10 per cent. Additionally, the amount and timing of cash outflows for certain Canadian coal plants and mining operations was also revised, resulting in an increase to the corresponding liabilities.



	Decommissioning and restoration	Other	Total
Balance, Dec. 31, 2017	437	33	470
Current portion	40	27	67
Non-current portion	397	6	403
Balance, Dec. 31, 2018	407	49	456
Current portion	35	35	70
Non-current portion	372	14	386

A. Decommissioning and Restoration

A provision has been recognized for all generating facilities and mines for which TransAlta is legally, or constructively, required to remove the facilities at the end of their useful lives and restore the sites to their original condition. TransAlta estimates that the undiscounted amount of cash flow required to settle these obligations is approximately $1 billion , which will be incurred between 2019 and 2073. The majority of the costs will be incurred between 2020 and 2050. At Dec. 31, 2018 , the Corporation had provided a surety bond in the amount of US $139 million ( 2017 - US $139 million ) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2018 , the Corporation had provided letters of credit in the amount of $122 million ( 2017 - $120 million ) in support of future decommissioning obligations at the Alberta mine. Some of the facilities that are co-located with mining operations do not currently have any decommissioning obligations recorded as the obligations associated with the facilities are indeterminate at this time.

B. Other Provisions

Other provisions include amounts related to a portion of the Corporation’s fixed price commitments under several natural gas transportation contracts for firm transportation that is not expected to be used and for vacant leased premises.

TRANSALTA CORPORATION F 69

Notes to Consolidated Financial Statements

Accordingly, the unavoidable costs of meeting these obligations exceed the economic benefits expected to be received. The contracts extend to 2023.

Other provisions also include provisions arising from ongoing business activities and include amounts related to commercial disputes between the Corporation and customers or suppliers. Information about the expected timing of settlement and uncertainties that could impact the amount or timing of settlement has not been provided as this may impact the Corporation’s ability to settle the provisions in the most favourable manner.

22 . Credit Facilities, Long-Term Debt and Finance Lease Obligations

A. Amounts Outstanding

The amounts outstanding are as follows:



As at Dec. 31	2018					2017
	Carrying value		Face value	Interest ⁽¹⁾		Carrying value		Face value	Interest ⁽¹⁾
Credit facilities ⁽²⁾	339		339	3.8	%	27		27	2.8	%
Debentures	647		651	5.8	%	1,046		1,051	6.0	%
Senior notes ⁽³⁾	943		955	5.4	%	1,499		1,510	6.0	%
Non-recourse ⁽⁴⁾	1,236		1,250	4.4	%	1,022		1,032	4.3	%
Other ⁽⁵⁾	39		39	9.2	%	44		44	9.2	%
	3,204		3,234			3,638		3,664
Finance lease obligations	63					69
	3,267					3,707
Less: current portion of long-term debt	(130	)				(729	)
Less: current portion of finance lease obligations	(18	)				(18	)
Total current long-term debt and finance lease obligations	(148	)				(747	)
Total credit facilities, long-term debt and finance lease obligations	3,119					2,960

(1) Interest is an average rate weighted by principal amounts outstanding before the effect of hedging.

(2) Composed of bankers’ acceptances and other commercial borrowings under long-term committed credit facilities.

(3) US face value at Dec. 31, 2018 - US $0.7 billion ( Dec. 31, 2017 - US $1.2 billion ).

(4) Includes US $1 million at Dec. 31, 2018 ( Dec. 31, 2017 - US $27 million ).

(5) Includes US $21 million at Dec. 31, 2018 ( Dec. 31, 2017 - US $24 million ) of tax equity financing.

Credit facilities are comprised of the Corporation's $1.25 billion committed syndicated bank credit facility expiring in 2022, TransAlta Renewable's $500 million committed syndicated bank credit facility expiring in 2022 and the Corporation's three bilateral credit facilities totalling $240 million expiring in 2020. The $1.75 billion ( Dec. 31, 2017 - $1.5 billion ) committed syndicated bank facilities are the primary source for short-term liquidity after the cash flow generated from the Corporation's business. Interest rates on the credit facilities vary depending on the option selected - Canadian prime, bankers' acceptances, US LIBOR, or US base rate - in accordance with a pricing grid that is standard for such facilities.

During 2018, the Corporation's US $200 million committed facility was cancelled and the Corporation's committed syndicated bank credit facility was increased by $250 million .

During 2017:

▪

TransAlta Renewables entered into a syndicated credit agreement giving it access to a $500 million committed credit facility. The agreement is fully committed for four years. Interest rates on the credit facilities vary depending on the option selected - Canadian prime, bankers' acceptances, US LIBOR, or US base rate - in accordance with a pricing grid that is standard for such facilities. The facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. In conjunction with the credit agreement, the $350 million credit facility provided by TransAlta was cancelled.

The Corporation has a total of $2.0 billion ( Dec. 31, 2017 - $2.0 billion ) of committed credit facilities, including TransAlta Renewables’ credit facility of $0.5 billion ( Dec. 31, 2017 - $0.5 billion ). In total, $0.9 billion ( Dec. 31, 2017 - $1.4 billion ) is not drawn. At Dec. 31, 2018 , the $1.1 billion ( Dec. 31, 2017 - $627 million ) of credit utilized under these facilities was comprised of actual drawings of $339 million ( Dec. 31, 2017 - $27 million ) and letters of credit of $720 million ( Dec. 31,

TRANSALTA CORPORATION F 70

Notes to Consolidated Financial Statements

2017 - $677 million ). The Corporation is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. In addition to the $0.9 billion available under the credit facilities, the Corporation also has $89 million of available cash and cash equivalents and $35 million ($ 27 million principal portion) in cash restricted for repayment of the OCP bonds (see section E below).

Debentures bear interest at fixed rates ranging from 5.0 per cent to 7.3 per cent and have maturity dates ranging from 2020 to 2030.

On Aug. 2, 2018, the Corporation early redeemed all of its outstanding 6.40 per cent debentures, which were due Nov. 18, 2019, for the principal amount of $400 million . The redemption price was $425 million in aggregate, including a $19 million prepayment premium recognized in net interest expense and $6 million in accrued and unpaid interest to the redemption date.

Senior notes bear interest at rates ranging from 4.5 per cent to 6.5 per cent and have maturity dates ranging from 2022 to 2040.

During 2018, the Corporation early redeemed its outstanding 6.650 per cent US $500 million senior notes due May 15, 2018. The repayment was hedged with foreign exchange forwards and cross currency swaps. The redemption price for the notes was approximately $617 million (US $516 million ), including a $5 million early redemption premium, recognized in net interest expense, and $14 million in accrued and unpaid interest to the redemption date.

During 2017 , the Corporation's US $400 million 1.90 per cent senior note matured and was paid out using existing liquidity. The repayment was hedged with a currency swap. The maturity value of the bond was $434 million .

A total of US $400 million ( 2017 - US $480 million ) of the senior notes has been designated as a hedge of the Corporation’s net investment in US foreign operations.

Non-recourse debt consists of bonds and debentures that have maturity dates ranging from 2023 to 2033 and bear interest at rates ranging from 2.95 per cent to 6.26 per cent.

During 2018, the Corporation:


▪	Paid out the US $25 million non-recourse debt related to its Mass Solar projects.


▪	Monetized the OCA and closed a $345 million bond offering through its indirect wholly owned subsidiary TransAlta OCP by way of private placement. The non-recourse amortizing bonds bear interest from their date of issuance at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030.

During 2017, TransAlta Renewables closed a $260 million non-recourse bond offering by way of a private placement. At the same time, the Corporation early redeemed the $191 million face value CHD non-recourse debentures on Oct. 12, 2017. The redemption price was $201 million , including an early redemption premium of $6 million , recognized in net interest expense and accrued and unpaid interest of $4 million .

