TransAlta (TAC) SUPPL Supplemental materials (foreign)

Filed pursuant to General Instruction II.L of Form F-10
File No. 333-257098

PROSPECTUS SUPPLEMENT

(To the short form base shelf prospectus dated June 28, 2021)

New Issue

US$400,000,000

7.750% Senior Notes due 2029

TRANSALTA CORPORATION

The Notes (as hereinafter defined) will bear interest at the rate of 7.750% per annum. Interest on the Notes is payable on November 15 and May 15 of each year, beginning on May 15, 2023. The Notes will mature on November 15, 2029.

At any time on or after November 15, 2025, we may redeem some or all of the Notes at the redemption prices set forth in this Prospectus Supplement, plus accrued and unpaid interest. Prior to November 15, 2025, we may redeem some or all of the Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, plus a “make-whole” premium.

In addition, prior to November 15, 2025, we may redeem up to 35% of original aggregate principal amount of the Notes (which includes additional Notes, if any) in an amount not to exceed the amount of the proceeds of certain equity offerings at the redemption price set forth in this Prospectus Supplement, plus accrued and unpaid interest. We will also have the option to redeem the Notes in whole and not in part at 100% of the aggregate principal amount of the Notes, plus accrued interest to the date of redemption, in the event of certain changes to Canadian withholding tax laws or the enforcement or interpretation thereof. Upon the occurrence of a Change of Control Triggering Event (as hereinafter defined), holders of the Notes will have the right to require us to repurchase all or any part of their notes at a repurchase price equal to 101% of the principal amount of the Notes, plus accrued and unpaid interest.

The Notes will be our senior unsecured obligations and will rank equally in right of payment with all of our existing and future senior indebtedness and senior in right of payment to all of our future subordinated indebtedness. The Notes will be effectively subordinated to any of our future secured indebtedness to the extent of the value of the assets securing such indebtedness. None of our existing and future subsidiaries will guarantee the Notes. As a result, the Notes will be structurally subordinated to all existing and future obligations of our subsidiaries, including trade payables and indebtedness.

The underwriters, as principals, conditionally offer the Notes, subject to prior sale, if, as and when issued by the Corporation (as hereinafter defined) and accepted by the underwriters in accordance with the conditions contained in the underwriting agreement referred to under “Underwriting (Conflicts of Interest)” in this Prospectus Supplement.

Investing in the Notes involves risks. See “Risk Factors” in this Prospectus Supplement beginning on page  S-18 and under the heading “Risk Factors” beginning on page 28 of the accompanying Prospectus (as hereinafter defined).

	Per Senior Note			Total
Public Offering Price(1)		100	%	US$400,000,000
Underwriting Commission(2)		1.25	%	US$5,000,000
Proceeds to TransAlta(1)(3)		98.75	%	US$395,000,000

(1) The public offering price of the Notes will also include accrued interest, if any, from November 17, 2022 to the date of delivery.

(2) We refer you to “Underwriting (Conflicts of Interest)” beginning on page S-46 of this Prospectus Supplement for additional information regarding underwriting compensation.

(3) Before deducting the expenses of the offering, which are estimated to be approximately US$2,000,000.

The Notes will not be listed on any securities exchange or quotation system and, consequently, there is no market through which these securities may be sold and purchasers may not be able to resell securities purchased under this Prospectus Supplement. This may affect the pricing of the Notes in the secondary market, the transparency and availability of trading prices, the liquidity of the Notes and the extent of issuer regulation. See “Risk Factors” in this Prospectus Supplement.

THE NOTES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION (THE “SEC”) OR ANY UNITED STATES STATE SECURITIES COMMISSION NOR HAS THE SEC OR ANY UNITED STATES STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

This offering is made by a Canadian issuer that is permitted, under the multijurisdictional disclosure system adopted by the United States and Canada, to prepare this Prospectus Supplement and the accompanying Prospectus in accordance with Canadian disclosure requirements. Prospective investors should be aware that such disclosure requirements are different from those of the United States. The financial statements included herein have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”) and they are subject to Canadian auditing and auditor independence standards. As a result, such financial statements may not be comparable to financial statements of United States companies.

Prospective investors should be aware that the acquisition of the securities described in this Prospectus Supplement and the accompanying Prospectus may have tax consequences both in the United States and Canada. Such tax consequences for investors who are resident in, or citizens of, the United States may not be described fully in this Prospectus Supplement or the accompanying Prospectus. You should read the tax discussion under “Certain Income Tax Considerations” in this Prospectus Supplement and consult with your own tax advisor with respect to your own particular circumstances.

The enforcement by investors of civil liabilities under United States federal securities laws may be affected adversely by the fact that we are incorporated and organized under the laws of Canada, that most of our officers and directors are residents of Canada, that some or all of the underwriters or experts named in this Prospectus Supplement are residents of Canada, and that a substantial portion of our assets and the assets of said persons are located outside the United States. We have appointed our subsidiary, TransAlta Holdings U.S. Inc., 913 Big Hanaford Road, Centralia, WA 98531, as our authorized agent for service of process in any suit or proceeding arising out of or relating to the debt securities issued under the Indenture (as hereinafter defined) and for actions brought under federal or state securities laws in any federal or state court located in the City of New York.

The earnings coverage ratio on long-term debt for the twelve month period ended December 31, 2021 is less than one to one. See “Earnings Coverage” in this Prospectus Supplement.

The Notes will be ready for delivery in book-entry form only through the facilities of The Depository Trust Company (“DTC”) and its direct and indirect participants on or about November 17, 2022.

Our head and registered office is located at 110 -12th Avenue S.W., Calgary, Alberta, T2P 2M1.

Joint Book-Running Managers

RBC CAPITAL MARKETS	CIBC CAPITAL MARKETS	BOFA SECURITIES
	Co-Managers
SCOTIABANK	BMO CAPITAL MARKETS	TD SECURITIES
NATIONAL BANKOF CANADA FINANCIAL MARKETS	MUFG	DESJARDINS CAPITAL MARKETS
ATB CAPITAL MARKETS	MIZUHO	LOOP CAPITAL MARKETS

The date of this Prospectus Supplement is November 14, 2022

IMPORTANT NOTICE ABOUT INFORMATION IN

THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS

This document is divided into two parts. The first part is this prospectus supplement (this “Prospectus Supplement”), which describes the specific terms of the senior notes we are offering (the “Notes”) and also adds to and updates certain information contained in the short form base shelf prospectus of the Corporation (as hereinafter defined) dated June 28, 2021 (the “Prospectus”) and the documents incorporated by reference into this Prospectus Supplement or the accompanying Prospectus. The second part, the accompanying Prospectus, gives more general information, some of which may not apply to the Notes we are offering hereby. Defined terms used in this Prospectus Supplement that are not defined herein have the meanings ascribed thereto in the accompanying Prospectus.

Except as set forth under “The Offering” and “Description of Notes” in this Prospectus Supplement or under “Description of Debt Securities” in the accompanying Prospectus, and unless the context otherwise requires, all references in this Prospectus Supplement to “TransAlta”, the “Corporation”, “we”, “us” and “our” mean TransAlta Corporation and its consolidated subsidiaries including any consolidated partnerships of which the Corporation or any of its subsidiaries are partners.

If the description of the Notes varies between this Prospectus Supplement and the accompanying Prospectus, you should rely on the information in this Prospectus Supplement.

You should rely on the information contained in or incorporated by reference into this Prospectus Supplement and the accompanying Prospectus and any term sheet or other free writing prospectus for this offering that we file with the securities regulatory authorities in Canada or the SEC. We have not, and the underwriters have not, authorized anyone to provide you with different or additional information. We are not, and the underwriters are not, making an offer to sell the Notes in any jurisdiction where the offer or sale is not permitted. You should not assume that the information appearing in this Prospectus Supplement or the accompanying Prospectus is accurate as of any date other than the date on the front of this Prospectus Supplement.

PRESENTATION OF FINANCIAL INFORMATION

In this Prospectus Supplement, unless otherwise specified or the context otherwise requires, all dollar amounts are expressed in Canadian dollars. “U.S. dollars” or “US$” means the lawful currency of the United States. Unless otherwise indicated, all financial information included and incorporated by reference in this Prospectus Supplement and the accompanying Prospectus is determined using IFRS. Therefore, our consolidated financial statements included in this Prospectus Supplement and the accompanying Prospectus, copies of which are available on SEDAR (as hereinafter defined) at www.sedar.com and on the SEC’s website at www.sec.gov, may not be comparable to financial statements of U.S. companies prepared in accordance with U.S. generally accepted accounting principles.

We use a number of financial measures to evaluate our performance and the performance of our business segments, including measures and ratios that are presented on a non-IFRS basis, as described below. We believe that these non-IFRS amounts, measures and ratios, read together with our IFRS amounts, provide investors with a better understanding of how management assesses results. Non-IFRS amounts, measures and ratios do not have standardized meanings under IFRS. They are unlikely to be comparable to similar measures presented by other companies and should not be viewed in isolation from, or as an alternative for, or more meaningful than our IFRS results.

Adjusted EBITDA and deconsolidated net debt to deconsolidated adjusted EBITDA ratio are non-IFRS measures that are presented in this Prospectus Supplement. See “Highlights – Unaudited Interim Condensed Consolidated Financial Highlights”, “Additional IFRS Measures and Non-IFRS Measures” and “Key Non-IFRS Financial Ratios” in the management’s interim discussion and analysis of financial condition and results of operations as at and for the three and nine-month periods ended September 30, 2022 (“Interim MD&A”) appended to this Prospectus Supplement as Exhibit “D” for additional information, including a definition and reconciliation of such non-IFRS measures to the most comparable IFRS measure.

TABLE OF CONTENTS

Prospectus Supplement

EXCHANGE RATE INFORMATION	i
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	i
DOCUMENTS INCORPORATED BY REFERENCE	iv
MARKETING MATERIALS	v
WHERE YOU CAN FIND MORE INFORMATION	v
SUMMARY	1
THE OFFERING	14
RISK FACTORS	18
USE OF PROCEEDS	21
CAPITALIZATION	22
GREEN FINANCING FRAMEWORK	23
DESCRIPTION OF NOTES	26
EARNINGS COVERAGE	41
CERTAIN INCOME TAX CONSIDERATIONS	42
UNDERWRITING (CONFLICTS OF INTEREST)	46
LEGAL MATTERS	50
EXPERTS	50
EXHIBIT “A” – ANNUAL AUDITED FINANCIAL STATEMENTS AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2021 AND 2020	1
EXHIBIT “B” – ANNUAL MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	1
EXHIBIT “C” – INTERIM UNAUDITED FINANCIAL STATEMENTS AS AT AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2022	1
EXHIBIT “D” – INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	1

Prospectus

ABOUT THIS PROSPECTUS	2
DOCUMENTS INCORPORATED BY REFERENCE	2
CERTAIN AVAILABLE INFORMATION	4
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	4
TRANSALTA CORPORATION	6
CONSOLIDATED CAPITALIZATION	6
USE OF PROCEEDS	6
EARNINGS COVERAGE RATIOS	7
DESCRIPTION OF SHARE CAPITAL	7
DESCRIPTION OF WARRANTS	9
DESCRIPTION OF SUBSCRIPTION RECEIPTS	10
DESCRIPTION OF UNITS	11
DESCRIPTION OF DEBT SECURITIES	12
PRIOR SALES	25
MARKET FOR SHARES	25
CERTAIN INCOME TAX CONSIDERATIONS	25
SELLING SHAREHOLDER	26
PLAN OF DISTRIBUTION	27
RISK FACTORS	28
LEGAL MATTERS	28
EXPERTS	28
INTEREST OF EXPERTS	28
TRANSFER AGENT AND REGISTRAR	28
DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT	29
ENFORCEMENT OF CERTAIN CIVIL LIABILITIES	29

EXCHANGE RATE INFORMATION

TransAlta publishes its consolidated financial information in Canadian dollars. The following table sets forth the Canada/U.S. exchange rates on the last day of the periods indicated as well as the high, low and average rates for such periods. The high, low and average exchange rates for each period were identified or calculated from spot rates in effect on each trading day during the relevant period. The exchange rates shown are expressed as the number of U.S. dollars required to purchase one Canadian dollar. These exchange rates are based on those published on the Bank of Canada’s website on each trading day (the “Bank of Canada rate”). On November 10, 2022, the Bank of Canada rate was US$0.7475 equals $1.00.

	Nine Months Ended September 30,		Year Ended December 31,
	2022		2021		2020		2019
High for period	US$	0.8031	US$	0.8306	US$	0.7863	US$	0.7699
Low for period	US$	0.7285	US$	0.7727	US$	0.6898	US$	0.7353
Rate at end of period	US$	0.7296	US$	0.7888	US$	0.7854	US$	0.7699
Average rate for the period(1)	US$	0.7798	US$	0.7980	US$	0.7461	US$	0.7537

(1) The average of the Bank of Canada rate on the last day of each month during the applicable period.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Prospectus Supplement and the accompanying Prospectus contain both historical and forward-looking statements within the meaning of Section 27A of the United States Securities Act of 1933, as amended (the “U.S. Securities Act”), and Section 21E of the United States Securities Exchange Act of 1934, as amended (the “U.S. Exchange Act”). All forward-looking statements are based on TransAlta’s beliefs as well as assumptions based on information available at the time the assumption was made and on management’s experience and perception of historical trends, current conditions and expected further developments as well as other factors deemed appropriate in the circumstances. These forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as “may”, “will”, “believe”, “expect”, “anticipate”, “intend”, “plan”, “foresee”, “potential”, “enable”, “continue”, “estimate”, “would” or other words or phrases of similar import. These forward-looking statements are subject to known and unknown risks, uncertainties and other important factors, many of which are beyond the Corporation’s control, that could cause actual events, outcomes or results to differ materially from those expressed or implied in the forward-looking statement. Although the Corporation believes that the assumptions and expectations conveyed by such forward-looking statements are reasonable based on information available on the date they are made, there can be no assurance that such assumptions and expectations will prove to be correct.

Forward-looking statements in this Prospectus Supplement, the Prospectus and the documents incorporated by reference in the Prospectus and this Prospectus Supplement include, but are not limited to, statements with respect to TransAlta’s possible or assumed future results set out under “General Development of the Business” and “Business of TransAlta” in our most recent annual information form dated February 23, 2022 (the “Annual Information Form”) for the year ended December 31, 2021 and the management’s discussion and analysis of financial condition and results of operations as at and for the year ended December 31, 2021 (the “Annual MD&A”) (each of which is contained in our annual report on Form 40-F for the year ended December 31, 2021 (the “Form 40-F”)).

With respect to forward-looking statements contained in this Prospectus Supplement, we have made assumptions regarding, among other things: our ability to close this offering on a timely basis and on the terms expected; fulfillment by the underwriters and qualified independent underwriter of their obligations pursuant to the underwriting agreement; and that no event will occur which would allow the underwriters to terminate their obligations under the underwriting agreement.

S-i

In particular, this Prospectus Supplement and the accompanying Prospectus contain forward-looking statements pertaining to the following: the anticipated closing of the offering of the Notes, the net proceeds from the offering and the use of such proceeds, including in respect of the matters relating to our Green Financing Framework (each as defined herein), including project evaluation and selection, management of proceeds and reporting; the sources of financing of the repayment of our 2022 Notes (as defined herein); our credit ratings outlook; 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; impacts arising from COVID-19 not becoming significantly more onerous on the Corporation; merchant power prices in Alberta, Ontario and the Pacific Northwest; our proportionate ownership of TransAlta Renewables not changing materially; no material decline in the dividends expected to be received from TransAlta Renewables; Alberta’s power generation mix and related shifts in energy consumption; the remediation of Kent Hills 1 and Kent Hills 2 wind facilities; expected sources of financing; and assumptions regarding our current strategy and priorities. Additional assumptions on which we have based our 2022 guidance are disclosed with such guidance in the Interim MD&A and the Annual MD&A.

Factors that may cause the Corporation’s actual plans, actions or results to differ materially from those estimated or projected and expressed in, or implied by, these forward-looking statements include 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, sun, or wind required to operate our facilities; failure to meet financial expectations; disruptions and delays with the Corporation’s supply chain, including as it pertains to the Corporation’s development and construction projects; exposure of our facilities, construction projects and operations to effects of natural disasters, public health crises (such as pandemics and epidemics, including COVID-19) and other catastrophic events beyond our control; natural and man-made disasters resulting in dam failures; the threat of domestic terrorism and cyberattacks; foreign political risks, including the escalation of armed hostilities in Ukraine; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner or timely manner or at all; 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; 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; changes in the payment of future dividends, including from TransAlta Renewables; insurance coverage; credit ratings; our provision for income taxes; legal, regulatory, and contractual disputes and proceedings involving the Corporation; outcomes of investigations and disputes; reliance on key personnel; labour relations matters; development projects and acquisitions; and the expected retirement of coal-fired generation and increase in generation from renewable sources.

Additional information about material factors that could cause actual results to differ materially from expectations and about material factors or assumptions applied in making forward-looking statements may be found in this Prospectus Supplement and the accompanying Prospectus under “Risk Factors” as well as in the Annual MD&A as appended hereto as Exhibit “B” and the Annual Information Form, and elsewhere in TransAlta’s filings with the Canadian and U.S. securities regulators.

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 Prospectus Supplement, the Prospectus and the documents incorporated by reference in the

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Prospectus and this Prospectus Supplement are made only as of the date such statements and the Corporation does not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties and assumptions, the forward-looking events might occur to a different extent or at a different time than the Corporation has described or might not occur. The Corporation cannot assure you that projected results or events will be achieved. The foregoing risk factors, among others, including risks relating to the nature of the Notes, are described in further detail under the heading “Risk Factors” in this Prospectus Supplement and in the accompanying Prospectus and in the documents incorporated by reference into this Prospectus Supplement and the accompanying Prospectus, including the Annual MD&A and the Annual Information Form, and elsewhere in TransAlta’s filings with Canadian and U.S. securities regulators.

S-iii

DOCUMENTS INCORPORATED BY REFERENCE

Various documents are incorporated or deemed to be incorporated by reference into the accompanying Prospectus and reference should be made to the accompanying Prospectus for full details. See “Documents Incorporated by Reference” in the accompanying Prospectus. As of the date of this Prospectus Supplement, the following documents filed with the securities commissions or similar authorities in each of the provinces of Canada and with the SEC are specifically incorporated by reference into and form an integral part of this Prospectus Supplement and the accompanying Prospectus:

(a) the Annual Information Form (incorporated by reference to Exhibit 13.1 to our annual report on Form 40-F filed with the SEC on February 23, 2022, File No. 001-15214); and

(b) the management proxy circular dated March 18, 2022 prepared in connection with our annual and special meeting of shareholders held on April 28, 2022 (incorporated by reference to Exhibit 99.1 to our report on Form 6-K filed with the SEC on March 23, 2022, File No. 001-15214).

Any documents of the type required to be incorporated by reference in a short form prospectus pursuant to National Instrument 44-101 — Short Form Prospectus Distributions of the Canadian Securities Administrators, including any documents of the type referred to above or under “Documents Incorporated by Reference” in the accompanying Prospectus, material change reports (excluding confidential material change reports) and business acquisition reports we subsequently file with any securities commissions or similar authorities in Canada after the date of this Prospectus Supplement and prior to the termination of any offering of the Notes under this Prospectus Supplement shall be deemed to be incorporated by reference into this Prospectus Supplement and the accompanying Prospectus. These documents are available through the internet on the System for Electronic Document Analysis and Retrieval (“SEDAR”), which can be accessed at www.sedar.com. In addition, any similar documents we file with, or furnish to, the SEC pursuant to Section 13(a), 13(c) or 15(d) of the U.S. Exchange Act on or after the date of this Prospectus Supplement and prior to the termination of this distribution of Notes, shall be deemed to be incorporated by reference into this Prospectus Supplement or the accompanying Prospectus and the registration statement on Form F-10 of which this Prospectus Supplement and the accompanying Prospectus form a part, if and to the extent expressly provided in such report, except that any report on Form 6-K shall be incorporated only to the extent expressly provided in such report. Our reports on Form 6-K, and our annual reports on Form 40-F, are available on the SEC’s website at www.sec.gov.

Any statement contained in this Prospectus Supplement or the accompanying Prospectus, or in a document incorporated or deemed to be incorporated by reference herein or therein, shall be deemed to be modified or superseded for the purposes of this Prospectus Supplement to the extent that a statement contained herein or in any other subsequently filed document that also is or is deemed to be incorporated by reference herein modifies or supersedes such statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement is not to be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus Supplement.

Copies of the documents incorporated herein by reference (other than exhibits to such documents, unless such exhibits are specifically incorporated by reference in such documents) may be obtained either over the internet on the SEC’s website www.sec.gov or on request without charge from the Corporate Secretary of TransAlta at P.O. Box 1900, Station “M”, 110 - 12th Avenue S.W., Calgary, Alberta, Canada T2P 2M1, Telephone (403) 267-7110.

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MARKETING MATERIALS

Any “template version” of any “marketing materials” (as such terms are defined under applicable Canadian securities laws) that are utilized by the underwriters in connection with the offering of Notes are not part of this Prospectus Supplement and the accompanying Prospectus to the extent that the contents of the template version of the marketing materials have been modified or superseded by a statement contained in this Prospectus Supplement. Any template version of any marketing materials filed with Canadian securities regulators after the date of this Prospectus Supplement and before the termination of the distribution of the Notes under the offering (including any amendments to, or an amended version of, any template version of any marketing materials) is deemed to be incorporated into this Prospectus Supplement and the accompanying Prospectus.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC under the U.S. Securities Act a registration statement on Form F-10 relating to the Notes and of which this Prospectus Supplement and the accompanying Prospectus form a part. This Prospectus Supplement and the accompanying Prospectus do not contain all of the information set forth in such registration statement, certain items of which are contained in the exhibits to such registration statement as permitted or required by the rules and regulations of the SEC. See “Documents Filed as Part of the Registration Statement” in the accompanying Prospectus. Statements made in this Prospectus Supplement and the accompanying Prospectus as to the contents of any contract, agreement or other document referred to are not necessarily complete, and in each instance, reference is made to the exhibit, if applicable, for a more complete description of the relevant matter, each such statement being qualified in its entirety by such reference. Items of information omitted from this Prospectus Supplement and the accompanying Prospectus but contained in the registration statement on Form F-10 are available on the SEC’s website at www.sec.gov.

We are subject to the information requirements of the U.S. Exchange Act, and, in accordance therewith, file reports and other information with the SEC. Under the multijurisdictional disclosure system adopted in the United States and Canada, such reports and other information, subject to certain exceptions, may be prepared in accordance with the disclosure requirements of Canada, which requirements are different from those of the United States. We are exempt from the rules under the U.S. Exchange Act prescribing the furnishing and content of proxy statements, and our officers, directors and principal shareholders are exempt from the reporting and short swing profit recovery provisions contained in Section 16 of the U.S. Exchange Act. Under the U.S. Exchange Act, we are not required to publish financial statements as promptly as United States companies. Such reports and other information are available on the SEC’s EDGAR website at www.sec.gov. Prospective investors may read and download any public document that we have filed with the securities regulatory authorities in each of the provinces and territories of Canada on SEDAR at www.sedar.com.

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SUMMARY

The following is a summary of certain information contained in this Prospectus Supplement (including the documents incorporated by reference herein) and does not purport to be complete and is therefore qualified in its entirety by, and is subject to, the detailed information and consolidated financial statements, including the notes, contained elsewhere in this Prospectus Supplement. It does not contain all the information about our business or the offering that you should consider before investing in the notes. You should read the entire Prospectus Supplement (including the documents incorporated by reference herein), including the risk factors under the heading “Risk factors”. Terms not defined in this summary are defined elsewhere in this Prospectus Supplement. In this section, “we”, “us” and “our” refer only to TransAlta Corporation and not to any of its subsidiaries, unless otherwise stated.

TransAlta Corporation

TransAlta is one of Canada’s largest publicly traded power generators, by installed capacity, with over 110 years of operating experience. We focus on generating resilient cash flows through our high quality, highly diversified portfolio of assets across Canada, the United States, and Australia. Our business is driven by our reliable hydro portfolio, our contracted wind and solar portfolio, and our efficient natural gas portfolio. We complement our diverse portfolio with our leading asset optimization and energy marketing capabilities.

Our goal is to be a leading customer-centered electricity company, committed to a sustainable future, focused on increasing shareholder value by growing our portfolio of high-quality generation facilities with stable and predictable cash flows. Our strategy includes meeting our customers’ needs for clean, low-cost, reliable electricity and providing operational excellence with continuous improvement. On September 28, 2021, TransAlta announced its strategic growth targets and accelerated Clean Electricity Growth Plan that focuses on strategic growth targets including delivering 2 gigawatts (“GW”) of incremental renewable capacity. Since 2018, we have retired 4,064 megawatts (“MW”) of coal-fired generation capacity while converting 1,660 MW to natural gas, significantly reducing our carbon footprint. Moreover in 2021, we increased our renewable fleet by 334 MW through acquisitions and construction of renewable wind and solar facilities. There are currently 800 MW of renewable generation that have been announced since September 2021 that contribute to the Corporation’s Clean Electricity Growth Plan, resulting in the Corporation having already achieved 40% of its renewable energy capacity target.

As part of our focus on stable cash flows and our renewable energy strategy, TransAlta is the majority owner of TransAlta Renewables Inc. (“TransAlta Renewables”) (TSX:RNW), with an approximate 60 per cent direct and indirect ownership. TransAlta Renewables holds an aggregate of 2,996 MW of gross installed capacity, including 26 wind facilities, 13 hydro facilities, 8 natural gas facilities, 2 solar facilities and one battery storage facility. On a fully consolidated basis, approximately 45% of our business is contracted under power purchase agreements (“PPAs”) based on 2021 EBITDA, and investment grade counterparties account for 95% of contracted assets with a weighted average contract life of approximately 13 years.

Approximately 52% of our gross installed capacity is located in Alberta. Our portfolio of assets in Alberta is a combination of hydro facilities, wind facilities, a battery storage facility, cogeneration facilities and converted natural gas-fired thermal facilities. Optimization of the Alberta facilities is driven by the diversity in fuel types, which enables portfolio management and allows for maximization of operating margins. A portion of the uncontracted installed generation capacity in the Alberta portfolio is hedged to provide cash flow certainty.

Our generating fleet is geographically and technologically diverse and we have experienced teams in place to deliver our current and future operational needs. We currently own or have an interest in a portfolio of assets that we operate through four business segments:

• The Hydro segment consists of 26 critical-infrastructure assets with 925 MW of gross installed capacity in Alberta, British Columbia and Ontario, including several large-scale hydro facilities with storage and dispatch capabilities.

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• The Wind and Solar segment consists of a highly contracted portfolio consisting of 29 assets with 1,907 MW of gross installed capacity across Canada and the United States. The Wind and Solar segment also includes a battery storage asset that is co-located with our Summerview II wind facility.

• The Gas segment consists of efficient natural gas portfolio comprised of 17 assets with 3,084 MW of gross installed capacity across Canada, the United States, and Australia.

• The Energy Transition segment consists of one contracted coal-fired generation facility of 670 MW in the United States and one hydroelectric generation facility of 1 MW in the United States. The coal-fired facility is scheduled to be retired following the expiration of the PPA for the facility at the end of 2025.

Furthermore, through years of expansion and investment, we’ve built a leading Energy Marketing business. The Energy Marketing segment continues to deliver value and strong cash flow by optimizing our fleet, trading power, natural gas and environmental products across several markets to capitalize on electricity demand and minimizing risk in merchant power markets. The Energy Marketing segment also works to support our growth aspirations by leveraging our first-hand knowledge, insights and industry relationships to support the development of new opportunities.

(1) Fuel type and geography allocations based on the last twelve months (“LTM”) September 30, 2022 EBITDA.

(2) Fuel type excludes corporate and other expenses.

(3) Profile allocations based on LTM September 30, 2022 production.

(4) Non-IFRS measure, see “Presentation of Financial Information” in this Prospectus Supplement.

TransAlta has a proven track record of delivering growth through the development and acquisition of renewables assets. This includes the expansion of onshore wind in North America through customer-centered greenfield development, establishing a position in solar in the United States and Australia through acquisitions and the continued exploration and development of storage opportunities. In addition, we expect to continue optimizing the legacy Alberta hydro assets in conjunction with our gas generation fleet to maximize cash flows in order to support continued investment in renewables and storage.

In addition to power generation, we continue to assess new industry sectors such as water treatment, transmission/distribution and car charging, and monitor new technologies such as storage and hydrogen, in addition to carbon capture technologies for deployment post-2025.

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Our Operating Assets

The following table provides an overview of our assets in which we have an owned interest:

As at September 30, 2022	Facility	Nameplate capacity (MW)	Consolidated Interest	Gross Installed capacity	Ownership (%)	Net Capacity Ownership Interest (MW)	Region	Revenue source	Contract expiry date
Hydro	Brazeau, AB	355	100%	355	100%	355	Western Canada	Merchant	—
26 facilities	Bighorn, AB	120	100%	120	100%	120	Western Canada	Merchant	—
	Spray, AB	112	100%	112	100%	112	Western Canada	Merchant	—
	Ghost, AB	54	100%	54	100%	54	Western Canada	Merchant	—
	Rundle, AB	50	100%	50	100%	50	Western Canada	Merchant	—
	Cascade, AB	36	100%	36	100%	36	Western Canada	Merchant	—
	Kananaskis, AB	19	100%	19	100%	19	Western Canada	Merchant	—
	Bearspaw, AB	17	100%	17	100%	17	Western Canada	Merchant	—
	Pocaterra, AB	15	100%	15	100%	15	Western Canada	Merchant	—
	Horseshoe, AB	14	100%	14	100%	14	Western Canada	Merchant	—
	Barrier, AB	13	100%	13	100%	13	Western Canada	Merchant	—
	Taylor, AB*	13	100%	13	100%	13	Western Canada	Merchant	—
	Interlakes, AB	5	100%	5	100%	5	Western Canada	Merchant	—
	Belly River, AB*	3	100%	3	100%	3	Western Canada	Merchant	—
	Three Sisters, AB	3	100%	3	100%	3	Western Canada	Merchant	—
	Waterton, AB*	3	100%	3	100%	3	Western Canada	Merchant	—
	St. Mary, AB*	2	100%	2	100%	2	Western Canada	Merchant	—
	Upper Mamquam, BC*	25	100%	25	100%	25	Western Canada	LTC	2025
	Pingston, BC*	45	50%	23	100%	23	Western Canada	LTC	2023
	Bone Creek, BC*	19	100%	19	100%	19	Western Canada	LTC	2031
	Akolkolex, BC*	10	100%	10	100%	10	Western Canada	LTC	2046

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As at September 30, 2022	Facility	Nameplate capacity (MW)	Consolidated Interest	Gross Installed capacity	Ownership (%)	Net Capacity Ownership Interest (MW)	Region	Revenue source	Contract expiry date
	Ragged Chute, ON*	7	100%	7	100%	7	Eastern Canada	LTC	2029
	Misema, ON*	3	100%	3	100%	3	Eastern Canada	LTC	2027
	Galetta, ON(1)*	2	100%	2	100%	2	Eastern Canada	LTC	2030
	Appleton, ON*(1)	1	100%	1	100%	1	Eastern Canada	LTC	2030
	Moose Rapids, ON*	1	100%	1	100%	1	Eastern Canada	LTC	2030
Total Hydro		947		925		925
Wind &	Summerview 1, AB*	68	100%	68	100%	68	Western Canada	Merchant	—
Battery Storage	Summerview 2, AB*	66	100%	66	100%	66	Western Canada	Merchant	—
27 facilities	Ardenville, AB*	69	100%	69	100%	69	Western Canada	Merchant	—
	Blue Trail and Macleod Flats, AB*	69	100%	69	100%	69	Western Canada	Merchant	—
	Castle River, AB*	44	100%	44	100%	44	Western Canada	Merchant	—
	McBride Lake, AB*	75	50%	38	100%	38	Western Canada	LTC	2024
	Soderglen, AB*	71	50%	36	100%	36	Western Canada	Merchant	—
	Cowley North, AB*	20	100%	20	100%	20	Western Canada	Merchant	—
	Oldman, AB*	4	100%	4	100%	4	Western Canada	Merchant	—
	Sinnott, AB*	7	100%	7	100%	7	Western Canada	Merchant	—
	Windrise, AB*	206	100%	206	100%	206	Western Canada	LTC	2041
	WindCharger battery storage, AB*	10	100%	10	100%	10	Western Canada	Merchant	—
	Melancthon, ON*	200	100%	200	100%	200	Eastern Canada	LTC	2026-2028
	Wolfe Island, ON*	198	100%	198	100%	198	Eastern Canada	LTC	2029

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As at September 30, 2022	Facility	Nameplate capacity (MW)	Consolidated Interest	Gross Installed capacity	Ownership (%)	Net Capacity Ownership Interest (MW)	Region	Revenue source	Contract expiry date
	Kent Breeze, ON*	20	100%	20	100%	20	Eastern Canada	LTC	2031
	Kent Hills, NB*	167	100%	167	83%	139	Eastern Canada	LTC	2035
	Le Nordais, QC*	98	100%	98	100%	98	Eastern Canada	LTC	2033
	New Richmond, QC*	68	100%	68	100%	68	Eastern Canada	LTC	2033
	Wyoming Wind, WY*	140	100%	140	100%	140	United States	LTC	2028
	Lakeswind, MN*	50	100%	50	100%	50	United States	LTC	2034
	Big Level, PA*	90	100%	90	100%	90	United States	LTC	2034
	Antrim, NH*	29	100%	29	100%	29	United States	LTC	2039
	Skookumchuck, WA	137	49%	67	100%	67	United States	LTC	2040
Total Wind		1,906		1,763		1,735
Solar	Mass Solar, MA*	21	100%	21	100%	21	United States	LTC	2032-2035
2 facilities	North Carolina Solar, NC	122	100%	122	100%	122	United States	LTC	2033
Total Solar		143		143		143
Gas	Keephills 2, AB	395	100%	395	100%	395	Western Canada	Merchant	—
17 facilities	Keephills 3, AB	463	100%	463	100%	463	Western Canada	Merchant	—
	Poplar Creek, AB	230	100%	230	100%	230	Western Canada	LTC	2030
	Sheerness, AB	800	50%	400	50%	200	Western Canada	Merchant	—
	Sundance 6, AB	401	100%	401	100%	401	Western Canada	Merchant	—
	Fort Saskatchewan, AB	118	60%	71	50%	35	Western Canada	LTC/Merchant	2029
	Sarnia, ON*	499	100%	499	100%	499	Eastern Canada	LTC	2022-2032

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As at September 30, 2022	Facility	Nameplate capacity (MW)	Consolidated Interest	Gross Installed capacity	Ownership (%)	Net Capacity Ownership Interest (MW)	Region	Revenue source	Contract expiry date
	Ottawa, ON	74	100%	74	50%	37	Eastern Canada	LTC/ Merchant	2020-2033
	Windsor, ON	72	100%	72	50%	36	Eastern Canada	LTC/ Merchant	2031
	Ada, MI*	29	100%	29	100%	29	United States	LTC	2026
	Parkeston, WA*	110	50%	55	100%	55	Australia	LTC	2026
	Southern Cross, WA*	245	100%	245	100%	245	Australia	LTC	2038
	South Hedland, WA*	150	100%	150	100%	150	Australia	LTC	2042
Total Gas		3,586		3,084		2,775
Energy Transition	Centralia, WA	670	100%	670	100%	670	United States	LTC/ Merchant	2025
2 facilities	Skookumchuck, WA	1	100%	1	100%	1	United States	LTC	2025
Total Energy Transition		671		671		671
Total		7,253		6,586		6,249

Notes:

(1) Subject to a purchase and sale agreement.

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Industry Overview

Alberta Merchant Power Market

Alberta is part of the Western Electric Coordinating Council with over 17,000 MW of installed generation and seasonal peak demand of 11,939 MW. The power grid in Alberta includes approximately 26,000 kilometres of transmission lines and connects approximately 426 generating assets and over 225 market participants to the wholesale market. Alberta’s deregulated electricity market began in 1996, when the Electric Utilities Act established a competitive market for electricity generation; transmission and distribution assets remain regulated.

In 2000, the province introduced PPAs via auction to introduce competition and help transition the Alberta wholesale electricity market off of its regulated model. PPAs allowed existing utility owners to continue to own and operate their facilities, but auctioned the dispatch rights of the associated energy to new buyers. PPAs auctioned in 2000 expired at the end of 2020, and in 2021 the market became fully merchant. Alberta average spot power prices for the first nine months of 2022, and for 2021, were approximately 200% higher and 100% higher than the four preceding years, respectively.

The wholesale electricity market in Alberta is currently an “energy-only” model, meaning that generators are only paid for energy they produce. Generators must offer all available power into the market, with prices ranging from $0/MW hour (“MWh”) to $999.99/MWh. The Alberta Electric System Operator (“AESO”) is responsible for operating the power pool in the province, which is the wholesale energy market where the price is set every hour based on the metrics of supply and demand. All dispatched generators are compensated at the same settlement price for all energy produced within the hour. Roughly two-thirds of Alberta’s merit order is comprised of generation such as renewables, imports, the must-run components of coal and combined-cycles, as well as cogeneration that is often offered at $0/MWh in order to ensure dispatch. When the supply cushion is even (either from healthy supply availability and/or soft demand), the price is usually set at the marginal cost of either coal or combined-cycle, with the order of dispatch being driven by gas price and environmental compliance costs. As the supply cushion tightens, prices shift to be set by peaking simple-cycle units pricing at multiples of fuel, and during periods of very tight supply cushion by aggressive strategic offers from peaking units and dispatchable hydro.

Alberta’s generation mix is expected to undergo a major shift as federal and provincial policies drive the retirement of all coal-fired generation by the end of 2023. The AESO forecasts that coal will be replaced with a mix of natural gas generation and renewable energy, and we expect to benefit from this transition.

Renewable Energy

Renewable energy has been rapidly growing over the last several years, and BloombergNEF’s New Energy Outlook 2021 (“NEO 2021”) expects that generation from renewable sources will increase significantly from 2021 to 2050. Approximately 68% of global power generation by 2050 is expected to come from clean energy sources, which indicates that renewable energy will continue to become more mainstream. Energy consumption is expected to shift from approximately 68% fossil fuels today to approximately 13-30% by 2050. According to NEO 2021, an expansion and decarbonization of generating capacity is estimated to require $33-57 trillion of new investment between now and 2050, of which $20.5-28.5 trillion is expected to go towards renewable generation. To achieve this, annual investment in energy supply and infrastructure will need to increase from approximately $1.7 trillion per year today to an estimated $3.1-5.8 trillion over the next 3 decades. Additionally, electrification is expected to continue to accelerate and the economic efficiency of energy is expected to improve, with a decoupling of energy consumption relative to GDP, falling 62% between 2019 and 2050, which translates to a 3.1% year-on-year decline in the energy intensity of GDP.

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Natural Gas Power

Natural Gas power production has undergone changes influenced by climate concerns and a growing economic need for reliable generation. We expect that natural gas power plants will continue to be essential around the globe, and instead of investing in new plants themselves, we believe utility providers will be interested in outsourcing capacity and signing long-term PPAs. While we believe renewables will continue to grow their share of global power generation, the natural gas sector will remain attractive and compliment capacity needs over the medium term with its reliable generation and low capital costs.

Our Competitive Strengths

Diversified Portfolio of High-Quality Assets

We own and operate a fleet of power generation assets diversified across geography and fuel type. As of September 30, 2022 LTM EBITDA was generated:

• 35% by our fleet of efficient natural gas facilities, including four facilities which were recently converted from coal;

• 21% by our fleet of wind and solar facilities located across Canada and the United States;

• 32% by our unique portfolio of large-scale, dispatchable hydro facilities in Alberta, British Columbia and Ontario;

• 7% by our Energy Transition segment, comprised of two coal generation facilities in Alberta which were retired on December 31, 2021 and April 1, 2022, and Centralia, which will be retired on December 31, 2025 following the expiration of its PPA; and

• 5% by our Energy Marketing segment, which generates revenue from the wholesale trading of electricity and other energy-related commodities and derivatives.

Stable Cash Flow Profile with Commitment to Contracted Cash Flow Growth

Our cash flow profile is supported by long-term PPAs with credit-worthy counterparties. As of year-end 2021, approximately 44% of our EBITDA was from contracted generation. Approximately 95% of contracted generation was with investment grade counterparties with a weighted average contract life of approximately 13 years. As existing contracts approach expiration, we actively engage with our customers to extend offtake agreements in a mutually beneficial manner. Furthermore, 100% of our in-construction or approved-for-construction projects have already secured long-term contracts.

For the Alberta gas fleet, which predominantly sells power on a merchant basis, we reduce cash flow volatility by selling forward production and by hedging the cost of natural gas. As of September 30, 2022, we had sold forward 90% of production and hedged 98% of the estimated natural gas requirements for the balance of 2022.

Leading Market Share in Alberta Power Market with World-Class Portfolio Optimization

We believe portfolio diversification and operational expertise have us well-positioned to perform in an Alberta energy-only market with an increasing proportion of renewable power. We believe active portfolio management involving fleet-wide optimization of thermal, hydro, wind and storage assets will allow us to remain a significant participant in the Alberta market. Further, we believe our integrated analytics, electricity trading, structuring and origination capability, commercial and industrial sales business, along with natural gas and environmental product trading desks, allow us to take full advantage of both the evolving market and our changing fleet.

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We have the largest hydro fleet in the province; an asset class that we believe is well-positioned to support the grid through an oversupply of noncommittal generating sources. We are currently the largest provider of ancillary services, a product that we expect will have increasing value as the continued build-out of renewables increases power price volatility. Our converted natural gas facilities run as pseudo peaking plants, making us the largest provider of peaking capacity in the province. We have a strong customer and commercial contracting team, which supplements our commercial and industrial retail business. Our marketing platform allows us to further optimize our portfolio with dedicated natural gas trading and scheduling desks, as well as an environmental products desk and a team of power traders, optimizers and analysts.

Prudent Financial Profile with Strong Liquidity and Access to Capital

We intend to maintain a conservative credit profile as we continue to grow our contracted renewables portfolio. We have continued to lower our deconsolidated net debt to deconsolidated adjusted EBITDA profile since 2018 from 3.5x to 1.5x as of September 30, 2022. We have a strong liquidity profile and maintain access to capital with our $1.25 billion syndicated credit facility “Credit Facility”), $0.8 billion of cash and cash equivalents as of September 30, 2022, $240 million Canadian committed bilateral credit facilities, and a $400 million two-year term loan facility. We will use cash-on-hand and draw any remaining amount needed on the Credit Facility to fund the repayment in full of TransAlta’s 4.500% unsecured senior notes due November 15th, 2022 (“2022 Notes”). We use balance sheet cash, funds from operations, and asset level debt to finance our portfolio growth. When we engage in asset level financings, we seek to structure the debt quantum to an investment grade profile and fully amortize the debt over the life of the contract.

Premier Player in ESG with Significant Commitment to Renewables

Our goal is to be a leading customer-centered electricity company committed to a sustainable future and focused on increasing shareholder value by growing our portfolio of high quality generation facilities with stable and predictable cash flows. Our strategy includes meeting our customers’ needs for clean, low-cost, reliable electricity.

We have reported on sustainability for over 25 years, and 2021 marked our seventh year of integrating financial performance with environment, social and governance disclosure. We track over 80 social and environmental key performance indicators, many aligned with the United Nation’s sustainable development goals and report in alignment with Task Force on Climate-Related Financial Disclosures and Sustainability Accounting Standards Boards, which are two leading environmental social and corporate governance (“ESG”) frameworks. Our MSCI ESG Rating was recently upgraded to “A” from “BBB”. The upgrade reflects TransAlta’s strong renewable energy growth compared to peers.

Our Clean Energy Investment Plan, announced in 2019, included converting our existing Alberta coal assets to natural gas and advancing our leadership position in renewable electricity. Since 2018, we have retired 4,064 MW of coal-fired generation while converting 1,659 MW to natural gas, significantly reducing our carbon footprint. We operate one remaining coal facility, which is scheduled to be retired on December 31, 2025, following the expiration of its PPA. Through these retirements, we will have achieved a 61% carbon reduction from 2015 levels, and on our own have delivered the equivalent of approximately 9% of the emissions reductions necessary to achieve Canada’s national emissions reduction target. As a result of these changes, we no longer have any coal generating assets in Canada.

On September 28, 2021, we announced our strategic growth targets and Accelerated Clean Electricity Growth Plan, which established the following strategic priorities and targets to guide our path from 2021 to 2025:

• Deliver 2 GW of incremental renewable capacity with a targeted capital investment of $3 billion by the end of 2025;

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• Accelerate growth into customer-centered renewables and storage through the deployment of our 3 GW development pipeline;

• Expand the Corporation’s development pipeline to 5 GW by 2025 to enable a two-fold increase in our renewable fleet between 2025 and 2030;

• Realize targeted diversification and value creation by focusing on expanding our platform in each of our core geographies;

• Lead in ESG policy development to enable the successful evolution of the markets in which we operate and compete; and

• Define the next generation of power solutions and technologies and potential for parallel investments in new complementary sectors by the end of 2025.

The Credit Facility was amended in 2021 to provide for sustainability-linked loans. The Credit Facility’s financing terms will align the cost of borrowing to our greenhouse gas (“GHG”) emissions reduction and gender diversity targets, which are part of our overall ESG strategy. In May 2022, we extended our Credit Facility to June 30, 2026.

Green Financing Framework

We intend to allocate an amount equal to the net proceeds from this offering to finance or refinance, in part or in full, new and/or existing eligible green projects (“Eligible Projects”) in accordance with our green bond framework (the “Green Financing Framework”). See “Use of Proceeds” in this Prospectus Supplement.

The Green Financing Framework has been developed in line with the Green Bond Principles 2021 (“GBP”) published by the International Capital Market Association (“ICMA”). The Green Financing Framework is intended to provide transparency to our green bond issuances and reporting processes. The Green Financing Framework is based on the four core components of the GBP, being: (1) Use of Proceeds; (2) Process for Project Evaluation and Selection; (3) Management of Proceeds and (4) Reporting. The Green Financing Framework also describes the manner in which green bonds support and contribute towards meeting the United Nations Sustainable Development Goals (“SDG”). Under the Green Financing Framework, TransAlta may issue green bonds in various formats, according to the prevailing terms described in the documentation. See “Green Financing Framework” in this Prospectus Supplement.

Strategic Investment by Brookfield

On March 22, 2019, the Corporation entered into an agreement (the “Investment Agreement”) whereby an affiliate of Brookfield Renewable Partners (“Brookfield”) agreed to invest $750 million in the Corporation through the purchase of exchangeable securities, which are exchangeable by Brookfield into an equity ownership interest in certain of TransAlta’s Alberta hydro assets in the future at a value based on a multiple of the Alberta hydro assets’ future-adjusted EBITDA. Under the terms of the Investment Agreement, Brookfield committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to not less than nine per cent. In connection with the Investment Agreement, Brookfield is entitled to nominate two directors for election to the Board. As of September 30, 2022, Brookfield held approximately 13% of our issued and outstanding common shares.

Visible pipeline of development projects for sustained future growth

We are primarily evaluating greenfield opportunities in Alberta, Western Australia and the US, along with acquisitions in markets in which we have existing operations. The following greenfield development projects have been approved by the Board of Directors, have executed PPAs and are currently under construction.

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Project	Type	Region	Capacity (MW)	Target Completion	Avg. Annual EBITDA ($ millions)
Garden Plain	Wind	Alberta	130	Q4 2022	$14 - $15
White Rock	Wind	Oklahoma	300	H2 2023	US$48 – US$52
Horizon Hill	Wind	Oklahoma	200	H2 2023	US$30 – US$33
Northern Goldfields Solar	Hybrid Solar	Western Australia	48	H1 2023	AU$9 – AU$10
Mount Keith 132 kV Expansion	Transmission	Western Australia	n/a	H2 2023	AU$6 – AU$7

The following growth projects have detailed engineering, advanced positions in the interconnection queue and are progressing off-take opportunities.

Project	Type	Region	Capacity (MW)
Tempest	Wind	Alberta	100
SCE Capacity Expansion	Gas	Western Australia	42
WaterCharger	Battery Storage	Alberta	180
Australia Transmission Expansion	Transmission	Western Australia	n/a

Our Business Strategy

TransAlta has a diversified and resilient generating fleet and leading trading and optimization capabilities, all guided by a single leadership team driving operational and financial synergies. Our strategy focuses on optimizing our existing assets while growing our portfolio of high quality generation facilities with stable and predictable cash flows in a safe and reliable way. Our strategy includes meeting our customers’ needs for clean, low-cost, reliable electricity and providing operational excellence and continuous improvement in everything we do. We continuously work towards our goal of being a leading customer-centered electricity company, committed to a sustainable future, focused on increasing shareholder value.

Our plan for executing this strategy includes the following key components:

Focus on stable, long-term contracted renewables asset growth

We intend to focus on growing our renewable generation capacity and contracted assets under long term agreements. We believe we have extensive experience and proven structures and management processes in place, as well as the benefit of operating efficiencies and scale, to execute our growth plan. We expect this to allow us to further the stability of our cash flows. We intend to maintain a diversified portfolio with EBITDA generated from low-carbon footprint assets, as we believe these technologies will see significant growth in our targeted geographies. Our enhanced focus on renewable generation and storage solutions for customers is driven largely by global decarbonization policies and the increase in demand and growth projections in the renewable sector. We expect that, through the execution of our Clean Electricity Growth Plan, EBITDA generated from renewable sources, including hydro, wind, and solar, will increase from 53% to 70% in the near-to-medium term.

Continuous improvement in optimization of the Merchant portfolio in the Alberta market

Our portfolio is focused on fleet diversity, peaking generation, ancillary service offerings and a low carbon footprint. Coupling these strengths with our long-standing optimization expertise, we believe we are well-positioned to be successful not only in the current Alberta power price environment, but also in an environment with lower average prices and higher levels of volatility.

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For our hydro and thermal fleets, our trading and optimization team’s ability to strategically use our units allows us to achieve higher-than-average prices. In the third quarter of 2022, our Alberta hydro assets realized an average premium of 11% to the spot price, while our gas and energy transition assets realized an average premium of 19%.

Maintain diversification across three core regions

Our focus on three core countries, Canada, the United States, and Australia, helps to ensure exposure to markets in which we believe the natural gas and renewable energy sectors will continue to grow significantly given power demand needs and emission reduction policies.

Maintain a low-risk approach

As of year-end 2021, approximately 45% of our EBITDA was from contracted generation. Approximately 95% of contracted generation was with investment grade counterparties with a weighted average contract life of approximately 13 years. For the Alberta gas fleet, which predominantly sells power on a merchant basis, we reduce cash flow volatility by selling forward production and by hedging the cost of natural gas. As of September 30, 2022, we had sold forward 90% of production and hedged 98% of the estimated natural gas requirements for the balance of 2022. We expect to continue our hedging strategy and as we grow our renewables portfolio, we plan to enter into PPAs ahead of construction to achieve greater cash flow certainty.

Maintain a prudent financial policy and financial flexibility

Maintaining a low leverage profile is an important principle for us. As we continue to grow our contracted renewables portfolio, we intend to maintain our low corporate net leverage profile which currently stands at 1.5x net debt to adjusted EBITDA on a consolidated basis. We intend to finance our portfolio growth with balance sheet cash, funds from operations, and project debt targeting investment grade metrics that is structured to fully amortize over the duration of the contract. In addition, we hedge a significant portion of our interest rate risk exposure. We intend to maintain a strong financial position through a combination of undrawn credit facilities and unrestricted cash. As of September 30, 2022 we had approximately $2.3 billion in available liquidity. In order to maintain flexibility, we use diversified sources of financing in our project and corporate debt including banks, capital markets participants, and tax equity investors.

Recent Developments

Effective November 15, 2022, TransAlta will repay in full all of the outstanding 2022 Notes, of which an aggregate principal amount of US$400 million are outstanding. We will use cash-on-hand and draw any remaining amount needed on the Credit Facility to fund the repayment in full of the 2022 Notes.

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Organization Structure

The following summary chart sets forth our ownership structure as of the date of this Prospectus Supplement:

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THE OFFERING

The following is a brief summary of some of the terms of this offering. For a more complete description of the terms of the Notes, see “Description of Notes” in this Prospectus Supplement and “Description of Debt Securities” in the accompanying Prospectus. In this section, “we”, “us” and “our” refer only to TransAlta Corporation and not to any of its subsidiaries, unless otherwise stated.

Issuer TransAlta Corporation.

Notes Offered US$400,000,000 million aggregate principal amount of 7.750% senior notes due November 15, 2029.

Interest Rate The Notes will bear interest at the rate of 7.750% per annum from November 17, 2022 or from the most recent date to which interest has been paid or provided for.

Interest Payment Dates November 15 and May 15 of each year, commencing May 15, 2023.

Maturity Date November 15, 2029.

Ranking The Notes will be our senior unsecured obligations and will rank:

• equally in right of payment with all of our existing and future senior indebtedness;

• senior in right of payment to all of our future subordinated indebtedness;

• effectively subordinated to any of our future secured indebtedness to the extent of the value of the assets securing such indebtedness; and

• structurally subordinated to all existing and future obligations, including trade payables and indebtedness, of all of our existing and future subsidiaries.

As of September 30, 2022, after giving effect to this offering of the Notes and the use of proceeds therefrom as described under “Use of Proceeds” in this Prospectus Supplement, we would have had approximately $3,539 million of total long-term debt outstanding, including the Notes, of which $1,759 million is secured. As at September 30, 2022, the Corporation’s subsidiaries had approximately $1,902 million of total debt outstanding (excluding intercompany indebtedness and lease liabilities). None of our existing or future subsidiaries will guarantee the Notes.

Use of Proceeds We expect that the net proceeds from this offering will be approximately US$393 million after deducting underwriting commissions and estimated expenses of this offering. We intend to allocate an amount equal to the net proceeds from this offering to finance or refinance, in part or in full, new and/or existing “Eligible Projects” (as defined under “Green Financing Framework” in this Prospectus Supplement).

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Pending such allocation, we intend to use the net proceeds from this offering to repay $100 million drawn on the Credit Facility (as defined herein) and replace balance sheet cash used to fund the repayment in full of the 2022 Notes.

Green Financing Framework The Green Financing Framework has been developed in line with the GBP published by the ICMA. The Green Financing Framework is intended to provide transparency to our issuances of green bonds, including the Notes, and reporting processes. The Green Financing Framework is based on the four core components of the GBP, being: (1) Use of Proceeds; (2) Process for Project Evaluation and Selection; (3) Management of Proceeds and (4) Reporting. The Green Financing Framework also describes the manner in which the green bonds support and contribute towards meeting the SDG. Under the Green Financing Framework, TransAlta may issue green bonds in various formats, according to the prevailing terms described in the documentation. See “Green Financing Framework” in this Prospectus Supplement.

Optional Redemption At any time prior to November 15, 2025, we may redeem up to 35% of the aggregate principal amount of the Notes issued under the Indenture with an amount of cash not greater than the net cash proceeds from one or more Equity Offerings at the redemption price set forth under “Description of Notes—Optional Redemption” in this Prospectus Supplement, if at least 65% of the aggregate principal amount of the Notes issued under the Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such Equity Offering.

At any time prior to November 15, 2025, we may on any one or more occasions, redeem all or a part of the Notes at a redemption price equal to 100% of the principal amount of the Notes redeemed, plus a “make whole” premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption.

On and after November 15, 2025, we may redeem the Notes, in whole or in part, at the redemption prices set forth under “Description of Notes—Optional Redemption” in this Prospectus Supplement, plus accrued and unpaid interest, if any, to, but excluding, the redemption date.

See “Description of Notes—Optional Redemption” in this Prospectus Supplement.

Additional Amounts; Tax Redemption All payments in respect of the Notes will be made without withholding or deduction for any taxes or other governmental charges imposed or levied by or on behalf of any taxing authority, except to the extent required by law.

If such withholding or deduction is required by law, subject to certain exceptions, we will pay additional amounts so that the net amount you receive is no less than what you would have received in the absence of such withholding or deduction.

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See “Description of Notes—General” in this Prospectus Supplement and “Description of Debt Securities—Payment of Additional Amounts” in the accompanying Prospectus.

If certain changes in Canadian law are proposed or become effective that would require us to make additional payments with respect to taxes withheld from payments in respect of the Notes, we may redeem the Notes in whole, but not in part, at any time, at a redemption price equal to 100% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to, but excluding, the redemption date.

See “Description of Notes—Tax Redemption” in this Prospectus Supplement.

Change of Control Triggering Event We will be required to make an offer to repurchase the Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase upon the occurrence of a Change of Control Triggering Event. See “Description of Notes — Repurchase Upon Change of Control Triggering Event” in this Prospectus Supplement.

Certain Covenants The Indenture pursuant to which the Notes will be issued contains certain covenants that, among other things, limit:

• our and our subsidiaries’ ability to create liens;

• our ability to enter into sale and leaseback transactions; and

• our ability to merge, amalgamate or consolidate with, or sell all or substantially all of our assets to, any other person.

See “Description of Debt Securities — Covenants” in the accompanying Prospectus. These covenants are subject to important exceptions and qualifications that are described under the caption “Description of Debt Securities — Covenants” in the accompanying Prospectus.

Form The Notes will be represented by one or more fully registered global notes deposited in book-entry form with, or on behalf of, DTC, and registered in the name of its nominee. See “Description of Notes — Book-Entry System” in this Prospectus Supplement. Except as described under “Description of Notes” in this Prospectus Supplement and under “Description of Debt Securities” in the accompanying Prospectus, Notes in certificated form will not be issued.

Conflicts of Interest Affiliates of RBC Capital Markets, LLC beneficially own in excess of 10% of our issued and outstanding common stock. Accordingly, RBC Capital Markets, LLC is deemed to have a “conflict of interest” under Rule 5121 of the Financial Industry Regulatory Authority, Inc. (“FINRA”). As a result, this offering is being made in compliance with the requirements of Rule 5121 which requires, among other things, that a “qualified independent underwriter” participate in the

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preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this Prospectus Supplement. BofA Securities, Inc. has agreed to act as a qualified independent underwriter for this offering and to undertake the legal responsibilities and liabilities of an underwriter under the U.S. Securities Act, specifically including those inherent in Section 11 thereof. BofA Securities, Inc. will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify BofA Securities, Inc. against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act. See “Underwriting (Conflicts of Interest)” in this Prospectus Supplement.

Governing Law The Notes and the Indenture governing the Notes will be governed by the laws of the State of New York.

Risk Factors Investing in the Notes involves risks. See “Risk Factors” in this Prospectus Supplement beginning on page S-18 and under the heading “Risk Factors” beginning on page 28 of the accompanying Prospectus.

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RISK FACTORS

An investment in the Notes is subject to a number of risks. In addition to the other information contained in and incorporated by reference into this Prospectus Supplement and the accompanying Prospectus, you should consider carefully the risk factors set forth below and under the heading “Risk Factors” in the accompanying Prospectus, “Risk Factors” and “Governance and Risk Management” in the Annual MD&A and “Risk Factors” in the Annual Information Form. The risks and uncertainties described below, in the Prospectus and in the documents incorporated by reference are not the only ones we may face. Additional risks and uncertainties that we are unaware of, or that we currently deem to be immaterial, may also become important factors that affect us. If any of the following risks actually occurs, our business, financial condition or results of operations could be materially adversely affected, with the result that the trading price of the Notes could decline and you could lose all or part of your investment.

There is no public market for the Notes.

The Notes are a new issue of securities for which there is currently no public market. We do not intend to apply for listing of the Notes on any securities exchange or to arrange for the Notes to be quoted on any automated dealer quotation system. If the Notes are traded after their initial issue, they may trade at a discount from their initial offering prices, depending on prevailing interest rates, the market for similar securities and other factors, including general economic conditions and our financial condition. We cannot assure you as to the liquidity of the trading market for the Notes or that a trading market for the Notes will develop.

Changes in interest rates may cause the market value of the Notes to decline.

Prevailing interest rates will affect the market price or value of the Notes. The market price or value of the Notes may decline as prevailing interest rates for comparable debt instruments rise, and increase as prevailing interest rates for comparable debt securities decline.

The Notes are unsecured obligations of the Corporation.

The Notes will be our direct unsecured obligations, ranking equally and pari passu, except as to sinking fund or analogous provisions, with all of our other unsecured and unsubordinated indebtedness. The Notes will be effectively subordinated to all indebtedness and other liabilities of our subsidiaries and will be effectively subordinated to all of our existing and future secured indebtedness, to the extent of the value of the assets securing such secured indebtedness. If we are involved in any bankruptcy, dissolution, liquidation or reorganization, the holders of indebtedness and liabilities of our subsidiaries would be paid before the holders of Notes receive any amounts due under the Notes and the holders of our secured indebtedness would be paid before the holders of Notes receive any amounts due under the Notes, to the extent of the value of the assets securing such secured indebtedness. In that event, a holder of Notes may not be able to recover any principal or interest due under the Notes.

We may not be able to fulfill our repurchase obligations with respect to the Notes upon a change of control.

If we experience a Change of Control Triggering Event, we will be required to make an offer to repurchase all outstanding Notes at a repurchase price equal to 101% of the principal amount of the Notes repurchased, plus accrued and unpaid interest, if any, to the applicable repurchase date. Failure to repurchase, or to make an offer to repurchase, the Notes would constitute a default under the Indenture governing the Notes, which would also constitute a default under certain instruments governing our existing indebtedness. See “Description of Notes — Repurchase Upon Change of Control Triggering Event” in this Prospectus Supplement.

If a Change of Control Triggering Event were to occur, we cannot assure you that we would have sufficient funds to repay any Notes that we would be required to offer to repurchase, or to satisfy any other

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obligations that would become immediately due and payable under the other instruments governing our indebtedness, as a result of such Change of Control Triggering Event. In order to satisfy our obligations, we may attempt to refinance our indebtedness or obtain consents from our other lenders or from the holders of the Notes. We cannot assure you that we would be able to refinance our indebtedness or obtain such consents on satisfactory terms or at all.

Because the Indenture governing the Notes will not contain limits on the amount of additional debt that we may incur, our ability to make timely payments on the Notes you hold may be affected by the amount and terms of our future debt.

Our ability to make timely payments on our outstanding debt may depend on the amount and terms of our other obligations, including any notes. The Indenture governing the Notes will not contain any limitation on the amount of indebtedness or other liabilities that we or any of our subsidiaries may incur in the future, including additional senior debt securities. In the event we issue additional notes under the Indenture governing the Notes or incur other indebtedness, unless our earnings grow in proportion to our debt and other fixed charges, our ability to service the notes on a timely basis may become impaired. We expect that we will from time to time incur additional debt and other liabilities. In addition, TransAlta will not be restricted from paying dividends on or repurchasing its securities under the Indenture governing the Notes.

The Indenture governing the Notes will not require that we allocate an amount equal to the net proceeds from this offering to Eligible Projects or take the other actions described under “Green Financing Framework” in this Prospectus Supplement, and our failure to do so could adversely impact the value of the Notes.

The market price and tradability of the Notes may be impacted by any failure by us to allocate an amount equal to the net proceeds from this offering to Eligible Projects, take the other actions as described under “Green Financing Framework” in this Prospectus Supplement or to otherwise meet or continue to meet the investment requirements of certain sustainability-focused investors. Although we intend to allocate an amount equal to the net proceeds from this offering to Eligible Projects and take the other actions as described under “Green Financing Framework” in this Prospectus Supplement, it will not be an event of default under the Indenture governing the Notes nor will we be required to repurchase or redeem the Notes if we fail to do so. See “Green Financing Framework” in this Prospectus Supplement.

We may use or allocate an amount equal to the net proceeds from this offering in ways with which you may not agree.

We intend to allocate an amount equal to the net proceeds from this offering to finance or refinance, in part or in full, new and/or existing Eligible Projects and will use the net proceeds from this offering to repay $100 million drawn on the Credit Facility and to replace balance sheet cash used to fund the repayment in full of the 2022 Notes. See “Use of Proceeds” in this Prospectus Supplement. We may also allocate or re-allocate amounts relating to this offering to other new Eligible Projects. We have significant flexibility in allocating amounts relating to this offering, including re-allocating in the event we no longer own assets to which we allocated amounts relating to this offering or if the assets to which we allocated amounts related to this offering no longer meet the criteria for an Eligible Project. You may not agree with the ultimate allocation of amounts relating to this offering, even if we believe the expenditures to which we allocate such amounts were in respect of Eligible Projects.

We cannot assure you that the Eligible Projects to which we allocate amounts relating to this offering will satisfy, or continue to satisfy, investor criteria and expectations regarding environmental impact and sustainability performance nor can we assure you that the Eligible Projects criteria and other aspects of the framework described under “Green Financing Framework” in this Prospectus Supplement will satisfy, or continue to satisfy, investor criteria or expectations for sustainable finance products.

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Recent Canadian tax proposals

In February 2022, the Department of Finance (Canada) released draft legislation, including a proposal on interest deductibility. The proposal was open for public comment until May 2022 and was originally intended to be effective for taxation years beginning on or after January 1, 2023. On November 3, 2022, the Department of Finance (Canada) released revised legislative proposals relating to the interest deductibility proposals and, while the November 3, 2022 draft legislative provisions provided that the interest deductibility proposals would be effective for taxation years beginning on or after October 1, 2023, it is unknown when the legislation may be enacted. The November 3, 2022 draft legislative proposals are open for public comment until January 6, 2023. We will continue to assess the proposed changes in tax legislation as they could affect our business, financial condition and cash flows available to make payments to holders of the Notes.

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USE OF PROCEEDS

We expect that the net proceeds from this offering will be approximately US$393 million after deducting underwriting commissions and estimated expenses of this offering. We intend to allocate an amount equal to the net proceeds from this offering to finance or refinance, in part or in full, new and/or existing Eligible Projects.

Pending such allocation, we intend to use the net proceeds from this offering to repay $100 million drawn on the Credit Facility and replace balance sheet cash used to fund the repayment in full of the 2022 Notes. Certain of the underwriters or their respective affiliates are lenders under our credit facilities. Such underwriters or their affiliates may receive a portion of the net proceeds from this offering in connection with the repayment of indebtedness. See “Our Competitive Strengths — Prudent Financial Profile with Strong Liquidity and Access to Capital” and “Underwriting (Conflicts of Interest)” in this Prospectus Supplement.

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CAPITALIZATION

The following table summarizes our consolidated capitalization as of September 30, 2022, on an actual basis and on an (i) as adjusted basis to give effect to the repayment in full of the 2022 Notes effective November 15, 2022 and (ii) as further adjusted to give effect to the issuance Notes offered by this Prospectus Supplement. As noted under “Use of Proceeds”, we intend to use the net proceeds from this offering to repay $100 million drawn on the Credit Facility and to replace balance sheet cash used to fund the repayment in full of the 2022 Notes and, as a result, it is expected that this offering will not result in an increase in our long-term debt except to the extent of discounts, commissions and other expenses of the offering. You should read this table together with our unaudited consolidated financial statements for the three and nine months ended September 30, 2022 which are included in this Prospectus Supplement. All U.S. dollar amounts in the following table have been converted to Canadian dollars using the exchange rate of US$1 = C$1.366.

(in millions of Canadian dollars)	As at September 30, 2022			As adjusted at September 30, 2022(4)			As further adjusted at September 30, 2022(5)
Cash and Cash Equivalents	$	816		$	370		$	808
Indebtedness
Syndicated Bank Facility(1)		—		$	100			—
Bilateral Credit Facilities(1)		—			—			—
Term Facility(2)		—			—			—
Renewables Syndicated Bank Facility(3)		—			—			—
7.30% Debentures due 2029	$	110			110		$	110
6.90% Debentures due 2030		141			141			141
4.50% US$ Senior Notes due 2022		546			—			—
6.50% US$ Senior Notes due 2040		410			410			410
New US$400mm Senior Notes		—			—			546
Exchangeable Debentures		350			350			350
Lease Obligations & Other		106			106			106
Exchangeable Preferred Securities		400			400			400
Project Bonds		1,795			1,795			1,795
Tax Equity		133			133			133
Unamortized Issuance Costs		(44	)		(44	)		(52	)
Total Indebtedness		3,947			3,501			3,939
Total Shareholders’ Equity		2,417			2,417			2,417
Total Capitalization	$	6,364		$	5,918		$	6,356

Notes:

(1) As of November 12, 2022, under our Syndicated Bank Facility and Bilateral Credit Facilities, we have cumulative commitments available to be borrowed of $618 million (after giving effect to $872 million of outstanding letters of credit).

(2) As of November 12, 2022, we have commitments available to be borrowed under our Term Facility of $400 million (no outstanding letters of credit issued under the facility).

(3) As of November 12, 2022, we have commitments available to be borrowed under our TransAlta Renewables Syndicated Bank Facility of $585 million (after giving effect to $102 million of outstanding letters of credit and $13 million in borrowings).

(4) Reflects adjustments for the repayment of the 4.50% US$ Senior Notes due 2022 using $100 million of drawings on our Syndicated Bank facility and $446 million in cash.

(5) Reflects adjustments for the expected cash proceeds for the anticipated issuance of US$400 million and cash issuance costs of US$6 million using the exchange rate above.

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GREEN FINANCING FRAMEWORK

We intend to allocate an amount equal to the net proceeds from this offering to finance or refinance, in part or in full, new and/or existing Eligible Projects. See “Use of Proceeds” in this Prospectus Supplement.

Our Green Financing Framework has been developed in line with the GBP published by the ICMA. Our Green Financing Framework is intended to provide transparency to our issuances of green bonds, including the Notes, and reporting processes. The Green Financing Framework is based on the four core components of the GBP, being: (1) Use of Proceeds; (2) Process for Project Evaluation and Selection; (3) Management of Proceeds; and (4) Reporting. The Green Financing Framework also describes the manner in which green bonds support and contribute towards meeting the SDG. Under the Green Financing Framework, TransAlta may issue green bonds in various formats, according to the prevailing terms described in the documentation.

Use of Proceeds

An amount equivalent to the net proceeds from the issuance of the Notes will be allocated to finance or refinance, in part or in full, Eligible Projects providing tangible environmental benefits. TransAlta will follow the process described in the Green Financing Framework along with its professional judgement, discretion and sustainability expertise when identifying the Eligible Projects.

In the case of refinancing existing Eligible Projects, investments and expenditures that have been made within the 36-month period preceding the date of issuance of the Notes shall be considered for inclusion as Eligible Projects. TransAlta will fully allocate the net proceeds of the Notes within 24-months of issuance.

Eligible Projects

Project Category	Eligible Criteria	Alignment with UN SDG
Renewable Energy	•   Proceeds may be allocated to the construction, development, operation, acquisition, maintenance, connection, transmission and distribution of the following renewable energy generation sources: •  Solar or solar-plus-storage •  Wind or wind-plus-storage •  Refurbishment, operation or maintenance of existing hydroelectric facilities provided the size of the dam or reservoir is not increased •  Run of river hydroelectric power or hydro-plus-storage •  Green hydrogen (<36.4g CO2e/MJ)	7, 13
Energy Efficiency	•   Proceeds may be allocated to products and systems that reduce energy consumption or mitigate emissions, including: •  Development of large-scale, long duration energy storage projects	7, 11, 13

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Process for Project Evaluation and Selection

TransAlta has established a Green Bond Committee (the “Committee”) at the Management level with responsibility for governing the selection and monitoring of the Eligible Projects. The Committee will be chaired by the Treasurer and include senior members of the following teams representing TransAlta: Finance, Legal and Sustainability.

The Committee will be principally responsible for: (1) evaluating and selecting Eligible Projects; (2) annually reviewing the list of previously allocated Eligible Projects against the eligibility criteria; and (3) reviewing and approving updates to the Green Financing Framework.

When evaluating Eligible Projects, the Committee will assess whether the Eligible Projects meet the eligibility criteria laid out in the “Use of Proceeds” section of the Green Financing Framework. Projects must also comply with applicable laws and regulations and TransAlta’s policies and guidelines, such as our Total Safety Management Policy.

Additionally, the Committee will, if a project no longer meets the eligibility criteria set forth in the Green Financing Framework, review and approve removing it and replacing it with another Eligible Project.

Sustainability is overseen by TransAlta’s Governance, Safety and Sustainability Committee (“GSSC”) of the Board of Directors of TransAlta (the “Board”). The GSSC assists the Board in fulfilling its oversight responsibilities with respect to TransAlta’s monitoring of climate change, environmental, health and safety regulations, public policy changes and the development of strategies, policies and practices for climate change, environment, health and safety, and social well-being, including human rights, working conditions and responsible sourcing.

Management of Proceeds

TransAlta’s treasury team will manage the allocation of an amount equal to the net proceeds of the Notes to Eligible Projects. Net proceeds will be recorded separately in TransAlta’s records in order to clearly track the use of and allocation of funds for Eligible Projects. TransAlta will strive to achieve a level of allocation to the Eligible Project portfolio that matches or exceeds the balance of net proceeds of the outstanding Notes within 24 months of issuance.

Pending full allocation of an amount equal to the net proceeds of the outstanding Notes, the proceeds will be held in temporary investments such as cash, cash equivalents and/or other liquid marketable investments in line with TransAlta’s financial policies or used to pay outstanding indebtedness.

Payment of principal and interest on the Notes will not be directly linked to the performance of any eligible asset.

If any Eligible Projects are removed from the portfolio of Eligible Projects, TransAlta will strive to substitute those projects with replacement eligible projects, as soon as possible and in any case within 24 months.

Reporting

For each issuance of green bonds, including the Notes, TransAlta commits to publish an allocation and impact report annually within one year of issuance until full allocation of the proceeds and in the event of any material changes until the relevant maturity date. TransAlta’s green bond reporting, including in respect of the Notes, will be made publicly available on our website.

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Allocation Reporting

TransAlta will provide information on the allocation of the net proceeds of the Notes on its website. The information will contain at least the following details: (1) net proceeds of outstanding Notes; (2) the proportion of spending by Eligible Project category as defined in the Use of Proceeds section of the Green Financing Framework; (3) subject to confidentiality considerations, a list of the Eligible Projects financed through the Notes, including a description of the projects and allocated amounts; and (4) the remaining balance of unallocated proceeds, if any.

Impact Reporting

TransAlta will report on relevant environmental impact metrics, where feasible and on a proportion-funded basis, and disclose measurement methodology. Examples of impact metrics that may be reported are found in the below table.

Eligible Project Category	Potential Quantitative Impact Metrics
Renewable Energy	•   Total installed capacity (MW) •   GHG emissions avoided per year (tCO2e)
Energy Efficiency	•   Total installed capacity of energy storage (MWh) •   Energy use reduction (GJ) •   GHG emissions reduced/avoided (tCO2e)

External Review

TransAlta’s Green Financing Framework is supported by a second-party opinion, available on our website, and a post-issuance external verification on reporting.

Information contained on our website (including allocation reports, impact reports and second-party opinions) or the website of our second-party opinion provider, is not and should not be deemed to be a part of this Prospectus Supplement or the accompanying Prospectus. In addition, the Green Financing Framework is not and should not be deemed to be a part of this Prospectus Supplement or the accompanying Prospectus.

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DESCRIPTION OF NOTES

The following description of the terms of the Notes supplements, and to the extent inconsistent therewith replaces, the description set forth under the heading “Description of Debt Securities” in the accompanying Prospectus and should be read in conjunction with such description. In this section, “Corporation” refers only to TransAlta Corporation and not to any of its subsidiaries, unless otherwise stated. All capitalized terms used under this heading “Description of Notes” that are not defined herein have the meanings ascribed thereto in the accompanying Prospectus.

General

The Notes will be direct unsecured obligations of the Corporation and will rank equally and ratably with all other unsubordinated and unsecured indebtedness of the Corporation.

Payment of the principal, premium, if any, and interest on the Notes will be made in U.S. dollars.

The provisions of the Indenture relating to the payment of additional amounts in respect of Canadian withholding taxes in certain circumstances (described under the heading “Description of Debt Securities — Payment of Additional Amounts” in the accompanying Prospectus) and the provisions of the Indenture relating to the redemption of Notes in the event of specified changes in Canadian withholding tax laws or the enforcement or interpretation thereof on or after the date of this Prospectus Supplement (described under the heading “Description of Notes — Tax Redemption” in this Prospectus Supplement) will apply to the Notes, except (i) as described under the heading “Certain Income Tax Considerations — Certain U.S. Federal Income Tax Considerations — FATCA” in this Prospectus Supplement, (ii) that for the purposes of Section 10.5 of the Indenture, a “Holder” of a Note shall include a beneficial owner thereof, and (iii) that in addition to the exclusions contained in the Indenture, no additional amounts will be paid in the following circumstances:

(a) where the payment is in respect of a debt or other obligation to pay an amount to a person with whom the Corporation is not dealing at arm’s length for the purposes of the Income Tax Act (Canada) (the “Tax Act”);

(b) to any person in respect of whom such Canadian Taxes (as defined in the accompanying Prospectus) are required to be withheld or deducted as a result of such person being a “specified non-resident shareholder” of the Corporation (within the meaning of subsection 18(5) of the Tax Act) at the time of the payment or such person not dealing at arm’s length for the purposes of the Tax Act with a “specified shareholder” (within the meaning of subsection 18(5) of the Tax Act) of the Corporation at the time of payment;

(c) where Canadian Taxes (as defined in the accompanying Prospectus) are required to be withheld or deducted as a result of the Corporation being a “specified entity” (as defined in proposed subsection 18.4(1) of the Tax Act released on April 29, 2022 by the Minister of Finance (Canada), or substantially analogous provisions of any finally enacted amendment to the Tax Act) in respect of the recipient of a payment, to the extent that the applicable payment would be subject to withholding tax under such Act as a consequence of such proposals or provisions; or

(d) for any combination of any of the items described in paragraphs (a) to (c) above or paragraphs (a) to (f) under the heading “Description of Debt Securities — Payment of Additional Amounts” in the accompanying Prospectus.

The Notes will initially be issued in an aggregate principal amount of US$400 million and will mature on November 15, 2029. The Notes will bear interest at the rate of 7.750% per annum from November 17, 2022 or from the most recent date to which interest has been paid or provided for, payable semi-annually on November 15 and May 15 of each year, commencing May 15, 2023, to the persons in whose names the Notes are registered at the close of business on the preceding May 1 or November 1, respectively. Interest shall be computed assuming a 360-day year consisting of twelve 30-day months.

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The Corporation may from time to time, without the consent of the holders of the Notes, issue additional Notes after this offering. The Notes and any additional Notes subsequently issued under the Indenture will be treated as a single class for all purposes under the Indenture (except in respect of the payment of interest accruing prior to the issue date of the additional Notes and the first payment of interest following the issue date of the additional Notes), including, without limitation, waivers, amendments, redemptions and offers to purchase.

The Notes will be issuable in minimum denominations of US$2,000 or integral multiples of US$1,000 in excess thereof.

The Notes will not be entitled to the benefits of any sinking fund.

Optional Redemption

On and after November 15, 2025, the Corporation may, at its option on one or more occasions, redeem all or a part of the Notes, upon notice as described under “— Selection and Notice”, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, on the Notes to be redeemed to, but not including, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), if redeemed during the twelve-month period beginning on November 15 of the years indicated below:

Year	Percentage
2025		103.875	%
2026		101.938	%
2027 and thereafter		100.000	%

At any time prior to November 15, 2025, the Corporation may, at its option on one or more occasions redeem up to 35% of the aggregate principal amount of the Notes (including additional Notes) originally issued under the Indenture, upon notice as described under “— Selection and Notice”, at a redemption price of 107.750% of the principal amount, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), with an amount of cash not greater than the net cash proceeds of one or more Equity Offerings by the Corporation, provided, that for purposes of calculating the principal amount of the Notes able to be redeemed with such cash proceeds of such Equity Offering or Equity Offerings, such amount shall include only the principal amount of the Notes to be redeemed plus the premium on such Notes to be redeemed, provided further that:

(1) at least 65% of the aggregate principal amount of the Notes (including additional Notes) originally issued under the Indenture remains outstanding immediately after the occurrence of such redemption (excluding Notes held by the Corporation and its Subsidiaries); and

(2) the redemption occurs within 180 days of the date of the closing of the related Equity Offering.

In addition, at any time prior to November 15, 2025, the Corporation may, at its option on one or more occasions, redeem all or a part of the Notes, upon notice as described under “— Selection and Notice”, at a redemption price equal to the sum of:

(1) 100.0% of the principal amount thereof, and

(2) the Make Whole Premium (as defined herein) as of the applicable redemption date,

plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

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“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York, Calgary, Alberta or another place of payment are authorized or required by law to close

“Equity Offering” means any public or private sale of capital stock of the Corporation made on a primary basis by the Corporation (other than (x) capital stock that is mandatorily redeemable or otherwise required to be repurchased at the option of the holder thereof on or prior to the date that is 91 days after the date on which the Notes mature and (y) any sale to a subsidiary of the Corporation).

“Make Whole Premium” means, with respect to a Note as of any redemption date for such Note whose redemption price may be determined by reference to the Make Whole Premium, the excess, if any, of (1) the present value as of the applicable redemption date of (a) the redemption price of such Note at November 15, 2025 (such redemption price being set forth in the first full paragraph of this “— Optional Redemption” section) plus (b) any required interest payments due on such Note through November 15, 2025 (except for accrued and unpaid interest to, but not including, the applicable redemption date), computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over (2) the then-outstanding principal amount of such Note.

“Treasury Rate” means, with respect to any redemption date for any Note whose redemption price may be determined by reference to the Make Whole Premium, the yield to maturity as of the redemption date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Selected Interest Rates (Daily) - H.15 that has become publicly available at least two Business Days prior to such date (or, if such Statistical Release is no longer published, any publicly available source of similar market data selected by the Corporation)) most nearly equal to the period from such date to November 15, 2025; provided, that if such period is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Corporation shall obtain the Treasury Rate by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to November 15, 2025 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used. Calculation of the Make Whole Premium and the Treasury Rate will be made by the Corporation or on behalf of the Corporation by such Person as the Corporation shall designate. The Corporation will (1) calculate the Treasury Rate and the Make Whole Premium no later than the first (and no earlier than the fourth) Business Day preceding the applicable redemption date (or, in the case of any redemption in connection with a defeasance of the Notes or a satisfaction and discharge of the Indenture, on the Business Day preceding such event), and (2) prior to such redemption date (or such event, as applicable), file with the Trustee a statement setting forth the Treasury Rate and the Make Whole Premium and showing the calculation of each in reasonable detail.

Repurchase Upon Change of Control Triggering Event

If a Change of Control Triggering Event occurs, unless the Corporation has exercised its right to redeem the Notes as described under “— Optional Redemption”, each holder of Notes will have the right to require the Corporation to purchase all or a portion of such holder’s Notes pursuant to the offer described below (the “Change of Control Offer”). In the Change of Control Offer, the Corporation will offer a payment (the “Change of Control Payment”) equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of purchase, subject to the rights of holders of Notes on the relevant record date to receive interest due on the relevant interest payment date.

Within 30 days following the date upon which the Change of Control Triggering Event occurred, or at the Corporation’s option, prior to any Change of Control but after the public announcement of the pending Change of Control, the Corporation will be required to send, by first class mail, a notice to each holder of Notes,

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with a copy to the Trustee (as hereinafter defined), which notice will govern the terms of the Change of Control Offer. Such notice will state, among other things, the purchase date, which must be no earlier than 10 days nor later than 60 days from the date such notice is mailed, other than as may be required by law (the “Change of Control Payment Date”). The notice, if mailed prior to the date of consummation of the Change of Control, will state that the Change of Control Offer is conditional on the Change of Control being consummated on or prior to the Change of Control Payment Date. Each holder of Notes electing to have Notes purchased pursuant to a Change of Control Offer will be required to surrender their Notes, with the form entitled “Option of Holder to Elect Purchase” on the reverse of the Note completed, to the paying agent at the address specified in the notice, or transfer their Notes to the paying agent by book-entry transfer pursuant to the applicable procedures of the paying agent, prior to the close of business on the third business day prior to the Change of Control Payment Date.

The Corporation will not be required to make a Change of Control Offer if (a) a third party makes such an offer in the manner, at the times and otherwise in compliance with the requirements for such an offer made by the Corporation and such third party purchases all Notes properly tendered and not withdrawn under its offer; (b) a notice of redemption has been given, unless and until there is a default in payment of the applicable redemption price or (c) in connection with or in contemplation of any Change of Control, the Corporation or a third party has made an offer to purchase (an “Alternate Offer”) any and all Notes validly tendered at a cash price equal to or higher than the Change of Control Payment and has purchased all Notes properly tendered in accordance with the terms of such Alternate Offer. Notwithstanding anything to the contrary contained herein, a Change of Control Offer, tender offer or Alternate Offer by the Corporation or a third party may be made in advance of a Change of Control Triggering Event or Change of Control, conditioned upon the occurrence of such Change of Control Triggering Event or a Change of Control, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer, tender offer or Alternate Offer is made.

In connection with any Change of Control Offer, tender offer or Alternate Offer by the Corporation or any third party to purchase all of the Notes, if holders of not less than 90.0% of the aggregate principal amount of the then outstanding Notes validly tender and do not validly withdraw such Notes in connection with such Change of Control Offer, tender offer or Alternate Offer and the Corporation or such third party purchases all of the Notes validly tendered and not validly withdrawn by such holders, all of the holders of the Notes will be deemed to have consented to such Change of Control Offer, tender offer or Alternate Offer and accordingly, the Corporation or such third party (as applicable) will have the right upon not less than 10 days’ nor more than 60 days’ prior written notice, given not more than 60 days following such purchase date pursuant to the Change of Control Offer, tender offer or Alternate Offer, to purchase all Notes that remain outstanding following such purchase at a purchase price equal to the highest price offered to each other holder in such Change of Control Offer, tender offer or Alternate Offer, plus, to the extent not included in the Change of Control Offer, tender offer or Alternate Offer, accrued and unpaid interest to, but excluding, the applicable purchase date (subject to the right of the holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the applicable purchase date).

The definition of Change of Control includes a phrase relating to the direct or indirect sale, transfer, conveyance or other disposition of “all or substantially all” of the assets of the Corporation and its subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of Notes to require the Corporation to repurchase its Notes as a result of a sale, transfer, conveyance or other disposition of less than all of the assets of the Corporation and its subsidiaries taken as a whole to another “person” may be uncertain. In addition, a recent Delaware Chancery Court decision raised questions about the enforceability of provisions, which are similar to those in the Indenture, related to the triggering of a change of control as a result of a change in the composition of a board of directors. Accordingly, the ability of a holder of Notes to require the Corporation to repurchase its Notes as a result of a change in the composition of the board of directors of the Corporation may be uncertain.

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To the extent that the provisions of any applicable securities laws or regulations conflict with the Change of Control provisions of the Indenture, the Corporation will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the Indenture by virtue of such compliance.

“Ratings Decline” means the occurrence of a decrease in the rating of the Notes by one or more gradations (including gradations within the rating categories, as well as between categories) by each of the Rating Agencies, within 60 days of the earliest of (a) a Change of Control, (b) the date of public notice of the occurrence of a Change of Control or (c) public notice of the intention of the Corporation to effect a Change of Control (which 60 day period shall be extended so long as the rating of the Notes is under publicly announced consideration for possible downgrade by an a Rating Agency); provided, however, that notwithstanding the foregoing, a Ratings Decline shall be deemed not to have occurred if any of the Rating Agencies rates the Notes with an Investment Grade Rating that is not subject to review for possible downgrade on such 60^th day.

The Trustee shall not be charged with knowledge of, or be responsible for the monitoring of, the ratings of the Notes.

“Change of Control” means the occurrence of any of the following:

(a) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger, amalgamation, arrangement or consolidation), in one or more series of related transactions, of all or substantially all of the Corporation’s assets and the assets of its subsidiaries, taken as a whole, to any person, other than to the Corporation or one of its subsidiaries;

(b) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any person (other than a subsidiary of the Corporation) becomes the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the U.S. Exchange Act), directly or indirectly, of more than 50% of the Corporation’s outstanding Voting Shares or other Voting Shares into which the Corporation’s Voting Shares are reclassified, consolidated, exchanged or changed, measured by voting power rather than number of shares;

(c) the Corporation consolidates with, or merges or amalgamates with or into, or enters into an arrangement with, any person, or any person consolidates with, or merges or amalgamates with or into, the Corporation, in any such event pursuant to a transaction in which any of the Corporation’s outstanding Voting Shares or the Voting Shares of such other person are converted into or exchanged for cash, securities or other property, other than any such transaction where the Corporation’s Voting Shares outstanding immediately prior to such transaction constitute, or are converted into or exchanged for, a majority of the Voting Shares of the surviving person or any direct or indirect parent company of the surviving person immediately after giving effect to such transaction; or

(d) the adoption of a plan relating to the liquidation or dissolution of the Corporation.

Notwithstanding the foregoing, (1) a transaction will not be deemed to involve a Change of Control under clause (b) above if (i) we become a direct or indirect wholly-owned subsidiary of a holding company and (ii) (A) the direct or indirect holders of the Voting Shares of such holding company immediately following that transaction are substantially the same as the holders of the Corporation’s Voting Shares immediately prior to that transaction or (B) immediately following that transaction no person (other than a holding company satisfying the requirements of this sentence) is the beneficial owner, directly or indirectly, of more than 50% of the Voting Shares of such holding company; and (2) the term “Change of Control” shall include a merger, amalgamation or consolidation of the Corporation with, or the sale, lease, transfer, conveyance or other disposition of all or substantially all of the assets of the Corporation and its subsidiaries taken as a whole to, an affiliate of the Corporation that is incorporated or organized solely for the purpose of reincorporating or reorganizing the Corporation in another jurisdiction, which is not otherwise prohibited by the terms of the Indenture. The term “person”, as used in this definition, has the meaning given thereto in Section 13(d)(3) of the U.S. Exchange Act.

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“Change of Control Triggering Event” means the occurrence of both a Change of Control and so long as the Notes are rated, a related Ratings Decline.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s and BBB– (or the equivalent) by S&P, or, in each case, if such Rating Agency ceases to make a rating of the Notes publicly available, the equivalent investment grade credit rating by the replacement agency selected by the Corporation in accordance with the procedures described below.

“Rating Agencies” means Moody’s and S&P; and if either ceases to make a rating of the Notes publicly available, a “nationally recognized statistical rating organization”, within the meaning of Sections 3(a)(62) under the U.S. Exchange Act, selected by the Corporation (as certified by a resolution of the Corporation’s board of directors) as a replacement agency for Moody’s or S&P, or each of them, as the case may be.

“Voting Shares” means, with respect to any specified person as of any date, the shares of such person that is at the time entitled to vote generally in the election of the board of directors of such person.

Tax Redemption

The Notes will be subject to redemption at any time, in whole but not in part, at the option of the Corporation, at a redemption price equal to the principal amount thereof together with accrued and unpaid interest to the date fixed for redemption, upon the giving of a notice as described below in “—Selection and Notice”, if (1) the Corporation determines that (a) as a result of any change in or amendment to the laws (or any regulations or rulings promulgated thereunder) of Canada or of any political subdivision or taxing authority thereof or therein affecting taxation, or any change in official position regarding application or interpretation of such laws, regulations or rulings (including a holding by a court of competent jurisdiction), which change or amendment is announced or becomes effective on or after the date of this Prospectus Supplement, the Corporation has or will become obligated to pay, on the next succeeding date on which interest is due, additional amounts with respect to the Notes as described under “Description of Debt Securities—Payment of Additional Amounts” in the accompanying Prospectus; or (b) on or after the date of this Prospectus Supplement, any action has been taken by any taxing authority of, or any decision has been rendered by a court of competent jurisdiction in, Canada or any political subdivision or taxing authority thereof or therein, including any of those actions specified in (a) above, whether or not such action was taken or decision was rendered with respect to the Corporation, or any change, amendment, application or interpretation shall be officially proposed, which, in any such case, in the written opinion to the Corporation of legal counsel of recognized standing, will result in the Corporation becoming obligated to pay, on the next succeeding date on which interest is due, additional amounts with respect to the Notes and (2) in any such case, the Corporation in its business judgment determines that such obligation cannot be avoided by the use of reasonable measures available to the Corporation; provided, however, that (i) no such notice of redemption may be given earlier than 60 days prior to the earliest date on which the Corporation would be obligated to pay such additional amounts were a payment in respect of the Notes then due, and (ii) at the time such notice of redemption is given, such obligation to pay such additional amounts remains in effect; and provided, further, that any such notice of redemption shall be given no later than 30 days prior to such redemption.

In the event that the Corporation elects to redeem the Notes pursuant to the provisions set forth in the preceding paragraph, the Corporation shall deliver to the Trustee a certificate, signed by an authorized officer, stating that the Corporation is entitled to redeem the Notes pursuant to their terms.

Prior to the publication or, where relevant, mailing of any notice of redemption of the Notes pursuant to the foregoing, the Corporation will deliver the Trustee an opinion of counsel to the effect that there has been such change or amendment which would entitle the Corporation to redeem the notes hereunder. In addition, before the Corporation publishes or mails notice of redemption of the Notes as described above, it will deliver to the

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Trustee a certificate, signed by an authorized officer, stating that the Corporation cannot avoid its obligation to pay additional amounts by taking reasonable measures available to it and all other conditions for such redemption have been met.

The Trustee shall be entitled to rely on such officer’s certificate and opinion of counsel as sufficient evidence of the existence and satisfaction of the conditions precedent as described above, in which event it will be conclusive and binding on the holders of the Notes. The Trustee shall not be responsible for the determination of any redemption price.

Selection and Notice

Notice of any redemption will be mailed by first class mail (or sent electronically if DTC is the recipient) at least 10 days but not more than 60 days before the redemption date to each holder of Notes to be redeemed at its registered address. No Notes of US$2,000 or less can be redeemed in part.

Notes called for redemption will become due on the date fixed for redemption, subject to the Corporation’s right to delay or rescind an optional redemption date as provided below. Unless the Corporation defaults in payment of the redemption price, on and after the redemption date, interest will cease to accrue on the Notes or portions thereof called for redemption. If fewer than all of the Notes of the applicable series are to be redeemed, the particular Notes or portions thereof to be redeemed will be selected, not more than 60 days prior to the redemption date, from the outstanding Notes of such series not previously called (a) if such Notes are held in global form, in accordance with the procedures of DTC or (b) if such Notes are held in certificated form, on a pro rata basis.

Notice of any optional redemption of the Notes may, at the Corporation’s discretion, be subject to one or more conditions precedent, including, but not limited to, (i) the completion of one or more Equity Offerings or other securities offerings or other financings or the completion of any transaction (or series of related transactions) that constitute a Change of Control; and (ii) any other instructions, as determined by the Corporation, that a holder of Notes must follow. If an optional redemption of the Notes is subject to satisfaction of one or more conditions precedent, such notice may state that, at the Corporation’s discretion, the redemption date may be delayed on one or more occasions either to a date specified in a subsequent notice to holders of the Notes or until such time (which date or time may be more than 60 days after the date the notice of redemption was mailed or otherwise sent) as any or all such conditions shall be satisfied or waived, and that such redemption will not occur and such notice will be rescinded if any or all such conditions shall not have been satisfied as and when required (as determined by the Corporation in its sole discretion taking into account any election by the Corporation to delay such redemption date), unless the Corporation has waived any such conditions that are not satisfied, or at any time if in the good faith judgment of the Corporation any or all of such conditions will not be satisfied. In addition, such notice will state that no representation is made as to the correctness or accuracy of the CUSIP, ISIN or similar number, if any, listed in such notice or printed on the Notes.

If any Note is to be redeemed in part only, the notice of redemption that relates to that Note will state the portion of the principal amount of that Note that is to be redeemed. A new Note in principal amount equal to the unredeemed portion of the original Note will be issued in the name of the holder of Notes upon cancellation of the original Note.

The Indenture

The Notes will be issued under the Indenture. The Indenture is subject to, and governed by, the U.S. Trust Indenture Act of 1939, as amended. Whenever there are references to particular provisions of the Indenture, those provisions are qualified in their entirety by reference to the Indenture. References in parentheses are to section numbers of the Indenture. All capitalized terms used under this heading “The Indenture” that are not defined herein have the meanings ascribed thereto in the Indenture.

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Events of Default

The following events are defined in the Indenture as “Events of Default” with respect to debt securities of any series: (a) the failure of the Corporation to pay when due the principal of or premium (if any) on the Notes; (b) the failure of the Corporation, continuing for 30 days, to pay any interest due on the Notes; (c) the breach or violation of any covenant or condition (other than as referred to in (a) and (b) above), which continues for a period of 60 days after notice from the Trustee or from holders of at least 25% in principal amount of all outstanding Notes of any series affected thereby; (d) the failure of the Corporation or any Subsidiary to pay when due (after giving effect to any applicable grace periods) any amount owing in respect of any Indebtedness other than Non-Recourse Debt, or the Corporation or any Subsidiary otherwise defaults in the performance or observance of any other covenant, term, agreement or condition in connection with such Indebtedness, and if such Indebtedness has not matured it shall have been accelerated prior to the date on which the same would otherwise have become due and payable, provided that the aggregate principal amount of such Indebtedness is in excess of the greater of US$75 million and 3% of Consolidated Shareholders’ Equity (provided that if such default is waived by the persons entitled to do so, then the Event of Default in this clause (d) will be deemed to be waived without further action on the part of the Trustee or the holders of the Notes); (e) the entry of certain judgments or decrees against the Corporation or any Material Subsidiary for the payment of money in excess of the greater of US$75 million and 3% of Consolidated Shareholders’ Equity, in the aggregate, if the Corporation or any such Material Subsidiary, as the case may be, fails to pay such decree or judgment within 60 days or file an appeal thereof within 60 days or, if the Corporation or such Material Subsidiary, as the case may be does file an appeal, that judgment or decree continues undischarged or unstayed as provided in the Indenture; or (f) certain events of bankruptcy, insolvency or reorganization involving the Corporation or a Material Subsidiary.

Mergers, Consolidations, Amalgamations and Sale of Assets

The Corporation will not enter into any transaction whereby all or substantially all of its undertaking, property and assets would become the property of any other person (the “Successor”), whether by reorganization, consolidation, amalgamation, arrangement, merger, transfer, sale, or otherwise, unless:

(a) the Successor expressly assumes all of the covenants and obligations of the Corporation under the Indenture and the transaction otherwise meets all of the requirements of the Indenture;

(b) the entity formed by or continuing from such consolidation or amalgamation or into which the Corporation is merged or with which the Corporation enters into such arrangement or the person which acquires or leases all or substantially all of the Corporation’s properties and assets is organized and existing under the laws of the United States, any state thereof or the District of Columbia or the laws of Canada or any province thereof;

(c) immediately before and after giving effect to such transaction, no Event of Default, and no event which, after notice or lapse of time or both, would become an Event of Default, shall have happened and be continuing; and

(d) no condition or event will exist as to the Corporation (at the time of such transaction) or the Successor (immediately after such transaction) and after giving full effect thereto or immediately after the Successor will become liable to pay the principal monies, premium, if any, interest and other monies due or which may become due hereunder, which constitutes or would constitute an Event of Default under the Indenture.

In addition to the above conditions, such transaction will substantially preserve and not impair any of the rights and powers of the Trustee or of the holders of Notes (Section 8.1).

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Covenants

The Indenture covenants substantially to the following effect:

Restriction on Sales and Leasebacks

The Corporation will not, and will not permit any Subsidiary to, enter into any sale and leaseback transaction unless the Corporation and its Subsidiaries comply with this restrictive covenant. A “sale and leaseback transaction” is an arrangement between the Corporation or any Subsidiary and a bank, insurance company or other lender or investor where the Corporation or any Subsidiary lease real or personal property which was or will be sold by the Corporation or any Subsidiary to that lender or investor. The Corporation can comply with this restrictive covenant if it meets either of the following conditions:

(a) the sale and leaseback transaction is entered into prior to, concurrently with or within 270 days after the acquisition, the completion of construction (including any improvements on an existing property) or the commencement of commercial operations of the property; or

(b) the Corporation or its Subsidiaries could otherwise grant a Security Interest on the property as permitted by the provisions of the covenant (described under the heading “—Negative Pledge” in the accompanying Prospectus) (Section 10.10).

Negative Pledge

So long as any Notes remain outstanding the Corporation and its Subsidiaries will not create, assume or otherwise have outstanding any Security Interest, except for Permitted Encumbrances, on or over its or their respective assets (present or future) in respect of any Indebtedness of any person unless, in the opinion of legal counsel to the Corporation, the obligations of the Corporation in respect of all Notes then outstanding shall be secured equally and rateably therewith (Section 10.12).

“Attributable Amount” means with respect to any sale and leaseback transaction (as defined herein under the heading “Covenants—Restriction on Sales and Leasebacks” below), as at the time of determination, the present value (discounted at the rate of interest set forth or implicit in the terms of such lease, compounded annually) of the total obligations of the lessee for rental payments during the remaining term of the lease included in such sale and leaseback transaction.

“Consolidated Net Tangible Assets” means all consolidated assets of the Corporation as shown on the most recent audited consolidated balance sheet of the Corporation, less the aggregate of the following amounts reflected upon such balance sheet: (i) all goodwill, deferred assets, trademarks, copyrights and other similar intangible assets; (ii) to the extent not already deducted in computing such assets and without duplication, depreciation, depletion, amortization, reserves and any other account which reflects a decrease in the value of an asset or a periodic allocation of the cost of an asset; provided that no such deduction shall be made to the extent such account reflects a decrease in the value or periodic allocation of the cost of any assets referred to in (i) above; (iii) minority interests; (iv) current liabilities; and (v) assets created, developed, constructed or acquired with or in respect of which Non-Recourse Debt has been incurred, and any and all receivables, inventory, equipment, chattel paper, intangibles and other rights or collateral arising from or connected with those assets (including the shares or other ownership interests of a single purpose entity which holds only such assets and other rights and collateral arising from or connected therewith) and to which recourse of the lender of such Non-Recourse Debt is limited to the extent of the outstanding Non-Recourse Debt financing such assets.

“Consolidated Shareholders’ Equity” means, without duplication, the aggregate amount of shareholders’ equity (including, without limitation, common share capital, preferred share capital, contributed surplus and retained earnings) of the Corporation as shown on the most recent audited consolidated balance sheet of the Corporation, adjusted by the amount by which common share capital, preferred share capital and

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contributed surplus has been increased or decreased (as the case may be) from the date of such balance sheet to the relevant date of determination, in accordance with Generally Accepted Accounting Principles, together with the aggregate principal amount of obligations of the Corporation in respect of Preferred Securities.

“Financial Instrument Obligations” means obligations arising under:

(a) any interest swap agreement, forward rate agreement, floor, cap or collar agreement, futures or options, insurance or other similar agreement or arrangement, or any combination thereof, entered into or guaranteed by the Corporation where the subject matter of the same is interest rates or the price, value, or amount payable thereunder is dependent or based upon the interest rates or fluctuations in interest rates in effect from time to time (but, for certainty, shall exclude conventional floating rate debt);

(b) any currency swap agreement, cross currency agreement, forward agreement, floor, cap or collar agreement, futures or options, insurance or other similar agreement or arrangement, or any combination thereof, entered into or guaranteed by the Corporation where the subject matter of the same is currency exchange rates or the price, value or amount payable thereunder is dependent or based upon currency exchange rates or fluctuations in currency exchange rates in effect from time to time; and

(c) any agreement for the making or taking of any commodity (including natural gas, oil or electricity), any commodity swap agreement, floor, cap or collar agreement or commodity future or option or other similar agreements or arrangements, or any combination thereof, entered into or guaranteed by the Corporation where the subject matter of the same is any commodity or the price, value or amount payable thereunder is dependent or based upon the price of any commodity or fluctuations in the price of any commodity;

to the extent of the net amount due or accruing due by the Corporation thereunder (determined by marking to market the same in accordance with their terms).

“Generally Accepted Accounting Principles” means generally accepted accounting principles which are in effect from time to time in Canada.

“Indebtedness” means all items of indebtedness in respect of any amounts borrowed (including obligations with respect to bankers’ acceptances and contingent reimbursement obligations relating to letters of credit and other financial instruments) and all Purchase Money Obligations which, in accordance with Generally Accepted Accounting Principles, would be recorded in the financial statements as at the date as of which Indebtedness is to be determined, and in any event including, without duplication: (i) obligations secured by any Security Interest existing on property owned subject to such Security Interest, whether or not the obligations secured thereby shall have been assumed; and (ii) guarantees, indemnities, endorsements (other than endorsements for collection in the ordinary course of business) or other contingent liabilities in respect of obligations of another person for indebtedness of that other person in respect of any amounts borrowed by them.

“Material Subsidiary” means, at any time, a Subsidiary (i) the total assets of which represent more than 10% of the total assets of the Corporation determined on a consolidated basis as shown in the most recent audited consolidated balance sheet of the Corporation; or (ii) the total revenues of which represent more than 10% of the total revenues of the Corporation determined on a consolidated basis as shown in the consolidated income statement of the Corporation for the four most recent fiscal quarters of the Corporation.

“Non-Recourse Debt” means any Indebtedness incurred to finance the creation, development, construction or acquisition of assets and any increases in or extensions, renewals or refundings of any such Indebtedness, provided that the recourse of the lender thereof or any agent, trustee, receiver or other person acting on behalf of the lender in respect of such Indebtedness in respect thereof is limited in all circumstances

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(other than in respect of false or misleading representations or warranties and customary indemnities provided with respect to such financings) to the assets created, developed, constructed or acquired in respect of which such Indebtedness has been incurred and to any receivables, inventory, equipment, chattel paper, intangibles and other rights or collateral arising from or connected with the assets so created, developed, constructed or acquired (including the shares or other ownership interests of a single purpose entity which holds only such assets and other rights and collateral arising from or connected therewith) and to which the lender has recourse.

“Permitted Encumbrance” means any of the following:

(a) any Security Interest existing as of the date of the first issuance by the Corporation of Securities issued pursuant to the Indenture, or arising thereafter pursuant to contractual commitments entered into prior to such issuance;

(b) any Security Interest created, incurred or assumed to secure any Purchase Money Obligation;

(c) any Security Interest created, incurred or assumed to secure any Non-Recourse Debt;

(d) any Security Interest in favor of any Wholly-Owned Subsidiary;

(e) any Security Interest on property of a corporation or its Subsidiaries which Security Interest exists at the time such corporation is merged into, or amalgamated or consolidated with the Corporation or such property is otherwise, directly or indirectly acquired by the Corporation other than a Security Interest incurred in contemplation of such merger, amalgamation, consolidation or acquisition;

(f) any Security Interest securing any Indebtedness to any bank or banks or other lending institution or institutions incurred in the ordinary course of business and for the purpose of carrying on the same, repayable on demand or maturing within 12 months of the date when such Indebtedness is incurred or the date of any renewal or extension thereof;

(g) any Security Interest on or against cash or marketable debt securities pledged to secure Financial Instrument Obligations;

(h) any Security Interest in respect of:

(i) liens for taxes, duties and assessments not at the time overdue or any liens securing workmen’s compensation assessments, unemployment insurance or other social security obligations; provided however, that if any such liens, duties or assessments are then overdue the Corporation or the applicable Subsidiary thereof shall be contesting the same in good faith;

(ii) any liens or rights of distress reserved in or exercisable under any lease for rent and for compliance with the terms of such lease;

(iii) any obligations or duties, affecting the property of the Corporation or any Subsidiary thereof, to any municipality or governmental, statutory or other public authority, with respect to any franchise, permit, licence or grant and any defects in title to structures or other facilities arising solely from the fact that such structures or facilities are constructed or installed on lands held by the Corporation or any Subsidiary thereof, under franchises, permits, licences or other grants, from a municipality or other such authority, which obligations, duties and defects in the aggregate do not materially impair the use of such property, structures or facilities for the purpose for which they are held by the Corporation or any Subsidiary thereof;

(iv) any deposits or liens in connection with contracts, bids, tenders or expropriation proceedings, surety or appeal bonds, costs of litigation when required by law, public and statutory obligations, liens or claims incidental to current construction, builders’, mechanics’, labourers’, materialmen’s, warehousemen’s, carriers’ and other similar liens;

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(v) the right reserved to or vested in any municipality or governmental, statutory or other public authority by any statutory provision or by the terms of any lease, license, franchise, grant or permit, that affects any land, to terminate any such lease, license, franchise, grant or permit or to require annual or other periodic payments as a condition to the continuance thereof;

(vi) any undetermined or inchoate liens and charges incidental to the current operations of the Corporation or any Subsidiary thereof that have not at the time been filed against the Corporation; provided however, that if any such lien or charge shall have been filed, the Corporation or the applicable Subsidiary thereof shall be contesting the same in good faith;

(vii) any Security Interest the validity of which is being contested at the time by the Corporation or the applicable Subsidiary thereof in good faith or payment of which has been provided for by deposit with the Trustee or another trustee of debt securities issued by the Corporation or the applicable Subsidiary thereof of an amount in cash sufficient to pay the same in full;

(viii) any easements, rights-of-way and servitudes (including, without in any way limiting the generality of the foregoing, easements, rights-of-way and servitudes for railways, sewers, dykes, drains, gas and water mains or electric light and power or telephone and telegraph conduits, poles, wires and cables) that, in the opinion of the Corporation, will not in the aggregate materially and adversely impair the use or value of the land concerned for the purpose for which it is held by the Corporation or any Subsidiary thereof;

(ix) any security to a public utility or any municipality or governmental, statutory or other public authority when required by such utility, municipality or other such authority in connection with the operations of the Corporation or any Subsidiary thereof;

(x) any liens and privileges arising out of judgments or awards with respect to which the Corporation or the applicable Subsidiary thereof shall be prosecuting an appeal or proceedings for review and with respect to which it shall have secured a stay of execution pending such appeal or proceedings for review; and

(xi) any other liens of a nature similar to the foregoing which do not in the opinion of the Corporation materially impair the use of the property subject thereto or the operation of the business of the Corporation or the applicable Subsidiary thereof or the value of such property for the purpose of such business;

(i) any extension, renewal, alteration or replacement (or successive extensions, renewals, alterations or replacements) in whole or in part, of any Security Interest referred to in the foregoing clauses (a) through (h) inclusive, provided the extension, renewal, alteration or replacement of such Security Interest is limited to all or any part of the same property that secured the Security Interest extended, renewed, altered or replaced (plus improvements on such property) and the principal amount of the Indebtedness secured thereby is not increased; and

(j) any other Security Interest if the aggregate amount of Indebtedness secured pursuant to this clause (j) (together with the Attributable Amount of any sale and leaseback transaction) does not exceed 20% of Consolidated Net Tangible Assets.

“Preferred Securities” means securities which on the date of issue thereof by a Person: (i) have a term to maturity of more than 30 years; (ii) rank subordinate to the unsecured and unsubordinated Indebtedness of such person outstanding on such date; (iii) entitle such person to defer the payment of interest thereon for more than four years without thereby causing an event of default in respect of such securities to occur; and (iv) entitle such person to satisfy the obligation to make payments of deferred interest thereon from the proceeds of the issuance of its shares.

“Purchase Money Obligation” means any monetary obligation created or assumed as part of the purchase price of real or tangible personal property, whether or not secured, any extensions, renewals, alterations

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or replacements of any such obligation, provided that the principal amount of such obligation outstanding on the date of such extension, renewal, alteration or replacement is not increased and further provided that any security given in respect of such obligation shall not extend to any property other than the property acquired in connection with which such obligation was created or assumed and fixed improvements, if any, erected or constructed thereon.

“Security Interest” means any mortgage, charge, pledge, lien, encumbrance, assignment by way of security, title retention agreement or other security interest whatsoever, howsoever created or arising, whether absolute or contingent, fixed or floating, perfected or not, which secures payment or performance of an obligation.

“Subsidiary” means, in relation to a Person (i) any corporation of which at least a majority of the outstanding shares having by the terms thereof ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether at the time shares of any other class or classes of such corporation might have voting power by reason of the happening of any contingency, unless the contingency has occurred and then only for as long as it continues) is at the time directly, indirectly or beneficially owned or controlled by the person or one or more of its Subsidiaries, or the person and one or more of its Subsidiaries; (ii) any partnership of which the person or one or more of its Subsidiaries, or the person and one or more of its Subsidiaries: (i) directly, indirectly or beneficially own or control more than 50% of the income, capital, beneficial or ownership interests (however designated) thereof; and (ii) is a general partner, in the case of a limited partnership, or is a partner that has authority to bind the partnership, in all other cases; or (iii) any other person of which at least a majority of the income, capital, beneficial or ownership interests (however designated) are at the time directly, indirectly or beneficially owned or controlled by the first mentioned person or one or more of its Subsidiaries, or the first mentioned person and one or more of its Subsidiaries.

“Wholly-Owned Subsidiary” means any Subsidiary that the Corporation directly or indirectly beneficially owns 100% of the outstanding shares having by the terms thereof ordinary voting power to elect a majority of the board of directors of such Subsidiary or owns, directly or indirectly, 100% of the income, capital, beneficial or ownership interests (however designated) thereof.

Book-Entry System

DTC, New York, New York, will act as Notes depository for the Notes. The Notes will be issued as fully-registered securities registered in the name of Cede & Co. (DTC’s partnership nominee) or such other name as may be requested by an authorized representative of DTC. One fully-registered certificate will be issued for the Notes, in the aggregate principal amount of the issue, and will be deposited with DTC.

DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the U.S. Exchange Act. DTC holds and provides asset servicing for issues of U.S. and non-U.S. equity issues, corporate and municipal debt issues, and money market instruments that DTC’s participants (“Direct Participants”) deposit with DTC. DTC also facilitates the post-trade settlement among Direct Participants of sales and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between Direct Participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct Participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations, and certain other organizations. DTC is a wholly-owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, and clearing corporations that clear through or maintain a custodial

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relationship with a Direct Participant, either directly or indirectly (“Indirect Participants”). The DTC Rules applicable to its Participants are on file with the SEC. More information about DTC can be found at www.dtcc.com and www.dtc.org.

Purchases of Notes under the DTC system must be made by or through Direct Participants, which will receive a credit for the Notes on DTC’s records. The ownership interest of each actual purchaser of each Note (“Beneficial Owner”) is in turn to be recorded on the Direct and Indirect Participants’ records. Beneficial Owners will not receive written confirmation from DTC of their purchase. Beneficial Owners are, however, expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the Notes are to be accomplished by entries made on the books of Direct and Indirect Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in the Notes, except in the event that use of the book-entry system for the Notes is discontinued.

To facilitate subsequent transfers, all Notes deposited by Direct Participants with DTC are registered in the name of DTC’s partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of Notes with DTC and their registration in the name of Cede & Co. or such other DTC nominee do not affect any change in beneficial ownership. DTC has no knowledge of the actual Beneficial Owners of the Notes; DTC’s records reflect only the identity of the Direct Participants to whose accounts such Notes are credited, which may or may not be the Beneficial Owners. The Direct and Indirect Participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Beneficial Owners of Notes may wish to take certain steps to augment the transmission to them of notices of significant events with respect to the Notes, such as redemptions, tenders, defaults, and proposed amendments to the Notes. For example, Beneficial Owners of Notes may wish to ascertain that the nominee holding the Notes for their benefit has agreed to obtain and transmit notices to Beneficial Owners. In the alternative, Beneficial Owners may wish to provide their names and addresses to the registrar and request that copies of notices be provided directly to them.

Neither DTC nor Cede & Co. (nor any other DTC nominee) will consent or vote with respect to Notes unless authorized by a Direct Participant in accordance with DTC’s Money Market Instrument procedures. Under its usual procedures, DTC mails an “Omnibus Proxy” to the Corporation as soon as possible after the record date. The Omnibus Proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts Notes are credited on the record date (identified in a listing attached to the Omnibus Proxy).

Payments on the Notes will be made to Cede & Co., or such other nominee as may be requested by an authorized representative of DTC. DTC’s practice is to credit Direct Participants’ accounts upon DTC’s receipt of funds and corresponding detail information from the Corporation or the Trustee, on payable date in accordance with their respective holdings shown on DTC’s records. Payments by Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with Notes held for the accounts of customers in bearer form or registered in “street name”, and will be the responsibility of such Participant and not of DTC, the Trustee, or the Corporation, subject to any statutory or regulatory requirements as may be in effect from time to time. Any payment due to Cede & Co. (or such other nominee as may be requested by an authorized representative of DTC) is the Corporation’s responsibility or the responsibility of the Trustee, disbursement of such payments to Direct Participants shall be the responsibility of DTC, and disbursement of such payments to the Beneficial Owners shall be the responsibility of Direct Participants and Indirect Participants.

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DTC may discontinue providing its services as depository with respect to the Notes at any time by giving reasonable notice to the Corporation or the Trustee. Under such circumstances, in the event that a successor depository is not obtained, certificates for the Notes are required to be printed and delivered.

The Corporation may decide to discontinue use of the system of book-entry-only transfers through DTC (or a successor Notes depository). In that event, certificates will be printed and delivered to DTC.

The information in this section covering DTC and DTC’s system has been obtained from sources that the Corporation believes to be reliable, but the Corporation takes no responsibility for the accuracy thereof. The information in this section is subject to any changes to the arrangements between the Corporation and DTC and any changes to these procedures that may be instituted unilaterally by DTC.

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EARNINGS COVERAGE

The following coverage ratios have been prepared in accordance with Canadian securities law requirements and are included in this Prospectus Supplement in accordance with Canadian disclosure requirements.

The following table sets forth our earnings coverage ratios calculated for the twelve-month period ended December 31, 2021 and the twelve-month period ended September 30, 2022. Such earnings coverage ratios do not give effect to the issuance of any Notes offered by this Prospectus Supplement since the aggregate principal amount of Notes that will be issued hereunder and the terms of issue are not presently known and do not give effect to events subsequent to September 30, 2022.

	Twelve month period ended
	December 31, 2021			September 30, 2022
Earnings coverage on long-term debt(1)		(0.87	)x(2)		1.81x

(1) 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 and interest income. For purposes of calculating the earnings coverage ratios set forth herein, long-term debt includes the current portion of long-term debt and does not include any amounts with respect to Notes that may be issued under this Prospectus Supplement.

(2) The Corporation would have required additional earnings of $506 million for the twelve months ended December 31, 2021 in order to achieve an earnings coverage ratio of one-to-one for such period.

The pro forma earnings coverage ratio for the twelve month period ended December 31, 2021 and the twelve month period ended September 30, 2022, giving effect to this offering and the application of the net proceeds from the sale of the Notes, including any interest savings in connection with the use of proceeds of this offering (assuming this offering took place on the first date of the respective twelve month period), would have been 0.81x and 1.70x, respectively.

The earnings coverage ratios set forth above do not purport to be indicative of earnings coverage ratios for any future periods. The earnings coverage ratios have been calculated based on information prepared in accordance with IFRS.

We evaluate our performance using a variety of measures. Earnings coverage discussed above is not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to, or more meaningful than, net earnings as determined in accordance with IFRS as an indicator of our financial performance or liquidity. This measure is not necessarily comparable to a similarly titled measure of another company. Net earnings has been calculated on a consistent basis for the twelve month period ended December 31, 2021 and the twelve month period ended September 30, 2022.

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CERTAIN INCOME TAX CONSIDERATIONS

The following summary is of a general nature only and is not intended to be, and should not be construed to be, legal or tax advice to any prospective investor and no representation with respect to the tax consequences to any particular investor is made. Accordingly, prospective investors should consult with their own tax advisors for advice with respect to the income tax consequences to them having regard to their own particular circumstances, including any consequences of an investment in the Notes arising under state, provincial or local tax laws in the United States or Canada or tax laws of jurisdictions outside the United States or Canada.

Certain Canadian Federal Income Tax Considerations

In the opinion of Norton Rose Fulbright Canada LLP, counsel to the Corporation, and Blake, Cassels & Graydon LLP, counsel to the underwriters, the following summary, as of the date hereof, describes the principal Canadian federal income tax considerations generally applicable to a prospective purchaser of Notes pursuant to this Prospectus Supplement and the accompanying Prospectus who, at all relevant times, for purposes of the Income Tax Act (Canada) (the “Tax Act”) and any applicable tax treaty: (i) is neither resident nor deemed to be resident in Canada; (ii) deals at arm’s length with, and is not affiliated with, us and with any transferee who is resident in Canada (or deemed to be resident in Canada) for purposes of the Tax Act and to whom the purchaser assigns or otherwise transfers a Note; (iii) does not use or hold and is not deemed to use or hold a Note in carrying on business in Canada; (iv) is not an insurer who carries on an insurance business, or is deemed to carry on an insurance business, in Canada and elsewhere, (v) is entitled to receive all payments (including principal, interest and premium, if any) in respect of a Note; and (vi) is not a “specified shareholder” of us within the meaning of subsection 18(5) of the Tax Act or a person that does not deal at arm’s length with any such specified shareholder (each such purchaser is referred to herein as a “Non-Resident Holder”).

This summary is based on the current provisions of the Tax Act, the regulations thereunder (the “Regulations”) and counsel’s understanding of the current administrative policies and assessing practices of the Canada Revenue Agency (the “CRA”) published in writing, publicly available and in effect as of the date hereof. This summary also takes into account all specific proposals to amend the Tax Act and the Regulations publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date of this Prospectus Supplement (the “Proposed Amendments”) and assumes that all Proposed Amendments will be enacted in the form proposed. No assurance can be given that the Proposed Amendments will be enacted in the form proposed, or at all. Other than the Proposed Amendments, this summary does not anticipate any changes in law or CRA administrative policies or assessing practices, whether by legislative, governmental or judicial action or interpretation, nor does it take into account provincial, territorial or foreign tax considerations, which may differ significantly from those discussed herein.

This summary does not address the possible application of the “hybrid mismatch arrangement” rules included in Proposed Amendments released on April 29, 2022 to a Non-Resident Holder (i) that disposes of a Note to a person or entity with which it does not deal at arm’s length or to an entity that is a “specified entity” (as defined in such Proposed Amendments) with respect to the Non-Resident Holder or in respect of which the Non-Resident Holder is a “specified entity”, (ii) that disposes of a Note under, or in connection with, a “structured arrangement” (as defined in such Proposed Amendments), or (iii) in respect of which we are a “specified entity”. Such Non-Resident Holders should consult their own tax advisors.

This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal or tax advice to any particular purchaser and no representations with respect to the income tax consequences to any particular purchaser are made. This summary is not exhaustive of all Canadian federal income tax considerations. Accordingly, prospective purchasers of Notes should consult their own tax advisors with respect to their own particular circumstances.

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No Canadian withholding tax will apply to amounts paid or credited, or deemed to be paid or credited, by us to a Non-Resident Holder as, on account or in lieu of payment of, or in satisfaction of, interest, principal, premium, bonus or penalty on the Notes. No other Canadian taxes on income or capital gains will be payable under the Tax Act by a Non-Resident Holder in respect of the acquisition, holding, redemption or disposition of a Note by a Non-Resident Holder, or the receipt of interest, principal or premium thereon by a Non-Resident Holder solely as a consequence of such acquisition, holding, redemption or disposition of a Note.

Certain U.S. Federal Income Tax Considerations

The following is a summary of the material U.S. federal income tax consequences of the acquisition, ownership and disposition of a Note by an initial purchaser thereof who is a U.S. Holder (as hereinafter defined) who purchases the Note for cash at its “issue price” (the first price at which a substantial amount of the Notes is sold for cash, excluding sales to bond houses, brokers, or similar persons acting in the capacity of underwriters, placement agents or wholesalers) and who will hold the Note as a “capital asset” within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended (the “Code”). This summary is intended for general information only and does not address all potentially relevant U.S. federal income tax matters.

This summary does not address the tax consequences to U.S. Holders subject to special provisions of the Code including, without limitation: banks; financial institutions; thrifts; tax-exempt organizations; insurance companies; regulated investment companies or real estate investment trusts; holders subject to the alternative minimum tax; certain former citizens or residents of the United States; dealers in securities or foreign currencies that elect to use a mark-to-market method of accounting; traders that mark-to-market their securities; qualified retirement plans; individual retirement accounts or other tax-deferred accounts; holders holding Notes as part of a “hedge”, “straddle”, “conversion transaction” or other integrated transaction; investors in pass-through entities that hold the Notes; and persons required for U.S. federal income tax purposes to conform the timing of income accruals with respect to their Notes to their financial statements under Section 451 of the Code and holders with a “functional currency” other than the U.S. dollar. This summary also does not cover any state, local or non-U.S. tax consequences. This summary is based upon existing provisions of the Code, final and temporary regulations promulgated thereunder (“U.S. Treasury Regulations”), and rulings and judicial decisions in effect on the date hereof, all of which are subject to change (possibly with retroactive effect) and differing interpretations, so as to result in U.S. federal income tax consequences different from those described herein. This discussion is not binding on the U.S. Internal Revenue Service (the “IRS”) and we have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance that the IRS will not take positions that are different from those discussed below or that a U.S. court will not sustain such a challenge.

As used herein, the term “U.S. Holder” means a beneficial owner of a Note that is (i) an individual who is a citizen or resident of the United States as determined for U.S. federal income tax purposes, (ii) a corporation, or other entity treated as a corporation for U.S. federal income tax purposes, created or organized under the laws of the United States or any political subdivision thereof, (iii) an estate the income of which is subject to U.S. federal income tax without regard to its source, or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust or if the trust has made a valid election to be treated as a United States person.

If a partnership (or other entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds Notes, the U.S. federal income tax treatment of a partner in the partnership will depend on the status of the partner and the activities of the partnership. Partners in partnerships (or other entities or arrangements treated as partnerships for U.S. federal income tax purposes) holding Notes should consult their tax advisors regarding the tax consequences of the acquisition, ownership or disposition of the Notes.

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Effect of Certain Contingencies

In certain circumstances we may be obligated to pay amounts in excess of stated interest or principal on the Notes (see, for example, “Description of Debt Securities —Payment of Additional Amounts” in the accompanying Prospectus and “Description of Notes—Optional Redemption” and “Description of Notes—Repurchase Upon Change of Control Triggering Event” in this Prospectus Supplement). Under the applicable U.S. Treasury Regulations, such excess amounts should not cause the Notes to be subject to special rules applicable to contingent payment debt instruments if, based on all the facts and circumstances as of the date on which the Notes are issued, there is only a remote likelihood that any contingencies causing the payment of such excess amounts will occur, or if such excess amounts, in the aggregate, are considered incidental. We believe that the possibility of paying excess amounts is remote and/or that such amounts are incidental. Accordingly, we do not intend to treat the Notes as contingent payment debt instruments. Our position will be binding on a U.S. Holder unless such holder timely and explicitly discloses its contrary position in the manner required by applicable U.S. Treasury Regulations. Our position, however, is not binding on the IRS. If the IRS successfully challenges this position, the timing and amount of income included and the character of the income recognized with respect to the Notes may be materially and adversely different from the consequences discussed herein. U.S. Holders should consult their own tax advisors regarding this issue. The remainder of this discussion assumes that the Notes will not be treated as contingent payment debt instruments.

Payments of Interest

Interest (including additional amounts and any taxes withheld on payments of interest, if any) on the Notes will generally be taxable to a U.S. Holder as ordinary income at the time received or accrued, in accordance with such holder’s method of accounting for U.S. federal income tax purposes. Such interest will constitute income from sources outside the United States for U.S. foreign tax credit limitation purposes. The rules governing U.S. foreign tax credits are complex. Prospective purchasers of Notes should consult their tax advisors regarding the availability of U.S. foreign tax credits in their particular circumstances.

Original Issue Discount

If the stated redemption price at maturity of a Note exceeds its issue price by more than a de minimis amount, a U.S. Holder will be required to treat such excess amount as original issue discount (“OID”), which is treated for U.S. federal income tax purposes as accruing over the term of the Note as interest income to such U.S. Holder in accordance with a constant yield method based on a compounding of interest before the receipt of cash payments attributable to this income. A U.S. Holder’s adjusted tax basis in a Note would be increased by the amount of any OID included in gross income. In compliance with U.S. Treasury Regulations, if we determine that the Notes are issued with OID, we will provide certain information to the IRS and/or U.S. Holders, as applicable, that is relevant to determining the amount of OID in each accrual period.

Sale, Exchange, Retirement or Redemption of Notes

Upon the sale, exchange, retirement, redemption or other taxable disposition of a Note, a U.S. Holder generally will recognize gain or loss equal to the difference between the amount realized on such sale, exchange, retirement, redemption or other taxable disposition of the Notes (other than amounts received that are attributable to accrued but unpaid interest, which amounts will be taxable as ordinary income to the extent not previously included in income) and such U.S. Holder’s adjusted tax basis in the Note, which generally is its cost. Such gain or loss generally will constitute capital gain or loss and will be long-term capital gain or loss if the Note was held by such U.S. Holder for more than one year. Net long-term capital gain of non-corporate U.S. Holders, including individuals, is generally eligible for reduced rates of taxation. The deductibility of capital losses is subject to limitations.

Gain or loss recognized by a U.S. Holder generally will be treated as U.S. source income or loss for foreign tax credit purposes. Prospective investors should consult their own tax advisors as to the foreign tax credit implications of such sale, exchange or other disposition of a Note.

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Additional Tax on Investment Income

Certain U.S. Holders who are individuals, estates or trusts and whose income exceeds certain thresholds generally will be required to pay an additional 3.8 percent tax on all or a portion of their “net investment income,” which includes, among other things, interest income and capital gains from the sale or other disposition of a Note, subject to certain limitations and exceptions. U.S. Holders should consult their own tax advisors regarding the application of this additional tax to their investment in the Notes.

Information Reporting and Backup Withholding

In general, payments of interest and principal on and the proceeds from sales of Notes held by a U.S. Holder will be required to be reported to the IRS unless the U.S. Holder is a corporation or other exempt recipient and, when required, demonstrates this fact. In addition, a U.S. Holder that is not an exempt recipient may be subject to backup withholding of U.S. federal income tax on such payments unless it provides a taxpayer identification number and otherwise complies with applicable certification requirements. Backup withholding is not an additional tax. The amount of any backup withholding from a payment to a U.S. Holder generally will be allowed as a credit against such U.S. Holder’s U.S. federal income tax liability and may entitle such U.S. Holder to a refund, provided that the required information is furnished to the IRS in a timely manner. Holders should consult their tax advisors regarding the application of backup withholding, the availability of an exemption from backup withholding and the procedure for obtaining such an exemption, if available.

Information with Respect to Foreign Financial Assets

Individuals that own “specified foreign financial assets” with an aggregate value in excess of US$50,000 are generally required to file an information report (on IRS Form 8938) with respect to such assets with their tax returns. “Specified foreign financial assets” include any financial accounts maintained by foreign financial institutions, as well as any of the following, but only if they are not held in accounts maintained by certain financial institutions: (i) stocks and securities issued by non-U.S. persons, (ii) financial instruments and contracts held for investment that have non U.S. issuers or counterparties, and (iii) interests in foreign entities. The Notes may be subject to these rules. Under certain circumstances, U.S. entities that hold specified foreign financial assets may also be subject to these rules. A U.S. Holder that does not file a required IRS Form 8938 may be subject to substantial penalties, and the statute of limitations on the assessment and collection of all U.S. federal income taxes of such holder for the related tax year may not close before the date which is three years after the date on which such report is filed. U.S. Holders are urged to consult their tax advisors regarding the application of this legislation to their ownership of the Notes.

FATCA

No additional amounts will be required to be paid on account of, and payments on the Notes will be paid net of, any deduction or withholding imposed under Sections 1471 through 1474 of the Code (provisions commonly known as “FATCA”) or any current or future regulations issued thereunder, any intergovernmental agreement entered into with respect to FATCA or similar law or regulation adopted pursuant to an intergovernmental agreement between a non-U.S. jurisdiction and the United States with respect to the foregoing or any agreements entered into pursuant to Section 1471(b)(1) of the Code.

THE U.S. FEDERAL INCOME TAX DISCUSSION SET FORTH ABOVE IS INCLUDED FOR GENERAL INFORMATION ONLY AND MAY NOT BE APPLICABLE DEPENDING UPON A PROSPECTIVE PURCHASER’S PARTICULAR SITUATION. PROSPECTIVE PURCHASERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE TAX CONSEQUENCES TO THEM OF THE ACQUISITION, OWNERSHIP AND DISPOSITION OF THE NOTES INCLUDING THE TAX CONSEQUENCES UNDER STATE, LOCAL, NON-U.S. AND OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF CHANGES IN U.S. OR OTHER TAX LAWS.

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UNDERWRITING (CONFLICTS OF INTEREST)

We intend to offer the Notes through the underwriters named below for whom RBC Capital Markets, LLC (the “Representative”) is acting as representative. Subject to the terms and conditions contained in the underwriting agreement dated the date of this Prospectus Supplement, each underwriter has severally agreed to purchase, and we have agreed to sell to such underwriter, the principal amount of Notes set forth opposite the underwriter’s name.

Underwriter	Principal Amounts of Notes
RBC Capital Markets, LLC	US$	100,000,000
CIBC World Markets Corp.	US$	64,000,000
BofA Securities, Inc.	US$	12,000,000
Scotia Capital (USA) Inc.	US$	52,000,000
BMO Capital Markets Corp.	US$	32,000,000
TD Securities (USA) LLC	US$	32,000,000
National Bank of Canada Financial Inc.	US$	32,000,000
MUFG Securities Americas Inc.	US$	20,000,000
Desjardins Securities Inc.	US$	20,000,000
ATB Capital Markets Inc.	US$	20,000,000
Mizuho Securities USA LLC	US$	12,000,000
Loop Capital Markets LLC	US$	4,000,000
Total	US$	400,000,000

In the underwriting agreement, the underwriters have severally agreed, subject to the terms and conditions set forth therein, to purchase all the Notes offered under this Prospectus Supplement if any of the Notes are purchased. In the event of default by an underwriter, the underwriting agreement provides that, in certain circumstances, purchase commitments of the non-defaulting underwriters may be increased or the underwriting agreement may be terminated. The obligations of the underwriters under the underwriting agreement may also be terminated upon the occurrence of certain stated events specified in the underwriting agreement including “regulatory out”, “litigation out”, “disaster out” and “material change out” provisions.

The underwriting agreement provides that the obligations of the underwriters to purchase the Notes included in this offering are subject to approval of legal matters by counsel and to other conditions.

The underwriters propose to offer the Notes directly to the public at the public offering price set forth on the cover page of this Prospectus Supplement. After the initial offering of the Notes to the public, the Representative may change the public offering price.

The following table shows the underwriting commission that we will pay to the underwriters in connection with this offering (expressed as a percentage of the principal amount of the Notes). We will pay a structuring fee equal to 0.25% of the gross proceeds from this offering (including any proceeds from the exercise of the option to purchase additional common units) to RBC Capital Markets, LLC for the structuring services provided in connection with the refinancing of the 2022 Notes.

	Paid by TransAlta
Per Note		1.25	%

In connection with this offering, the Representative may purchase and sell Notes in the open market. These transactions may include over-allotment, syndicate covering transactions and stabilizing transactions. Over-allotment involves syndicate sales of the Notes in excess of the principal amount of the Notes to be purchased by the underwriters in this offering, which creates a syndicate short position. Syndicate covering

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transactions involve purchases of the Notes in the open market after the distribution has been completed in order to cover syndicate short positions. Stabilizing transactions consist of certain bids or purchases of the Notes made for the purpose of preventing or retarding a decline in the market price of the Notes while this offering is in progress.

The underwriters may also impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the Representative, in covering syndicate short positions or making stabilizing purchases, repurchases Notes originally sold by that syndicate member.

As a result of these activities, the market price of the Notes offered under this Prospectus Supplement may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time without notice. The underwriters may carry out these transactions in the over-the-counter market or otherwise. Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the Notes.

We estimate that our total expenses for this offering will be approximately US$1,000,000 (not including underwriting commissions and the structuring fee).

Certain of the underwriters and their respective affiliates have in the past performed, and may in the future perform, various financial advisory, investment banking and commercial lending service for us and our affiliates in the ordinary course of business, for which they have received and will receive customary fees and commissions.

Certain of the underwriters or their respective affiliates are lenders under our credit facilities. Such underwriters or their affiliates may receive a portion of the net proceeds from this offering in connection with the repayment of indebtedness. See “Use of Proceeds.” In addition, in the ordinary course of their business activities, the underwriters and their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. Certain of the underwriters or their affiliates that have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. Typically, such underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities, including potentially the Notes offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the Notes offered hereby. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Certain of the underwriters may not be U.S. registered broker-dealers and accordingly will not effect any sales within the United States except in compliance with applicable U.S. laws and regulations, including the rules of the FINRA.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the U.S. Securities Act, or to contribute to payments the underwriters may be required to make because of any such liabilities.

The Notes will not be qualified for sale under the securities laws of Canada or any province or territory of Canada (other than the Province of Alberta) and may not be, directly or indirectly, offered, sold or delivered in Canada or to residents of Canada in contravention of the securities laws of any province or territory of Canada. Each underwriter has agreed that it will not, directly or indirectly, offer, sell or deliver any Notes purchased by it in Canada or to residents of Canada.

S-47

Conflicts of Interest

Affiliates of RBC Capital Markets, LLC, an underwriter in this offering, beneficially own in excess of 10% of our issued and outstanding common stock. Accordingly RBC Capital Markets, LLC is deemed to have a “conflict of interest” under FINRA Rule 5121. As a result, this offering is being made in compliance with the requirements of Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this Prospectus Supplement. BofA Securities, Inc. has agreed to act as a qualified independent underwriter for this offering and to undertake the legal responsibilities and liabilities of an underwriter under the U.S. Securities Act, specifically including those inherent in Section 11 thereof. BofA Securities, Inc. will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify BofA Securities, Inc. against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act. Pursuant to Rule 5121, RBC Capital Markets, LLC will not confirm any sales to any account over which it exercises discretionary authority without the specific written approval of the account holder.

Settlement

We expect that delivery of the Notes will be made to investors on or about November 17, 2022, which will be the third business day following the date of this Prospectus Supplement (such settlement being referred to as “T+3”). Under Rule 15c6-1 under the U.S. Exchange Act, trades in the secondary market are required to settle in two business days, unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade Notes prior to the delivery of the Notes hereunder may be required, by virtue of the fact that the Notes initially settle in T+3, to specify an alternate settlement arrangement at the time of any such trade to prevent a failed settlement. Purchasers of Notes who wish to trade Notes prior to their date of delivery hereunder should consult their advisors.

No Sales of Similar Securities

We have agreed that we will not, for a period of 90 days after the date of this Prospectus Supplement, without first obtaining the prior written consent of the Representative, offer, sell, or contract to sell, directly or indirectly, any debt securities issued or guaranteed by us, except for the Notes sold to the underwriters pursuant to the underwriting agreement.

Offering Restrictions

The Notes are offered for sale in those jurisdictions in the United States where it is lawful to make such offers. No action has been taken, or will be taken, which would permit a public offering of the Notes in any jurisdiction outside the United States.

Each of the underwriters has severally represented and agreed that it has not offered, sold or delivered and it will not offer, sell or deliver, directly or indirectly, any of the Notes, in or from any jurisdiction except under circumstances that are reasonably designed to result in compliance with the applicable laws and regulations thereof.

This prospectus supplement does not constitute an offer of the Notes, directly or indirectly, in Canada or to residents of Canada. Each underwriter, severally and not jointly, has represented and agreed that it will not, directly or indirectly, offer, sell or deliver, any of the Notes purchased by it to any resident of Canada without the consent of TransAlta and that any sub-underwriting, banking group or selling group agreement or similar arrangement with respect to the Notes that may be entered into by such underwriter in connection with the offering of the Notes will require each other party thereto to make an agreement to the same effect.

S-48

Notice to Prospective Investors in the United States of America

The Notes may not be acquired or held by any person who is an employee benefit plan or other plan or arrangement subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), or Section 4975 of the Code, or who is acting on behalf of or investing the assets of any such plan or arrangement, unless the acquisition and holding of the Notes by such person will not result in a non-exempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Code.

S-49

LEGAL MATTERS

Certain legal matters relating to Canadian law in connection with the offering of the Notes will be passed upon on behalf of the Corporation by Norton Rose Fulbright Canada LLP, Calgary, Alberta and on behalf of the underwriters by Blake, Cassels & Graydon LLP. Certain legal matters relating to United States law in connection with the offering of the Notes will be passed upon on behalf of the Corporation by Paul, Weiss, Rifkind, Wharton & Garrison LLP, New York, New York and on behalf of the underwriters by Latham & Watkins LLP, Houston, Texas.

The partners and associates of Norton Rose Fulbright Canada LLP, as a group, and Blake, Cassels & Graydon LLP, as a group, beneficially own, directly or indirectly, less than 1% of any class of securities of the Corporation.

EXPERTS

The consolidated financial statements of the Corporation, included in this prospectus from the TransAlta Corporation Annual Report, and the effectiveness of the Corporations’ internal control over financial reporting, have been audited by Ernst & Young LLP, an independent registered public accounting firm, as set forth in their reports thereon, included therein, and included herein. Such consolidated financial statements have been included herein in reliance upon the reports of such firm given on their authority as experts in accounting and auditing.

In connection with the audit of our Annual Financial Statements, Ernst & Young LLP is independent with respect to TransAlta Corporation in accordance with the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta and in compliance with Rule 3520 of the Public Company Accounting Oversight Board (United States).

S-50

EXHIBIT “A” – ANNUAL AUDITED FINANCIAL STATEMENTS AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2021 AND 2020

See attached.

SA-1

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 (“TransAlta”) 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, Finance 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.

/s/ John Kousinioris	/s/ Todd Stack
John Kousinioris	Todd Stack
President and Chief Executive Officer	Executive Vice Precident, Finance and Chief Financial Officer

February 23, 2022

SA-2

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.

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.

In accordance with the provisions of NI 52-109 and consistent with U.S. Securities and Exchange Commission guidance, the scope of the evaluation did not include internal controls over financial reporting of North Carolina Solar, which the Company acquired on Nov. 5, 2021. North Carolina Solar was excluded from management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as at Dec. 31, 2021, due to the proximity of the acquisition to year-end. Further details related to the acquisition are disclosed in Note 4 to the Company’s Consolidated Financial Statements for the year ended Dec. 31, 2021. Included in the 2021 Consolidated Financial Statements of TransAlta for North Carolina Solar is 2 per cent and 5 per cent of the Company’s total and net assets, respectively, as at Dec. 31, 2021.

TransAlta proportionately consolidates the joint operations of the Sheerness Generating Station and equity accounts for our investment in SP Skookumchuck Investment, LLC in accordance with International Financial Reporting Standards. Management does not have the contractual ability to assess the internal controls of these joint arrangements and associates. Once the financial information is obtained from these joint arrangements and associates 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 and associates.

Included in the 2021 Consolidated Financial Statements of TransAlta for joint operations and equity accounted investments are 4 per cent and 10 per cent of the Company’s total and net assets, respectively, as of Dec. 31, 2021, and 8 per cent of the Company’s revenues for the year then ended.

SA-3

Consolidated Financial Statements

Changes in Internal Controls over Financial Reporting

The Company’s internal controls over financial reporting commencing Nov. 5, 2021, include controls designed to result in complete and accurate consolidation of North Carolina Solar’s results. Other than the North Carolina Solar acquisition, there has been no change in the Company’s internal control over financial reporting that occurred during the year covered by this Annual Report that has materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management has assessed the effectiveness of TransAlta’s internal control over financial reporting, as at Dec. 31, 2021, 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 Dec. 31, 2021, 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.

/s/ John Kousinioris	/s/ Todd Stack
John Kousinioris	Todd Stack
President and Chief Executive Officer	Executive Vice President, Finance and Chief Financial Officer
February 23, 2022

SA-4

Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of 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, 2021, 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 (the “Company”) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.

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 joint operations of the Sheerness Generating Station and equity accounted joint venture of SP Skookumchuck Investment, LLC which are included in the 2021 consolidated financial statements of the Company and constituted 4% and 10% of total and net assets, respectively, as of December 31, 2021, and 8% of revenues for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of the joint operations of the Sheerness Generating Station and equity accounted joint venture of SP Skookumchuck Investment, LLC.

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 North Carolina Solar, which is included in the 2021 consolidated financial statements of the Company and constituted 2% and 5% of total and net assets, respectively, as of December 31, 2021. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of North Carolina Solar.

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, 2021 and 2020, and the related consolidated statements of earnings (loss), comprehensive earnings (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and our report dated February 23, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’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 the Company’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 the Company in accordance with the U.S. 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.

SA-5

Consolidated Financial Statements

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 generally accepted accounting principles. 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 company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the consolidated 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.

/s/ Ernst & Young LLP

Chartered Professional Accountants

Calgary, Canada

February 23, 2022

SA-6

Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of TransAlta Corporation

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated statements of financial position of TransAlta Corporation (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of earnings (loss), comprehensive earnings (loss), changes in equity and cash flows, for each of the three years in the period ended December 31, 2021, 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 the Company at December 31, 2021 and 2020, and the financial performance and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2021, 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 23, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’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 the Company in accordance with the U.S. 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 included 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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

SA-7

Consolidated Financial Statements

Valuation of Long-Lived Assets related to certain cash generating units (“CGU“s) within the Wind and Solar segment and Goodwill related to the Wind and Solar segment
Description of the Matter	As disclosed in notes 2(G), 2(H), 2(P)(I), 7, 18 and 21 of the consolidated financial statements, the Company owns significant Wind and Solar generation assets and has recognized goodwill from historical acquisitions which must be tested for impairment at least annually or when indicators are present. The carrying value of Goodwill related to the Wind and Solar segment was $175 million and the carrying value of long-lived assets in the Wind and Solar segment consisted of property, plant & equipment of $2,304 million, right-of-use assets of $64 million and intangible assets of $147 million as at December 31, 2021.
	Determining the recoverable amounts for the Wind and Solar segment for the purposes of the goodwill impairment test and of certain CGUs in the Wind and Solar segment with indicators of impairment (“Wind and Solar CGUs”) for the asset impairment test was identified as a critical audit matter due to the significant estimation uncertainty and judgment applied by management in determining the recoverable amount, primarily due to the sensitivity of the significant assumptions to the future cash flows and the effect that changes in these assumptions would have on the recoverable amount. The estimates with a high degree of subjectivity include generation profiles, commodity prices, cost estimates, and determining the appropriate discount rate.
How We Addressed the Matter in Our Audit	We obtained an understanding of management’s process for estimating the recoverable amount of the Wind and Solar segment and the Wind and Solar CGUs. We evaluated the design and tested the operating effectiveness of controls over the Company’s processes to determine the recoverable amount. Our audit procedures to test the Company’s recoverable amount of the Wind and Solar segment and the Wind and Solar CGUs with indicators of impairment included, among others, comparing the significant assumptions used to estimate cash flows to current contracts with external parties and historical trends and obtaining historical power generation data to evaluate future generation forecasts. We assessed the historical accuracy of management’s forecasts by comparing them with actual results and performed a sensitivity analysis to evaluate the assumptions that were most significant to the determination of the recoverable amount. We evaluated the Company’s determination of future commodity prices by comparing them to externally available third-party future commodity price estimates. We also involved our internal valuation specialist to assist in our evaluation of the discount rates, which involved benchmarking the inputs against available market data.
Valuation of Level III Derivative Instruments
Description of the Matter	As disclosed in notes 2(P)(IV), 15 and 25 of the consolidated financial statements, the Company enters into transactions that are accounted for as derivative financial instruments and are recorded at fair value. The valuation of derivative instruments classified as level III are determined using assumptions that are not readily observable. As at December 31, 2021 the fair value of the Company’s derivative financial instruments classified as level III was $159 million net risk management assets.
	Auditing the determination of fair value of level III derivative instruments that rely on significant unobservable inputs can be complex and relies on judgments and estimates concerning future commodity prices, discount rates, volatility, unit availability and demand profiles, and can fluctuate significantly depending on market conditions. Therefore, such determination of fair value was identified as a critical audit matter.

SA-8

Consolidated Financial Statements

How We Addressed the Matter in Our Audit We obtained an understanding of the Company’s processes and we evaluated and tested the design and operating effectiveness of internal controls addressing the determination and review of inputs used in establishing level III fair values. Our audit procedures included, among others, testing a sample of level III derivative instrument internal models used by management and evaluating the significant assumptions utilized. We also compared management’s future pricing assumptions, credit valuation adjustments, and liquidity assumptions to third-party data as well as comparing terms such as volumes and timing to executed commodity contracts. We compared the unit availability and demand profile assumptions to historical information. We performed a sensitivity analysis to evaluate the assumptions that were most significant to the determination of level III fair value. For a sample of level III derivative instruments, we involved our internal valuation specialist to assist in our evaluation of the appropriateness of the discount rates by evaluating the key assumptions and methodologies.

/s/ Ernst & Young LLP

Chartered Professional Accountants

We have served as auditors of TransAlta Corporation and its predecessor entities since 1947.

Calgary, Canada

February 23, 2022

SA-9

Consolidated Financial Statements

Consolidated Statements of Earnings (Loss)

Year ended Dec. 31 (in millions of Canadian dollars except where noted)	2021			2020			2019
Revenues (Note 5)		2,721			2,101			2,347
Fuel and purchased power (Note 6)		1,054			805			881
Carbon compliance		178			163			205
Gross margin		1,489			1,133			1,261
Operations, maintenance and administration (Note 6)		511			472			475
Depreciation and amortization		529			654			590
Asset impairment charge (Note 7)		648			84			25
Gain on termination of Keephills 3 coal rights contract (Note 18)		—			—			(88	)
Taxes, other than income taxes		32			33			29
Termination of Sundance B and C PPAs		—			—			(56	)
Net other operating loss (income) (Note 9)		8			(11	)		(49	)
Operating income (loss)		(239	)		(99	)		335
Equity income (Note 10)		9			1			—
Finance lease income		25			7			6
Net interest expense (Note 11)		(245	)		(238	)		(179	)
Foreign exchange gain (loss)		16			17			(15	)
Gain on sale of assets and other (Note 4 and 18)		54			9			46
Earnings (loss) before income taxes		(380	)		(303	)		193
Income tax expense (recovery) (Note 12)		45			(50	)		17
Net earnings (loss)		(425	)		(253	)		176
Net earnings (loss) attributable to:
TransAlta shareholders		(537	)		(287	)		82
Non-controlling interests (Note 13)		112			34			94
		(425	)		(253	)		176
Net earnings (loss) attributable to TransAlta shareholders		(537	)		(287	)		82
Preferred share dividends (Note 28)		39			49			30
Net earnings (loss) attributable to common shareholders		(576	)		(336	)		52
Weighted average number of common shares outstanding in the year (millions)		271			275			283
Net earnings (loss) per share attributable to common shareholders, basic and diluted (Note 27)		(2.13	)		(1.22	)		0.18

See accompanying notes.

SA-10

Consolidated Financial Statements

Consolidated Statements of Comprehensive Earnings (Loss)

Year ended Dec. 31 (in millions of Canadian dollars)	2021			2020			2019
Net earnings (loss)		(425	)		(253	)		176
Other comprehensive loss
Net actuarial gains (loss) on defined benefit plans, net of tax(1)		37			(11	)		(26	)
Losses on derivatives designated as cash flow hedges, net of tax		—			(1	)		—
Total items that will not be reclassified subsequently to net earnings		37			(12	)		(26	)
Losses on translating net assets of foreign operations, net of tax		(14	)		(11	)		(59	)
Gains on financial instruments designated as hedges of foreign operations, net of tax		—			11			21
Gains (losses) on derivatives designated as cash flow hedges, net of tax(2)		(200	)		20			61
Reclassification of gains on derivatives designated as cash flow hedges to net earnings, net of tax(3)		(8	)		(110	)		(42	)
Total items that will be reclassified subsequently to net earnings		(222	)		(90	)		(19	)
Other comprehensive loss		(185	)		(102	)		(45	)
Total comprehensive earnings (loss)		(610	)		(355	)		131
Total comprehensive earnings (loss) attributable to:
TransAlta shareholders		(693	)		(439	)		54
Non-controlling interests (Note 13)		83			84			77
		(610	)		(355	)		131

(1) Net of income tax expense of $11 million for the year ended Dec. 31, 2021 (2020 — $3 million recovery, 2019 — $7 million recovery).

(2) Net of income tax recovery of $55 million for the year ended Dec. 31, 2021 (2020 —$8 million expense, 2019 — $16 million expense).

(3) Net of reclassification of income tax recovery of $2 million for the year ended Dec. 31, 2021 (2020 —$31 million recovery, 2019 — $10 million recovery).

See accompanying notes.

SA-11

Consolidated Financial Statements

Consolidated Statements of Financial Position

As at Dec. 31 (in millions of Canadian dollars)	2021			2020
Cash and cash equivalents		947			703
Restricted cash (Note 24)		70			71
Trade and other receivables (Note 14)		651			583
Prepaid expenses		29			31
Risk management assets (Note 15 and 16)		308			171
Inventory (Note 17)		167			238
Assets held for sale (Note 4 and 18)		25			105
		2,197			1,902
Investments (Note 10)		105			100
Long-term portion of finance lease receivables (Note 8)		185			228
Risk management assets (Note 15 and 16)		399			521
Property, plant and equipment (Note 18)
Cost		13,389			13,398
Accumulated depreciation		(8,069	)		(7,576	)
		5,320			5,822
Right-of-use assets (Note 19)		95			141
Intangible assets (Note 20)		256			313
Goodwill (Note 21)		463			463
Deferred income tax assets (Note 12)		64			51
Other assets (Note 22)		142			206
Total assets		9,226			9,747
Accounts payable and accrued liabilities		689			599
Current portion of decommissioning and other provisions (Note 23)		48			59
Risk management liabilities (Note 15 and 16)		261			94
Current portion of contract liabilities (Note 5)		19			1
Income taxes payable		8			18
Dividends payable (Note 27 and 28)		62			59
Current portion of long-term debt and lease liabilities (Note 24)		844			105
		1,931			935
Credit facilities, long-term debt and lease liabilities (Note 24)		2,423			3,256
Exchangeable securities (Note 25)		735			730
Decommissioning and other provisions (Note 23)		779			614
Deferred income tax liabilities (Note 12)		354			396
Risk management liabilities (Note 15 and 16)		145			68
Contract liabilities (Note 5)		13			14
Defined benefit obligation and other long-term liabilities (Note 26)		253			298
Equity
Common shares (Note 27)		2,901			2,896
Preferred shares (Note 28)		942			942
Contributed surplus		46			38
Deficit		(2,453	)		(1,826	)
Accumulated other comprehensive income (Note 29)		146			302
Equity attributable to shareholders		1,582			2,352

SA-12

Consolidated Financial Statements

As at Dec. 31 (in millions of Canadian dollars)	2021		2020
Non-controlling interests (Note 13)		1,011		1,084
Total equity		2,593		3,436
Total liabilities and equity		9,226		9,747

Commitments and contingencies (Note 36)

	/s/ John P. Dielwart	/s/ Beverlee F. Park
On behalf of the Board:	John P. Dielwart Director	Beverlee F. Park Director

See accompanying notes.

SA-13

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, 2019		2,978			942		42			(1,455	)		454			2,961			1,101			4,062
Net earnings (loss)		—			—		—			(287	)		—			(287	)		34			(253	)
Other comprehensive earnings (loss):
Net losses on derivatives designated as cash flow hedges, net of tax		—			—		—			—			(91	)		(91	)		—			(91	)
Net actuarial losses on defined benefits plans, net of tax		—			—		—			—			(11	)		(11	)		—			(11	)
Intercompany FVOCI investments		—			—		—			—			(50	)		(50	)		50			—
Total comprehensive earnings (loss)										(287	)		(152	)		(439	)		84			(355	)
Common share dividends		—			—		—			(58	)		—			(58	)		—			(58	)
Preferred share dividends		—			—		—			(49	)		—			(49	)		—			(49	)
Shares purchased under NCIB		(79	)		—		—			18			—			(61	)		—			(61	)
Changes in non-controlling interests in TransAlta Renewables (Note 13)		—			—		—			5			—			5			15			20
Effect of share-based payment plans		(3	)		—		(4	)		—			—			(7	)		—			(7	)
Distributions paid, and payable, to non-controlling interests		—			—		—			—			—			—			(116	)		(116	)
Balance, Dec. 31, 2020		2,896			942		38			(1,826	)		302			2,352			1,084			3,436
Net earnings (loss)		—			—		—			(537	)		—			(537	)		112			(425	)
Other comprehensive earnings (loss):
Net losses on translating net assets of foreign operations, net of hedges and tax		—			—		—			—			(14	)		(14	)		—			(14	)
Net gains (losses) on derivatives designated as cash flow hedges, net of tax		—			—		—			—			(208	)		(208	)		—			(208	)
Net actuarial gains on defined benefits plans, net of tax		—			—		—			—			37			37			—			37

SA-14

Consolidated Financial Statements

	Common shares		Preferred shares		Contributed surplus		Deficit			Accumulated other comprehensive income(1)			Attributable to shareholders			Attributable to non- controlling interests			Total
Intercompany FVOCI investments		—		—		—		—			29			29			(29	)		—
Total comprehensive earnings (loss)								(537	)		(156	)		(693	)		83			(610	)
Common share dividends		—		—		—		(51	)		—			(51	)		—			(51	)
Preferred share dividends		—		—		—		(39	)		—			(39	)		—			(39	)
Effect of share-based payment plans (Note 30)		5		—		8		—			—			13			—			13
Distributions paid, and payable, to non-controlling interests		—		—		—		—			—			—			(156	)		(156	)
Balance, Dec. 31, 2021		2,901		942		46		(2,453	)		146			1,582			1,011			2,593

(1) Refer to Note 29 for details on components of, and changes in, accumulated other comprehensive earnings (loss). See accompanying notes.

SA-15

Consolidated Financial Statements

Consolidated Statements of Cash Flows

Year ended Dec. 31 (in millions of Canadian dollars)	2021			2020			2019
Operating activities
Net earnings (loss)		(425	)		(253	)		176
Depreciation and amortization (Note 18 and 37)		719			798			709
Net gain on sale of assets		(54	)		(9	)		(45	)
Accretion of provisions (Note 23)		32			30			23
Decommissioning and restoration costs settled (Note 23)		(18	)		(18	)		(34	)
Deferred income tax recovery (Note 12)		(11	)		(85	)		(18	)
Unrealized (gain) loss from risk management activities		(34	)		42			(32	)
Unrealized foreign exchange (gain) loss		(24	)		1			13
Provisions		(41	)		9			13
Asset impairment (Note 7)		648			84			25
Equity income, net of distributions from investments (Note 10)		(5	)		(1	)		—
Other non-cash items		40			15			(102	)
Cash flow from operations before changes in working capital		827			613			728
Change in non-cash operating working capital balances (Note 33)		174			89			121
Cash flow from operating activities		1,001			702			849
Investing activities
Additions to property, plant and equipment (Note 18 and 37)		(480	)		(486	)		(417	)
Additions to intangible assets (Note 20 and 37)		(9	)		(14	)		(14	)
Restricted cash (Note 24)		(1	)		(39	)		34
Loan receivable (Note 22)		(3	)		(5	)		(10	)
Acquisitions, net of cash acquired (Note 4)		(120	)		(32	)		(117	)
Acquisition of investments (Note 10)		—			(102	)		—
Investment in the Pioneer Pipeline		—			—			(83	)
Proceeds on sale of Pioneer Pipeline (Note 4)		128			—			—
Proceeds on sale of property, plant and equipment		39			6			13
Realized gains (losses) on financial instruments		(6	)		2			3
Decrease in finance lease receivable		41			17			24
Other		(16	)		(12	)		23
Change in non-cash investing working capital balances		(45	)		(22	)		32
Cash flow used in investing activities		(472	)		(687	)		(512	)
Financing activities
Net decrease in borrowings under credit facilities (Note 24 and 33)		(114	)		(106	)		(119	)
Repayment of long-term debt (Note 24 and 33)		(92	)		(489	)		(96	)
Issuance of long-term debt (Note 24)		173			753			166
Issuance of exchangeable securities (Note 25)		—			400			350
Dividends paid on common shares (Note 27)		(48	)		(47	)		(45	)
Dividends paid on preferred shares (Note 28)		(39	)		(39	)		(40	)
Repurchase of common shares under NCIB (Note 27)		(4	)		(57	)		(68	)
Proceeds on issuance of common shares		8			—			—
Realized gains on financial instruments		3			3			—
Distributions paid to subsidiaries’ non-controlling interests (Note 13)		(156	)		(97	)		(106	)
Decrease in lease liabilities (Note 24 and 33)		(8	)		(25	)		(21	)
Financing fees and other		(4	)		(11	)		(35	)

SA-16

Consolidated Financial Statements

Year ended Dec. 31 (in millions of Canadian dollars)	2021			2020			2019
Change in non-cash financing working capital balances		(1	)		(13	)		—
Cash flow from (used in) financing activities		(282	)		272			(14	)
Cash flow from operating, investing, and financing activities		247			287			323
Effect of translation on foreign currency cash		(3	)		5			(1	)
Increase in cash and cash equivalents		244			292			322
Cash and cash equivalents, beginning of year		703			411			89
Cash and cash equivalents, end of year		947			703			411
Cash taxes paid		57			36			35
Cash interest paid		220			201			185

See accompanying notes.