Other consists of an unsecured commercial loan obligation that bears interest at 5.9 per cent and matures in 2023, requiring annual payments of interest and principal, and tax equity financing assumed in the Lakeswind wind acquisition.

TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2018 , the Corporation was in compliance with all debt covenants.

B. Restrictions on Non-Recourse Debt

The Melancthon Wolfe Wind, Pingston, TAPC Holdings LP, New Richmond, KHWLP and OCP non-recourse bonds with a carrying value of $1,235 million ( Dec. 31, 2017 - $1,022 million ) are subject to customary financing conditions and covenants that may restrict the Corporation’s ability to access funds generated by the facilities’ operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the fourth quarter. However, funds in these entities that have accumulated since the fourth quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2019 . At Dec. 31, 2018 , $33 million ( Dec. 31, 2017 - $35 million ) of cash was subject to these financial restrictions.

TRANSALTA CORPORATION F 71

Notes to Consolidated Financial Statements

C. Security

Non-recourse debts of $766 million in total ( Dec. 31, 2017 - $848 million ) are each secured by a first ranking charge over all of the respective assets of the Corporation’s subsidiaries that issued the bonds, which includes certain renewable generation facilities with total carrying amounts of $1,021 million at Dec. 31, 2018 ( Dec. 31, 2017 - $1,107 million ). At Dec. 31, 2018 , a non-recourse bond of approximately $127 million ( Dec. 31, 2017 - $174 million ) was secured by a first ranking charge over the equity interests of the issuer that issued the non-recourse bond.

The new TransAlta OCP bonds with a carrying value of $342 million are secured by the assets of TransAlta OCP, including the right to annual capital contributions and OCA payments from the Government of Alberta. Under the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million , net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030.

D. Principal Repayments



	2019	2020	2021	2022	2023	2024 and thereafter	Total
Principal repayments ⁽¹⁾	130	486	91	947	141	1,439	3,234

(1) Excludes impact of derivatives.

E. Restricted Cash

The Corporation has $ 31 million ( Dec. 31, 2017 - $30 million ) of restricted cash related to the Kent Hills project financing that is held in a construction reserve account. The proceeds will be released from the construction reserve account upon certain conditions being met, which are expected to be finalized in Q1 2019.

The Corporation also has $35 million ( Dec. 31, 2017 - nil ) of restricted cash related to the TransAlta OCP bonds, which is required to be held in a debt service reserve account to fund the next scheduled debt repayment in February 2019.

F. Finance Lease Obligations

Amounts payable for mining assets and other finance leases are as follows:



As at Dec. 31	2018		2017
	Minimum lease payments	Present value of minimum lease payments	Minimum lease payments	Present value of minimum lease payments
Within one year	21	20	20	20
Second to fifth years inclusive	39	35	43	38
More than five years	10	8	15	11
	70	63	78	69
Less: interest costs	7	—	9	—
Total finance lease obligations	63	63	69	69

Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease obligations	18		18
Long-term portion of finance lease obligations	45		51
	63		69

G. Letters of Credit

Letters of credit issued by TransAlta are drawn on its committed syndicated credit facility, its $240 million bilateral committed credit facilities and its uncommitted $100 million demand letter of credit facility. Letters of credit issued by TransAlta Renewables are drawn on its uncommitted $100 million demand letter of credit facility.

TRANSALTA CORPORATION F 72

Notes to Consolidated Financial Statements

Letters of credit are issued to counterparties under various contractual arrangements with the Corporation and certain subsidiaries of the Corporation. If the Corporation or its subsidiary does not perform under such contracts, the counterparty may present its claim for payment to the financial institution through which the letter of credit was issued. Any amounts owed by the Corporation or its subsidiaries under these contracts are reflected in the Consolidated Statements of Financial Position. All letters of credit expire within one year and are expected to be renewed, as needed, in the normal course of business. The total outstanding letters of credit as at Dec. 31, 2018 , was $720 million ( 2017 - $677 million ) with no ( 2017 - nil ) amounts exercised by third parties under these arrangements.

23 . Defined Benefit Obligation and Other Long-Term Liabilities

The components of defined benefit obligation and other long-term liabilities are as follows:



As at Dec. 31	2018	2017
Defined benefit obligation (Note 28)	227	235
Long-term incentive accruals (Note 27)	9	16
Other	51	46
Total ⁽¹⁾	287	297

(1) 2017 deferred revenues of $62 million have been reclassified on the statement of financial position to contract liabilities as required under IFRS 15. See Note 3(A) and Note 5(B) for further details.

24 . Common Shares

A. Issued and Outstanding

TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.



As at Dec. 31	2018				2017
	Common shares (millions)		Amount		Common shares (millions)	Amount
Issued and outstanding, beginning of year	287.9		3,094		287.9	3,095
Purchased and cancelled under the NCIB	(3.3	)	(35	)	—	—
	284.6		3,059		287.9	3,095
Amounts receivable under Employee Share Purchase Plan	—		—		—	(1	)
Issued and outstanding, end of year	284.6		3,059		287.9	3,094

B. NCIB Program

Shares purchased by the Corporation under the NCIB are recognized as a reduction to share capital equal to the average carrying value of the common shares. Any difference between the aggregate purchase price and the average carrying value of the common shares is recorded in retained earnings.

The following are the effects of the Corporation's purchase and cancellation of the common shares during the year ended Dec. 31, 2018 :



Total shares purchased ⁽¹⁾	3,264,500
Average purchase price per share	$	7.02
Total cost	23
Weighted average book value of shares cancelled	35
Increase to retained earnings	12

(1) Includes 204,000 shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date.

C. Shareholder Rights Plan

The Corporation initially adopted the Shareholder Rights Plan in 1992, which has been revised since that time to ensure conformity with current practices. As required, the Shareholder Rights Plan must be put before the Corporation’s

TRANSALTA CORPORATION F 73

Notes to Consolidated Financial Statements

shareholders every three years for approval, and it was last approved on April 22, 2016. The primary objective of the Shareholder Rights Plan is to provide the Board sufficient time to explore and develop alternatives for maximizing shareholder value if a takeover bid is made for the Corporation and to provide every shareholder with an equal opportunity to participate in such a bid. When an acquiring shareholder acquires 20 per cent or more of the Corporation’s common shares, other than by way of a “permitted bid” or a "competing permitted bid" (as defined in the Shareholder Rights Plan), where the offer is made to all shareholders by way of a takeover bid circular, the rights granted under the Shareholder Rights Plan become exercisable by all shareholders except those held by the acquiring shareholder. Each right will entitle a shareholder, other than the acquiring shareholder, to acquire an additional $200 worth of common shares for $100 .

D. Earnings per Share



Year ended Dec. 31	2018		2017		2016
Net earnings (loss) attributable to common shareholders	(248	)	(190	)	117
Basic and diluted weighted average number of common shares outstanding (millions)	287		288		288
Net earnings (loss) per share attributable to common shareholders, basic and diluted	(0.86	)	(0.66	)	0.41

E. Dividends

On Oct. 10, 2018, the Corporation declared a quarterly dividend of $0.04 per common share, payable on Jan. 1, 2019.

On Dec. 14, 2018, the Corporation declared a quarterly dividend of $0.04 per common share, payable on Apr. 1, 2019.

There have been no other transactions involving common shares between the reporting date and the date of completion of these consolidated financial statements.

25 . Preferred Shares

A. Issued and Outstanding

All preferred shares issued and outstanding are non-voting cumulative redeemable fixed rate first preferred shares.