SA-17

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 “Company”) was incorporated under the Canada Business Corporations Act in March 1985. The Company became a public company in December 1992. Its head office is located in Calgary, Alberta.

I. Generation Segments

During the fourth quarter of 2021, the Company realigned its current operating segments to better reflect a change in how TransAlta’s President and Chief Executive Officer (the chief operating decision maker) (“CODM”) reviews financial information in order to allocate resources and assess performance. The primary changes are the elimination of the Alberta Thermal and the Centralia segments, and the reorganization of the North American Gas and Australia Gas segments into a new “Gas” segment. The Alberta Thermal facilities that have been converted to gas have been included in the Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets and those facilities not converted to gas and the remaining Centralia unit, are included in a new “Energy Transition” segment. No changes were made to the Hydro and Wind and Solar segments. This change better aligns with the Company’s long-term strategy and reflects its Clean Electricity Growth Plan.

The four generation segments of the Company are as follows: Hydro, Wind and Solar, Gas, and Energy Transition. Previously, the six generation segments were as follows: Hydro, Wind and Solar, North American Gas, Australian Gas, Alberta Thermal, and Centralia. The Company directly or indirectly owns and operates hydro, wind and solar, natural- gas-fired and coal-fired facilities, related mining operations and natural gas pipeline operations in Canada, the United States (“US”) and Australia. The Wind and Solar segment includes the financial results, on a proportionate basis, of our investment in SP Skookumchuck Investment, LLC. Revenues are derived from the availability and production of electricity and steam as well as ancillary services.

Comparative segmented results for 2020 and 2019 have been restated to align with the 2021 operating segments.

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. No change was made to the Energy Marketing segment.

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 optimization activities are included in each generation segment.

III. Corporate and Other Segment

The Corporate and Other segment includes the Company’s central finance, legal, administrative, corporate development and investor relations functions. Activities and charges directly or reasonably attributable to other segments are allocated thereto. Since 2020, the Corporate and Other segment also includes the investment in EMG International, LLC (“EMG”), a wastewater treatment processing company.

SA-18

Notes to Consolidated Financial Statements

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, 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 Feb. 23, 2022.

C. Basis of Consolidation

The consolidated financial statements include the accounts of the Company and the subsidiaries that it controls. Control exists when the Company 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.

2. Material Accounting Policies

The Company has reviewed the accounting policies disclosed in accordance with the amendments to IAS 1 to disclose the material accounting policy information rather than significant accounting policies. The definition of material that management has used to judgmentally determine disclosure is that information is material if omitting it or misstating it could influence decisions users make on the basis of financial information.

A. Revenue Recognition

I. Revenue from Contracts with Customers

The majority of the Company’s revenues from contracts with customers are derived from the sale of generation capacity, electricity, thermal energy, environmental attributes and byproducts of power generation. The Company 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 Company’s performance to date. The Company 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 Company’s contracts may contain more than one performance obligation.

Transaction Price

The Company 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

SA-19

Notes to Consolidated Financial Statements

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 Company’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 that 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.

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 Company expects to be entitled to in exchange for transferring the good or service. The Company estimates the amount of the transaction price to allocate to individual performance obligations based on their relative stand-alone selling prices, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions.

Recognition

The nature, timing of recognition of satisfied performance obligations and payment terms for the Company’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 the 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.
Environmental attributes	Environmental attributes refers to the delivery of renewable energy certificates, green attributes and other similar items. Customers may contract for environmental 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 environmental attributes. Obligations to deliver environmental attributes are satisfied at a point in time, generally upon delivery of the item.

SA-20

Notes to Consolidated Financial Statements

Good or service	Description
Generation byproducts	Generation byproducts refers to the sale of byproducts from the use of coal in the Company’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.

A contract liability is recorded when the Company receives consideration before the performance obligations have been satisfied. A contract asset is recorded when the Company has rights to consideration for the completion of a performance obligation before it has invoiced the customer. The Company 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.

II. Revenue from Other Sources

Merchant Revenue

Revenues from non-contracted capacity (i.e., merchant) are comprised of energy payments, at market price, for each MWh produced and are recognized upon delivery.

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 Company 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. The Company also enters into contracts for differences and virtual Power Purchase Agreements (“PPA”). Contracts for differences is a financial contract whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh. A virtual PPA is where the Company receives the difference between the fixed contract price per MWh and the settled market price. These arrangements are option-based derivatives and judgment is applied to determine if the contract meets the ‘own use’ exemption or if derivative treatment is required.

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 Company 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.

SA-21

Notes to Consolidated Financial Statements

B. Financial Instruments and Hedges

I. Financial Instruments

Classification and Measurement

IFRS 9 introduced the requirement to classify and measure financial assets based on their contractual cash flow characteristics and the Company’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 Company 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 (“FVOCI”).

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 FVOCI 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.

Funds received under tax equity investment arrangements are classified as long-term debt. These arrangements are used in the US where project investors acquire an equity investment in the project entity and in return for their investment, are allocated substantially all of the earnings, cash flows and tax benefits (such as production tax credits, investment tax credits, accelerated tax depreciation, as applicable) until they have achieved the agreed upon target rate of return. Once achieved, the arrangements flip, with the Company then receiving the majority of earnings, cash flows and tax benefits. At that time, the tax equity financings will be classified as a non-controlling interest. In applying the effective interest method to tax equity financings, the Company has made an accounting policy choice to recognize the impacts of the tax attributes in net interest expense.

The Company 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 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.

SA-22

Notes to Consolidated Financial Statements

Financial assets are also derecognized when the Company 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 FVTPL. For other financial instruments, such as debt instruments, transaction costs are recognized as part of the carrying amount of the financial instrument. The Company 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 Company 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

Where hedge accounting can be applied and the Company 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 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 Company’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.

SA-23

Notes to Consolidated Financial Statements

The Company 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 Company does not apply hedge accounting, the derivative is recognized at fair value on the Consolidated Statements of Financial Position, with subsequent changes in fair value recorded in net earnings in the period of change.

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.

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 other comprehensive earnings (“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 accumulated other comprehensive earnings (“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

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.

C. Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash and highly liquid investments with original maturities of three months or less.

SA-24

Notes to Consolidated Financial Statements

D. Inventory

I. Fuel

The Company’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.

IV. Emission Credits and Allowances

Emission credits and allowances are recorded as inventory at cost. Those purchased for use by the Company are recorded at cost and are carried at the lower of weighted average cost and net realizable value. For emission credits that are not ordinarily interchangeable, the Company records the credits using the specific identification method. 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 Company 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.

E. Property, Plant and Equipment

The Company’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.

SA-25

Notes to Consolidated Financial Statements

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 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 is 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 life 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 remaining useful lives of the components of depreciable assets, categorized by asset class, are as follows:

Hydro generation	2-51 years
Wind generation	2-30 years
Gas generation	2-36 years
Energy Transition	2-16 years
Capital spares and other	2-51 years

TransAlta capitalizes borrowing costs on capital invested in projects under construction. 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.

F. 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.

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Notes to Consolidated Financial Statements

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. 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, software and intangibles under development. Estimated remaining useful lives of intangible assets are as follows:

Software	2-7 years
Power sale contracts	1-19 years

G. Impairment of Tangible and Intangible Assets Excluding Goodwill

At the end of each reporting period, the Company 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 Company’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 Company 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 Company’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 Company. If the recoverable amount is less than the carrying amount of the asset or CGU, an asset impairment charge 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 charge 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 charge previously recognized is reversed. Where an impairment charge 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 charge been recognized previously. A reversal of an impairment charge is recognized in net earnings.

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Notes to Consolidated Financial Statements

H. 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 indicates 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 Company’s CGUs or groups of CGUs that are expected to benefit from the synergies of the business combination in which the goodwill arose. Accordingly, the Company performs its test for impairment, where the recoverable amount of the CGUs or groups of CGUs to which the goodwill relates is compared to its carrying amount for each operating segment. If the recoverable amount is less than the carrying amount, an impairment charge 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 charge recognized for goodwill is not reversed in subsequent periods.

I. Income Taxes

The Company 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 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. Unrecognized deferred tax assets are re-assessed at each reporting date and are recognised to the extent that it has become probable that future taxable income will allow the deferred income tax asset to be recovered.

Deferred income tax liabilities are recognized for taxable temporary differences arising on investments in subsidiaries, except where the Company 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.

Cash taxes paid disclosed on the Consolidated Statements of Cash Flows includes income taxes and taxes paid related to the Part VI. 1 tax in Canada for the period.

J. Employee Future Benefits

The Company 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

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Notes to Consolidated Financial Statements

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 Company’s defined benefit pension plans give rise to recording an additional liability, letters of credit provided by the Company 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.

K. Provisions

Provisions are recognized when the Company has a present obligation (legal or constructive) as a result of a past event, it is probable that the Company 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 Company 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 Company 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 Company determines the present value of the provision using the current discount rates that reflect the time value of money and associated risks. The Company 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(E)) to the extent the related PP&E asset is still in use. Where the related PP&E asset has reached the end of its useful life, changes in the decommissioning and restoration provision 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. Where the Company 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.

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.

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Notes to Consolidated Financial Statements

L. Leases

Under IFRS 16, a contract contains a lease when the customer obtains the right to control the use of an identified asset for a period of time in exchange for consideration.

Lessee

The Company enters into lease arrangements with respect to land, building and office space, vehicles and site machinery and equipment. For all contracts that meet the definition of a lease under IFRS 16 in which the Company is the lessee, and which are not exempt as short-term or low-value leases, the Company:

• Recognizes right-of-use assets and lease liabilities in the Consolidated Statements of Financial Position;

• Recognizes depreciation of the right-of-use assets and interest expense on lease liabilities in the Consolidated Statements of Earnings (Loss); and

• Recognizes the principal repayments on lease liabilities as financing activities and interest payments on lease liabilities as operating activities in the Consolidated Statements of Cash Flows.

For short-term and low-value leases, the Company recognizes the lease payments as operating expenses.

Variable lease payments that do not depend on an index or a rate are not included in the measurement of the lease liability and the right-of-use asset and are recognized as an expense in the period in which the event or condition that triggers the payments occurs.

Right-of-use assets are initially measured at an amount equal to the lease liability and adjusted for any payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset, or to restore the underlying asset or the site on which it is located, less any lease incentives received.

Lease liabilities are initially measured at the present value of the lease payments that are not paid at commencement and discounted using the Company’s incremental borrowing rate or the rate implicit in the lease. The lease liability is remeasured when there is a change in future lease payments arising from a change in an index or rate, or if there is a change in the Company’s estimate or assessment of whether it will exercise an extension, termination or purchase option. A corresponding adjustment is made to the carrying amount of the right-of-use asset, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero.

The lease term includes periods covered by an option to extend if the Company is reasonably certain to exercise that option and periods covered by an option to terminate if the Company is reasonably certain not to exercise that option.

Right-of-use assets are depreciated over the shorter period of either the lease term or the useful life of the underlying asset. If a lease transfers ownership of the underlying asset or the cost of the right-of-use asset reflects that the Company expects to exercise the purchase option, the related right-of-use asset is depreciated over the useful life of the underlying asset.

The Company has elected to apply the practical expedient that permits a lessee not to separate non-lease components, and instead account for any lease and associated non-lease components as a single arrangement.

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Notes to Consolidated Financial Statements

Lessor

PPAs and other long-term contracts may contain, or may be considered, leases where the fulfillment 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 control the use of that asset.

Where the Company 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 Company determines that the contractual provisions of a contract contain, or are, a lease and result in the Company 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.

When the Company has subleased all or a portion of an asset it is leasing and for which it remains the primary obligor under the lease, it accounts for the head lease and the sublease as two separate contracts. The sublease is classified as a finance lease by reference to the right-of-use asset arising from the head lease.

M. Non-Controlling Interests

Non-controlling interests arise from business combinations in which the Company 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 Company determines on a transaction-by-transaction basis for which the measurement method is used. Non-controlling interests also arise from other contractual arrangements between the Company and other parties, whereby the other party has acquired an equity interest in a subsidiary, and the Company 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 earnings is attributed to the non-controlling interests even if this results in the non-controlling interests having a negative balance.

N. 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. The Company’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 Company 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.

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Notes to Consolidated Financial Statements

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 Company 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 Company’s share of the joint venture’s net earnings or loss after the date of acquisition. The impact of transactions between the Company and joint ventures is eliminated based on the Company’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 charge 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.

O. 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. A business consists of inputs and processes applied to those inputs that have the ability to contribute to the creation of outputs. 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.

The optional fair value concentration test is applied on a transaction-by-transaction basis, to permit a simplified assessment of whether an acquired set of activities and assets are not a business. Where substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, the Company may elect to treat the acquisition as an asset acquisition and not as a business combination.

P. 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 Company’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 Company’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 charge may exist or that a previously recognized impairment charge may no longer exist or may have decreased. In

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Notes to Consolidated Financial Statements

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.

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.

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. The Company evaluates the market design, transmission constraints and the contractual profile of each facility, as well as the Company’s own 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. The Company 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 2019 to 2021 is found in Notes 7, 18 and 21.

II. Leases

In determining whether the Company’s contracts contain, or are, leases, management must use judgment in assessing whether the contract provides the customer with the right to substantially all of the economic benefits from the use of the asset during the lease term and whether the customer obtains the right to direct the use of the asset during the lease term. For those agreements considered to contain, or be, leases, further judgment is required to determine the lease term by assessing whether termination or extension options are reasonably certain to be exercised. Judgment is also applied in identifying in-substance fixed payments (included) and variable payments that are based on usage or performance factors (excluded) and in identifying lease and non-lease components (services that the supplier performs) of contracts and in allocating contract payments to lease and non-lease components.

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Notes to Consolidated Financial Statements

For leases where the Company is a lessor, judgment is required to determine if substantially all of the significant risks and rewards of ownership are transferred to the customer or remain with the Company, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant and impact how the Company 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 Company 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 Company’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 Company’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 Company’s estimates could materially impact the amounts recognized for deferred income tax assets and liabilities. See Note 12 for further details on the impacts of the Company’s tax policies.

IV. Financial Instruments and Derivatives

The Company’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 15. Some of the Company’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 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 Company’s estimates of pricing and production to allow the future transaction to be fulfiled.

When the Company enters into contracts to buy or sell non-financial items, such as certain commodities, and the contracts can be settled net in cash, the Company must use judgment to evaluate whether such contracts were entered into and continue to be held for the purposes of the receipt or delivery of the commodity in accordance with the Company’s expected purchase, sale or usage requirements (i.e., normal purchase and sale). If this assertion cannot be supported, initially at contract inception and on an ongoing basis, the contracts must be accounted for as derivatives and measured at fair value, with changes in fair value recognized in net earnings. In

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Notes to Consolidated Financial Statements

supporting the normal purchase and sale assertion, the Company considers the nature of the contracts, the forecasted demand and supply requirements to which the contracts relate, and its past practice of net settling other similar contracts, which may taint the normal purchase and sale assertion. The Company also enters into PPAs and contracts for differences and judgment is applied to determine if the contract meets the ‘own use’ exemption or if derivative treatment is required.

V. Project Development Costs

Project development costs are recognized in operating expenses until construction of a facility 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 Company, at which time the costs incurred subsequently are included in PP&E or other assets. The appropriateness of capitalization of these costs is evaluated each reporting period, and amounts capitalized for projects no longer probable of occurring or when there is uncertainty of timing of when the projects will proceed are charged to net earnings. 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 Company, in determining the amount to be capitalized. Information on the write-off of project development costs is disclosed in Note 7.

VI. Provisions for Decommissioning and Restoration Activities

TransAlta recognizes provisions for decommissioning and restoration obligations as outlined in Note 2(K) and Note 23. Initial decommissioning provisions, and subsequent changes thereto, are determined using the Company’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. Information regarding significant judgments and estimates made during 2021 in respect of decommissioning and restoration provisions can be found in Notes 7 and 23.

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 18.

VIII. Employee Future Benefits

The Company 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;

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Notes to Consolidated Financial Statements

• 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 31 for disclosures on employee future benefits.

IX. Other Provisions

Where necessary, the Company 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 Company’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 9 and 23 with respect to other provisions.

X. Revenue from Contracts with Customers

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 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.

In determining the transaction price and estimates of variable consideration, management considers the past history of customer usage in estimating the goods and services to be provided to the customer. The Company also considers the historical production levels and operating conditions for its variable generating assets. The Company’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 Company estimates the amount of the transaction price to allocate to individual performance obligations based on their stand-alone selling price, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions.

The satisfaction of performance obligations requires management to make judgments 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 permits recognition of revenue at the invoiced amount, if that invoiced amount corresponds directly with the entity’s performance to date.

XI. Classification of Joint Arrangements

Upon entering into a joint arrangement, the Company must classify it as either a joint operation or joint venture, which classification affects the accounting for the joint arrangement. In making this classification, the Company

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Notes to Consolidated Financial Statements

exercises judgment in evaluating the terms and conditions of the arrangement to determine whether the parties have rights to the assets and obligations or rights to the net assets. Factors such as the legal structure, contractual arrangements and other facts and circumstances, such as where the purpose of the arrangement is primarily for the provision of the output to the parties and when the parties are substantially the only source of cash flows for the arrangement, must be evaluated to understand the rights of the parties to the arrangement.

XII. Significant Influence

Upon entering into an investment, the Company must classify it as either an investment as an associate or an investment under IFRS 9. In making this classification, the Company exercises judgment in evaluating whether the Company has significant influence over the investee. Significant influence is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control over those policies. If the Company holds 20 per cent or more of the voting rights in the investee, it is presumed that the entity has significant influence, unless it can be clearly demonstrated that this is not the case. Other factors such as representation on the board of directors, participation in policy-making processes, material transactions between the Company and investee, interchange of managerial personnel or providing essential technical information are considered when assessing if the Company has significant influence over an investee.

XIII. Change in Estimates

During the year ended Dec. 31, 2021, there were changes in estimates relating to defined benefit obligations and decommissioning and other provisions. Refer to Note 23 and 26 for further details. During the year ended Dec. 31, 2020, there were changes in estimates relating to the useful life of PP&E. Refer to Note 18 for further details.

3. Accounting Changes

A. Current Accounting Changes

I. Amendments to IAS 1 Presentation of Financial Statements: Material Accounting Policies

Effective for the 2021 annual financial statements, the Company early adopted amendments to IAS 1 Presentation of Financial Statements in advance of its mandatory effective date of Jan. 1,2023, which requires entities to disclose their material accounting policy information rather than their significant accounting policies. The Company has updated the accounting policies disclosed in Note 2 based on its assessment of the amended standard.

II. Amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use

Effective Jan. 1, 2021, the Company early adopted amendments to IAS 16 Property, plant and equipment (“IAS 16 Amendments”) in advance of its mandatory effective date of Jan. 1, 2022. The Company adopted the IAS 16 Amendments retroactively. No cumulative effect of initially applying the guidance arose. The IAS 16 Amendments prohibit deducting from the cost of an item of property, plant and equipment any proceeds from selling items produced while bringing that asset to the location and condition necessary for it to be capable of operating in a manner intended by management. Instead, an entity recognizes the proceeds from selling such items, and the cost of producing those items, in profit or loss. No adjustments resulted from early adopting the amendments.

III. IFRS 7 Financial Instruments: Disclosures — Interest Rate Benchmark Reform

The transition of the London Interbank Offered Rates (“LIBOR”) has begun with the cessation of the publication of one-week and two- month USD LIBOR occurring on Dec. 31, 2021. The remaining overnight, one-, three-,

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Notes to Consolidated Financial Statements

six-, and 12-month USD LIBOR will continue to be published until their cessation date on June 30, 2023. Existing financial instruments may continue to use USD LIBOR while they are published until they mature, however, new financial instruments will not be using USD LIBOR if entered into after Dec. 31, 2021. The IASB issued Interest Rate Benchmark Reform — Phase 2 in August 2020, which amends IFRS 9 Financial Instruments, IAS 39 Financial instruments: Recognition and Measurement, IFRS 7 Financial Instruments: Disclosures and IFRS 16 Leases. The amendments were effective Jan. 1, 2021, and were adopted by the Company on Jan. 1, 2021. There was no financial impact upon adoption.

The Company’s credit facilities references USD LIBOR for US-dollar drawings and the Canadian Dollar Offered Rate for Canadian drawings, and includes appropriate fallback language to replace these benchmark rates if a benchmark transition event were to occur. For the year ended Dec. 31, 2021, there were no drawings under the credit facilities. The Company has interest rate swap agreements in place with a notional amount of US$150 million referencing three-month LIBOR, expected to settle in the third quarter of 2022.

B. Future Accounting Changes

I. Amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets

On May 14, 2020, the IASB issued Onerous Contracts — Cost of Fulfilling a Contract and amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets to specify which costs to include when assessing whether a contract will be loss-making. The amendments are effective for annual periods beginning on or after Jan. 1, 2022, and will be adopted by the Company in 2022. The amendments are effective for contracts for which an entity has not yet fulfilled all its obligations on or after the effective date. No financial impact is expected upon adoption.

II. Amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction

On May 7, 2021, the IASB issued amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction. The amendments clarify that the initial recognition exemption under IAS 12 does not apply to transactions such as leases and decommissioning obligations. These transactions give rise to equal and offsetting temporary differences in which deferred tax should be recognized.

The amendments are effective for annual periods beginning on or after Jan. 1, 2023, with early application permitted. The Company’s current position aligns with the amendment and no financial impact is therefore expected upon adoption on the effective date.

III. Amendments to IAS 1 Classification of Liabilities as Current or Non-Current

In January 2020, the IASB issued amendments to IAS 1 Presentation of Financial Statements, to provide a more general approach to the presentation of liabilities as current or non-current based on contractual arrangements in place at the reporting date. These amendments specify that the rights and conditions existing at the end of the reporting period are relevant in determining whether the Company has a right to defer settlement of a liability by at least 12 months, provide that management’s expectations are not a relevant consideration as to whether the Company will exercise its rights to defer settlement of a liability and clarify when a liability is considered settled.

The amendments are effective for annual periods beginning on or after Jan. 1, 2023, and are to be applied retrospectively. The Company has not yet determined the impact of these amendments on its consolidated financial statements.

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Notes to Consolidated Financial Statements

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. Business Acquisitions and Divestitures

In accordance with IFRS 3 Business Combinations, the substance of the transactions described below constituted a business combination for TransAlta. The fair values of the identifiable assets and liabilities of the acquired entity in the business combinations as at the date of acquisition were:

	North Carolina Solar (A) Nov. 5, 2021			Ada facility (B) May 19, 2020
Assets
Cash and cash equivalents		4			1
Accounts receivable		4			3
Property, plant and equipment		146			1
Intangible assets(1)		—			37
Right of use assets		13			—
Inventory		—			1
Prepaid expenses		—			1
Liabilities
Accounts payable and accrued liabilities		(4	)		—
Lease liabilities		(13	)		—
Tax equity liability		(20	)		—
Deferred taxes		(3	)		—
Risk management liabilities (current and long-term)		—			(5	)
Decommissioning provisions		(4	)		(1	)
Net assets acquired		123			38
Cash consideration		120			32
Working capital consideration		3			6
Total purchase consideration transferred		123			38

1) This relates to the power sales contract acquired and is being amortized over six years.

A. Acquisition of North Carolina Solar

On Nov. 5, 2021, the Company closed the acquisition of a 100 per cent membership interest in CI-II Mitchell Holding LLC, owner of a 122 MW portfolio of operating solar sites located in North Carolina (collectively, “North Carolina Solar”), for cash consideration of US$99 million (including working capital adjustments) and the assumption of existing tax equity obligations. The acquisition was funded using existing liquidity. The North Carolina Solar facility consists of 20 solar photovoltaic sites across North Carolina. The sites were commissioned between November 2019 and May 2021 and are all operational. The facility is secured by long-term PPAs with Duke Energy, which have an average remaining term of 12 years. Under the PPAs, Duke Energy receives the renewable electricity, capacity and environmental attributes from each facility.

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Notes to Consolidated Financial Statements

Certain assets and liabilities have been measured on a provisional basis. If new facts and circumstances are obtained within one year from the date of acquisition that existed at the date of acquisition, any identified adjustments to the above amounts or additional provisions that existed at the date of acquisition, may result in a revision to the accounting for the acquisition.

Had North Carolina Solar been acquired at the beginning of the year, the assets would have contributed an estimated $16 million to revenues and $9 million to net earnings before taxes.

At the closing of the acquisition, TransAlta Renewables Inc. (“TransAlta Renewables”), a subsidiary of the Company, acquired a 100 per cent economic interest in North Carolina Solar from a wholly owned subsidiary of the Company through a tracking preferred share structure for aggregate consideration of approximately US$102 million.

B. Acquisition of the Ada Facility

On May 19, 2020, the Company closed the acquisition of a contracted natural-gas-fired cogeneration facility from two private companies for a purchase price of US$27 million. The Ada facility is a 29 MW cogeneration facility in Michigan that is contracted under a PPA and a steam sale agreement for approximately 6 years with Consumers Energy and Amway.

C. Sale of Pioneer Pipeline

On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. (“ATCO”) for the aggregate sale price of $255 million. The net cash proceeds to TransAlta from the sale of its 50 per cent interest was approximately $128 million, subject to certain adjustments.

As a result of this sale, the Company has derecognized the related Pioneer Pipeline assets that were classified as assets held for sale of $97 million and recognized a gain on sale of $31 million on the statement of earnings. In addition, as part of the transaction, the natural gas transportation agreement with the Pioneer Pipeline Limited Partnership was terminated, which resulted in the derecognition of the right-of-use asset of $41 million and a lease liability of $43 million related to the pipeline, resulting in a gain of $2 million.

5. Revenue

A. Disaggregation of Revenue

The majority of the Company’s revenues are derived from the sale of physical power, capacity and environmental attributes, leasing of power facilities, and from asset optimization activities, which the Company disaggregates into the following groups for the purpose of determining how economic factors affect the recognition of revenue.

Year ended Dec. 31, 2021	Hydro		Wind and Solar			Gas(1)			Energy Transition(2)		Energy Marketing		Corporate and Other		Total
Revenues from contracts with customers
Power and other(3)		28		207			395			24		—		—		654
Environmental attributes		—		28			—			—		—		—		28
Revenue from contracts with customers		28		235			395			24		—		—		682
Revenue from leases(4)		—		—			19			—		—		—		19
Revenue from derivatives and other trading activities		—		(25	)		(118	)		138		211		4		210
Merchant revenue and other(3)(5)		355		95			813			547		—		—		1,810
Total revenue		383		305			1,109			709		211		4		2,721

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Notes to Consolidated Financial Statements

Year ended Dec. 31, 2021	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)		Energy Marketing		Corporate and Other		Total
Revenues from contracts with customers Timing of revenue recognition
At a point in time		—		28		2		23		—		—		53
Over time		28		207		393		1		—		—		629
Total revenue from contracts with customers		28		235		395		24		—		—		682

(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details.

(3) The Alberta PPAs for certain facilities included in the Hydro, Gas and Energy Transition segments with the Balancing Pool expired at Dec. 31, 2020. These facilities began operating on a merchant basis in the Alberta market on Jan. 1, 2021.

(4) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases.

(5) Includes merchant revenue, government incentives and other miscellaneous.

Year ended Dec. 31, 2020	Hydro		Wind and Solar			Gas(1)			Energy Transition(2)		Energy Marketing		Corporate and Other			Total
Revenues from contracts with customers
Power and other		141		238			465			156		—		—			1,000
Environmental attributes		—		23			—			—		—		—			23
Revenue from contracts with customers		141		261			465			156		—		—			1,023
Revenue from leases(3)		—		—			123			—		—		—			123
Revenue from derivatives and other trading activities		—		(2	)		(8	)		283		122		12			407
Merchant revenue and other(4)		11		70			207			265		—		(5	)		548
Total revenue		152		329			787			704		122		7			2,101
Revenues from contracts with customers Timing of revenue recognition
At a point in time		—		25			7			26		—		—			58
Over time		141		236			458			130		—		—			965
Total revenue from contracts with customers		141		261			465			156		—		—			1,023

(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details.

(3) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases.

(4) Includes merchant revenue, government incentives and other miscellaneous

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Notes to Consolidated Financial Statements

Year ended Dec. 31, 2019	Hydro		Wind and Solar		Gas(1)			Energy Transition(2)		Energy Marketing		Corporate and Other			Total
Revenues from contracts with customers
Power and other		142		221		497			185		—		—			1,045
Environmental attributes		—		23		—			—		—		—			23
Revenue from contracts with customers		142		244		497			185		—		—			1,068
Revenue from leases(3)		—		—		130			—		—		—			130
Revenue from derivatives and other trading activities		—		18		(15	)		160		129		4			296
Merchant revenue and other(4)		14		50		239			560		—		(10	)		853
Total revenue		156		312		851			905		129		(6	)		2,347
Revenues from contracts with customers Timing of revenue recognition
At a point in time		—		27		5			46		—		—			78
Over time		142		217		492			139		—		—			990
Total revenue from contracts with customers		142		244		497			185		—		—			1,068

(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details.

(3) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases.

(4) Includes merchant revenue, government incentives and other miscellaneous.

B. Contract Liabilities

The Company has recognized the following revenue-related contract liabilities:

Contract liabilities	2021			2020
Balance, beginning of the year		15			15
Amounts transferred to revenue included in opening balance		(1	)		(1	)
Consideration received		8			1
Increases due to amounts billed to customers		—			2
Changes in transaction price		11			—
Performance obligations satisfied		(1	)		(2	)
Balance, end of year		32			15
Current portion		19			1
Long-term portion		13			14

The contract liabilities outstanding at Dec. 31, 2021, and Dec. 31, 2020, primarily relate to prepayments relating to the Company’s New Richmond and Bone Creek facilities where the Company still has to fulfil its performance obligations. In addition, the Company recognized a provision for liquidated damages due to the Sarnia outages that occurred in the second quarter of 2021.

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Notes to Consolidated Financial Statements

C. Remaining Performance Obligations

The following disclosures regarding the aggregate amounts of transaction prices allocated to remaining performance obligations (contract revenues that have not yet been recognized) for contracts in place at the end of the reporting period exclude revenues related to contracts that qualify for the invoice practical expedient and contracts with an original expected duration of less than 12 months.

Additionally, in many of the Company’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 Company’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.

Contracts with customers that are accounted for as derivatives are excluded from these disclosures. Refer to Note 15 for further details. Contracts that have been executed for development projects are excluded until commercial operations have been achieved.

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 Company from its contractual portfolio.

Hydro

At Dec. 31, 2020, the Company’s PPA with the Balancing Pool to provide the capacity of 12 hydro facilities throughout the province of Alberta concluded. Commencing Jan. 1, 2021, production has been sold into the Alberta merchant market.

The Company has contracts for services at specific hydro facilities, which will conclude at the end of 2030. The Company also has a contract with the Government of Alberta to manage water for flood and drought mitigation purposes, which concludes in 2026. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2021, are approximately $46 million.

Wind and Solar

At Dec. 31, 2021, the Company had long-term contracts with customers to deliver electricity and the associated renewable energy credits from three wind facilities located in Alberta, Minnesota and Quebec, 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 pricing subject to annual escalations for inflation. The Company expects to recognize such amounts as revenue as it delivers electricity over the remaining terms of the contracts, until 2024, 2034 and 2033, respectively. The variable revenues under the contracts are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures.

The Company 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 purchasers over the remaining terms of the contracts, from 2022 through 2024. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2021, are approximately $9 million.

Gas

At Dec. 31, 2020, the Company’s PPAs with the Balancing Pool for capacity and electricity from the Keephills Unit 2 and Sheerness Units 1 and 2 legacy coal facilities concluded. Future production has been sold into the merchant market.

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Notes to Consolidated Financial Statements

At Dec. 31, 2021, the Company has contracts with customers to deliver energy services from one of its gas facilities in Ontario. The contracts all consist of a single performance obligation requiring the Company to stand ready to deliver electricity and steam. On May 12, 2021, the Company executed an Amended and Restated Energy Supply Agreement with one of its large industrial customers at the Sarnia cogeneration facility that provides for the supply of electricity and steam. This agreement will extend the term of the original agreement from Dec. 31, 2022 to Dec. 31, 2032. However, if TransAlta is unable to enter into a new contract with the Ontario Independent Electricity System Operator or enter into agreements with its other industrial customers at the Sarnia cogeneration facility that extend past Dec. 31, 2025, then the Company has the option to provide notice of termination in 2022 that would terminate the Amended and Restated Energy Supply Agreement four years following such notice. The Company currently expects to recognize revenue as it delivers electricity and steam to the other industrial customers at the Sarnia cogeneration facility until the completion of the contracts in late 2025, or 2032, if the contract is extended.

At the same gas facility, the Company 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 Company’s control and are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Company 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, 2021, the Company had contracts with customers to deliver steam, hot water and chilled water from one of its other gas facilities in Ontario, extending through 2023 and 2033. Prices under these contracts include fixed annual fees, variable thermal energy charges based on gas prices, and fixed base amounts per gigajoule, subject to escalation annually for both gas prices and inflation. One contract includes minimum annual take-or-pay volumes. Estimated future revenues related to the remaining performance obligations for this contract as of Dec. 31,2021, are approximately $31 million.

The Company has a contract with its customer for provision of steam and electricity output at its Alberta cogeneration facility extending through to Dec. 31, 2029. The contract is considered an operating lease resulting in some revenues being classified for accounting purposes as variable lease revenues. Other revenue streams are based on cost-recovery mechanisms and are variable in nature and considered to be fully constrained and are these revenues are excluded from these disclosures.

The Company has a contract, commencing in late 2023, for the sale of capacity and electricity, exercisable at the option of the customer in Canada, under which the Company will receive a fixed capacity payment and variable energy payments based on production. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2021, are approximately $336 million, of which the Company expects to recognize on average, between $5 million to $10 million in 2023 and $40 million to $45 million annually thereafter for the duration of the contracts.

At Dec. 31, 2021, the Company has PPAs with customers to deliver electricity from its gas facilities located in Australia. 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. The variable revenues under the contracts are considered to be fully constrained and are excluded from these disclosures. Another one of the Company’s PPA to deliver electricity from its gas facilities is considered a finance lease resulting in some revenues being classified for accounting purposes as finance lease income and are excluded from these disclosures. The Company also earns revenues from providing operation and maintenance services for the facility for a fixed monthly fee. Estimated future revenues related to the remaining performance obligations for these contracts as at Dec. 31, 2021, are approximately $2.5 billion, of which the Company expects to recognize

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Notes to Consolidated Financial Statements

approximately $285 million in total over the next two fiscal years and on average, between approximately $85 million to $145 million annually thereafter for the duration of the remaining contract.

Energy Transition

At Dec. 31, 2020, the Company’s PPAs with the Balancing Pool for capacity and electricity from the Keephills Unit 1 coal facility concluded. Commencing Jan. 1,2021, production has been sold into the merchant market.

6. Expenses by Nature

Fuel and purchased power and operations, maintenance and administrative (“OM&A”) expenses classified by nature are as follows:

Year ended Dec. 31	2021				2020				2019
	Fuel and purchased power		OM&A		Fuel and purchased power		OM&A		Fuel and purchased power		OM&A
Gas fuel costs(1)		306		—		159		—		133		—
Coal fuel costs(1)(2)		164		—		269		—		310		—
Royalty, land lease, other direct costs		19		—		20		—		21		—
Purchased power		339		—		163		—		246		—
Mine depreciation(3)		190		—		144		—		119		—
Salaries and benefits		36		234		50		235		52		228
Other operating expenses(4)		—		277		—		237		—		247
Total		1,054		511		805		472		881		475

(1) During 2021, fuel costs have been split to show natural gas and coal fuel costs separately within the above table and carbon compliance costs have been reclassified from fuel and purchased power to a separate line called carbon compliance costs on the Consolidated Statements of Earnings (Loss). Prior periods have been adjusted to reflect these reclassifications.

(2) Included in coal fuel costs for 2021 was $17 million related to the impairment of coal inventory recorded during 2021 (2020 — $15 million). Refer to Note 17 for further details.

(3) Included in mine depreciation for 2021 was $48 million related to the mine depreciation that was initially recorded in the standard cost of coal inventory and then subsequently impaired during 2021 (2020 — $22 million). Refer to Note 17 for further details.

(4) Included in OM&A costs for 2021 was $28 million related to the write-down of parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities. Refer to Note 17 for further details.

7. Asset Impairment

As part of the Company’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 Company 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 Company 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 Company’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to the Company’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 2072.

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Notes to Consolidated Financial Statements

	2021		2020		2019
PP&E Impairments:
Energy Transition facilities and projects (reversals)		345		79		(151	)
Energy Transition - Centralia mine decommissioning and restoration provision		—		3		141
Changes in decommissioning and restoration provisions for retired assets(1)		32		—		2
Highvale mine		195		—		—
Kaybob Cogeneration Project		27		—		—
Wind		12		—		—
Hydro		5		2		—
Gas		5		—		—
Intangible asset impairment - coal rights(2)		17		—		—
Assets held for sale(3)		—		—		15
Project development costs(4)		10		—		18
Asset impairment		648		84		25

(1) Changes related to changes in discount rates on retired assets.

(2) Impaired to nil as no future coal will be extracted from this area of the mine.

(3) 2019 amounts relate to trucks and associated inventory to be sold within the Energy Transition segment and accordingly, these items were impaired to net realizable value.

(4) During 2021, the Company recorded an impairment of $9 million in the Hydro segment for the balance of project development costs at one of our hydro facilities as there is uncertainty on timing of when the project will proceed and $1 million related to projects that are no longer proceeding. During 2020, the Company wrote off nil (2019 — $18 million) in project development costs related to projects that are no longer proceeding within the Corporate segment.

A. Energy Transition Asset Impairments

During 2021, the Company recognized asset impairment charges in the Energy Transition segment as a result of the decision to suspend the Sundance Unit 5 repowering project ($191 million) and planned retirements of Keephills Unit 1, effective Dec. 31, 2021 ($94 million), Sundance Unit 4, effective April 1, 2022 ($56 million) Keephills Unit 1 and Sundance Unit 4 impairment assessments were based on the estimated salvage values of these units which were in excess of the expected economic benefits from these units. For the Sundance Unit 5 repowering project, the recoverable amount was determined based on estimated fair value less costs of disposal of selling the equipment for assets under construction and estimated salvage value for the balance of the costs. The fair value measurement for assets under construction is categorized as a Level III fair value measurement. The total remaining estimated recoverable amount and salvage values for Sundance Unit 5 repowering project was $33 million, of which $25 million was related to assets held for sale. Discounting did not have a material impact to these asset impairments. The asset retirement and project suspension decisions were based on the Company’s assessment of future market conditions, the age and condition of in-service units, as well as TransAlta’s strategic focus toward renewable energy solutions.

During 2020, the Company recognized an impairment on Sundance Unit 3 in the amount of $70 million due to the Company’s decision to retire the unit. As there were no estimated future cash flows from power generation expected to be derived from the unit, the unit was removed from the Alberta merchant CGU and immediately written down to the salvage value of the scrap materials. In addition, the Company recognized an impairment of $9 million (US$7 million) due to a decrease in the fair value of land for the Centralia mine determined through a third-party appraiser.

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Notes to Consolidated Financial Statements

In 2019, an internal valuation indicated the fair value less costs of disposal of the Centralia thermal facility CGU exceeded the carrying value, resulting in a recoverability test in 2019. The updated fair value included sustained changes in the market power price and cost of coal due to contract renegotiation. As a result of the recoverability test, an impairment reversal of $151 million was recorded in the Centralia segment.

B. Highvale Mine

During 2021, with the expected closure of the Highvale mine at the end of 2021, it was determined that the estimated salvage value exceeded the economic benefit to the Alberta Merchant CGU. The asset has been removed from the Alberta Merchant CGU for impairment purposes and was assessed for impairment as an individual asset which resulted in the recognized impairment charge of $195 million in the Energy Transition segment, with the asset being written down to salvage value.

C. Kaybob Cogeneration Project

On Oct. 1, 2019, TransAlta and Energy Transfer Canada (“ET Canada” formerly known as SemCAMS Midstream ULC) entered into definitive agreements to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant. The facility was expected to receive its final regulatory approvals in the second half of 2020 and begin construction in December 2020. On Sept. 25, 2020, the Alberta Utilities Commission (“AUC”) released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. TransAlta will not be proceeding with the Kaybob cogeneration facility as a result of ET Canada’s purported termination of the agreements to develop, construct and operate the 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant. As a result, the Company recorded an impairment of $27 million in the Corporate segment as this facility was not yet operational. The recoverable amount was based on estimated fair value less costs of disposal of reselling the equipment purchased to date. TransAlta has commenced an arbitration seeking compensation for ET Canada’s wrongful termination of the agreements. Refer to Note 36 for further details.

D. Wind Facilities

During the third quarter of 2021, the Company recorded an impairment of $10 million for a wind asset as result of an increase in estimated decommissioning costs after the review of a recent engineering study on the decommissioning costs of the wind sites. Refer to Note 23 for more details for changes in decommissioning and restoration provisions. The resulting fair value measurement less cost of disposal is categorized as a Level III fair value measurement and the Company has adjusted the expected value down to $65 million using discount rates of 5.0 per cent (Dec. 31,2020 — 5.3 per cent). The key assumptions impacting the determination of fair value are electricity production, sales prices and cost inputs, which are subject to measurement uncertainty.

During 2021, the Company recognized an impairment of $2 million related to the Kent Hills Wind LP tower failure. The Company’s subsidiary, Kent Hills Wind LP, experienced a single tower failure at its 167 MW Kent Hills wind facility in Kent Hills, New Brunswick. The failure involved a collapsed tower located within the Kent Hills 2 site. Refer to Note 24 for further details.

E. Impairment on Decommissioning and Restoration Provision on Retired Assets

During 2019, the Company adjusted the Centralia mine decommissioning and restoration provision as management no longer believed that the fine coal recovery and reclamation work will occur as originally proposed. At the end of 2019, the Company’s best estimate of the decommissioning and restoration provision increased by $141 million. Since the Centralia mine is no longer operating and reached the end of its useful life in 2006, this adjustment resulted in the immediate recognition of the full $141 million, through asset impairment charges to net earnings.

SA-47

Notes to Consolidated Financial Statements

8. Finance Lease Receivables

Amounts receivable under the Company’s finance leases associated with the Poplar Creek cogeneration facility and the Southern Cross Energy facilities are as follows:

As at Dec. 31	2021				2020
	Minimum lease receipts		Present value of minimum lease receipts		Minimum lease receipts		Present value of minimum lease receipts
Within one year		58		54		63		56
Second to fifth years inclusive		127		105		169		126
More than five years		80		66		100		82
		265		225		332		264
Less: unearned finance lease income		40		—		68		—
Total finance lease receivables		225		225		264		264
Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease receivables (Note 14)		40				36
Long-term portion of finance lease receivables		185				228
Total finance lease receivables		225				264

On Oct. 22, 2020, Southern Cross Energy (“SCE”), a subsidiary of the Company, replaced and extended its current long- term PPA with BHP Billiton Nickel West Pty Ltd. (“BHP”). The new agreement was effective Dec. 1, 2020, and replaces the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extends the term to Dec. 31, 2038, and provides SCE with the exclusive right to supply thermal and electrical energy from the Southern Cross Facilities for BHP’s mining operations located in the Goldfields region of Western Australia. For accounting purposes, the original agreement was accounted for as an operating lease. Under the new PPA, the agreement is now accounted for as a finance lease.

As a result, in 2020, the Company derecognized net assets of $77 million, which included balances for PP&E, intangible assets, deferred credits and prepaid expenses. In addition, the Company recognized a finance lease receivable of $89 million and a gain on asset disposition of $12 million. Subsequent to the transaction, the Company incurred additional major maintenance costs in relation to these assets which was recorded as a reduction to the gain on asset disposition.

9. Net Other Operating Expense (Income)

Net other operating income includes the following:

Year ended Dec. 31	2021			2020			2019
Alberta Off-Coal Agreement		(40	)		(40	)		(40	)
Supplier settlements		34			—			—
Onerous contract provisions		14			29			—
Insurance recoveries and other(1)		—			—			(9	)
Net other operating expense (income)		8			(11	)		(49	)

SA-48

Notes to Consolidated Financial Statements

(1) There were no insurance recoveries in 2021 or 2020. In 2019, the Company received $10 million in insurance recoveries related to insurance proceeds for tower fires at Wyoming and Summerview.

A. Alberta Off-Coal Agreement (“OCA”)

The Company receives payments from the Government of Alberta for the cessation of coal-fired emissions on or before Dec. 31, 2030. Under the terms of the agreement, the Company receives annual cash payments on or before July 31 of approximately $40 million ($37 million, net of the non-controlling interest related to Sheerness), which commenced Jan. 1, 2017, and will terminate at the end of 2030. The Company 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 which has been achieved effective Dec. 31, 2021. 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, 2030. In July 2018, the Company obtained financing against the OCA payments. Refer to Note 24 for further details.

B. Supplier Settlements

During 2021, $34 million was expensed relating to decisions to no longer proceed with the Sundance Unit 5 repowering project and to retire Keephills Unit 1, including a deferred asset of $10 million (US$8 million) for which the Company is unlikely to incur sufficient capital or operating expenditures to utilize the remaining credit.

C. Onerous Contract Provisions

During 2021, an onerous contract provision for future royalty payments of $14 million was recognized with the shutdown of the Highvale mine.

During 2020, an onerous contract provision of $29 million was recognized as a result of a decision to accelerate plans to eliminate coal as a fuel source by the end of 2021 at the Sheerness facility. The last coal shipment was received during the first quarter of 2021, while the payments under the coal supply agreement will continue until 2025.

10. Investments

The Company’s investments in joint ventures and associates that are accounted for using the equity method consist of its investments in Skookumchuck and EMG.

The change in investments is as follows:

	Skookumchuck			EMG			Total
Balance, Dec. 31, 2019		—			—			—
Contributions		86			16			102
Equity income		1			—			1
Change in foreign exchange rates		(2	)		(1	)		(3	)
Balance, Dec. 31, 2020		85			15			100
Equity income		12			(3	)		9
Distributions received		(4	)		—			(4	)
Balance, Dec. 31, 2021		93			12			105

SA-49

Notes to Consolidated Financial Statements

A. Skookumchuck Wind Project

On Nov. 25, 2020, TransAlta completed the purchase of a 49 per cent interest in SP Skookumchuck Investments, LLC from Southern Power for cash consideration of $86 million (US$66 million). Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state consisting of 38 Vestas V136 wind turbines. The project has a 20-year PPA with Puget Sound Energy.

B. EMG International Acquisition

On Nov. 30, 2020, TransAlta acquired a 30 per cent equity interest in EMG. Included in the purchase price of US$12 million is an estimated component contingent on EMG realizing certain earnings metrics in 2020 and 2021, following the acquisition. The final contingent amount will be calculated based on actual earnings metrics achieved. EMG is an established company with over 25 years of experience in process wastewater treatment and specializes in the design and construction of high-rate anaerobic digester systems. The investment provides an opportunity for TransAlta to leverage its expertise in on-site generation to support further advancements by EMG in the waste-to-energy space and will advance the Company’s Clean Electricity Growth plan in the US market .

Summarized financial information on the results of operations relating to the Company’s pro-rata interests in Skookumchuck and EMG is as follows:

Year ended Dec. 31	2021			2020
Results of operations
Revenues		19			3
Expenses		(10	)		(2	)
Proportionate share of net earnings		9			1

11. Net Interest Expense

The components of net interest expense are as follows:

Year ended Dec. 31	2021			2020			2019
Interest on debt		163			158			161
Interest on exchangeable debentures (Note 25)		29			29			20
Interest on exchangeable preferred shares (Note 25)		28			5			—
Interest income		(11	)		(10	)		(13	)
Capitalized interest (Note 18)		(14	)		(8	)		(6	)
Interest on lease liabilities		7			8			4
Credit facility fees, bank charges and other interest		18			18			15
Tax shield on tax equity financing (Note 24)(1)		(9	)		1			(35	)
Interest on line loss rule proceeding (Note 36(H)(I))		—			5			—
Other(2)		2			2			10
Accretion of provisions (Note 23)		32			30			23
Net interest expense		245			238			179

(1) Credit in 2021 primarily relates to the tax benefit associated with investment tax credits claimed in 2021 on the North Carolina Solar projects that was assigned to the tax equity investor. Credit in 2019 primarily relates to the tax benefit associated with bonus tax depreciation claimed in 2019 on the Big Level and Antrim projects that was assigned to the tax equity investor. The tax equity investments are treated as debt under IFRS and the monetization of the tax attributes is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.

SA-50

Notes to Consolidated Financial Statements

(2) In 2021, other interest expense included approximately nil (2020 — nil , 2019 — $5 million) for the significant financing component required under IFRS 15.

12. Income Taxes

A. Consolidated Statements of Earnings

I. Rate Reconciliations

Year ended Dec. 31	2021			2020			2019
Earnings (loss) before income taxes		(380	)		(303	)		193
Net earnings (loss) attributable to non-controlling interests not subject to tax		(33	)		2			(26	)
Adjusted earnings (loss) before income taxes		(413	)		(301	)		167
Statutory Canadian federal and provincial income tax rate (%)		23.6	%		24.5	%		26.5	%
Expected income tax expense (recovery)		(98	)		(74	)		44
Increase (decrease) in income taxes resulting from:
Differences in effective foreign tax rates		4			3			5
Deferred income tax expense related to temporary difference on investment in subsidiaries		—			9			—
Write-down (reversal of write-down) of unrecognized deferred income tax assets		134			8			(9	)
Statutory and other rate differences		4			(7	)		(31	)
Other		1			11			8
Income tax expense (recovery)		45			(50	)		17
Effective tax rate (%)		(11	%)		17	%		10	%

II. Components of Income Tax Expense

The components of income tax expense are as follows:

Year ended Dec. 31	2021			2020			2019
Current income tax expense		56			35			35
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences		(145	)		(95	)		22
Deferred income tax expense related to temporary difference on investment in subsidiary		—			9			—
Deferred income tax recovery resulting from changes in tax rates or laws		—			(7	)		(31	)
Deferred income tax expense (recovery) arising from the unrecognized deferred income tax assets(1)		134			8			(9	)
Income tax expense (recovery)		45			(50	)		17
Year ended Dec. 31	2021			2020			2019
Current income tax expense		56			35			35
Deferred income tax recovery		(11	)		(85	)		(18	)
Income tax expense (recovery)		45			(50	)		17

SA-51

Notes to Consolidated Financial Statements

(1) During the year ended Dec. 31, 2021, the Company recorded a write-down of deferred tax assets of $134 million (2020 —$8 million write-down, 2019 — $9 million write-down reversal). In the current year additional deferred tax assets were created from the recognition of other comprehensive losses in the US. The deferred income tax assets mainly relate to the tax benefits of losses associated with the Company’s directly owned US operations and Canadian operations. The Company evaluates at each period end, whether it is probable that sufficient future taxable income would be available from the Company’s directly owned US operations to utilize the underlying tax losses.

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	2021			2020			2019
Income tax expense (recovery) related to:
Net impact related to cash flow hedges		(57	)		(23	)		6
Net actuarial gains (losses)		11			(3	)		(7	)
Income tax recovery reported in equity		(46	)		(26	)		(1	)

C. Consolidated Statements of Financial Position

Significant components of the Company’s deferred income tax assets (liabilities) are as follows:

As at Dec. 31	2021			2020
Net operating loss carryforwards(1)		530			469
Future decommissioning and restoration costs		183			140
Property, plant and equipment		(651	)		(717	)
Risk management assets and liabilities, net		(53	)		(107	)
Employee future benefits and compensation plans		53			62
Interest deductible in future periods		17			22
Foreign exchange differences on US-denominated debt		16			31
Other deductible temporary differences		(5	)		2
Net deferred income tax liability, before write-down of deferred income tax assets		90			(98	)
Unrecognized deferred income tax assets		(380	)		(247	)
Net deferred income tax liability, after write-down of deferred income tax assets		(290	)		(345	)

(1) Net operating losses expire between 2031 and 2040.

The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows:

As at Dec. 31	2021			2020
Deferred income tax assets(1)		64			51
Deferred income tax liabilities		(354	)		(396	)
Net deferred income tax liability		(290	)		(345	)

SA-52

Notes to Consolidated Financial Statements

(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 Company’s long-range forecasts.

D. Contingencies

As of Dec. 31, 2021, the Company had recognized a net liability of nil (2020 — nil) related to uncertain tax positions.

Ongoing CRA Audit

The Company is subject to routine audits of its tax filing positions by the Canada Revenue Agency (“CRA”) on an ongoing basis. The CRA is currently examining the Company’s tax filings for the 2015 taxation year and, in connection with such audit, is reviewing the internal reorganization completed in 2015. To date, the CRA has not proposed any reassessment of the Company’s tax liability as a consequence of such audit and management believes that any reassessment would be without merit. The Company strongly believes that the Company’s tax filing positions are appropriate, and accordingly no amounts have been accrued in the consolidated financial statements in respect of any such potential reassessment. If a notice of reassessment were issued, the Company would expect to vigorously oppose any such reassessment. If the CRA were to issue such a reassessment, the Company would be required to pay, on a provisional basis, up to 50 per cent of the amounts assessed, estimated to be between nil and $57 million. Any payment made by the Company in this context would be held by CRA until the final resolution of the dispute. The Company firmly believes it will be able to successfully defend its original filing position so that, ultimately, no increased income tax payable will result from the CRA’s audit and any amounts paid to the CRA by the Company would be refunded.

13. Non-Controlling Interests

The Company’s subsidiaries and operations that have non-controlling interests are as follows:

Subsidiary/Operation	Non-controlling interest as at Dec. 31, 2021
TransAlta Cogeneration L.P.	49.99% — Canadian Power Holdings Inc.
TransAlta Renewables	39.9% — 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 dual-fuel generating 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 Company.

SA-53

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 facility located in New Brunswick.

Year ended Dec. 31	2021		2020		2019
Revenues		470		436		446
Net earnings		139		97		183
Total comprehensive earnings		66		223		138
Amounts attributable to the non-controlling interests:
Net earnings		50		40		73
Total comprehensive earnings		21		90		56
Distributions paid to non-controlling interests		100		80		69

As at Dec. 31	2021			2020
Current assets		430			743
Long-term assets		3,319			2,913
Current liabilities		(593	)		(364	)
Long-term liabilities		(1,033	)		(987	)
Total equity		(2,123	)		(2,305	)
Equity attributable to non-controlling interests		(869	)		(948	)
Non-controlling interests’ share (per cent)		39.9			39.9

In 2020, the Company’s ownership per cent decreased from 60.4 per cent in 2019 to 60.1 per cent due to TransAlta Renewables issuing approximately 1 million common shares under their Dividend Reinvestment Plan (“DRIP”). The Company did not participate in this plan. In the fourth quarter of 2020, TransAlta Renewables suspended the DRIP in respect of any future declared dividends.

B. TA Cogen

Year ended Dec. 31	2021		2020			2019
Results of operations
Revenues		265		146			181
Net earnings (loss)		103		(13	)		43
Total comprehensive earnings (loss)		103		(13	)		43
Amounts attributable to the non-controlling interest:
Net earnings (loss)		62		(6	)		21
Total comprehensive earnings (loss)		62		(6	)		21
Distributions paid to Canadian Power Holdings Inc.		56		17			37

SA-54

Notes to Consolidated Financial Statements

As at Dec. 31	2021			2020
Current assets		66			69
Long-term assets		312			323
Current liabilities		(52	)		(78	)
Long-term liabilities		(36	)		(37	)
Total equity		(290	)		(277	)
Equity attributable to Canadian Power Holdings Inc.		(142	)		(136	)
Non-controlling interest share (per cent)		49.99			49.99

In 2020, the Balancing Pool PPA concluded and the Sheerness facility became a merchant facility in 2021. This resulted in new protocols under the amended contractual agreement whereby the revenue and cost of sales for the facility are allocated based on dispatch activities. Capital and operating expenses continue to be allocated based on ownership interest.

14. Trade and Other Receivables

As at Dec. 31	2021		2020
Trade accounts receivable	��	499		488
Collateral paid (Note 16)		55		49
Current portion of finance lease receivables (Note 8)		40		36
Loan receivable (Note 22)		55		—
Income taxes receivable		2		10
Trade and other receivables		651		583

15. 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. The following table outlines the carrying amounts and classifications of the financial assets and liabilities:

Carrying value as at Dec. 31, 2021
	Derivatives used for hedging		Derivatives held for trading (FVTPL)		Amortized cost		Total
Financial assets
Cash and cash equivalents(1)		—		—		947		947
Restricted cash		—		—		70		70
Trade and other receivables		—		—		651		651
Long-term portion of finance lease receivable		—		—		185		185
Risk management assets
Current		36		272		—		308
Long-term		252		147		—		399

SA-55

Notes to Consolidated Financial Statements

Carrying value as at Dec. 31, 2021
	Derivatives used for hedging		Derivatives held for trading (FVTPL)		Amortized cost		Total
Financial liabilities
Accounts payable and accrued liabilities		—		—		689		689
Dividends payable		—		—		62		62
Risk management liabilities
Current		—		261		—		261
Long-term		—		145		—		145
Credit facilities, long-term debt and lease liabilities(2)		—		—		3,267		3,267
Exchangeable securities (Note 25)		—		—		735		735

(1) Includes cash equivalents of nil.

(2) Includes current portion.

Carrying value as at Dec. 31, 2020
	Derivatives used for hedging		Derivatives held for trading (FVTPL)		Amortized cost		Total
Financial assets
Cash and cash equivalents(1)		—		—		703		703
Restricted cash		—		—		71		71
Trade and other receivables		—		—		583		583
Long-term portion of finance lease receivables		—		—		228		228
Risk management assets
Current		102		69		—		171
Long-term		471		50		—		521
Other assets (Note 22)		—		—		52		52
Financial liabilities
Accounts payable and accrued liabilities		—		—		599		599
Dividends payable		—		—		59		59
Risk management liabilities
Current		10		84		—		94
Long-term		—		68		—		68
Credit facilities, long-term debt and lease liabilities(2)		—		—		3,361		3,361
Exchangeable securities (Note 25)		—		—		730		730

(1) Includes cash equivalents of nil.

(2) Includes current portion.

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 Company has access. In the absence of an active market, the Company determines fair values based on valuation models or by reference to other similar products in active markets.

SA-56

Notes to Consolidated Financial Statements

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

I. Level I, II and III Fair Value Measurements

The Level I, II and III classifications in the fair value hierarchy utilized by the Company 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.

a. Level I

Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date. In determining Level I fair values, the Company 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.

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.

The Company’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 interpolation formulas, where the inputs are readily observable.

In determining Level II fair values of other risk management assets and liabilities, the Company 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 Company 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 Company 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 mark-to-forecast and mark-to-model. For mark-to-model valuations, derivative pricing models, regression-based models and historical bootstrap models may be employed. The model inputs may be based on historical data such as unit availability, transmission congestion, demand profiles for individual non-standard deals and structured products, and/or volatility and correlations between products derived from historical price relationships.

The Company 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.

SA-57

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, 2021, are as follows: Level I — $12 million net asset (Dec. 31, 2020 — $13 million net liability), Level II — $122 million net asset (Dec. 31, 2020 — $27 million net liability) and Level III — $159 million net asset (Dec. 31, 2020 — $582 million net asset).

Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2021, are primarily attributable to volatility in market prices on both existing contracts and new contracts as well as contract settlements.

The following tables summarize the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification during the years ended Dec. 31, 2021 and 2020, respectively:

	Year ended Dec. 31, 2021									Year ended Dec. 31, 2020
	Hedge			Non-hedge			Total			Hedge			Non-hedge			Total
Opening balance		573			9			582			678			8			686
Changes attributable to:
Market price changes on existing contracts		(181	)		4			(177	)		(18	)		3			(15	)
Market price changes on new contracts		—			(134	)		(134	)		—			7			7
Contracts settled		(107	)		(5	)		(112	)		(71	)		(10	)		(81	)
Change in foreign exchange rates		—			—			—			(16	)		1			(15	)
Net risk management assets (liabilities) at end of period		285			(126	)		159			573			9			582
Additional Level III information:
Losses recognized in other comprehensive earnings		(181	)		—			(181	)		(34	)		—			(34	)
Total gains (losses) included in earnings before income taxes		107			(130	)		(23	)		71			11			82
Unrealized gains (losses) included in earnings before income taxes relating to net assets held at period end		—			(135	)		(135	)		—			1			1

The Company 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.

The Company’s risk management department determines methodologies and procedures regarding commodity risk management Level III fair value measurements. Level III fair values are primarily calculated within the Company’s energy trading risk management system. These calculations are 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.

SA-58

Notes to Consolidated Financial Statements

As at Dec. 31, 2021, the total Level III risk management asset balance was $305 million (2020 — $615 million) and Level III risk management liability balance was $146 million (2020 — $33 million). The 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. These include the effects on fair value of discounting, liquidity and credit value adjustments; however, the potential offsetting effects of Level II positions are not considered. 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, volatility in commodity prices and correlations, delivery volumes, escalation rates and cost of supply. During 2021, the sensitivities include the effects of liquidity and credit value adjustments.

As at	Dec. 31, 2021
Description	Sensitivity		Valuation technique	Unobservable input	Reasonable possible change
Long-term power sale – US		+22 -145	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$3 or price increase of US$20
Coal transportation – US		+3 -18	Numerical derivative valuation	Illiquid future power prices (per MWh) Volatility Rail rate escalation	Price decrease of US$3 or price increase of US$20 80% to 120% zero to 4%
Full requirements – Eastern US		+9 -9	Historical bootstrap	Volume Cost of supply	95% to 105% (+/-) US$1 per MWh
Long-term wind energy sale – Eastern US		+17 -16	Long-term price forecast	Illiquid future power prices (per MWh) Illiquid future REC prices (per unit)	Price increase or decrease of US$6 Price decrease of US$3 or increase of US$2
Long-term wind energy sale – Canada		+21 -11	Long-term price forecast	Illiquid future power prices (per MWh) Wind discounts	Price decrease of C$24 or increase of C$5 5% decrease or 5% increase
Long-term wind energy sale - Central US		+27 -15	Long-term price forecast	Illiquid future power prices (per MWh) Wind discounts	Price decrease of US$2 or increase of US$ 3 3% decrease or 3% increase
Others		+6 -6

SA-59

Notes to Consolidated Financial Statements

As at	Dec. 31, 2020
Description	Sensitivity		Valuation technique	Unobservable input	Reasonable possible change
Long-term power sale – US		+35 -59	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$3 or a price increase of US$5
Coal transportation – US		+3 -5	Numerical derivative valuation	Illiquid future power prices (per MWh) Volatility Rail rate escalation	Price decrease of US$3 or a price increase of US$5 80% to 120% zero to 4%
Full requirements – Eastern US		+3 -3	Historical bootstrap	Volume Cost of supply	95% to 105% (+/-) US$1 per MWh
Long-term wind energy sale – Eastern US		+22 -22	Long-term price forecast	Illiquid future power prices (per MWh) Illiquid future REC prices (per unit)	Price increase or decrease of US$6 Price increase or decrease of US$1
Others		+5 -5

i. Long-Term Power Sale – US

The Company 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 2023, 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).

The contract is denominated in US dollars. The US dollar relative to the Canadian dollar remained consistent from Dec. 31, 2020, to Dec. 31, 2021, resulting in the sensitivity values remaining consistent. The balance for this contract at Dec. 31, 2021 decreased mainly due to higher forward power prices compared to previously estimated prices.

ii. Coal Transportation - US

The Company has a coal rail transport agreement that includes an upside sharing mechanism, with a contract start date of Jan. 1, 2021, that extends until Dec. 31, 2025. Option pricing techniques have been utilized to value the obligation associated with this component of the deal.

The key unobservable inputs used in the valuation include non-liquid power prices, option volatility and rail rate escalation. Reasonably possible alternative inputs were used to determine sensitivity on the fair value measurements.

For periods beyond 2023, 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

SA-60

Notes to Consolidated Financial Statements

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). Option volatility and rail rate escalation ranges have been determined based on historical data and professional judgment.

iii. Full Requirements – Eastern US

The Company has a portfolio of full requirement service contracts, whereby the Company agrees to supply specific utility customer needs for a range of products that may include electrical energy, capacity, transmission, ancillary services, renewable energy credits (“RECs”) and independent system operator costs.

The key unobservable inputs used in the portfolio valuation include delivered volume and supply cost. Hourly shaping of consumption will result in a realized cost that may be at a premium (or discount) relative to the average settled price. Reasonable possible alternative inputs are used to determine sensitivity on the fair value measurement.

iv. Long-Term Wind Energy Sale – Eastern US

In relation to the Big Level wind facility, the Company has a long-term contract for differences whereby the Company 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 based on proxy generation. Commercial operation of the facility was achieved in December 2019, with the contract commencing on July 1, 2019, and extending for 15 years after the commercial operation date. 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 non-liquid forward prices for power and RECs.

v. Long-Term Wind Energy Sale – Canada

In relation to the Garden Plain wind project, the Company has entered into a virtual PPA whereby the Company receives the difference between the fixed contract price per MWh and the Alberta Electric System Operator (“AESO”) settled pool price per MWh. The contract commences on commercial operation of the facility, which is expected by the end of 2022, and extending for 18 years past that date. The energy component of the contract is accounted for at fair value through profit or loss.

In addition to the virtual PPA contract, the Company has entered into a “bridge contract” that runs 16 months from Sept. 1, 2021 through Dec. 31, 2022, with the potential for extension at the virtual PPA price, depending on the commencement of commercial operations.

Under a separate agreement, Pembina has the option to purchase a 37.7 per cent interest in the project (49 per cent of the PPA). The option must be exercised no later than 30 days after commercial operational date.

The key unobservable inputs used in the valuation of the contracts are the non-liquid forward prices for power and monthly wind discounts.

SA-61

Notes to Consolidated Financial Statements

vi. Long-Term Wind Energy Sale – Central US

On Dec. 22, 2021, TransAlta executed two long-term virtual PPAs for the off take of 100 per cent of the generation from its 300 MW White Rock East and White Rock West wind power projects (collectively, the “White Rock Wind Projects”) to be located in Caddo County, Oklahoma. The Company receives the difference between the fixed contract price per MWh and the settled pool price per MWh. The contracts commence on commercial operation of the facilities, which is expected within the second half of 2023, and extend for 15 years past that date. The energy component of the contracts is accounted for at fair value through profit or loss.

The key unobservable inputs used in the valuation of the contracts are the non-liquid forward prices for power and monthly wind discounts.

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 asset fair value of $8 million as at Dec. 31, 2021 (Dec. 31, 2020 – $12 million net liability) are classified as Level II fair value measurements. The significant changes in other net risk management assets and liabilities during the year ended Dec. 31, 2021, are primarily attributable to favourable market prices on existing 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 value(1)
	Level I		Level II		Level III		Total
Exchangeable securities — Dec. 31, 2021		—		770		—		770		735
Long-term debt — Dec. 31, 2021		—		3,272		—		3,272		3,167
Exchangeable securities — Dec. 31, 2020		—		769		—		769		730
Long-term debt — Dec. 31, 2020		—		3,480		—		3,480		3,227

(1) Includes current portion.

The fair values of the Company’s debentures, senior notes and exchangeable securities 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.

The carrying amount of other short-term financial assets and liabilities (cash and cash equivalents, restricted cash, 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 22) and the finance lease receivables (see Note 8) approximate the carrying amounts.

SA-62

Notes to Consolidated Financial Statements

C. Inception Gains and Losses

The majority of derivatives traded by the Company 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 15 above 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	2021			2020			2019
Unamortized net gain (loss) at beginning of year		(33	)		9			49
New inception gain (loss)(1)		(50	)		(13	)		3
Amortization recorded in net earnings during the year		(19	)		(29	)		(43	)
Unamortized net gain (loss) at end of year(2)		(102	)		(33	)		9

(1) During 2021, the Company entered into PPAs for the White Rock Wind Projects that resulted in a new inception loss due to the difference between the fixed PPA price and future estimated market prices. There are other key factors, such as project economics and incentives, that influence the long-term power price for renewable projects outside of the power price curve, which is not liquid for the majority of the duration of the power agreement contract period. During 2020, the Company entered into a coal rail transportation agreement that includes an upside sharing mechanism. Option pricing techniques have been utilized to value the obligation associated with this component of the deal.

(2) During 2020, the net inception gain on the long-term fixed price power sale contract in the US changed to a loss position based on the day one forward price curve at inception of the contract.

16. Risk Management Activities

A. Risk Management Strategy

The Company is exposed to market risk from changes in commodity prices, foreign exchange rates, interest rates, credit risk and liquidity risk. These risks affect the Company’s earnings and the value of associated financial instruments that the Company holds. In certain cases, the Company seeks to minimize the effects of these risks by using derivatives to hedge its risk exposures. The Company’s risk management strategy, policies and controls are designed to ensure that the risks it assumes comply with the Company’s internal objectives and its risk tolerance.

The Company 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 Company 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 Company may apply hedge accounting to those hedging commodity price risk, interest rate risk and foreign currency risk.

SA-63

Notes to Consolidated Financial Statements

The use of financial derivatives is governed by the Company’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 Company 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 Company 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.

At the inception of the hedge relationship, the Company 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 Company 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 Company 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 Company adjusts the hedge ratio of the hedging relationship so that it continues to meet the qualifying criteria.

SA-64

Notes to Consolidated Financial Statements

B. Net Risk Management Assets and Liabilities

Aggregate net risk management assets (liabilities) are as follows:

As at Dec. 31, 2021
	Cash flow hedges		Not designated as a hedge			Total
Commodity risk management
Current		33		12			45
Long-term		252		(4	)		248
Net commodity risk management assets		285		8			293
Other
Current		3		(1	)		2
Long-term		—		6			6
Net other risk management assets		3		5			8
Total net risk management assets		288		13			301

As at Dec. 31, 2020
	Cash flow hedges			Not designated as a hedge			Total
Commodity risk management
Current		101			(11	)		90
Long-term		471			(19	)		452
Net commodity risk management assets (liabilities)		572			(30	)		542
Other
Current		(9	)		(4	)		(13	)
Long-term		—			1			1
Net other risk management liabilities		(9	)		(3	)		(12	)
Total net risk management assets (liabilities)		563			(33	)		530

I. Netting Arrangements

Information about the Company’s financial assets and liabilities that are subject to enforceable master netting arrangements or similar agreements is as follows:

As at Dec. 31	2021												2020
	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		394			330			(306	)		(122	)		120			69			(132	)		(104	)
Gross amounts set-off		(137	)		(53	)		138			54			(69	)		(10	)		69			10
Net amounts as included in the Consolidated Statements of Financial Position		257			277			(168	)		(68	)		51			59			(63	)		(94	)

SA-65

Notes to Consolidated Financial Statements

C. Nature and Extent of Risks Arising from Financial Instruments

I. Market Risk

a. Commodity Price Risk Management

The Company 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 Company’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 Company’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 Company’s proprietary trading business and commodity derivatives used in hedging relationships associated with the Company’s electricity generating activities.

To mitigate the risk of adverse commodity price changes, the Company 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 Company has executed commodity price hedges for its Centralia thermal facility 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 Company’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 Company’s exposure to market risks or the manner in which these risks are managed or measured.

i. Commodity Price Risk Management – Proprietary Trading

The Company’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 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 Company’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.

SA-66

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, 2021, associated with the Company’s proprietary trading activities was $2 million (2020 — $1 million, 2019 — $1 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 Company’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 Company’s reported net earnings.

VaR at Dec. 31, 2021, associated with the Company’s commodity derivative instruments used in generation hedging activities was $33 million (2020 — $12 million, 2019 — $25 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, 2021, associated with these transactions was $51 million (2020 — $15 million, 2019 — $8 million).

iii. Commodity Price Risk Management — Hedges

The Company’s outstanding commodity derivative instruments designated as hedging instruments are as follows:

As at Dec. 31	2021				2020
Type (thousands)	Notional amount sold		Notional amount purchased		Notional amount sold		Notional amount purchased
Electricity (MWh)(1)		—		—		95		—

(1) Excludes the long-term power sale - US contract. For further details on this contract, refer to Note 15(B)(I)(c)(i).

During 2021, unrealized pre-tax losses of $1 million (2020 — $1 million gains, 2019 — $1 million gains) 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 Company’s outstanding commodity derivative instruments not designated as hedging instruments are as follows:

As at Dec. 31	2021				2020
Type (thousands)	Notional amount sold		Notional amount purchased		Notional amount sold		Notional amount purchased
Electricity (MWh)		46,139		14,951		12,944		8,258
Natural gas (GJ)		7,501		173,898		23,035		177,448
Transmission (MWh)		37		1,097		—		1,578
Emissions (MWh)		445		2,030		1,831		2,112
Emissions (tonnes)		350		350		2,160		2,365
Coal (tonnes)		—		9,352		—		9,078

SA-67

Notes to Consolidated Financial Statements

b. Interest Rate Risk Management

Interest rate risk arises as the fair value of future cash flows from a financial instrument fluctuates because of changes in market interest rates. Changes in interest rates can impact the Company’s borrowing costs. Changes in the cost of capital may also affect the feasibility of new growth initiatives.

The Company’s credit facility and the Poplar Creek non-recourse bond are the only debt instruments subject to floating interest rates, which represent 3 per cent of the Company’s debt as at Dec. 31, 2021 (2020 – 7 per cent). Interest rate risk is managed with the use of derivatives. The Company’s outstanding interest rate derivative instruments are as follows:

In 2021, the Company had interest rate swap agreements in place with a notional amount of US$150 million (2020 — US$150 million) whereby the Company receives a variable rate of interest equal to the three-month LIBOR rate and pays interest at a fixed rate equal to 0.94 per cent (2020 — 0.94 per cent) on the notional amount. The swaps are being used to hedge interest rate exposure on a highly probable future US$400 million fixed rate debt issuance, expected to occur in 2022.

In 2021, the Company had bond lock agreements in place with a total notional amount of US$150 million (2020 — $75 million) whereby on the pricing date, if the difference between the underlying 1.375 per cent US Treasury bond (2020 — 5.75 per cent Government of Canada bond) and the forward bond yield (2020 — $150 million forward yield 1.20 per cent) is positive, the Company receives settlement. If the difference is negative, the Company pays settlement. The bond lock is being used to hedge interest rate exposure on a highly probable future US$400 million (2020 — $150 million) fixed rate debt issuance. The $75 million bond lock outstanding at Dec. 31, 2020, was settled in 2021.

There were no interest rate derivative instruments outstanding in 2019.

LIBOR reform could impact interest rate risk with respect to the Company’s credit facilities and the Poplar Creek non-recourse bond held by a TransAlta subsidiary. The facility references LIBOR for US dollar drawings and Canadian Dollar Offer Rate (“CDOR”) for Canadian dollar drawings, and includes appropriate fallback language to replace these benchmark rates if a benchmark transition event were to occur. Currently there are no drawings on the facility. The non-recourse bond references the three-month CDOR: however, only the six-and 12-month CDOR have been discontinued with no expectation to stop publishing other CDOR rates at this time.

In addition, the Company has interest rate swap agreements in place with a notional amount of US$150 million referencing the three-month LIBOR, expected to settle in the third quarter of 2022. The cessation date for three-month LIBOR is June 30, 2023.

c. Currency Rate Risk

The Company has exposure to various currencies, such as the US dollar and the Australian dollar, 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 Company 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; and

SA-68

Notes to Consolidated Financial Statements

• 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.

The Company’s 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 and the Australian exposure will be managed with a combination of interest expense on our Australian-dollar denominated debt and forward foreign exchange contracts.

i. Net Investment Hedges

When designating foreign currency debt as a hedge of the Company’s net investment in foreign subsidiaries, the Company has determined that the hedge is effective if the foreign currency of the net investment is the same as the currency of the hedge, and therefore an economic relationship is present.

The Company’s hedges of its net investment in foreign operations were comprised of US-dollar-denominated long-term debt with a face value of US$370 million (2020 — US$370 million).

ii. Cash Flow Hedges

The Company uses foreign exchange forward contracts to hedge a portion of its future foreign-denominated receipts and expenditures, and both foreign exchange forward contracts and cross-currency swaps to manage foreign exchange exposure on foreign-denominated debt not designated as a net investment hedge.

As at Dec. 31	2021					2020
Notional amount sold	Notional amount purchased	Fair value liability		Maturity		Notional amount sold	Notional amount purchased	Fair value liability			Maturity
Foreign exchange forward contracts – foreign-denominated receipts/expenditures
CAD10	USD8		—		2022	CAD71	USD54		(2	)		2021
AUD19	USD14		—		2022	—	—		—			—

iii. Non-Hedges

The Company 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	2021							2020
Notional amount sold	Notional amount purchased		Fair value asset (liability)			Maturity		Notional amount sold	Notional amount purchased	Fair value asset (liability)			Maturity
Foreign exchange forward contracts – foreign-denominated receipts/expenditures
AUD28		CAD26		(5	)		2022-2025	AUD197	CAD181		(14	)		2021 - 2024
USD271		CAD357		8			2022-2025	USD47	CAD72		9			2021 -2024
								AUD4	USD3		—			2021
								CAD1	EUR1		—			2021
Foreign exchange forward contracts – foreign-denominated debt
CAD191		USD150		1			2022	CAD191	USD150		2			2022

SA-69

Notes to Consolidated Financial Statements

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 Company’s functional currency, is outlined below. The sensitivity analysis has been prepared using management’s assessment that an average three cent (2020 — three cent, 2019 — three 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	2021					2020					2019
Currency	Net earnings increase (decrease)(1)			OCI gain(1)(2)		Net earnings decrease(1)			OCI gain(1)(2)		Net earnings decrease(1)			OCI gain(1)(2)
USD		(13	)		1		(8	)		1		(18	)		2
AUD		1			—		(4	)		—		(6	)		—
Total		(12	)		1		(12	)		1		(24	)		2

(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 Company by failing to discharge their obligations, and the risk to the Company associated with changes in creditworthiness of entities with which commercial exposures exist. The Company 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 Company 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 Company 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 Company 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 Company’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at Dec. 31, 2021:

	Investment grade (Per cent)		Non-investment grade (Per cent)		Total (Per cent)		Total amount
Trade and other receivables(1,2)		89		11		100		651
Long-term finance lease receivable		100		—		100		185
Risk management assets(1)		86		14		100		707
Total								1,543

(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.

SA-70

Notes to Consolidated Financial Statements

(2) Includes loan receivable with a counterparty that has no external credit rating. Refer to Note 22 for further details.

An impairment analysis is performed at each reporting date using a provision matrix to measure expected credit losses. The provision rates are based on segment historical rates of default of trade receivables as well as incorporating 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 Company did not have significant expected credit losses as at Dec. 31, 2021.

The Company’s maximum exposure to credit risk at Dec. 31, 2021, 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, 2021, was $37 million (2020 — $22 million).

Amidst the current economic conditions resulting from the COVID-19 pandemic, TransAlta has implemented the following additional measures to monitor its counterparties for changes in their ability to meet obligations:

• Daily monitoring of events impacting counterparty creditworthiness and counterparty credit downgrades;

• Weekly oversight and follow-up, if applicable, of accounts receivables; and

• Review and monitoring of key suppliers, counterparties and customers (i.e., offtakers).

As needed, additional risk mitigation tactics will be taken to reduce the risk to TransAlta. These risk mitigation tactics may include, but are not limited to, immediate follow-up on overdue amounts, adjusting payment terms to ensure a portion of funds are received sooner, requiring additional collateral, reducing transaction terms and working closely with impacted counterparties on negotiated solutions.

III. Liquidity Risk

Liquidity risk relates to the Company’s ability to access capital to be used for proprietary trading activities, commodity hedging, capital projects, debt refinancing and general corporate purposes. As at Dec. 31, 2021, TransAlta maintains an investment grade rating from one credit rating agency and below investment grade ratings from two credit rating agencies. Between 2022 and 2024, the Company has approximately $1 billion of debt maturing, comprised of approximately $515 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments and the classification of the Kent Hills Wind LP bond as current.

Collateral is posted based on negotiated terms with counterparties, which can include the Company’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs.

SA-71

Notes to Consolidated Financial Statements

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; and maintaining sufficient undrawn committed credit lines to support potential liquidity requirements. The Company does not use derivatives or hedge accounting to manage liquidity risk.

A maturity analysis of the Company’s financial liabilities is as follows:

	2022			2023			2024			2025			2026		2027 and thereafter			Total
Accounts payable and accrued liabilities		689			—			—			—			—		—			689
Long-term debt(1)
Debentures		—			—			—			—			—		251			251
Senior Notes		511			—			—			—			—		383			894
Non-recourse — Hydro		—			45			—			—			—		—			45
Non-recourse — Wind & Solar		263			49			52			54			51		283			752
Non-recourse — Gas		44			45			47			59			61		855			1,111
Tax equity financing		15			15			14			14			15		68			141
Other		3			1			—			—			—		—			4
Exchangeable securities(2)		—			—			—			750			—		—			750
Commodity risk management (assets) liabilities		(45	)		(35	)		(117	)		(95	)		1		(2	)		(293	)
Other risk management (assets) liabilities		(2	)		(3	)		(3	)		1			—		(1	)		(8	)
Lease liabilities(3)		(6	)		4			3			3			3		93			100
Interest on long-term debt and lease liabilities(4)		149			120			115			109			104		787			1,384
Interest on exchangeable securities(2,4)		53			53			62			—			—		—			168
Dividends payable		62						—			—			—		—			62
Total		1,736			294			173			895			235		2,717			6,050

(1) Excludes impact of hedge accounting and derivatives

(2) Assumes the exchangeable securities will be exchanged on Jan. 1, 2025. Refer to Note 25 for further details.

(3) Lease liabilities include a lease incentive of $13 million expected to be received in 2022.

(4) Not recognized as a financial liability on the Consolidated Statements of Financial Position.

IV. Equity Price Risk

a. Total Return Swaps

The Company has certain compensation, deferred and restricted share unit programs, the values of which depend on the common share price of the Company. The Company 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 Company’s common shares at the end of each quarter.

SA-72

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
	2022		2023		2024		2025		2026		2027 and thereafter
Cash flow hedges
Foreign currency forward contracts
Notional amount ($ millions)
CAD/USD		8		—		—		—		—		—
AUD/USD		14		—		—		—		—		—
Average Exchange Rate
CAD/USD		0.7893		—		—		—		—		—
AUD/USD		0.7352		—		—		—		—		—
Commodity derivative instruments Electricity
Notional amount (thousands MWh)		3,329		3,329		3,338		2,628		—		—
Average price ($ per MWh)		71.95		73.76		75.6		77.49		—		—

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, 2021
	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		13 MMWh		285		Risk management assets		(181	)
Interest rate risk
Cash flow hedges
Interest rate swap		USD300		3		Risk management assets		3
Foreign currency risk
Cash flow hedges
Foreign-denominated expenditures		USD8		—		Risk management assets		—
Foreign-denominated expenditures		USD14		—		Risk management assets		—
Net investment hedges
Foreign-denominated debt		USD370		CAD473		Credit facilities, long- term debt and lease liabilities		—

SA-73

Notes to Consolidated Financial Statements

As at Dec. 31, 2020
	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		16 MMWh		573			Risk management assets		(33	)
Interest rate risk
Cash flow hedges
Interest rate swap		USD150		(3	)		Risk management liabilities		3
Interest rate swap		CAD75		(4	)		Risk management liabilities		4
Foreign currency risk
Net investment hedges
Foreign-denominated debt		USD370		CAD472			Credit facilities, long- term debt and lease liabilities		11

The impact of the hedged items on the statement of financial position is as follows:

As at Dec. 31	2021		2020
	Change in fair value used for measuring ineffectiveness	Cash flow hedge reserve(1)	Change in fair value used for measuring ineffectiveness	Cash flow hedge reserve(1)
Commodity price risk
Cash flow hedges
Power forecast sales – Centralia	(181)	226	(33)		417
Interest rate risk
Cash flow hedges
Interest expense on long-term debt	3	2	7		19
	Change in fair value used for measuring ineffectiveness	Foreign currency translation reserve(1)	Change in fair value used for measuring ineffectiveness	Foreign currency translation reserve(1)
Foreign currency risk
Net investment hedges
Net investment in foreign subsidiaries	—	(35)	11		(21	)

(1) Included in AOCI.

The hedging loss recognized in OCI before tax is equal to the change in fair value used for measuring effectiveness for the net investment hedge. There is no ineffectiveness recognized in profit or loss.

SA-74

Notes to Consolidated Financial Statements

The impact of hedged items designated in hedging relationships on OCI and net earnings is:

Year ended Dec. 31, 2021
				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 recognized in OCI			Location of (gain) loss reclassified from OCI	Pre-tax (gain) loss recognized in earnings
Commodity contracts		(268	)	Revenue		(13	)	Revenue		—
Foreign exchange forwards on project hedges		—		Property, plant and equipment		1		Foreign exchange (gain) loss		—
Forward starting interest rate swaps		13		Interest expense		4		Interest expense		—
OCI impact		(255	)	OCI impact		(8	)	Net earnings impact		—

Over the next 12 months, the Company estimates that approximately $25 million of after-tax gain 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, 2020
				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 recognized from OCI			Location of (gain) loss reclassified from OCI	Pre-tax (gain) loss recognized in earnings
Commodity contracts		41		Revenue		(137	)	Revenue		—
Foreign exchange forwards on project hedges		(1	)	Property, plant and equipment		—		Foreign exchange (gain) loss		—
Forward starting interest rate swaps		(12	)	Interest expense		(4	)	Interest expense		—
OCI impact		28		OCI impact		(141	)	Net earnings impact		—

Year ended Dec. 31, 2019
			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		77	Revenue		(59	)	Revenue		—
Forward starting interest rate swaps		—	Interest expense		6		Interest expense		—
OCI impact		77	OCI impact		53	)	Net earnings impact		—

II. Effect of Non-Hedges

For the year ended Dec. 31, 2021, the Company recognized a net unrealized gain of $97 million (2020 — gain of $43 million, 2019 — gain of $33 million) related to commodity derivatives.

SA-75

Notes to Consolidated Financial Statements

For the year ended Dec. 31, 2021, a gain of $6 million (2020 — gain of $11 million, 2019 — gain of $24 million) related to foreign exchange and other derivatives was recognized, which consists of net unrealized gains of $4 million (2020 — loss of $2 million, 2019 — gain of $6 million) and net realized gains of $2 million (2020-gains of $13 million, 2019 — gains of $18 million), respectively.

F. Collateral

I. Financial Assets Provided as Collateral

At Dec. 31, 2021, the Company provided $55 million (2020 – $49 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, 2021, the Company held $18 million (2020 – nil) in cash collateral associated with counterparty obligations. Under the terms of the contracts, the Company 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 Company’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs.

As at Dec. 31, 2021, the Company had posted collateral of $356 million (2020 – $163 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 Company having to post an additional $120 million (2020 – $85 million) of collateral to its counterparties.

17. Inventory

The components of inventory are as follows:

As at Dec. 31	2021		2020
Parts and materials		82		107
Coal		27		83
Deferred stripping costs		—		8
Natural gas		3		2
Purchased emission credits(1)		55		38
Total		167		238

(1) Purchased emissions credits increased due to trading and compliance credits purchased, including those for Alberta compliance under the Technology Innovation and Emissions Reduction program.

SA-76

Notes to Consolidated Financial Statements

No inventory is pledged as security for liabilities.

Carbon compliance costs are regulated costs that the business incurs as a result of greenhouse gas emissions generated from our operating units. TransAlta’s exposure to carbon compliance costs is mitigated through the use of eligible emission credits generated from the Company’s Wind and Solar and Hydro segments, as well as, purchasing emission credits from the market at prices lower than the regulated compliance price of carbon. Emission credits generated from our Alberta business have no recorded book value but are expected to be used to offset emission obligations from our gas facilities located in Canada in the future when the compliance price of carbon is expected to increase, resulting in a reduced cash cost for carbon compliance. At Dec. 31, 2021, the Company currently holds 2,033,752 purchased emission credits (2020 — 1,434,761) recorded at $55 million (2020 — $38 million) and approximately 1,922,973 (2020 — 1,211,230) emission credits with no recorded book value.

The change in inventory is as follows:

	2021			2020
Balance, Jan. 1		238			251
Net additions (use)		22			26
Write-downs, coal		(65	)		(37	)
Write-downs, parts and materials		(28	)		—
Change in foreign exchange rates		—			(2	)
Balance, Dec. 31		167			238

With the decision in 2020 to adjust the useful life of the Highvale mine assets to align with the Company’s conversion to gas plans, the standard cost of coal increased during 2021 and 2020 as a result of increased depreciation costs and reduced coal consumption. During the same period, as the cost of the coal was not expected to be recovered based on power pricing, the Company recognized a $65 million (2020 — $37 million) write-down to net realizable value on its internally produced coal inventory for the year ended Dec. 31, 2021, of which $48 million relates to increased depreciation from the accelerated closure of the mine.

In addition, OM&A costs included a write-down of $28 million, for parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities. With the accelerated shutdown of the Highvale mine and full conversion to natural gas completed in 2021. It was determined that a portion of the coal-related parts and materials inventory would not be utilized in the operations of our converted natural gas facilities and therefore the value was adjusted down to the expected net realizable amounts for the end of 2021.

SA-77

Notes to Consolidated Financial Statements

18. Property, Plant and Equipment

A reconciliation of the changes in the carrying amount of PP&E is as follows:

	Land			Renewable generation			Gas generation(1)			Energy Transition(1)			Assets under construction			Capital spares and other(2)			Total
Cost
As at Dec. 31, 2019, as previously reported		91			3,574			1,671			7,342			228			489			13,395
Adjustments due to re-segmentation		—			—			2,402			(2,402	)		—			—			—
As at Dec 31, 2019, adjusted		91			3,574			4,073			4,940			228			489			13,395
Additions		—			—			—			—			478			8			486
Acquisitions (Note 4)		—			—			1			—			—			—			1
Disposals		(2	)		—			—			(1	)		—			(2	)		(5	)
Impairment (Note 7)		(9	)		(2	)		—			(69	)		—			(1	)		(81	)
Revisions and additions to decommissioning and restoration costs (Note 23)		—			8			1			85			—			—			94
Retirement of assets		—			(7	)		(47	)		(3	)		—			(1	)		(58	)
Change in foreign exchange rates		(1	)		(14	)		45			(39	)		—			6			(3	)
Transfers		17			33			(138	)		(12	)		(211	)		(120	)		(431	)
As at Dec. 31, 2020, adjusted		96			3,592			3,935			4,901			495			379			13,398
Additions		—			—			—			—			478			2			480
Acquisitions (Note 4)		—			146			—			—			—			—			146
Disposals		(1	)		—			(2	)		(74	)		(2	)		—			(79	)
Impairment (Note 7)		—			(15	)		(2	)		(468	)		(91	)		(13	)		(589	)
Revisions and additions to decommissioning and restoration costs (Note 23)		—			129			6			—			—			—			135
Retirement of assets		—			(15	)		(57	)		(49	)		—			—			(121	)
Change in foreign exchange rates		—			3			(25	)		2			—			(6	)		(26	)
Transfers		1			303			232			201			(696	)		4			45
As at Dec. 31, 2021		96			4,143			4,087			4,513			184			366			13,389

SA-78

Notes to Consolidated Financial Statements

	Land		Renewable generation			Gas generation(1)			Energy Transition(1)			Assets under construction		Capital spares and other(2)			Total
Accumulated depreciation
As at Dec. 31, 2019, as previously reported		—		1,284			900			4,836			—		168			7,188
Adjustments due to re-segmentation		—		—			1,137			(1,137	)		—		—			—
As at Dec 31, 2019, adjusted		—		1,284			2,037			3,699			—		168			7,188
Depreciation		—		141			258			304			—		14			717
Retirement of assets		—		(5	)		(43	)		(3	)		—		—			(51	)
Disposals		—		—			—			(1	)		—		(1	)		(2	)
Change in foreign exchange rates		—		(4	)		18			(37	)		—		2			(21	)
Transfers		—		—			(212	)		(29	)		—		(14	)		(255	)
As at Dec. 31, 2020, adjusted		—		1,416			2,058			3,933			—		169			7,576
Depreciation		—		154			184			264			—		12			614
Retirement of assets		—		(9	)		(55	)		(48	)		—		—			(112	)
Disposals		—		—			(1	)		(72	)		—		—			(73	)
Change in foreign exchange rates		—		—			(8	)		2			—		(1	)		(7	)
Transfers		—		—			—			71			—		—			71
As at Dec. 31, 2021		—		1,561			2,178			4,150			—		180			8,069
Carrying amount
As at Dec. 31, 2019, adjusted		91		2,290			2,036			1,241			228		321			6,207
As at Dec. 31, 2020, adjusted		96		2,176			1,877			968			495		210			5,822
As at Dec. 31, 2021		96		2,582			1,909			363			184		186			5,320

(1) The gas generation and energy transition includes the previously disclosed coal generation and mining property and equipment categories.

(2) Includes major spare parts and stand-by equipment available, but not in service and spare parts used for routine, preventive or planned maintenance.

A. Renewable Generation

During 2021, the Company acquired North Carolina Solar (Refer to Note 4 for further details).

During the third quarter of 2021, Kent Hills 2 had a tower collapse resulting in an impairment of $2 million. Following extensive independent engineering assessments and root cause failure analysis, the Company announced on Jan. 11, 2022, that all 50 turbine foundations at the Kent Hills 1 and Kent Hills 2 sites require a full foundation replacement. As the turbines will not be returning to service until the foundations are replaced, the foundations were written off, resulting in an increase in depreciation of $12 million.

SA-79

Notes to Consolidated Financial Statements

Transfers from assets under construction in 2021 are related to the Windrise wind facility of $255 million, Kent Hills wind rehabilitation project of $7 million and the balance is related to other wind and hydro facilities. Transfers between the classifications of PP&E in 2020 relate to the WindCharger project and planned major maintenance.

B. Gas Generation

During 2021, the Company completed the full conversion of Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 from thermal coal to natural gas. Transfers from assets under construction of $200 million relates to the planned coal to gas conversions and the balance is related to the Australian and US gas facilities.

During 2019, the sale of Genesee 3 resulted in a gain of $77 million, which was recognized in gains on sale of assets and other on the statement of earnings during the fourth quarter.

Transfers out of PP&E in 2020 mainly relate to removing the Southern Cross assets from PP&E to a finance lease receivable and moving the Pioneer Pipeline and mine equipment to assets held for sale. Transfers between the classifications of PP&E in 2020 relate to the Sundance Unit 6 conversion to gas.

C. Energy Transition Generation

Keephills Unit 1, Sundance Unit 5 and Sundance Unit 3 were retired from service effective Dec. 31, 2021, Nov. 1, 2021, and July 31, 2020, respectively. Sundance Unit 4 will be retired effective April 1, 2022. During 2021, the Company sold equipment related to coal generation that resulted in a gain of sale of $23 million. Centralia Unit 1 was retired from service effective Dec. 31, 2020, as originally planned.

Transfers from assets under construction in 2021 are mainly related to Keephills Unit 1 of $20 million, Sundance Unit 5 of $78 million and the mining property and equipment related to SunHills and Centralia of $100 million. The Company transferred certain generation assets from the Energy Transition segment to assets held for sale as a result of its assessment under IFRS 5 — Non-current Assets Held for Sale and Discontinued Operations. As part of this review there were no impairment charges recognized against the carrying value of $25 million. Transfers between the classifications of PP&E in 2020 relate to the Centralia land purchase.

During the third quarter of 2020, the Board approved the accelerated shutdown of the Highvale mine by the end of 2021 and accordingly the useful life of the related assets was adjusted to align with the Company’s conversion to gas plans. This resulted in an increase of $15 million in depreciation expense that was recognized in the Consolidated Statements of Earnings (Loss) during the second half of 2020.

D. Assets Under Construction

Initial construction activities on the Garden Plain wind project started in the third quarter of 2021. In addition, the Company commenced construction in the fourth quarter of 2021 on the Northern Goldfields Solar Project. The Northern Goldfields Solar Project comprises the 27 MW Mount Keith Solar Farm, 11 MW Leinster Solar Farm, 10MW/5MWh Leinster battery energy storage system and interconnecting transmission infrastructure, all of which will be integrated into our existing 169 MW Southern Cross Energy North remote network in Western Australia. Upon completion of construction, these will be transferred to finance lease receivables.

Additions in 2021 are related to the Windrise wind project of $96 million (2020 — $156 million), White Rock Wind Projects of $32 million (2020 — nil), Garden Plain wind project of $38 million (2020 — nil), the Kaybob cogeneration project of $14 million (2020 — $31 million), coal to gas conversions of $91 million (2020 — $93 million) and planned major maintenance expenditures. In 2020, the additions included the WindCharger battery storage project of $6 million and Centralia mine land of $17 million.

SA-80

Notes to Consolidated Financial Statements

Transfers out to assets held for sale include $25 million related to salvage values for Sundance Unit 5 repowering project.

In 2021, the Company capitalized $14 million (2020 — $8 million) of interest to PP&E in at a weighted average rate of 6.0 per cent (2020 — 6.0 per cent).

19. Right-of-Use Assets

The Company leases various properties and types of equipment. Lease contracts are typically made for fixed periods. Leases are negotiated on an individual basis and contain a wide range of terms and conditions. The lease agreements do not impose covenants, but leased assets may not be used as security for borrowing purposes.

A reconciliation of the changes in the carrying amount of the right-of-use assets is as follows:

	Land			Buildings			Vehicles			Equipment			Pipeline			Total
As at Dec. 31, 2019		58			16			2			25			45			146
Additions		3			13			—			—			—			16
Depreciation		(3	)		(5	)		(1	)		(9	)		(3	)		(21	)
As at Dec. 31, 2020		58			24			1			16			42			141
Additions		—			1			—			—			—			1
Acquisitions (Note 4)		13			—			—			—			—			13
Depreciation		(3	)		(5	)		—			(2	)		(1	)		(11	)
Disposal of assets (Note 4)		—			—			—			—			(41	)		(41	)
Transfers		—			—			—			(8	)		—			(8	)
As at Dec. 31, 2021		68			20			1			6			—			95

On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO. As part of the transaction, the natural gas transportation agreement with the Pioneer Pipeline Limited Partnership was terminated, which resulted in the derecognition of the right-of-use asset of $41 million and lease liability of $43 million related to the pipeline, resulting in a gain of $2 million.

For the year ended Dec. 31, 2021, TransAlta paid $15 million (2020 — $33 million) related to recognized lease liabilities, consisting of $7 million in interest (2020 — $8 million) and $8 million (2020 — $25 million) in principal repayments.

Short-term leases (term of less than 12 months) and leases with total lease payments below the Company’s capitalization threshold do not require recognition as lease liabilities and right-of-use assets.

Some of the Company’s land leases that met the definition of a lease were not recognized as they require variable payments based on production or revenue. Additionally, certain land leases require payments to be made on the basis of the greater of the minimum fixed payments and variable payments based on production or revenue. For these leases, lease liabilities have been recognized on the basis of the minimum fixed payments. For the year ended Dec. 31, 2021, the Company expensed $6 million (2020 — $7 million) in variable land lease payments for these leases. For further information regarding leases refer to Note 5, 11, 24 and 36.

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Notes to Consolidated Financial Statements

20. Intangible Assets

A reconciliation of the changes in the carrying amount of intangible assets is as follows:

	Power sale contracts			Software and other			Intangibles under development			Coal rights			Total
Cost
As at Dec. 31, 2019		250			378			11			149			788
Additions		—			—			14			—			14
Acquisition (Note 4)		37			—			—			—			37
Disposals		—			(1	)		—			—			(1	)
Change in foreign exchange rates		(2	)		—			—			—			(2	)
Transfers		(16	)		35			(22	)		—			(3	)
As at Dec. 31, 2020		269			412			3			149			833
Additions		—			—			9			—			9
Impairment (Note 7)		—			—			—			(17	)		(17	)
Change in foreign exchange rates		—			(2	)		—			—			(2	)
Transfers		—			12			(8	)		—			4
As at Dec. 31, 2021		269			422			4			132			827
Accumulated amortization
As at Dec. 31, 2019		107			246			—			117			470
Amortization		15			28			—			8			51
Disposals		—			(1	)		—			—			(1	)
Transfers		1			(1	)		—			—			—
As at Dec. 31, 2020		123			272			—			125			520
Amortization		17			27			—			7			51
As at Dec. 31, 2021		140			299			—			132			571
Carrying amount
As at Dec. 31, 2019		143			132			11			32			318
As at Dec. 31, 2020		146			140			3			24			313
As at Dec. 31, 2021		129			123			4			—			256

21. 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	2021		2020
Hydro		258		258
Wind and Solar		175		175
Energy Marketing		30		30
Total goodwill		463		463

For the purposes of the 2021 goodwill impairment review, the Company determined the recoverable amounts of the Wind and Solar segment by calculating the fair value less costs of disposal using discounted cash flow

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Notes to Consolidated Financial Statements

projections based on the Company’s long-range forecasts for the period extending to the last planned asset retirement in 2052. The resulting fair value measurement is categorized within Level III of the fair value hierarchy. In 2021, the Company relied on the recoverable amounts determined in 2019 for the Hydro and Energy Marketing segments in performing the 2021 goodwill impairment review. No impairment of goodwill arose for any segment.

The key assumptions impacting the determination of fair value for the Wind and Solar and Hydro segments are the following:

• Discount rates used for the goodwill impairment calculation in 2021 for the Wind and Solar segment ranged from 5.0 per cent to 6.4 per cent (2020 — 4.8 per cent to 6.3 per cent).

• 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 2021 models ranged between $17 to $136 per MWh during the forecast period (2020 — $6 to $160 per MWh).

22. Other Assets

The components of other assets are as follows:

As at Dec. 31	2021		2020
South Hedland prepaid transmission access and distribution costs		65		70
Project development costs		29		25
Long-term prepaids and other assets		48		59
Loan receivable		55		52
Total other assets		197		206
Included in the Consolidated Statements of Financial Position as:
Total current other assets (Note 14)		55		—
Total long-term other assets		142		206
Total other assets		197		206

South Hedland prepaid transmission access and distribution costs are costs that are amortized on a straight-line basis over the South Hedland PPA contract life.

Project development costs primarily include the project costs for US wind and Australian development projects. Some project costs were written off in 2021 due to the uncertainty on timing of when the projects will proceed (see Note 7).

Long-term prepaids and other assets includes: the funded portion of rail transportation commitments discussed in Note 36(C), the funded portion of the TransAlta Energy Transition Bill commitments discussed in Note 36(G) and other contractually required prepayments and deposits.

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Notes to Consolidated Financial Statements

The loan receivable relates to the advancement by the Company’s subsidiary, Kent Hills Wind LP, of $55 million (2020 — $52 million) which is net of the Kent Hills Wind bond financing proceeds to its 17 per cent partner. The unsecured loan bears interest at 4.55 per cent, with interest payable quarterly, commencing on Dec. 31, 2017 and matures in October 2022; as such, it was moved to current assets (Note 14).

23. Decommissioning and Other Provisions

The change in decommissioning and other provision balances is as follows:

	Decommissioning and restoration			Other provisions			Total
Balance, Dec. 31, 2019		501			45			546
Liabilities incurred		1			34			35
Liabilities settled		(18	)		(19	)		(37	)
Accretion		30			—			30
Acquisition of liabilities		1			—			1
Revisions in estimated cash flows		61			11			72
Revisions in discount rates(1)		36			—			36
Reversals		—			(6	)		(6	)
Change in foreign exchange rates		(4	)		—			(4	)
Balance, Dec. 31, 2020		608			65			673
Liabilities incurred		8			22			30
Liabilities settled (Note 36)		(18	)		(62	)		(80	)
Accretion		32			—			32
Acquisition of liabilities		2			—			2
Revisions in estimated cash flows		167			12			179
Revisions in discount rates		(6	)		—			(6	)
Reversals		—			(3	)		(3	)
Balance, Dec. 31, 2021		793			34			827

(1) Discount rates at Dec. 31, 2020, are generally lower than those at Dec. 31, 2019, due to decreases in the underlying risk-free US and Canadian benchmark yields and changes in credit spreads due to volatility within the market as a result of COVID-19. On average, these rates decreased by approximately 0.3 to 0.9 per cent.

	Decommissioning and restoration		Other		Total
Balance, Dec. 31, 2020		608		65		673
Current portion		21		38		59
Non-current portion		587		27		614
Balance, Dec. 31, 2021		793		34		827
Current portion		35		13		48
Non-current portion		758		21		779

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

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Notes to Consolidated Financial Statements

original condition. TransAlta estimates that the undiscounted amount of cash flow required to settle these obligations is approximately $1.6 billion, which will be incurred between 2022 and 2072. The majority of the costs will be incurred between 2025 and 2050.

In 2021, the Company adjusted the wind assets decommissioning and restoration provision as estimates were updated after the review of a recent engineering study on the decommissioning costs of the wind sites. The Company’s current best estimate of the decommissioning and restoration provision increased by $120 million. The change in estimate is unrelated to the tower failure identified in the fourth quarter of 2021. The Company also increased the decommissioning and restoration provision by approximately $47 million for the Sundance and Keephills Units included in the Gas and Energy Transition segments to reflect the change in the timing of the expected reclamation work resulting from asset retirements and change in useful lives. These changes resulted in an increase in the related assets in PP&E.

At Dec. 31, 2021, the Company had provided a surety bond in the amount of US$147 million (2020 — US$147 million) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2021, the Company had provided letters of credit in the amount of $188 million (2020 — $131 million) in support of future decommissioning obligations at the Highvale mine.

In the fourth quarter of 2020, the Company adjusted the Sarnia decommissioning and restoration provision to reflect an updated engineering study. The Company’s current best estimate of the decommissioning and restoration provision decreased by $15 million. This resulted in a decrease in the related assets in PP&E.

In the third quarter of 2020, the Company adjusted the Highvale mine decommissioning and restoration provision to reflect the mine closure advancement, an updated mine plan and current mining activity including increased volume of material movement. The Company’s current best estimate of the decommissioning and restoration provision increased by $75 million. This resulted in an increase in the related assets in PP&E.

B. Other Provisions

Other provisions also include provisions arising from ongoing business activities and include amounts related to commercial disputes between the Company 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 Company’s ability to settle the provisions in the most favourable manner.

During the third quarter of 2021, an onerous contract provision for future royalty payments of $14 million was recognized as a result of a decision to accelerate the plans to shut down the Highvale mine, with the effect that any remaining future royalty payments related to the extraction of coal has no future economic benefit. Payments required under the royalty contract will continue through 2023. At Dec. 31, 2021, the remaining balance of the provision was $14 million.

During the fourth quarter of 2020, an onerous contract provision of $29 million was recognized as a result of a decision to accelerate plans to eliminate coal as a fuel source at the Sheerness facility by the end of 2021. The last coal shipment was received during the first quarter of 2021, while payments required under the contract will continue until 2025. At Dec. 31, 2021, the remaining balance of the provision was $14 million.

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Notes to Consolidated Financial Statements

24. Credit Facilities, Long-Term Debt and Lease Liabilities

A. Amounts Outstanding

The amounts outstanding are as follows:

As at Dec. 31	2021														2020
	Segment		Maturity		Currency		Carrying value			Face value		Interest(1)			Carrying value			Face value		Interest
Credit facilities
Committed syndicated bank facility(2)		Corporate		2025		CAD		—			—		—	%		114			114		2.7	%
Debentures
7.3% Medium term notes		Corporate		2029		CAD		110			110		7.3	%		109			110		7.3	%
6.9% Medium term notes		Corporate		2030		CAD		141			141		6.9	%		140			141		6.9	%
Senior notes(3)
6.5% Senior notes		Corporate		2040		USD		378			383		6.5	%		380			383		6.5	%
4.5% Senior notes		Corporate		2022		USD		510			511		4.5	%		506			511		4.5	%
Non-recourse
Melancthon Wolfe Wind LP bond		Wind & Solar		2028		CAD		235			237		3.8	%		268			270		3.8	%
New Richmond Wind LP bond		Wind & Solar		2032		CAD		120			121		4.0	%		127			128		4.0	%
Kent Hills Wind LP bond(4)		Wind & Solar		2033		CAD		221			221		4.5	%		230			233		4.5	%
Windrise Wind LP bond		Wind & Solar		2041		CAD		171			173		3.4	%		—			—		—	%
Pingston bond		Hydro		2023		CAD		45			45		3.0	%		45			45		3.0	%
TAPC Holdings LP bond (Poplar Creek)		Gas		2030		CAD		102			104		4.4	%		111			113		4.5	%
TEC Hedland PTY Ltd bond(5)		Gas		2042		AUD		732			742		4.1	%		772			782		4.1	%
TransAlta OCP LP bond		Gas		2030		CAD		263			265		4.5	%		284			287		4.5	%
Tax equity financing
Big Level & Antrim(6)		Wind & Solar		2029		USD		106			112		6.6	%		112			119		6.6	%
Lakeswind(7)		Wind & Solar		2029		USD		18			18		10.5	%		22			22		10.5	%
North Carolina Solar(8)		Wind & Solar		2028		USD		11			11		7.3	%		—			—		—
Other		Corporate		2023		CAD		4			4		5.9	%		7			6		5.9	%
Total long-term debt								3,167			3,198					3,227			3,264
Lease liabilities								100								134
							3,267								3,361
Less: current portion of long-term debt								(837	)							(97	)
Less: current portion of lease liabilities								(7	)							(8	)
Total current long-term debt and lease liabilities								(844	)							(105	)
Total credit facilities, long-term debt and lease liabilities								2,423								3,256

(1) Interest is 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, 2021 — US$700 million (Dec. 31, 2020 — US$700 million).

(4) Kent Hills Wind LP bond is classified as a current liability. Refer to section B — Restrictions Related to Non-Recourse Debt and Other Debt, for more information.

(5) AU face value at Dec. 31, 2021 — AU$800 million related to the TEC offering (2020 — AU$800 million).

(6) US face value at Dec. 31, 2021 — US$88 million (2020 — US$94 million).

(7) US face value at Dec. 31, 2021 — US$14 million (2020 — US$16 million).

(8) US face value at Dec. 31, 2021 — US$9 million (2020 — nil).

SA-86

Notes to Consolidated Financial Statements

The Company’s credit facilities are summarized in the table below:

As at Dec. 31, 2021	Facility size		Utilized				Available capacity		Maturity date
			Outstanding letters of credit(1)		Actual drawings
TransAlta Corporation
Committed syndicated bank facility(2)		1,250		618		—		632		Q2 2025
Canadian committed bilateral credit facilities		240		186		—		54		Q2 2023
TransAlta Renewables
Committed credit facility(2)		700		98		—		602		Q2 2025
Total		2,190		902		—		1,288

(1) TransAlta has 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, pension plan obligations, construction projects and purchase obligations. At Dec. 31, 2021, TransAlta provided cash collateral of $55 million.

(2) Includes letters of credit issued under the demand facilities for TransAlta and TransAlta Renewables.

The Company has $2 billion (2020 — $2 billion) of committed syndicated bank facilities and $0.2 billion of committed bilateral credit facilities, of which $1.3 billion was available as at Dec. 31, 2021 (2020 — $1.5 billion) and including the undrawn letters of credit are the primary source for short-term liquidity after the cash flow generated from the Company’s business. This includes a $1.3 billion credit facility that was converted into a facility with a Sustainability Linked Loan (“SLL”) and that was extended to June 30, 2025. The facility’s financing terms will align the cost of borrowing to TransAlta’s greenhouse gas emission reductions and gender diversity targets, which are part of the Company’s overall plan for environment, social and governance. The SLL will have a cumulative pricing adjustment to the borrowing costs on the facilities and a corresponding adjustment to the standby fee (the “Sustainability Adjustment”). Depending on performance against interim targets that have been set for each year of the credit facility term, the Sustainability Adjustment is structured as a two-way mechanism and could move either up, down or remain unchanged for each sustainability performance target based on performance. In addition, the Company’s committed bilateral credit facilities were also extended to June 30, 2023. Interest rates on the credit facilities vary depending on the option selected — Canadian prime, bankers’ acceptances, USD LIBOR or US base rate — in accordance with a pricing grid that is standard for such facilities.

The Company is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. In addition to the $1.3 billion available under the credit facilities, the Company also has $947 million of available cash and cash equivalents and $17 million ($17 million principal portion) in cash restricted for repayment of the OCP bonds (refer to section E below).

TransAlta has letters of credit of $157 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities.

Debentures

On Nov. 25, 2020, the Company redeemed $400 million of its then due 5.0 per cent medium term notes.

SA-87

Notes to Consolidated Financial Statements

Senior notes

A total of US$370 million (2020 — US$370 million) of the senior notes has been designated as a hedge of the Company’s net investment in US foreign operations.

Non-recourse debt

On Dec. 6, 2021, TransAlta completed a secured green bond offering by way of private placement for approximately $173 million (the “Offering”). The Offering is secured by a first ranking charge over all assets of the issuer, Windrise Wind LP, and the bonds amortize and bear interest from their date of issue at a rate of 3.41 per cent per annum and mature on Sept. 30, 2041. Payments on the bonds will be interest-only to and including Dec. 31, 2022, with quarterly blended payments of principal and interest commencing on March 31, 2023. TransAlta intends to use proceeds of the Offering to finance or refinance eligible green projects, including renewable energy facilities and to fund a construction reserve account.

On Oct. 22, 2020, TEC closed an AU$800 million senior secured note offering, by way of a private placement, which is secured by, among other things, a first ranking charge over all assets of TEC. The notes bear interest at 4.07 per cent per annum, payable quarterly and matures on June 30, 2042, with principal payments starting on March 31, 2022. Funds were used to repay indebtedness on the credit facility and to fund future growth opportunities within TransAlta Renewables. The TEC Offering has a rating of BBB by Kroll Bond Rating Agency.

Tax Equity

Tax equity financings are typically represented by the initial equity investments made by the project investors at each project (net of financing costs incurred), except for the Lakeswind and North Carolina Solar acquired tax equity which were initially recognized at their fair values. Tax equity financing balances are reduced by the value of tax benefits (production tax credits, tax depreciation and investment tax credits) allocated to the investor and by cash distributions paid to the investor for their share of net earnings and cash flow generated at each project. Tax equity financing balances are increased by interest recognized at the implicit interest rate. The maturity dates of each financing are subject to change and primarily dependent upon when the project investor achieves the agreed upon targeted rate of return. The Company anticipates the maturity dates of the tax equity financings will be: Big Level and Antrim — on March 31, 2030, 10 years from commercial operation of the projects; Lakeswind — March 31, 2029, and North Carolina Solar on Dec. 31, 2028.

Other

Other debt 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.

TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2021, the Company was in compliance with all debt covenants except the Kent Hills non-recourse bond as discussed below.

B. Restrictions Related to Non-Recourse Debt and Other Debt

The Melancthon Wolfe Wind LP, Pingston, TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd notes, Windrise Wind LP and TransAlta OCP LP non-recourse bonds with a carrying value

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Notes to Consolidated Financial Statements

of $1.9 billion as at Dec. 31, 2021 (Dec. 31, 2020 — $1.8 billion) are subject to customary financing conditions and covenants that may restrict the Company’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 of 2021, except the Kent Hills non-recourse bond as discussed below. 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 2022. At Dec. 31, 2021, $67 million (Dec. 31, 2020 — $73 million) of cash was subject to these financial restrictions. At Dec. 31, 2021, Kent Hills cash in the amount of $6 million is not able to be distributed or accessed by other corporate entities, as discussed below.

Proceeds received from the TEC Notes in the amount of $3 million (AU$4 million) are not able to be accessed by other corporate entities as the funds must be solely used by the project entities for the purpose of paying major maintenance costs.

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.

As a result of the determination that all 50 foundations require replacement, as well as certain resulting amendments to applicable insurance policies, the Company has provided notice to BNY Trust Company of Canada, as trustee (the “Trustee”), for the approximately $221 million outstanding non-recourse project bonds (the “KH Bonds”) secured by, among other things, the Kent Hills 1, 2 and 3 wind sites, that events of default may have occurred under the trust indenture governing the terms of the KH Bonds. Upon the occurrence of any event of default, holders of more than 50 per cent of the outstanding principal amount of the KH Bonds have the right to direct the Trustee to declare the principal and interest on the KH Bonds and all other amounts due, together with any make-whole amount (Dec. 31, 2021 — $39 million), to be immediately due and payable and to direct the Trustee to exercise rights against certain collateral. The Company is in discussions with the Trustee and holders of the Kent Hills bonds to negotiate required waivers and amendments while the Company works to remedy the matters described in the notice. Although the Company expects that it will reach agreement with the Trustee and holders of the KH Bonds with respect to terms of an acceptable waiver and amendment, there can be no assurance that the Company will receive such waivers and amendments. Accordingly, the Company has classified the entire carrying value of the KH Bonds as a current liability as at Dec. 31, 2021.

C. Security

Non-recourse debts totalling $1.5 billion as at Dec. 31, 2021 (Dec. 31, 2020 — $1.4 billion) are each secured by a first ranking charge over all of the respective assets of the Company’s subsidiaries that issued the bonds, which include PP&E with total carrying amounts of $1.5 billion at Dec. 31, 2021 (Dec. 31, 2020 — $1 billion) and intangible assets with total carrying amounts of $78 million (Dec. 31, 2020 — $88 million). At Dec. 31, 2021, a non-recourse bond of approximately $103 million (Dec. 31, 2020 — $111 million) was secured by a first ranking charge over the equity interests of the issuer that issued the non-recourse bond.

The TransAlta OCP bonds have a carrying value of $263 million (Dec. 31, 2020 — $285 million) and 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 Company receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million, net to the Company), commencing on Jan. 1, 2017, and terminating at the end of 2030.

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Notes to Consolidated Financial Statements

D. Principal Repayments

	2022(1)			2023		2024		2025		2026		2027 and thereafter		Total
Principal repayments(2)		836			155		113		127		127		1,840		3,198
Lease liabilities(3)		(6	)		4		3		3		3		93		100

(1) Includes the Kent Hills Wind LP non-recourse bonds. The successful receipt of waivers and amendments would extend principal repayments beyond 2022.

(2) Excludes impact of hedge accounting and derivatives.

(3) Lease liabilities include a lease incentive of $13 million, expected to be received in 2022.

E. Restricted Cash

At Dec. 31, 2021, the Company had nil (Dec. 31, 2020 — $9 million) in restricted cash related to the Big Level tax equity financing that is held in a construction reserve account. The proceeds were released from the construction reserve account in 2021.

The Company had $17 million (Dec. 31, 2020 — $17 million) 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 2022.

The Company also had $53 million (Dec. 31, 2020 — $45 million) of restricted cash related to the TEC Notes; reserves are required to be held under TEC commercial arrangements and for debt service. Cash reserves may be replaced by letters of credit in the future.

F. 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 two uncommitted $150 million and $100 million demand letters of credit facilities. Letters of credit issued by TransAlta Renewables are drawn on its uncommitted $150 million demand letter of credit facility.

Letters of credit are issued to counterparties under various contractual arrangements with the Company and certain subsidiaries of the Company. If the Company 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 Company 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, 2021, was $902 million (2020 — $621 million) with no (2020 — nil) amounts exercised by third parties under these arrangements.

25. Exchangeable Securities

On March 22, 2019, the Company entered into an Investment Agreement whereby Brookfield Renewable Partners or its affiliates (collectively “Brookfield”) agreed to invest $750 million in TransAlta through the purchase of exchangeable securities, which are exchangeable into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Alberta Hydro Assets’ future-adjusted EBITDA (“Option to Exchange”).

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Notes to Consolidated Financial Statements

Upon entering into the Investment Agreement and as required under the terms of the agreement, the Company paid Brookfield a $7.5 million structuring fee. A commitment fee of $15 million was also paid upon completion of the initial funding. These transaction costs, representing three per cent of the total investment of $750 million, have been recognized as part of the carrying value of the unsecured subordinated debentures.

On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for seven per cent unsecured subordinated debentures due May 1, 2039. On Oct. 30, 2020, Brookfield invested the second tranche of $400 million in exchange for redeemable, retractable first preferred shares.

A. $750 million Exchangeable Securities

As at	Dec. 31, 2021							Dec. 31, 2020
	Carrying value		Face value		Interest			Carrying value		Face value		Interest
Exchangeable debentures — due May 1, 2039		335		350		7	%		330		350		7	%
Exchangeable preferred shares(1)		400		400		7	%		400		400		7	%
Total long-term debt		735		750					730		750

(1) Exchangeable preferred share dividends are reported as interest expense.

On Dec. 13, 2021, the Company declared a dividend of $7 million in aggregate for Exchangeable Preferred Shares at the fixed rate of 1.764 per cent, per share payable on Feb. 28, 2022. The Exchangeable Preferred Shares are considered debt for accounting purposes, and as such, dividends are reported as interest expense (Note 11).

B. Option to Exchange

As at	Dec. 31, 2021				Dec. 31, 2020
Description	Base fair value		Sensitivity		Base fair value		Sensitivity
				+nil				+nil
Option to exchange — embedded derivative		—		-32		—		-33

The Investment Agreement allows Brookfield the option, after Dec. 31, 2024, to exchange all of the outstanding exchangeable securities into an equity ownership interest of up to a maximum 49 per cent in an entity that has been formed to hold TransAlta’s Alberta Hydro Assets. The fair value of the option to exchange is considered a Level III fair value measurement as there is no available market-observable data. It is therefore valued using a mark-to-forecast model with inputs that are based on historical data and changes in underlying discount rates only when it represents a long-term change in the value of the option to exchange.

Sensitivity ranges for the base fair value are determined using reasonably possible alternative assumptions for key unobservable inputs, which is mainly the change in the implied discount rate of the future cash flow. The sensitivity analysis has been prepared using the Company’s assessment that a change in the implied discount rate of the future cash flow of 1 per cent is a reasonably possible change.

The maximum equity interest Brookfield can own with respect to the Hydro Assets is 49 per cent. If Brookfield’s ownership interest is less than 49 per cent at conversion, Brookfield has a one-time option payable in cash to increase its ownership to up to 49 per cent, exercisable up until Dec. 31, 2028, and provided Brookfield holds at least 8.5 per cent of TransAlta’s common shares. Under this top-up option, Brookfield will be able to acquire an

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Notes to Consolidated Financial Statements

additional 10 per cent interest in the entity holding the Hydro Assets, provided the 20-day volume-weighted average price (“VWAP”) of TransAlta’s common shares is not less than $14 per share prior to the exercise of the option, and up to the full 49 per cent if the 20-day VWAP of TransAlta’s common shares at that time is not less than $17 per share. To the extent the value of the investment would exceed a 49 per cent equity interest, Brookfield will be entitled to receive the balance of the redemption price in cash.

Under the terms of the Investment Agreement, Brookfield committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to not less than nine per cent by May 1, 2021. As of Dec. 31, 2021, Brookfield, through its affiliates, held, owned or had control over an aggregate of 35,425,696 common shares, representing approximately 13.1 per cent of the issued and outstanding common shares, calculated on an undiluted basis. In connection with the Investment Agreement, Brookfield is entitled to nominate two directors for election to the Board.

26. 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	2021		2020
Defined benefit obligation (Note 31)		228	282
Long-term incentive accruals (Note 30)		4	4
Other		21	12
Total		253	298

The liability for pension and post-employment benefits and associated costs included in compensation expenses are impacted by estimates related to changes in key actuarial assumptions, including discount rates. As a result of increases in discount rates in 2021, largely driven by increases in market benchmark rates, the defined benefit obligation has decreased by $54 million to $228 million as at Dec. 31, 2021, from $282 million as at Dec. 31, 2020.

27. 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	2021					2020
	Common shares (millions)		Amount			Common shares (millions)			Amount
Issued and outstanding, beginning of year		269.8		2,896			277.0			2,978
Purchased and cancelled under the NCIB		—		—			(7.3	)		(79	)
Effects of share-based payment plans		—		(3	)		—			(3	)
Stock options exercised		1.2		8			0.1			—
Issued and outstanding, end of year		271.0		2,901			269.8			2,896

B. Normal course issuer bid (“NCIB”) Program

Shares purchased by the Company 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 deficit.

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Notes to Consolidated Financial Statements

The following are the effects of the Company’s purchase and cancellation of the common shares during the year:

For the year ended Dec. 31	2021		2020
Total shares purchased(1)		—		7,352,600
Average purchase price per share		—	$	8.33
Total cost		—		61
Weighted average book value of shares cancelled		—		79
Amount recorded in deficit		—		18

(1) As at Dec. 31, 2021, includes nil (2020 — 456,200) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date.

2021

On May 25, 2021, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to implement an NCIB for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. 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 May 31, 2021 and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election. No common shares have been repurchased under the current and previous NCIB in 2021.

2020

On May 26, 2020, the Company announced that the TSX accepted the notice filed by the Company to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, the Company was permitted to purchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its issued and common shares as at May 25, 2020.

C. Shareholder Rights Plan

The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 26, 2019, to reflect current market practice and to reflect changes to the take-over bid regime. As required, the Shareholder Rights Plan must be put before the Company’s shareholders every three years for approval. It was last approved on April 26, 2019, and will need to be approved at the annual meeting of shareholders in 2022. The primary objective of the Shareholder Rights Plan is to encourage a potential acquirer to meet certain minimum standards designed to promote the fair and equal treatment of all common shareholders. When an acquiring shareholder acquires 20 per cent or more of the Company’s common shares, except in limited circumstances including by way of a “permitted bid” or a “competing permitted bid” (as defined in the Shareholder Rights Plan), 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 purchase additional common shares at a significant discount to market, thus exposing the person acquiring 20 per cent or more of the shares to substantial dilution of their holdings.

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Notes to Consolidated Financial Statements

D. Earnings per Share

Year ended Dec. 31	2021			2020			2019
Net earnings (loss) attributable to common shareholders		(576	)		(336	)		52
Basic and diluted weighted average number of common shares outstanding (millions)		271			275			283
Net earnings (loss) per share attributable to common shareholders, basic and diluted		(2.13	)		(1.22	)		0.18

E. Dividends

On Dec. 13, 2021, the Company declared a quarterly dividend of $0.05 per common share, payable on April 1, 2022.

There have been no other transactions involving common shares between the reporting date and the date of completion of these consolidated financial statements.

28. Preferred Shares

A. Issued and Outstanding

All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares.

As at Dec. 31	2021				2020
	Number of				Number of
	shares				shares
Series	(millions)		Amount		(millions)		Amount
Series A		9.6		235		10.2		248
Series B		2.4		58		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 A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion

On March 18, 2021, the Company announced that 1,417,338 of its 10.2 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares (“Series A Shares”) and 871,871 of its 1.8 million Series B Cumulative Redeemable Floating Rate Preferred Shares (“Series B Shares”) were tendered for conversion, on a one-for-one basis, into Series B Shares and Series A Shares, respectively after having taken into account all election notices. As a result of the conversion, the Company had 9.6 million Series A Shares and 2.4 million Series B Shares issued and outstanding at March 31, 2021.

II. 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

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Notes to Consolidated Financial Statements

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, the shares are also:

• Redeemable at the option of the Company, 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 Company 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, 2021, are as follows:

Series	Rate during term	Annual dividend rate per share ($)		Next conversion date	Rate spread over benchmark (percent)		Convertible to Series
A	Fixed		0.71924	March 31, 2026		2.03		B
B	Floating		0.53866	March 31, 2026		2.03		A
C	Fixed		1.00676	June 30, 2022		3.10		D
D	Floating		—	—		3.10		C
E	Fixed		1.29852	Sept. 30, 2022		3.65		F
F	Floating		—	—		3.65		E
G	Fixed		1.24700	Sept. 30, 2024		3.80		H
H	Floating		—	—		3.80		G

B. Dividends

The following table summarizes the value of the preferred share dividends declared in 2021 and 2020:

	Total dividends declared
Series	2021(1)		2020
A		7		9
B(2)		1		1
C		11		14
E		12		15
G		8		10
Total for the year		39		49

(1) No dividends were declared in the first quarter of 2021 as the quarterly dividend related to the period covering the first quarter of 2021 was declared in December 2020.

(2) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.03 per cent.

On Dec. 13, 2021, the Company declared a quarterly dividend of $0.1798 per share on the Series A preferred shares, $0.1331 per share on the Series B preferred shares, $0.2517 per share on the Series C preferred shares, $0.3246 per share on the Series E preferred shares, and $0.3118 per share on the Series G preferred shares, all payable on March 31, 2022.

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Notes to Consolidated Financial Statements

29. Accumulated Other Comprehensive Earnings

The components of, and changes in, accumulated other comprehensive earnings are as follows:

	2021			2020
Currency translation adjustment
Opening balance, Jan. 1		(21	)		(21	)
Losses on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		(14	)		(11	)
Gains on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax		—			11
Balance, Dec. 31		(35	)		(21	)
Cash flow hedges
Opening balance, Jan. 1		436			527
Losses on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax(1)		(208	)		(91	)
Balance, Dec. 31		228			436
Employee future benefits
Opening balance, Jan. 1		(66	)		(55	)
Net actuarial gains (losses) on defined benefit plans, net of tax(2)		37			(11	)
Balance, Dec. 31		(29	)		(66	)
Other
Opening balance, Jan. 1		(47	)		3
Intercompany investments at FVOCI		29			(50	)
Balance, Dec. 31		(18	)		(47	)
Accumulated other comprehensive earnings		146			302

(1) Net of income tax of $57 million for the year ended Dec. 31, 2021 (2020 — $23 million).

(2) Net of income tax of $11 million for the year ended Dec. 31, 2021 (2020 — $3 million).

30. Share-Based Payment Plans

The Company 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 Company’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 Company’s share price over the three-year period and accrue dividends as additional units at the same rate as dividends paid on the Company’s common shares.

The pre-tax compensation expense related to PSUs and RSUs in 2021 was $14 million (2020 — $15 million, 2019 — $19 million), which is included in operations, maintenance and administration expense in the Consolidated Statements of Eamings (Loss).

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Notes to Consolidated Financial Statements

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 Company and fluctuates based on the changes in the value of the Company’s common shares in the marketplace. DSUs accrue dividends as additional DSUs at the same rate as dividends are paid on the Company’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 Company.

The Company 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 $3 million in 2021 (2020 — $1 million, 2019 — $2 million).

C. Stock Option Plans

On May 4, 2021, the Company approved amendments to the Stock Option Plan to reduce the total aggregate number of common shares held in reserve for issuance under this program. The amendments reduce the aggregate total number of shares reserved for issuance to 14.5 million common shares as at March 31, 2021 (Dec. 31, 2020 — 16.5 million common shares). The Company is authorized to grant options to purchase up to an aggregate of 14.5 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 2021, the Company granted executive officers of the Company a total of 0. 7 million stock options with a weighted average exercise price of $9.86 that vest after a three-year period and expire seven years after issuance (2020 — 0. 7 million stock options at $9.17; 2019 — 1.4 million stock options at $5.65). The expense recognized relating to these grants during 2021 was approximately $2 million (2020 — approximately $2 million, 2019 — approximately $1 million).

The total options outstanding and exercisable under these stock option plans at Dec. 31, 2021, are outlined below:

	Options outstanding
Range of exercise prices(1) ($ per share)	Number of options (millions)		Weighted average remaining contractual life (years)		Weighted average exercise price ($ per share)
5.00 — 9.00		3.2		4.2		7.54

(1) Options currently exercisable as at Dec. 31, 2021.

31. Employee Future Benefits

A. Description

The Company sponsors registered pension plans in Canada and the US covering substantially all employees of the Company 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.

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Notes to Consolidated Financial Statements

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, 2021. The latest actuarial valuation for accounting purposes of the Highvale and Canadian pension plans was at Dec. 31, 2019. 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, 2021.

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 Company. The Company 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 Company posted a letter of credit in March 2021 for the amount of $97 million to secure the obligations under the supplemental plan.

The Company 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, 2019, and Jan. 1, 2021, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2021.

The Company 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.

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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, 2021	Registered			Supplemental		Other		Total
Current service cost		3			2		1		6
Administration expenses		1			—		—		1
Interest cost on defined benefit obligation		12			2		—		14
Interest on plan assets		(8	)		—		—		(8	)
Curtailment and amendment gain		(7	)		—		—		(7	)
Defined benefit expense		1			4		1		6
Defined contribution expense		8			—		—		8
Net expense		9			4		1		14

Year ended Dec. 31, 2020	Registered			Supplemental			Other		Total
Current service cost		5			2			1		8
Administration expenses		1			—			—		1
Interest cost on defined benefit obligation		16			3			1		20
Interest on plan assets		(11	)		(1	)		—		(12	)
Curtailment and amendment gain		(2	)		—			—		(2	)
Defined benefit expense		9			4			2		15
Defined contribution expense		9			—			—		9
Net expense		18			4			2		24

Year ended Dec. 31, 2019	Registered			Supplemental			Other		Total
Current service cost		7			2			1		10
Administration expenses		2			—			—		2
Interest cost on defined benefit obligation		19			3			1		23
Interest on plan assets		(12	)		(1	)		—		(13	)
Curtailment and amendment gain		(3	)		—			—		(3	)
Defined benefit expense		13			4			2		19
Defined contribution expense		9			—			—		9
Net expense		22			4			2		28

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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:

Year ended Dec. 31, 2021	Registered			Supplemental			Other			Total
Fair value of plan assets		339			14			—			353
Present value of defined benefit obligation		(469	)		(101	)		(23	)		(593	)
Funded status — plan deficit		(130	)		(87	)		(23	)		(240	)
Amount recognized in the consolidated financial statements:
Accrued current liabilities		(4	)		(6	)		(2	)		(12	)
Other long-term liabilities		(126	)		(81	)		(21	)		(228	)
Total amount recognized		(130	)		(87	)		(23	)		(240	)
Year ended Dec.31, 2020	Registered			Supplemental			Other			Total
Fair value of plan assets		367			14			—			381
Present value of defined benefit obligation		(542	)		(109	)		(24	)		(675	)
Funded status — plan deficit		(175	)		(95	)		(24	)		(294	)
Amount recognized in the consolidated financial statements:
Accrued current liabilities		(5	)		(5	)		(2	)		(12	)
Other long-term liabilities		(170	)		(90	)		(22	)		(282	)
Total amount recognized		(175	)		(95	)		(24	)		(294	)

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, 2019		373			13			—			386
Interest on plan assets		11			1			—			12
Net return on plan assets		25			(1	)		—			24
Contributions		6			6			1			13
Benefits paid		(45	)		(5	)		(1	)		(51	)
Administration expenses		(1	)		—			—			(1	)
Effect of translation on US plans		(2	)		—			—			(2	)
As at Dec. 31, 2020		367			14			—			381
Interest on plan assets		8			—			—			8
Net return on plan assets		14			(1	)		—			13
Contributions		5			6			1			12
Benefits paid		(54	)		(5	)		(1	)		(60	)
Administration expenses		(1	)		—			—			(1	)
As at Dec. 31, 2021		339			14			—			353

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Notes to Consolidated Financial Statements

The fair value of the Company’s defined benefit plan assets by major category is as follows:

Year ended Dec. 31, 2021	Level I		Level II		Level III		Total
Equity securities
Canadian		—		29		4		33
US		—		20		—		20
International		47		79		—		126
Private		—		—		1		1
Bonds
AAA		—		28		—		28
AA		—		54		—		54
A		—		36		—		36
BBB		1		24		—		25
Below BBB		—		10		—		10
Money market and cash and cash equivalents		—		20		—		20
Total		48		300		5		353
Year ended Dec. 31, 2020	Level I		Level II		Level III		Total
Equity securities
Canadian		—		64		—		64
US		—		30		—		30
International		—		103		—		103
Private		—		—		1		1
Bonds
AAA		—		36		—		36
AA		—		67		—		67
A		—		34		—		34
BBB		1		22		—		23
Below BBB		—		4		—		4
Money market and cash and cash equivalents		—		19		—		19
Total		1		379		1		381

Plan assets do not include any common shares of the Company at Dec. 31, 2021 and Dec. 31, 2020. The Company charged the registered plan nil for administrative services provided for the year ended Dec. 31, 2021 (2020 — nil).

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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, 2019		543			99			22			664
Current service cost		5			2			1			8
Interest cost		16			3			1			20
Benefits paid		(45	)		(5	)		(1	)		(51	)
Curtailment		(2	)		—			—			(2	)
Actuarial loss arising from financial assumptions		43			10			2			55
Actuarial gain arising from experience adjustments		(17	)		—			—			(17	)
Effect of translation on US plans		(1	)		—			(1	)		(2	)
Present value of defined benefit obligation as at Dec. 31, 2020		542			109			24			675
Current service cost		3			2			1			6
Interest cost		12			2			—			14
Benefits paid		(54	)		(5	)		(1	)		(60	)
Curtailment		(7	)		—			—			(7	)
Actuarial gain arising from financial assumptions		(26	)		(7	)		(1	)		(34	)
Actuarial gain arising from experience adjustments		(1	)		—			—			(1	)
Present value of defined benefit obligation as at Dec. 31, 2021		469			101			23			593

The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2021, is 13.6 years.

F. Contributions

The expected employer contributions for 2022 for the defined benefit pension and other post-employment benefit plans are as follows:

	Registered		Supplemental		Other		Total
Expected employer contributions		5		6		2		13

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Notes to Consolidated Financial Statements

G. Assumptions

The significant actuarial assumptions used in measuring the Company’s defined benefit obligation for the defined benefit pension and other post-employment benefit plans are as follows:

	As at Dec. 31, 2021						As at Dec. 31, 2020
(per cent)	Registered		Supplemental		Other		Registered		Supplemental		Other
Accrued benefit obligation
Discount rate		2.8		2.8		2.7		2.4		2.3		2.3
Rate of compensation increase		2.9		3.0		—		2.9		3.0		—
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)		—		—		6.8		—		—		6.8
Dental-care cost escalation		—		—		4.0		—		—		4.0
Benefit cost for the year
Discount rate		2.4		2.3		2.3		3.0		3.0		3.0
Rate of compensation increase		2.9		3.0		—		2.9		3.0		—
Assumed health-care cost trend rate
Health-care cost escalation(2)(4)		—		—		7.1		—		—		7.1
Dental-care cost escalation		—		—		4.0		—		—		4.0

(1) 2021 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 2030 for Canada.

(2) 2021 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 2030 for Canada.

(3) 2020 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 2030 for Canada.

(4) 2020 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 2030 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, 2021	Registered		Supplemental		Other		Pension		Other
1% decrease in the discount rate		61		15		2		3		1
1% increase in the salary scale		3		—		—		—		—
1% increase in the health-care cost trend rate		—		—		2		—		—
10% improvement in mortality rates		20		4		—		1		—

32. Joint Arrangements

Joint arrangements at Dec. 31, 2021, included the following:

Joint operations	Segment	Ownership (per cent)	Description
Sheerness	Gas	50	Dual-fuel facility in Alberta, of which TA Cogen has a 50 per cent interest, operated by Heartland Generation Ltd., an affiliate of Energy Capital Partners

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Notes to Consolidated Financial Statements

Joint operations	Segment	Ownership (per cent)	Description
Goldfields Power	Gas	50	Gas-fired facility in Australia operated by TransAlta
Fort Saskatchewan	Gas	60	Cogeneration facility 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 and Solar	50	Wind generation facility in Alberta operated by TransAlta
Soderglen	Wind and Solar	50	Wind generation facility in Alberta operated by TransAlta
Pingston	Hydro	50	Hydro facility in British Columbia operated by TransAlta
Joint venture	Segment	Ownership (per cent)	Description
Skookumchuck	Wind and Solar	49	Wind generation facility in Washington operated by Southern Power

33. Cash Flow Information

A. Change in Non-Cash Operating Working Capital

Year ended Dec. 31	2021			2020			2019
(Use) source:
Accounts receivable		(28	)		(79	)		261
Prepaid expenses		9			2			—
Income taxes receivable		—			(4	)		(6	)
Inventory		42			6			(13	)
Accounts payable, accrued liabilities and provisions		153			160			(130	)
Income taxes payable		(2	)		4			9
Change in non-cash operating working capital		174			89			121

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Notes to Consolidated Financial Statements

B. Changes in Liabilities from Financing Activities

	Balance Dec. 31, 2020		Cash issuances		Repayments and dividends paid			New leases		Dividends declared		Foreign exchange impact			Other			Balance Dec. 31, 2021
Long-term debt and lease liabilities		3,361		173		(214	)		1		—		(39	)		(15	)		3,267
Exchangeable securities		730		—		—			—		—		—			5			735
Dividends payable (common and preferred)		59		—		(87	)		—		90		—			—			62
Total liabilities from financing activities		4,150		173		(301	)		1		90		(39	)		(10	)		4,064

	Balance Dec. 31, 2019		Cash issuances		Repayments and dividends paid			New leases		Dividends declared		Foreign exchange impact		Other			Balance Dec. 31, 2020
Long-term debt and lease liabilities		3,212		753		(620	)		16		—		5		(5	)		3,361
Exchangeable securities		326		400		—			—		—		—		4			730
Dividends payable (common and preferred)		37		—		(86	)		—		107		—		1			59
Total liabilities from financing activities		3,575		1,153		(706	)		16		107		5		—			4,150

34. Capital

TransAlta’s capital is comprised of the following:

As at Dec. 31	2021			2020			Increase/ (decrease)
Long-term debt(1)		3,267			3,361			(94	)
Exchangeable securities		735			730			5
Equity
Common shares		2,901			2,896			5
Preferred shares		942			942			—
Contributed surplus		46			38			8
Deficit		(2,453	)		(1,826	)		(627	)
Accumulated other comprehensive earnings		146			302			(156	)
Non-controlling interests		1,011			1,084			(73	)
Less: available cash and cash equivalents(2)		(947	)		(703	)		(244	)
Less: principal portion of restricted cash on TransAlta OCP bonds(3)		(17	)		(11	)		(6	)
Less: fair value asset of hedging instruments on long-term debt(4)		(2	)		(2	)		—
Total capital		5,629			6,811			(1,182	)

(1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt.

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Notes to Consolidated Financial Statements

(2) The Company 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 Company includes the principal portion of restricted cash on TransAlta OCP bonds because this cash is restricted specifically to repay outstanding debt.

(4) The Company 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.

The Company’s overall capital management strategy and its objectives in managing capital are as follows:

A. Maintain a Strong Financial Position

The Company operates in a long-cycle and capital-intensive commodity business, and it is therefore a priority to maintain a strong financial position that enables the Company to access capital markets at reasonable interest rates.

Maintaining a strong balance sheet also allows its commercial team to contract the Company’s portfolio with a variety of counterparties on terms and prices that are favourable to the Company’s financial results and provides the Company with better access to capital markets through commodity and credit cycles. The Company has an investment grade credit rating from DBRS (stable outlook). During 2021, Moody’s reaffirmed its issuer rating of Ba1 with a stable outlook; DBRS reaffirmed the Company’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 Company’s Unsecured Debt rating and Issuer Rating of BB+ with stable outlook. The Company remains focused on maintaining a strong financial position and cash flow coverage ratios. Credit ratings provide information relating to the Company’s financing costs, liquidity and operations and affect the Company’s ability to obtain short-term and long-term financing and/or the cost of such financing.

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. Liquidity

For the years ended Dec. 31, 2021 and 2020, cash inflows and outflows are summarized below. The Company manages variations in working capital using existing liquidity under credit facilities to ensure sufficient cash and credit is available to fund operations, pay dividends, distribute payments to subsidiaries’ non-controlling interests and invest in PP&E.

Year ended Dec. 31	2021			2020			Increase (decrease)
Cash flow from operating activities		1,001			702			299
Change in non-cash working capital		(174	)		(89	)		(85	)
Cash flow from operations before changes in working capital		827			613			214
Dividends paid on common shares		(48	)		(47	)		(1	)
Dividends paid on preferred shares		(39	)		(39	)		—
Distributions paid to subsidiaries’ non-controlling interests		(156	)		(97	)		(59	)
Property, plant and equipment expenditures		(480	)		(486	)		6
Inflow (outflow)		104			(56	)		160

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Notes to Consolidated Financial Statements

TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2021, $1.3 billion (2020 — $1.5 billion) of the Company’s credit facilities were fully available.

From time to time, 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.

35. Related-Party Transactions

Details of the Company’s principal operating subsidiaries at Dec. 31, 2021, 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	60.1	Generation and sale of electricity

Associate or joint venture	Country	Ownership (per cent)	Principal activity
SP Skookumchuck Investment, LLC	US	49	Generation and sale of electricity
EMG International, LLC	US	30	Wastewater treatment and biogas fuel to generate electricity

Transactions between the Company and its subsidiaries have been eliminated on consolidation and are not disclosed. Associates and joint ventures have been equity accounted for by the Company.

A. Transactions with Key Management Personnel

TransAlta’s key management personnel include the President and Chief Executive Officer (“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	2021		2020		2019
Total compensation		30		27		30
Comprised of:
Short-term employee benefits		14		12		13
Post-employment benefits		1		2		2
Termination benefits		—		—		2
Share-based payments		15		13		13

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Notes to Consolidated Financial Statements

B. TransAlta Renewables Acquisitions

North Carolina Solar

On Nov. 5, 2021, TransAlta completed the sale of a 100 per cent economic interest in the 122 MW portfolio of solar facilities in North Carolina for US$102 million. Pursuant to the transaction, a TransAlta subsidiary owns North Carolina Solar directly and another subsidiary issued tracking preferred shares to TransAlta Renewables reflecting the economic interest in the facilities.

Ada and Skookumchuck

On April 1, 2021, the Company completed the sale of its 100 per cent economic interest in the 29 MW Ada cogeneration facility and its 49 per cent economic interest in the 137 MW Skookumchuck wind facility to TransAlta Renewables for $43 million and $103 million, respectively. Pursuant to the transaction, a TransAlta subsidiary owns Ada and Skookumchuck directly and another subsidiary issued tracking preferred shares to TransAlta Renewables reflecting the economic interest in the facilities.

Big Level and Antrim

During 2021, TransAlta Renewables subscribed for additional tracking preferred shares in Big Level and Antrim for $7 million (US$6 million). In addition, TransAlta Renewables repaid a portion of the total outstanding promissory notes to the Company related to the Big Level and Antrim wind facilities in the amount of $18 million (US$14 million).

Windrise Wind

On Dec. 23, 2020, TransAlta announced that it had entered into definitive agreements for the acquisition by TransAlta Renewables, a subsidiary of the Company, of its 100 per cent direct interest in the 206 MW Windrise wind project located in the Municipal District of Willow Creek, Alberta. On Feb. 26, 2021, TransAlta completed the sale of its 100 per cent direct interest in the 206 MW Windrise wind project to TransAlta Renewables, for $213 million.

WindCharger

On Aug. 1, 2020, the WindCharger battery storage project was sold to TransAlta Renewables for $12 million.

TEC Offering

In relation to the TEC Offering, TransAlta Renewables has received $480 million (AU$515 million) of the proceeds through the redemption of certain intercompany structures. An additional AU$200 million has been loaned to TransAlta Renewables by TransAlta Energy (Australia) Pty Ltd., which is a subsidiary of TransAlta. The loan bears interest at 4.32 per cent and will be repaid by Oct. 23, 2022, or on demand. The remaining proceeds from the TEC Offering were set aside for required reserves and transaction costs. TransAlta Renewables used a portion of the proceeds from the redemption and the intercompany loan to repay existing indebtedness on its credit facility and to acquire the asset and economic interests noted above.

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Notes to Consolidated Financial Statements

36. Commitments and Contingencies

In addition to commitments disclosed elsewhere in the financial statements, the Company has incurred the following additional contractual commitments, either directly or through its interests in joint operations. Approximate future payments under these agreements are as follows:

	2022		2023		2024		2025		2026		2027 and thereafter		Total
Natural gas, transportation and other contracts		47		54		45		44		45		508		743
Transmission		9		9		6		6		2		—		32
Coal supply and mining agreements1		76		98		90		75		—		—		339
Long-term service agreements		89		46		43		32		25		54		289
Operating leases		4		3		3		1		1		31		43
Growth		941		276		—		—		—		—		1,217
TransAlta Energy Transition Bill		6		6		—		—		—		—		12
Total		1,172		492		187		158		73		593		2,675

(1) Relates to coal supply and mining agreements for Centralia Unit 2.

A. Natural Gas, Transportation and Other Contracts

The Company has fixed price or volume natural gas purchase and transportation contracts. Upon closing of the sale of the Pioneer Pipeline, additional 15-year natural gas transportation agreements for 275 terajoules (“TJ”) per day on a firm basis by 2023 arose, bringing the total firm natural gas transportation to 400 TJ per day. Additionally, on June 30, 2021, the Company’s agreement to purchase 139 TJ per day of natural gas from Tidewater Midstream & Infrastructure Ltd. was terminated and the commitment related to commodity dispatching was discharged, resulting in a reduction to the commitments disclosed at Dec. 31, 2020, by approximately $1.3 billion.

B. Transmission

The Company has several agreements to purchase transmission network capacity in Canada and the Pacific Northwest. Provided certain conditions for delivering the service are met, the Company 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 thermal facility. The coal supply agreements allow TransAlta to take delivery of coal at fixed volumes with dates extending to 2025. Pricing is reflective of current market conditions.

Commitments related to mining agreements for the Company’s share of its Sheerness joint operation have been reduced due to the accelerated plans to eliminate coal as a fuel source at the Sheerness facility. Amounts due under the contract and a mining royalty agreement for the Highvale mine have been recognized as onerous contract provisions, with the result that no amounts are included as future commitments. For additional information refer to Note 9.

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Notes to Consolidated Financial Statements

D. Long-Term Service Agreements

TransAlta has various service agreements in place, primarily for inspections, repairs and maintenance that may be required on natural gas facilities, coal facilities, equipment for coal and gas, and turbines at various wind facilities.

E. Operating Leases

Operating leases include lease commitments not recognized under IFRS 16 and lease commitments that have not yet commenced, mainly related to buildings, vehicles and land.

F. Growth

Commitments for growth relate to the following projects: White Rock Wind Projects, Garden Plain wind project, Horizon Hill wind project and the Northern Goldfields Solar Project.

G. TransAlta Energy Transition Bill Commitments

As part of the TransAlta Energy Transition Bill signed into law in the State of Washington and the subsequent Memorandum of Agreement (“MOA”), The Company has committed to fund US$55 million in total over the remaining life of the Centralia 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 portion thereof would no longer be required. As of Dec. 31, 2021, the Company has funded approximately US$46 million of the commitment, which is recognized in other assets in the Consolidated Statements of Financial Position.

H. 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 Company’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 Company responds as required.

I. Transmission Line Loss Rule Proceeding

The Company has been participating in a line loss rule proceeding before the AUC. The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed the AESO to recalculate loss factors for 2006 to 2016. The AUC approved an invoice settlement process and all three planned settlements have been received. The first two invoices were settled by the first quarter of 2021 and the third invoice settled in the second quarter of 2021. The true-up invoices issued by the AESO in the fourth quarter of 2021 were settled by Dec. 31, 2021, with no further invoices expected.

II. Fortescue Metals Group Ltd. (“FMG”) at South Hedland Power Station

On May 2, 2021, the Company entered into a conditional settlement with FMG. The settlement was concluded and the actions were formally dismissed in the Supreme Court of Western Australia on Dec. 7, 2021. The

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Notes to Consolidated Financial Statements

settlement amount has been recorded as revenue in the fourth quarter of 2021, while all other balances previously provided for have been reversed. The settlement has resulted in FMG continuing as a customer of the South Hedland facility.

III. Mangrove Claim

On April 23, 2019, the Mangrove Partners Master Fund Ltd. (“Mangrove”) commenced an action in the Ontario Superior Court of Justice naming the Company, the incumbent members of the Board of the Company on such date, and Brookfield as defendants. Mangrove was seeking to set aside the 2019 Brookfield transaction. The parties reached a confidential settlement and the action was discontinued in the Ontario Superior Court of Justice on April 30, 2021.

IV. Keephills 1 Stator Force Majeure

The Balancing Pool and ENMAX Energy Corporation (“ENMAX”) are seeking to set aside an arbitration award on the basis that they did not receive a fair hearing. The Alberta Court of Queen’s Bench (“ABQB”) dismissed the Balancing Pool and ENMAX’s allegations of unfairness on June 26, 2019. The Balancing Pool and ENMAX, however, sought leave to appeal the ABQB’s decision at the Court of Appeal, which was granted on Feb. 13, 2020. The appeal was heard on July 8, 2021. After the hearing, counsel for ENMAX raised concerns that one of the three justices on the appeal panel was distracted during the hearing. The justice has since recused herself from the hearing and the parties made submissions with respect to whether the remaining two justices can continue to issue the decision or whether a new hearing is required. On Nov. 8, 2021, the Alberta Court of Appeal released its decision and ordered that the appeal be reheard by a new three-person panel of the Court of Appeal, which was heard on Jan. 27, 2022. TransAlta remains of the view that the Court of Appeal will affirm the ABQB decision that the arbitration proceeding was fair.

V. Keephills 1 Superheater Force Majeure

Keephills Unit 1 was taken offline from March 17, 2015, to May 17, 2015, as a result of a large leak in the secondary superheater. TransAlta claimed force majeure under the Alberta PPA. ENMAX, the purchaser under the Alberta PPA at the time, did not dispute the force majeure but the Balancing Pool attempted to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The parties reached a confidential settlement on April 21, 2021, and this matter is now resolved.

VI. Sundance A Decommissioning

TransAlta filed an application with the AUC seeking payment from the Balancing Pool for TransAlta’s decommissioning costs for Sundance A, including its proportionate share of the Highvale mine. The Balancing Pool and Utilities Consumer Advocate are participating as interveners because they take issue with the decommissioning costs claimed by TransAlta. Due to various factors, including the COVID-19 pandemic and significant information requests from the Balancing Pool, the application has been delayed. While a hearing date has not been set, the application will likely be heard in late 2022 or early 2023. TransAlta expects to receive payment from the Balancing Pool for its decommissioning costs; however, the amount that the AUC will award is uncertain.

VII. Hydro Power Purchase Arrangement (“Hydro PPA”) Emission Performance Credits

The Balancing Pool claims to be entitled to emission performance credits (“EPCs”) earned by the Hydro facilities as a result of opting those facilities into the Carbon Competitiveness Incentive Regulation from 2018-2020

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Notes to Consolidated Financial Statements

inclusive. The Balancing Pool claims ownership of the EPCs because it believes the change-in-law provisions under the Hydro PPA require the EPCs to be passed through to the Balancing Pool. TransAlta has not received any benefit from the EPCs or from any purported change in law and believes that the Balancing Pool has no rights to these credits. An arbitration has commenced, and the hearing is scheduled for Feb. 6-10, 2023.

VIII. Direct Assigned Capital Deferral Account (“DACDA”) Application

AltaLink Management Ltd. (“AltaLink”) and TransAlta (as a secondary applicant) filed an application before the AUC to recover its 2016-2018 DACDA costs incurred for the 240 kV line upgrades for the Edmonton Region Project. The AUC disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta disputed this finding and filed a permission to appeal application with the Court of Appeal and a review and variance application with the AUC (the “R&V”). The AUC dismissed the R&V application on April 22, 2021. The permission to appeal was subsequently discontinued on July 5, 2021, which concludes this matter.

IX. Sarnia Outages

The Sarnia cogeneration facility experienced three separate outages between May 19, 2021, and June 9, 2021, that resulted in steam interruptions to its industrial customers. As a result, the customers have submitted claims for liquidated damages. Steam supply disruptions of this nature are atypical and infrequent at the Sarnia cogeneration facility. The Company conducted an investigation to determine the root cause of each of the three events, which concluded all three outages were within TransAlta’s control. As such, liquidated damages in an amount dictated by the applicable agreements are payable by TransAlta to the customers for the three outages.

X. Kaybob 3 Cogeneration Dispute

The Company is engaged in a dispute with ET Canada as a result of ET Canada’s purported termination of agreements between the parties to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing facility. TransAlta commenced an arbitration seeking full compensation for ET Canada’s wrongful termination of the agreements. ET Canada seeks a declaration that the agreements were lawfully terminated. A hearing is scheduled for two weeks starting Jan. 9, 2023.

37. Segment Disclosures

A. Description of Reportable Segments

The Company has six reportable segments as described in Note 1.

The following tables provides each segment’s results in the format that the CODM reviews the Company’s segments to make operating decisions and assess performance. The CODM assesses the performance of the operating segments based on a measure of adjusted EBITDA. This measurement basis represents earnings before income taxes, adjusted for the effects of: depreciation of property, plant and equipment and amortization of intangibles, depreciation of right-of-use assets, finance lease income, unrealized mark-to-market gains or losses and unrealized foreign exchange gains or losses on commodity transactions, depreciation on our mining equipment included in fuel and purchased power, interest income recorded on the prepaid funds, write-down of coal inventory and parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities, going off-coal which resulted in the remaining coal supply payments on the existing coal supply agreement being recognized as an onerous contract, impairment charges, share of (profit) loss of joint venture, and other costs or income adjustments. The tables below show the reconciliation of the total segmented results and adjusted EBITDA to the statement of earnings (loss) reported under IFRS. Prior periods have been adjusted for comparable purposes.

SA-112

Notes to Consolidated Financial Statements

For internal reporting purpose, the earnings information from the Company’s investment in Skookumchuck has been presented in the Wind and Solar segment on a proportionate basis. Information on a proportionate basis reflects the Company’s share of Skookumchuck’s statement of earnings on a line-by-line basis. Proportionate financial information is not, and is not intended to be, presented in accordance with IFRS. Under IFRS, the investment in Skookumchuck has been accounted for as a joint venture using the equity method.

B. Reported Adjusted Segment Earnings (Loss) and Segment Assets

I. Reconciliation of Adjusted EBITDA to Earnings before Income Tax

Year ended Dec. 31, 2021	Hydro		Wind & Solar(1)		Gas(2)			Energy Transition(3)			Energy Marketing			Corporate			Total			Equity investments(1)			Reclass adjustments			IFRS financials
Revenues		383		323		1,109			709			211			4			2,739			(18	)		—			2,721
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		25		(40	)		19			(38	)		—			(34	)		—			34			—
Decrease in finance lease receivable		—		—		41			—			—			—			41			—			(41	)		—
Finance lease income		—		—		25			—			—			—			25			—			(25	)		—
Unrealized foreign exchange gain on commodity		—		—		(3	)		—			—			—			(3	)		—			3			—
Adjusted revenues		383		348		1,132			728			173			4			2,768			(18	)		(29	)		2,721
Fuel and purchased power		16		17		457			560			—			4			1,054			—			—			1,054
Reclassifications and adjustments:
Australian interest income		—		—		(4	)		—			—			—			(4	)		—			4			—
Mine depreciation		—		—		(79	)		(111	)		—			—			(190	)		—			190			—
Coal inventory write-down		—		—		—			(17	)		—			—			(17	)		—			17			—
Adjusted fuel and purchased power		16		17		374			432			—			4			843			—			211			1,054
Carbon compliance(4)		—		—		118			60			—			—			178			—			—			178
Gross margin		367		331		640			236			173			—			1,747			(18	)		(240	)		1,489
OM&A		42		59		175			117			36			84			513			(2	)		—			511
Reclassifications and adjustments:
Parts and materials write-down		—		—		(2	)		(26	)		—			—			(28	)		—			28			—
Curtailment gain		—		—		—			6			—			—			6			—			(6	)		—
Adjusted OM&A		42		59		173			97			36			84			491			(2	)		22			511
Taxes, other than income taxes		3		10		13			6			—			1			33			(1	)		—			32
Net other operating expense (income)		—		—		(40	)		48			—			—			8			—			—			8
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties		—		—		—			(48	)		—			—			(48	)		—			48			—
Adjusted net other operating income		—		—		(40	)		—			—			—			(40	)		—			48			8
Adjusted EBITDA		322		262		494			133			137			(85	)		1,263
Equity income from associate																											9
Finance lease income																											25
Depreciation and amortization																											(529	)
Asset impairment																											(648	)
Net interest expense(6)																											(245	)
Foreign exchange gain																											16
Gain on sale of assets and other																											54
Loss before income taxes																											(380	)

(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

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Notes to Consolidated Financial Statements

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) As of the first quarter of 2021, carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes.

(5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

(6) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings.