As at Dec. 31	2018		2017
Series	Number of shares (millions)	Amount	Number of shares (millions)	Amount
Series A	10.2	248	10.2	248
Series B	1.8	45	1.8	45
Series C	11.0	269	11.0	269
Series E	9.0	219	9.0	219
Series G	6.6	161	6.6	161
Issued and outstanding, end of year	38.6	942	38.6	942

I. Series E Cumulative Redeemable Rate Reset Preferred Shares Conversion

On Sept. 17, 2017, the Corporation announced that, after taking into account all election notices received by the Sept. 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series E (the “Series E Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series F (the “Series F Shares”), there were 133,969 Series E Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series F Shares. Therefore, none of the Series E Shares were converted into Series F Shares on Sept. 30, 2017. As a result, the Series E Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series E Shares for the five-year period from and including Sept. 30, 2017, to, but excluding, Sept. 30, 2022, will be 5.194 per cent, which is equal to the five -year Government of Canada bond yield of 1.544 per cent, determined as of Aug. 31, 2017, plus 3.65 per cent, in accordance with the terms of the Series E Shares.

TRANSALTA CORPORATION F 74

Notes to Consolidated Financial Statements

II. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion

On June 16, 2017, the Corporation announced that after, taking into account all election notices received by the June 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series C (the “Series C Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series D (the “Series D Shares”), there were 827,628 Series C Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series D Shares. Therefore, none of the Series C Shares were converted into Series D Shares on June 30, 2017. As a result, the Series C Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series C Shares for the five-year period from and including June 30, 2017, to, but excluding, June 30, 2022, will be 4.027 per cent, which is equal to the five -year Government of Canada bond yield of 0.927 per cent, determined as of May 31, 2017, plus 3.10 per cent, in accordance with the terms of the Series C Shares.

III. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion

On March 17, 2016, the Corporation announced that 1,824,620 of its 12.0 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares (“Series A Shares”) were tendered for conversion, on a one-for-one basis, into Series B Cumulative Redeemable Floating Rate Preferred Shares (“Series B Shares”) after having taken into account all election notices. As a result of the conversion, the Corporation has 10.2 million Series A Shares and 1.8 million Series B Shares issued and outstanding at Dec. 31, 2018 .

The Series A Shares pay fixed cumulative preferential cash dividends on a quarterly basis for the five -year period from and including March 31, 2016, to, but excluding, March 31, 2021, if, as and when declared by the Board based on an annual fixed dividend rate of 2.709 per cent.

The Series B Shares pay quarterly floating rate cumulative preferential cash dividends for the five -year period from and including March 31, 2016, to, but excluding, March 31, 2021, if, as and when declared by the Board based on the 90 day Treasury Bill rate plus 2.03% .

IV. Preferred Share Series Information

The holders are entitled to receive cumulative fixed quarterly cash dividends at a specified rate, as approved by the Board. After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed rate resets to the sum of the then five -year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified spread. Upon each Rate Reset Date, they are also:


▪	Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption.

▪

Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90 -day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above.

Characteristics specific to each first preferred share series as at Dec. 31, 2018 , are as follows:



Series	Rate during term	Annual dividend rate per share ($)	Next conversion date	Rate spread over Benchmark (per cent)	Convertible to Series
A	Fixed	0.67725	March 31, 2021	2.03	B
B	Floating	0.93575	March 31, 2021	2.03	A
C	Fixed	1.00675	June 30, 2022	3.10	D
D	Floating	—	—	3.10	C
E	Fixed	1.29850	Sept. 30, 2022	3.65	F
F	Floating	—	—	3.65	E
G	Fixed	1.32500	Sept. 30, 2019	3.80	H
H	Floating	—	—	3.80	G

TRANSALTA CORPORATION F 75

Notes to Consolidated Financial Statements

B. Dividends

The following table summarizes the preferred share dividends declared in 2018 , 2017 and 2016 :



	Total dividends declared ($)
Series	2018	2017	2016
A	9	5	10
B	1	1	1
C	14	9	16
E	15	8	14
G	11	7	11
Total for the year	50	30	52

26 . Accumulated Other Comprehensive Income

The components of, and changes in, accumulated other comprehensive income (loss) are as follows:



	2018		2017
Currency translation adjustment
Opening balance, Jan. 1	(26	)	(1	)
Losses on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax ⁽¹⁾	84		(89	)
Gains on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax ⁽²⁾	(41	)	64
Balance, Dec. 31	17		(26	)
Cash flow hedges
Opening balance, Jan. 1	562		456
Gains on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax ⁽³⁾	(54	)	106
Balance, Dec. 31	508		562

Employee future benefits
Opening balance, Jan. 1	(44	)	(38	)
Net actuarial gains (losses) on defined benefit plans, net of tax ⁽⁴⁾	15		(6	)
Balance, Dec. 31	(29	)	(44	)
Other
Opening balance, Jan. 1	(3	)	(18	)
Change in ownership of TransAlta Renewables	4		4
Intercompany investments at FVOCI	(16	)	11
Balance, Dec. 31	(15	)	(3	)
Accumulated other comprehensive income	481		489

(1) Net of income tax of nil for the year ended Dec. 31, 2018 ( 2017 - 11 million ).

(2) Net of income tax of nil for the year ended Dec. 31, 2018 ( 2017 - 4 million ).

(3) Net of income tax of 12 million for the year ended Dec. 31, 2018 ( 2017 - 108 million ).

(4) Net of income tax of 5 million for the year ended Dec. 31, 2018 ( 2017 - 4 million ).

TRANSALTA CORPORATION F 76

Notes to Consolidated Financial Statements

27 . Share-Based Payment Plans

The Corporation has the following share-based payment plans:

A. Performance Share Unit (“PSU”) and Restricted Share Unit (“RSU”) Plan

Under the PSU and RSU Plan, grants may be made annually, but are measured and assessed over a three -year performance period. Grants are determined as a percentage of participants’ base pay and are converted to PSUs or RSUs on the basis of the Corporation’s common share price at the time of grant. Vesting of PSUs is subject to achievement over a three -year period of two to three performance measures that are established at the time of each grant. RSUs are subject to a three -year cliff-vesting requirement. RSUs and PSUs track the Corporation’s share price over the three -year period and accrue dividends as additional units at the same rate as dividends paid on the Corporation’s common shares. The Human Resources Committee of the Board has the discretion to determine whether payments on settlement are made through purchase of shares on the open market or in cash. The expense related to this plan is recognized during the period earned, with the corresponding payable recorded in liabilities. The liability is valued at the end of each reporting period using the closing price of the Corporation’s common shares on the TSX.

The pre-tax compensation expense related to PSUs and RSUs in 2018 was $8 million ( 2017 - $15 million , 2016 - $17 million ), which is included in operations, maintenance and administration expense in the Consolidated Statements of Earnings (Loss).

B. Deferred Share Unit (“DSU”) Plan

Under the DSU Plan, members of the Board and executives may, at their option, purchase DSUs using certain components of their fees or pay. A DSU is a notional share that has the same value as one common share of the Corporation and fluctuates based on the changes in the value of the Corporation’s common shares in the marketplace. DSUs accrue dividends as additional DSUs at the same rate as dividends are paid on the Corporation’s common shares. DSUs are redeemable in cash and may not be redeemed until the termination or retirement of the director or executive from the Corporation.

The Corporation accrues a liability and expense for the appreciation in the common share value in excess of the DSU’s purchase price and for dividend equivalents earned. The pre-tax compensation expense related to the DSUs was nil in 2018 ( 2017 - $1 million , 2016 - $3 million ).

C. Stock Option Plans

The Corporation is authorized to grant options to purchase up to an aggregate of 13 million common shares at prices based on the market price of the shares on the TSX as determined on the grant date. The plan provides for grants of options to all full-time employees, including executives, designated by the Human Resources Committee from time to time.