Year ended Dec. 31, 2020	Hydro		Wind & Solar(1)		Gas(2)			Energy Transition(3)			Energy Marketing		Corporate			Total			Equity accounted investments(1)			Reclass adjustments			IFRS financials
Revenues		152		332		787			704			122		7			2,104			(3	)		—			2,101
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		2		33			(14	)		21		—			42			—			(42	)		—
Decrease in finance lease receivable		—		—		17			—			—		—			17			—			(17	)		—
Finance lease income		—		—		7			—			—		—			7			—			(7	)		—
Unrealized foreign exchange loss on commodity		—		—		4			—			—		—			4			—			(4	)		—
Adjusted revenues		152		334		848			690			143		7			2,174			(3	)		(70	)		2,101
Fuel and purchased power		8		25		325			435			—		12			805			—			—			805
Reclassifications and adjustments:
Australian interest income		—		—		(4	)		—			—		—			(4	)		—			4			—
Mine depreciation		—		—		(100	)		(46	)		—		—			(146	)		—			146			—
Coal inventory write-down		—		—		—			(37	)		—		—			(37	)		—			37			—
Adjusted fuel and purchased power		8		25		221			352			—		12			618			—			187			805
Carbon compliance(4)		—		—		120			48			—		(5	)		163			—			—			163
Gross margin		144		309		507			290			143		—			1,393			(3	)		(257	)		1,133
OM&A		37		53		166			106			30		80			472			—			—			472
Taxes, other than income taxes		2		8		13			9			—		1			33			—			—			33
Net other operating expense (income)		—		—		(11	)		—			—		—			(11	)		—			—			(11	)
Reclassifications and adjustments:
Impact of Sheerness going off-coal		—		—		(28	)		—			—		—			(28	)		—			28			—
Adjusted net other operating income						(39	)		—			—		—			(39	)		—			28			(11	)
Adjusted EBITDA(5)		105		248		367			175			113		(81	)		927
Equity income from associate																										1
Finance lease income																										7
Depreciation and amortization																										(654	)
Asset impairment																										(84	)
Net interest expense(6)																										(238	)
Foreign exchange loss																										17
Gain on sale of assets and other																										9
Loss before income taxes																										(303	)

(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) As of the first quarter of 2021, carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes.

(5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

(6) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings.

SA-114

Notes to Consolidated Financial Statements

Year ended Dec. 31, 2019	Hydro		Wind & Solar			Gas(1)			Energy Transition(2)			Energy Marketing			Corporate			Total			Reclass adjustments			IFRS financials
Revenues		156		312			851			905			129			(6	)		2,347			—			2,347
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		(17	)		6			(12	)		(10	)		—			(33	)		33			—
Decrease in finance lease receivable		—		—			24			—			—			—			24			(24	)		—
Finance lease income		—		—			6			—			—			—			6			(6	)		—
Adjusted revenues		156		295			887			893			119			(6	)		2,344			3			2,347
Fuel and purchased power		7		16			315			539			—			4			881			—			881
Reclassifications and adjustments:
Australian interest income		—		—			(4	)		—			—			—			(4	)		4			—
Mine depreciation		—		—			(81	)		(40	)		—			—			(121	)		121			—
Adjusted fuel and purchased power		7		16			230			499			—			4			756			125			881
Carbon compliance		—		—			138			77			—			(10	)		205			—			205
Gross margin		149		279			519			317			119			—			1,383			(122	)		1,261
																			��
OM&A		36		50			162			124			30			73			475			—			475
Taxes, other than income taxes		3		8			9			8			—			1			29			—			29
Net other operating expense (income)		—		(10	)		(41	)		—			—			2			(49	)		—			(49	)
Termination of Sundance B and C PPAs		—		—			(14	)		(42	)		—			—			(56	)		—			(56	)
Adjusted EBITDA(3)		110		231			403			227			89			(76	)		984
Finance lease income																									6
Depreciation and amortization																									(590	)
Asset impairment																									(25	)
Gain on termination of Keephills 3 coal rights contract																									88
Net interest expense(4)																									(179	)
Foreign exchange loss																									(15	)
Gain on sale of assets and other																									46
Earnings before income taxes																									193

(1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

(2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

(4) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings.

II. Selected Consolidated Statements of Financial Position Information

As at Dec. 31, 2021	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)		Energy Marketing		Corporate		Total
PP&E		466		2,304		2,036		481		—		33		5,320
Right-of-use assets		5		64		7		1		—		18		95
Intangible assets		3		147		56		9		5		36		256
Goodwill		258		175		—		—		30		—		463

SA-115

Notes to Consolidated Financial Statements

As at Dec. 31, 2020	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)		Energy Marketing		Corporate		Total
PP&E		467		2,005		2,102		1,232		—		16		5,822
Right-of-use assets		6		55		5		53		—		22		141
Intangible assets		4		159		66		36		7		41		313
Goodwill		258		175		—		—		30		—		463

(1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

(2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

III. Selected Consolidated Statements of Cash Flows Information

Additions to non-current assets are as follows:

Year ended Dec. 31, 2021	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)		Energy Marketing		Corporate		Total
Additions to non-current assets:
PP&E		29		166		167		90		—		28		480
Intangible assets		—		—		—		1		—		8		9
Year ended Dec. 31, 2020	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)		Energy Marketing		Corporate		Total
Additions to non-current assets:
PP&E		22		174		199		78		—		13		486
Intangible assets		—		—		—		1		—		13		14
Year ended Dec. 31, 2019	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)		Energy Marketing		Corporate		Total
Additions to non-current assets:
PP&E		23		229		74		90		—		1		417
Intangible assets		—		—		—		2		—		12		14

(1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

(2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

SA-116

Notes to Consolidated Financial Statements

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	2021		2020		2019
Depreciation and amortization expense on the Consolidated Statements of Earnings (Loss)		529		654		590
Depreciation included in fuel, carbon compliance and purchased power (Note 6)		190		144		119
Depreciation and amortization on the Consolidated Statements of Cash Flows		719		798		709

C. Geographic Information

I. Revenues

Year ended Dec. 31	2021		2020		2019
Canada		1,854		1,227		1,460
US		731		716		727
Australia		136		158		160
Total revenue		2,721		2,101		2,347

II. Non-Current Assets    

	Property, plant and equipment				Right-of-use assets				Intangible assets				Other assets
As at Dec. 31	2021		2020		2021		2020		2021		2020		2021		2020
Canada		4,051		4,661		52		107		141		185		15		74
US		860		737		39		30		85		94		61		61
Australia		409		424		4		4		30		34		66		71
Total		5,320		5,822		95		141		256		313		142		206

D. Significant Customer

During the year ended Dec. 31, 2021, sales to the AESO represent 35 per cent of the Company’s total revenue (2020 — sales to the AESO represented 15 per cent of the Company’s total revenue). There were no other companies greater than 10 per cent of the Company’s total revenue.

SA-117

EXHIBIT “B” – ANNUAL MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See attached.

SB-1

Management’s Discussion and Analysis

Table of Contents

Forward-Looking Statements	M2
Description of the Business	M4
Alberta Electricity Portfolio	M7
Accelerated Clean Electricity Growth Plan	M9
Highlights	M13
Significant and Subsequent Events	M17
Segmented Financial Performance and Operating Results	M25
Fourth Quarter Highlights	M34
Segmented Financial Performance and Operating Results for the Fourth Quarter	M36
Selected Quarterly Information	M36
Financial Position	M38
Financial Capital	M41
Other Consolidated Analysis	M48
Cash Flows	M51
Financial Instruments	M52
Additional IFRS Measures and Non-IFRS Measures	M54
Financial Highlights on a Proportional Basis of TransAlta Renewables	M67
Key Non-IFRS Financial Ratios	M68
2022 Financial Outlook	M73
Critical Accounting Policies and Estimates	M76
Accounting Changes	M83
Environment, Social and Governance (“ESG”)	M84
Transforming Our Business Model to Become Carbon Neutral by 2050	M85
2022+ Sustainable Targets	M87
Our 2021 Sustainability Performance	M89
Decarbonizing Our Energy Mix	M93
Engaging with Our Stakeholders to Create Positive Relationships	M112
Building a Diverse and Inclusive Workforce	M122
Progressive Environmental Stewardship	M128
Reliable, Low-Cost and Sustainable Energy Production	M138
Technology Adoption and Innovation Focus	M139
Sustainability Governance	M142
Governance and Risk Management	M142
Disclosure Controls and Procedures	M159

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our 2021 audited annual consolidated financial statements (the “consolidated financial statements”) and our 2021 annual information form (“AIF”), each for the fiscal year ended Dec. 31, 2021. The 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, 2021. All dollar amounts in 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. All other dollar amounts in this MD&A are in Canadian dollars, unless otherwise noted. This MD&A is dated February 23, 2022. Additional information respecting TransAlta Corporation (“TransAlta”, “we”, “our”, “us” or the “Company”), including our AIF, 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.

SB-2

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 US securities laws, including the US 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, statements relating to: our Clean Electricity Growth Plan and ability to achieve the target of 2 gigawatts (“GW”) of incremental renewables capacity with an investment of $3 billion by 2025; the Company’s future growth pipeline, including the timing of commercial operations and the costs of the advanced and early-stage projects; expansion of the Company’s development pipeline to 5 GW; the White Rock East and White Rock West Wind Power Projects (“White Rock Wind Projects”), including the total construction costs, ability to secure tax equity financing, the timing of commercial operation and expected average earnings before interest, taxes, depreciation and amortization (“EBITDA”); the proportion of EBITDA to be generated from renewable sources by the end of 2025; the suspension of the Sundance 5 repowering project; expected average annual EBITDA of the North Carolina Solar (as defined below) portfolio; the incident at the Kent Hills 1 and 2 wind facilities and the extent of any remediation, the timing and cost of such remediation, the ability to secure waivers in respect of the Kent Hills bonds for any potential event of default, and the impact such incident could have on the Company’s revenues and contracts; the Northern Goldfields Solar Project, including the total construction capital and expected average annual EBITDA; the Garden Plain wind project, including construction capital and expected average annual EBITDA; expected increases to our cost per tonne of coal at Centralia; the expected impact and quantum of carbon compliance costs; the ability to realize future growth opportunities with BHP (as defined below); regulatory developments and their expected impact on the Company, including the Canadian federal climate plan and the implementation of the major aspects thereof (including increased carbon pricing and increased funding for clean technology); the ability of the Company to realize benefits from Canadian, US and Australian regulatory developments, including receiving funding for clean electricity projects; the potential increase in value of emission reduction credits; the 2022 financial outlook, including adjusted EBITDA, free cash flow (“FCF”) and annualized dividend in 2022; increased gross margin contribution from Energy Marketing; hedged production and price for the full year 2022; hedged gas volume and gas price for 2022; sustaining and productivity capital in 2022, including routine capital, planned major maintenance and mine capital; significant planned major outages for 2022 and lost production due to planned major maintenance for 2022; expected power prices in Alberta, Ontario and the Pacific Northwest; the cyclicality of the business, including as it relates to maintenance costs, production and loads; expectations regarding refinancing the debt maturing in 2022; the liquidated damages potentially payable in respect of the Sarnia cogeneration facility outages in the second quarter of 2021; and the Company continuing to maintain a strong financial position and significant liquidity.

The forward-looking statements contained in this MD&A are based on many assumptions including, but not limited to, the following: the impacts arising from COVID-19 not becoming significantly more onerous on the Company; no significant changes to applicable laws and regulations beyond those that have already been announced; no significant changes to the fuel and purchased power costs; no material adverse impacts to the long-term investment and credit markets; Alberta spot prices of $80/MWh to $90/MWh in 2022; Mid-Columbia

SB-3

Management’s Discussion and Analysis

spot prices of US$45/MWh to US$55/MWh in 2022; sustaining capital of $150 million to $170 million; the Company’s proportionate ownership of TransAlta Renewables Inc. (“TransAlta Renewables”) not changing materially; no decline in the dividends to be received from TransAlta Renewables; and the growth of TransAlta Renewables. Forward-looking statements are subject to a number of significant risks and uncertainties 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 risks relating to: the impact of COVID-19, including more restrictive directives of government and public health authorities; increased force majeure claims; reduced labour availability and ability to continue to staff our operations and facilities; disruptions to our supply chains, including our ability to secure necessary equipment; our ability to obtain regulatory approvals on the expected timelines or at all in respect of our growth projects; restricted access to capital and increased borrowing costs; changes in short-term and/or long-term electricity supply and demand; fluctuations in market prices, including lower merchant pricing in Alberta, Ontario and Mid-Columbia; reductions in production; increased costs; a higher rate of losses on our accounts receivables due to credit defaults; impairments and/or write-downs of assets; adverse impacts on our information technology systems and our internal control systems, including increased cybersecurity threats; commodity risk management and energy trading risks, including the effectiveness of the Company’s risk management tools associated with hedging and trading procedures to protect against significant losses; 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; changes to the legislative, regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; operational risks involving our facilities, including unplanned outages; disruptions in the transmission and distribution of electricity; the effects of weather, including man-made or natural disasters and other climate-change related risks; unexpected increases in cost structure; reductions to our generating units’ relative efficiency or capacity factors; disruptions in the source of fuels, including natural gas and coal, as well as the extent of water, solar or wind resources required to operate our facilities; general economic risks, including deterioration of equity markets, increasing interest rates or rising inflation; failure to meet financial expectations; general domestic and international economic and political developments, including armed hostilities, the threat of terrorism, including cyberattacks, diplomatic developments or other similar events that could adversely affect our business; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner or timely manner or at all, including if the remediation at the Kent Hills 1 and 2 wind facilities is more costly or takes longer than expected; industry risk and competition; fluctuations in the value of foreign currencies; structural subordination of securities; counterparty credit risk; changes to our relationship with, or ownership of, TransAlta Renewables; changes in the payment or receipt of future dividends, including from 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; inadequacy or unavailability of insurance coverage; our provision for income taxes; legal, regulatory and contractual disputes and proceedings involving the Company; 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 AIF for the year ended Dec. 31, 2021.

Readers are urged to consider these factors carefully in evaluating the forward-looking statements, which reflect the Company’s expectations only as of the date hereof, and are cautioned not to place undue reliance on them. 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. The purpose of the financial outlooks contained herein is to give the reader information about management’s current expectations and plans and readers are cautioned that such information may not be appropriate for other purposes. 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.

SB-4

Management’s Discussion and Analysis

Description of the Business

Portfolio of Assets

TransAlta is a Canadian corporation and one of Canada’s largest publicly traded power generators with over 110 years of operating experience. We own, operate and manage a geographically diversified portfolio of assets utilizing a broad range of fuels that includes water, wind, solar, natural gas and thermal coal.

The following table provides our consolidated ownership of our facilities across the regions in which we operate as at Dec. 31, 2021:

As at Dec. 31, 2021		Hydro		Wind and Solar(4)		Gas(4)(5)		Energy Transition(6)		Total
Alberta	Gross installed capacity (MW)(1)		834		636		1,960		801		4,231
	Number of facilities		17		13		7		2		39
	Weighted average contract life(2)		—		7		1		—		2
Canada, Excl. Alberta	Gross installed capacity (MW)(1)		91		751		645		—		1,487
	Number of facilities		9		9		3		—		21
	Weighted average contract life(3)		7		10		6		—		8
US	Gross installed capacity (MW)(1)		—		519		29		671		1,219
	Number of facilities		—		7		1		2		10
	Weighted average contract life(3)		—		12		4		4		8
Australia	Gross installed capacity (MW)(1)		—		—		450		—		450
	Number of facilities		—		—		6		—		6
	Weighted average contract life(3)		—		—		17		—		17
Total	Gross installed capacity (MW)(1)		925		1,906		3,084		1,472		7,387
	Number of facilities		26		29		17		4		76
	Weighted average contract life(3)		1		9		5		2		5

(1) Gross installed capacity for consolidated reporting represents 100 per cent output of a facility. Capacity figures for Wind and Solar includes 100 per cent of the Kent Hills wind facilities; Gas includes 100 per cent of the Ottawa and Windsor facilities, 100 per cent of the Poplar Creek facility, 50 per cent of the Sheerness facility and 60 per cent of the Fort Saskatchewan facility.

(2) The weighted average contract life for the assets in Alberta are nil as it is operating primarily on a merchant basis in the Alberta market. Refer to the Alberta Electricity Portfolio section for more information.

(3) For power generated under long-term power purchase agreements (“PPA”), power hedge contracts and short- and long-term industrial contracts, the PPAs have a weighted average remaining contract life (based on gross long-term average gross installed capacity).

(4) The weighted average remaining contract life is related to the contract period for the McBride Lake (38 MW), the Windrise facility (206 MW), Poplar Creek facility (115 MW) and the Fort Saskatchewan facility (71 MW), with remaining wind and gas facilities operated on a merchant basis.in the Alberta market.

(5) Gas segment includes the segments previously known as Australian Gas and North American Gas and the coal generation assets converted to gas from the segment previously known as Alberta Thermal.

(6) Energy Transition segment includes the segment previously known as Centralia and the coal generation assets not converted to gas (including Sundance 4) and mining assets from the segment previously known as Alberta Thermal.

Our Clean Energy Investment Plan, announced in 2019, included converting our existing Alberta coal assets to natural gas and advancing our leadership position in renewable electricity. To date, we have retired 4,064 MW of

SB-5

Management’s Discussion and Analysis

coal-fired generation capacity since 2018 while converting 1,659 MW to natural gas, significantly reducing our carbon footprint. During 2021, we increased our renewable fleet by 334 MW through acquisitions and construction of renewable wind and solar facilities and on Sept 28, 2021, we announced a Clean Electricity Growth Plan that includes strategic growth targets. Please refer to the Accelerated Clean Electricity Growth Plan section of this MD&A for further information.

Approximately 57 per cent of our gross installed capacity is located in Alberta. Our portfolio of merchant assets in Alberta is a combination of hydro facilities, wind facilities, a battery storage facility and converted natural-gas-fired thermal facilities. This balance of fuel types provides us with portfolio generation diversification. It also provides us with capacity that can be monetized as ancillary services or dispatched into the energy market during times of supply tightness. We also enter into financial contracts to reduce our exposure to variable power prices on our merchant generation. Please refer to the Alberta Electricity Portfolio section of this MD&A for further information.

Clean Energy Transition

The Company has completed the conversion to gas at its Alberta facilities that were formerly fuelled by coal; these facilities are now running solely on gas. The Company retired the Highvale coal mine effective Dec. 31, 2021, and is no longer mining coal. Our Centralia coal-fired facility in Washington State is committed to be retired under the TransAlta Energy Transition Bill by 2025. Centralia Unit 1 retired on Dec. 31, 2020, and the remaining unit, Centralia Unit 2, is scheduled to retire on Dec. 31, 2025.

The following table shows the Company’s completed conversions to gas:

Project	MW		Cumulative Conversion Project Spend(1)		Project Completion Date
Keephills Unit 3		463	$	31		Q4 2021
Keephills Unit 2		395	$	34		Q2 2021
Sundance Unit 6		401	$	39		Q1 2021
Sheerness Unit 1(2)		200	$	7		Q1 2021
Sheerness Unit 2(2)		200	$	14		Q1 2020

(1) Conversion project spend only includes costs associated with the conversion to gas-burning technology. Any additional planned major maintenance has been included as part of sustaining capital spend.

(2) These facilities are jointly owned by TransAlta Cogeneration L.P. (“TA Cogen”) and Heartland Generation Ltd. This represents the portion of the 400 MW facility consolidated by the Company.

During the 2021 Investor Day, the Company announced its decision to retire Keephills Unit 1 and Sundance Unit 4 effective Dec. 31, 2021, and April 1, 2022, respectively. The retirement decisions were largely driven by TransAlta’s assessment of future market conditions, the age and condition of the units and the Company’s strategic focus on customer-centred renewable energy solutions. As a result of the decision to retire these units, the Company recorded impairment charges of $94 million and $56 million, respectively, on these units based on the estimated salvage value.

Following an in-depth evaluation and assessment of the Sundance Unit 5 repowering project, the Company suspended the project. The decision was made due to escalating costs, changing supply and demand dynamics and forecasted power prices in the Alberta market, as well as risks associated with carbon pricing and the evolving regulatory environment. With the suspension of the project, the Company will redeploy the capital previously allocated to the Sundance Unit 5 repowering project to renewable growth projects. The Company

SB-6

Management’s Discussion and Analysis

recorded an impairment charge of $191 million in 2021 in relation to the project. The total remaining estimated recoverable amount and salvage value for the Sundance Unit 5 repowering project was $33 million. Of this amount, $25 million was related to assets held for sale. Included in the impairment charge was $141 million for assets under construction and $50 million for the balance of the plant steam equipment. An additional $20 million was expensed for amounts due under contracts as a result of the suspension of the project.

With the suspension of the Sundance Unit 5, we have also impaired a previously recognized deferred asset, as it is no longer likely that we will incur sufficient capital or operating expenditures to utilize the remaining credit. The Company impaired the remaining balance of the credit of $10 million (US$8 million) in 2021.

The Highvale mine is no longer considered to be providing significant economic benefit to the Alberta Merchant cash-generating unit (“CGU”) and it has been removed from the CGU, which resulted in an impairment recognized in 2021 of $195 million. An onerous contract provision of $14 million relating to future Highvale mine royalty payments (2022 and 2023), has also been recognized as an expense in 2021.

With the successful completion of the Keephills Unit 3 conversion on Dec. 29, 2021, and the planned closure of the Highvale coal mine effective Dec. 31, 2021, TransAlta’s thermal facilities in Alberta have been fully transitioned to 100 per cent natural gas operation. We have reduced our CO₂ emissions by 61 per cent from 2015 levels.

Reporting Segment Changes

With the completion of the Clean Energy Transition plan and the announcement of our strategic focus on customer-centred renewable generation, the Company has realigned its current operating segments to better reflect its current strategic focus and to align with the Company’s Clean Electricity Growth Plan. The segment reporting changes reflect a corresponding change in how the Chief Executive Officer assesses the performance of the Company.

The primary changes are the elimination of the Alberta Thermal and the Centralia segments and the reorganization of the North American Gas and Australia Gas segments into a new “Gas” segment. The Alberta Thermal facilities that have been converted to gas are included in the Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets and those facilities not converted to gas and the remaining Centralia unit, are included in a new “Energy Transition” segment. No changes have been made to the Hydro, Wind and Solar, Energy Marketing or the Corporate and Other segments. Please refer to the Segmented Financial Performance and Operating Results section of this MD&A for further information.

Performance by Segment with Supplemental Geographical Information

The following table provides the performance of our facilities across the regions we operate in as at Dec. 31, 2021, and Dec. 31, 2020:

Year ended Dec. 31, 2021	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)		Energy Marketing		Corporate and Other			Total
Alberta		308		63		269		59		—		(85	)		614
Canada, excl. Alberta		14		120		75		—		137		—			346
US		—		79		10		74		—		—			163
Australia		—		—		140		—		—		—			140
Total adjusted EBITDA(3)		322		262		494		133		137		(85	)		1,263
Loss before income taxes															(380	)

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Management’s Discussion and Analysis

Year ended Dec. 31, 2020	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)		Energy Marketing		Corporate and Other			Total
Alberta		88		18		151		36		—		(81	)		212
Canada, excl. Alberta		17		153		88		—		113		—			371
US		—		77		4		139		—		—			220
Australia		—		—		124		—		—		—			124
Total adjusted EBITDA(3)		105		248		367		175		113		(81	)		927
Loss before income taxes															(303	)

(1) Gas segment includes the segments previously known as Australian Gas and North American Gas and the coal generation assets converted to gas from the segment previously known as Alberta Thermal.

(2) Energy Transition segment includes the segment previously known as Centralia and the coal generation assets not converted to gas and mining assets from the segment previously known as Alberta Thermal.

(3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Presenting this from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Please refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Alberta Electricity Portfolio

Generating capacity in Alberta is 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 in the real-time energy-only market. Our merchant Alberta fleet operates under this framework and we internally manage our offers to sell power.

On Dec. 31, 2020, the legislated Alberta Power Purchase Arrangements (“Alberta PPA”) for our Alberta hydro assets (“Alberta Hydro Assets”), Sheerness 1 and 2 Units, and the Keephills 1 and 2 Units expired. Effective Jan. 1, 2021, these facilities began operating on a fully merchant basis in the Alberta market and form a core part of our Alberta portfolio optimization activities.

The Alberta Electricity Portfolio generated gross margin of $864 million, an increase of $405 million compared to the same period in 2020. This performance was driven by strengthened power prices in the province, optimization of production during periods of favourable pricing, partially offset by higher natural gas and carbon pricing and higher transmission costs. Optimization of facilities is driven by the diversity in fuel types, which enables portfolio management and allows for maximization of operating margins. A portion of the baseload generation in the portfolio is hedged to provide cash flow certainty. The portfolio consists of hydro, wind, energy storage and natural gas units operating, primarily, on a merchant basis in the Alberta market. Prior to 2022, the Alberta Electricity Portfolio also included coal units, which are now either retired, have been converted to natural gas or will only operate on gas. Sundance Unit 4 will continue to operate within the portfolio, fuelled only by gas, until its retirement date on April 1, 2022.

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Management’s Discussion and Analysis

Alberta’s annual demand expanded approximately 3.0 per cent from 2020 to 2021 as the economy recovered from the impacts of the COVID-19 pandemic and stronger market conditions for energy commodities supported power demand in the province. The average pool price increased from $47/MWh in 2020 to $102/MWh in 2021. Pool prices were higher in each quarter compared to 2020, generally as a result of competition among generators, higher demand in the province, tighter supply conditions due to higher planned outages, and higher natural gas and carbon prices. In addition, in 2021, Alberta experienced very strong weather-driven demand in February, June, July and December.

	2021										2020										2019
Year ended Dec. 31	Hydro		Wind & Solar		Gas		Energy Transition		Total		Hydro		Wind & Solar		Gas		Energy Transition		Total		Hydro		Wind & Solar		Gas		Energy Transition		Total
Total Production (GWh)(1)		1,586		1,319		7,281		2,591		12,777		1,779		1,320		7,732		2,865		13,696		1,715		1,058		8,691		4,698		16,162
Revenues		358		97		680		257		1,392		126		57		482		207		872		132		59		519		334		1,044
Fuel and purchased power		13		9		258		92		372		6		15		151		73		245		4		6		151		84		245
Carbon compliance		—		—		96		60		156		—		—		120		48		168		—		—		138		77		215
Gross margin		345		88		326		105		864		120		42		211		86		459		128		53		230		173		584

(1) Units in the Gas and Energy Transition segment in the current and prior years may have operated on coal.

The following table provides information for the Company’s Alberta Electricity Portfolio:

Year ended Dec. 31	2021		2020		2019
Spot power price average per MWh	$	102	$	47	$	55
Natural gas price (AECO) per GJ	$	3.39	$	2.11	$	1.68
Carbon cost per tonne	$	40	$	30	$	20
Realized power price per MWh(1)	$	109	$	64	$	65
Hydro energy realized power price per MWh	$	122	$	51	$	61
Hydro ancillary realized price per MWh	$	55	$	23	$	30
Wind energy realized power price per MWh	$	63	$	33	$	38
Gas and Energy Transition realized power price per MWh	$	102	$	71	$	64
Hedged volume (MW)(2)		6,992		5,395		5,187
Hedge position (percentage)(3)		75		100		87
Hedged power price average per MWh(2)	$	72	$	54	$	55
Fuel and purchased power per MWh(4)	$	38	$	23	$	18
Carbon compliance cost per MWh(4)	$	16	$	16	$	16

(1) Realized power price for the Alberta Electricity Portfolio is the average price realized as a result of the Company’s commercial contracted sales and portfolio optimization activities divided by total GWh produced.

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Management’s Discussion and Analysis

(2) In 2020 and 2019, much of the portfolio in Alberta was still under PPAs and the PPA volumes are not included in the total hedged volumes listed above.

(3) Represents the percentage of production sold forward at the end of the reporting period for the Gas assets only. The hedge program is focused primarily on generation from the merchant Gas and Energy Transition assets.

(4) Fuel and purchased power per MWh and carbon compliance cost per MWh are calculated over production from carbon-emitting generation segments in Gas and Energy Transition.

For the year ended Dec. 31, 2021, the realized power price per MWh of production increased by $45 per MWh, compared with the same period in 2020, primarily due to the optimization of production during periods of favourable pricing. The realized prices include gains and losses from hedging positions that are entered into in order to mitigate the impact of unfavourable market pricing.

For the year ended Dec. 31, 2021, the fuel and purchased power cost per MWh of production increased by $15 per MWh compared to the same period in 2020. Cost per MWh increased due to higher natural gas pricing, higher coal mine depreciation and coal inventory write-downs at the Highvale mine and higher transmission costs.

For the year ended Dec. 31, 2021, carbon compliance costs per MWh of production were consistent with the same period in 2020. Carbon compliance costs have increased in 2021 primarily due to an increase in carbon price from $30 per tonne to $40 per tonne; however, this was substantially offset by changes in fuel ratios as we increased our natural gas combustion compared to coal. The shift in fuel ratio effectively lowered our greenhouse gas (“GHG”) compliance costs as natural gas combustion produces fewer GHG emissions than coal combustion.

Accelerated Clean Electricity Growth Plan

On Sept. 28, 2021, TransAlta announced its strategic growth targets and Accelerated Clean Electricity Growth Plan. Our goal is to be a leading customer-centred electricity company, committed to a sustainable future, focused on increasing shareholder value by growing our portfolio of high quality generation facilities with stable and predictable cash flows. Our strategy includes meeting our customers’ needs for clean, low-cost, reliable electricity and providing operational excellence and continuous improvement in everything we do.

The Company’s enhanced focus on renewable generation and storage solutions for customers is driven largely by global decarbonization policies and the increase in demand and growth projections in the renewable sector, namely for companies to achieve their environment, social and governance (“ESG”) ambitions. For additional information on regulatory developments, see the ESG section of this MD&A.

We are primarily evaluating greenfield opportunities in Alberta, Western Australia and the US along with acquisitions in markets in which we have existing operations. We maintain highly qualified and experienced development teams to identify and develop these opportunities.

Our Accelerated Clean Electricity Growth Plan has established the following strategic priorities and targets to guide our path from 2021 to 2025. These include:

• Deliver 2 GW of incremental renewable capacity with a targeted capital investment of $3 billion by the end of 2025. These new assets, once fully operational are targeted to deliver incremental average annual EBITDA¹ of $250 million;

¹  Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

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Management’s Discussion and Analysis

• Accelerate growth into customer-centred renewables and storage through the deployment of our 3 GW development pipeline;

• Expand the Company’s development pipeline to 5 GW by 2025 to enable a two-fold increase in its renewables fleet between 2025 and 2030;

• Realize targeted diversification and value creation by focusing on expanding our platform in each of our core geographies (Canada, United States and Australia);

• Lead in ESG policy development to enable the successful evolution of the markets in which we operate and compete; and

• Define the next generation of power solutions and technologies and potential for parallel investments in new complementary sectors by the end of 2025.

We expect the Company’s EBITDA generated from renewable sources, including hydro, wind, and solar technologies, to increase from 35 per cent to 70 per cent by the end of 2025.

The Clean Electricity Growth Plan will largely be funded from current cash balances, cash generated from operations, and asset-level financing.

Growth

In 2021, the Company announced 600 MW of new build projects and asset acquisitions and has 240 MW in advanced-stage development. In addition, the current growth pipeline has a potential capacity ranging from 2,085 MW to 2,685 MW from projects in the early stages of development.

Announced Acquisition

North Carolina Solar

On Nov. 5, 2021, the Company closed the previously announced acquisition of a 122 MW portfolio of operating solar sites located in North Carolina (collectively, “North Carolina Solar”). The North Carolina Solar facility consists of 20 solar photovoltaic sites across North Carolina. The sites were commissioned between November 2019 and May 2021 and are all operational. The facility is secured by long-term PPAs with Duke Energy, which have an average remaining term of 12 years. Under the PPAs, Duke Energy receives the renewable electricity, capacity and environmental attributes from each site. The North Carolina Solar facility is expected to generate an average annual EBITDA¹ of approximately US$9 million and average annual cash available for distribution of approximately US$7 million.

¹  Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

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Management’s Discussion and Analysis

Projects under Construction

The following projects have been approved by the Board of Directors (“the Board”), have executed PPAs and are currently under construction. The projects under construction will be financed through existing liquidity in the near term. We will continue to explore project financing or tax equity as a long-term financing solution on an asset-by-asset basis.

Total project

Target completion date(1)

Average annual EBITDA(2)

Project

Type

Region

MW

Estimated spend

Spent to date

PPA Term

Status

Projects Under Construction or Approved for Construction

Canada

Garden Plain(3)

Wind

AB

130

$190 — $200

$37

H2 2022

18

$14 - $18

•  Secured all required permits and approvals •  Construction activities commenced in Q4 2021 •  On track to be completed on schedule

United States

White Rock Wind

Wind

OK

300

US$460 — US$470

US$30

H2 2023

US$42 - US$46

•  Long-term PPA executed •  All major equipment supply and EPC agreements executed •  Detailed design and final permitting on track

Australia

Northern Goldfields Solar

Hybrid Solar

WA

48

AU$69 — AU$73

AU$15

H2 2022

16

AU$9 - AU$10

•  Final Notice to Proceed issued on Sept. 28, 2021 •  On track to be completed on schedule

(1) H2 is defined as the second half of the year

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Management’s Discussion and Analysis

(2) This item is not defined and has no standardized meaning under IFRS and is forward-looking. Please refer to the Additional IFRS measures and Non-IFRS Measures section of this MD&A for further discussion.

(3) The Garden Plain PPA with Pembina Pipeline Corporation (“Pembina”) is for 100 MW of the total 130 MW capacity of the facility.

Advanced-Stage Development

These projects have detailed engineering, advanced position in the interconnection queue and are progressing offtake opportunities. The following table shows the pipeline of future growth projects currently under advanced-stage development:

Project	Type	Region	Gross Installed Capacity (MW)		Estimated Spend		Average Annual EBITDA(1)
Advanced-Stage Development
Horizon Hill	Wind	Oklahoma		200		US$290 - US$310		US$25 - US$35
Mount Keith 132kV Expansion	Transmission	Western Australia		n/a		AU$50 - AU$53		AU$6 - AU$7
Mount Keith Capacity Expansion	Gas	Western Australia		40		AU$80 - AU$100		AU$9 - AU$12

(1) This item is not defined and has no standardized meaning under IFRS and is forward-looking. Please refer to the Additional IFRS measures and Non-IFRS Measures section of this MD&A for further discussion.

Early-Stage Development

These projects are in the early stages and may or may not move ahead. Generally, these projects will have:

• Collected meteorological data;

• Begun securing land control;

• Started environmental studies;

• Confirmed appropriate access to transmission; and

• Started preliminary permitting and other regulatory approval processes.

The following table shows the pipeline of future growth projects currently under early-stage development:

Project	Type		Region			Gross Installed Capacity (MW)
Early-Stage Development
Canada
Riplinger Wind		Wind		Alberta			300
Willow Creek 1		Wind		Alberta			70
Willow Creek 2		Wind		Alberta			70
Tempest		Wind		Alberta			100
WaterCharger		Battery Storage		Alberta			180
Sunhills Solar		Solar		Alberta			85
Alberta Solar Opportunities		Solar		Alberta			35
Canadian Wind Opportunities		Wind		Various			200
Brazeau Pumped Hydro		Hydro		Alberta			300 - 900
					Total		1,340 - 1,940

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Management’s Discussion and Analysis

Project	Type	Region		Gross Installed Capacity (MW)
US
Prairie Violet	Wind	Illinois			130
Old Town	Wind	Illinois			185
Big Timber	Wind	Pennsylvania			50
Other US Wind Prospects	Wind	Various			240
			Total		605
Australia
Goldfields Expansions	Gas, Solar and Wind	Western Australia			90
South Hedland Solar	Solar	Western Australia			50
			Total		140
Canada, US and Australia			Total		2,085 - 2,685

Highlights

Consolidated Financial Highlights

Year ended Dec. 31	2021			2020			2019
Adjusted availability (%)		86.6			90.7			90.0
Production (GWh)		22,105			24,980			29,071
Revenues		2,721			2,101			2,347
Fuel and purchased power(1)		1,054			805			881
Carbon compliance(1)		178			163			205
Operations, maintenance and administration		511			472			475
Adjusted EBITDA(2,3,7)		1,263			927			984
Earnings (loss) before income tax		(380	)		(303	)		193
Net earnings (loss) attributable to common shareholders		(576	)		(336	)		52
Cash flow from operating activities		1,001			702			849
Funds from operations(2,3)		971			685			757
Free cash flow(2,3)		562			358			435
Net earnings (loss) per share attributable to common shareholders, basic and diluted		(2.13	)		(1.22	)		0.18
Dividends declared per common share(4)		0.19			0.22			0.12
Dividends declared per preferred share(5)		1.02			1.27			0.78
Funds from operations per share(2,3,8)		3.58			2.49			2.67
Free cash flow per share(2,3,8)		2.07			1.30			1.54

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Management’s Discussion and Analysis

As at Dec. 31	2021		2020		2019
Total assets		9,226		9,747		9,508
Total consolidated net debt(3,6)		2,636		2,974		3,110
Total long-term liabilities		4,702		5,376		4,329
Total liabilities		6,633		6,311		5,446

(1) Carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes and did not impact previously reported net earnings.

(2) Includes $56 million received on settlement of the dispute with the Balancing Pool in the third quarter of 2019.

(3) These items are not defined and have no standardized meaning 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. Please refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(4) No dividends were declared in the first quarter of 2021 as the quarterly dividend related to the period covering the first quarter of 2021 was declared in December 2020.

(5) 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.

(6) Total consolidated net debt includes long-term debt, including current portion, amounts due under credit facilities, exchangeable securities, US tax equity financing and lease liabilities, net of available cash and cash equivalents, the principal portion of restricted cash on our subsidiary TransAlta OCP LP (“TransAlta OCP”) and the fair value of economic hedging instruments on debt. See the table in the Financial Capital section of this MD&A for more details on the composition of total consolidated net debt.

(7) In the fourth quarter of 2021, comparable EBITDA was relabelled as adjusted EBITDA to align with industry standard terminology.

(8) Funds from operations (“FFO”) per share and free cash flow per share are calculated using the weighted average number of common shares outstanding during the period. The weighted average number of common shares outstanding at Dec. 31, 2021 was 271 million shares (2020 - 275 million shares and 2019 - 283 million shares). Please refer to the Additional IFRS Measures and Non-IFRS Measures section in this MD&A for the purpose of these non-IFRS ratios.

We have seen exceptional performance from our Alberta Electricity Portfolio, driving overall strong performance for the Company. Both the Hydro and Gas segments had high availability on the merchant assets during periods of peak pricing, which resulted from abnormally warm summer and cold winter weather and periods of province-wide planned thermal outages. The Alberta merchant portfolio was positioned to capture opportunities from these strong spot market conditions through both energy and ancillary service revenues. This was further supplemented by strong performance in our Energy Marketing segment.

Adjusted availability for 2021 was 86.6 per cent compared to 90.7 per cent in 2020. The decrease was primarily due to higher planned and unplanned outages in the Energy Transition segment. The unplanned outages at Centralia Unit 2 and Sundance Unit 4 adversely impacted availability. In addition, adjusted availability was reduced by the planned outages for the Keephills Unit 2 and Keephills Unit 3 boiler conversions. The unplanned outage at the Kent Hills 1 and 2 wind facilities further contributed to reduced adjusted availability.

Production for 2021 was 22,105 gigawatt hours (“GWh”) compared to 24,980 GWh in 2020. Overall, the decrease in production was primarily due to the planned retirement of Centralia Unit 1, portfolio optimization activities in Alberta, lower wind resources, the outage at the Kent Hills 1 and 2 wind facilities in the Wind and Solar segment and lower

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Management’s Discussion and Analysis

capacity loads in the Gas segment. This was partially offset by higher incremental production at our Ada facility within our Gas segment and higher incremental production from the Skookumchuck wind facility, the Windrise wind facility and the North Carolina Solar facility in the Wind and Solar segment.

Revenues for 2021 increased by $620 million compared to 2020, mainly as a result of capturing higher realized prices within the Alberta market through our optimization and operating activities and the elimination of the net payment obligations under the Alberta Hydro PPA required in the prior period. Revenues also increased due to the strong performance from the Energy Marketing segment, an increase in revenues within the Gas segment from the addition of the Ada facility and an increase within the Wind and Solar segment from the addition of the North Carolina Solar facility and the Windrise wind facility. These increases were partially offset by lower production in the Energy Transition, Hydro, Wind and Solar, and Gas segments.

Fuel and purchased power costs in 2021 increased by $249 million compared to 2020. In our Energy Transition segment, our fuel and purchased power costs increased compared to 2020 due to higher fuel transportation costs and the acquisition of higher-priced power during periods of higher merchant pricing to fulfil our contractual obligations during planned and unplanned outages at the Centralia facility. In addition, the Gas and Energy Transition segments experienced higher natural gas pricing, higher coal mine depreciation and coal inventory write-downs at the Highvale mine, all of which contributed to higher fuel costs.

Carbon compliance costs increased by $15 million compared to 2020, due to an increase in the carbon price per tonne, partially offset by reductions in GHG emissions stemming from changes in the fuel mix ratio as we operated more on natural gas and fired less with coal. Additionally, carbon compliance costs were partially offset by lower production in the Gas and Energy Transition segments. Operating with natural gas reduces carbon compliance costs as we produce fewer GHG emissions than by using coal.

Operations, maintenance and administration (“OM&A”) expenses for 2021 increased by $39 million compared to 2020. A write-down of $28 million was recorded on parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities. In addition, variability caused by the total return swap resulted in a favourable change of $7 million. During 2021, we received a Canada Emergency Wage Subsidy (“CEWS”) of $8 million. Excluding the impact of the total return swap, CEWS funding and inventory write-down, OM&A expenses were higher compared to the same periods in 2020, primarily due to increased staffing costs for growth and strategic initiatives and higher incentive costs. In addition, there were additional costs associated with the legal fees and the settlement of outstanding legal issues. As previously committed, the CEWS funding continues to be used to support incremental employment within the Company.

Adjusted EBITDA increased by $336 million compared to 2020. Adjusted EBITDA increased largely due to higher gross margin, driven by higher realized prices and dispatch optimization in the Alberta market from our merchant facilities residing in the Alberta Electricity Portfolio across the Hydro, Wind and Solar, Gas, and Energy Transition segments. In addition, the Energy Marketing segment also increased adjusted EBITDA due to favourable short-term trading of both physical and financial power and natural gas products across North American markets. This increase was partially offset by the retirement of Centralia Unit 1, unplanned outages at Centralia Unit 2 in the Energy Transition segment and the extended site outage at the Kent Hills 1 and 2 wind facilities. Significant changes in segmented adjusted EBITDA are highlighted in the Segmented Financial Performance and Operating Results section within this MD&A.

Loss before income taxes for 2021 increased by $77 million compared to 2020. Net loss attributable to common shareholders for 2021 was $576 million compared to a loss of $336 million in 2020. The higher loss before income taxes and the higher net loss attributable to common shareholders in 2021 was largely driven by higher asset impairments related to decisions to shut down the Highvale mine, suspend the Sundance 5 repowering project and planned retirements of Sundance Unit 4 and Keephills Unit 1. These higher asset impairments were partially offset by

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Management’s Discussion and Analysis

higher adjusted EBITDA largely resulting from the strong performance of the Alberta Electricity Portfolio across all of our fuel segments, higher gains on sale of assets due to the gain on sale of equipment in the Energy Transition segment and the gain from the sale of the Pioneer Pipeline in the Gas segment and lower depreciation. The higher net loss attributable to common shareholders was also impacted by higher income tax expense in 2021 due to higher earnings in the Energy Marketing segment and from the Alberta Electricity Portfolio.

Cash flow from operating activities increased by $299 million compared with 2020, primarily due to higher revenues being realized in Alberta on the merchant assets and changes in non-cash working capital, partially offset by higher fuel and purchased power and OM&A costs as the Company transitioned off coal.

FCF, one of the Company’s key financial metrics, totalled $562 million compared to $358 million in 2020. This represents an increase of $204 million, driven primarily by higher adjusted EBITDA, partially offset by an increase in sustaining capital spending related to higher planned maintenance and facility turnarounds, settlement of provisions and higher distributions paid to subsidiaries’ non-controlling interests.

Sustaining Capital

We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake sustaining capital expenditures that ensures our facilities operate reliably and safely over a long period of time.

Year ended Dec. 31	2021		2020		2019
Total sustaining capital expenditures		199		157		141

Total sustaining capital expenditures were $42 million higher compared to 2020, mainly due to higher planned major maintenance turnarounds related to Keephills Unit 2 and 3 and Sheerness Unit 1 and distributed planned maintenance expenditures across the entire hydro and wind fleet, with a focus on planned component replacements in the wind fleet.

Ability to Deliver Financial Results

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

Year ended Dec. 31			2021		2020		2019
Adjusted EBITDA (1)	Target	(2)		1,200-1,300		925-1000		875-975
	Actual			1,263		927		984
FCF (1)	Target	(2)		500-560		325-375		350-380
	Actual			562		358		435

(1) These items are not defined and have no standardized meaning under IFRS. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.

(2) This represents our revised outlook, as a result of strong performance in the second and third quarters of 2021, the Company revised the following 2021 targets: Adjusted EBITDA from the previously announced target range of $960 million - $1,080 million to the target range of $1,200 million - $1,300 million and FCF target range from $340 million - $440 million to the target range of $500 million - $560 million. In addition, during the fourth quarter of 2019, we revised our FCF target from a range of $270 million to $330 million to a range of $350 million to $380 million.

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Management’s Discussion and Analysis

Significant and Subsequent Events

White Rock Wind Projects and Fully Executed Corporate PPAs

On Dec. 22, 2021, TransAlta executed two long-term PPAs with a new customer with an AA credit rating from S&P Global Ratings for 100 per cent of the generation from its 300 MW White Rock Wind Projects to be located in Caddo County, Oklahoma. The White Rock Wind Projects will consist of a total of 51 Vestas turbines. Construction is expected to begin in late 2022 with a target commercial operation date in the second half of 2023. TransAlta will construct, operate and own the facilities. Total construction capital is estimated at approximately US$460 million to US$470 million and is expected to be financed with a combination of existing liquidity and tax equity financing. Over 90 per cent of the project costs are captured under executed fixed price turbine supply agreements and fixed price engineering, procurement and construction agreements. The project is expected to generate average annual EBITDA² of approximately US$42 million to US$46 million including production tax credits.

North Carolina Solar Acquisition

On Nov. 5, 2021, the Company closed the acquisition of a 122 MW portfolio of 20 solar photovoltaic sites located in North Carolina. The assets were acquired from a fund managed by Copenhagen Infrastructure Partners for approximately US$99 million (including working capital adjustments) and the assumption of existing tax equity obligations. The acquisition was funded using existing liquidity.

At the closing of the acquisition, TransAlta Renewables acquired a 100 per cent economic interest in North Carolina Solar from a wholly owned subsidiary of TransAlta through a tracking share structure for aggregate consideration of approximately US$102 million.

The facilities are all operational and were commissioned between November 2019 and May 2021. The facilities are secured by PPAs with Duke Energy, which have an average remaining term of 12 years. Under the PPAs, Duke Energy receives the renewable electricity, capacity and environmental attributes from each facility. North Carolina Solar is expected to generate an average annual EBITDA³ of approximately US$9 million.

Kent Hills Wind Facilities Outage

On Sept. 27, 2021, the Company’s subsidiary, Kent Hills Wind LP, experienced a single tower failure at its 167 MW Kent Hills wind facilities in Kent Hills, New Brunswick. The failure involved a collapsed tower located within the Kent Hills 2 site. There were no injuries as a result of the collapse. No one was in the area when the incident occurred and there are no homes in the immediate vicinity. The Company’s emergency response team secured the area to ensure safety. The Company recorded an impairment charge of $2 million on the collapsed tower.

The facilities consist of 50 turbines at the Kent Hills 1 and 2 wind facilities and five turbines at Kent Hills 3. Following extensive independent engineering assessments and root cause failure analysis, the Company announced on Jan. 11, 2022, that all 50 turbine foundations at the Kent Hills 1 and 2 wind facilities require a full foundation replacement. The root cause failure analysis indicates that deficiencies in the original design of the foundations had led to subsurface crack propagation within the foundations and that the foundations must be

²  Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

³  Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

SB-18

Management’s Discussion and Analysis

replaced. The Company is in the process of planning the rehabilitation of the wind sites and currently expects the wind facility foundations to be fully replaced by the end of 2023. Based on the recommendations of independent engineers, and in order to maintain the safety of the affected facilities and turbines, the wind turbines will cease to operate until their associated foundations are replaced. The Company has recorded $12 million of accelerated depreciation relating to the 50 foundations that will be replaced.

Foundation replacements will require expenditures of approximately $75 million to $100 million, in aggregate. The remediation plan is expected to begin to be implemented in 2022. The outage is expected to result in foregone revenue of approximately $3.4 million per month on an annualized basis so long as all 50 turbines are offline, based on average historical wind production, with revenue expected to be earned as the wind turbines are returned to service.

TransAlta and New Brunswick Power Corporation continue discussions to enable the safe return to service of the facilities.

The foundation issues at the Kent Hills 1 and 2 wind facilities are unique to the design of those sites and there is no indication of any foundation issue at the Kent Hills 3 facility or any other wind facility in the fleet. The Company is maintaining communication with all key stakeholders and is keeping them fully apprised of the situation. The Company is actively evaluating any options that may be available to recover these costs from third parties and insurance.

As a result of the determination that all 50 foundations require replacement, as well as certain resulting amendments to applicable insurance policies, the Company’s operating subsidiary, Kent Hills Wind LP, has provided notice to BNY Trust Company of Canada, as trustee (the “Trustee”), for the approximately $221 million outstanding non-recourse project bonds (the “KH Bonds”) secured by, among other things, the Kent Hills 1, 2 and 3 wind facilities, that events of default may have occurred under the trust indenture governing the terms of the KH Bonds. Upon the occurrence of any event of default, holders of more than 50 per cent of the outstanding principal amount of the KH Bonds have the right to direct the Trustee to declare the principal and interest on the KH Bonds and all other amounts due, together with any make-whole amount as at Dec. 31, 2021 — $39 million, to be immediately due and payable and to direct the Trustee to exercise rights against certain collateral. The Company is in discussions with the Trustee and holders of the KH Bonds to negotiate required waivers and amendments while the Company works to remedy the matters described in the notice. Although the Company expects that it will reach agreement with the Trustee and holders of the KH Bonds with respect to terms of an acceptable waiver and amendment, there can be no assurance that the Company will receive such waivers and amendments. Accordingly, the Company has classified the entire carrying value of the KH Bonds as a current liability as at Dec. 31, 2021.

Investor Day

On Sept. 28, 2021, TransAlta held our 2021 Investor Day and announced our Clean Electricity Growth Plan. The Company has established targets to deliver 2 GW of incremental renewables capacity with a targeted investment of $3 billion by 2025. TransAlta will accelerate its growth with a focus on customer-centred renewables and storage through the execution of its 3 GW development pipeline. Please see the Accelerated Clean Electricity Growth Plan section of this MD&A.

Retirement of Sundance Unit 4, Keephills Unit 1 and Sundance Unit 5 Coal-Fired Units

The Company announced, during its recent Investor Day, its decision to suspend the Sundance Unit 5 repowering project and retire Keephills Unit 1 on Jan. 1, 2022 and Sundance Unit 4 in 2022.

SB-19

Management’s Discussion and Analysis

On July 29, 2021, in accordance with applicable regulatory requirements, the Company gave notice to the AESO of its intention to retire the currently mothballed coal-fired Sundance Unit 5 effective Nov. 1, 2021, and to terminate the associated transmission service agreement. Refer to the Clean Energy Transition section within the Description of the Business section of this MD&A for additional details on these thermal assets.

TransAlta Achieves Full Phase-Out of Coal in Canada

During the year, the Company completed the full conversion of Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 from thermal coal to natural gas. Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 will maintain the same generator nameplate capacity of 395 MW, 463 MW and 401 MW, respectively. These conversion to gas projects will reduce our CO₂ emissions by more than half and completes our plan to generate 100 per cent clean electricity in Alberta by the end of 2021. As of Dec. 31, 2021, the Company has fully transitioned to natural gas in Canada.

Highvale Mine Impairment

During the third quarter of 2020, the Board approved the accelerated shutdown of the Highvale mine by the end of 2021 and, accordingly, the useful life of the related assets was adjusted to align with the Company’s conversion to gas plans. During the third quarter of 2021, with all of TransAlta’s remaining coal-fired units having been converted, in the process of being converted to natural gas or being retired, the Highvale mine was no longer considered to be providing significant economic benefit to the Alberta Merchant CGU and was removed from the CGU. This resulted in an impairment being recognized during 2021 of $195 million. Effective Dec. 31, 2021, the mine has entered its reclamation phase.

Announced Common Dividend Increase

On Sept. 28, 2021, the Company announced that the Board approved an 11 per cent increase on its common share dividend and declared a dividend of $0.05 per common share paid on Jan. 1, 2022, to shareholders of record at the close of business on Dec. 1, 2021. The quarterly dividend of $0.05 per common share represents an annualized dividend of $0.20 per common share.

Northern Goldfields Solar Project

On July 29, 2021, TransAlta Renewables announced that Southern Cross Energy (“SCE”), a subsidiary of the Company and an entity in which TransAlta Renewables owns an indirect economic interest, had reached an agreement to provide BHP Billiton Nickel West Pty Ltd. (“BHP”) with renewable electricity to its Goldfields-based operations through the construction of the Northern Goldfields Solar Project. The project consists of the 27 MW Mount Keith Solar Farm, 11 MW Leinster Solar Farm, 10 MW/5MWh Leinster Battery Energy Storage System and interconnecting transmission infrastructure, all of which will be integrated into our existing 169 MW Southern Cross Energy North remote network in Western Australia. Construction commenced in the first quarter of 2022 with completion of the projects expected in the second half of 2022. Total construction capital for the project is estimated at approximately AU$69 million to AU$73 million. The project is expected to generate average annual EBITDA⁴ of approximately AU$9 million to AU$10 million.

On Oct. 22, 2020, SCE replaced and extended its current PPA with BHP. SCE is composed of four generation facilities with a combined capacity of 245 MW in the Goldfields region of Western Australia. The new

⁴  Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

SB-20

Management’s Discussion and Analysis

agreement was effective Dec. 1, 2020, and replaces the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extends the term to Dec. 31, 2038, and provides SCE with the exclusive right to supply thermal and electrical energy from the Southern Cross Facilities for BHP’s mining operations located in the Goldfields region of Western Australia. The extension will provide SCE a return on new capital investments, which will be required to support BHP’s future power requirements and recently announced emission reduction targets. The amendments within the PPA also provide BHP with participation rights in integrating renewable electricity generation, including solar and wind, with energy storage technologies, subject to the satisfaction of certain conditions. In addition to the Northern Goldfields Solar Project, evaluation of further renewable energy supply and carbon emissions reduction initiatives under the extended PPA with BHP are underway, including wind generation and lower emission firming generation to support BHP’s future power requirements.

Sale of the Pioneer Pipeline

On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. (“ATCO”) for the aggregate sale price of $255 million. The net cash proceeds to TransAlta from the sale of its 50 per cent interest was approximately $128 million. Pioneer Pipeline has been integrated into the NOVA Gas Transmission Ltd. (“NGTL”) and ATCO Alberta natural gas transmission systems to provide reliable natural gas supply to the Company’s power generation stations at Sundance and Keephills. As part of the transaction, TransAlta has entered into additional long-term gas transportation agreements with NGTL for new and existing transportation service of 400 TJ per day by the end of 2023.

Sarnia Cogeneration Facility Contract Extension

On May 12, 2021, the Company executed an Amended and Restated Energy Supply Agreement with one of its large industrial customers at the Sarnia cogeneration facility, which provides for the supply of electricity and steam. This agreement will extend the term of the original agreement from Dec. 31, 2022 to Dec. 31, 2032. The agreement provides that if the Company is unable to enter into a new contract with the Ontario Independent Electricity System Operator (“IESO”) or enter into agreements with its other industrial customers at the Sarnia cogeneration facility that extend past Dec. 31, 2025, then the Company has the option to provide notice of termination in 2022 that would terminate the Amended and Restated Energy Supply Agreement four years following such notice. The Company is in active discussions with the three other existing industrial customers regarding extensions to their supply of electricity and steam from the Sarnia cogeneration facility on comparable terms. The current contract with the IESO in respect of the Sarnia cogeneration facility expires on Dec. 31, 2025. On July 19, 2021, the IESO released its Annual Acquisition Report, which included draft details for medium- and long-term procurement mechanisms for capacity for 2026 and beyond for existing and new generation. The medium-term procurement process is scheduled to be run in 2022. The Company plans to bid into the process, seeking to secure a contract extension for the Sarnia cogeneration facility following the end of the current contract.

Garden Plain Wind Project

On May 3, 2021, the Company announced that it entered into a long-term PPA with Pembina pursuant to which Pembina has contracted for the renewable electricity and environmental attributes for 100 MW of the 130 MW Garden Plain project. Under a separate agreement, Pembina has the option to purchase a 37.7 per cent interest in the project (49 per cent of the quantity under the PPA). The option must be exercised no later than 30 days after the commercial operational date. TransAlta would remain the operator of the facility and earn a management fee if Pembina exercises this option. Garden Plain will be located approximately 30 kilometres north of Hanna, Alberta. Construction activities started in the fall of 2021 with completion of the project expected in the second

SB-21

Management’s Discussion and Analysis

half of 2022. Total construction capital for the project is estimated at approximately $195 million. The project is expected to contribute between $14 million and $18 million of average annual EBITDA⁵.

TransAlta Renewables is Named on the Best 50 Corporate Citizens List

During the second quarter of 2021, TransAlta Renewables was recognized by Corporate Knights as one of the Best 50 Corporate Citizens for 2021. The Best 50 Corporate Citizens list evaluates and ranks Canadian corporations against a set of 24 key performance indicators covering ESG indicators relative to their industry peers and using publicly available information. The Company is committed to continuous improvement on key ESG issues and to ensuring its economic value creation is balanced with a value proposition for the environment and its communities.

Equity, Diversity and Inclusion Program

On May 3, 2021, TransAlta announced that it received certification from a third party that specializes in measuring and tracking equity, diversity and inclusion (“ED&I”) metrics for organizations, due to its continued commitment to and meaningful performance on ED&I in the workplace. The Company developed a five-year ED&I strategy that was approved by the Board in August 2021, and is now executing the first year of that ED&I strategy.

Sustainability-Linked Loan

In March 2021, TransAlta extended its $1.3 billion syndicated credit facility to June 30, 2025, and converted the facility into a Sustainability-Linked Loan (“SLL”). The facility’s financing terms will align the cost of borrowing to TransAlta’s GHG emission reductions and gender diversity targets, which are part of the Company’s overall ESG strategy. The SLL will have a cumulative pricing adjustment to the borrowing costs on the facilities and a corresponding adjustment to the standby fee (the “Sustainability Adjustment”). Depending on performance against interim targets that have been set for each year of the credit facility term, the Sustainability Adjustment is structured as a two-way mechanism and could move either up, down or remain unchanged for each sustainability performance target based on performance. The SLL further underscores TransAlta’s dedication to sustainability, including ED&I and emissions reduction.

Mangrove Claim

On April 23, 2019, the Mangrove Partners Master Fund Ltd. (“Mangrove”) commenced an action in the Ontario Superior Court of Justice naming the Company, the members of the Board of the Company on such date, and Brookfield BRP Holdings (Canada) (“Brookfield”) as defendants. Mangrove was seeking to set aside the 2019 Brookfield transaction. The parties reached a confidential settlement and the action was discontinued in the Ontario Superior Court of Justice on April 30, 2021.

Fortescue Metals Group Ltd. (“FMG”) Dispute at South Hedland Power Station

On May 2, 2021, the Company entered into a conditional settlement with FMG. The settlement was concluded and the actions were formally dismissed in the Supreme Court of Western Australia on Dec. 7, 2021. The settlement amount has been recorded as revenue in the fourth quarter of 2021, while all other balances previously provided for have been reversed. The settlement has resulted in FMG continuing as a customer of the South Hedland facility.

⁵  Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

SB-22

Management’s Discussion and Analysis

Keephills 1 Superheater Force Majeure

Keephills Unit 1 was taken offline from March 17, 2015, to May 17, 2015, as a result of a large leak in the secondary superheater. TransAlta claimed force majeure under the PPA. ENMAX Energy Corporation (“ENMAX”), the purchaser under the PPA at the time, did not dispute the force majeure but the Balancing Pool attempted to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The parties reached a confidential settlement on April 21, 2021, and this matter is now resolved.

TransAlta Renewables Acquisitions

The Company completed the sale of its 100 per cent direct interest in the 206 MW Windrise wind project (“Windrise”) to TransAlta Renewables on Feb. 26, 2021, for $213 million. The remaining construction costs for Windrise were paid by TransAlta Renewables. On Nov. 10, 2021, Windrise achieved commercial operations. On Dec. 6, 2021, the Company’s indirect wholly owned subsidiary, Windrise Wind LP, secured green bond financing by way of private placement for $173 million. The bonds will be amortizing and will bear interest from their date of issue at a rate of 3.41 per cent per annum and mature on Sept. 30, 2041.

On April 1, 2021, the Company completed the sale of its 100 per cent economic interest in the 29 MW Ada cogeneration facility (“Ada”) and its 49 per cent economic interest in the 137 MW Skookumchuck wind facility (“Skookumchuck”) to TransAlta Renewables for $43 million and $103 million, respectively. Both facilities are fully operational. Pursuant to the transaction, a TransAlta subsidiary owns Ada and Skookumchuck directly and has issued to TransAlta Renewables tracking preferred shares reflecting its economic interest in the facilities. The Ada facility is under a PPA until 2026. The Skookumchuck wind facility is contracted under a PPA until 2040 with an investment grade counterparty.

Normal Course Issuer Bid

On May 25, 2021, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to implement a normal course issuer bid (“NCIB”) for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. 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 May 31, 2021, and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election.

No common shares were repurchased under the current or previous NCIB in 2021.

Management Changes

On March 31, 2021, Dawn Farrell retired from the Board and as President and Chief Executive Officer of the Company. John Kousinioris succeeded Mrs. Farrell as President and Chief Executive Officer and joined the Board on April 1, 2021. Prior to his appointment as Chief Executive Officer of TransAlta, Mr. Kousinioris held the roles of Chief Operating Officer, Chief Growth Officer and Chief Legal and Compliance Officer and Corporate Secretary with the Company.

On April 30, 2021, Brett Gellner, our Chief Development Officer, retired after almost 13 years with TransAlta. Mr. Gellner continues to serve on the Board of Directors of TransAlta Renewables as a non-independent director.

SB-23

Management’s Discussion and Analysis

Board of Director Changes

On May 4, 2021, the Company announced the election of four new directors: Mr. Thomas O’Flynn, Ms. Laura W. Folse, Mr. Jim Reid and Ms. Sarah Slusser, who each bring diverse expertise and new perspectives to the Board. Mr. Richard Legault, Mr. Yakout Mansour and Mrs. Georgia Nelson did not stand for re-election and retired from the Board immediately following the annual shareholder meeting on May 4, 2021.

COVID-19

The World Health Organization declared a Public Health Emergency of International Concern relating to COVID-19 on Jan. 30, 2020, which they subsequently declared, on March 11, 2020, as a global pandemic.

The Company continues to operate under its business continuity plan, which is focused on ensuring that: (i) employees who can work remotely do so; and (ii) employees who operate and maintain our facilities, and who are not able to work remotely, are able to work safely and in a manner that ensures their health and safety. TransAlta has adopted local public health authority and government guidelines in all jurisdictions in which we operate to promote the health and safety of all employees and contractors with our health and safety protocols. All of TransAlta’s offices and sites follow health screening and social distancing protocols, including personal protective equipment. Employees can be exempted from rapid testing if they are able to provide proof of vaccination. Further, TransAlta maintains travel limitations that are aligned to local jurisdictional guidance, enhanced cleaning procedures, revised work schedules, contingent work teams and the reorganization of processes and procedures to minimize any workplace transmission of the virus.

Notwithstanding the challenges associated with the pandemic, all of our facilities continue to remain fully operational and are capable of meeting our customers’ needs, with the exception of the Kent Hills 1 and 2 wind facilities, which as described above, is not related to the pandemic. The Company continues to work and serve all of our customers and counterparties under the terms of their contracts. We have not experienced interruptions to service requirements as a result of COVID-19. Electricity and steam supply continue to remain a critical service requirement to all of our customers and have been deemed an essential service in our jurisdictions.

The Company continues to maintain a strong financial position due in part to its long-term contracts and hedged positions, and its ample financial liquidity.

The Board and management have been monitoring the evolution of the pandemic and are continually assessing its impact to the safety of the Company’s employees, operations, supply chains and customers as well as, more generally, to our existing capital projects, and the business and affairs of the Company. Potential impacts of the pandemic on the business and affairs of the Company include, but are not limited to: (i) potential interruptions of production; (ii) supply chain disruptions; (iii) unavailability of employees; (iv) potential delays in capital projects; (v) increased credit risk with counterparties and increased volatility in commodity prices; as well as (vi) increased volatility in the valuation of financial instruments. In addition, the broader impacts to the global economy and financial markets could have potential adverse impacts on the availability of capital for investment and the demand for power and commodity pricing.

Strategic Investment by Brookfield

On March 22, 2019, the Company entered into an agreement (the “Investment Agreement”) whereby Brookfield agreed to invest $750 million in the Company through the purchase of exchangeable securities, which are exchangeable by Brookfield into an equity ownership interest in certain of TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Alberta Hydro Assets’ future-adjusted EBITDA.

SB-24

Management’s Discussion and Analysis

On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for seven per cent unsecured subordinated debentures due May 1, 2039. On Oct. 30, 2020, Brookfield invested the second tranche of $400 million in consideration for redeemable, retractable first preferred shares. The proceeds from the first and second tranche were used to accelerate our conversion to gas program. In addition, the proceeds from the second tranche of the financing will be used to fund other growth initiatives and for general corporate purposes.

Under the terms of the Investment Agreement, Brookfield committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to not less than nine per cent. At Dec. 31, 2021, Brookfield, through its affiliates, held, owned or had control over an aggregate of 35,425,696 common shares, representing approximately 13.1 per cent of the issued and outstanding common shares, calculated on an undiluted basis. In connection with the Investment Agreement, Brookfield is entitled to nominate two directors for election to the Board.

In accordance with the terms of the Investment Agreement, TransAlta formed a Hydro Assets Operating Committee consisting of two representatives from Brookfield and two representatives from TransAlta to collaborate in connection with the operation and maximization of the value of the Alberta Hydro Assets. In connection with this, the Company has committed to pay Brookfield an annual fee of $1.5 million for six years beginning May 1, 2019, which is recognized in the OM&A expense on the Consolidated Statements of Earnings (Loss).

Centralia Unit 1 and 2 Retirement

In 2011, Washington State passed the TransAlta Energy Transition Bill (chapter 180, Laws of 2011) (the “Bill’’) allowing the Centralia thermal facility to comply with the state’s 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 oxide (“NO_x”) controls. Centralia Unit 1 was retired from service effective Dec. 31, 2020, as planned. The Centralia Unit 2 is set to shut down at the end of 2025.

TEC Hedland Pty Ltd. Secures AU$800 Million Financing

On Oct. 22, 2020, TEC Hedland Pty Ltd. (“TEC”), a subsidiary of the Company, closed an AU$800 million senior secured note offering, by way of a private placement, which is secured by, among other things, a first ranking charge over all assets of TEC (the “TEC Offering”). The TEC Offering bears interest at 4.07 per cent per annum, payable quarterly and maturing on June 30, 2042, with principal payments starting on March 31, 2022. The TEC Offering has a rating of BBB by Kroll Bond Rating Agency.

TransAlta Renewables has received $480 million (AU$515 million) of the proceeds from the TEC Offering through the redemption of certain intercompany structures. An additional AU$200 million was loaned to TransAlta Renewables by TransAlta Energy (Australia) Pty Ltd., which is a subsidiary of TransAlta. The loan bears interest at 4.32 per cent and will be repaid by Oct. 23, 2022, or on demand. The remaining proceeds from the TEC Offering were set aside for required reserves and transaction costs. TransAlta Renewables used a portion of the proceeds from the redemption and the intercompany loan to repay existing indebtedness on its credit facility and to acquire the asset and economic interests noted above.

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Management’s Discussion and Analysis

Segmented Financial Performance and Operating Results

Segmented Disclosures

Segmented information is prepared on the same basis that the Company manages the business, evaluates financial results and makes key operating decisions. Refer to the Description of the Business section of this MD&A for explanation of the reporting segment changes.

The primary changes are the elimination of the Alberta Thermal and the Centralia segments, and the reorganization of the North American Gas and Australia Gas segments into a new “Gas” segment. The Alberta Thermal facilities that have been converted to gas have been included in the Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets and those facilities not converted to gas and the remaining Centralia unit, are included in a new “Energy Transition” segment. No changes were made to the Hydro, Wind and Solar, Energy Marketing or the Corporate and Other segments. Prior years’ metrics were adjusted to be comparable to the new segments.

Consolidated Results

The following table reflects the generation and summary financial information on a consolidated basis for the year ended Dec. 31:

	LTA generation (GWh)(1)						Actual production (GWh)(2)						Adjusted EBITDA(3)
For the year ended Dec. 31	2021		2020		2019		2021		2020		2019		2021			2020			2019
Hydro		2,030		2,030		2,030		1,936		2,132		2,045		322			105			110
Wind and Solar		4,345		3,916		3,549		3,898		4,069		3,355		262			248			231
Renewables		6,375		5,946		5,579		5,834		6,201		5,400		584			353			341
Gas								10,565		10,780		11,819		494			367			403
Energy Transition								5,706		7,999		11,852		133			175			227
Energy Marketing														137			113			89
Corporate and Other														(85	)		(81	)		(76	)
Total								22,105		24,980		29,071		1,263			927			984
Total earnings (loss) before income taxes														(380	)		(303	)		193

(1) Long-term average production (“LTA (GWh)”) is calculated based on our portfolio as at Dec. 31, 2021, on an annualized basis from the average annual energy yield predicted from our simulation model based on historical resource data performed over a period of typically 30-35 years for the Wind and Solar segment and 36 years for Hydro segment. LTA (GWh) for Energy Transition is not considered for these facilities as we are currently transitioning these units completely by the end of 2025 and the LTA (GWh) for Gas is not considered as it is largely dependent on market conditions and merchant demand.

(2) Actual production levels are compared against the long-term average to highlight the impact of an important factor that affects the variability in our business results. In the short term, for each segment for Hydro, Wind and Solar, the conditions will vary from one period to the next and over time facilities will continue to produce in line with their long-term averages, which have proven to be reliable indicators of performance.

(3) This item is not defined and has no standardized meaning under IFRS. Please refer to below in this MD&A for further discussion of this item, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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Management’s Discussion and Analysis

Hydro

Year ended Dec. 31	2021			2020			2019
Gross installed capacity (MW)		925			925			925
LTA (GWh)		2,030			2,030			2,030
Availability (%)		92.4			93.2			95.9
Production
Energy contract
Alberta Hydro Assets (GWh)(1)		—			1,703			1,653
Other Hydro energy (GWh)(1)		434			353			331
Energy merchant
Alberta Hydro Assets (GWh)		1,502			—			—
Other Hydro energy (GWh)		—			76			61
Total energy production (GWh)		1,936			2,132			2,045
Ancillary service volumes (GWh)(4)		2,897			2,857			2,978
Alberta Hydro Assets(1)		185			87			101
Other Hydro Assets and other revenue(1)(2)		42			45			44
Capacity payments(3)		—			60			57
Alberta Hydro ancillary services(4)		160			66			90
Net payment relating to Alberta Hydro PPA(5)		(4	)		(106	)		(136	)
Revenues		383			152			156
Fuel and purchased power		16			8			7
Gross margin		367			144			149
Operations, maintenance and administration		42			37			36
Taxes, other than income taxes		3			2			3
Adjusted EBITDA		322			105			110
Supplemental Information:
Gross revenues per MWh
Alberta Hydro Assets energy ($/MWh)		123			51			61
Alberta Hydro Assets ancillary ($/MWh)		55			23			30
Sustaining capital		26			20			14

(1) Alberta Hydro Assets include 13 hydro facilities on the Bow and North Saskatchewan river systems included under the PPA legislation. These PPAs expired Dec. 31, 2020. Other hydro facilities include our hydro facilities in BC and Ontario and the hydro facilities in Alberta not included in the legislated PPAs and transmission revenues.

(2) 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.

(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. The PPA expired on Dec. 31, 2020.

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

(5) The net payment relating to the Alberta Hydro PPA represents the Company’s financial obligations for notional amounts of energy and ancillary services in accordance with the Alberta Hydro PPA that expired on Dec. 31, 2020.

SB-27

Management’s Discussion and Analysis

2021

Availability for 2021 decreased compared to 2020, primarily due to higher planned and unplanned outages.

Production for 2021 decreased by 196 GWh compared to 2020, mainly due to higher planned outages and lower precipitation.

Ancillary service volumes for 2021 increased by 40 GWh compared to 2020, in line with our expectations.

Adjusted EBITDA for 2021 increased by $217 million compared to 2020. Effective Jan. 1, 2021, with the expiration of the Alberta PPA for our Alberta Hydro Assets, these facilities began operating on a merchant basis in the Alberta power market. This eliminated the net payment obligations under the Alberta PPA. With strong availability during periods of market volatility, the Company captured higher energy and ancillary service revenue, partially offset by increased costs related to portfolio management services, dam safety staffing, dredging and station services.

Sustaining capital expenditures for 2021 were $6 million higher than in 2020, due to higher planned outages in 2021.

2020

Availability for 2020 decreased compared to 2019, primarily due to higher planned and unplanned outages.

Production for 2020 increased by 87 GWh over 2019, primarily due to higher water resources.

Ancillary service volumes for 2020 decreased by 121 GWh compared to 2019. This was primarily due to the AESO procuring lower ancillary volumes in 2020. Ancillary volumes were impacted by weaker market conditions, partially due to COVID-19 and reduced industrial demand in Alberta.

In 2020, Alberta Hydro energy revenue per MWh of production decreased by approximately $10 per MWh, compared to 2019, as result of lower merchant prices in Alberta. In 2020, Alberta Hydro ancillary revenue per MWh of production decreased by approximately $7 per MWh, compared to 2019. Lower realized prices were primarily due to unfavourable market conditions in Alberta in 2020.

Adjusted EBITDA for 2020 decreased by $5 million compared to 2019, from lower revenues partially offset by recoveries allocated by the AESO related to the AESO transmission line loss proceeding.

Sustaining capital expenditures for 2020 were $6 million higher than in 2019, due to higher planned outages in 2020.

Wind and Solar

Year ended Dec. 31	2021		2020		2019
Gross installed capacity (MW)(1)		1,906		1,572		1,495
LTA (GWh)		4,345		3,916		3,549
Availability (%)		91.9		95.1		95.0
Contract production (GWh)		2,850		2,871		2,395
Merchant production (GWh)		1,048		1,198		960
Total production (GWh)		3,898		4,069		3,355

SB-28

Management’s Discussion and Analysis

Year ended Dec. 31	2021		2020		2019
Revenues(2)		348		334		295
Fuel and purchased power		17		25		16
Gross margin(2)		331		309		279
Operations, maintenance and administration		59		53		50
Taxes, other than income taxes		10		8		8
Net other operating income(3)		—		—		(10	)
Adjusted EBITDA		262		248		231
Supplemental information:
Sustaining capital		13		13		13

(1) The 2021 gross installed capacity includes 206 MW for the Windrise wind facility and 4 MW for the Oldman Wind facility, which were added in 2021. The 2021 and 2020 gross installed capacity includes 10 MW for the WindCharger battery storage facility and 67 MW for our proportionate share of the Skookumchuck wind facility.

(2) For details of the adjustments to revenues included in adjusted EBITDA, refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.

(3) Relates to insurance proceeds included in net other operating income.

2021

Availability for the year ended Dec. 31, 2021, decreased compared to 2020, primarily as a result of the unplanned outage at the Kent Hills 1 and 2 wind facilities.

Production for the year ended 2021, decreased 171 GWh compared to 2020, and was impacted by lower wind resources in Eastern Canada and in the US and the unplanned outage at the Kent Hills 1 and 2 wind facilities, which was partially offset by a full year of production from the Skookumchuck wind facility, the commissioning of the Windrise wind facility, and the acquisition of the North Carolina Solar facility.

Adjusted EBITDA for 2021 increased by $14 million compared to 2020, primarily due to higher merchant pricing in Alberta, a full year of operations from the Skookumchuck wind facility and the WindCharger battery storage facility as well as incremental value from the newly commissioned or acquired assets in 2021: consisting of the Windrise wind facility and the North Carolina Solar facility. Also, fuel and purchased power costs were lower in 2021 due to the AESO transmission line loss recorded in 2020. Adjusted EBITDA was negatively impacted by lower wind resources in Eastern Canada and the US, the unplanned outage at the Kent Hills 1 and 2 wind facilities and the weakening US dollar relative to the Canadian dollar.

Sustaining capital expenditures for 2021 were consistent with 2020.

2020

Availability for the year ended Dec. 31, 2020, was consistent with 2019, which was in line with our expectations.

Production for the year ended Dec. 31, 2020, increased 714 GWh, mainly due to the Big Level and Antrim wind facilities commencing commercial operations in December 2019 and strong wind resources across all regions in 2020, in particular at the Alberta wind facilities.

SB-29

Management’s Discussion and Analysis

Adjusted EBITDA for 2020 increased by $17 million compared to 2019, primarily due to the addition of the Big Level and Antrim wind facilities and higher production, partially offset by insurance proceeds received in 2019, lower Alberta pricing and the planned expiry of certain wind power production incentives in 2019. In addition, during 2020, the AESO began issuing invoices pertaining to the AESO transmission line loss. Wind and Solar were allocated $8 million in costs in 2020, which has been reflected in fuel and purchased power within the same year.

Sustaining capital expenditures for 2020 were consistent with 2019.

Gas

Year ended Dec. 31	2021			2020			2019
Gross installed capacity (MW)(1)		3,084			3,084			3,049
Availability (%)		85.7			87.7			92.8
Contract production (GWh)		3,622			7,280			8,101
Merchant production (GWh)(2)		7,084			3,698			3,810
Purchased power (GWh)(2)		(141	)		(198	)		(92	)
Total production (GWh)		10,565			10,780			11,819
Revenues(3)		1,132			848			887
Fuel and purchased power(3)		374			221			230
Carbon compliance		118			120			138
Gross margin(3)		640			507			519
Operations, maintenance and administration(3)		173			166			162
Taxes, other than income taxes		13			13			9
Net other operating income(3)		(40	)		(39	)		(41	)
Termination of Sundance B and C PPAs		—			—			(14	)
Adjusted EBITDA		494			367			403
Supplemental information:
Sustaining capital		128			87			33

(1) 2021 and 2020 includes 29 MW for the acquisition of the Ada facility.

(2) Purchased power used for dispatch optimization has been separated from merchant production in the current year. Comparable periods have been adjusted to reflect this change.

(3) For details of the adjustments to revenues, fuel and purchased power, operations, maintenance and administration and net other operating income included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

The Gas Segment is a new segment as described in the Segmented Financial Performance and Operating Results section of this MD&A. Included in the Gas segment is the previous North American Gas segment, Australian Gas segment and the facilities from the previous Alberta Thermal segment converted to gas.This includes Sheerness Unit 1 and 2, Keephills Unit 2 and 3 and Sundance Unit 6. Previous periods have been adjusted to be comparable to the new segment.

SB-30

Management’s Discussion and Analysis

2021

Availability for the year ended Dec. 31, 2021, decreased compared to 2020, primarily as a result of an increase in unplanned outages and planned boiler conversions of Keephills Unit 2, Keephills Unit 3, and Sheerness Unit 1 in Alberta, partially offset by higher availability of Sundance 6 with the gas conversion completed in 2020.

Production for the year ended Dec. 31, 2021, decreased by 215 GWh compared to 2020, mainly due to higher portfolio optimization activities in Alberta and lower customer loads in Australia, partially offset by higher demand in our other facilities and incremental production from a full year of operations at the Ada cogeneration facility.

Adjusted EBITDA for the year ended Dec. 31, 2021, increased by $127 million compared to 2020, primarily due to higher merchant pricing in the Alberta market, the South Hedland PPA contract settlement and incremental production from a full year of operations at our Ada cogeneration facility, partially offset by an increase in fuel, unplanned short-term steam supply outages at our Sarnia cogeneration facility, higher OM&A costs related to the BHP pass-through projects and legal fees related to the South Hedland PPA contract settlement.

Sustaining capital expenditures for the year ended Dec. 31, 2021, increased by $41 million mainly due to major maintenance costs associated with conversion to natural gas outages of Keephills Unit 2 and Unit 3 and Sheerness Unit 1, planned major maintenance at the Australian gas facilities, and the purchase of an additional engine at the South Hedland facility.

2020

Availability for the year ended Dec. 31, 2020, decreased compared to 2019, due to the Sundance Unit 6 planned turnaround and conversion to gas, higher unplanned outages and derates.

Production for the year ended Dec. 31, 2020, decreased by 1,039 GWh compared to 2019, mainly due to lower availability, lower merchant production in Alberta and Ontario and lower customer demand in Australia, partially offset by the addition of the Ada cogeneration facility.

Adjusted EBITDA for the year ended Dec. 31, 2020, decreased by $36 million compared to 2019, due to lower revenues from lower realized merchant pricing in Alberta and lower production, higher fuel costs and $14 million related to the settlement on the Sundance B and C PPAs in 2019, partially offset by the addition of the Ada facility, deferral of legal costs, reduced staffing due to cost controls and the strengthening of the Australian dollar against the Canadian dollar.

Sustaining capital expenditures for the year ended Dec. 31, 2020, increased by $54 million mainly due to the major maintenance that occurred during the Sheerness dual-fuel conversion and the Sundance Unit 6 turnaround and planned major maintenance at the Southern Cross facility, partially offset by a reduction in sustaining capital associated with a major planned outage for Sarnia cogeneration facility in 2019.

SB-31

Management’s Discussion and Analysis

Energy Transition

Year ended Dec. 31	2021			2020			2019
Gross installed capacity (MW)(1)		1,472			2,548			2,916
Availability (%)		75.3			82.6			78.7
Adjusted availability (%)(2)		78.8			91.3			84.2
Contract sales volume (GWh)		3,329			5,526			5,622
Merchant sales volume (GWh)		6,052			6,248			10,095
Purchased power (GWh)		(3,675	)		(3,775	)		(3,865	)
Total production (GWh)		5,706			7,999			11,852
Revenues(3)		728			690			893
Fuel and purchased power(3)		432			352			499
Carbon compliance		60			48			77
Gross margin(3)		236			290			317
Operations, maintenance and administration(3)		97			106			124
Taxes, other than income taxes		6			9			8
Termination of Sundance B and C PPAs		—			—			(42	)
Adjusted EBITDA		133			175			227
Supplemental information:
Highvale mine reclamation spend		6			7			15
Centralia mine reclamation spend		9			7			11
Sustaining capital		19			22			69

(1) 2021 gross installed capacity excludes Centralia Unit 1 (670 MW retired on Dec. 31, 2020) and Sundance Unit 5 (406 MW) retired during the year. 2021 and 2020 excludes 368 MW from Sundance Unit 3, which retired during 2020.

(2) Adjusted for dispatch optimization.

(3) For details of the adjustments to revenues, fuel and purchased power and operations, maintenance and administration included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

The Energy Transition segment is a new segment as described in the Segmented Financial Performance and Operating Results section of this MD&A. Included in the Energy Transition segment is the previous Centralia segment, mine assets and the previous Alberta Thermal segment facilities that were not converted to gas. This includes Keephills Unit 1 and Sundance Unit 4. Previous periods have been adjusted to be comparable to the new segment.

2021

Adjusted availability for the year ended Dec. 31, 2021, decreased compared to 2020 due to higher planned and unplanned outages at Centralia Unit 2 and Sundance Unit 4 related to derates.

Production decreased by 2,293 GWh for the year ended Dec. 31, 2021, compared to 2020, primarily due the planned retirement of Centralia Unit 1 and dispatch optimization of the Alberta assets.

Adjusted EBITDA decreased by $42 million for the year ended Dec. 31, 2021, compared to 2020, primarily due the planned retirement of Centralia Unit 1, higher fuel and purchased power due to unplanned outages at Centralia Unit 2, higher carbon compliance costs for the Alberta assets primarily due to an increase in carbon

SB-32

Management’s Discussion and Analysis

prices and the weakening of the US dollar relative to the Canadian dollar throughout the year, partially offset by dispatch optimization of the Alberta assets and lower OM&A as a result the planned retirement of Centralia Unit 1.

Mine reclamation spend for the Highvale and Centralia mines was mainly consistent compared to 2020.

Sustaining capital expenditures for the year ended Dec. 31, 2021, were $3 million lower than 2020 mainly due to reduction in planned outage work performed.

2020

Adjusted availability for the year increased compared to 2019 due to reduced forced outages at Centralia Unit 1 and lower planned outages at the Alberta sites.

Production decreased by 3,853 GWh in 2020 compared to 2019 mainly due to lower merchant pricing and Genesee 3 no longer being owned by the company. In 2020, both Centralia units were taken out of service in February and March as a result of seasonally lower prices in the Pacific Northwest, whereas in 2019 both units remained in service into April due to higher prices in the Pacific Northwest. In 2020, Genesee 3 was not included due to a 2019 ownership swap, resulting in the Company no longer owning a portion of the facility.

Adjusted EBITDA decreased by $52 million compared to 2019, primarily due to lower merchant production in Alberta due to unfavourable market conditions, a $42 million settlement related to the Sundance B and C PPAs in 2019, partially offset by dispatch optimization at Centralia in 2020 and from the increased cost of buybacks due to forced outages.

Mine reclamation spend decreased by $8 million for the Highvale mine and $4 million for the Centralia mine compared to 2019, mainly due to downsizing, an updated mine plan and the mine closure advancement for the Highvale Mine. In addition, due to COVID-19 in 2020, the mine reclamation spend was deferred to future years.

Sustaining capital expenditures for 2020 decreased by $47 million compared to 2019 mainly due to lower planned outage work performed in 2020 and lower mining equipment purchases and maintenance.

Energy Marketing

Year ended Dec. 31	2021		2020		2019
Revenues(1)		173		143		119
Operations, maintenance and administration		36		30		30
Adjusted EBITDA		137		113		89

(1) For details of the adjustments to revenues included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

2021

Adjusted EBITDA for 2021 increased by $24 million compared to 2020. Results were better primarily due to favourable short-term trading of both physical and financial power and natural gas products across all North American markets. This was partially offset by OM&A increases due to higher incentives related to stronger performance. The Energy Marketing team was able to capitalize on short-term market volatility in the markets in which we trade without materially changing the risk profile of the business unit.

SB-33

Management’s Discussion and Analysis

2020

Adjusted EBITDA for 2020 increased by $24 million compared to 2019. Results were primarily from continued strong performance in both power and natural gas markets. Gains were realized from short-term strategies across various geographic regions aided by market and price volatility. The Energy Marketing team was able to capitalize on short-term arbitrage opportunities in the markets in which we trade without materially changing the risk profile of the business unit. OM&A spending for 2020 and 2019 was similar.

Corporate

Year ended Dec. 31	2021				2020			2019
Operations, maintenance, and administration		84				80			73
Taxes, other than income taxes		1				1			1
Net other operating loss		—				—			2
Adjusted EBITDA		(85	)			(81	)		(76	)
Supplemental information:
Total sustaining capital		13				14			12
				��

2021

Adjusted EBITDA for the year ended Dec. 31, 2021, decreased by $4 million compared to 2020, primarily due to higher incentive payments, higher employee costs, higher insurance costs, and higher legal fees for settlement of outstanding legal issues, partially offset by the receipt of CEWS funding and realized gains from the total return swap. A portion of the settlement costs of our employee share-based payment plans is hedged by entering into total return swaps, which are cash settled every quarter. Excluding the impact of the total return swap, staffing costs increased due to additional headcount to support growth initiatives. As previously committed, the CEWS funding is being used to support incremental employment within the Company.

For the year ended Dec. 31, 2021, sustaining capital expenditures were consistent with 2020.

2020

Adjusted EBITDA for the year ended Dec. 31, 2020, decreased by $5 million compared to 2019, primarily due to realized gains and losses from the total return swap. A portion of the settlement cost of our employee share-based payment plans is fixed by entering into total return swaps, which are cash settled every quarter. Excluding the impact of the total return swap, Corporate overhead costs for 2020 decreased by $10 million compared to 2019, mainly due to lower legal fees, lower labour and reduced travel costs, partially offset by additional costs to support growth and development projects, centralization of shared services to the Corporate segment and additional costs incurred to support COVID-19 protocols.

For the year ended Dec. 31, 2020, sustaining capital expenditures were $2 million higher than 2019, mainly due to capital spend on information technology.

SB-34

Management’s Discussion and Analysis

Fourth Quarter Highlights

Consolidated Financial Highlights

Three months ended Dec. 31	2021			2020
Adjusted availability (%)		83.8			87.1
Production (GWh)		5,823			7,704
Revenues		610			544
Fuel and purchased power		272			282
Carbon compliance		39			45
Operations, maintenance and administration		124			118
Adjusted EBITDA(1)		270			234
Loss before income taxes		(32	)		(168	)
Net loss attributable to common shareholders		(78	)		(167	)
Cash flow from operating activities		54			110
FFO(1)		213			161
FCF(1)		106			52
Net earnings (loss) per share attributable to common shareholders, basic and diluted		(0.29	)		(0.61	)
Dividends declared per common share(2)		0.10			0.09
Dividends declared per preferred share(3)		0.25			0.50
FFO per share(1,4)		0.79			0.59
FCF per share(1,4)		0.39			0.19

(1) These items are not defined and have no standardized meaning under IFRS. Please refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(2) Dividends declared vary year over year due to timing of dividend declarations.

(3) 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.

(4) The weighted average number of common shares outstanding for the three months ended Dec. 31, 2021 was 271 million shares (2020 - 273 million shares).

Financial Highlights

During the fourth quarter of 2021, the Company completed the year with solid performance from our Alberta Electricity Portfolio. Hydro, Gas and the Energy Transition segments had high availability in Alberta during periods of peak pricing, which resulted from extreme cold weather and periods of province-wide planned and unplanned outages. The Alberta merchant portfolio was positioned to capture opportunities from these strong spot market conditions through both energy and ancillary services revenues.

Adjusted availability for the three months ended Dec. 31, 2021, was 83.8 per cent compared to 87.1 per cent for the same period in 2020. Higher unplanned outages at our Wind and Solar segment and Energy Transition segment were partially offset by lower unplanned and planned outages at our Hydro segment. Wind and Solar availability was impacted by the unplanned outages at Kent Hills 1 and 2 wind facilities. Energy Transition availability was impacted by unplanned outages in our Centralia Unit 2 facility and dispatch optimization in Alberta.

SB-35

Management’s Discussion and Analysis

Production for the three months ended Dec. 31, 2021, was 5,823 GWh compared to 7,704 GWh for the same period in 2020. The decrease in production for the three-month period in 2021 was due to the planned retirement of Centralia Unit 1 and unplanned outage at Centralia Unit 2, lower availability, the outage at the Kent Hills 1 and 2 wind facilities, and lower wind resources in the Wind and Solar segment. This decrease in production was partially offset by incremental production at our North Carolina Solar facility, the Windrise and Skookumchuck wind facilities in the Wind and Solar segment, and higher production at our Ada and Sarnia facilities within our Gas segment.

Revenues for the three months ended Dec. 31, 2021, increased $66 million compared to the same period in 2020, mainly as a result of capturing higher realized prices within the Alberta market through our optimization and operating activities and the elimination of the net payment obligations under the Alberta Hydro PPA required in the prior period. Revenues further increased due to the addition of the North Carolina Solar facility and commercial operation of the Windrise wind facility in the Wind and Solar segment, in addition to increased revenue from the Ada facility within the Gas segment. These increases were partially offset by lower production in the Energy Transition, Hydro and Wind and Solar segments.

Fuel and purchased power costs decreased by $10 million in the three months ended Dec. 31, 2021, compared to the same period in 2020. In our Energy Transition segment, our costs increased compared to 2020 due to higher fuel transportation costs and the acquisition of higher-priced power to fulfil our contractual obligations during planned and unplanned outages during periods of higher merchant pricing at the Centralia facility and higher natural gas pricing within the Gas segment. This was partially offset by lower coal mine depreciation and coal inventory write-downs at the Highvale mine in the fourth quarter of 2021.

Carbon compliance costs decreased by $6 million in the three months ended Dec. 31, 2021, compared to the same period in 2020, due to reductions in GHG emissions stemming from changes in the fuel mix ratio as we operated more on natural gas and fired less with coal, partially offset by an increase in the carbon price per tonne.

OM&A expenses for the three months ended Dec. 31, 2021, increased by $6 million, compared to the same period in 2020, primarily due to increased staffing costs for growth and strategic initiatives and higher incentive costs.

Adjusted EBITDA for the three months ended Dec. 31, 2021, increased by $36 million compared with the same period in 2020, largely due to higher adjusted EBITDA in our Hydro and Gas segments, which was driven by higher realized prices in the Alberta market, partially offset by lower production at Centralia Unit 2 within our Energy Transition segment due to a transformer failure that has now been resolved and an unplanned outage at the Kent Hills 1 and 2 wind facilities.

Net loss attributable to common shareholders in the fourth quarter of 2021 was $78 million compared to net loss of $167 million in the same period of 2020, a decrease of $89 million. The net loss in 2021 was favourably impacted by lower depreciation and amortization expense related to asset retirements and impairments in our Gas and Energy Transition segments and higher adjusted EBITDA.

Cash flow from operating activities in the fourth quarter of 2021 decreased by $56 million compared with the same period in 2020, primarily due to changes in non-cash working capital.

FCF in the fourth quarter of 2021 was $106 million compared to $52 million in the same period of 2020, as a result of higher adjusted EBITDA due to higher realized prices in Alberta, settlement of provisions and lower sustaining capital expenditures, partially offset by higher distributions paid to subsidiaries’ non-controlling interests.

SB-36

Management’s Discussion and Analysis

Segmented Financial Performance and Operating Results for the Fourth Quarter

A summary of our adjusted EBITDA by segment and total loss before income taxes for the three months ended Dec. 31, 2021 and 2020 is as follows:

Three months ended Dec. 31	Adjusted EBITDA 2021			2020
Hydro		67			22
Wind and Solar		76			77
Gas(1)		110			92
Energy Transition(2)		37			42
Energy Marketing		9			23
Corporate and Other		(29	)		(22	)
Total adjusted EBITDA		270			234
Loss before income taxes		(32	)		(168	)

(1) Gas segment includes the segments previously known as Australian Gas and North American Gas and the coal generation assets converted to gas from the segment previously known as Alberta Thermal.

(2) Energy Transition segment includes the segment previously known as Centralia and the coal generation assets not converted to gas (including Sundance 4) and mining assets from the segment previously known as Alberta Thermal.

Adjusted EBITDA increased by $36 million for the fourth quarter of 2021, compared to 2020, primarily as a result of:

• Hydro results were $45 million higher due to increased revenues from higher merchant prices in Alberta. Effective Jan. 1, 2021, with the expiration of the PPA for the Alberta Hydro facilities, these facilities began operating on a merchant basis in the Alberta power market. This eliminated the net payment obligations under the Alberta PPA.

• Wind and Solar results were consistent compared to the prior period; results were impacted by the unplanned outage at the Kent Hills 1 and 2 wind facilities, which was partially offset by higher merchant pricing in Alberta and incremental value from newly commissioned or acquired assets such as the North Carolina Solar facility and the Windrise facility.

• Gas results were $18 million higher mainly due to higher merchant prices in Alberta and the South Hedland PPA contract settlement, partially offset by higher OM&A costs and legal fees.

• Energy Transition results were $5 million lower as a result of the retirement of Centralia Unit 1, unplanned outages at Centralia Unit 2 due to a transformer failure that has now been resolved, partially offset by dispatch optimization of Alberta assets.

• Energy Marketing results were in line with expectations, but lower than prior year by $14 million.

• Corporate costs were higher primarily due to higher incentive payments and higher staffing costs, partially offset by lower legal dispute settlement costs. Impacts from the total return swap on our share-based payment plans were higher in 2021 compared to 2020.

Selected Quarterly Information

Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are often incurred in the spring and fall when electricity prices are expected to be lower, as electricity prices

SB-37

Management’s Discussion and Analysis

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 Centralia. Typically, hydroelectric 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 2021			Q2 2021			Q3 2021			Q4 2021
Revenues		642			619			850			610
Adjusted EBITDA		310			302			381			270
Earnings (loss) before income taxes		21			72			(441	)		(32	)
Cash flow from operating activities		257			80			610			54
FFO		211			250			297			213
Net earnings (loss) attributable to common shareholders		(30	)		(12	)		(456	)		(78	)
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1)		(0.11	)		(0.04	)		(1.68	)		(0.29	)
	Q1 2020			Q2 2020			Q3 2020			Q4 2020
Revenues		606			437			514			544
Adjusted EBITDA		220			217			256			234
Earnings (loss) before income taxes		46			(52	)		(129	)		(168	)
Cash flow from operating activities		214			121			257			110
FFO		172			159			193			161
Net earnings (loss) attributable to common shareholders		27			(60	)		(136	)		(167	)
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1)		0.10			(0.22	)		(0.50	)		(0.61	)

(1) Basic and diluted earnings per share attributable to common shareholders and adjusted 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, adjusted EBITDA and FFO are generally higher in the first and fourth quarters due to higher demand associated with the cold winter months in the markets in which we operate and lower planned outages.

Net earnings (loss) attributable to common shareholders has also been impacted by the following variations and events:

• Acquisition of the North Carolina Solar facility in the fourth quarter of 2021;

• The unplanned outage at Kent Hills 1 and 2 wind facilities and Centralia Unit 2 in the fourth quarter of 2021;

• Sundance Unit 5 repowering was suspended in the third quarter of 2021 and retired during 2021;

• Gains relating to the sale of the Pioneer Pipeline in the second quarter of 2021 and gains on sale of Gas equipment in the third quarter of 2021;

• The unplanned outages at the Sarnia cogeneration facility in the second quarter of 2021;

• Alberta hydro facilities, Keephills Units 1 and 2 and Sheerness began operating on a merchant basis in the Alberta market effective Jan. 1, 2021;

SB-38

Management’s Discussion and Analysis

• Revenues declined due to weaker market conditions in 2020 as a result of the COVID-19 pandemic and low oil prices;

• Sundance Unit 3 was retired in the third quarter of 2020;

• Accelerated plans to shutdown the Highvale Mine resulted in remaining future royalty payments being recognized as an onerous contract in the third quarter of 2021;

• Sheerness going off-coal has resulted in the remaining coal supply payments on the existing coal supply agreement being recognized as an onerous contract in the fourth quarter of 2020;

• Accelerated shutdown of the Highvale Mine, increased mine depreciation included in the cost of coal. Coal inventory write-downs incurred in the first three quarters of 2021 and third and fourth quarters of 2020;

• Coal-related parts and materials inventory write-downs incurred in the second and third quarters of 2021;

• The impact of the updated provision estimates for the transmission line loss rule during the first quarter of 2021 and the last three quarters of 2020;

• Significant foreign exchange gains in the last three quarters of 2020, which more than offset foreign exchange losses experienced during the first quarter of 2020;

• The effects of impairments and reversals during all periods shown;

• The effects of changes in decommissioning and restoration provisions for retired assets in all periods shown;

• The effects of changes in useful lives of certain assets during the third quarter of 2020; and

• Current tax expense increases since the fourth quarter of 2020, mainly due to the Energy Marketing segment and certain Hydro operations becoming taxable, increased valuation allowances taken on US deferred tax assets along with a decreased deferred tax recovery mainly due to increased revenues in 2021.

Financial Position

The following table highlights significant changes in the consolidated statements of financial position from Dec. 31, 2020, to Dec. 31, 2021:

Assets	Dec. 31, 2021		Dec. 31, 2020		Increase/(decrease)
Current assets
Cash and cash equivalents		947		703		244
Trade and other receivables		651		583		68
Risk management assets		308		171		137
Inventory		167		238		(71	)
Assets held for sale		25		105		(80	)
Other current assets(1)		99		102		(3	)
Total current assets		2,197		1,902		295
Non-current assets
Risk management assets		399		521		(122	)
Property, plant and equipment, net		5,320		5,822		(502	)
Right-of-use assets		95		141		(46	)
Other non-current assets(2)		1,215		1,361		(146	)
Total non-current assets		7,029		7,845		(816	)
Total assets		9,226		9,747		(521	)

SB-39

Management’s Discussion and Analysis

Assets	Dec. 31, 2021		Dec. 31, 2020		Increase/(decrease)
Liabilities
Current liabilities
Credit facilities, long-term debt and lease liabilities (current)		844		105		739
Other current liabilities(3)		1,087		830		257
Total current liabilities		1,931		935		996
Non-current liabilities
Credit facilities, long-term debt and lease liabilities		2,423		3,256		(833	)
Decommissioning and other provisions (long-term)		779		614		165
Risk management liabilities (long-term)		145		68		77
Deferred income tax liabilities		354		396		(42	)
Other non-current liabilities(4)		1,001		1,042		(41	)
Total non-current liabilities		4,702		5,376		(674	)
Total liabilities		6,633		6,311		322
Equity
Equity attributable to shareholders		1,582		2,352		(770	)
Non-controlling interests		1,011		1,084		(73	)
Total equity		2,593		3,436		(843	)
Total liabilities and equity		9,226		9,747		(521	)

(1) Includes restricted cash and prepaid expenses.

(2) Includes investments, long-term portion of finance lease receivables, intangible assets, goodwill, deferred income tax assets and other assets.

(3) Includes accounts payable and accrued liabilities, current portion of decommissioning and other provisions, current portion of contract liabilities, income taxes payable and dividends payable.

(4) Includes exchangeable securities, contract liabilities and defined benefit obligation and other long-term liabilities.

Significant changes in TransAlta’s consolidated statements of financial position were as follows:

Working Capital

Including the current portion of long term debt and lease liabilities, the excess of current assets over current liabilities was $266 million as at Dec. 31, 2021 (2020 - $967 million). Our working capital decreased year over year mainly due to the reclassification of debt from long-term to current. Excluding the current portion of long-term debt and lease liabilities of $844 million, the excess of current assets over liabilities was $1,110 million as at Dec. 31, 2021 (2020 - $1,072 million), consistent with the previous year.

Current assets increased by $295 million to $2,197 million as at Dec. 31, 2021, from $1,902 million as at Dec. 31, 2020. Strong Alberta pricing has increased operating cash flow and receivables. In addition, a loan receivable

SB-40

Management’s Discussion and Analysis

relating to Kent Hills Wind LP of $55 million was reclassified as current as it matures in October 2022. This was partially offset by reductions in inventory of $71 million and in assets held for sale of $80 million. Inventory balances have declined with coal inventory write-downs and parts and material write-downs relating to the transition off of coal and the closure of the Highvale mine. Assets held for sale decreased with the closing of the Pioneer Pipeline sale during the year.

Current liabilities increased by $996 million from $935 million as at Dec. 31, 2020, to $1,931 million as at Dec. 31, 2021, mainly due to the reclassification to current of $510 million Senior Notes coming due in 2022 and the reclassification of the Kent Hills bond of $221 million as the KH Bonds may be in default at the end of the year. We currently expect to refinance the senior notes maturing in 2022. Management is in discussions with the Trustee and holders of the KH Bonds to negotiate waivers and amendments related to the KH Bonds.

Derivative financial instruments also contributed favourably to the working capital balance.

Non-Current Assets

Non-Current assets at Dec. 31, 2021 was $7,029 million, a decrease of $816 million from $7,845 million as at Dec. 31, 2020. The decrease was primarily due to the asset impairments that have occurred during the year. The Energy Transition segment recognized $345 million of asset impairment charges in the year as a result of the decision to suspend the Sundance Unit 5 repowering project and the planned retirements of Keephills Unit 1 and Sundance Unit 4. In addition, with the completion of the transition to gas of the Alberta coal fleet, the Highvale mine was removed from the Alberta Merchant CGU, which resulted in an impairment recognized on the remaining mine assets, further reducing the property, plant and equipment (“PP&E”) balance by $195 million. These impacts were partially offset by the construction of the Windrise wind facility and Garden Plain wind project, as well as the acquisition of the North Carolina Solar facility.

During 2021, the Company completed the sale of the Pioneer Pipeline to ATCO and derecognized the right- of-use asset of $43 million relating to the natural gas transportation agreement that was terminated as part of the transaction.

Non-Current Liabilities

Non-Current liabilities as at Dec. 31, 2021, are $4,702 million, a decrease of $674 million from $5,376 million as at Dec. 31, 2020, mainly due to a $833 million decrease in long-term debt and lease liabilities related in most part to the reclassification of the Senior Notes and KH Bonds to current liabilities, derecognition of the lease liability on the termination of the natural gas transportation agreement and from scheduled principal repayments on long-term debt and lease liabilities. This was partially offset by a $120 million increase in the wind decommissioning provisions resulting from a review of a recent wind engineering study on the decommissioning of the wind sites. The change in estimate is unrelated to the tower failure identified in the fourth quarter of 2021. In addition, the Company had a $47 million increase related to the Sundance and Keephills facilities to reflect a change in the timing of the expected reclamation work resulting from asset retirements and change in useful lives.

Total Equity

As at December 31, 2021, the decrease in total equity of $843 million was mainly due to the total comprehensive loss of $610 million, distributions to non-controlling interests of $156 million and dividends declared on common and preferred shares of $90 million, partially offset by the effect of shared-based payment plans of $13 million.

SB-41

Management’s Discussion and Analysis

Financial Capital

The Company is focused on maintaining a strong balance sheet and financial position to ensure access to sufficient financial capital. Credit ratings provide information relating to the Company’s financing costs, liquidity and operations and affect the Company’s ability to obtain short-term and long-term financing and/or the cost of such financing. Maintaining a strong balance sheet also allows the Company to enter into contracts with a variety of counterparties on terms and prices that are favourable to the Company’s financial results and provide TransAlta with better access to capital markets through commodity and credit cycles.

In 2021, Moody’s reaffirmed its Corporate Family Rating of Ba1 and maintained its rating outlook at stable. During 2021, DBRS Limited confirmed the Company’s Issuer Rating and Unsecured Debt/Medium-Term Notes rating of BBB (low), and the Company’s Preferred Shares rating of Pfd-3 (low), all with stable trends. During 2021, S&P Global Ratings reaffirmed the Company’s Issuer Credit Rating and Senior Unsecured Debt rating of BB+ with a stable outlook. Risks associated with our credit ratings are discussed in the Governance and Risk Management section of this MD&A.

Capital Structure

A strong financial position provides the Company with better access to capital markets through commodity and credit cycles. We use total capital to help evaluate the strength of our financial position.

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

As at Dec. 31	2021						2020						2019
	$			%			$			%			$			%
TransAlta Corporation
Net senior unsecured debt
Recourse debt — CAD debentures		251			4			249			3			647			9
Recourse debt — US senior notes		888			16			886			13			905			13
Credit facilities		—			—			114			2			—			—
Other		4			—			7			—			9			—
Less: cash and cash equivalents		(703	)		(12	)		(121	)		(2	)		(348	)		(5	)
Less: other cash and liquid assets(1)		(19	)		—			(13	)		—			(17	)		—
Net senior unsecured debt		421			8			1,122			16			1,196			17
Other debt liabilities
Exchangeable debentures		335			6			330			5			326			5
Non-recourse debt
TAPC Holdings LP bond		102			2			111			2			119			2
TransAlta OCP bond		263			5			284			4			305			4
Other		—			—			—			—			2			—
Lease liabilities		78			1			112			2			119			2
Total net debt — TransAlta Corporation		1,199			22			1,959			29			2,067			30

SB-42

Management’s Discussion and Analysis

As at Dec. 31	2021						2020						2019
	$			%			$			%			$			%
TransAlta Renewables
Net TransAlta Renewables reported debt
Credit facility		—			—			—			—			220			3
Non-recourse debt
Pingston bond		45			1			45			1			45			1
Melancthon Wolfe Wind bond		235			4			268			4			298			4
New Richmond Wind bond		120			2			127			2			134			2
Kent Hills Wind bond		221			4			230			3			241			3
Windrise Wind bond		171			3			—			—			—			—
Lease liabilities		22			—			22			—			23			—
Less: cash and cash equivalents		(244	)		(4	)		(582	)		(9	)		(63	)		(1	)
Debt on TransAlta Renewables Economic Investments
US tax equity financing(2)		135			2			134			2			145			2
South Hedland non-recourse debt(3)		732			13			772			11			—			—
Total net debt — TransAlta Renewables		1,437			25			1,016			14			1,043			14
Total consolidated net debt(4)(5)		2,636			47			2,975			43			3,110			44
Non-controlling interests		1,011			18			1,084			16			1,101			15
Exchangeable preferred securities(5)		400			7			400			6			—			—
Equity attributable to shareholders
Common shares		2,901			51			2,896			43			2,978			42
Preferred shares		942			17			942			14			942			13
Contributed surplus, deficit and accumulated other comprehensive income		(2,261	)		(40	)		(1,486	)		(22	)		(959	)		(14	)
Total capital		5,629			100			6,811			100			7,172			100

(1) Includes principal portion of TransAlta OCP restricted cash and fair value asset of hedging instruments on debt.

(2) TransAlta Renewables has an economic interest in the entities holding these debts.

(3) TransAlta Renewables has an economic interest in the Australia entities holding these debts.

(4) The tax equity financing for Skookumchuck, an equity accounted joint venture, is not represented in these amounts.

(5) In 2021, total consolidated net debt excludes the exchangeable preferred securities as they are considered equity with dividend payments for credit purposes. In 2020, 50 per cent of the exchangeable preferred securities were classified as debt and included in total consolidated net debt. 2020 has been revised to be consistent with the change in 2021. For accounting purposes, they are accounted for as debt with interest expense in the consolidated financial statements.

Total capital consists of long-term debt, exchangeable securities and equity, less:

• Available cash and cash equivalents, 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;

• The principal portion of restricted cash on TransAlta OCP bonds because this cash is restricted specifically to repay outstanding debt; and

SB-43

Management’s Discussion and Analysis

• The fair value of economic and designated hedging instruments on debt in an asset or liability, as the carrying value of the related debt is impacted by changes in foreign exchange rates.

We continued strengthening our financial position during 2021 and have sufficient liquidity to fund our growth strategy.

We have enhanced shareholder value through the following:

2021

• Obtained $173 million in project financing related to our Windrise wind facility.

2020

• Obtained AU$800 million in project financing related to our South Hedland facility;

• On Oct. 30, 2020, we received the second tranche of $400 million from Brookfield in consideration for redeemable, retractable first preferred shares;

• Redeemed our outstanding 5 per cent $400 million medium-term notes due on Nov. 25, 2020; and

• Purchased and cancelled 7,352,600 common shares at an average price of $8.33 per share through our NCIB program, for a total cost of $61 million.

2019

• Obtained US$126 million in tax equity financing to fund the Big Level and Antrim wind facilities;

• Entered into a strategic investment with Brookfield whereby Brookfield agreed to invest $750 million in the Company. On May 1, 2019, we received the initial tranche of $350 million in exchange for seven per cent unsecured subordinated debentures due May 1, 2039, which are exchangeable by Brookfield into an equity ownership interest in our Alberta Hydro Assets in the future; and

• Purchased and cancelled 7,716,300 common shares at an average price of $8.80 per share through our NCIB program, for a total cost of $68 million.

Between 2022 and 2024, we have $1,104 million of debt maturing, including $515 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments. We currently expect to refinance the senior notes maturing in 2022.

SB-44

Management’s Discussion and Analysis

Credit Facilities

The Company’s credit facilities are summarized in the table below:

As at Dec. 31, 2021	Facility size		Utilized				Available capacity		Maturity date
			Outstanding letters of credit(1)		Actual drawings
TransAlta Corporation
Committed syndicated bank facility(2)		1,250		618		—		632		Q2 2025
Canadian committed bilateral credit facilities		240		186		—		54		Q2 2023
TransAlta Renewables
Committed credit facility(2)		700		98		—		602		Q2 2025
Total		2,190		902		—		1,288

(1) TransAlta has 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, pension plan obligations, construction projects and purchase obligations. At Dec. 31, 2021, we provided cash collateral of $55 million.

(2) TransAlta has letters of credit of $157 million and TransAlta Renewables has letters of credit of $98 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities.

The US dollar relative to the Canadian dollar weakened from Dec. 31, 2020 to Dec. 31, 2021, with no impact on our long-term debt balances as at Dec. 31, 2021. The weakening of the US dollar decreased our long-term debt balances as at Dec. 31, 2020 by $24 million. Almost all our US-denominated debt is hedged either through financial contracts or net investments in our US operations.

US Tax Equity Financing

The Company owns equity interests in some facilities that are eligible for tax incentives available for renewable energy facilities in the United States. With its current portfolio of renewable energy facilities, TransAlta cannot fully monetize such tax incentives. To take full advantage of these incentives, the Company partners with Tax Equity Investors (“TEI”) who invest in these facilities in exchange for a share of the tax credits.

Some TEI financing structures include a partial pay as you go (“Pay-go”) funding arrangement under which, when the actual annual MWh production exceeds a certain production threshold, the TEI are obligated to make a cash contribution (“Pay-go Contribution”) to the Company. The Pay-go arrangement results in a lower initial investment by the TEI and provides them with some protection from potential underperformance of the asset.

TransAlta recognizes the TEI contributions as long-term debt, at an amount representing the proceeds received from the TEI in exchange for shares of a subsidiary of TransAlta, net of the following elements:

• Production tax credits (“PTC”) — Allocation of PTCs to the TEI derived from the power generated during the period is recognized in other revenues as earned and as a reduction in tax equity financing;

• Tax shield — Allocation of tax benefits and attributes to the TEI, such as investment tax credits and tax depreciation, is recognized in net interest expense as claimed and as a reduction in tax equity financing;

• Interest expense — Interest expense using the effective interest rate method is recognized in net interest expense as incurred and as an increase in tax equity financing;

SB-45

Management’s Discussion and Analysis

• Pay-go contributions — Additional cash contributions made by the TEI when the annual production exceeds the contractually determined threshold and is recognized as an increase in tax equity financing; and

• Cash distributions — Cash payments to the TEI, recognized as a reduction in tax equity financing.

Production Tax Credit Program

Current United States tax law allows qualified wind energy projects to receive tax credits that are earned for each MWh of generation during the first 10 years of the projects’ operation. The TEIs are allocated a portion of the renewable energy facility’s taxable income (losses) and PTCs produced and a portion of the cash generated by the facility until they achieve an agreed-upon after-tax investment return (“Flip Point”). After the Flip Point, the TEI will retain a lesser portion of the cash and the taxable income (losses) generated by the facility.

Facility	Commercial operation date		Expected Flip Point		Initial TEI investment ($)		Expected annual PTC generation ($)		Expected annual Pay-go Contribution ($)		TEI allocation of taxable income and PTCs (pre-Flip Point)			TEI allocation of cash distributions (pre-Flip Point) ($)
Lakeswind		2014		2029		45		4		—		99	%		22
Big Level and Antrim		2019		2030		126		9		—		99	%		58
Skookumchuck(1)		2020		2029 - 2030		121		10		—		99	%		29

(1) The Company has a 49 per cent interest in the Skookumchuck wind facility, which is treated as an equity investment under IFRS and our proportionate share of the net earnings is reflected as equity income on the statement of earnings under IFRS.

Non-Recourse Debt

The Melancthon Wolfe Wind LP, Pingston, TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd notes, Windrise Wind LP and TransAlta OCP LP non-recourse bonds with a carrying value of $1.9 billion (Dec. 31, 2020 — $1.8 billion) are subject to customary financing conditions and covenants that may restrict the Company’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 of 2021, except the Kent Hills non-recourse bond as discussed below. 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 2022. At Dec. 31, 2021, $67 million (Dec. 31, 2020 — $73 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.

In connection with the foundation issues at Kent Hills 1 and 2 wind facilities, Kent Hills Wind LP has provided notice to the Trustee, BNY Trust Company of Canada, for the approximately $221 million outstanding non-recourse KH Bonds secured by, among other things, the Kent Hills 1, 2 and 3 wind facilities, that events of default may have occurred under the trust indenture governing the terms of such bonds. The Company is in discussions with the Trustee and holders of the KH Bonds to negotiate waivers and amendments. Refer to the Significant and Subsequent Events section of this MD&A for further details on the Kent Hills 1 and 2 wind facilities outage.

SB-46

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	2021			2020			2019
Interest on debt		163			158			161
Interest on exchangeable debentures		29			29			20
Interest on exchangeable preferred shares		28			5			—
Interest income		(11	)		(10	)		(13	)
Capitalized interest		(14	)		(8	)		(6	)
Interest on lease liabilities		7			8			4
Credit facility fees, bank charges and other interest		18			18			15
Tax shield on tax equity financing(1)		(9	)		1			(35	)
Interest on the line loss proceeding		—			5			—
Other(2)		2			2			10
Accretion of provisions		32			30			23
Net interest expense		245			238			179

(1) Credit in 2021 primarily relates to the tax benefit associated with investment tax credits claimed in 2021 on the North Carolina Solar facility that was assigned to the tax equity investor. Credit in 2019 primarily relates to the tax benefit associated with bonus tax depreciation claimed in 2019 on the Big Level and Antrim wind facilities that was assigned to the tax equity investor. The tax equity investment is treated as debt under IFRS and the monetization of the tax depreciation and investment tax credits (as applicable) is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.

(2) In 2021, other interest expense included approximately nil (2020 — nil; 2019 — $5 million) for the significant financing component required under IFRS 15.

Net interest expense was higher in 2021 primarily due to the full year of interest incurred on the exchangeable preferred shares issued in the fourth quarter of 2020, project financing related to the South Hedland non-recourse debt obtained in the fourth quarter of 2020 and additional project financing related to the Windrise wind facility obtained in the fourth quarter of 2021, partially offset by an increase in capitalized interest on the construction of development projects, the redemption of the $400 million medium-term notes in the fourth quarter of 2020 and lower interest on other debt balances due to scheduled repayments and investment tax credits related to the North Carolina Solar facility tax equity.

Net interest expense was higher in 2020 primarily due to interest on the additional $400 million exchangeable preferred shares issued as part of the Brookfield Investment Agreement and the AU$800 million TEC Offering, both issued in October 2020. In addition, interest was higher due to interest charges received in 2020 for the AESO transmission line loss proceedings, and the 2019 impact of the $35 million tax credit received relating to the tax shield on Big Level and Antrim wind facilities offset by the termination of the Keephills 3 contract liability in 2019, resulting in the deferred financing costs being recognized.

Share Capital

On March 18, 2021, the Company announced that 1,417,338 of its 10.2 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares (“Series A Shares”) and 871,871 of its 1.8 million Series B Cumulative Redeemable Floating Rate Preferred Shares (“Series B Shares”) were tendered for conversion, on a one-for-one

SB-47

Management’s Discussion and Analysis

basis, into Series B Shares and Series A Shares, respectively, after having taken into account all election notices. As a result of the conversion, the Company had 9.6 million Series A Shares and 2.4 million Series B Shares issued and outstanding at March 31, 2021.

The following tables outline the common and preferred shares issued and outstanding:

As at	Feb. 23, 2022		Dec. 31, 2021		Dec. 31, 2020
	Number of shares (millions)
Common shares issued and outstanding, end of period		271.2		271.0		269.8
Preferred shares
Series A		9.6		9.6		10.2
Series B		2.4		2.4		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 in equity, end of period		38.6		38.6		38.6
Series I - Exchangeable Securities(1)		0.4		0.4		0.4
Preferred shares issued and outstanding, end of period		39.0		39.0		39.0

(1) Brookfield invested $400 million in consideration for redeemable, retractable, first preferred shares. For accounting purposes, these preferred share are considered debt and disclosed as such in the consolidated financial statements.

Dividends to Shareholders

The declaration of dividends is at the discretion of the Board. The following are the common and preferred shares dividends declared each quarter during 2021:

	Payable date				Common dividends per share		Preferred Series dividends per share
Declaration date	Common shares		Preferred shares				A		B		C		E		G
May 3, 2021		Jul 1, 2021		Jun 30, 2021		0.0450		0.17981		0.13108		0.25169		0.32463		0.31175
Aug 5, 2021		Oct.1, 2021		Sept. 30, 2021		0.0450		0.17981		0.13479		0.25169		0.32463		0.31175
Nov 1, 2021		Jan 1, 2022		Dec. 31. 2021		0.0500		0.17981		0.13970		0.25169		0.32463		0.31175
Dec 31, 2021		Apr 1, 2022		Mar 31, 2022		0.0500		0.17981		0.13309		0.25169		0.32463		0.31175

Non-Controlling Interests

As of Dec. 31, 2021, the Company owns 60.1 per cent (2020 — 60.1 per cent) of TransAlta Renewables.

In 2020, our ownership per cent (60.1 per cent) decreased from our ownership in 2019 (60.4 per cent) due to TransAlta Renewables issuing approximately one million common shares under their Dividend Reinvestment Plan (“DRIP”). We did not participate in this plan. In the fourth quarter of 2020, TransAlta Renewables suspended the DRIP in respect of any future declared dividends. The dividend paid on Oct. 30, 2020, to shareholders of record on Oct. 15, 2020, was the last dividend payment eligible for reinvestment by participating shareholders. Subsequent dividends will be paid only in cash.

SB-48

Management’s Discussion and Analysis

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 also own 50.01 per cent of TA Cogen, which owns, operates or has an interest in three natural-gas-fired facilities (Ottawa, Windsor and Fort Saskatchewan) and one dual-fuel generating facility (Sheerness) for 2021 which will operate as a natural-gas-fired facility in 2022. 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.

Reported earnings attributable to non-controlling interests for the year ended Dec. 31, 2021, increased by $78 million to $112 million compared to 2020. Earnings increased at TransAlta Renewables in 2021 mainly due to higher finance income from investments in subsidiaries of TransAlta and no fair value losses recognized in the current year, partially offset by liquidating damages provisions related to unplanned outages at Sarnia cogeneration facility, unfavourable steam reconciliation adjustment to Canadian Gas, lower wind production from the Canadian wind fleet, lower foreign exchange gains and higher asset impairments. Earnings from TA Cogen were higher in 2021 mainly due to higher prices in the Alberta market. Refer to Note 13 of the consolidated financial statements for further details.

Reported earnings attributable to non-controlling interests for the year ended Dec. 31, 2020, decreased by $60 million to $34 million compared to 2019. Earnings were down at TransAlta Renewables in 2020 mainly due to lower finance income and change in the fair value of financial assets and an increase in income tax expense, offset by higher operating income and an increase in foreign exchange gains resulting from the strengthening of the Australian dollar relative to the Canadian dollar. Earnings from TA Cogen were lower in 2020 mainly due to lower operating income as a result of the planned outage for the dual-fuel conversion at Sheerness Unit 2, low Alberta market demand and the onerous contract provision for the coal supply agreement.

Other Consolidated Analysis

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, pension plan obligations, construction projects and purchase obligations. At Dec. 31, 2021, we provided letters of credit totalling $902 million (2020 — $621 million) and cash collateral of $55 million (2020 — $49 million). These letters of credit and cash collateral secure certain amounts included on our Consolidated Statements of Financial Position under risk management liabilities, defined benefit obligation and other long-term liabilities, and decommissioning and other provisions. The increase in the amount of letters of credit issued during 2021 relates to the increased energy marketing activity, including the full requirements business, as well as pension plan commitments and the Highvale mine pension plan and reclamation obligations.

SB-49

Management’s Discussion and Analysis

Commitments

Contractual commitments are as follows:

	2022			2023		2024		2025		2026		2027 and thereafter		Total
Natural gas, transportation and other contracts		47			54		45		44		45		508		743
Transmission		9			9		6		6		2		—		32
Coal supply and mining agreements		76			98		90		75		—		—		339
Long-term service agreements		89			46		43		32		25		54		289
Operating leases(1)		4			3		3		1		1		31		43
Long-term debt(2)		836			155		113		127		127		1,840		3,198
Exchangeable securities(3)		—			—		—		750		—		—		750
Principal payments on lease liabilities(4)		(6	)		4		3		3		3		93		100
Interest on long-term debt and lease liabilities(5,6)		149			120		115		109		104		787		1,384
Interest on exchangeable securities(3,6)		53			53		62		—		—		—		168
Growth(7)		941			276		—		—		—		—		1,217
TransAlta Energy Transition Bill		6			6		—		—		—		—		12
Total		2,204			824		480		1,147		307		3,313		8,275

(1) Includes leases that have not yet commenced.

(2) Excludes impact of hedge accounting and derivatives.

(3) Assumes the exchangeable securities will be exchanged by Brookfield on Jan. 1, 2025. Please refer to the Significant and Subsequent Events section of this MD&A for further details.

(4) Lease liabilities include a lease incentive of $13 million, expected to be received in 2022.

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

(6) Not recognized as a financial liability on the Consolidated Statements of Financial Position.

(7) For further details on growth commitments, refer to the Accelerated Clean Electricity Growth Plan section of this MD&A.

Contingencies

Transmission Line Loss Rule Proceeding

The Company has been participating in a line loss rule proceeding before the AUC. The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed the AESO to recalculate loss factors for 2006 to 2016. The AUC approved an invoice settlement process and all three planned settlements have been received. The first two invoices were settled by the first quarter of 2021 and the third invoice settled in the second quarter of 2021. The true-up invoices issued by the AESO in the fourth quarter of 2021 were settled by Dec. 31, 2021, with no further invoices expected.

FMG Dispute at South Hedland Power Station

On May 2, 2021, the Company entered into a conditional settlement with FMG. The settlement was concluded and the actions were formally dismissed in the Supreme Court of Western Australia on Dec. 7, 2021. The settlement amount has been recorded as revenue in the fourth quarter of 2021, while all other balances previously provided for have been reversed. The settlement has resulted in FMG continuing as a customer of the South Hedland facility.

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Management’s Discussion and Analysis

Mangrove Claim

On April 23, 2019, Mangrove commenced an action in the Ontario Superior Court of Justice naming the Company, the incumbent members of the Board of the Company on such date, and Brookfield as defendants. Mangrove was seeking to set aside the 2019 Brookfield transaction. The parties reached a confidential settlement and the action was discontinued in the Ontario Superior Court of Justice on April 30, 2021.

Keephills 1 Stator Force Majeure Appeal

The Balancing Pool and ENMAX are seeking to set aside an arbitration award on the basis that they did not receive a fair hearing. The Alberta Court of Queen’s Bench (“ABQB”) dismissed the Balancing Pool and ENMAX’s allegations of unfairness on June 26, 2019. The Balancing Pool and ENMAX, however, sought leave to appeal the ABQB’s decision at the Court of Appeal, which was granted on Feb. 13, 2020. The appeal was heard on July 8, 2021. After the hearing, counsel for ENMAX raised concerns that one of the three justices on the appeal panel was distracted during the hearing. The justice has since recused herself from the hearing and the parties made submissions with respect to whether the remaining two justices can continue to issue the decision or whether a new hearing is required. On Nov. 8, 2021, the Alberta Court of Appeal released its decision and ordered that the appeal be re-heard by a new three-person panel of the Court of Appeal, which was heard on Jan. 27, 2022. TransAlta remains of the view that the Court of Appeal will affirm the ABQB decision that the arbitration proceeding was fair.

Keephills 1 Superheater Force Majeure

Keephills Unit 1 was taken offline from March 17, 2015 to May 17, 2015, as a result of a large leak in the secondary superheater. TransAlta claimed force majeure under the Alberta PPA. ENMAX, the purchaser under the Alberta PPA at the time, did not dispute the force majeure but the Balancing Pool attempted to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The parties reached a confidential settlement on April 21, 2021, and this matter is now resolved.

Sundance A Decommissioning

TransAlta filed an application with the AUC seeking payment from the Balancing Pool for TransAlta’s decommissioning costs for Sundance A, including its proportionate share of the Highvale mine. The Balancing Pool and Utilities Consumer Advocate are participating as interveners because they take issue with the decommissioning costs claimed by TransAlta. Due to various factors, including the COVID-19 pandemic and significant information requests from the Balancing Pool, the application has been delayed. While a hearing date has not been set, the application will likely be heard in late 2022 or early 2023. TransAlta expects to receive payment from the Balancing Pool for its decommissioning costs; however, the amount that the AUC will award is uncertain.

Hydro Power Purchase Arrangement (“Hydro PPA”) Emission Performance Credits

The Balancing Pool claims to be entitled to emission performance credits (“EPCs”) earned by the Hydro facilities as a result of opting those facilities into the Carbon Competitiveness Incentive Regulation from 2018-2020 inclusive. The Balancing Pool claims ownership of the EPCs because it believes the change-in-law provisions under the Hydro PPA require the EPCs to be passed through to the Balancing Pool. TransAlta has not received any benefit from the EPCs or from any purported change in law and believes that the Balancing Pool has no rights to these credits. An arbitration has commenced, and the hearing is scheduled for Feb. 6-10, 2023.

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Management’s Discussion and Analysis

Direct Assigned Capital Deferral Account (“DACDA”) Application

AltaLink Management Ltd. (“AltaLink”) and TransAlta (as a secondary applicant) filed an application before the AUC to recover its 2016-2018 DACDA costs incurred for the 240 kV line upgrades for the Edmonton Region Project. The AUC disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta disputed this finding and filed a permission to appeal application with the Court of Appeal and a review and variance application with the AUC (the “R&V”). The AUC dismissed the R&V application on April 22, 2021. The permission to appeal was subsequently discontinued on July 5, 2021, which concludes this matter.

Sarnia Outages

The Sarnia cogeneration facility experienced three separate outages between May 19, 2021 and June 9, 2021 that resulted in steam interruptions to its industrial customers. As a result, the customers have submitted claims for liquidated damages. Steam supply disruptions of this nature are atypical and infrequent at the Sarnia cogeneration facility. The Company conducted an investigation to determine the root cause of each of the three events, which concluded that all three events do not qualify as events of force majeure. As such, liquidated damages in an amount dictated by the applicable agreements are payable by TransAlta to the customers for the three outages and have been accrued within contract liabilities.

Kaybob 3 Cogeneration Dispute

The Company is engaged in a dispute with Energy Transfer Canada ULC, formerly SemCAMS Midstream ULC (“ET Canada”) as a result of ET Canada’s purported termination of agreements between the parties to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing facility. TransAlta commenced an arbitration seeking full compensation for ET Canada’s wrongful termination of the agreements. ET Canada seeks a declaration that the agreements were lawfully terminated. A hearing is scheduled for two weeks starting Jan. 9, 2023.

Cash Flows

The following chart highlights significant changes in the consolidated statements of cash flows for the years ended Dec. 31, 2021, Dec. 31, 2020 and Dec. 31, 2019:

Year ended Dec. 31	2021			2020			Increase/ (decrease)
Cash and cash equivalents, beginning of year		703			411			292
Provided by (used in):
Operating activities		1,001			702			299
Investing activities		(472	)		(687	)		215
Financing activities		(282	)		272			(554	)
Translation of foreign currency cash		(3	)		5			(8	)
Cash and cash equivalents, end of year		947			703			244

Cash provided by operating activities for the year ended Dec. 31, 2021, increased compared with 2020 primarily due to to higher revenues being realized in Alberta on the merchant assets, partially offset by higher fuel and purchased power and OM&A costs as the Company transitions off coal.

Cash used in investing activities for the year ended Dec. 31, 2021, decreased compared with 2020, largely due to:

• No acquisitions of investments in 2021 compared to Skookumchuck and EMG International LLC (“EMG”) in 2020 ($102 million);

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Management’s Discussion and Analysis

• Proceeds on the sale of Pioneer Pipeline ($128 million) and the sale of equipment within the Energy Transition segment ($39 million); and

• Higher cash spent on the North Carolina Solar facility acquisition ($120 million) in 2021 compared to the Ada acquisition of ($32 million) in 2020.

Cash used in financing activities for the year ended Dec. 31, 2021, increased compared with 2020, largely due to:

• Lower debt issuances in 2021. Issuance of the Windrise Wind LP bond of $173 million in 2021 compared to $753 million in long-term debt from the TEC Offering and $400 million in exchangeable securities in 2020;

• Increased distributions paid to subsidiaries’ non-controlling interests ($59 million);

• Partially offset by lower repayments on long term debt ($397 million); and

• Lower common share repurchases under the NCIB ($53 million).

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 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.

SB-53

Management’s Discussion and Analysis

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 earnings (“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.

Hedge accounting follows a principles-based approach for qualifying hedges that is aligned with an entity’s approach to risk management. 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 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

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Management’s Discussion and Analysis

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, 2021, Level III instruments had a net asset carrying value of $159 million (2020 — $582 million). Please 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, 2020.

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, 2021, 2020 and 2019. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.

We use a number of financial measures to evaluate our performance and the performance of our business segments, including measures and ratios that are presented on a non-IFRS basis, as described below. Unless otherwise indicated, all amounts are in Canadian dollars and have been derived from our audited annual consolidated financial statements prepared in accordance with IFRS. We believe that these non-IFRS amounts, measures and ratios, read together with our IFRS amounts, provide readers with a better understanding of how management assesses results.

Non-IFRS amounts, measures and ratios do not have standardized meanings under IFRS. They are unlikely to be comparable to similar measures presented by other companies and should not be viewed in isolation from, or as an alternative for, or more meaningful than our IFRS results.

Non-IFRS Financial Measures

Adjusted EBITDA, FFO, FCF, total net debt, total consolidated net debt and adjusted net debt are non-IFRS measures that are presented in this MD&A. See the Segmented Financial Performance and Operating Results, Segmented Financial Performance and Operating Results for the Fourth Quarter, Selected Quarterly Information, Financial Capital and Key Non-IFRS Financial Ratios sections of this MD&A for additional information, including a reconciliation of such non-IFRS measures to the most comparable IFRS measure.

Adjusted EBITDA

In the fourth quarter of 2021, comparable EBITDA was relabelled as adjusted EBITDA to align with industry standard terminology. Each business segment assumes responsibility for its operating results measured to adjusted EBITDA. Adjusted EBITDA is an important metric for management that represents our core business profitability. Interest, taxes, depreciation and amortization are not included, as differences in accounting treatments may distort our core business results. In addition, certain reclassifications and adjustments are made to better assess results excluding those items that may not be reflective of ongoing business performance. This presentation may facilitate the readers analysis of trends. Adjusted EBITDA is a non-IFRS measure. The following are descriptions of the adjustments made.

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Management’s Discussion and Analysis

Adjustments to revenue

• Certain assets we own in Canada and 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.

• Adjusted EBITDA is adjusted to exclude the impact of unrealized mark-to-market gains or losses and unrealized foreign exchange gains or losses on commodity transactions.

Adjustments to fuel and purchased power

• We adjust for depreciation on our mining equipment included in fuel and purchased power.

• We adjust for items resulting from the decision in 2020 to accelerate being off-coal and accelerating the shutdown of the Highvale mine by the end of 2021 as not reflective of ongoing business performance. Within fuel and purchased power this included coal inventory write-downs.

• On the commissioning of the South Hedland facility 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.

Adjustments to operations, maintenance and administration

• We adjust for write-down of parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities.

• We adjust for the curtailment gain related to the Highvale mine defined-benefit pension plan.

Adjustments to net other operating income (expense)

• We adjust for the onerous contract provision for future royalty payments recognized with the shutdown of the Highvale mine.

• We adjust for the Sheerness going off-coal which resulted in the remaining coal supply payments on the existing coal supply agreement being recognized as an onerous contract in the fourth quarter of 2020.

Adjustments to earnings in addition to interest, taxes, depreciation and amortization

• Asset impairment charges (reversals) are removed as these are accounting adjustments that impact depreciation and amortization and do not reflect business performance.

• Any gains or losses on asset sales or foreign exchange gains or losses are not included as these are not part of operating income.

Adjustments for equity accounted investments

• During the fourth quarter of 2020, we acquired a 49 per cent interest in the Skookumchuck wind facility, which is treated as an equity investment under IFRS and our proportionate share of the net earnings is reflected as equity income on the statement of earnings under IFRS. As this investment is

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Management’s Discussion and Analysis

part of our regular power-generating operations, we have included our proportionate share of the adjusted EBITDA of Skookumchuck in our total adjusted EBITDA. In addition, in the Wind and Solar adjusted results, we have included our proportionate share of revenues and expenses to reflect the full operational results of this investment. We have not included EMG’s adjusted EBITDA in our total adjusted EBITDA as it does not represent our regular power-generating operations.

Average Annual EBITDA

Average annual EBITDA is a non-IFRS financial measure that is forward-looking, used to show the average annual EBITDA that the project currently under construction is expected to generate upon completion.

Funds From Operations (“FFO”)

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. FFO is a non-IFRS measure.

Adjustments to cash from operations

• Includes FFO related to the Skookumchuk wind facility, which is treated as an equity accounted investment under IFRS and equity income, net of distributions from joint ventures is included in cash flow from operations under IFRS. As this investment is part of our regular power generating operations, we have included our proportionate share of FFO.

• Payments received on finance lease receivables reclassified to reflect cash from operations.

• We adjust for items included in cash from operations related to the decision in 2020 to accelerate being off-coal and accelerating the shutdown of the Highvale mine by the end of 2021, and the write-down on parts and material inventory for our coal operations (“Clean energy transition provisions and adjustments”).

Free Cash Flow

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. FCF is a non-IFRS measure.

Non-IFRS Ratios

FFO per share, FCF per share, FFO before interest to adjusted interest coverage and adjusted net debt to adjusted EBITDA are non-IFRS ratios that are presented in the MD&A. See the Reconciliation of Cash Flow from Operations to FFO and FCF and Key Non-IFRS Financial Ratios sections of this MD&A for additional information.

FFO per Share and FCF per Share

FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period. FFO per share and FCF per share is a non-IFRS ratio.

SB-57

Management’s Discussion and Analysis

Supplementary Financial Measures

Financial highlights presented on a proportional basis of TransAlta Renewables, deconsolidated adjusted EBITDA, deconsolidated FFO and deconsolidated adjusted EBITDA to deconsolidated FFO are supplementary financial measures the Company uses to present adjusted EBITDA on a deconsolidated basis. See the Financial Highlights on a Proportional Basis of TransAlta Renewables and Key Non-IFRS Financial Ratios sections of this MD&A for additional information.

The Alberta Electricity Portfolio metrics disclosed are also supplementary financial measures used to present the gross margin by segment for the Alberta market. See the Alberta Electricity Portfolio section of this MD&A for additional information.

Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment

The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings (loss) before income taxes for the three months ended Dec. 31, 2021:

	Attributable to common shareholders
	Hydro		Wind & Solar(1)		Gas			Energy Transition			Energy Marketing			Corporate			Total			Equity accounted investments(1)			Reclass adjustments			IFRS financials
Revenues		84		98		172			238			26			(2	)		616			(6	)		—			610
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		3		82			(8	)		(12	)		—			65			—			(65	)		—
Decrease in finance lease receivable		—		—		11			—			—			—			11			—			(11	)		—
Finance lease income		—		—		6			—			—			—			6			—			(6	)		—
Unrealized foreign exchange (gain) loss on commodity		—		—		—			—			—			—			—			—			—			—
Adjusted revenues		84		101		271			230			14			(2	)		698			(6	)		(82	)		610
Fuel and purchased power		9		6		110			149			—			(2	)		272			—			—			272
Reclassifications and adjustments:
Australian interest income		—		—		(1	)		—			—			—			(1	)		—			1			—
Mine depreciation		—		—		—			(11	)		—			—			(11	)		—			11			—
Coal Inventory write-down		—		—		—			(1	)		—			—			(1	)		—			1			—
Adjusted fuel and purchased power		9		6		109			137			—			(2	)		259			—			13			272
Carbon compliance		—		—		14			25			—			—			39			—			—			39
Gross margin		75		95		148			68			14			—			400			(6	)		(95	)		299
OM&A		7		17		46			20			5			29			124			—			—			124

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Management’s Discussion and Analysis

	Attributable to common shareholders
	Hydro		Wind & Solar(1)		Gas			Energy Transition			Energy Marketing		Corporate			Total			Equity accounted investments(1)		Reclass adjustments			IFRS financials
Reclassifications and adjustments:
Parts and materials write-down		—		—		—			3			—		—			3			—		(3	)		—
Curtailment gain		—		—		—			6			—		—			6			—		(6	)		—
Adjusted OM&A		7		17		46			29			5		29			133			—		(9	)		124
Taxes, other than income taxes		1		2		2			1			—		—			6			—		—			6
Net other operating income		—		—		(10	)		(8	)		—		—			(18	)		—		—			(18	)
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties		—		—		—			9			—		—			9			—		(9	)		—
Adjusted net other operating income		—		—		(10	)		1			—		—			(9	)		—		(9	)		(18	)
Adjusted EBITDA		67		76		110			37			9		(29	)		270
Equity income																									4
Finance income from subsidiaries																									6
Depreciation and amortization																									(134	)
Asset impairment																									(28	)
Net interest expense																									(59	)
Foreign exchange loss																									(6	)
Gain on sale of assets and other																									(2	)
Loss before income taxes																									(32	)

(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. Includes reclassification adjustments.

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Management’s Discussion and Analysis

The following table reflects Adjusted EBITDA by segment and provides reconciliation to earnings (loss) before income taxes for the three months ended Dec. 31, 2020:

	Attributable to common shareholders
	Hydro			Wind & Solar(1)		Gas			Energy Transition			Energy Marketing		Corporate		Total			Equity accounted investments(1)			Reclass adjustments			IFRS financials
Revenues		31			92		167			230			19		8		547			(3	)		—			544
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—			10		34			(10	)		10		—		44			—			(44	)		—
Decrease in finance lease receivable		—			—		6			—			—		—		6			—			(6	)		—
Finance lease income		—			—		3			—			—		—		3			—			(3	)		—
Unrealized foreign exchange (gain) loss on commodity		—			—		4			—			—		—		4			—			(4	)		—
Adjusted revenues		31			102		214			220			29		8		604			(3	)		(57	)		544
Fuel and purchased power		(1	)		11		98			166			—		8		282			—			—			282
Reclassifications and adjustments:
Australian interest income		—			—		(1	)		—			—		—		(1	)		—			1			—
Mine depreciation		—			—		(40	)		(18	)		—		—		(58	)		—			58			—
Coal inventory write-down		—			—		—			(15	)		—		—		(15	)		—			15			—
Adjusted fuel and purchased power		(1	)		11		57			133			—		8		208			—			74			282
Carbon compliance		—			—		30			15			—		—		45			—			—			45
Gross margin		32			91		127			72			29		—		351			(3	)		(131	)		217
OM&A		9			13		42			27			6		21		118			—			—			118
Taxes, other than income taxes		1			1		2			3			—		1		8			—			—			8
Net other operating expense (income)		—			—		19			—			—		—		19			—			—			19
Reclassifications and adjustments:
Impact of Sheerness going off-coal		—			—		(28	)		—			—		—		(28	)		—			28			—
Adjusted net other operating income		—			—		(9	)		—			—		—		(9	)		—			28			19

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Management’s Discussion and Analysis

	Attributable to common shareholders
	Hydro		Wind & Solar(1)		Gas		Energy Transition		Energy Marketing		Corporate			Total		Equity accounted investments(1)	Reclass adjustments	IFRS financials
Adjusted EBITDA		22		77		92		42		23		(22	)		234
Equity income																			1
Finance income from subsidiaries																			4
Depreciation and amortization																			(173	)
Asset impairment																			(17	)
Net interest expense																			(64	)
Foreign exchange loss																			2
Gain on sale of assets and other																			7
Loss before income taxes																			(168	)

(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. Includes reclassification adjustments.

Reconciliation of Cash flow from operations to FFO and FCF

The table below reconciles our cash flow from operating activities to our FFO and FCF for the three months ended Dec. 31, 2021 and 2020:

Three months ended Dec. 31	2021			2020
Cash flow from operating activities(1)		54			110
Change in non-cash operating working capital balances		148			25
Cash flow from operations before changes in working capital		202			135
Adjustments
Share of adjusted FFO from joint venture(1)		6			3
Decrease in finance lease receivable		11			6
Clean energy transition provisions and adjustments(2)		(6	)		15
Other(3)		—			2
FFO(4)		213			161
Deduct:
Sustaining capital(1)		(55	)		(58	)
Productivity capital		(2	)		(3	)
Dividends paid on preferred shares		(10	)		(9	)
Distributions paid to subsidiaries’ non-controlling interests		(38	)		(29	)
Principal payments on lease liabilities(1)		(2	)		(10	)
FCF(4)		106			52
Weighted average number of common shares outstanding in the period		271			273
FFO per share(4)		0.79			0.59
FCF per share(4)		0.39			0.19

(1) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.

SB-61

Management’s Discussion and Analysis

(2) Includes write-down on parts and material inventory for our coal operations, write-down on coal inventory to net realizable value and amounts due to contractors for not proceeding with the Sundance Unit 5 repowering project.

(3) Other consists of production tax credits which is a reduction to tax equity debt.

(4) These items are not defined and have no standardized meaning under IFRS. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

The table below provides a reconciliation of our adjusted EBITDA to our FFO and FCF for the three months ended Dec. 31, 2021 and 2020:

Three months ended Dec. 31	2021			2020
Adjusted EBITDA(1)		270			234
Provisions		(18	)		(10	)
Interest expense(2)		(51	)		(56	)
Current income tax expense(2)		3			5
Realized foreign exchange loss		(4	)		(1	)
Decommissioning and restoration costs settled(2)		(5	)		(5	)
Other non-cash items		18			(6	)
FFO(3)		213			161
Deduct:
Sustaining capital(2)		(55	)		(58	)
Productivity capital		(2	)		(3	)
Dividends paid on preferred shares		(10	)		(9	)
Distributions paid to subsidiaries’ non-controlling interests		(38	)		(29	)
Principal payments on lease liabilities(2)		(2	)		(10	)
FCF(3)		106			52

(1) Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to earnings (loss) before income taxes above.

(2) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.

(3) FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to cash flow from operating activities above.

SB-62

Management’s Discussion and Analysis

Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment

The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings (loss) before income taxes for the year ended Dec. 31, 2021:

	Attributable to common shareholders
	Hydro		Wind & Solar(1)		Gas			Energy Transition			Energy Marketing			Corporate		Total			Equity accounted investments(1)			Reclass adjustments			IFRS financials
Revenues		383		323		1,109			709			211			4		2,739			(18	)		—			2,721
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		25		(40	)		19			(38	)		—		(34	)		—			34			—
Decrease in finance lease receivable		—		—		41			—			—			—		41			—			(41	)		—
Finance lease income		—		—		25			—			—			—		25			—			(25	)		—
Unrealized foreign exchange gain on commodity		—		—		(3	)		—			—			—		(3	)		—			3			—
Adjusted revenues		383		348		1,132			728			173			4		2,768			(18	)		(29	)		2,721
Fuel and purchased power		16		17		457			560			—			4		1,054			—			—			1,054
Reclassifications and adjustments:
Australian interest income		—		—		(4	)		—			—			—		(4	)		—			4			—
Mine depreciation		—		—		(79	)		(111	)		—			—		(190	)		—			190			—
Coal inventory write-down		—		—		—			(17	)		—			—		(17	)		—			17			—
Adjusted fuel and purchased power		16		17		374			432			—			4		843			—			211			1,054
Carbon compliance		—		—		118			60			—			—		178			—			—			178
Gross margin		367		331		640			236			173			—		1,747			(18	)		(240	)		1,489
OM&A		42		59		175			117			36			84		513			(2	)		—			511

SB-63

Management’s Discussion and Analysis

	Attributable to common shareholders
	Hydro		Wind & Solar(1)		Gas			Energy Transition			Energy Marketing		Corporate			Total			Equity accounted investments(1)			Reclass adjustments			IFRS financials
Reclassifications and adjustments:
Parts and materials write-down		—		—		(2	)		(26	)		—		—			(28	)		—			28			—
Curtailment gain		—		—		—			6			—		—			6			—			(6	)		—
Adjusted OM&A		42		59		173			97			36		84			491			(2	)		22			511
Taxes, other than income taxes		3		10		13			6			—		1			33			(1	)		—			32
Net other operating expense (income)		—		—		(40	)		48			—		—			8			—			—			8
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties		—		—		—			(48	)		—		—			(48	)		—			48			—
Adjusted net other operating income		—		—		(40	)		—			—		—			(40	)		—			48			8
Adjusted EBITDA		322		262		494			133			137		(85	)		1,263
Equity income from associate																										9
Finance lease income																										25
Depreciation and amortization																										(529	)
Asset impairment																										(648	)
Net interest expense																										(245	)
Foreign exchange gain																										16
Gain on sale of assets and other																										54
Loss before income taxes																										(380	)

(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment.

SB-64

Management’s Discussion and Analysis

Year ended Dec. 31, 2020	Attributable to common shareholders
	Hydro		Wind & Solar(1)		Gas			Energy Transition			Energy Marketing		Corporate			Total			Equity accounted investments(1)			Reclass adjustments			IFRS financials
Revenues		152		332		787			704			122		7			2,104			(3	)		—			2,101
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		2		33			(14	)		21		—			42			—			(42	)		—
Decrease in finance lease receivable		—		—		17			—			—		—			17			—			(17	)		—
Finance lease income		—		—		7			—			—		—			7			—			(7	)		—
Unrealized foreign exchange loss on commodity		—		—		4			—			—		—			4			—			(4	)		—
Adjusted revenues		152		334		848			690			143		7			2,174			(3	)		(70	)		2,101
Fuel and purchased power		8		25		325			435			—		12			805			—			—			805
Reclassifications and adjustments:
Australian interest income		—		—		(4	)		—			—		—			(4	)		—			4			—
Mine depreciation		—		—		(100	)		(46	)		—		—			(146	)		—			146			—
Coal inventory write-down		—		—		—			(37	)		—		—			(37	)		—			37			—
Adjusted fuel and purchased power		8		25		221			352			—		12			618			—			187			805
Carbon compliance		—		—		120			48			—		(5	)		163			—			—			163
Gross margin		144		309		507			290			143		—			1,393			(3	)		(257	)		1,133
OM&A		37		53		166			106			30		80			472			—			—			472
Taxes, other than income taxes		2		8		13			9			—		1			33			—			—			33
Net other operating expense (income)		—		—		(11	)		—			—		—			(11	)		—			—			(11	)
Reclassifications and adjustments:
Impact of Sheerness going off-coal		—		—		(28	)		—			—		—			(28	)		—			28			—
Adjusted net other operating income						(39	)		—			—		—			(39	)		—			28			(11	)
Adjusted EBITDA		105		248		367			175			113		(81	)		927

SB-65

Management’s Discussion and Analysis

Year ended Dec. 31, 2020

Attributable to common shareholders

Hydro

Wind & Solar(1)

Gas

Energy Transition

Energy Marketing

Corporate

Total

Equity accounted investments(1)

Reclass adjustments

IFRS financials

Equity income from associate

1

Finance lease income

7

Depreciation and amortization

(654

)

Asset impairment

(84

)

Net interest expense

(238

)

Foreign exchange loss

17

Gain on sale of assets and other

9

Loss before income taxes

(303

)

(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment.

Year ended Dec. 31, 2019	Attributable to common shareholders
	Hydro		Wind & Solar			Gas			Energy Transition			Energy Marketing			Corporate			Total			Reclass adjustments			IFRS financials
Revenues		156		312			851			905			129			(6	)		2,347			—			2,347
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		(17	)		6			(12	)		(10	)		—			(33	)		33			—
Decrease in finance lease receivable		—		—			24			—			—			—			24			(24	)		—
Finance lease income		—		—			6			—			—			—			6			(6	)		—
Adjusted revenues		156		295			887			893			119			(6	)		2,344			3			2,347
Fuel and purchased power		7		16			315			539			—			4			881			—			881
Reclassifications and adjustments:
Australian interest income		—		—			(4	)		—			—			—			(4	)		4			—
Mine depreciation		—		—			(81	)		(40	)		—			—			(121	)		121			—
Adjusted fuel and purchased power		7		16			230			499			—			4			756			125			881
Carbon compliance		—		—			138			77			—			(10	)		205			—			205
Gross margin		149		279			519			317			119			—			1,383			(122	)		1,261
OM&A		36		50			162			124			30			73			475			—			475
Taxes, other than income taxes		3		8			9			8			—			1			29			—			29
Net other operating expense (income)		—		(10	)		(41	)		—			—			2			(49	)		—			(49	)
Termination of Sundance B and C PPAs		—		—			(14	)		(42	)		—			—			(56	)		—			(56	)
Adjusted EBITDA		110		231			403			227			89			(76	)		984

SB-66

Management’s Discussion and Analysis

Year ended Dec. 31, 2019	Attributable to common shareholders
	Hydro	Wind & Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total	Reclass adjustments	IFRS financials
Finance lease income										6
Depreciation and amortization										(590	)
Asset impairment										(25	)
Gain on termination of Keephills 3 coal rights contract										88
Net interest expense										(179	)
Foreign exchange loss										(15	)
Gain on sale of assets and other										46
Earnings before income taxes										193

Reconciliation of Cash flow from operations to FFO and FCF

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

Year ended Dec. 31	2021			2020			2019
Cash flow from operating activities(1)(2)		1,001			702			849
Change in non-cash operating working capital balances		(174	)		(89	)		(121	)
Cash flow from operations before changes in working capital		827			613			728
Adjustments
Share of adjusted FFO from joint venture(2)		13			3			—
Decrease in finance lease receivable		41			17			24
Clean energy transition provisions and adjustments(3)		79			37			—
Other(4)		11			15			5
FFO(5)		971			685			757
Deduct:
Sustaining capital(2)		(199	)		(157	)		(141	)
Productivity capital		(4	)		(4	)		(9	)
Dividends paid on preferred shares		(39	)		(39	)		(40	)
Distributions paid to subsidiaries’ non-controlling interests		(159	)		(102	)		(111	)
Principal payments on lease liabilities(2)		(8	)		(25	)		(21	)
FCF(5)		562			358			435
Weighted average number of common shares outstanding in the year		271			275			283
FFO per share(5)		3.58			2.49			2.67
FCF per share(5)		2.07			1.30			1.54

(1) 2019 includes the PPA Termination Payments. See the Significant and Subsequent Events section for further details.

(2) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.

SB-67

Management’s Discussion and Analysis

(3) Includes write-down on parts and material inventory for our coal operations, write-down on coal inventory to net realizable value, amounts due to contractors for not proceeding with the Sundance Unit 5 repowering project and impairment of a previously recognized deferred asset, as it is no longer likely that we will incur sufficient capital or operating expenditures to utilize the remaining credit.

(4) Other consists of production tax credits which is a reduction to tax equity debt.

(5) These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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

Year ended Dec. 31	2021			2020			2019
Adjusted EBITDA(1)(2)		1,263			927			984
Provisions and other		(43	)		7			13
Interest expense(3)		(200	)		(192	)		(174	)
Current income tax expense(3)		(55	)		(35	)		(35	)
Realized foreign exchange gain (loss)		(2	)		8			(6	)
Decommissioning and restoration costs settled(3)		(18	)		(18	)		(34	)
Other cash and non-cash items(4)		26			(12	)		9
FFO(5)		971			685			757
Deduct:
Sustaining capital(3)		(199	)		(157	)		(141	)
Productivity capital		(4	)		(4	)		(9	)
Dividends paid on preferred shares		(39	)		(39	)		(40	)
Distributions paid to subsidiaries’ non-controlling interests		(159	)		(102	)		(111	)
Principal payments on lease liabilities(3)		(8	)		(25	)		(21	)
FCF(5)		562			358			435

(1) 2019 amounts include the PPA Termination Payments.

(2) Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to earnings (loss) before income taxes above.

(3) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.

(4) Other consists of production tax credits which is a reduction to tax equity debt.

(5) FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to cash flow from operating activities above.

For explanations for the current period, please refer to the Highlights section of this MD&A.

FCF decreased by $77 million in 2020 compared to 2019, primarily due to lower segmented cash flows for the Alberta Thermal facilities included in the Gas and Energy Transition segments and higher sustaining capital expenditures, partially offset by strong cash flows for the Centralia Unit in the Energy Transition segment and lower distributions paid to subsidiaries’ non controlling interests. There were no PPA Termination Payments included in 2020.

Financial Highlights on a Proportional Basis of TransAlta Renewables

The proportionate financial information below reflects TransAlta’s share of TransAlta Renewables relative to TransAlta’s total consolidated figures. The financial highlights presented on a proportional basis of TransAlta Renewables are supplementary financial measures to reflect TransAlta Renewables’ portion of the consolidated figures.

SB-68

Management’s Discussion and Analysis

Consolidated Results for the year ended Dec. 31

The following table reflects the generation and summary financial information on a consolidated basis for the year ended Dec. 31:

	Actual generation (GWh)									Adjusted EBITDA									Earnings (loss) before income taxes
	2021			2020			2019			2021			2020			2019			2021			2020			2019
TransAlta Renewables
Hydro		434			429			393			17			21			18
Wind and Solar(1)		3,898			4,042			3,355			248			256			238
Gas(1)		3,236			2,919			3,089			217			205			202
Corporate		—			—			—			(19	)		(20	)		(20	)
TransAlta Renewables before adjustments		7,568			7,390			6,837			463			462			438			133			188			232
Less: Proportion of TransAlta Renewables not owned by TransAlta Corporation		(3,020	)		(2,938	)		(2,694	)		(185	)		(182	)		(173	)		(53	)		(74	)		(91	)
Portion of TransAlta Renewables owned by TransAlta Corporation		4,548			4,452			4,143			278			280			265			80			114			141
Add: TransAlta Corporation’s owned assets excluding TransAlta Renewables
Hydro		1,502			1,703			1,652			305			84			92
Wind and Solar		—			27			—			14			(8	)		(7	)
Gas		7,329			7,861			8,730			277			162			201
Energy Transition		5,706			7,999			11,852			133			175			227
Energy Marketing		—			—			—			137			113			89
Corporate		—			—			—			(66	)		(61	)		(56	)
TransAlta Corporation with Proportionate Share of TransAlta Renewables		19,085			22,042			26,377			1,078			745			811			(433	)		(377	)		102
Non-controlling interests		3,020			2,938			2,694			185			182			173			53			74			91
TransAlta Consolidated		22,105			24,980			29,071			1,263			927			984			(380	)		(303	)		193

(1) Wind and Solar and Gas segments include those assets that TransAlta Renewables holds an economic interest in.

Key Non-IFRS 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 and have no standardized meaning under IFRS and may not be comparable to those used by other entities or by rating agencies. We maintained a strong and flexible financial position in 2021.

SB-69

Management’s Discussion and Analysis

Funds from Operations before Interest to Adjusted Interest Coverage

For the year ended Dec. 31	2021		2020		2019
FFO(1)		971		685		757
Less: PPA Termination Payments		—		—		(56	)
Add: Interest on debt, exchangeable securities and preferred shares and leases, net of interest income and capitalized interest(2)		202		182		166
FFO before interest		1,173		867		867
Interest on debt, exchangeable securities and leases, net of interest income(2)(3)		188		185		172
Add: 50 per cent of dividends paid on preferred shares(3)		33		22		20
Adjusted interest		221		207		192
FFO before interest to adjusted interest coverage (times)		5.3		4.2		4.5

(1) See the Segmented Financial Performance and Operating Results section in this MD&A for reconciliation of cash flow from operating activities to FFO. See also the Additional IFRS Measures and Non-IFRS Measures section for further details.

(2) The interest on tax equity financing for Skookumchuck, an equity accounted joint venture, is not represented in the amounts.

(3) Exchangeable preferred shares are considered equity with dividend payments for credit purposes. For accounting purposes, they are accounted for as debt with interest expense in the Consolidated Financial Statements.

The FFO before interest to adjusted interest coverage ratio is used by management to assess our ability to pay interest on outstanding debts. Our target for FFO before interest to adjusted interest coverage is 4.0 to 5.0 times. While 2020 and 2019 are within our target range, the 2021 ratio exceeds the high end of our target, and increased compared to 2020, mainly due to higher FFO in 2021 compared to 2020.