In February 2018, the Corporation granted executive officers of the Corporation a total of 0.7 million stock options with an exercise price of $7.45 that vest after a three -year period and expire seven years after issuance. In March 2017, the Corporation granted executive officers of the Corporation a total of 0.7 million stock options with an exercise price of $7.25 that vest after a three -year period and expire seven years after issuance. In February 2016, the Corporation granted executive officers of the Corporation a total of 1.1 million stock options with an exercise price of $5.93 that vest after a three -year period and expire seven years after issuance. The expense recognized relating to these grants during 2018 was approximately $1 million ( 2017 - approximately $1 million , 2016 - less than $1 million ).

The total options outstanding and exercisable under these stock option plans at Dec. 31, 2018 , are outlined below:



	Options outstanding
Range of exercise prices ($ per share)	Number of options (millions)	Weighted average remaining contractual life (years)	Weighted average exercise price ($ per share)
5.00 - 8.00	2.3	5	6.71
22.00 - 30.00 ⁽¹⁾	0.5	1.1	23.69
5.00 - 30.00	2.8	4.3	9.66

(1) Options currently exercisable.

TRANSALTA CORPORATION F 77

Notes to Consolidated Financial Statements

D. Employee Share Purchase Plan

Under the terms of the employee share purchase plan, the Corporation extended interest-free loans (up to 30 per cent of an employee’s base salary) to employees below executive level and allowed for payroll deductions over a three -year period to repay the loan. Executives were not eligible for this program in accordance with the Sarbanes-Oxley legislation. An agent purchased these common shares on the open market on behalf of employees at prices based on the market price of the shares as determined on the date of purchase. Employee sales of these shares were handled in the same manner. At Dec. 31, 2018 , amounts receivable from employees under the plan was nil ( 2017 - less than $1 million ).

On Jan. 14, 2016, the Corporation suspended its employee share purchase plan.

28 . Employee Future Benefits

A. Description

The Corporation sponsors registered pension plans in Canada and the US covering substantially all employees of the Corporation in these countries and specific named employees working internationally. These plans have defined benefit and defined contribution options, and in Canada there is an additional non-registered supplemental plan for eligible employees whose annual earnings exceed the Canadian income tax limit. Except for the Highvale pension plan acquired in 2013, the Canadian and US defined benefit pension plans are closed to new entrants. The US defined benefit pension plan was frozen effective Dec. 31, 2010, resulting in no future benefits being earned. The supplemental pension plan was closed as of Dec. 31, 2015, and a new defined contribution supplemental pension plan commenced for executive members effective Jan. 1, 2016. Current executives as of Dec .31, 2015, were grandfathered into the old supplemental plan.

The latest actuarial valuation for accounting purposes of the US pension plan was at Jan. 1, 2018. The latest actuarial valuation for accounting purposes of the Highvale and Canadian pension plans was at Dec. 31, 2016. The measurement date used for all plans to determine the fair value of plan assets and the present value of the defined benefit obligation was Dec. 31, 2018 .

Funding of the registered pension plans complies with applicable regulations that require actuarial valuations of the pension funds at least once every three years in Canada, or more, depending on funding status, and every year in the US. The supplemental pension plan is solely the obligation of the Corporation. The Corporation is not obligated to fund the supplemental plan but is obligated to pay benefits under the terms of the plan as they come due. The Corporation posted a letter of credit in March 2018 for the amount of $80 million to secure the obligations under the supplemental plan.

The Corporation provides other health and dental benefits to the age of 65 for both disabled members and retired members through its other post-employment benefits plans. The latest actuarial valuations for accounting purposes of the Canadian and US plans were as at Dec. 31, 2016, and Jan. 1, 2018, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2018 .

The Corporation provides several defined contribution plans, including an Australian superannuation plan and a US 401(k) savings plan, that provide for company contributions from 5 per cent to 10 per cent, depending on the plan. Optional employee contributions are allowed for all the defined contribution plans.

TRANSALTA CORPORATION F 78

Notes to Consolidated Financial Statements

B. Costs Recognized

The costs recognized in net earnings during the year on the defined benefit, defined contribution and other post-employment benefits plans are as follows:



Year ended Dec. 31, 2018	Registered		Supplemental	Other	Total
Current service cost	9		2	1	12
Administration expenses	1		—	—	1
Interest cost on defined benefit obligation	18		3	1	22
Interest on plan assets	(13	)	—	—	(13	)
Defined benefit expense	15		5	2	22
Defined contribution expense	10		—	—	10
Net expense	25		5	2	32

Year ended Dec. 31, 2017	Registered		Supplemental	Other	Total
Current service cost	7		2	1	10
Administration expenses	2		—	—	2
Interest cost on defined benefit obligation	20		3	1	24
Interest on plan assets	(15	)	—	—	(15	)
Defined benefit expense	14		5	2	21
Defined contribution expense	11		—	—	11
Net expense	25		5	2	32



Year ended Dec. 31, 2016	Registered		Supplemental	Other	Total
Current service cost	7		2	2	11
Administration expenses	2		—	—	2
Interest cost on defined benefit obligation	21		3	1	25
Interest on plan assets	(16	)	—	—	(16	)
Defined benefit expense	14		5	3	22
Defined contribution expense	15		—	—	15
Net expense	29		5	3	37

TRANSALTA CORPORATION F 79

Notes to Consolidated Financial Statements

C. Status of Plans

The status of the defined benefit pension and other post-employment benefit plans is as follows:



As at Dec. 31, 2018	Registered		Supplemental		Other		Total
Fair value of plan assets	368		13		—		381
Present value of defined benefit obligation	(514	)	(80	)	(25	)	(619	)
Funded status - plan deficit	(146	)	(67	)	(25	)	(238	)
Amount recognized in the consolidated financial statements:
Accrued current liabilities	(5	)	(5	)	(1	)	(11	)
Other long-term liabilities	(141	)	(62	)	(24	)	(227	)
Total amount recognized	(146	)	(67	)	(25	)	(238	)

As at Dec. 31, 2017	Registered		Supplemental		Other		Total
Fair value of plan assets	416		12		—		428
Present value of defined benefit obligation	(561	)	(87	)	(27	)	(675	)
Funded status - plan deficit	(145	)	(75	)	(27	)	(247	)
Amount recognized in the consolidated financial statements:
Accrued current liabilities	(4	)	(6	)	(2	)	(12	)
Other long-term liabilities	(141	)	(69	)	(25	)	(235	)
Total amount recognized	(145	)	(75	)	(27	)	(247	)

D. Plan Assets

The fair value of the plan assets of the defined benefit pension and other post-employment benefit plans is as follows:



	Registered		Supplemental		Other		Total
As at Dec. 31, 2016	423		10		—		433
Interest on plan assets	15		—		—		15
Net return on plan assets	26		—		—		26
Contributions	6		6		—		12
Benefits paid	(51	)	(4	)	—		(55	)
Administration expenses	(2	)	—		—		(2	)
Effect of translation on US plans	(1	)	—		—		(1	)
As at Dec. 31, 2017	416		12		—		428
Interest on plan assets	13		—		—		13
Net return on plan assets	(25	)	—		—		(25	)
Contributions	5		6		1		12
Benefits paid	(42	)	(5	)	(1	)	(48	)
Administration expenses	(1	)	—		—		(1	)
Effect of translation on US plans	2		—		—		2
As at Dec. 31, 2018	368		13		—		381

TRANSALTA CORPORATION F 80

Notes to Consolidated Financial Statements

The fair value of the Corporation’s defined benefit plan assets by major category is as follows:



Year ended Dec. 31, 2018	Level I		Level II	Level III	Total
Equity securities
Canadian	—		65	—	65
US	—		26	—	26
International	—		101	—	101
Private	—		—	1	1
Bonds
AAA	—		48	—	48
AA	—		64	—	64
A	—		39	—	39
BBB	1		21	—	22
Below BBB	—		3	—	3
Money market and cash and cash equivalents	(2	)	14	—	12
Total	(1	)	381	1	381



Year ended Dec. 31, 2017	Level I		Level II	Level III	Total
Equity securities
Canadian	—		76	—	76
US	—		31	—	31
International	—		118	—	118
Private	—		—	1	1
Bonds
AAA	—		43	—	43
AA	—		71	—	71
A	—		44	—	44
BBB	1		25	—	26
Below BBB	—		5	—	5
Money market and cash and cash equivalents	(1	)	14	—	13
Total	—		427	1	428

Plan assets do not include any common shares of the Corporation at Dec. 31, 2018 , and Dec. 31, 2017 . The Corporation charged the registered plan $0.1 million for administrative services provided for the year ended Dec. 31, 2018 ( 2017 - $0.1 million ).