Adjusted Net Debt to Adjusted EBITDA (Excluding PPA Termination Payments)

As at Dec. 31	2021			2020			2019
Period-end long-term debt(1)		3,267			3,361			3,212
Exchangeable securities		335			330			326
Less: Cash and cash equivalents		(947	)		(703	)		(411	)
Add: 50 per cent of issued preferred shares and exchangeable preferred shares(2)		671			671			471
Other(3)		(19	)		(13	)		(17	)
Adjusted net debt(4)		3,307			3,646			3,581
Adjusted EBITDA(5)		1,263			927			984
Less: PPA Termination Payments(5)		—			—			(56	)
Adjusted EBITDA (excluding PPA Termination Payments)(5)		1,263			927			928
Adjusted net debt to adjusted EBITDA (excluding PPA Termination Payments) (times)		2.6			3.9			3.9

(1) Consists of current and long-term portion of debt, which includes lease liabilities and tax equity financing.

SB-70

Management’s Discussion and Analysis

(2) Exchangeable preferred shares are considered equity with dividend payments for credit-rating purposes. For accounting purposes, they are accounted for as debt with interest expense in the Consolidated Financial Statements. For purpose of this ratio, we consider 50% of issued preferred shares, including these, as debt.

(3) Includes principal portion of TransAlta OCP restricted cash and fair value of hedging instruments on debt (included in risk management assets and/or liabilities on the Consolidated Statements of Financial statements).

(4) The tax equity financing for Skookumchuck, an equity accounted joint venture, is not represented in the amounts. Adjusted net debt is not defined and has no standardized meaning 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. See the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(5) Last 12 months.

The Company’s capital is managed internally and evaluated by management using a net debt position. Our current and long-term debt is adjusted for 50 per cent of the exchangeable preferred shares plus 50 per cent of outstanding preferred shares less available cash and cash equivalents, principal portion of TransAlta OCP restricted cash and including fair value assets of hedging instruments on debt, to provide a more readily comparable debt figure from period to period. We use the adjusted net debt to adjusted EBITDA ratio as a measurement of financial leverage and assess our ability to pay off debt. Our target for adjusted net debt to adjusted EBITDA (excluding PPA Termination Payments) is 3.0 to 3.5 times. Our adjusted net debt to adjusted EBITDA ratio for 2021 was better than the low end of our target, and improved compared to 2020, as a result of strong adjusted EBITDA, debt repayments and higher cash and cash equivalents.

Deconsolidated Adjusted EBITDA by Segment

We invest in our assets directly as well as with joint venture partners. Deconsolidated financial information is a supplementary financial measure, and is not intended to be presented in accordance with IFRS.

Adjusted EBITDA is a key metric for TransAlta and TransAlta Renewables and provides management and shareholders a representation of core business profitability. Deconsolidated adjusted EBITDA is used in key planning and credit metrics and segment results highlight the operating performance of assets held directly at TransAlta that are comparable from period to period.

A reconciliation of adjusted EBITDA to deconsolidated adjusted EBITDA by segment results is set out below:

	2021								2020								2019
	TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated		TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated		TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated
Hydro		322			17					105			21					110			18
Wind and Solar		262			248					248			256					231			238
Gas		494			217					367			205					403			202
Energy Transition		133			—					175			—					227			—
Energy Marketing		137			—					113			—					89			—
Corporate		(85	)		(19	)				(81	)		(20	)				(76	)		(20	)
Adjusted EBITDA(1)		1,263			463			800		927			462			465		984			438			546

SB-71

Management’s Discussion and Analysis

	2021					2020					2019
	TransAlta Consolidated	TransAlta Renewables	TransAlta Deconsolidated			TransAlta Consolidated	TransAlta Renewables	TransAlta Deconsolidated			TransAlta Consolidated	TransAlta Renewables	TransAlta Deconsolidated
Less: TA Cogen adjusted EBITDA				(133	)				(54	)				(80	)
Less: Termination of Sundance B and C PPAs(1)				—					—					(56	)
Less: EBITDA from joint venture investments(2)				—					(3	)				—
Add: Dividend from TransAlta Renewables(1)				151					151					151
Add: Dividend from TA Cogen(1)				34					17					37
Deconsolidated TransAlta adjusted EBITDA				852					576					598

(1) Last 12 months.

(2) Represents our share of amounts for Skookumchuck, an equity accounted joint venture.

Deconsolidated FFO

The Company has set capital allocation targets based on deconsolidated FFO available to shareholders. Deconsolidated financial information is a supplementary financial measure and is not defined and has no standardized meaning under IFRS, and may not be comparable to those used by other entities or by rating agencies. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further details. Deconsolidated FFO for the years ended Dec. 31 is detailed below:

	2021							2020						2019
	TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated	TransAlta Consolidated			TransAlta Renewables		TransAlta Deconsolidated	TransAlta Consolidated			TransAlta Renewables		TransAlta Deconsolidated
Cash flow from operating activities		1,001			336				702			267			849			331
Change in non- cash operating working capital balances		(174	)		(13	)			(89	)		31			(121	)		23
Cash flow from operations before changes in working capital		827			323				613			298			728			308
Adjustments:
Decrease in finance lease receivable		41			—				17			—			24			—
Clean energy transition provisions and adjustments		79			—				37			—			—			—

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Management’s Discussion and Analysis

	2021								2020								2019
	TransAlta Consolidated		TransAlta Renewables			TransAlta Deconsolidated			TransAlta Consolidated		TransAlta Renewables			TransAlta Deconsolidated			TransAlta Consolidated		TransAlta Renewables			TransAlta Deconsolidated
Share of FFO from joint venture(1)		13		—						3		—						—		—
Finance income - economic interests		—		(108	)					—		(69	)					—		(76	)
FFO - economic interests(2)		—		191						—		180						—		153
Other(3)		11		—						15		—						5		—
FFO		971		406			565			685		409			276			757		385			372
Dividend from TransAlta Renewables							151								151								151
Distributions to TA Cogen’s Partner							(56	)							(17	)							(37	)
Less: Share of adjusted FFO from joint venture(1)							—								(3	)							—
Less: PPA Termination Payments							—								—								(56	)
Deconsolidated TransAlta FFO							660								407								430

(1) Represents our share of amounts for Skookumchuck, an equity accounted joint venture.

(2) FFO - economic interests calculated as Free Cash Flow economic interests plus sustaining capital expenditures economic interests plus/minus currency adjustment and in 2021 less distributions from equity accounted joint venture.

(3) Other consists of production tax credits, which is a reduction to tax equity debt and in 2021 less distributions from equity accounted joint venture.

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Management’s Discussion and Analysis

Deconsolidated Net Debt to Deconsolidated Adjusted EBITDA

In addition to reviewing fully consolidated ratios and results, management reviews net debt to adjusted EBITDA on a deconsolidated basis to highlight TransAlta’s financial flexibility, balance sheet strength and leverage. Deconsolidated financial information is a supplementary financial measure and is not defined under IFRS, and may not be comparable to those used by other entities or by rating agencies. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further details.

As at Dec. 31	2021			2020			2019
Adjusted net debt(1)		3,307			3,646			3,581
Add: TransAlta Renewables cash and cash equivalents		244			582			63
Less: TransAlta Renewables long-term debt		(814	)		(692	)		(961	)
Less: US tax equity financing and South Hedland debt(2)		(867	)		(906	)		(145	)
Deconsolidated net debt		1,870			2,630			2,538
Deconsolidated adjusted EBITDA(3)		852			576			598
Deconsolidated net debt to deconsolidated adjusted EBITDA(4) (times)		2.2			4.6			4.2

(1) Refer to the Adjusted Net Debt to Adjusted EBITDA (Excluding PPA Termination Payments) calculation under the Key Non-IFRS Financial Ratios section of this MD&A for the reconciliation and composition of adjusted net debt.

(2) Relates to assets where TransAlta Renewables has economic interests.

(3) Refer to the Deconsolidated Adjusted EBITDA by Segment section of this MD&A for the reconciliation and composition of deconsolidated adjusted EBITDA.

(4) The non-IFRS ratio is not a standardized financial measure under IFRS and might not be comparable to similar financial measures disclosed by other issuers.

Our target for deconsolidated net debt to deconsolidated adjusted EBITDA is 2.5 to 3.0 times. Our deconsolidated net debt to deconsolidated adjusted EBITDA ratio decreased compared with 2020, due to lower deconsolidated net debt which was partially offset by higher deconsolidated adjusted EBITDA. Lower deconsolidated net debt is a result of scheduled repayments on corporate debt and an increase in cash balances.

2022 Financial Outlook

The following table outlines our expectation on key financial targets and related assumptions for 2022 and should be read in conjunction with the narrative discussion that follows and the Governance and Risk Management section of this MD&A:

Measure	2022 Target	2021 Actuals
Adjusted EBITDA(1)	$1,065 million - $1,185 million	$1,263 million
FCF(1)	$455 million - $555 million	$562 million
Dividend	$0.20 per share annualized	$0.20 per share annualized

(1) These items are not defined and have no standardized meaning under IFRS. Please refer to the Reconciliation of Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS measures and Non-IFRS Measures section of this MD&A.

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Management’s Discussion and Analysis

Range of key power price assumptions

Market	2022 Assumption
Alberta Spot ($/MWh)	$80 - $90
Mid-C Spot (US$/MWh)	US$45 - US$55
AECO Gas Price ($/GJ)	$3.60
Other assumptions relevant to the 2022 financial outlook
Sustaining capital	$150 million - $170 million
Energy Marketing gross margin	$95 million - $115 million

Alberta Hedging

Range of hedging assumptions	2022
Hedged production (GWh)	6,278
Hedge Price ($/MWh)	$75
Hedged gas volumes (GJ)	50 million
Hedge gas prices ($/GJ)	$2.75

Adjusted EBITDA is estimated to be between $1.065 billion to $1.185 billion. FCF is expected to be between $455 million and $555 million and excludes the impact of rehabilitation capital expenditures required at Kent Hills 1 and 2 wind facilities. The midpoint of the range represents a 5 per cent decrease from the midpoint of the 2021 outlook largely driven by lower expectations on Alberta power pricing, a return to normal performance from Energy Marketing, and a step-up in mine reclamation expenditures, partially offset by the contribution from new assets, settlements of non-recurring provisions in 2021 and lower expected sustaining capital.

The Company expects its outlook for 2022 to be impacted by a number of factors detailed further below.

Market Pricing

For 2022, we see continuing strong merchant pricing levels in Alberta and the Pacific Northwest though at lowered target ranges for both regions. Lower year-over-year pricing in Alberta is expected to be driven by fewer planned outages and the expected additions of new wind and solar supply, including TransAlta’s new Windrise wind facility and Garden Plain wind facility, expected to achieve commercial operation in late 2022. Weather and demand are also major factors in actual settled prices. Lower year-over-year pricing in the Pacific Northwest will be impacted by natural gas prices and hydro generation resulting from actual weather and hydrology of the year. Ontario power prices for 2022 are expected to be higher than 2021 due to higher natural gas prices and additional nuclear refurbishment outages.

The objective of our portfolio management strategy in Alberta is to balance opportunity and risk, and to deliver optimization strategies that contribute to our total investment, which includes a return of and on invested capital. We can be more or less hedged in a given period and we expect to realize our annual targets through a combination of forward hedging and selling generation into the spot market. The Alberta assets are managed as a portfolio to maximize the overall value of generation and capacity from our hydro, wind and energy storage and thermal facilities. Financial hedging is a key component of cash flow certainty and the hedges are tied to the portfolio of assets rather than a single facility.

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Management’s Discussion and Analysis

Kent Hills Wind Facilities Outage

It is expected that the outage at Kent Hills 1 and 2 wind facilities will continue and rehabilitation efforts for all of the foundations is expected to commence during the second quarter of 2022 with the aim of fully returning the wind facilities to service by the end of 2023. The outage is expected to result in foregone revenue of approximately $3.4 million per month on an annualized basis so long as all 50 turbines at Kent Hills 1 and 2 wind facilities are offline, based on average historical wind production, with revenue expected to be earned as the wind turbines are returned to service.

Addition of Windrise and North Carolina Solar

On Nov. 5, 2021, TransAlta Renewables completed the acquisition of the economic interest in the fully contracted 122 MW North Carolina Solar portfolio, which is expected to generate an average annual EBITDA⁶ of approximately US$9 million.

On Dec. 2, 2021, TransAlta Renewables announced commercial operation of the Windrise wind facility in Alberta was achieved on Nov. 10, 2021. Windrise is expected to generate an average annual EBITDA⁶ of approximately $20 million to $22 million.

Fuel and Compliance Costs

For the Gas fleet, coal consumption in Alberta is expected to be zero in 2022 given TransAlta has now retired or fully converted all its coal-fired facilities to gas. Increased gas consumption in the Gas fleet will drive lower GHG emissions and the combined effect will result in lower total fuel and GHG costs for a given volume of power production. This will be partially offset by an increased carbon tax in Alberta.

In the Pacific Northwest of the US, the coal mine adjacent to our Centralia thermal facility is in the reclamation stage. Fuel at Centralia has been purchased from external suppliers in the Powder River Basin and delivered by rail. In 2020, we amended our fuel and rail contract such that our rail freight costs fluctuate partly with power prices. The delivered fuel cost in 2022 is expected to be marginally higher than 2021 costs.

Most of the generation from gas turbine-based power facilities 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

Adjusted EBITDA from our Energy Marketing segment is affected by prices and volatility in the market, overall strategies adopted and changes in regulation and legislation. Our outlook has been adjusted to reflect the exceptional performance achieved in 2021. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our 2022 objective for Energy Marketing is for the segment to contribute between $95 million to $115 million in gross margin for the year, which is consistent with normalized performance expectations.

⁶  Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

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Management’s Discussion and Analysis

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.

Decommissioning and Restoration Costs

Decommissioning and restoration costs are expected to be higher in 2022 due to the closure of the Highvale coal mine and increased reclamation activity at Centralia due to deferral of certain activities impacted by COVID-19.

Sustaining Capital Expenditures

The Company expects sustaining capital to be in the range of $150 million to $170 million. The midpoint for the range represents a 25 per cent decrease from the midpoint of the 2021 outlook. This is driven by fewer planned maintenance outages at the thermal fleet in Alberta due to the completion of gas conversions that occurred in 2021, partially offset by increased sustaining capital expenditures at the Sarnia cogeneration facility for planned major maintenance, as well as increased dam safety and major maintenance across our Hydro fleet. The Kent Hills foundation rehabilitation capital expenditure has been segregated from our sustaining capital range due to the extraordinary and rare nature of this expenditure. The initial estimated range for the rehabilitation at Kent Hills is between $75 million to $100 million with approximately $40 million to $60 million estimated to be incurred in 2022.

Our estimate for total sustaining capital is as follows:

	Spent in 2020		Spent in 2021		Expected spend in 2022
Total sustaining capital		157		199		150 - 170

Liquidity and Capital Resources

We expect to maintain adequate available liquidity under our committed credit facilities. We currently have access to $2.2 billion in liquidity, including $947 million in cash. We expect to be well positioned to refinance the upcoming debt maturity in 2022. The funds required for committed growth, sustaining capital and productivity projects are not expected to be significantly impacted by the current economic environment. Please refer to the Description of Business and Financial Capital sections of this MD&A for further details.

Net Interest Expense

Interest expense for 2022 is expected to be higher than in 2021 largely due to higher levels of debt. The increase in debt is mainly due to the $173 million Windrise project financing that was completed in November 2021. In addition, changes in interest rates on variable debt, and in the value of the Canadian dollar relative to the US and Australian dollars can affect the amount of interest expense incurred.

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

SB-77

Management’s Discussion and Analysis

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 material accounting policies are described in Note 2 of the consolidated financial statements. 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, Finance and Risk Committee (“AFRC”) and our independent auditors. The AFRC has reviewed and approved our disclosure relating to critical accounting estimates in this MD&A. These critical accounting estimates are described as follows:

Revenue Recognition

Revenue from Contracts with Customers

Identification of Performance Obligations

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

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

Allocation of Transaction Price to Performance Obligations

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 Company expects to be entitled to in exchange for transferring the good or service.

The Company’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

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Management’s Discussion and Analysis

obligations, the Company 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.

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 permits recognition of revenue at the invoiced amount, if that invoiced amount corresponds directly with the entity’s performance to date.

Revenue from Other Sources

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 that are used to earn revenues and to gain market information. These derivatives are accounted for using fair value accounting. 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.

Merchant Revenue

Revenues from non-contracted capacity (i.e., merchant) are comprised of energy payments, at market price, for each MWh produced and are recognized upon delivery.

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 Company 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. Refer to Note 15(B)(I) from our audited annual consolidated financial statements for further details on the inputs used for each level.

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Management’s Discussion and Analysis

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, 2021, is an estimated total upside of $105 million (2020 — $68 million upside) and total downside of $220 million (2020 — $94 million) impact to the carrying value of the financial instruments. Fair values are stressed for volumes and prices. The amount of $22 million upside (2020 — $35 million upside) and $145 million downside (2020 — $59 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$28 to US$51/MWh (Dec. 31, 2020 — US$24-US$32/MWh) for the period beyond the liquid period, 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.

In addition to the Level III fair value measurements discussed above, the Brookfield Investment Agreement allows Brookfield the option to exchange all of the outstanding exchangeable securities into an equity ownership interest of up to a maximum of 49 per cent in an entity formed to hold TransAlta’s Alberta Hydro Assets after Dec. 31, 2024. The fair value of the option to exchange is considered a Level III fair value measurement, with an estimated downside of $32 million (2020 — $33 million downside) potential impact to the carrying value of nil as at Dec. 31, 2021 (2020 — nil). The sensitivity analysis has been prepared using the Company’s assessment that a change in the implied discount rate of the future cash flow of one per cent is a reasonably possible change.

Valuation of PP&E and Associated Contracts

At the end of each reporting period, we assess whether there is any indication that PP&E and finite life intangible assets are impaired or whether a previously recognized impairment may no longer exist or may have decreased.

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 asset or CGU to which the asset 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, 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 facility operates, anticipated production levels, planned and unplanned outages, changes to regulations and transmission capacity or constraints for the remaining life of the facilities.

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.

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Management’s Discussion and Analysis

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 facilities 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 2021.

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. Please refer to the Financial Position 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.

For purposes of the 2021, 2020 and 2019 annual goodwill impairment reviews, the Company determined the recoverable amounts of the CGUs by calculating the fair value less costs of disposal using discounted cash flow projections based on the Company’s long-range forecasts for the period extending to the last planned asset retirement in 2072. The resulting fair value measurement is categorized within Level III of the fair value hierarchy.

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.

Project Development Costs

Project development costs include external, direct and incremental costs that are necessary for completing an acquisition or construction project. 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.

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Management’s Discussion and Analysis

Leases

In determining whether our contracts contain, or are, leases, management must use judgment in assessing whether the contract provides the customer with the right to substantially all of the economic benefits from the use of the asset during the lease term and whether the customer obtains the right to direct the use of the asset during the lease term. For those agreements considered to contain, or be, leases, further judgment is required to determine the lease term by assessing whether termination or extension options are reasonably certain to be exercised. Judgment is also applied in identifying in-substance fixed payments (included) and variable payments that are based on usage or performance factors (excluded) and in identifying lease and non-lease components (services that the supplier performs) of contracts and in allocating contract payments to lease and non-lease components.

For leases where we are a lessor, judgment is required to determine if substantially all of the significant risks and rewards of ownership are transferred to the customer or remain with us, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant and impact 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 amount of certain items of revenue and expense are dependent upon such classifications.

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 we operate. The process also involves making an estimate of taxes currently payable and income taxes expected to be payable or recoverable in future periods, referred to as deferred income taxes. 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.

Employee Future Benefits

We provide selected pension and other post-employment benefits to employees, such as health and dental benefits. The cost of providing these benefits is dependent upon many factors, including actual plan experience and estimates and assumptions about future experience.

The liabilities for pension, other post-employment 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

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Management’s Discussion and Analysis

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.

Decommissioning and Restoration Provisions

We recognize decommissioning and restoration provisions for generating facilities and mine sites in the period in which they are incurred if there is a legal or constructive obligation to remove the facilities and restore the 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 current market-based risk-free interest rate adjusted to reflect the market’s evaluation of our credit standing.

We estimate the undiscounted amount of cash flow required to settle the decommissioning and restoration provisions is approximately $1.6 billion, which will be incurred between 2022 and 2072. The majority of these costs will be incurred between 2025 and 2050.

Other Provisions

Where necessary, we recognize 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 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.

Classification of Joint Arrangements

Upon entering into a joint arrangement, the Company must classify it as either a joint operation or joint venture, and the classification affects the accounting for the joint arrangement. In making this classification, the Company exercises judgment in evaluating the terms and conditions of the arrangement to determine whether the parties have rights to the assets and obligations or rights to the net assets. Factors such as the legal structure, contractual arrangements and other facts and circumstances, such as where the purpose of the arrangement is primarily for the provision of the output to the parties and when the parties are substantially the only source of cash flows for the arrangement, must be evaluated to understand the rights of the parties to the arrangement.

Significant Influence

Upon entering into an investment, the Company must classify it as either an investment as an associate or an investment under IFRS 9. In making this classification, the Company exercises judgment in evaluating whether the Company has significant influence over the investee. Significant influence is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control over those policies. If the Company holds 20 per cent or more of the voting rights in the investee, it is presumed that the entity has significant influence, unless it can be clearly demonstrated that this is not the case. Other factors such as representation on the board of directors, participation in policy-making processes, material transactions between the Company and investee, interchange of managerial personnel or providing essential technical information are considered when assessing if the Company has significant influence over an investee.

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Management’s Discussion and Analysis

Accounting Changes

Current Accounting Changes

Amendments to IAS 1 Presentation of Financial Statements: Material Accounting Policies

Effective for the 2021 annual financial statements, the Company early adopted amendments to IAS 1 Presentation of Financial Statements in advance of its mandatory effective date of Jan. 1, 2023, which requires entities to disclose their material accounting policy information rather than their significant accounting policies. The Company has updated the accounting policies disclosed in Note 2 based on its assessment of the amended standard.

Amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use

Effective Jan. 1, 2021, the Company early adopted amendments to IAS 16 Property, plant and equipment (“IAS 16 Amendments”) in advance of its mandatory effective date of Jan. 1, 2022. The Company adopted the IAS 16 Amendments retroactively. No cumulative effect of initially applying the guidance arose. The IAS 16 Amendments prohibit deducting from the cost of an item of property, plant and equipment any proceeds from selling items produced while bringing that asset to the location and condition necessary for it to be capable of operating in a manner intended by management. Instead, an entity recognizes the proceeds from selling such items, and the cost of producing those items, in profit or loss. No adjustments resulted from early adopting the amendments.

IFRS 7 Financial Instruments: Disclosures — Interest Rate Benchmark Reform

The transition of the London Interbank Offered Rates (“LIBOR”) has begun with the cessation of the publication of one-week and two-month USD LIBOR occurring on Dec. 31, 2021. The remaining overnight, one-, three-, six-, and 12-month USD LIBOR will continue to be published until their cessation date on June 30, 2023. Existing financial instruments may continue to use USD LIBOR while they are published until they mature, however, new financial instruments will not be using USD LIBOR if entered into after Dec. 31, 2021. The IASB issued Interest Rate Benchmark Reform — Phase 2 in August 2020, which amends IFRS 9 Financial Instruments, IAS 39 Financial instruments: Recognition and Measurement, IFRS 7 Financial Instruments: Disclosures and IFRS 16 Leases. The amendments were effective Jan. 1, 2021, and were adopted by the Company on Jan. 1, 2021. There was no financial impact upon adoption.

The Company’s credit facilities references USD LIBOR for US-dollar drawings and the Canadian Dollar Offered Rate for Canadian drawings, and includes appropriate fallback language to replace these benchmark rates if a benchmark transition event were to occur. For the year ended Dec. 31, 2021, there were no drawings under the credit facilities. The Company has interest rate swap agreements in place with a notional amount of US$150 million referencing three-month LIBOR, expected to settle in the third quarter of 2022.

Future Accounting Changes

Amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets

On May 14, 2020, the IASB issued Onerous Contracts — Cost of Fulfilling a Contract and amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets to specify which costs to include when assessing whether a contract will be loss-making. The amendments are effective for annual periods beginning on or after Jan. 1, 2022, and will be adopted by the Company in 2022. The amendments are effective for contracts for which an entity has not yet fulfilled all its obligations on or after the effective date. No financial impact is expected upon adoption.

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Management’s Discussion and Analysis

Amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction

On May 7, 2021, the IASB issued amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction. The amendments clarify that the initial recognition exemption under IAS 12 does not apply to transactions such as leases and decommissioning obligations. These transactions give rise to equal and offsetting temporary differences in which deferred tax should be recognized.

The amendments are effective for annual periods beginning on or after Jan. 1, 2023, with early application permitted. The Company’s current position aligns with the amendment and no financial impact is therefore expected upon adoption on the effective date.

Amendments to IAS 1 Classification of Liabilities as Current or  Non-Current

In January 2020, the IASB issued amendments to IAS 1 Presentation of Financial Statements, to provide a more general approach to the presentation of liabilities as current or non-current based on contractual arrangements in place at the reporting date. These amendments specify that the rights and conditions existing at the end of the reporting period are relevant in determining whether the Company has a right to defer settlement of a liability by at least 12 months, provide that management’s expectations are not a relevant consideration as to whether the Company will exercise its rights to defer settlement of a liability and clarify when a liability is considered settled.

The amendments are effective for annual periods beginning on or after Jan. 1, 2023, and are to be applied retrospectively. The Company has not yet determined the impact of these amendments on its consolidated financial statements.

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.

Environmental, Social and Governance (“ESG”)

Sustainability or ESG management and performance is a priority at TransAlta. Sustainability is one of our core values, which means it is part of our corporate culture. We perpetually strive to further integrate sustainability into our governance, decision-making, risk management and day-to-day business processes, while enabling our growth strategy. The ultimate outcome of our sustainability focus is continuous improvement on key, material ESG issues and ensuring our economic value creation is balanced with a value proposition for the environment and our stakeholders.

Our key strategic sustainability pillars build on our corporate strategy and weave through our business. Our track record in these areas illustrates our commitment to sustainability (including climate change leadership and safety). In other areas where we have set new goals in recent years (including ED&I), we believe the focus will only strengthen our corporate strategy and support value creation into the future. Our pillars include:

1. Clean, Reliable and Sustainable Electricity Production

2. Safe, Healthy, Diverse and Engaged Workplace

3. Positive Indigenous, Stakeholder and Customer Relationships

4. Progressive Environmental Stewardship

5. Technology and Innovation

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Management’s Discussion and Analysis

We have been reporting on sustainability since 1994. This year, we have structured the ESG section of this MD&A to help stakeholders better understand the most material issues affecting our ESG performance.

Reporting on Our Material Sustainability Factors

TransAlta’s ESG content is integrated within this MD&A to provide information on how ESG affects our business (including material focus areas) and is guided by leading ESG reporting frameworks. Content is structured using non-traditional capital (this includes natural, human, social and relationship, intellectual and manufactured capital) as per guidance from the International Integrated Reporting Framework.

Climate-related data to be disclosed is informed by climate change questionnaires from CDP (the global disclosure system for environmental impacts known formerly as Carbon Disclosure Project) and the Task Force on Climate-related Financial Disclosures (“TCFD”) recommendations. In 2021, we conducted a climate-related scenario analysis that enhanced our alignment with both international sustainability frameworks. GHG emissions data for scopes 1 and 2 follow the accounting and reporting standards of the GHG Protocol. For further information on climate change management and the findings of our scenario analysis, please refer to the Decarbonizing Our Energy Mix section of this MD&A.

We adopt guidance from the Global Reporting Initiative and Sustainability Accounting Standards Board (“SASB”) requirements for ‘Electric Utilities and Power Generators’. We continue to monitor the development of sustainability disclosure standards to assess our future reporting, such as the International Sustainability Standards Board and the Taskforce on Nature-related Financial Disclosures.

The disclosure of our most relevant sustainability factors is guided by our sustainability materiality assessment. Our materiality assessment is developed through evaluation of key sector-specific research on material issues and supported by internal and external engagement on key sustainability issues. Our Enterprise Risk Management (“ERM”) program is designed to help the organization focus its efforts on key enterprise risks, within the planning horizon, that could significantly impact the success of its strategy, including its sustainability objectives. We consider a sustainability factor as material if it could substantively affect our ability to create value. Our major environmental risk factors include climate change, weather, environmental disasters, exposure to the elements, environmental compliance risk and current and emerging environmental regulation. Our major social risk factors include Indigenous and stakeholder relationships, local communities, public health and safety, employee and contractor health and safety, employee retention, supply chain and cybersecurity. For further guidance on our risk factors, please refer to the Governance and Risk Management section of this MD&A.

Transforming Our Business Model to Become Carbon Neutral by 2050

At TransAlta, our mission is to provide safe, low-cost and reliable clean electricity to our customers. As a customer-centred clean energy leader, we are well positioned to support our customers’ ESG and sustainability goals. To achieve this goal, in today’s evolving economy and increasingly electrified world, our strategy focuses on renewable electricity growth and a deep commitment to sustainability. We believe we are uniquely positioned as the world continues to electrify and adopt sustainability practices. For further information, please refer to the Description of the Business section of this MD&A.

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Management’s Discussion and Analysis

Our President and Chief Executive Officer, John Kousinioris, speaks about our decarbonization journey in the sections below.

How is TransAlta’s strategy contributing to energy transition?

“In our sector, there is a lot of agreement about what is required to achieve a low-carbon energy transition. First, we need to transition away from high-emitting coal generation. As of the end of 2021, TransAlta has completed this transition in Canada and we will retire our single remaining coal unit in the US at the end of 2025. Second, we need to significantly expand the supply of zero-emission renewable electricity. TransAlta already has a leading portfolio of renewable assets and our growth plan will see us expand our wind and solar business by 2 GW over the next five years. Finally, we need to achieve breakthroughs that allow us to harness intermittent renewables to provide reliable electricity for consumers. TransAlta’s WindCharger facility was the first utility-scale battery project linked to a renewables facility in Alberta and our growth plan includes further investments in energy storage. The key elements of TransAlta’s strategy are aligned with the energy transition underway in the global economy.”

How does the company’s strategy align with global climate efforts?

“We are very proud of our emissions track record to date. Our Company has achieved a 29 million tonne annual GHG emission reduction from 2005 levels. This reduction already exceeds the national 2030 emissions targets in Canada, the US and Australia where we operate. In that sense, we are already ahead of the ambitious national efforts in our home markets. That said, we recognize that decarbonizing the electricity sector is a key pillar of global climate efforts because electrification enables emission reductions in other sectors, such as transportation. This means we have to continually raise our level of ambition as we did last year by setting our carbon neutrality target for 2050 and we did this year by enhancing and accelerating our near-term reduction target.

“We are the first publicly traded Canadian energy company to commit to setting a science-based emissions target. This step is critical in ensuring that our actions are aligned with the steps required to achieve global climate goals. Further, we were pleased to join the Powering Past Coal Alliance during the 26th UN Climate Change Conference of the Parties (“COP26”) in Glasgow. The Alliance is a group of governments and companies committed to achieving one of the key steps in the global energy transition.”

TransAlta accelerated and strengthened its GHG emissions reduction target. Why did the Company choose to take that step?

“Our new target is a function of our new growth strategy. Simply put, by focusing on growing our contracted renewables assets we are growing our business and not our emissions. This type of growth, coupled with coal-to-gas conversions that cut emissions from our thermal assets, and efficient on-site cogeneration, creates an emissions pathway for our Company that delivers substantial reductions over the next five years. We believe it is important for the Company to publicly hold itself accountable for delivering these results and ensuring our investors, customers and stakeholders are aware of where we are going in this important effort.”

How can TransAlta help customers to decarbonize?

“Most importantly, TransAlta helps our customers by reliably delivering and operating renewable and storage projects and on-site generation that meet their energy needs. Underneath that core commitment is a set of technologies and contracting options that we tailor to ensure customers receive the energy they require, and environmental outcomes aligned with their ESG commitments. In 2021, we were proud to announce a major wind project in Oklahoma which will provide electricity to a leading US-based company, a major wind project in

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Management’s Discussion and Analysis

Alberta to provide electricity to Pembina Pipelines as well as a smaller-scale solar and battery project with BHP in Australia. All are examples of a tailored approach designed to meet the unique needs of customers as they advance their own decarbonization goals. In the future, we see more demand for reliable zero-emission electricity and our growth strategy is designed to position the Company to deliver these projects effectively for new and existing partners in all of our markets.”

2022+ Sustainability Targets

Our 2022 and longer-term sustainability targets support the long-term success of our business so that the Company will continue to be positioned as an ESG leader in the future. Goals and targets are established to improve our ESG performance and to manage current and emerging material sustainability issues, in support of the United Nations Sustainable Development Goals (“UN SDGs”) and the Future-Fit Business Benchmark. TransAlta is committed to decarbonizing our energy generation and to accelerating clean energy growth. We believe we can make a greater positive impact on UN SDG 7 “Affordable and Clean Energy” and SDG 13 “Climate Action”, while supporting several other SDGs.

In December 2021, TransAlta approved a more stringent climate-related target to reduce 75 per cent of our scope 1 and 2 GHG emissions by 2026 from a 2015 base year. We estimate that this is in line with limiting global warming to 1.5°C and, in December 2021, committed to setting a science-based emissions reduction target through the Science Based Targets initiative. In 2021, the Company established a Sustainability-Linked Loan that will align the cost of borrowing to TransAlta’s GHG emission reductions and gender diversity targets. For further details on the Sustainability-Linked Loan, please refer to the Significant and Subsequent Events section of this MD&A. In 2021, the Company’s indirect wholly owned subsidiary, Windrise Wind LP, secured green bond financing. This supports our goal to deliver on our customers’ needs for clean electricity. Please refer to the TransAlta Renewables Acquisitions section of this MD&A for further details.

Targets are outlined below:

ESG Alignment: Environment

TransAlta Sustainability Goal	TransAlta Sustainability Target	Alignment with UN SDG Target or Future-Fit Business Benchmark
Reclaim land utilized for mining	By 2040, complete full reclamation of our Centralia coal mine in Washington State	Future-Fit Business Benchmark: “Positive Pursuits 13: Ecosystems are restored”
	By 2046, complete full reclamation of our Highvale coal mine in Alberta	Future-Fit Business Benchmark: “Positive Pursuits 13: Ecosystems are restored”
Responsible water management	By 2026, reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m3 or 40 per cent over the 2015 baseline	UN SDG Target 6.4: “By 2030, substantially increase water-use efficiency across all sectors and ensure sustainable withdrawals and supply of freshwater to address water scarcity and substantially reduce the number of people suffering from water scarcity.”

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Management’s Discussion and Analysis

TransAlta Sustainability Goal	TransAlta Sustainability Target	Alignment with UN SDG Target or Future-Fit Business Benchmark
Reduce operational waste	By 2022, reduce total waste generation by 80 per cent over a 2019 baseline	UN SDG Target 12.5: “By 2030, substantially reduce waste generation through prevention, reduction, recycling and reuse.”
Reduce air emissions	By 2026, achieve a 95 per cent reduction of SO2 emissions and an 80 per cent reduction of NOx emissions below 2005 levels	UN SDG Target 9.4: “By 2030, upgrade infrastructure and retrofit industries to make them sustainable, with increased resource-use efficiency and greater adoption of clean and environmentally sound technologies and industrial processes”
Reduce GHG emissions	By 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from a 2015 base year	UN SDG Target 13.2: “Integrate climate change measures into national policies, strategies and planning.”
	By 2050, achieve carbon neutrality

ESG Alignment: Social
TransAlta Sustainability Goal	TransAlta Sustainability Target	Alignment with UN SDG Target or Future-Fit Target
Reduce safety incidents	Achieve a Total Recordable Injury Frequency rate below 0.61	UN SDG Target 8.8: “Protect labour rights and promote safe and secure working environments for all workers, including migrant workers, in particular women migrants, and those in precarious employment.”
Support prosperous Indigenous communities	Support equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunities	UN SDG Target 4.5: “By 2030, eliminate gender disparities in education and ensure equal access to all levels of education and vocational training for the vulnerable, including persons with disabilities, Indigenous peoples and children in vulnerable situations.”
	Provide Indigenous cultural awareness training to all TransAlta employees by the end of 2023	UN SDG Target 12.8: “By 2030, ensure that people everywhere have the relevant information and awareness for sustainable development and lifestyles in harmony with nature.”

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Management’s Discussion and Analysis

ESG Alignment: Governance
TransAlta Sustainability Goal	TransAlta Sustainability Target	Alignment with UN SDG Target or Future-Fit Target
Strengthen gender equality	Achieve 50 per cent female representation on the Board by 2030	UN SDG Target 5.5: “Ensure women’s full and effective participation and equal opportunities for leadership at all levels of decision making in political, economic and public life.”
	Achieve at least 40 per cent female employment among all employees of the Company by 2030
	Maintain equal pay for women in equivalent roles as men
Demonstrate leadership on ESG reporting within financial disclosures	Maintain our position as a leader on integrated ESG disclosure through increased annual alignment with leading sustainability disclosure frameworks	UN SDG Target 12.6: “Encourage companies, especially large and transnational companies, to adopt sustainable practices and to integrate sustainability information into their reporting cycle.”
ESG Alignment: Environment and Social
TransAlta Sustainability Goal	TransAlta Sustainability Target	Alignment with UN SDG Target or Future-Fit Target
Coal transition	No further coal generation by the end of 2025 with 100 per cent of our owned net generation capacity to be from renewables and gas	UN SDG Target 7.1: “By 2030, ensure universal access to affordable, reliable and modern energy services.”
Clean energy solutions for customers	Develop new renewable projects that support customer sustainability goals to achieve both long-term power price affordability and carbon reductions	UN SDG Target 7.2: “By 2030, increase substantially the share of renewable energy in the global energy mix.”

Our 2021 Sustainability Performance

In 2021, we achieved an environmental performance milestone in our journey to grow our clean electricity fleet with the completion of our coal-to-gas conversions in Canada. Overall, the converted units generate nearly 50 per cent fewer CO₂ emissions fuelled by natural gas compared to coal. The completed unit conversions and the end of production at the Highvale coal mine in Alberta also contributed to the goals of the Powering Past Coal Alliance, which TransAlta joined at COP26. Our social performance was highlighted by our positive contribution to support equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunities.

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Management’s Discussion and Analysis

Performance against our 2021 sustainability targets is outlined below:

ESG Alignment: Environment

TransAlta Sustainability Goal	TransAlta Sustainability Target	Results	Comments
Reclaim land utilized for mining	By 2040, complete full reclamation of our Centralia coal mine in Washington State	On track	Reclamation work at our Centralia and Highvale mines has been executed progressively.
	By 2046, complete full reclamation of our Highvale coal mine in Alberta	On track	Our Highvale coal mine in Alberta retired on Dec. 31 2021, and reclamation has been executed progressively.
Responsible water management	By 2026, reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m3 or 40 per cent over a 2015 baseline	On track	In 2021, we reduced fleet-wide water consumption by 4 million m3 or 11 per cent over 2020 levels.
Reduce operational waste	By 2022, reduce total waste generation by 80 per cent over a 2019 baseline	On track	In 2021, we reduced total waste generation by 620,000 tonnes equivalent or 55 per cent over 2020 levels.
Reduce air emissions	By 2026, achieve a 95 per cent reduction of SO2 emissions and an 80 per cent reduction of NOx emissions below 2005 levels	On track	Since 2005, we have reduced SO2 emissions by 90 per cent and NOx emissions by 77 per cent. In 2021, we reduced SO2 emissions by 42 per cent and NOx emissions by 29 per cent over 2020 levels.
Reduce GHG emissions	By 2030, achieve company-wide GHG reductions of 60 per cent below 2015 levels, in line with a commitment to the UN SDGs and prevention of 2ºC of global warming	Achieved	Since 2015, we have reduced GHG emissions by 61 per cent. In 2021, we reduced approximately 3.9 million tonnes of CO2e or 24 per cent over 2020 levels.
	By 2050, achieve carbon neutrality	On track	Since 2015, we have reduced GHG emissions by 61 per cent. In 2021, we reduced approximately 3.9 million tonnes of CO2e or 24 per cent over 2020 levels.

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Management’s Discussion and Analysis

ESG Alignment: Social
TransAlta Sustainability Goal	TransAlta Sustainability Target	Results	Comments
Reduce safety incidents	Achieve a Total Recordable Injury Frequency rate below 0.61	Not achieved	TRIF performance year over year has remained relatively unchanged. In 2021, we achieved a TRIF of 0.82 compared to 0.81 in 2020. Our focus on safety culture transformation remains as we continue to work to meet and exceed our goal of 0.61 in the future.
Support prosperous Indigenous communities	Support equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunities	Achieved	Support in 2021 represented a total value of $375,000 and provided 14 bursaries through a partnership with Indspire; funded academic upgrading programs through the Southern Alberta Institute of Technology; and maintained communication on employment opportunities through various mediums to support different access options for Indigenous communities.
	Provide Indigenous cultural awareness training to all TransAlta employees by the end of 2023.	On track	In 2021, we committed to and began development of Indigenous Awareness training that will be provided to all Canadian, Australian and US employees by the end of 2023.

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Management’s Discussion and Analysis

ESG Alignment: Governance

TransAlta Sustainability Goal	TransAlta Sustainability Target	Results	Comments
Strengthen gender equality	Achieve 50 per cent female representation on the Board by 2030	On track	As of Dec. 31, 2021, women made up 42 per cent of our total Board composition compared to 45 per cent in 2020, due to the retirement of one female Board member. In 2021, we achieved 50 per cent female representation on the Board, excluding the two nominees from Brookfield.
	Achieve at least 40 per cent female employment among all employees of the Company by 2030	On track	As of Dec. 31, 2021, women made up 24 per cent of all employees, an increase over 2020 levels (21 per cent).
	Maintain equal pay for women in equivalent roles as men	Achieved	Equal pay for women in the Company was maintained in 2021.
Demonstrate leadership on ESG reporting within financial disclosures	Maintain our position as a leader on integrated ESG disclosure through increased annual alignment with leading sustainability disclosure frameworks	Achieved	In 2021, we conducted a climate-related scenario analysis that enhanced our alignment with TCFD and CDP (the global disclosure system for environmental impacts known formerly as Carbon Disclosure Project).
ESG Alignment: Environment and Social
TransAlta Sustainability Goal	TransAlta Sustainability Target	Results	Comments
Leading clean power company by 2025	No further coal generation by the end of 2025 with 100 per cent of our owned net generation capacity to be from clean electricity (renewables and gas)	On track	In 2021, Sundance Unit 5 was retired, and Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 were converted to natural gas. The Highvale coal mine was closed. Centralia Unit 1 retired on Dec. 31, 2020, and the remaining unit is set to retire on Dec. 31, 2025.
	Discontinue coal power generation in Canada by the end of 2021	Achieved	In 2021, our Sundance 5 facility was retired, and Keephills Unit 2, Keephills Unit 3 and Sundance 6 facilities were converted to natural gas. The Highvale coal mine was closed.

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Management’s Discussion and Analysis

TransAlta Sustainability Goal	TransAlta Sustainability Target	Results	Comments
Clean energy solutions for customers	Develop new renewable projects that support customer sustainability goals to achieve both long-term power price affordability and carbon reductions	Achieved	In 2021, the Company purchased a 122 MW portfolio of operating solar facilities in North Carolina and started the construction of a 48 MW solar and battery storage system in Western Australia. We also entered into long-term PPAs for the off take of 100 MW from our Garden Plain wind project in Alberta and 100 per cent of our 300 MW White Rock East and White Rock West wind projects in Oklahoma.

Decarbonizing Our Energy Mix

ESG is more than simply a business strategy at TransAlta; it is a competitive advantage. Sustainability is one of our core values; therefore, we strive to integrate climate change into governance, decision-making, risk management and our day-to-day business operations. The outcome of our climate change focus is continuous improvement on key climate-related issues and ensuring our economic value creation is balanced with a value proposition for the environment and people.

We recognize the impact of climate change on society and our business both today and into the future. Our renewable energy commitment began more than one hundred years ago when we built the first hydro assets in Alberta, which still operate today. In 2002, we acquired our first wind farm, in 2015, our first solar farm, and in 2020, our first battery storage facility. Today, we operate over 50 renewable facilities across Canada, the US and Australia.

Our climate-change-related reporting is guided by the TCFD. This framework helps inform discussion and provide context on how climate change affects our business.

The following are examples of how we have transitioned our business to manage climate change risk and opportunity, how we have demonstrated leadership through action on climate change-related issues and how we are positioned for climate resiliency.

• Today, we are proud to be one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta — we have grown our nameplate renewable energy capacity from approximately 900 MW in 2000 to over 2,800 MW in 2021.

• Our business demonstrates climate change resiliency by reducing GHG emissions – we have a target to reduce annual CO₂e emission by 75 per cent over 2015 levels by 2026. Since 2015, we have reduced our annual emissions by 19.7 million tonnes of CO₂e or 61 per cent, putting us on track to achieve our 2026 target.

• As a leader in North American renewable electricity, we are well-positioned to build renewable energy facilities and hybrid facilities to support customer decarbonization goals. Our strategy involves retiring our single coal unit by the end of 2025 and achieving a 100 per cent mix of renewables and natural gas with 70 per cent of EBITDA from renewables.

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Management’s Discussion and Analysis

Climate Change Governance

Climate-related risks and opportunities can significantly impact our business, especially regulatory changes and shifting customer preferences toward lower-carbon energy. Therefore, we actively manage risks and opportunities so that we can continue to grow and achieve our goals. Climate-related issues are identified at every level of management, including the Board, executive team, business units and corporate functions (for example, government relations, regulatory, emissions trading, sustainability, commercial, customer relations, investor relations). Ensuring climate-related issues are acknowledged and addressed at the most senior levels of the Company (including at the Board and executive level) has allowed us to establish actionable emission reduction targets and grow our generation capacity through renewable energy and storage.

Oversight by the Board of Directors

The highest level of climate change oversight is at the Board level, with specific oversight of certain aspects of the Company’s response to climate change being delegated to our Governance, Safety and Sustainability Committee (“GSSC”), our Audit, Finance and Risk Committee (“AFRC”), and our Investment Performance Committee (“IPC”).

Meeting quarterly, the GSSC assists the Board in monitoring and assessing compliance with climate change regulation and reporting. The GSSC receives management reports on changes in climate-related legislation and the potential impact of policy developments on TransAlta’s operations. The GSSC then supports the Board in developing Company-wide climate change strategies, policies and practices. The GSSC also reviews environmental protection guidelines, including GHG mitigation, and considers whether our environmental procedures are being effectively implemented.

The AFRC and IPC also play a role in managing TransAlta’s climate-related risks and opportunities. The AFRC assists the Board in overseeing the integrity of our consolidated financial statements and ensures climate risks and opportunities are factored into financial decision-making. Further, the AFRC is responsible for approving our Commodity and Financial Exposure Management policies and reviewing quarterly ERM reporting. The IPC considers and assesses risks related to capital projects, including overseeing climate risk assessments and mitigation plans. As a result, climate-related capital expenditures, acquisitions and budgets are reviewed by the AFRC and IPC on a case-by-case basis.

Our Board is composed of individuals with a mix of skills, knowledge and experience critical to our strategy success and business growth. Notably, five of our Board members have identified environment/climate change among their top four relevant competencies.

Role of Senior Management

TransAlta’s President and CEO maintains the highest level of oversight on climate-related issues at the executive level. Our business units and corporate functions work closely together to support the executive team in understanding climate-related risks and opportunities. Our executive team reviews risks and opportunities quarterly and reports to the GSSC and AFRC.

At the business unit level, climate change risks are identified through our Total Safety Management System, asset management function and systems, energy and trading business, communication with stakeholders, active monitoring and participation in working groups.

Notably, we tie a component of executive compensation to reducing GHG emissions and climate change management. We link our corporate executive annual incentive plans (short-term incentive or yearly bonus and

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Management’s Discussion and Analysis

long-term share incentives) to performance on our strategic goals. Our strategic goals include growing renewable energy, reducing GHG emissions, and supporting our customers’ sustainability goals to decarbonize through on-site low carbon energy generation.

For further information on incentives for ESG performance, please refer to the ESG-Linked Compensation in Building a Diverse and Inclusive Workforce section of this MD&A.

Strategy and Risk Management

Climate Change Strategy

As described in the following sections, our risks and opportunities assessment and climate scenarios analysis support the development and continuous improvement of our climate change strategy. We actively monitor and manage climate-related risks and opportunities as part of our overall business strategy to ensure we remain resilient across all scenarios.

TransAlta remains committed to creating a path to resiliency in a decarbonizing world so that we support the goals proposed under the Paris Agreement and those solidified during successive meetings, such as COP26. Our strategy is focused on the operation of our existing assets (wind, hydro, solar, gas, storage and coal), the phase-out of coal-fired electricity generation and the development of renewable energy and storage projects. Our customers are increasingly integrating ESG risk into their business decisions; therefore, we see an advantage in growing our clean power business to support our customers’ sustainability goals. Our investments and growth in renewable energy are highlighted by our portfolio of renewable energy-generating assets. From 2000 to 2021, we grew our nameplate renewables capacity from approximately 900 MW to over 2,800 MW. Today, our diversified renewable fleet makes us one of the largest renewable power producers in North America, one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta.

Another way we contribute to our customers’ sustainability goals is through environmental attributes. The environmental attributes we generate include carbon offsets, renewable energy credits and emission offsets. Our customers can use environmental attributes to lower compliance costs attributed to carbon policies or renewable portfolio standards. Further, environmental attributes can help achieve voluntary corporate sustainability or carbon reduction goals.

To combat the challenges of renewable energy intermittency, we continue to invest in battery storage. In 2020, we launched WindCharger, a “first of its kind” battery storage project in Alberta that stores energy produced by our Summerview II wind facility and discharges electricity onto the Alberta grid during system supply shortages. Further, in 2021, we agreed to provide renewable solar electricity supported with a battery energy storage system to BHP through the construction of the Northern Goldfields Solar Project in Western Australia. This project will support BHP in meeting its emissions reduction targets and delivering lower carbon, sustainable nickel to its customers. With a target operation date in early 2023, the Northern Goldfields Solar Project is expected to reduce BHP’s scope 2 electricity GHG emissions by 540,000 tonnes of CO₂e over the first 10 years of operation.

In support of our own path to climate resiliency, we have taken significant steps to reduce our carbon footprint over the last several years. In 2021, we adopted a more stringent climate-related target to reduce 75 per cent of our scope 1 and 2 GHG emissions by 2026 from a 2015 base year. TransAlta estimates that this is in line with limiting global warming to 1.5°C and, in 2021, committed to setting a science-based emissions reduction target through the Science Based Targets initiative. In addition, we have a target to be carbon neutral by 2050, while growing renewable energy and optimizing natural gas. We are also taking strategic steps to decarbonize the power sector and support the energy transition. In 2021, we completed our conversion of existing Canadian coal

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Management’s Discussion and Analysis

assets to natural gas, achieving our goal of transitioning off coal in Canada. In 2021, we also announced our Clean Electricity Growth Plan which will see the Company execute on 2 GW of renewables growth by 2025. In 2025 we will also retire our single remaining coal unit, located in the United States, to complete TransAlta’s transition away from coal generation.

To date, we have retired 4,064 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to natural gas. Overall, our converted natural gas units generate nearly 50 per cent fewer CO₂ emissions compared to coal. Repurposing the facilities rather than decommissioning them reduces the cost and emissions associated with new construction and aligns with the UN SDGs, specifically “Goal 9: Industry, Innovation and Infrastructure.” The completed conversions and the closure of the Highvale coal mine also contributes to the goals of the Powering Past Coal Alliance, which TransAlta joined in November 2021 at COP26.

We actively engage policymakers and stakeholders on how to facilitate a transition where the electricity systems we serve can reach net-zero emissions while maintaining reliability. We will continue investing in renewables and assessing the best options to deliver energy storage, including incorporating learnings from our industrial-scale battery into our Company strategy and sharing those learnings with government. At the same time, natural gas will play an essential role in the electricity sector, providing baseload generation to support current system demands and a smooth energy transition. We always seek energy-efficiency improvements and opportunities to achieve emissions reductions at competitive costs. Further, we are committed to investing in climate change mitigation solutions to maximize value for our shareholders, customers, local communities and the environment.

Climate Scenarios

In 2021, we conducted climate scenario analysis to understand risks and opportunities and assess our strategy’s resiliency under several future climate scenarios. The analysis utilized scenarios from the International Energy Agency’s (“IEA”) 2020 World Energy Outlook, a large-scale simulation model designed to replicate how energy markets function. We used three scenarios, Stated Policies (“STEPS”), Sustainable Development (“SDS”) and Net Zero Emissions by 2050 (“NZE”).

In STEPS, the energy system has no major additional climate and environmental policies enacted by government(s). STEPS assumes that carbon pricing continues in Canada while no carbon price is set in the US or

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Australia. STEPS also assumes that the power sector reduces emissions by 45 per cent by 2040 while natural gas generation capacity increases. Finally, STEPS is limited to the deployment of commercial-ready technologies, including wind and solar.

In SDS, the goals of the Paris Agreement (2015) are achieved, resulting in net-zero emissions by 2070. The SDS assumes a rapid increase in clean energy policies and investments that position the energy system to also achieve key UN SDGs. In SDS, all current net-zero pledges are achieved, and there are extensive efforts to reduce emissions. SDS assumes that carbon pricing continues in Canada and is set in the US and Australia. It also assumes that the power sector reduces emissions by 90 per cent by 2040 while natural gas capacity remains stable into 2030 and declines toward 2040. Finally, SDS assumes that beyond wind and solar, the energy system relies on batteries, storage and some level of carbon capture, utilization and storage (“CCUS”) and hydrogen.

NZE represents a pathway for the global energy sector to achieve net-zero emissions by 2050. This scenario also assumes key energy-related SDGs are achieved through universal energy access by 2030 and major improvements in air quality. NZE is built upon the idea that a global increase in electrification supports the journey to net-zero. It assumes that an aggressive carbon price is set in Canada, the US and Australia. It also assumes the power sector reaches net-zero emissions by 2035 in advanced economies while natural gas capacity is stable to 2030 and declines significantly into 2040. Like the SDS, NZE assumes that beyond wind and solar, the energy system relies on batteries, storage and some level of CCUS and hydrogen.

Key Climate Scenario Findings

Using climate scenarios, we analyzed the resiliency of our business and determined specific risks and opportunities for our individual assets. All three scenarios present opportunities for TransAlta’s growth related to renewables, storage solutions and ancillary services. The scenario analysis found that our wind and solar assets have the highest prospects for growth, which aligns with our growth strategy. Under all scenarios, hydro remains a valuable asset as it allows for expansion to include storage.

The figures in the following sections highlight TransAlta’s top risks, opportunities and management response across all scenarios.

Top Identified Climate-Related Risks by Scenario

	Increased competition	Decreased demand of natural gas electricity	Increased operational costs
Description	Subsidies/funds available for clean energy transition increase as governments aim to grow installed capacity of renewables to meet rising electricity demand and compensate for the closure of carbon-intensive power plants. It is expected that major grid decarbonization investments will flow into Alberta as many	Demand of power from natural gas declines as the market shifts towards cleaner power. An additional decline from Canadian oil & gas customers can occur as oil production levels drop under NZE and SDS. The transition to a lower-carbon world will likely result in volatility and market uncertainty. Counterintuitively,	Carbon price increases the cost of natural gas operations. Additional mandated emission reductions could force remaining plants to invest in technologies like CCUS, increasing the operating costs for natural gas plants further. Natural gas assets in the US and Australia face less risk compared to assets in

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	Increased competition	Decreased demand of natural gas electricity	Increased operational costs
	other markets where TransAlta operates are heavily regulated and/or are already low carbon. This will increase competition in the merchant market, making a large part of the generating fleet frequently bid at zero, driving down the average price of dispatched electricity. Simultaneously the cost of renewables, expected to decline across all scenarios, decreases the capital barrier to entry. These combined factors will increase competition for TransAlta. The IEA scenarios do not provide clear indication of electricity pricing and how it can be affected by increased competition. As such, this remains a point of uncertainty. Some structural market changes may be required to guarantee returns for power generators and successfully decarbonize the grid.	natural gas power may be necessary to provide power in the transition if the pace of decarbonization is slower than expected in the scenarios or if grid-scale storage solutions do not develop/commercialize as modelled. In these cases, with coal phased out, natural gas assets will be relied on for baseload generation. This means that natural gas assets may still play a role for a smooth and efficient energy transition. Optimization of natural gas assets is required, and additional investments need to be assessed with caution to consider the pace of decarbonization and consequent risk of decreased demand for natural gas power.	Alberta as they are contracted and can pass down carbon costs to their clients. Current and anticipated regional carbon pricing monitoring is required to plan and assess increases in operational costs and impacts on new projects and investments.
NZE	By 2040, renewables are expected to comprise over 85 per cent of the total electricity generations in the regions we operate. This surge in renewables will increase competition and drive electricity pricing down. The change in electricity prices and increased market uncertainty are expected to impact our profits.	The share of natural gas electricity generation is expected to decline over 50 per cent in the regions where we operate by 2040 compared to 2019 levels. This lower demand for natural gas power is expected to impact our natural gas assets if no management responses are implemented.	Higher operational costs driven by an increase in carbon price to US$205/tonne CO2e by 2040 in all our operating regions (advanced economies under IEA scenarios) and lower operational capacity is expected to impact the profits from our natural gas assets.

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Management’s Discussion and Analysis

Top Identified Climate-Related Risks by Scenario

	Increased competition	Decreased demand of natural gas electricity	Increased operational costs
SDS	Fewer subsidies/funds are expected under this scenario compared to NZE. However, renewable costs will still decline approximately 10 per cent in wind and 55 per cent in solar by 2040 compared to 2019 levels. This decline with some level of subsidy will increase competition and potentially decrease electricity prices, which is expected to impact our profits.	Natural gas electricity generation still falls over 50 per cent in North America while remaining flat in Australia by 2040 when compared to 2019 levels. Demand for natural gas power is expected to decrease at slower pace than under NZE. This could potentially impact our natural gas assets if no management responses are implemented.	Increase in operational costs would happen at a slower rate compared to NZE but carbon costs are still expected to reach US$140/tonne CO2e by 2040 in all of our operating regions. This could potentially impact the operational capacity and profits from our natural gas assets, depending on the ability to pass carbon prices on through our contracts.
STEPS	While minimal subsidies are expected and the cost of entry will not decline at the same rate as SDS or NZE, renewable costs are still expected to decline approximately 8 per cent in wind and 45 per cent in solar by 2040 compared to 2019 levels. This will still cause an increase in competition that is expected to be offset by additional electricity demand and therefore it is not expected to impact our profits.	Natural gas electricity generation is expected to increase over 15 per cent in the regions we operate by 2040 compared to 2019 levels. These changes are not expected to affect our natural gas assets.	Operational costs are not expected to significantly increase under this scenario as only Canada sees a carbon price in 2040. Therefore, profits from our natural gas assets are not expected to be affected.
Management Response	Navigating the uncertainty around market dynamics (structure, pricing and competition),	Optimize gas assets to maximize value and cash flows to support renewables and storage growth. Our converted	We have taken significant steps to reduce our carbon footprint. In 2021, we achieved a total

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Increased competition	Decreased demand of natural gas electricity	Increased operational costs
government policies and planning is critical for TransAlta. We use hedging and PPAs to stabilize pricing and are planning on leading clean energy growth where we operate. See more details of our strategy and risk management under the Climate Strategy section and Managing Climate Change Risks and Opportunities section of this MD&A.	natural gas units generate nearly 50 per cent fewer CO2 emissions compared to coal. Repurposing the coal facilities rather than decommissioning them reduces the cost and emissions associated with new construction and aligns with the UN SDGs, specifically “Goal 9: Industry, Innovation and Infrastructure.” In parallel, we continue growing our renewable fleet; by 2025 we will have achieved a 100 per cent portfolio mix of renewables and natural gas with 70 per cent of EBITDA attributable to renewables.	reduction of 61 per cent compared to our 2015 emission levels. By 2026, we have a commitment to reduce scope 1 and 2 GHG emissions by 75 per cent from a 2015 base year and plan to achieve carbon neutrality by 2050. Further, our corporate functions apply regionally specific carbon pricing, both current and anticipated, as a mechanism to manage future risks of uncertainty in the carbon market.

Top Identified Climate-Related Opportunities by Scenario

	Renewables become major energy source	New technology development
Description	Opportunities to grow the renewable fleet exist across all scenarios. Renewable assets (hydro, wind, solar) are expected to become the default form of generation with demand for power from these type of assets increasing. Hydro is likely to grow in value given increased renewables penetration and the need for reliable zero-emitting generation. This can make hydroelectric power a stronger source of baseload electricity in many regions. The decreasing cost of renewables also facilitates the growth of a renewable fleet, especially under NZE and SDS.	Opportunities for development of battery or hydroelectric storage systems and ancillary services exist across all scenarios as renewable energy continues to penetrate the grid. Developments in these areas are required to keep electricity flowing when the renewables in a region are not producing. Storage is specially anticipated to play an important role in the energy transition. Cost-competitive battery storage enables greater adoption of renewables.

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Management’s Discussion and Analysis

	Renewables become major energy source	New technology development
NZE	A growth of renewable electricity generation of approximately 950 per cent is expected by 2040 compared to 2019 levels. This results in renewables comprising more than 85 per cent of the electricity generation in the regions we operate. The transition of hydro to baseload capacity is expected to create upside for TransAlta. An increase in TransAlta’s renewable capacity and demand are expected to enable growth and higher revenues.	Increased revenues through access to new and emerging markets are expected to enable growth and higher revenues under NZE. With more than 85 per cent of electricity in areas we operate made up of renewables, there will be big steps forward in storage and ancillary services technologies. Storage capacity is expected to grow to approximately 250 GW in the US by 2040.
SDS	A growth of renewable electricity generation of approximately 550 per cent is expected by 2040 compared to 2019 levels. This results in renewables comprising more than 75 per cent of the electricity generation in the regions where we operate. An increase in TransAlta’s renewable capacity and demand are expected to enable growth and higher revenues.	Increased revenues through access to new and emerging markets are expected to enable growth and higher revenues under SDS. A lower share of renewables than in NZE will allow swing production to remain present; however, growth in ancillary and storage capacity will still be needed to support the market. Storage capacity is expected to grow to approximately 110 GW in the US by 2040.
STEPS	STEPS growth is muted relative to the other scenarios but still sees a growth of renewables of 280 per cent by 2040 compared to 2019 levels. This growth will allow approximately 50 per cent of electricity generation to come from renewables in areas where we operate by 2040. Increase in TransAlta’s renewable capacity and demand are expected to enable growth and higher revenues.	Access to new and emerging markets would be limited under this scenario compared to NZE and SDS. While growth in renewables is expected, the need for new technologies is not a necessity in this market and may not be profitable. Therefore, our revenues are not expected to be affected.
Management Response	Our renewable energy commitment began more than 100	To leverage this opportunity and combat the challenges of

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Renewables become major energy source

New technology development

years ago when we built the first hydro assets in Alberta, which still operate today. Today we operate over 50 renewable facilities across Canada, the US and Australia. By the end of 2025, we expect 70 per cent of our EBITDA to be derived from renewables. Our strategy is focused on the operation of our existing assets (wind, hydro, solar, gas, storage and coal) and the development of renewable energy, storage and low-carbon natural gas generation. Our investments and growth in renewable energy are highlighted by our portfolio of renewable energy-generating assets. From 2000 to 2021, we grew our nameplate renewables capacity from approximately 900 MW to over 2,800 MW. Today, our diversified renewable fleet makes us one of the largest renewable producers in North America, one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta.

renewable energy intermittency, we continue to invest in battery storage. In 2020, we launched WindCharger, a “first of its kind” battery storage project that stores energy produced by our Summerview II wind facility and discharges electricity onto the Alberta grid during system supply shortages. Further, in 2021, we agreed to provide renewable solar electricity supported with a battery energy storage system to BHP through the construction of the Northern Goldfields Solar Project in Western Australia. This project will support BHP in meeting its emissions reduction targets and delivering lower carbon, sustainable nickel to its customers.

NZE: The most significant risks include increased competition, decreased demand for natural gas and increased operational costs due to increased carbon pricing and emission reduction mandates. The most significant opportunities include a shift toward renewables as the default energy source and new technology developments, including battery storage systems and ancillary services. It is worth noting that there are additional risks and opportunities for TransAlta under NZE. For example, changes in how energy market services are offered could positively or negatively impact our business. Further, as carbon credit policies evolve, so will our ability to use credits. Lastly, as renewables become the primary energy source, a rethinking of ancillary services will be necessary but could create significant opportunities for TransAlta.

SDS: The risks and opportunities remain the same under SDS as NZE; however, the impacts are reduced as market changes are slower and less extreme. Renewables still become the primary electricity source, and there are new technology opportunities, particularly in batteries. Natural gas electricity demand still declines by 2040. Carbon pricing exists in the US and Australia, but the price is reduced compared to NZE. Lastly, a reevaluation of ancillary services still presents an opportunity for TransAlta.

STEPS: Under STEPS, renewable generation sees significant growth but does not become the predominant energy source. Implementing new technologies is much slower, and the demand for batteries is reduced. The demand for natural gas electricity does not decline, and there are no large-scale market changes making services,

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Management’s Discussion and Analysis

pricing and ancillary services more stable. This removes the risk associated with natural gas electricity demand but eliminates the opportunity for growth in ancillary services. Physical risks become more relevant under this scenario than transitional risks.

To mitigate risks and capitalize on opportunities, we have developed climate signposts to monitor the evolution of future climate scenarios. Signposts are indicators that suggest the likelihood of a particular climate scenario. Examples of signposts include directional change in carbon and oil prices. As demonstrated in the following figure, the findings from the climate scenarios and these signposts work alongside our sustainability metrics and targets to inform the evolution and resiliency of our Company strategy and financial planning, risk management, opportunity assessment and planning for uncertainty.

The figure below shows how we integrate climate into our overall risk management strategy:

Managing Climate Change Risks and Opportunities

We actively monitor and manage climate-related risks through our company-wide enterprise risk management processes. In 2021, we established a formal process to review specific risks using climate scenario analysis. As previously mentioned, climate change risks and opportunities are addressed at each of the Board level, executive and management level, business unit level and through our corporate functions. The business units and corporate functions work closely together and provide information on risks and opportunities to management, the executive team and the Board.

Climate change risks at the asset or business unit level are identified through our Total Safety Management System, asset management function and systems, energy and trading business, communication with stakeholders, active monitoring and participation in working groups. All identified material risks are added to our ERM register and scored based on likelihood and impact. We do not consider risks in isolation, and major risks are the focus of management response and mitigation plans. Further discussion can be found in the Governance and Risk Management section of this MD&A.

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Management’s Discussion and Analysis

We divide our climate change risks into two major categories as per guidance from the TCFD: (i) risks related to the transition to a lower-carbon economy and (ii) risks related to the physical impacts of climate change.

Transition Risks to a Lower Carbon Economy

We actively aim to understand and manage the impact of climate change on our business as the world shifts to a lower-carbon society.

Policy and Legal Risks

Changes in current environmental legislation do have, and will continue to have, an impact upon our operations and our business in Canada, the US and Australia. For a more detailed assessment of policy and regulatory risks please refer to the Governance and Risk Management section of this MD&A.

Canada

The Government of Canada has set out ambitious objectives for carbon emissions reduction, including achieving a 40 to 45 per cent national emissions reduction over 2005 levels by 2030, a net-zero electricity grid by 2035 and a net-zero national economy by 2050. The government plans to rely on several policy tools to achieve its emissions objectives, including carbon pricing, emissions performance regulations, funding for industrial energy transition, a Clean Fuel Regulation and incentives for consumers.

In 2021, a Supreme Court of Canada decision confirmed the federal government has significant authority to set national carbon pricing standards. We anticipate the federal government will use this authority to align provincial carbon pricing systems with national carbon targets. Canada’s provinces have significant jurisdiction over their respective electricity sectors and play an important role in setting carbon pricing policy and emissions performance standards, as well as developing and operating their own funding and incentive programs. Negotiation to align carbon pricing, funding and regulatory standards will likely require significant effort and create the risk of tension and misalignment between federal and provincial governments.

Risks

• Escalation in carbon prices and emissions performance regulation may impact TransAlta’s natural gas generation fleet in Canada as governments escalate policy stringency to meet 2030, 2035 and 2050 targets.

• Increased government funding for industrial energy transition may create out of market incentives for competing generation.

• Regulatory incentives, including emissions reduction crediting, may create out of market incentives for competing generation.

• Lack of federal/provincial coordination with respect to climate policy and regulation may lead to investment uncertainty.

Opportunities

• Independent estimates suggest that achieving Canada’s climate targets will require a minimum of twice Canada’s current non-emitting generation. This presents strong policy alignment with TransAlta’s Clean Electricity Growth Plan.

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Management’s Discussion and Analysis

• Government funding for innovative technology to reduce emissions from the electricity sector offers TransAlta the potential opportunity to gain project support for uneconomic new technologies, which will enable the Company to grow its ESG and policy-aligned generation and energy storage fleet.

• Government support for industrial electrification and consumer incentives mandates for electrification, such as for the purchase of electric vehicles, will grow the electricity load over time and create new opportunities for contracted clean generation.

Management Response

• TransAlta’s Clean Electricity Growth Plan will reduce the proportional Company exposure to potential policy and regulatory decisions that negatively impact natural gas generation.

• Our coal-to-gas facilities fit well within government plans to continue providing reliable and competitively priced electricity for consumers and industry.

• Our remaining natural gas facilities operate under contract, reducing TransAlta’s exposure to changes in carbon pricing.

• TransAlta actively engages with the federal and provincial governments in Canada to inform and influence policy development to ensure that our generating fleet continues to serve our customers as the country undertakes a broader energy transition.

• We actively work, directly and through industry associations, to encourage governments to adopt a level playing field within funding and crediting programs so that all new projects receive equitable governments incentives and funding.

• TransAlta actively engages with all relevant Canadian governments to seek policy alignment across carbon pricing and regulatory and funding programs to create the greatest possible degree of investment certainty.

United States

The US government has set out ambitious objectives for carbon emissions reduction, including achieving a 50 to 52 per cent national emissions reduction over 2005 levels by 2030, a net-zero electricity grid by 2035 and a net-zero national economy by 2050. The US does not have a national carbon pricing regime but does offer federal incentives for renewable generation, which makes the US policy environment less predictable than in other countries where we operate.

State and regional climate and market policies have a significant impact on the pace of energy transition in the US with many governments operating under renewable portfolio standards and carbon pricing regimes. Similar to Canada, independent estimates suggest that the US will require substantial growth in zero-emissions generation to meet its national climate targets.

Risks

• TransAlta operates two thermal generating facilities in the US that could be subject to short-term climate policy changes, but our exposure to this policy risk is low (please refer to Management Response below).

• Given overall political uncertainty, renewable growth projects face elevated uncertainty with respect to long-term federal incentive programs.

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Management’s Discussion and Analysis

Opportunities

• Achieving US climate goals requires continued growth in zero-emissions electricity generation. TransAlta’s Clean Electricity Growth Plan is focused on providing renewable electricity to contracted customers in a manner aligned with federal and, where applicable, state goals.

• US tax incentive programs offer significant support for new renewable projects, making the US an attractive growth market.

Management Response

• TransAlta’s single coal unit in Washington State is subject to a retirement agreement with the state government that exempts the facility from carbon pricing prior to its end of life in 2025. TransAlta’s cogeneration unit at Ada operates under a contract that reduces the Company’s exposure to policy risk.

• Our Clean Electricity Growth Plan is focused on developing and acquiring contracted assets that provide long-term certainty with respect to revenue and eligibility for government incentive programs. TransAlta actively assesses available government renewable tax legislation and programs to maximize, wherever possible, access to project incentives.

Australia

The Government of Australia has a 26 to 28 per cent national emissions reduction target over 2005 levels by 2030 and a goal to achieve a net-zero national economy by 2050. The government has stated it does not plan to adopt carbon pricing but intends to offer incentives for energy transition. Australian state governments have all adopted net-zero goals and a number of states have interim targets for 2030 and 2040. These state policies are driving demand for zero-emissions electricity and energy storage.

Risks

• TransAlta’s Australian natural gas assets may face policy risk related to changes in government policies but remain well positioned to mitigate those risks (please refer to Management Response below).

Opportunities

• Our Clean Electricity Growth Plan is focused on building new, clean generation in Australia and other markets. Government policies and funding programs are generally supportive of the types of projects contemplated within TransAlta’s strategy.

Management Response

• TransAlta’s assets are predominantly contracted and serve remote industrial load. As a result, the Company faces reduced policy risk.

Technology Risks

Technological changes to support the low-carbon transition present both risks and opportunities for TransAlta. We evaluate existing and emerging impacts of technology through our technologies team and our ERM process. Examples of technology risks and opportunities include infrastructure changes (such as shift to distributed energy

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Management’s Discussion and Analysis

and away from large-scale power generation infrastructure assets and projects) and digitization combined with greater adoption of energy efficiency (less use of our end product). Cost-competitive battery storage will enable greater adoption of renewables and a shift to a distributed power generation model. We continue to evaluate battery storage for its financial viability while monitoring the potential impact battery technology could have on natural gas power generation. In 2020, we completed our first battery storage (10 MW) project at one of our wind farms in southern Alberta. In 2021, we agreed to deliver a hybrid system of solar with battery storage (48 MW) in Western Australia. We continue to investigate the possibility of battery storage at our other facility locations. Our teams continuously adopt improved technology at each of our new developments, which helps protect our shareholder value and maintain reliable and affordable electricity delivery.

We are well-positioned to take advantage of technological opportunities in storage through hydro and/or battery power. We are also well-positioned to take advantage of advancements in renewable technologies as we build new facilities. We are actively accelerating our renewable growth strategy, with $3 billion in investment and 2 GW of growth planned by 2025. We will continue monitoring new technologies such as storage, hydrogen and CCUS for future deployment. For further information on technology and innovation, please refer to the Technology Adoption and Innovation Focus section of this MD&A.

Market Risks

Our major market risks are associated with our coal and natural gas assets. Increased costs for natural gas supply due, in part, to carbon pricing changes could impact our operating costs. We actively monitor market risks through our energy marketing and asset optimization teams and our ERM process. We manage the market risks to our coal assets by converting them to natural gas and plan to fully transition off coal by 2025. Further, our corporate functions apply regionally specific carbon pricing, both current and anticipated, as a mechanism to manage future risks of uncertainty in the carbon market. To simultaneously manage our risks and leverage market opportunities, we continue operating our hydro, wind and solar facilities and are investing in expanding our renewable energy fleet.

We currently have over 20 renewable projects that are either under construction or in the development stage. We are committed to growing our clean energy fleet and since 2019 have added over 400 MW of renewables and storage, including utility-scale battery storage. In 2021, we retired or converted 2,260 MW of coal generation. Further, we established approximately 3 GW of wind and solar pipelines and organized Canadian, US and Australian clean energy growth teams. Our renewable fleet makes our overall portfolio more resilient to climate risk, provides increased flexibility in generation and creates incremental environmental value through environmental attributes. Lastly, we recognize the opportunity to grow our ancillary services, such as systems support, providing flexibility to the decarbonizing grid.

Reputation Risks

Negative reputational impacts, including revenue loss and reduced customer base, are evaluated through our ERM process. In the past, we experienced negative reputational impacts due to our coal operations, including a negative impact on the market price of our common shares. Our transition away from coal mitigates this reputational risk. As consumer trends move in favour of renewable and clean electricity, we are investing in a diversified mix of renewable generation and optimizing our natural gas fleet. We continue to actively monitor and manage reputational risks by delivering renewable power solutions while maintaining competitive costs and reliability.

Physical Impact Risks of Climate Change

As we learn more about the physical risks associated with climate change, we continue to consider acute and chronic risks that could significantly impact our operations.

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Management’s Discussion and Analysis

Acute Physical

We have operating assets in three countries and varied geographic locations, many of which could be impacted by extreme weather events. We are thus continuously evaluating the potential impact of acute climate change on our business. Our facilities, construction projects and operations are exposed to potential interruption or loss from environmental disasters (e.g., floods, strong winds, wildfires, ice storms, earthquakes, tornados, cyclones). A significant climate change event could disrupt our ability to produce or sell power for an extended period. Therefore, we strive to mitigate future impacts with climate adaptation solutions.

For example, our gas facility at South Hedland, Australia, is built with climate adaptation in mind. We designed the facility to withstand a category 5 cyclone (the highest cyclone rating). We have mitigated the risk of floods that can occur in the area by constructing the facility above normal flood levels. In 2019, a category 4 cyclone hit this facility but did not impact operations. We were able to continue generating electricity through the storm despite widespread flooding and the shutdown of the nearby port. For further information on weather-related risks, please refer to Weather in the Progressive Environmental Stewardship section of this MD&A.

Chronic Physical

We continuously investigate the physical impacts of chronic climate change on our operating assets and actively integrate climate modelling into our long-term planning. For example, changes to water flow or wind patterns could impact our hydro and wind businesses and associated revenue generation.

Climate Change Metrics and Targets

Metrics and Targets

At TransAlta, climate change management and performance are a top priority. We establish our goals and targets with reference to the UN SDGs and the Future-Fit Business Benchmark. Our sustainability targets support the long-term success of our business. Over time, we have set ourselves apart with actions that demonstrate climate change leadership, including reducing our annual emissions by over 19 million tonnes of CO₂e since 2015. We are committed to evolving our leading sustainability target-setting process, ensuring our goals are meaningful and ambitious, and securing TransAlta’s competitiveness, both today and in the future.

The following targets outline our pathway to becoming a leader in clean, affordable, and reliable power. We establish goals and targets to manage key and emerging sustainability issues and improve our performance in these areas. We will continue to evolve and adapt our targets to focus on key anticipated climate-related issues.

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Management’s Discussion and Analysis

Progress towards our climate-related targets are presented below:

Clean Energy Growth
Target	Develop new renewable projects that support our customers’ sustainability goals to achieve both long-term power price affordability and carbon reductions	No further coal generation; 100% of our owned net generation capacity from renewables and gas
Year	2021	2025
Progress (% of target met)
Notes	In 2020, we developed WindCharger, a “first of its kind” battery storage project; in 2021, we agreed to provide renewable solar electricity supported with a battery energy storage system to BHP through the construction of the Northern Goldfields Solar Project in Western Australia. In 2021, we also entered into long-term PPAs for the off take of 100 MW from our Garden Plain wind project in Alberta and 100 per cent of our 300 MW White Rock East and White Rock West wind projects in Oklahoma.	One of our major strategic goals is to be coal-free in Canada by the end of 2021 with the remaining US unit retiring by 2025. In 2021, we achieved full phase-out of coal in Canada. This means TransAlta’s thermal facilities in Alberta have been fully transitioned to a 100% natural gas operation. The Highvale coal mine was closed. In the US, Centralia Unit 1 retired on Dec. 31, 2020, and the remaining unit is set to retire on Dec. 31, 2025. Thus far, we have retired or converted 90% of our existing coal fleet and will retire the remaining 10% by 2025.
UN SDG Alignment	Target 7.2: “By 2030, increase substantially the share of renewable energy in the global energy mix.”	Target 7.1: “By 2030, ensure universal access to affordable, reliable and modern energy services.”

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Management’s Discussion and Analysis

Emissions Reduction
Target	By 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from a 2015 base year.	Achieve carbon neutrality
Year	2026	2050
Progress (% of target met)
Notes	We are well on track to achieve our target of 75 per cent GHG emissions reductions by 2026. We estimate that this is in line with limiting global warming to 1.5°C and, in 2021, committed to setting a science-based emissions reduction target through the Science Based Targets initiative. Since 2015, we have reduced our annual GHG emission by approximately 19.7 million tonnes CO2e or 61%. In 2021, we reduced approximately 3.9 million tonnes of CO2e over 2020 levels.	In 2021, we adopted a target to be carbon neutral by 2050. We believe carbon neutrality provides flexibility as we shape our strategy over the coming decades, and we believe our clean electricity strategy has us well positioned to support us achieving this.
UN SDG Alignment	Target 13.2: “Integrate climate change measures into national policies, strategies and planning.”	Target 13.2: “Integrate climate change measures into national policies, strategies and planning.”

GHG Disclosures

Our GHG emissions are calculated using a number of different methodologies depending on the technologies available at our facilities. Emissions data has been aligned with the “Setting Organizational Boundaries: Operational Control” methodology set out in the GHG Protocol: A Corporate Accounting and Reporting Standard developed by the World Resources Institute and the World Business Council for Sustainable Development. We report emissions on an operation control basis, which means we report 100 per cent of emissions at the facilities we operate.

The GHG Protocol 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 1 or 2) that occur in the value chain of the reporting company, including both upstream and downstream emissions.