TRANSALTA CORPORATION F 81

Notes to Consolidated Financial Statements

E. Defined Benefit Obligation

The present value of the obligation for the defined benefit pension and other post-employment benefit plans is as follows:



	Registered		Supplemental		Other		Total
Present value of defined benefit obligation as at Dec. 31, 2016	554		82		27		663
Current service cost	7		2		1		10
Interest cost	20		3		1		24
Benefits paid	(51	)	(4	)	—		(55	)
Actuarial gain arising from demographic assumptions	4		1		—		5
Actuarial loss arising from financial assumptions	26		3		—		29
Actuarial gain (loss) arising from experience adjustments	3		—		(1	)	2
Effect of translation on US plans	(2	)	—		(1	)	(3	)
Present value of defined benefit obligation as at Dec. 31, 2017	561		87		27		675
Current service cost	9		2		1		12
Interest cost	18		3		1		22
Benefits paid	(42	)	(5	)	(1	)	(48	)
Actuarial (gain) loss arising from financial assumptions	(35	)	(7	)	(2	)	(44	)
Actuarial (gain) loss arising from experience adjustments	—		—		(1	)	(1	)
Effect of translation on US plans	3		—		—		3
Present value of defined benefit obligation as at Dec. 31, 2018	514		80		25		619

The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2018 is 14 years.

F. Contributions

The expected employer contributions for 2019 for the defined benefit pension and other post-employment benefit plans are as follows:



	Registered	Supplemental	Other	Total
Expected employer contributions	5	4	2	11

TRANSALTA CORPORATION F 82

Notes to Consolidated Financial Statements

G. Assumptions

The significant actuarial assumptions used in measuring the Corporation’s defined benefit obligation for the defined benefit pension and other post-employment benefit plans are as follows:



	As at Dec. 31, 2018			As at Dec. 31, 2017
(per cent)	Registered	Supplemental	Other	Registered	Supplemental	Other
Accrued benefit obligation
Discount rate	3.9	3.8	3.9	3.3	3.3	3.4
Rate of compensation increase	2.5	3.0	—	2.9	3.0	—
Assumed health care cost trend rate
Health care cost escalation ⁽¹⁾⁽³⁾	—	—	7.1	—	—	7.8
Dental care cost escalation	—	—	4.0	—	—	4.0
Benefit cost for the year
Discount rate	3.3	3.3	3.4	3.7	3.6	3.7
Rate of compensation increase	2.6	3.0	—	2.6	3.0	—
Assumed health care cost trend rate
Health care cost escalation ⁽²⁾⁽⁴⁾	—	—	7.6	—	—	7.9
Dental care cost escalation	—	—	4.0	—	—	4.0
Provincial health care premium escalation	—	—	—	—	—	—

(1) 2018 Post- and pre- 65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2027 for Canada.

(2) 2018 Post- and pre- 65 rates: decreasing gradually to 4.5% by 2027 and remaining at that level thereafter for the US and decreasing gradually by 0.30% per year to 4.5% in 2027 for Canada.

(3) 2017 Post- and pre- 65 rates: decreasing gradually to 4.5% by 2027 and remaining at that level thereafter for the US and decreasing gradually by 0.30% per year to 4.5% in 2027 for Canada.

(4) 2017 Post- and pre- 65 rates: decreasing gradually to 4.5% by 2026 and remaining at that level thereafter for the US and decreasing gradually by 0.30% per year to 5% in 2024 for Canada.

H. Sensitivity Analysis

The following table outlines the estimated increase in the net defined benefit obligation assuming certain changes in key assumptions:



	Canadian plans			US plans
Year ended Dec. 31, 2018	Registered	Supplemental	Other	Pension	Other
1% decrease in the discount rate	70	11	3	2	1
1% increase in the salary scale	10	1	—	—	—
1% increase in the health care cost trend rate	—	—	2	—	—
10% improvement in mortality rates	18	3	—	1	—

TRANSALTA CORPORATION F 83

Notes to Consolidated Financial Statements

29 . Joint Arrangements

Joint arrangements at Dec. 31, 2018 , included the following:



Joint operations	Segment	Ownership (per cent)	Description
Sheerness	Coal	50	Coal-fired plant in Alberta, of which TA Cogen has a 50 per cent interest, operated by ATCO Power
Genesee Unit 3	Coal	50	Coal-fired plant in Alberta operated by Capital Power Corporation
Keephills Unit 3	Coal	50	Coal-fired plant in Alberta operated by TransAlta
Goldfields Power	Gas	50	Gas-fired plant in Australia operated by TransAlta
Fort Saskatchewan	Gas	60	Cogeneration plant in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta
Fortescue River Gas Pipeline	Gas	43	Natural gas pipeline in Western Australia, operated by DBP Development Group
McBride Lake	Wind	50	Wind generation facility in Alberta operated by TransAlta
Soderglen	Wind	50	Wind generation facility in Alberta operated by TransAlta
Pingston	Hydro	50	Hydro facility in British Columbia operated by TransAlta

30 . Cash Flow Information

A. Change in Non-Cash Operating Working Capital



Year ended Dec. 31	2018		2017		2016
(Use) source:
Accounts receivable	58		(228	)	(23	)
Prepaid expenses	19		(75	)	5
Income taxes receivable	—		8		(4	)
Inventory	(21	)	(7	)	11
Accounts payable, accrued liabilities, and provisions	(97	)	186		81
Income taxes payable	(3	)	2		3
Change in non-cash operating working capital	(44	)	(114	)	73

B. Changes in Liabilities from Financing Activities



	Balance Dec. 31, 2017	Net cash flows		New leases	Dividends declared	Foreign exchange impact	Other		Balance Dec. 31, 2018
Long-term debt and finance lease obligations	3,707	(540	)	10	—	95	(5	)	3,267
Dividends payable (common and preferred)	34	(86	)	—	107	—	3		58
Total liabilities from financing activities	3,741	(626	)	10	107	95	(2	)	3,325



	Balance Dec. 31, 2016	Net cash flows		New leases	Dividends declared	Foreign exchange impact		Other		Balance Dec. 31, 2017
Long-term debt and finance lease obligations	4,361	(545	)	14	—	(115	)	(8	)	3,707
Dividends payable (common and preferred)	54	(86	)	—	64	—		2		34
Total liabilities from financing activities	4,415	(631	)	14	64	(115	)	(6	)	3,741

TRANSALTA CORPORATION F 84

Notes to Consolidated Financial Statements

31 . Capital

TransAlta’s capital is comprised of the following:



As at Dec. 31	2018		2017		Increase/ (decrease)
Long-term debt ⁽¹⁾	3,267		3,707		(440	)
Equity
Common shares	3,059		3,094		(35	)
Preferred shares	942		942		—
Contributed surplus	11		10		1
Deficit	(1,496	)	(1,209	)	(287	)
Accumulated other comprehensive income	481		489		(8	)
Non-controlling interests	1,137		1,059		78
Less: available cash and cash equivalents ⁽²⁾	(89	)	(314	)	225
Less: principal portion of restricted cash on OCP Bonds ⁽³⁾	(27	)	—		(27	)
Less: fair value asset of hedging instruments on long-term debt ⁽⁴⁾	(10	)	(30	)	20
Total capital	7,275		7,748		(473	)

(1) Includes finance lease obligations, amounts outstanding under credit facilities, tax equity liability and current portion of long-term debt.

(2) The Corporation includes available cash and cash equivalents as a reduction in the calculation of capital, as capital is managed internally and evaluated by management using a net debt position. In this regard, these funds may be available and used to facilitate repayment of debt.

(3) The Corporation includes the principal portion of restricted cash on OCP bonds because this cash is restricted specifically to repay outstanding debt.

(4) The Corporation includes the fair value of economic and designated hedging instruments on debt in an asset, or liability, position as a reduction, or increase, in the calculation of capital, as the carrying value of the related debt has either increased, or decreased, due to changes in foreign exchange rates.

In 2018 , the Corporation continued to focus on reducing overall debt. The Corporation’s overall capital management strategy and its objectives in managing capital have remained unchanged from Dec. 31, 2017 , and are as follows:

A. Maintain an Investment Grade Credit Rating

The Corporation operates in a long-cycle and capital-intensive commodity business, and it is therefore a priority to maintain an investment grade credit rating as it allows the Corporation to access capital markets at reasonable interest rates. Key rating agencies assess TransAlta’s credit rating using a variety of methodologies, including financial ratios. These methodologies and ratios are not publicly disclosed. TransAlta’s management has developed its own definitions of metrics, ratios and targets to manage the Corporation’s capital. These metrics and ratios are not defined under IFRS, and may not be comparable to those used by other entities or by rating agencies.

The Corporation has an investment grade credit rating from Standard & Poor's (negative outlook), DBRS (stable outlook) and Fitch Ratings (stable outlook). In December 2015, Moody's downgraded the Corporation below investment grade to Ba1 with a stable outlook and in June 2018 Moody’s revised their rating outlook to positive from stable. During 2018, Fitch Ratings reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating of BBB- with a stable outlook; DBRS Limited reaffirmed the Corporation’s Unsecured Debt rating and Medium-Term Notes rating of BBB (low), the Preferred Shares rating of Pfd-3 (low), and Issuer Rating of BBB (low) with a stable outlook; and Standard and Poor’s reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating of BBB- with negative outlook. The Corporation is focused on strengthening its financial position and cash flow coverage ratios to achieve stable investment grade credit ratings. Credit ratings provide information relating to the Corporation's financing costs, liquidity and operations and affect the Corporation's ability to obtain short-term and long-term financing and/or the cost of such financing. Strengthening the Corporation’s financial position allows its commercial team to contract the Corporation’s portfolio with a variety of counterparties on terms and prices that are favourable to the Corporation’s financial results and provides the Corporation with better access to capital markets through commodity and credit cycles.

TRANSALTA CORPORATION F 85

Notes to Consolidated Financial Statements



As at Dec. 31	2018	2017	Target
Funds from operations before interest to adjusted interest coverage (times)	4.8	4.3	4 to 5
Adjusted funds from operations to adjusted net debt (%)	20.8	20.4	20 to 25
Adjusted net debt to comparable earnings before interest, taxes, depreciation and amortization (times)	3.7	3.6	3.0 to 3.5

Funds from Operations (“FFO”) before Interest to Adjusted Interest Coverage is calculated as FFO plus interest on debt (net of capitalized interest) divided by interest on debt plus 50 per cent of dividends paid on preferred shares. FFO is calculated as cash flow from operating activities before changes in working capital and is adjusted for transactions and amounts that the Corporation believes are not representative of ongoing cash flows from operations. The Corporation’s goal is to maintain this ratio in a range of four to five times.

Adjusted FFO to Adjusted Net Debt is calculated as FFO less 50 per cent of dividends paid on preferred shares divided by net debt (current and long-term debt plus 50 per cent of outstanding preferred shares less available cash and cash equivalents and including fair value assets of hedging instruments on debt). The Corporation’s goal is to maintain this ratio in a range of 20 to 25 per cent.

Adjusted Net Debt to Comparable Earnings before Interest, Taxes, Depreciation and Amortization (“EBITDA”) is calculated as net debt divided by comparable EBITDA. Comparable EBITDA is calculated as earnings before interest, taxes, depreciation and amortization and is adjusted for transactions and amounts that the Corporation believes are not representative of ongoing business operations. The Corporation’s goal is to maintain this ratio in a range of 3.0 to 3.5 times.

At times, the credit ratios may be outside of the specified target ranges while the Corporation realigns its capital structure. During 2018 , the Corporation continued to strengthen its financial position and reduce debt.

Management routinely monitors forecasted net earnings, cash flows, capital expenditures and scheduled repayment of debt with a goal of meeting the above ratio targets and to meet dividend and PP&E expenditure requirements.

B. Ensure Sufficient Cash and Credit is Available to Fund Operations, Pay Dividends, Distribute Payments to Subsidiaries’ Non-Controlling Interests, Invest in PP&E and Make Acquisitions

For the years ended Dec. 31, 2018 and 2017 , cash inflows and outflows are summarized below. The Corporation manages variations in working capital using existing liquidity under credit facilities.



Year ended Dec. 31	2018		2017		Increase (decrease)
Cash flow from operating activities	820		626		194
Change in non-cash working capital	44		114		(70	)
Cash flow from operations before changes in working capital	864		740		124
Dividends paid on common shares	(46	)	(46	)	—
Dividends paid on preferred shares	(40	)	(40	)	—
Distributions paid to subsidiaries’ non-controlling interests	(165	)	(172	)	7
Property, plant and equipment expenditures ⁽¹⁾	(277	)	(338	)	61
Inflow	336		144		192

(1) Includes growth capital associated with the South Hedland Power Station.

TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2018 , $0.9 billion ( 2017 - $1.4 billion ) of the Corporation’s available credit facilities were not drawn.

Periodically, TransAlta accesses capital markets, as required, to help fund some of these periodic net cash outflows, to maintain its available liquidity, and to maintain its capital structure and credit metrics within targeted ranges.

TRANSALTA CORPORATION F 86

Notes to Consolidated Financial Statements

32 . Related-Party Transactions

Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2018 , are as follows:



Subsidiary	Country	Ownership (per cent)	Principal activity
TransAlta Generation Partnership	Canada	100	Generation and sale of electricity
TransAlta Cogeneration, L.P.	Canada	50.01	Generation and sale of electricity
TransAlta Centralia Generation, LLC	US	100	Generation and sale of electricity
TransAlta Energy Marketing Corp.	Canada	100	Energy marketing
TransAlta Energy Marketing (U.S.), Inc.	US	100	Energy marketing
TransAlta Energy (Australia), Pty Ltd.	Australia	100	Generation and sale of electricity
TransAlta Renewables Inc.	Canada	60.9	Generation and sale of electricity

Transactions between the Corporation and its subsidiaries have been eliminated on consolidation and are not disclosed.

Transactions with Key Management Personnel

TransAlta’s key management personnel include the President and CEO and members of the senior management team that report directly to the President and CEO, and the members of the Board.

Key management personnel compensation is as follows:



Year ended Dec. 31	2018	2017	2016
Total compensation	17	24	20
Comprised of:
Short-term employee benefits	11	14	8
Post-employment benefits	2	2	2
Share-based payments	4	8	10

33 . Commitments and Contingencies

In addition to commitments disclosed elsewhere in the financial statements, the Corporation has other contractual commitments, either directly or through its interests in joint operations. Approximate future payments under these agreements are as follows:



	2019	2020	2021	2022	2023	2024 and thereafter	Total
Natural gas, transportation and other purchase contracts	28	15	13	11	12	157	236
Transmission	9	10	6	4	3	—	32
Coal supply and mining agreements	158	160	27	24	24	95	488
Long-term service agreements	64	86	32	17	8	34	241
Non-cancellable operating leases	8	8	8	7	4	45	80
Growth	324	79	144	—	—	—	547
TransAlta Energy Transition Bill	6	7	6	6	6	—	31
Total	597	365	236	69	57	331	1,655

A. Natural Gas, Transportation and Other Purchase Contracts

Several of the Corporation’s plants have fixed price natural gas purchase and related transportation contracts in place. Other purchase contracts relate to commitments for goods and services.

TRANSALTA CORPORATION F 87

Notes to Consolidated Financial Statements

B. Transmission

The Corporation has several agreements to purchase transmission network capacity in the Pacific Northwest. Provided certain conditions for delivering the service are met, the Corporation is committed to the transmission at the supplier’s tariff rate whether it is awarded immediately or delivered in the future after additional facilities are constructed.

C. Coal Supply and Mining Agreements

Various coal supply and associated rail transport contracts are in place to provide coal for use in production at the Centralia coal plant. The coal supply agreements allow TransAlta to take delivery of coal at fixed volumes with dates extending to 2020.

Commitments related to mining agreements include the Corporation’s share of commitments for mining agreements related to its Sheerness and Genesee Unit 3 joint operations, and certain other mining royalty agreements. Some of these commitments have been reduced due to the cessation of coal-fired emissions from the Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030.

D. Long-Term Service Agreements

TransAlta has various service agreements in place, primarily for inspections and repairs and maintenance that may be required on natural gas facilities, coal facilities and turbines at various wind facilities.

E. Non-Cancellable Operating Leases

TransAlta has operating leases in place for buildings, vehicles and various types of equipment.

During the year ended Dec. 31, 2018 , $8 million ( 2017 - $7 million , 2016 - $9 million ) was recognized as an expense in respect of these operating leases. Sublease payments received during 2018 , 2017 and 2016 were less than $1 million . No contingent rental payments were made in respect of these operating leases.

F. Growth

Commitments for growth relate to the Big Level, Antrim and Windrise wind development projects, the coal-to-gas conversions, and to the Corporation's 50% share of the Pioneer Pipeline project.

G. TransAlta Energy Transition Bill Commitments

On July 30, 2015, the Corporation announced that it would formalize its commitment to invest US $55 million over the remaining nine -year life of the Centralia coal plant to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State by waiving its right to terminate the commitment on the basis of the level of contract sales of the Centralia plant. As of Dec. 31, 2018 , the Corporation has funded approximately US $33 million of the commitment, which is recognized in other assets in the Consolidated Statements of Financial Position.

H. Other

A significant portion of the Corporation’s electricity and thermal production are subject to PPAs and long-term contracts. The majority of these contracts include terms and conditions customary to the industry in which the Corporation operates. The nature of commitments related to these contracts includes: electricity and thermal capacity, availability, and production targets; reliability and other plant-specific performance measures; specified payments for deliveries during peak and off-peak time periods; specified prices per MWh; risk sharing of fuel costs; and retention of heat rate risk.

I. Contingencies

TransAlta is occasionally named as a party in various claims and legal and regulatory proceedings that arise during the normal course of its business. TransAlta reviews each of these claims, including the nature of the claim, the amount in dispute or claimed, and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in the Corporation’s favour or that such claims may not have a material adverse effect on TransAlta. Inquiries from regulatory bodies may also arise in the normal course of business, to which the Corporation responds as required.

I. Line Loss Rule Proceeding

The Corporation has been participating in a line loss rule proceeding before the Alberta Utilities Commission ("AUC"). The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed the AESO to, among other things, perform such retroactive calculations. The various decisions by the AUC are, however, subject to appeal and challenge. A recent decision by the AUC determined the methodology to be used retroactively and it is now possible to estimate the total retroactive potential exposure faced by the Corporation for its non-PPA MWs. The current

TRANSALTA CORPORATION F 88

Notes to Consolidated Financial Statements

estimate of exposure based on known data is $15 million and therefore the Corporation increased the provision from $7.5 million to $15 million in 2018.

II. FMG Disputes

The Corporation is currently engaged in two disputes with Fortescue Metals Group Ltd. ("FMG"). The first arose as a result of FMG’s purported termination of the South Hedland PPA. TransAlta has sued FMG, seeking payment of amounts invoiced and not paid under the South Hedland PPA, as well as a declaration that the PPA is valid and in force. FMG, on the other hand, seeks a declaration that the PPA was lawfully terminated.

III. Balancing Pool Dispute

Pursuant to a written agreement, the Balancing Pool paid the Corporation approximately $157 million on March 29, 2018, as part of the net book value payment required on termination of the Sundance B and C PPAs. The Balancing Pool, however, excluded certain mining and corporate assets that the Corporation believes should be included in the net book value calculation, which amounts to an additional $56 million . The dispute is currently proceeding through arbitration.

34 . Segment Disclosures

A. Description of Reportable Segments

The Corporation has eight reportable segments as described in Note 1 .

B. Reported Segment Earnings (Loss) and Segment Assets

I. Earnings Information



Year ended Dec. 31, 2018	Canadian Coal		US Coal		Canadian Gas	Australian Gas	Wind and Solar		Hydro	Energy Marketing	Corporate		Total
Revenues	912		442		232	165	282		156	67	(7	)	2,249
Fuel and purchased power	666		314		96	8	17		6	—	(7	)	1,100
Gross margin	246		128		136	157	265		150	67	—		1,149
Operations, maintenance and administration	171		61		48	37	50		38	24	86		515
Depreciation and amortization	241		74		43	49	110		30	2	25		574
Asset impairment charge	38		—		—	—	12		—	—	23		73
Taxes, other than income taxes	13		5		1	—	8		3	—	1		31
Net other operating expense (income)	(198	)	—		—	—	(6	)	—	—	—		(204	)
Operating income (loss)	(19	)	(12	)	44	71	91		79	41	(135	)	160
Finance lease income	—		—		8	—	—		—	—	—		8
Net interest expense													(250	)
Foreign exchange loss													(15	)
Gain on sale of assets and other													1
Losses before income taxes													(96	)

TRANSALTA CORPORATION F 89

Notes to Consolidated Financial Statements



Year ended Dec. 31, 2017	Canadian Coal		US Coal	Canadian Gas		Australian Gas	Wind and Solar	Hydro	Energy Marketing	Corporate		Total
Revenues	999		435	261		135	287	121	69	—		2,307
Fuel and purchased power	585		293	101		14	17	6	—	—		1,016
Gross margin	414		142	160		121	270	115	69	—		1,291
Operations, maintenance and administration	192		51	50		31	48	37	24	84		517
Depreciation and amortization	317		73	38		37	111	31	2	26		635
Asset impairment charge	20		—	—		—	—	—	—	—		20
Taxes, other than income taxes	13		4	1		—	8	3	—	1		30
Net other operating expense (income)	(40	)	—	(9	)	—	—	—	—	—		(49	)
Operating income (loss)	(88	)	14	80		53	103	44	43	(111	)	138
Finance lease income	—		—	11		43	—	—	—	—		54
Net interest expense												(247	)
Foreign exchange loss												(1	)
Gain on sale of assets												2
Earnings before income taxes												(54	)



Year ended Dec. 31, 2016	Canadian Coal		US Coal		Canadian Gas		Australian Gas	Wind		Hydro	Energy Marketing	Corporate		Total
Revenues	1,048		354		402		119	272		126	76	—		2,397
Fuel and purchased power	451		281		185		20	18		8	—	—		963
Gross margin	597		73		217		99	254		118	76	—		1,434
Operations, maintenance and administration	178		54		54		25	52		33	24	69		489
Depreciation and amortization	242		61		100		17	119		33	3	26		601
Asset impairment reversals	—		—		—		—	28		—	—	—		28
Taxes, other than income taxes	13		4		1		1	8		3	—	1		31
Net other operating expense (income)	(2	)	—		(191	)	—	(1	)	—	—	1		(193	)
Operating income (loss)	166		(46	)	253		56	48		49	49	(97	)	478
Finance lease income	—		—		14		52	—		—	—	—		66
Net interest expense														(229	)
Foreign exchange loss														(5	)
Gain on sale of assets														4
Earnings before income taxes														314

Included in revenues of the Wind and Solar Segment for the year ended Dec. 31, 2018 is $16 million ( 2017 - $18 million , 2016 - $19 million ) of incentives received under a Government of Canada program in respect of power generation from qualifying wind projects.

TRANSALTA CORPORATION F 90

Notes to Consolidated Financial Statements

II. Selected Consolidated Statements of Financial Position Information



As at Dec. 31, 2018	Canadian Coal	US Coal	Canadian Gas	Australian Gas	Wind and Solar	Hydro	Energy Marketing	Corporate	Total
Goodwill	—	—	—	—	175	259	30	—	464
PP&E	2,587	332	391	554	1,799	481	1	19	6,164
Intangible assets	81	7	4	41	173	4	11	52	373

As at Dec. 31, 2017	Canadian Coal	US Coal	Canadian Gas	Australian Gas	Wind and Solar	Hydro	Energy Marketing	Corporate	Total
Goodwill	—	—	—	—	174	259	30	—	463
PP&E	2,902	370	416	606	1,764	497	1	22	6,578
Intangibles	91	7	3	42	149	3	13	56	364

III. Selected Consolidated Statements of Cash Flows Information

Additions to non-current assets are as follows:



Year ended Dec. 31, 2018	Canadian Coal	US Coal	Canadian Gas	Australian Gas	Wind and Solar	Hydro	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	101	14	21	6	117	16	—	2	277
Intangible assets	3	—	—	—	—	—	—	17	20

Year ended Dec. 31, 2017	Canadian Coal	US Coal	Canadian Gas	Australian Gas	Wind and Solar	Hydro	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	116	35	31	114	20	16	—	6	338
Intangibles	5	1	—	29	—	—	—	16	51

Year ended Dec. 31, 2016	Canadian Coal	US Coal	Canadian Gas	Australian Gas	Wind and Solar	Hydro	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	159	15	11	107	16	43	—	7	358
Intangibles	3	1	1	—	—	—	—	16	21

IV. Depreciation and Amortization on the Consolidated Statements of Cash Flows

The reconciliation between depreciation and amortization reported on the Consolidated Statements of Earnings (Loss) and the Consolidated Statements of Cash Flows is presented below:



Year ended Dec. 31	2018	2017	2016
Depreciation and amortization expense on the Consolidated Statements of Earnings (Loss)	574	635	601
Depreciation included in fuel and purchased power (Note 6)	136	73	63
Depreciation and amortization on the Consolidated Statements of Cash Flows	710	708	664

TRANSALTA CORPORATION F 91

Notes to Consolidated Financial Statements

C. Geographic Information

I. Revenues



Year ended Dec. 31	2018	2017	2016
Canada	1,573	1,663	1,828
US	511	509	450
Australia	165	135	119
Total revenue	2,249	2,307	2,397

II. Non-Current Assets



	Property, plant and equipment		Intangible assets		Other assets		Goodwill

As at Dec. 31	2018	2017	2018	2017	2018	2017	2018	2017
Canada	4,953	5,353	273	297	101	105	417	417
US	657	619	59	25	50	43	47	46
Australia	554	606	41	42	83	89	—	—
Total	6,164	6,578	373	364	234	237	464	463

D. Significant Customer

During the year ended Dec. 31, 2018 , sales to one customer represented 19 per cent of the Corporation’s total revenue ( 2017 - one customer represented 28 per cent).

TRANSALTA CORPORATION F 92

Exhibit 1

(Unaudited)

The information set out below is referred to as “unaudited” as a means of clarifying that it is not covered by the audit opinion of the independent registered public accounting firm that has audited and reported on the Consolidated Financial Statements.

To the Financial Statements of TransAlta Corporation

EARNINGS COVERAGE RATIO

The following selected financial ratio is calculated for the year ended Dec. 31, 2018 :

Earnings coverage on long-term debt supporting the Corporation’s Shelf Prospectus

0.23 times

Earnings coverage on long-term debt on a net earnings basis is equal to net earnings before interest expense and income taxes, divided by interest expense including capitalized interest.

TRANSALTA CORPORATION F 93

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use of our reports dated February 26, 2019 with respect to the Consolidated Financial Statements of TransAlta Corporation as at December 31, 2018 and 2017 and for each of the years in the three year period ended December 31, 2018 , and internal control over financial reporting as of December 31, 2018 of TransAlta Corporation, included as an exhibit to or incorporated by reference in the Annual Report (Form 40-F) for 2018 .

We also consent to the incorporation by reference in the following Registration Statements:


1.	Registration Statement (Form S-8 No. 333-72454 and No. 333-101470) pertaining to TransAlta Corporation’s Share Option Plan


2.	Registration Statement (Form F-10 No. 333-215608) pertaining to the registration of Debt and Equity Securities of TransAlta Corporation

of our reports dated February 26, 2019 , with respect to the Consolidated Financial Statements of TransAlta Corporation as at December 31, 2018 and 2017 and for each of the years in the three year period ended December 31, 2018 , and internal control over financial reporting as of December 31, 2018 of TransAlta Corporation, included as an exhibit to or incorporated by reference in the Annual Report (Form 40-F) of TransAlta Corporation for the year ended December 31, 2018 .



	/s/Ernst & Young LLP
	Chartered Professional Accountants

Calgary, Alberta

February 26, 2019

A member firm of Ernst & Young Global Limited

Exhibit 31.1

Certifications

I, Dawn L. Farrell, certify that:


1.	I have reviewed this annual report on Form 40-F of TransAlta Corporation;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;


4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and


5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.



February 26, 2019
	/s/ Dawn L. Farrell
	Dawn L. Farrell
	President and Chief Executive Officer

Exhibit 31.2

Certifications

I, Christophe Dehout, certify that:


1.	I have reviewed this annual report on Form 40-F of TransAlta Corporation;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;


4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and


5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.



February 26, 2019
	/s/ Christophe Dehout
	Christophe Dehout
	Chief Financial Officer

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of TransAlta Corporation (the “Company”) on Form 40-F for the year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Dawn L. Farrell, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:


1.	The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


2.	The information contained in the Report fairly presents, in all materials respects, the financial condition and result of operations of the Company.

/s/ Dawn L. Farrell

Dawn L. Farrell

President and Chief Executive Officer

Dated: February 26, 2019

The foregoing certification is being furnished solely to accompany the Report pursuant to 18 U.S.C § 1350, and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of TransAlta Corporation (the “Company”) on Form 40-F for the year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Christophe Dehout, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:


1.	The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable of the Securities Exchange Act of 1934, as amended; and


2.	The information contained in the Report fairly presents, in all materials respects, the financial condition and result of operations of the Company.



/s/ Christophe Dehout
Christophe Dehout
Chief Financial Officer

Dated: February 26, 2019