We compile our corporate GHG inventory using our business segment GHG calculations. As a result, emission factors and global warming potentials used in our GHG calculations can vary due to difference in regional compliance guidance. The Clean Energy Regulator in Australia amended global warming potentials in August 2020. Therefore, the use of global warming potentials in our GHG calculations related to our Australian assets differs from the rest of our fleet. Applying harmonized global warming potentials across our fleet would result in a minor variance to our overall calculated GHG totals.

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Management’s Discussion and Analysis

Our 2021 GHG data is reported to a number of different regulatory bodies throughout the year for regional compliance and, as a result, may incur minor revisions as we review and report data. Any historical revisions will be captured and reported in future disclosure. As per the Kyoto Protocol, GHGs include carbon dioxide, methane, nitrous oxide, sulphur hexafluoride, nitrogen trifluoride, hydrofluorocarbons and perfluorocarbons. Our exposure is limited to carbon dioxide, methane, nitrous oxide and a small amount of sulphur hexafluoride. The majority of our estimated GHG emissions result from carbon dioxide emissions from stationary combustion from coal and natural-gas-powered generation.

The following tables detail our GHG emissions by scope, business segment and country in million tonnes of CO₂e. Some values do not sum to the indicated total due to rounding of tabulated emissions. Zeros (0.0) indicate truncated values.

Year ended Dec. 31	2021		2020		2019
Scope 1		12.4		16.3		20.5
Scope 2		0.1		0.1		0.1
Total GHG emissions		12.5		16.4		20.6
Year ended Dec. 31	2021		2020		2019
Hydro		0.0		0.0		0.0
Wind & Solar		0.0		0.0		0.0
Gas		6.5		7.7		9.3
Energy Transition		6.0		8.6		11.3
Corporate and Energy Marketing		0.0		0.0		0.0
Total GHG emissions		12.5		16.4		20.6
Year ended Dec. 31	2021		2020		2019
Australia		1.0		1.1		1.1
Canada		7.9		9.4		11.6
US		3.6		5.9		8.0
Total GHG emissions		12.5		16.4		20.6

In 2021, our GHGs emissions (scopes 1 and 2) were estimated to be 12.5 million tonnes as a result of normal operating activities. Compared to 2020, this represents a reduction of approximately 24 per cent or 3.9 million tonnes CO₂e. Reductions in GHG emissions were primarily due to shutdowns during coal-to-gas conversions and coal unit retirements. Because we sell the environmental attributes generated from our renewable energy facilities, we do not subtract this amount from our total emissions, but it should be noted that TransAlta’s customers are reporting GHG reductions using our renewable energy assets, projects and operations.

GHG emissions are verified to a level of reasonable assurance in locations where we operate within a carbon regulatory framework. Any historical revisions to GHG data will be captured and reported in future disclosure. The majority of our GHG emissions result from carbon dioxide emissions from stationary combustion from coal and natural-gas-powered generation.

The following highlights our scope 1 and 2 GHG emission reductions since 2015 and our targeted emissions in 2026 (in line with our new GHG target). The actual GHG emissions for the Company in 2026 will vary from that presented below depending on, among other things, the growth of the Company, including its on-site generation business.

Year ended Dec. 31	2026 (forecast)		2021		2015
Total GHG emissions (million tonnes CO2e)		8.1		12.5		32.2

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We estimate our scope 3 emissions in 2021 to be in the range of four million tonnes of CO₂e, which is primarily attributed to our non-operated joint venture interests.

The table below shows the alignment of our climate change management disclosure with TCFD recommendations.

Recommended Disclosures	Location
Governance
Describe the board’s oversight of climate-related risks and opportunities	Oversight by the Board of Directors
Describe management’s role in assessing and managing climate-related risks and opportunities	Role of Senior Management
Strategy
Describe the climate-related risks and opportunities the organization has identified over the short, medium, and long term	Key Scenario Findings
Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy and financial planning	Climate Change Strategy, Key Climate Scenario Findings
Describe the resilience of the organization’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenario	Climate Scenarios, Key Climate Scenario Findings
Risk Management
Describe the organization’s processes for identifying and assessing climate-related risks	Climate Change Strategy
Describe the organization’s processes for managing climate-related risks	Managing Climate Change Risks and Opportunities
Describe how processes for identifying, assessing and managing climate-related risks are integrated into the organization’s overall risk management	Managing Climate Change Risks and Opportunities
Metrics and Targets
Disclose the metrics used by the organization to assess climate-related risks and opportunities in line with its strategy and risk management process	Climate Change Metrics and Targets
Disclose scope 1, scope 2 and, if appropriate, scope 3 greenhouse gas (GHG) emissions and the related risks	Climate Change Metrics and Targets
Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets	Climate Change Metrics and Targets

Engaging with Our Stakeholders to Create Positive Relationships

We strive to create shared value for our stakeholders through social and relationship value creation at TransAlta. The most material impacts on our social and relationship performance are fostering positive relationships with Indigenous neighbours, communities, stakeholders, governments, industry and landowners in the areas where we operate, as well as public health and safety. This section covers sustainability factors of social and relationship capital and intellectual capital as per guidance from the International Integrated Reporting Framework.

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Human Rights

TransAlta is committed to honouring domestic and internationally accepted labour standards and supports the protection of human rights of all its employees, contractors, suppliers, partners, Indigenous partners and other stakeholders. We abide by human rights and modern slavery legislation in Canada, the US and Australia. We have a zero tolerance approach to discrimination based on age, disability, gender, race, religion, colour, national origin, political affiliation or veteran’s status or any other prohibited ground as defined by human rights legislation in the jurisdictions in which we operate. We afford equal opportunities for men and women, support the right to freedom of association and the right to organize unions and bargain collectively. We do not conduct operational human rights reviews or impact assessments, but we do have governance practices in place for the protection of human rights.

Our Human Rights and Discrimination Policy communicates our commitment to human rights in our operations and supply chain to ensure that our personnel policies and practices in our global operations will respect fundamental rights. Expected behaviours of all our employees are set out in our Corporate Code of Conduct. We are committed to creating a work environment where all workers feel safe and are valued for the diversity they bring to our business. In 2021, we launched mandatory Code of Conduct training for employees to complete before signing the Code of Conduct. The training completion rate was 100 per cent. We also have adopted a Supplier Code of Conduct that defines the principles and standards expected of suppliers, their employees and contractors to meet while in the provision of goods and/or services to TransAlta.

Our Whistleblower Policy provides a mechanism for our employees, officers, directors and contractors to report, among other things, any actual or suspected ethical or legal violations. We would seek to remedy the impact promptly in order to establish a corrective action plan in collaboration with the relevant individuals and stakeholders.

In Australia, we report under the Australian modern slavery legislation. Our Modern Slavery Act Statements demonstrate the actions we have taken to assess and address modern slavery risks within our operations and supply chain. These annual statements are approved by our Board of Directors and are publicly available.

Indigenous Relationships and Partnerships

At TransAlta, we value relationships and partnerships with our Indigenous neighbours, aspiring to the highest standards in our relationships with Indigenous people. Our core values of safety, innovation, sustainability, respect and integrity represent how we do business and engage with Indigenous people. Our commitment to Indigenous relations is led by a centralized corporate team who foster a relationship-based approach, involving employees at each facility and within each business unit. These employees and teams build relationships with the neighbouring Indigenous communities and work to develop respectful, trusting relationships that help TransAlta continually improve its business practices.

Our Indigenous Relations Policy focuses on four key areas: community engagement and consultation; business development; community investment; and employment. We ensure that TransAlta’s principles for engagement are upheld and that the Company fulfils its commitments to Indigenous communities. Efforts are focused on building and maintaining solid relationships and strong communication channels that enable TransAlta to: share information regarding operations and growth initiatives; gather feedback to inform project planning; and understand priorities and interests from communities to better address concerns and unlock opportunities.

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Methods of engagement include:

• Relationship building through regular communication and meetings with representatives at various levels within Indigenous communities and organizations;

• Hosting company-community activities to share both business information and cultural knowledge;

• Maintaining consistent communications with each community and following appropriate community protocols and procedures;

• Participating in community events such as pow wows and blessing ceremonies; and

• Providing both monetary and in-kind sponsorships for community initiatives.

TransAlta takes a proactive approach in engagement by initiating communication early in project development to allow concerns to be identified and addressed, minimizing potential project delays. We strive to maintain relationships through the life cycle of our operations, from project development and construction, through operation, until decommissioning phases are complete. We work with communities to build relationships based on a foundation of ongoing communication and mutual respect. This is recognized in our Indigenous Relations Policy, which was recently updated to include our acknowledgement and understanding of the intent of the recommendations of the United Nations Declaration on the Rights of Indigenous Peoples. In addition, TransAlta is a member of the Canadian Council for Aboriginal Business (“CCAB”) and is certified at the Bronze level in the CCAB’s Progressive Aboriginal Relations program.

Participation in Indigenous Ceremonies

In 2021, TransAlta was honoured to participate in three ceremonies with Elders and other representatives from Indigenous communities in Canada: a Water Ceremony with the Aamjiwnaang First Nation; a Water Ceremony with the Wesley First Nation of the Stoney Nakoda Sioux Nations; and a Blessing Ceremony with an Elder from Paul First Nation at the Highvale mine for tree planting.

Support for Indigenous Youth, Education and Employment

TransAlta recognizes the importance of investing in Indigenous students and our financial support helps students complete their education, become self-sufficient and move forward to become future leaders in their communities. We are keen to help young Indigenous students reach their full potential and achieve their dreams. We also believe in providing support to Indigenous primary school students, helping to instill a passion for lifelong learning.

In 2021, TransAlta provided more than $375,000 to support Indigenous youth, education and employment programs, representing 13 per cent of TransAlta’s total community investment. Highlights include:

• Mother Earth’s Children’s Charter School (“MECCS”) – Located in Treaty 6 territory, Alberta, MECCS offers education for students from kindergarten to Grade 9 and is cited as Canada’s first and only Indigenous children’s charter school. The student population is diverse and includes Métis, Cree, Nakota Sioux and Stoney. Volunteers from TransAlta travel to the school to deliver Christmas gifts, providing both our employees and the students the opportunity to engage with each other. Due to the COVID-19 pandemic, this tradition has been conducted remotely. In 2021, more than 200 Christmas gifts were purchased for students at Mother Earth’s Children’s Charter School and Wihnemne School on Paul First Nation.

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• Spirit North – TransAlta is proud to support Spirit North, a national charitable organization that uses land-based activities to improve the health and well-being of Indigenous youth. Through the transformative power of sport and play, participants learn important lessons, discover untold potential and build the confidence and courage needed to overcome the hardships Indigenous youth often face.

• Southern Alberta Institute of Technology Gap Program – This program provides critical financial support needed for aspiring Indigenous students who require high school upgrading in order to qualify for a trade program where there is a “gap” in available funding.

• The Banff Centre for Arts and Creativity – This year, TransAlta continued our ongoing partnership with the Banff Centre and supported scholarship funding for Indigenous community members to participate in leadership training.

• Books In Homes – Funding supports an early literacy program for the children of Tjiwarl Aboriginal Corporation members in Western Australia.

• Mount Royal University Foundation – Continued partnership with the Mount Royal University Foundation in support of the Indigenous Family Housing Program, which features an Indigenous family tipi in an outdoor space dedicated to Indigenous students and supporting Indigenous cultural programming.

• Indspire – Continued support for Indspire, a national Indigenous registered charity. Through this program, 14 bursaries of $3,000 each were given to recipients from the following communities: Blood (Kanai) First Nation, Ermineskin Cree Nation, Enoch Cree Nation, Montana First Nation, Simpcw First Nation and Squamish First Nation.

• Diamond Willow Youth Lodge – In partnership with the United Way of Calgary & Area, designated funding was provided to the Diamond Willow Youth Lodge, a safe place for Calgary Indigenous youth to connect with peers and participate in a variety of programs that promote health and wellness, education and employment preparation.

Indigenous Cultural Awareness Training for TransAlta Employees

In 2021, we adopted a new sustainability target that will see that all employees complete Indigenous cultural awareness training by the end of 2023. We believe education is the foundation to ensuring respectful and strong relationships with Indigenous peoples into the future.

In addition to our training commitment, in 2021 our Indigenous Relations team led three company-wide cultural awareness initiatives in recognition of National Reconciliation Week in Australia and National Indigenous History Month and National Indigenous Peoples Day in Canada.

In 2021, September 30 marked the first National Day for Truth and Reconciliation, which is a federal statutory holiday in Canada and TransAlta chose to adopt this day as one of its statutory holidays. This is an important day for Canadians to take time to pause, reflect and focus to deepen their awareness and understanding of the Canadian residential school system. This day also provides an opportunity to consider how each of us can contribute to ongoing reconciliation with Indigenous peoples. Coinciding with the announcement of unmarked graves of Indigenous school children in British Columbia and Saskatchewan, TransAlta lowered the flags at its Canadian operations for one hour for each grave that was discovered. TransAlta’s Executive Leadership Team delivered a National Day for Truth and Reconciliation Town Hall online event.

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Stakeholder Relationships

Fostering positive relationships with our stakeholders is important to TransAlta. Driven by our core values, we see stakeholder transparency as an integral part of our relationships. We take a proactive approach to building relationships and understanding the impacts our business and operations may have on local stakeholders.

TransAlta Stakeholders

To act in the best interests of the Company and to optimize the balance between financial, environmental and social values for both our stakeholders and TransAlta, we seek to:

• Build relationships through regular engagement with stakeholders regarding our operations, growth prospects and future developments;

• Consider feedback and make changes to project designs and plans to resolve and/or accommodate concerns expressed by our stakeholders; and

• Respond in a timely and professional manner to stakeholder inquiries and concerns and work diligently to resolve issues or complaints.

Our stakeholders are identified through stakeholder mapping exercises conducted for each facility and prospective project development or acquisition. Through decades of establishing stakeholder relationships in the areas of our facilities, we have developed a strong knowledge of who our stakeholders are and have gained understanding of our stakeholders’ issues and concerns.

Our principal stakeholder groups are listed in the following table.

TransAlta Stakeholders
Non-governmental organizations (NGOs)	Community associations and organizations	Connecting transmission facility operators
Regulators	Industry organizations	Communities
Charitable organizations/Non-profit	Standards organizations	Retirees
All levels of government	Media	Residents/Landowners
Suppliers	Business partners	Investor organizations
Contractors	Unions/Labour organizations	Financial institutions
Government agencies	Forest associations/Industry	Mineral rights owners
System operators	Oil & gas associations/Industry	Railroad owners
Customers	Think tanks	Utility owners
Municipalities	Academics	Employees

Stakeholder Engagement

In order to run our business successfully, we maintain open communication channels with our stakeholders. We commit to timely and professional resolution in our dialogue with stakeholders. Our stakeholder engagement practices are guided by regulatory requirements, industry best practices, international standards and corporate policies. We work internally and with each stakeholder to identify and to mitigate further issues.

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Examples of our methods of engagement are listed in the following table.

Information & Communication	Dialogue & Consultation	Relationship Building
Open houses, town halls and public information sessions	In-person meetings with local groups and communities	Community advisory bodies
Newsletters, telephone conversations, emails and letters	Meetings with individual stakeholders (e.g., landowners and residents)	Capacity agreements
Websites	Targeted audience sessions	Sponsorships and donations
Social media postings	Tours of our facilities and sites	Hosting and attending events

A key focus of our work is to support business growth through proactive engagement with stakeholders in our geographic operating areas in Canada, the US and Australia to develop and maintain relationships, assess needs and fit and seek out collaborative and sustainable opportunities. This helps ensure any stakeholder concerns are identified and can be addressed early in the development process, thereby minimizing project delays. We conduct consultation primarily during project development and construction and maintain engaged communication throughout operations to decommissioning. Examples of stakeholder engagement in 2021 include: the WaterCharger Battery Energy Storage Project; the closure of the Highvale mine; the suspension of the Sundance Unit 5 Repowering Project; the coal-to-gas transition at our Alberta plants; and noise and aircraft lighting detection systems at the Antrim Wind Energy facility in New Hampshire.

Customers

TransAlta serves industrial and commercial customers with power and energy services across its fleet in Canada, the US and Australia. We are focused on customer-centred renewables growth to bring high levels of service quality and reliability for our customers in a low carbon future. As one of the largest electricity generators in Canada, our team serves businesses with:

• Sustainable solutions starting from the design phase;

• Energy consumption and cost management solutions;

• Market price risk and volume exposure mitigation; and

• Monitoring of energy market design changes, price signals and applicable and available incentives.

The customer solutions team at TransAlta has maintained a large portfolio of customers in Alberta across a broad range of industry segments, including commercial real estate, municipal, manufacturing, industrial, hospitality, finance and oil and gas.

Across our business in Canada, the US and Australia, we provide on-site generation for large mining and industrial customers. This requires us to be continually engaged with these customers, ensuring that current electricity requirements are provided safely, reliably and cost-effectively with the benefit of lower GHG emissions.

We continue to develop renewable energy facilities to support customers achieving their sustainability goals and targets, such as 100 per cent renewable power targets and/or GHG reduction targets. Production from renewable electricity in 2021 resulted in the avoidance of approximately 2.6 million tonnes of CO₂e for our costumers.

Examples of renewable energy projects in 2021 include our Garden Plain wind project in Alberta, which has a 130 MW capacity and is subject to a PPA with Pembina, our White Rock Wind Projects in Oklahoma with a

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300 MW capacity, which is subject to a PPA with a single offtaker, and our Northern Goldfields Solar Project with a battery energy storage system in Western Australia, which has a 48 MW capacity and is subject to a PPA with BHP.

For further details on how we support our customers’ sustainability objectives, please refer to Applied Technologies in the Technology Adoption and Innovation Focus section of this MD&A.

Energy Affordability

TransAlta focuses on assisting commercial and industrial customers in managing their cost of energy. TransAlta has a full suite of procurement strategies and products with various terms available to our customers to assist in understanding and reducing their energy costs.

For customers interested in making a long-term commitment to obtain predictable costs, TransAlta has the experience to develop renewable energy facilities, battery energy storage systems and hybrid solutions, or long-term offtake agreements from its existing and future renewable and gas-fired facilities.

End-Use Efficiency and Demand

TransAlta’s commercial and industrial customers have access to an extensive set of monthly reports providing detailed tracking of customer usage, allowing for corrective action as required, as well as cost-saving recommendations.

Our Power Factor Report advises the customer of sites that operate at less than a 90 per cent power factor so they can consider installing energy-efficient equipment. By reducing the customer’s power system demand charge through power factor correction, the customer’s site puts less strain on the electricity grid and reduces its carbon footprint. TransAlta’s Site Health Report advises customers of a site whose peak demand has been permanently reduced for a variety of reasons from its initial in-service date. The customer may be paying a higher demand charge each month to the distribution company based on the original peak demand expected at the site. TransAlta collaborates with the customer and determines the new peak demand based on the customer’s operation. The customer, working with the distribution company, may find it economic to buy down the distribution contract to reduce the monthly distribution costs going forward.

Community Investments

In 2021, TransAlta increased its community investments by 36 per cent and contributed approximately $3.0 million in donations and sponsorships (2020 - $2.2 million), with a continued focus in three priority areas: youth and education, environmental leadership, and community health and wellness.

One of our significant community investments each year is to United Way campaigns across Canada and the US. This year, TransAlta employees, retirees, contractors and the Company raised over $1.1 million for the United Way. TransAlta has been supporting the United Way for over 30 years and has contributed more than $20 million over that time. In 2021, TransAlta made a number of other significant investments. Key highlights for the year included:

• Calgary Health Foundation - In 2021, TransAlta partnered with the Calgary Health Foundation to support the Newborn Needs campaign in support of the development of a new Foothills Medical Centre Neonatal Intensive Care Unit (“NICU”), serving all of southern Alberta. TransAlta provided an initial $1 million of support in 2021, as part of a $2 million total commitment over a five-year term. The NICU will be a Centre of Excellence for Calgary, Alberta, Canada and the world.

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• The Calgary Stampede Foundation – Founded in 2017, the TransAlta Performing Arts Studio at Stampede Park continues to provide a year-round facility for the Calgary Stampede Foundation and Calgary’s youth performing arts groups to rehearse, train and celebrate the arts.

• TransAlta Tri-Leisure Centre – The TransAlta Tri-Leisure Centre is a sporting and recreation destination for many active and involved residents from the communities of Parkland County, Spruce Grove and Stony Plain in Alberta. At the facility, thousands of local residents and many of our employees participate in a wide range of sporting and cultural activities and join together in many community causes.

• Calgary Reads – TransAlta was proud to continue to support this organization in 2021, which is dedicated to supporting the improvement of literacy skills for children in Calgary.

• International Women’s Day – As part of TransAlta’s International Women’s Day Celebration, the company provided donations to five organizations that support women in the jurisdictions where we operate:

• Rise Kira House (Perth, Western Australia) – the Rise Kira House is a 24-hour service supporting young women (aged 14-18) leaving family and domestic violence.

• Women’s Interval Home of Sarnia-Lambton (Sarnia, Ontario) – The Women’s Interval Home provides emergency shelter and counselling services to abused women and their children. This includes 24-hour emergency and short-term shelter, support, individual and group counselling, transitional services and child-witness counselling services.

• Elizabeth Fry Society of Northern Alberta (Edmonton, Alberta) – The Elizabeth Fry Society of Northern Alberta partners with communities from Red Deer to Fort McMurray (including rural and Indigenous communities) to address the unique access to justice needs and gaps in services that affect vulnerable individuals.

• Women United (Lewis County, Washington) - Women United’s mission is to positively impact the lives of women and children living in poverty in Lewis County by encouraging self-sufficiency and empowerment. Women United gathers local women who seek to understand the issues facing the community and then roll up their sleeves to help. They operate as an affinity group of the United Way of Lewis County and as such, work within its mission to lift 30 per cent of Lewis County families out of poverty by 2030.

• The Women’s Centre of Calgary (Calgary, Alberta) – The Women’s Centre provides a safe and supportive space accessed by thousands of women in Calgary. Supports include: poverty and hunger, family breakdown, parenting, homelessness, unemployment, health and education, immigration and settlement, domestic violence, isolation and loneliness, life transitions and discrimination. Forty-one per cent of the women who access the services and volunteer their time are living in poverty.

• Calgary Pride – As part of TransAlta’s Pride Celebration in 2021, the company was happy to sponsor the 2021 Calgary Pride Festival and Parade. Calgary Pride aims to create spaces that ensure LGBTQ2+ belonging and celebration. The Calgary Pride Festival and Parade takes place each Labour Day long weekend, with thousands gathering in celebration of gender and sexual diversity.

• Leinster Community School – Funding was provided for an upgrade to the kindergarten playground area to create a new play-based learning environment, focused on sustainability.

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• Heart Kids – Support was provided for the annual 2021 charity walk for Heart Kids, Australia’s only not-for-profit organization solely focused on supporting and advocating for people impacted by childhood heart disease.

• Energy Transition Support – 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. Three funding boards were formed to invest the US$55 million: the Weatherization Board (US$10 million), the Economic & Community Development Board (US$20 million) and the Energy Technology Board (US$25 million). To date, the Weatherization Board has invested US$8 million, the Economic & Community Development Board US$15 million and the Energy Technology Board US$10 million. Specific projects that the boards funded in 2021 include financial support to learning centres (the United Learning Center project, a Boys & Girls Club and the Discover Children’s Museum), a project to install the first renewable energy project in Washington state that generates electricity by harvesting excess pressure from municipal water pipeline, and the installation of a shore power connection point at the Bell Street Cruise Terminal at Pier 66 in Seattle, Washington. The shore power connection will allow vessels with shore power technology to plug into the local electrical grid, which reduces GHG emissions and the burden of diesel exposure to people who live, work and visit along the Seattle waterfront.

Supply Chain and Sustainable Sourcing

We continue to seek solutions to advance supply chain sustainability. As we explore major projects, we assess vendors both at the evaluation stage and as part of 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;

• Estimated number of local Indigenous persons that will be employed;

• Understanding overall community spend and engagement; and

• Understanding the state of community relations through interview processes and stakeholder work.

In 2021, the Board approved our revised Supplier Code of Conduct that applies to all vendors and suppliers of TransAlta. Under this code, suppliers of goods and services to TransAlta are required to adhere to our core values, including as they pertain to health and safety, ethical business conduct and environmental leadership. The code also allows suppliers to report ethical or legal concerns via TransAlta’s Ethics Helpline.

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 Company and other stakeholders to communicate with the Board. For example, employees and other stakeholders may communicate with the Board through the AFRC by writing to the AFRC or by making submissions via the Company’s toll-free telephone or online Ethic Helpline (please refer to Risk Controls — Whistleblower System in the Governance and Risk Management section of this MD&A for more details). Shareholders are also invited to communicate directly with the Board under the Company’s Shareholder Engagement Policy, which outlines the Company’s approach to

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proactive director-shareholder engagement at and between the Company’s annual shareholders meetings. Under the Shareholder Engagement Policy, shareholders can submit questions or inquiries to the Board, to which the Company will respond. Our Shareholder Engagement Policy is available in the Governance section of the Investor Centre on our website. 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 Company’s approach to executive compensation (i.e., say-on-pay).

The Company 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. Throughout 2021, representatives of the Board engaged extensively with the Company’s significant shareholders. Specifically, since Jan. 1, 2021, independent members of the Board have met with 12 shareholders representing approximately 39 per cent of the Company’s total issued and outstanding common shares. In addition, independent members of the Board engaged with Proxy Advisory firms to discuss a number of topics of relevance to the Company and its stakeholders, including the Company’s strategic direction, executive compensation, ESG practices and Board composition and diversity.

Public Health and Safety

We are committed to protecting the public and our assets, as well as the physical, psychological and social well being of our people.

We specifically look to minimize the following risks:

• Harm to people;

• Damage to property;

• Operational liability; and

• Loss of organizational reputation and integrity.

We work to prevent incidents and lower our risk by administering security controls such as restricting physical access around and into our operating facilities. The use of security technology such as surveillance cameras and electronic access is utilized to ensure the control of secure areas. Regular audits and security risk assessments are conducted to ensure continuous improvement of the Security Management Program. Our Security Management Program is focused on the protection of people, property, information and reputation.

The Corporate Emergency Management Program prepares employees should an emergency incident occur. The program includes an emergency management policy and standard, which sets an expectation for employees to continuously prepare for emergencies. The program has executive sponsorship. It provides the overarching framework for each business unit to provide an Emergency Response Plan and Business Continuity Plan. We implement our Incident Command System, which is a standardized on-scene emergency and incident management system that provides an organizational structure able to respond to single or multiple incidents. Designed to aid in the management of resources during incidents, it combines facilities, equipment, personnel, procedures and communications operating within a common organizational structure. It is used as part of an all-hazards approach for incident management and is officially recognized for multi-agency response in emergency situations, however complex.

We develop strong relationships with local emergency responders. We periodically conduct multi-agency training events at our facilities. This ensures continuous improvement and familiarity with our assets and builds strong communication channels for emergency response.

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Our processes designate how we communicate with stakeholders in the event of a crisis. This is managed by our Crisis Communications Team. The team has the responsibility and goal to provide a unified message on behalf of the Company throughout the response and recovery, ensure all messaging is approved by the Incident Commander (the Chief Talent & Transformation Officer, or their designate), co-ordinate messaging with any applicable external agencies and, if necessary, deploy to an incident site.

Annual training requirements are adhered to by our employees operating at our facilities. The results are tracked, audited and presented at our annual executive review. The findings and recommendations assist in maintaining a sustainable program across the organization.

The Company continues to operate under its business continuity plan in response to the global pandemic declared in March 2020. For more information, please refer to COVID-19 in the Significant and Subsequent Events section of this MD&A.

Data and Digital Asset Protection

We work hard to protect our digital assets, including our corporate data and our digital identities that give us access into line of business applications. Cybersecurity risks that work to compromise these assets include the manipulation of data integrity, system and network hacking, use of social engineering tactics through email phishing, compromise of operations and infrastructure through the use of ransomware, credential breaches, attacks introduced through unknowing third-party vendors and service providers, as a well as malware. Given the ever-evolving nature of cyberattacks, we are consistently adapting our cybersecurity program to focus on three key pillars: technology, processes and people. Each of these pillars can be reinforced independently to address specific cyber risks and threats through a comprehensive and multi-faceted program. Through this program, TransAlta continually implements measures and controls to proactively mitigate internal and external cybersecurity risks and threats posed to the organization, and to deal efficiently and effectively with threats.

Please refer to Cybersecurity Risk in the Governance and Risk Management section of this MD&A for further details.

Building a Diverse and Inclusive Workforce

Engaging our workforce, developing our employees, creating a diverse and inclusive work environment and minimizing safety incidents are the keys to human capital value creation at TransAlta and our most material areas for management. In 2021, we improved our ESG performance through our efforts to promote an equitable, diverse and inclusive workforce. This section covers sustainability factors of human capital as per guidance from the International Integrated Reporting Framework.

Equity, Diversity and Inclusion

TransAlta’s commitment and focus on excellence in ED&I is found in our workplace, among our co-workers who at all levels advocate for the core values of equity and inclusion. We believe a strong focus on ED&I will drive performance in innovation, improve service to our customers and positively impact the communities that we all live in.

In 2021, TransAlta’s ED&I Council developed our five-year ED&I strategy to achieve the goals and set out a course to attaining the aspirations set out in our ED&I Pledge. Our five-year ED&I strategy was approved by the Board and sets out key milestones for the annual plans from 2021 to 2025. The first phase of this strategy focuses on raising awareness to build a foundation and common understanding upon which our co-workers can have meaningful conversations to learn about one another. The second phase centres around reinforcing and embedding inclusive behaviours.

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We continued to expand our ED&I platform in 2021 by offering employees a variety of training, education and awareness on ED&I such as webinars, employee engagement sessions, articles, videos and blogs. After completing our inaugural 2020 ED&I Census, which was delivered by a third party and was sent to all employees to understand our demographics and our experiences in the workplace, we put actions into place to address pain points in 2021. This included celebrating International Women’s week and Pride month with several activities, hosting a number of guest speakers on a variety of topics and implementing partnerships for mentorship and Employee Resource Groups opportunities.

Our 2021 ED&I Census results were benchmarked to those of other companies in our industry and within Canada. The results demonstrated a marked improvement of our workforce feeling a greater sense of inclusion and belonging. In addition, our ED&I Census inclusion results were above the energy industry average meeting the inclusion scores of leading ED&I corporations in Canada. In our ED&I Census we received an above industry average response rate of 58 per cent. Of the respondents that completed the ED&I Census, we understand that 30 per cent of the workforce identifies as female, 24 per cent of the workforce identifies with a racial or ethnic minority group, two per cent of the workforce identifies as members of LGBTQ2+ community and 10 per cent of the workforce are people with disabilities.

In 2021, we received market recognition for our ED&I efforts and were certified by a third party for our commitment to measuring, tracking and improving ED&I. We have been recognized for our efforts to measure and set targets to increase diversity, while regularly collecting data on our co-workers’ experiences to identify bias and barriers faced by underrepresented groups and implementing programs and policies designed to unlock specific challenges while tracking results. We have incorporated diversity metrics into TransAlta’s 2021 short-term incentive plan for our employees.

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 gender diversity in our business is evidenced by our female participation rates on both our executive team and Board. As of Dec. 31, 2021, women made up 38 per cent of our executive officer team and 42 per cent of our Board. These percentages are higher than our peers in Canada. Industry research highlights that the percentage of Board seats held by women from all disclosing Canadian TSX-listed companies in Canada is 22 per cent and the average percentage of women on executive teams is 18 per cent.

To further support female advancement, we have set targets to: (i) maintain equal pay for women in equivalent roles, (ii) achieve 50 per cent representation of women on our Board by 2030 and (iii) achieve 40 per cent representation of women among all employees by 2030. Our goal to achieve 40 per cent women across the entire workforce by 2030 is ambitious considering the majority of the operational roles are currently male dominated. Currently, women employees represent 24 per cent of all employees.

TransAlta was once again added to the Bloomberg Gender-Equality Index in 2021. Inclusion in the index recognizes our comprehensive investment in workplace gender equality and our commitment to driving progress by developing inclusive policies and disclosing data using Bloomberg’s gender reporting framework. In 2021, the Company received the Globe and Mail’s Women Lead Here award, which evaluates publicly traded Canadian companies’ ratio of female-identifying to male-identifying executives in the top three tiers of executive leadership.

In 2021, in celebration of International Women’s Day 2021 theme #ChooseToChallenge, TransAlta delivered a week-long campaign to highlight the contributions of women in the workplace with live events in recognition of

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this momentous day as well as training, challenges and a webinar with one of our female Board members. During these celebrations, we launched our Women in Trades Scholarship with 13 different educational institutions for eligible students enrolled in post-secondary trade programs. We are committed to investing in our communities through meaningful impact and the opportunity to enhance the quality of life wherever we operate. The Women in Trades Scholarship is intended to assist women in obtaining an education in trades by showcasing and rewarding successful female role models.

We also pioneered a female apprenticeship program in our Generation business to strategically target the recruitment of high potential female students and train them to gain valuable experiential learning in the trades. The female apprenticeship program has created a pipeline of future female talent for the Company and has resulted in us being able to creatively target, recruit, hire and retain the first-ever female wind technicians, as well as the first females in the roles of instrumentation technician, electrical technician and power plant operator in our gas fleet in Alberta.

Workforce Health and Safety

The safety of our people, communities and the environment is one of our core values. At TransAlta, we operate large and often complex facilities. The environments in which we work, including Canadian winters and the Australian outback, can add additional challenges to keeping our employees, contractors and visitors safe. Each year we invest significant resources into improving our safety performance, including positively enhancing our safety culture. At meetings of more than four people, we have a practice of starting the meeting with a “safety moment,” which helps share key safety learnings across the Company.

TransAlta’s management systems underpin the delivery of safe, reliable and competitive electricity to our customers and partners. Our Total Safety Management System is a combination of recognized best practices in process safety, risk management, asset management, occupational health, safety and environmental management. Since expanding our Occupational Health and Safety program in 2015 to encompass Total Safety, we have transitioned from the development and implementation of this framework into continuous improvement, always striving to achieve our Target Zero vision to operate our business with zero unexpected asset failures and zero environmental, health and safety incidents.

In 2021, we continued to progress our safety culture transformation despite an unprecedented and extraordinary challenge due to COVID-19. To reinforce behavioural safety, several training and capability-building initiatives were delivered. TransAlta conducted 90 one-hour leadership peer board sessions with participation by Generation leaders from across the fleet. We also implemented and rolled-out our fleet-wide app for Occupation Hazard Assessment. This app supports hazard recognition by identifying hazards and associated controls for tasks related to specific occupations.

Our Total Recordable Injury Frequency (“TRIF”) result for 2021 was 0.82 compared to 0.81 in 2020. TRIF tracks the number of more serious injuries, and excludes minor first aids, relative to exposure hours worked. Our TRIF performance year over year has remained relatively unchanged. In 2021, we established an ambitious target of 0.61 and while we did not meet this target, we will continue to work to achieve our goal in the future. In 2021, substantial progress was made on initiatives related to our three key targets: mature our safety culture, assess and address risk tolerance, and standardize safety information and technology. In 2022, we are expanding behavioural safety training to all employees in order to provide them with tools to take control of their behaviours, and consequently, improve our safety results. This training reinforces our journey to create a psychologically safe environment in our workplace as it encourages personal accountability towards safety.

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Safety at TransAlta (employees and contractors)	2021		2020		2019
Lost-time injuries		3		5		5
Medical aids		9		9		7
Restricted work injuries		5		2		3
Exposure hours		4,134,000		3,948,000		4,108,000
Total Recordable Injury Frequency (TRIF)		0.82		0.81		0.73

In addition to TRIF, we have also introduced Total Safety Report Frequency as a key safety metric in our 2021 annual incentive compensation. This is a leading indicator that measures Total Safety Reports (hazard, near miss and positive observations) per worker per year. Total Safety Reports are proactive in nature and demonstrate the actions we are taking to identify and prevent an injury or loss from occurring. In this way, we not only manage incidents if they do occur, but methodically work to prevent them from arising in the first place. In 2021, we recorded 7.35 reports per worker, which is above our target of 5.50.

As a demonstration to TransAlta’s commitment to safety, SunHills Mining LP was awarded the Safety Excellence Award from the Alberta Mine Safety Association in June 2021. This award is for best safety performance of all Alberta mines under one million workforce hours based on 2020 performance.

Organizational Culture and Structure

Our employees are central to value creation. Our corporate culture has evolved and adapted throughout our more than 110-year heritage. Our core values are safety, innovation, sustainability, respect and integrity. These five core values help provide clarity for our employees and guide our behaviour and decision-making. They also provide a foundation for leadership, collaboration, community support, personal growth and work/life balance. Through corporate initiatives and support throughout all levels of leadership, we encourage our employees to maximize their potential.

As of Dec. 31, 2021, we had 1,282 (2020 — 1,476) active employees. This number has decreased by 13 per cent from 2020 levels, following a reduction in positions in our coal fleet as part of our conversions to gas and ceasing mining operations. With approximately 33 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 employees to participate in collective bargaining.

Our organizational structure changed in 2021 to help facilitate effective pace and decision-making in our organization. Our business operates four generating segments, with Gas, Wind and Solar, Hydro and Energy Transition. The Energy Transition is a new segment as described in the Segmented Disclosures under the Segmented Financial Performance and Operating Results section of this MD&A. In addition, our Energy Marketing segment optimizes our asset fleet and trades electricity and other energy commodities. Our Corporate segment, including finance, legal, administrative, business development and investor relations functions, oversees our business and provides strategic alignment. The Company also includes a Shared Services division that oversees our information technology, supply chain, human resources, engineering and accounting functions. The consolidation and centralization of these functions has allowed us to streamline, standardize and, where appropriate, automate these functions while reducing costs and improving service delivery across the organization. Our operations portfolio is run by a single leadership team, which provides operational and financial synergies, enhancing our competitiveness.

TransAlta is committed to improving its internal work environment and the way that employees perceive their work and the Company. We track a broad number of factors to provide us insight into our progress and we use a

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third party to assist us in tracking our progress on an annual basis. We have made continual and notable improvements year-over-year and continue to target further improvements as we look forward.

Employee Retention and Recognition

ESG-Linked Compensation

At TransAlta we have linked our ESG performance to our employees’ compensation, including our executive leadership team. Our corporate executive annual incentive plans (short-term incentive or annual bonus and long-term share incentives) are linked to TransAlta’s performance (i.e., pay for performance). The targets and remuneration framework are reviewed and approved annually by our Board. In 2021, 20 per cent of our corporate annual incentive plan was linked to achieving specific ESG objectives: 10 per cent related to the completion of CO₂ reduction projects at existing facilities and diversity and inclusion and organizational health performance, and 10 per cent was linked to workers’ safety. A further 20 per cent of our corporate annual incentive plan was tied to growth, which is focused on expanding TransAlta’s portfolio of renewable generation and will help reduce the Company’s overall GHG emissions intensity. Our long-term incentive plans include strategic goals related to our focus on clean electricity and strong renewables growth.

Employee Retirement Savings Programs

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 programs, which include various incentive plans designed to align performance with our annual and longer-term targets, as determined annually by the Board.

Retirement savings plans are an example of rewards we provide. We have registered pension and savings plans in Canada and the US. The plans cover substantially all employees of the Company, its domestic subsidiaries and specific named employees working internationally. These plans have defined benefit (“DB”) and defined contribution (“DC”) options. The Canadian and US DB pension plans are closed to new entrants, with the exception of the Highvale mine (SunHills) pension plan acquired in 2013. The US DB pension plan was frozen effective Dec. 31, 2010. The plans are funded by the Company in accordance with governing regulations and actuarial valuations.

We also offer some optional plans for Canadian employees to enhance their financial wellness and retirement savings, with group RRSP and TFSA plans.

In Canada there is an additional non-registered supplemental pension plan (“SPP”) for executive officers whose annual earnings exceed the Canadian income tax limit. The DB SPP was closed as of Dec. 31, 2015, and only current executive officers were grandfathered in the plan. A new DC SPP commenced for executive members hired after Jan. 1, 2016.

In Australia, employees can nominate a superannuation fund for superannuation contributions. The Australian superannuation scheme is compulsory for employers with contributions required at a rate set by the government.

Other Employee Benefit Programs

TransAlta provides competitive benefit programs for most of our employees (options are dependent on the countries in which we operate). We also provide benefit programs based on negotiated union agreements in certain locations. Our flexible benefit plans provide employees and their families with choices of coverage including, among others, extended health, dental, vision, life insurance, critical illness, accident, disability and a health spending account.

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On an annual basis, TransAlta recognizes our top achievements through the President’s Awards. In 2021, we added an ED&I award. This award recognizes employees who significantly contributed towards TransAlta’s target of a 40 per cent female workforce by 2030 and TransAlta’s ED&I objective of creating a workplace where all employees feel they belong.

In 2021, TransAlta launched Wellness Wednesdays. This provides employees with weekly awareness, tips and tools on “wellness” topics. TransAlta’s focus on organizational health remained in 2021 through the implementation of nine priority practices into all facets of the organization.

Talent and Employee Development

Talent and employee development is viewed as a key pillar of organizational health. Investing in our employee development enhances employees’ skills and improves productivity and engagement. This contributes to a strong corporate culture that provides value for TransAlta.

In 2021, we expanded the content and topics in our Professional Development Library, which was launched in 2020. This includes adding a second library for ED&I articles and resources. This library has had over 3,000 hits and over 300 unique users. Important dates and definitions are explained here as well as tips on ED&I best practices such as land acknowledgments and empathetic thinking.

To increase cross-functional internal development opportunities, we created our Opportunity Board. On this Opportunity Board, leaders post opportunities for employees to work on projects within other parts of the organization. Employees then have the opportunity to apply for these projects in order to develop their knowledge and gain experience in a different areas of the business. Eight opportunities were posted, and nine employees were successfully matched to an opportunity during our pilot launch of the board.

Throughout 2021, a Speaker Series of subject matter experts was organized to assist with leadership development and our ED&I journey. Presentation topics included prioritization, constructive conflict, unconscious bias, belonging, allyship, the LGBTQ2+ community and empathy.

Employees and leaders were also offered the opportunity to participate in training focused on working within a remote environment. This training provided leaders and employees with valuable tools to effectively communicate, work productively in a “home” environment and maintain collaboration and connectivity with colleagues across the organization.

Additional internal training is held annually for both leaders and employees. Elevate, a self-directed development program focused on creating a leadership mindset, and Execution Engine, a two-day program that focuses on how to prepare projects, prioritize tasks, improve our communication skills and ensure we are sustaining the work completed by living our health practices. Since launching in 2017, hundreds of employees have participated in these programs.

During 2021, we launched leadership training with Blue Ocean Brain. Partnering with Blue Ocean Brain, a micro-learning consultancy, TransAlta leaders were provided with weekly email drips on best practices relevant to TransAlta’s current interests. In addition, Blue Ocean Brain was also engaged to provide 200 leaders with access to their learning library which contains articles, videos, knowledge checks and leadership briefs.

In addition, we extended our partnership with BetterUp, a consultancy providing professional coaching, to provide 1:1 coaching for over 50 leaders. BetterUp coaching is tailored to the individual’s needs to allow them to work with their personal coach on areas that are important for them. Since our partnership with BetterUp began in October 2019, our leaders have participated in over 640 coaching sessions over 390 hours.

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In 2021, 89 corporate managers and supervisors were enrolled into Sentis’ Zero Incident Process (“ZIP”) training. ZIP training reinforces our journey to create a psychologically safe environment in our workplace as it encourages personal accountability for ourselves and our work, improves decision-making processes, improves safety attitudes and creates a common language to have constructive conversations. In 2022, Corporate employees will be offered ZIP training.

Customer Relationship Training was designed in 2021 by entering a partnership with Vanry Inc. and tailoring the content with input from our managers in Commercial and Customer Relations. This 20-week series of workshops is currently being built and will be completed by 19 customer-facing leaders and employees in 2022. Topics include connecting with customers, listening for what matters, managing requests and building trust.

In 2021, we commenced the design of two leadership development programs – the Manager Development Program and Executive Development Program. These programs are designed to provide leaders with the skills and knowledge to lead in a changing world and the evolving nature with regards to the future of work. Both programs will be launched in 2022. We also launched leadership training on psychological safety, building and maintaining trust and cultural leadership in 2021. This training will be offered to all employees in 2022.

During 2021, TransAlta has had 28 intern and co-op placements with students in various areas of study including business, communications, finance and engineering. To assist in subsidizing the internship and co-op programs, TransAlta continues to partner with Electricity Human Resources Canada to access government funding. Over $150,000 in wage subsidies were received in 2021.

In addition, TransAlta continued to participate in the Canada Alberta Job Grant, which reimburses employers two-thirds of the cost of approved external training. TransAlta is currently approved to receive over $44,000 to cover training costs from 2021.

Advancing Other Sustainability Factors

In the following sections we outline our progress across other material sustainability factors. The sections cover natural, manufactured, intellectual, and social and relationship capital management as per guidance from the International Integrated Reporting Framework.

Progressive Environmental Stewardship

We continue to increase financial value from natural or environmental capital-related business activities, while minimizing our environmental footprint and potential risk factors related to environmental impacts. Adjusted EBITDA from renewable energy generation in 2021 was $584 million (2020 — $353 million). Our revenue in 2021 from environmental attribute sales was $40 million (2020 — $25 million). In addition, in 2021 the sale of coal byproducts and waste-related recycling generated financial value in the range of $15 million to $20 million, which was the same as our range in 2020.

The following are key trends in our natural capital:

Year ended Dec. 31	2021		2020		2019
Renewable energy adjusted EBITDA		584		353		341
Environmental attribute sales revenue		40		25		28
GHG emissions (million tonnes CO2e)		12.5		16.4		20.6

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Environmental Strategy

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 during our clean electricity transition. Our environmental management processes support our corporate strategy of ceasing GHG-intensive coal operations. In 2026, our generation mix will be made up of natural gas and renewable energy only, with a goal of 70 per cent of EBITDA from renewables.

Environmental Policy

Reducing the environmental impact of our activities benefits not only our operations and financial results, but also the communities in which we operate. We have a proactive approach to minimizing environmental risks and we anticipate this strategy will benefit our competitive position as stakeholders and society place an increasing emphasis on successful environmental management. The importance of environmental protection is outlined under our Total Safety Management Policy as a corporate responsibility for TransAlta, and the personal responsibility of each employee and contractor working on TransAlta’s behalf.

Environmental Management System

At TransAlta, we operate our facilities in line with best practices related to environmental management standards. Our environmental management processes are verified annually to ensure we continuously improve our environmental performance. Our knowledge of environmental management systems (“EMS”) has matured since we aligned our processes in accordance with the internationally recognized ISO 14001 EMS standard. 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 via our environmental management practices include land use, water use and waste management.

In addition to our environmental management practices, we are subject to environmental laws and regulations that affect aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of waste and hazardous substances. The Company’s activities have the potential to damage natural habitat, impact vegetation and wildlife, or cause contamination to land or water that may require remediation under applicable laws and regulations. These laws and regulations require us to obtain and comply with a variety of environmental registrations, licenses, permits and other approvals. The environmental regulations in the jurisdictions in which we operate are robust. Both public officials and private individuals may seek to enforce environmental laws and regulations against the Company. We interact with a number of regulators on an ongoing basis, including but not limited to: Alberta Environment and Parks; Ministry of the Environment, Conservation and Parks in Ontario; Ministry of Northern Development, Mines, Natural Resources and Forestry in Ontario; Ministry of Forests, Natural Resource Operations and Rural Development in British Columbia; Environment and Climate Change Canada; Fisheries and Oceans Canada; Michigan Department of Environment, Great Lakes, and Energy; Southwest Clean Air Agency in Washington; Washington State Department of Ecology; Washington State Department of Health; US Environmental Protection Agency; the Department of Agriculture, Water and the Environment in Australia; and the Clean Energy Regulator in Australia.

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Environmental Performance

Our performance on managing environmental aspects, reducing our environmental impact and capitalizing on environmental initiatives includes the following:

Renewable Energy and Battery Storage

Since 2005, we have added over 1,500 MW in renewable electricity capacity. We operate over 900 MW of hydro energy, and we were an early adopter of wind energy and today operate over 1,900 MW of wind power, including battery storage. In 2015, we made our first solar investment in a 21 MW solar facility in Massachusetts, and we continue to look for opportunities to develop and operate solar energy. In 2020, we commissioned the first utility-scale battery storage project in Alberta, located at our Summerview II wind facility. The project uses Tesla battery technology and has a capacity of 10 MW. In 2021, we agreed to provide renewable solar electricity supported with a battery energy storage system to BHP in Western Australia. For more information, please refer to Applied Technologies in the Technology Adoption and Innovation Focus section of this MD&A.

Natural Gas

Natural gas plays an important role in the electricity sector, providing low-emission baseload and peaking generation to support system demands and intermittent renewable generation as part of a clean electricity transition. TransAlta operates simple-cycle, combined-cycle and cogeneration facilities in Canada, the US and Australia. Natural gas facilities provide highly efficient electricity and, in the case of cogeneration, steam production, directly for customers and for wholesale markets. TransAlta is a significant operator of natural gas electricity in Canada and Australia. In 2021, our thermal facilities in Alberta have been fully transitioned to 100 per cent natural gas operation, which generates nearly 50 per cent fewer CO₂ emissions fueled compared to coal. In aggregate, TransAlta has retired 4,064 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to natural gas.

Coal Transition

As a result of our coal retirements and conversions to gas our energy use, GHG emissions, air emissions, waste generation and water usage will significantly decline. Transitioning off coal will eliminate all of our mercury emissions, the majority of particulate matter and sulphur dioxide emissions (“SO₂”), as well as significantly reduce our NO_x emissions. Our converted or repowered facilities will also use lower carbon natural gas, compared to facilities in other jurisdictions, as new methane reduction regulations in Alberta and Canada will reduce GHGs in the production and processing phase with respect to flaring and venting of methane (fugitive GHG emissions).

In 2021, we ceased coal-fired power generation in Canada. Our Centralia coal facility in the US will be retired by the end of 2025. Coal will be entirely eliminated from our operations by the end of 2025.

Energy Use

TransAlta uses energy in a number of different ways. We burn gas, diesel and coal (to the end of 2021 in Canada and the end of 2025 at Centralia) to generate electricity. We harness the kinetic energy of water and wind to generate electricity. We also generate electricity from the sun. In addition to combustion of fuel sources, we also track combustion of gasoline or diesel in our vehicles and the electricity use and fuel use for heating (such as

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natural gas) in the buildings we occupy. Knowledge of how much energy we use allows us to optimize and create energy efficiencies. As an electricity generator, we continually and consistently look for ways to optimize and create efficiencies related to the use of energy.

The following table captures our energy use (millions of gigajoules). Energy use declined by 31 per cent in 2021 over 2020, primarily as a result of reduced coal use. Some values do not sum to the indicated total due to rounding. Zeros (0) indicate truncated values:

Year ended Dec. 31	2021		2020		2019
Hydro		0		0		0
Wind & Solar		0		0		0
Gas		118		138		162
Energy Transition		74		141		184
Corporate and Energy Marketing		0		0		0
Total energy use (million gigajoules)		191		279		346

Air Emissions

Our coal facilities emit air emissions that we track, analyze and report to regulatory bodies. We also work on mitigation solutions depending on the type of air emission. We report our major air emissions from coal, which includes NO_x, SO₂, particulate matter and mercury. We will continue reducing air emissions in our existing fleet through our conversion and retirement of coal units in Alberta (completed in 2021) and Washington State (planned completion by the end of 2025). In 2020, we accelerated our target of 95 per cent SO₂ and 50 per cent NO_x emission reductions over 2005 levels by moving the target date from 2030 to 2026. In addition, we increased the stringency of our reduction levels for NO_x to 80 per cent. Since 2005, we have reduced SO₂ emissions by 90 per cent and NO_x by 77 per cent. We continue to capture 80 per cent of mercury emissions at our coal facilities and, by the end of 2025, mercury emissions will be eliminated following the planned retirement of the Centralia facility. Particulate matter and SO₂ emissions will also be virtually eliminated or considered negligible.

None of our Alberta coal facilities are located within 50 kilometres of dense or urban populations, and they all have been converted to gas in 2021. Our Centralia thermal facility in Washington State is 40 kilometres from a dense or urban population. As per guidance from SASB, “a facility is considered to be located near an area of dense population if it is located within 49 kilometres of an area of dense population” (being deemed to be a “minimum population of 50,000 persons”). The Centralia thermal facility has two units and we retired one unit in 2020 and will retire the additional unit by the end of 2025, at which time air emissions from our coal facilities will be eliminated.

Our gas facilities emit low levels of NO_x that trigger reporting obligations to national regulatory bodies. These gas facilities also produce trace amounts of SO₂ and particulate matter, but at levels that are deemed negligible and do not trigger any reporting requirements or compliance issues. Many of our gas facilities are located in very remote and unpopulated regions, away from dense urban areas. Our Sarnia, Windsor, Ottawa, Fort Saskatchewan and Ada gas facilities are our only facilities with air emissions within 49 kilometres of dense or urban environments.

Our total air emissions in 2021 decreased compared with 2020 levels. Specifically, NO_x was reduced 29 per cent, particulate matter was reduced 80 per cent and SO₂ was reduced 42 per cent over 2020 levels. Mercury emissions also decreased by 33 per cent over 2020 levels. Reductions in emissions were primarily due to shutdowns during coal-to-gas conversions and coal unit retirements.

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The following table represents our material air emissions. Figures have been rounded to the nearest one thousand with the exception of particulate matter (rounded to the nearest one hundred) and mercury (rounded to the nearest ten):

Year ended Dec. 31	2021		2020		2019
SO2 (tonnes)		7,000		12,000		16,000
NOx (tonnes)		15,000		21,000		26,000
Particulate matter (tonnes)		790		4,000		8,000
Mercury (kilograms)		40		60		60

Water

Our principal water use is for cooling and steam generation in our coal and gas facilities but our hydro operations also require water flow for operations. Water for coal and gas operations is withdrawn primarily from rivers where we hold permits and must adhere to regulations on the quality of discharged water. The difference between withdrawal and discharge, representing consumption, is due to several factors, which include evaporation loss and steam production for customers. Typically, TransAlta withdraws in the range of 220-240 million m³ of water across our fleet. In 2021, we withdrew approximately 240 million m³ (2020—230 million m³) and returned approximately 210 million m³ (2020 — 200 million m³) or 87 per cent. Overall, water consumption was approximately 30 million m³ (2020 — 40 million m³). Water consumption was lower in 2021 primarily due to shutdowns during coal-to-gas conversions and coal unit retirements.

Our water consumption reduction target is to reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m³ or 40 per cent in 2026 over a 2015 baseline. Water consumption in 2015 was 45 million m³. This target is in line with the UN SDGs, specifically “Goal 6: Clean Water and Sanitation.” Our water consumption will fluctuate somewhat over the period of 2020-2025 as we transition off coal, convert and repower gas facilities and ramp production upwards.

The following represents our total water consumption (million m³) over the last three years. Some values do not sum to the indicated total due to rounding. Figures below have been rounded to the nearest 10 million m³:

Year ended Dec. 31	2021		2020		2019
Water withdrawal		240		230		260
Water discharge		210		200		220
Total water consumption (million m3)		30		40		40

Our largest water withdrawal and discharge occurs at our Sarnia gas cogeneration facility (which produces both electricity and steam for our customer). The facility operates as a once-through, non-contact cooling system for our steam turbines. Despite large withdrawals from the adjacent St. Clair River to support our Sarnia operations, we return approximately 93 per cent of the water withdrawn. Water from this source is currently at low risk as per analysis from the SASB-endorsed Aqueduct Water Risk Atlas tool.

The Aqueduct Water Risk Atlas tool highlights that water risk is high at our interior and southern Western Australia facilities due to high interannual variability in the region. Interannual variability refers to wider variations in regional water supply from year to year. Our water supply at these facilities is provided at no cost under PPAs with our mining customers, hence our risk is significantly mitigated. In addition, our customers have developed conservation and re-use strategies aimed at recycling water for mining operational needs. All water used in the region is sourced from scheme water, and with respect to gas and diesel turbine water use, water wash

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techniques and frequency of activities are continually modified to minimize consumption and environmental impact. Water used in our operations is returned to our customers, who repurpose this water for vegetation and dust suppression in their mining operations.

At the South Hedland facility in Western Australia, water risk is also high due to the risk of flooding in the region. The South Hedland facility was built above normal flood levels to mitigate potential risk from flooding. During a category 4 cyclone event in the area and associated flooding in the region in 2019, the South Hedland facility stayed dry and continued to generate power for the region. In addition, the South Hedland facility has developed a Water Efficiency Management Plan with Water Corporation WA, the principal supplier of water, wastewater and drainage services in Western Australia. Initiatives are aimed at reducing water consumption and costs through innovative technology and efficiencies identified through facility management.

In southern Alberta, our hydroelectric facilities have played an increasingly important water management role following the flood of 2013. In 2021, we renewed for another five years our previous 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.

Waste

The importance of environmental protection and managing waste is outlined in our Total Safety Management Policy as a corporate responsibility for TransAlta, and a responsibility of each employee and contractor working on TransAlta’s behalf. Our waste data is reported annually to a number of different regulatory bodies.

Our waste reduction target is that by 2022 TransAlta will reduce total waste generation by 80 per cent over a 2019 baseline of 1.5 million tonnes equivalent of waste generation. This is in line with the UN SDGs, specifically, “Goal 12: Responsible Consumption and Production.”

In 2021, our operations generated approximately 515,000 tonnes equivalent of waste (2020 — 1.1 million tonnes). Of the total waste generated, 95 per cent was non-hazardous waste and 5 per cent was hazardous waste. In 2021, only 0.2 per cent of total waste generated was directed to landfill. Our 2020 waste data was revised in 2021 after we received final waste manifests as part of the reclamation project at our Mississauga facility. As a result, approximately 23,000 tonnes equivalent were added to Mississauga in multiple waste categories in 2020.

The following represents our total waste production over the last three years. Figures have been rounded to the nearest one thousand:

Year ended Dec. 31	2021		2020		2019
Total waste generation (tonnes equivalent)		515,000		1,135,000		1,533,000
Waste to landfill (tonne eq.)		1,000		11,000		1,000
Waste recycled (tonne eq.)		31,000		31,000		6,000
Waste reuse (tonne eq.)		176,000		533,000		746,000
% of total waste to landfill		0.2		1		0.07
% of total waste: hazardous		5		2		1
% hazardous waste to landfill		0.9		0.4		0.6

Our reuse waste or byproduct waste is generally sold to third parties. Byproduct sales and associated annual revenue generation typically ranges from $15 million to $20 million. Our operating teams are diligent at not only minimizing waste, but also maximizing recoverable value from waste. We have invested in equipment to capture

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Management’s Discussion and Analysis

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.

Given our transition off coal, we ceased producing fly ash waste in Canada at the end of 2021 and will no longer produce it past the end of 2025 in the US. The Company is looking at recovering fly ash that was returned to its original source at Highvale mine to replace this supply, which is used extensively in the concrete industry. By turning the recovered product into something marketable, it will continue to aid in reducing the amount of cement produced and consequent emissions while offering new job and economic growth opportunities. This innovative technology contributes to a circular economy and will reduce reclamation liabilities for TransAlta.

Biodiversity

The importance of environmental protection and biodiversity is outlined in our Total Safety Management Policy as a corporate responsibility for TransAlta, and a responsibility of each employee and contractor working on TransAlta’s behalf.

Overseeing biodiversity-related issues

TransAlta’s GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Company’s monitoring of environmental regulations, public policy changes and the development of strategies, policies and practices for the environment. For further information, please refer to the Sustainability Governance section of this MD&A.

Assessing biodiversity impacts of our value chain

We consider the biodiversity impact at all of our existing operations (a greater focus has been given to mining operations) and the biodiversity impacts of all new growth projects are evaluated in line with regulatory compliance and with respect to TransAlta’s focus on biodiversity health. Details on how we asses biodiversity impacts of our value chain are presented in the sections below.

Growth

Each new TransAlta development project must complete an in-depth environmental assessment (as prescribed by the local regulation and in line with our own assessment practices) describing baseline environmental conditions, identifying potential effects and developing mitigation strategies for identified environmental sensitivities prior to construction and operation. These assessments have been specifically designed to meet the environmental information requirements of the respective regions in which we operate while identifying alignment with the intent of the standards and/or regulations applicable to these jurisdictions (e.g., Wildlife Directive for Alberta Wind Energy Projects, US Fish & Wildlife Service Land-Based Wind Energy Guidelines, etc.). Typically, our renewable projects are greenfield development projects that require a higher level of evaluation compared to our gas projects, which integrate into existing industrial facilities.

In addition, TransAlta provides a detailed wildlife mitigation plan to environmental regulators outlining specific measures that will be employed to mitigate the effects that project construction and operation activities may have on wildlife, wildlife habitat and specific wildlife features identified during environmental studies completed during the development stage.

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Management’s Discussion and Analysis

Each greenfield development project has a detailed stakeholder consultation plan designed to ensure all potentially impacted host landowners, stakeholders, agencies, businesses, non-governmental organizations (“NGOs”), environmental NGOs and Indigenous communities understand the nature of the projects, have multiple and varied opportunities for engagement and feedback, and are able to engage in meaningful dialogue and discussion with TransAlta and its representatives. The ultimate goal is addressing, solving and mitigating stakeholder or Indigenous community biodiversity concerns before filing major permit applications for all of our projects.

Day-to-day operations

At our Alberta operations, in 2021 we continued with our Wildlife Monitoring Program designed to monitor wildlife abundance and species diversity in the study area over time. Based on these surveys, TransAlta has seen primarily stable or increasing biodiversity in the area, with various new bird species being detected over the years and incidents of vehicle collisions decreasing due to lower speed limit restrictions. Some animal population sizes fluctuate in the area based on weather conditions and available ground cover.

Our natural gas operations have a relatively limited impact on biodiversity. The facilities are frequently constructed adjacent to existing industrial operations, and TransAlta may not always be the holder of the environmental permits. The land area these facilities occupy is also generally relatively small. One exception is our Sarnia cogeneration facility. This facility is made up of 260 acres of brownfield industrial land, some of which contains areas with tall grasses and potential wildlife. Care will be taken at the time of redevelopment of this land to minimize impact to species-at-risk through the completion of species-at-risk surveys as well as performing certain construction activities outside of nesting periods. For all sites that are under our environmental scope, we adhere to all relevant environmental compliance permits.

At our hydro facilities, a major focus is on reducing the impact on fish and fish habitat. We adhere to provincial and federal regulations and operate in accordance with facility approvals. We continue to work toward operational improvement and regularly review our Environmental Operational Management Plans to ensure our operating parameters are met.

At our wind and solar operations, the business unit has established the WiSPER (Wind Stewardship Planning and Environmental Reporting) Program. The goal of the program is to provide continuous improvement and ongoing environmental monitoring programs beyond TransAlta’s regulatory requirements. This is achieved through periodic verification and inspection programs, and through collaboration with industry and the scientific community to address environmental concerns and impacts. An Operational Environmental Management Plan has been developed for each renewable asset to ensure that our facilities use environmentally sound and responsible practices that are based on a philosophy of continuous improvement of environmental protection through a program of inspection, monitoring and review.

Examples of WiSPER initiatives to support our biodiversity focus include our Avian Protection Program (installation of covers to protect birds from possible electrocution), a bird and bat mortality database (records all injuries and mortalities), environmentally sensitive resource monitoring (monitoring sensitive wildlife features in and around our operating wind facilities such as raptor nests and sharp-tailed grouse leks), long-term dataset collections (e.g., wildlife studies pre-construction and post-construction) and community wind education programs.

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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 and we have adopted a target to fully reclaim this mine by 2040. Reclamation work continued on the Centralia mine in 2021, including the planting of 23,330 trees.

Our Highvale mine in Alberta ceased operations on Dec. 31, 2021, as part of our target to discontinue coal-fired power generation in Canada at the end of 2021. The mine reclamation has been progressively executed as part of our regulatory approvals, and our target is to have it fully reclaimed by 2046. Approximately 26,000 trees were planted in 2021 at our Highvale mine. In 2021, our reclamation team obtained regulatory approval for our interim reclamation plans, until submission of final reclamation plan in 2022. The updated plans align with community priorities for the reclaimed land. Our reclamation plans at Highvale 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. Across our mining operations, to date we have reclaimed approximately 12,000 acres (4,800 hectares), which is approximately 38 per cent of land disturbed.

Environmental Incidents and Spills

Minimizing our impact on the environment supports healthy ecosystems and mitigates our environmental compliance risk and reputational risk. We maintain corporate incident management procedures, as part of our Total Safety Management System, for appropriate initial response, investigation and lessons learned to minimize environmental incidents. With respect to biodiversity management (management of ecosystems, natural habitats and life in the areas we operate), we seek to establish robust environmental research and data collection to establish scientifically sound baselines of the natural environment around our facilities to ensure we can accurately evaluate the level of significance to biodiversity following an incident. We closely monitor the air, land, water and wildlife in these areas to identify and curtail potential impacts.

In 2021, we recorded two regulatory non-compliance environmental incidents (2020 – two incidents). One incident occurred at our Sarnia cogeneration facility and was a wastewater discharge exceedance from our neutralization sump during water treatment. The second incident was related to regulatory compliance at our Centralia facility that resulted in an environmental permit exceedance when a worker opened the incorrect fan breaker. Both incidents had negligible environmental impacts, but the Centralia incident resulted in one enforcement action and a US$3,100 fine from the regulator.

Regulatory non-compliance environmental incidents follow:

Year ended Dec. 31	2021		2020		2019
Regulatory non-compliance environmental incidents		2		2		6

Regarding spills and releases, typical spills that could occur at our operation sites are hydrocarbon-based. Spills generally happen in low environmental impact areas and are almost always contained and fully recovered. It is extremely rare for large spills to occur. Efforts are placed on providing immediate response to all environmental spills to ensure assessment, containment and recovery of spilled materials result in minimal impact to the environment.

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Management’s Discussion and Analysis

The estimated volume of spills in 2021 was 6 m³ (2020 — 4 m³). Spill volumes in 2021 were higher due to one environmental incident recorded at our Centralia facility. The incident involved the release of mineral oil due to the failure of a phase generator step-up transformer. Spill response and control efforts were initiated immediately following the incident and environmental impacts were negligible and minimized due to the efficient response.

Significant environmental incidents follow:

Year ended Dec. 31	2021		2020		2019
Significant environmental incidents		0		6		3

There is a potential that ash ponds associated with our remaining coal facilities could fail. The probability of this occurring is low, but the impact could be significant. We follow applicable environmental regulations with respect to our ash ponds and satisfy ourselves that management is adequate given the robust regulations in the jurisdictions where we operate. Management includes periodic inspections and appropriate mitigation if issues are uncovered.

Weather

Abnormal weather events can impact our operations and give rise to risks. 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 facility. 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. Accumulated ice can have a significant impact on energy yields and could result in the wind turbine experiencing more downtime. 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.

Our generation facilities and their operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g., floods, strong winds, wildfires, earthquakes, tornados and cyclones), 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 that disrupts the operation or ability of the generation facilities to produce or sell power for an extended period, including events that preclude existing customers from purchasing electricity, could have a material adverse effect. 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.

During the past three years, we have experienced no significant impacts to annual financial results due to deviations from expected weather patterns.

Please refer to the Governance and Risk Management section of this MD&A for further discussion on weather-related risks.

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Management’s Discussion and Analysis

Reliable, Low-Cost and Sustainable Energy Production

TransAlta’s goal is to be a leading customer-centred clean electricity company, one that is committed to a sustainable future. Our strategy is focused on meeting our customers’ need for clean, low-cost and reliable electricity, operational excellence and continual improvement in everything that we do, which is a core ethos of our company. This section covers manufactured, intellectual, and social and relationship capital management as per guidance from the International Integrated Reporting Framework.

Brand Recognition

Our business resilience is enhanced by a purpose-based, long-term and sustainable business strategy: growth in renewable electricity, optimization of our existing natural gas generation, and a commitment to sustainability. TransAlta has operated power-generation assets for over 110 years, which reflects this approach to long-term and sustainable business practices. A long-term commitment to business and partnerships lends itself to goodwill and brand recognition, something we value and do not take for granted. We believe our low-cost and clean electricity strategy, supported by our internal values and sustainable approach to business, will help reinforce and continue to increase our positive brand recognition.

Diversified Knowledge

At TransAlta, we define intellectual capital as our knowledge-based assets. Measuring these assets serves two purposes. First, we seek to understand them so we can improve their management and performance. Second, we seek to understand these assets to communicate their real value. The experience and acumen of our employees enhances our value creation. Our experience in developing and operating power-generation technologies extends to over 110 years, and many of our employees have worked with us for over 30 years. Our energy marketing business complements our knowledge of operating power-generation assets.

Our experience in developing and operating power-generation technologies is highlighted below.

Power-Generation Type	Operating Experience (years)
Hydro		110
Natural Gas		71
Coal		71
Wind		19
Solar		6

For further details, please refer to Customers in the Engaging with Our Stakeholders to Create Positive Relationships section of this MD&A.

Grid Resiliency

As a large electricity generator, TransAlta works diligently to ensure the power we provide our customers is reliable, affordable and has low environmental impact. We provide decentralized and customized power solutions to industrial customers. In 2021, TransAlta agreed to build the Northern Goldfields Solar Project in Western Australia to provide renewable solar electricity supported with a battery energy storage system to the Goldfields-based operations of BHP. We also supply power to centralized power systems and own and operate transmission grid infrastructure in Alberta that addresses system reliability needs.

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Management’s Discussion and Analysis

In all jurisdictions where we operate, we work closely with the system operators to ensure overall supply adequacy and reliability of the grid. We consider a myriad of factors in our planning and operation decisions that could put grid resiliency at risk, including renewable energy intermittency, cyberattacks, extreme weather events and natural disasters. We are also committed to ensuring strong compliance with North American Electric Reliability Corporation standards and Alberta Reliability Standards for the power plant and transmission infrastructure that we own and operate.

As a Company, we are keenly focused on deploying clean power generation and new technology solutions to meet the emerging and future needs of the electric system that we operate in. For example, in Alberta, we brought online the first battery storage project, called WindCharger, in 2020 that is co-located with our Summerview II wind facility to create an emissions-free, peaking resource. This resource is participating in the AESO’s pilot fast frequency response initiative to support intertie operations. Beyond the fast frequency response initiative, WindCharger introduces a resource with a response time that is unmatched by existing generation technologies and can be operated with a high level of reliability to support the growing need for inertial response and resiliency to support a decarbonized grid with a supply mix made up of intermittent renewable resources.

For more information on technologies to support grid resiliency, please refer to Applied Technologies in the Technology Adoption and Innovation Focus section of this MD&A. For more guidance on cyberattacks, please refer to Public Health and Safety in the Engaging with Our Stakeholders to Create Positive Relationships section of this MD&A. For more information on extreme weather events and natural disasters, please refer to Weather in the Progressive Environmental Stewardship section of this MD&A.

Technology Adoption and Innovation Focus

Technology and innovation are an existing and increasing focus at TransAlta. As we navigate significant macro changes from energy transition, the impacts of climate change and decarbonization, and the continued rise of digital technology, automation and artificial intelligence, we are proactively applying technology solutions across our business. Our conversion of coal units to gas is an excellent example of utilizing useful manufactured capital or infrastructure. We also continue to adopt and apply innovative solutions to meet customer demand for power.

Idea Generation and Project Management

Our Greenlight program continues to be a driving force behind the strong culture of idea generation and problem solving at TransAlta. Led by our Transformation Office, the program emphasizes bottom-up innovation, which means business improvement ideas are generated by employees. These ideas are developed and advanced into business cases, adhering to best practices of project management, to ensure successful implementation of the improvement opportunity. From the initial ideation, to development and delivery, this process is driven entirely by employees, with support from management and the Transformation Office.

Another initiative we promote is the Supplier Innovation Series, which brings in guest speakers from outside TransAlta to discuss innovation. This includes thought leaders on new technologies to discuss conceptual ideas that initiate creative thinking and suppliers that provide insight into commercial applications of evolving technologies. In 2021, we delivered seven sessions on topics such as artificial intelligence, behaviours for achieving success, frontline and corporate worker apps, hydrogen, mobile robots, robotic inspections for boiler and piping systems, and strategic foresight. For further details on how we invest in our workforce, please refer to Talent and Employee Development in the Building a Diverse and Inclusive Workforce section of this MD&A.

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Management’s Discussion and Analysis

Infrastructure Innovation

In 2015, the Government of Alberta introduced regulations designed to end coal-powered generation in the province by 2030. A number of our coal facilities had useful lives beyond 2030 and could be converted to use natural gas. In 2021, our Sundance Unit 5 facility was retired, and Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 were converted to natural gas. This means TransAlta’s thermal facilities in Alberta have been fully transitioned to 100 per cent natural gas operation. In aggregate, the Company has retired 4,064 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to cleaner-burning natural gas. Overall, the converted units generate nearly 50 per cent fewer CO₂ emissions fueled by natural gas compared to coal. Repurposing the facilities rather than decommissioning them supports the concept of reuse and aligns with the UN SDGs, specifically “Goal 9: Industry, Innovation and Infrastructure.” The completed conversions and the closure of the Highvale coal mine also contribute to the goals of the Powering Past Coal Alliance, which TransAlta joined at COP26.

Applied Technologies

TransAlta has been at the forefront of innovation in the power-generation sector since the early 1900s when we developed hydro assets. 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 that monitors, to the second, 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 and in 2020 we installed the first utility-scale battery in Alberta at our Summerview II wind facility. As we balance growth with decarbonization, we continue to seek solutions to innovate and create value for investors, society and the environment.

In early 2021, TransAlta entered into a long-term PPA with Pembina for the offtake of 100 MW from our proposed 130 MW Garden Plain wind project, to be located in Alberta. The project began in 2021, with a target commercial operation date in the second half of 2022. In late 2021, TransAlta entered into two long-term PPAs for the offtake of 100 per cent of the generation from its 300 MW White Rock Wind Projects located in Oklahoma. Contracting the renewable electricity and environmental attributes to an outstanding new customer with an AA credit rating from S&P Global Ratings enables TransAlta to move into the construction phase expected to begin in late 2022 with a target commercial operation date in the second half of 2023. The delivery of low-cost, reliable and clean energy from Garden Plain and White Rock supports our customers’ sustainability goals and represents another step towards executing our growth plan of delivering 2 GW of capacity by 2025, which was announced in September 2021.

TransAlta is actively advancing its development pipeline, which currently consists of 800 MW in the US, up to 2 GW in Canada and 270 MW in Australia. In 2021, TransAlta acquired a 122 MW portfolio of operating solar sites located in North Carolina, which will represent a significant expansion of our solar generation. We intend to further expand our solar generation by actively pursuing solar opportunities in the US and Australian markets. The Company is also focused on pursuing hybrid integrated power solutions with customers.

We continue to invest in battery storage. In 2021, TransAlta agreed to provide renewable solar electricity supported with a battery energy storage system to the Goldfields-based operations of BHP through the construction of the Northern Goldfields Solar Project in Western Australia. The project consists of the 27 MW Mount Keith Solar Farm, 11 MW Leinster Solar Farm and 10 MW/5 MWh Leinster Battery Energy Storage System and interconnecting transmission infrastructure, all of which will be integrated into TransAlta’s 169 MW Southern Cross Energy North remote network. The network and new generation will support BHP to meet its emissions reduction targets and to deliver lower carbon, sustainable nickel to its customers. The Northern Goldfields Solar Project is expected to reduce BHP’s scope 2 electricity GHG emissions from its Leinster and Mount Keith operations by 540,000 tonnes of CO₂e over the first 10 years of operation. Construction of the project commenced in early 2022 and commercial operations are targeted in late 2022.

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Management’s Discussion and Analysis

Our teams continuously explore the use of applied or new technologies such as hydrogen and CCUS to find solutions and to expand or adapt our fleet. This helps protect our shareholder value and maintain delivery of reliable and affordable electricity to our costumers. We know that new technologies will emerge over the next number of years as the industry continues to drive towards lower emissions while maintaining a reliable and affordable product for customers.

Asset Analytics and Optimization

TransAlta’s Asset Analytics and Optimization (“AAO”) team, formerly the Operations Diagnostic Centre, was founded in 2008. This team monitors coal-fired steam, gas-fired steam, simple-cycle, combined-cycle/cogeneration and wind-generating assets across Canada, the US and Australia. A centralized team of engineers and operations specialists remotely monitors our power facilities for emerging equipment reliability and performance issues.

AAO staff are trained in the development and use of specialized equipment monitoring and performance assessment software and they apply their experience to power facility operations. If an issue is detected, the AAO will initially assess and then notify facility operations of their findings to support investigation and remedy of the issue before there is an impact to operations. This support is critical for reliability and performance of our operations. By way of example, if a wind turbine starts to show very early signs of equipment change compared to others, our operation team is notified and will work to investigate and remedy the issue. The monitoring, analysis and diagnostics completed by the AAO are focused on early identification of equipment issues based on longer-term trend analysis and complements day-to-day facility operations.

The AAO team also performs production reporting functions for the coal-fired steam, gas-fired steam, simple-cycle, combined-cycle/cogeneration and wind-generating assets, and are actively engaged in projects to improve this reporting.

Data and Innovation

TransAlta created the Data and Innovation team in 2019 to modernize its data infrastructure to take advantage of new opportunities in analytics and data science. The Data and Innovation team is cross-functional, composed of data architects, data scientists, data analysts, software developers, engineers, project managers, and financial and systems analysts. The team focuses its efforts on the delivery and enhancement of TransAlta’s Modern Data Architecture, the rapid delivery of data-driven applications, the design and implementation of machine learning and artificial intelligence models and the advancement of process automation through the Robotic Process Automation Centre of Excellence. In 2021, the Data and Innovation team worked with partners across the business to create new decision support tools and processes that improve our financial position and return capacity to our people. A few of the highlights from this work include:

• GenOS is a digital platform that provides near real-time performance awareness and operational decision support for our Generation fleet. By packaging the analytics and data science models of our operational data into a central platform, we are able to intuitively deliver insights to the Operations teams that drive real revenue increases and a reduction in costs. Built in-house, we have focused on onboarding our Wind and Solar fleet and have begun work with the Gas and Hydro teams.

• Industry partnership with AltaML Applied AI Lab, a groundbreaking initiative that focuses on building and expanding local talent while improving our business through the application of machine learning and artificial intelligence. The 2021 cohort worked on 11 data science use cases including building an energy market peak prediction model for our Trading team and a river flow forecasting model for our Hydro operations.

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Management’s Discussion and Analysis

Sustainability Governance

In order for an organization to truly integrate sustainability, it requires accountability at the Board and executive level. It requires an understanding of ESG issues and associated corporate actions to address these issues, while continuing to balance operations and growth.

Sustainability is overseen by TransAlta’s GSSC of the Board. The GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Company’s monitoring of climate change, environmental, health and safety regulations, public policy changes and the development of strategies, policies and practices for climate change, environment, health and safety, and social well-being, including human rights, working conditions and responsible sourcing.

The following policies help govern sustainability at TransAlta, and are publicly available in the Governance section of the Investor Centre on our website:

• Corporate Code of Conduct

• Supplier Code of Conduct

• Whistleblower Policy

• Total Safety Management Policy

• Human Rights and Discrimination Policy

• Indigenous Relations Policy

• Board and Workforce Diversity Policy, and Diversity and Inclusion Pledge

Our sustainability memberships include key sustainability organizations and working groups such as the EXCEL Partnership, the Canadian Business for Social Responsibility and the Canadian Electricity Association Sustainable Electricity Steering Committee, which all provide validation and support of our sustainability strategy and practices.

For additional details on governance, please refer to the Governance and Risk Management section of this MD&A.

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 a 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;

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Management’s Discussion and Analysis

• The Chair of our Board and all directors, other than our President and CEO, are independent within the meaning of National Instrument 58-101 — Disclosure of Corporate Governance Practices;

• 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 Company; 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; they outline 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 Company and ensures that the Company 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 Company’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 of the Board’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 AFRC, GSSC, the Human Resources Committee (the “HRC”) and the IPC.

The AFRC, 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

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Management’s Discussion and Analysis

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 AFRC approves our Commodity and Financial Exposure Management policies and reviews quarterly ERM reporting.

The GSSC is responsible for developing and recommending to the Board a set of corporate governance principles applicable to the Company and for monitoring 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 Company’s monitoring of climate change, environmental, health and safety regulations, public policy changes and the development of strategies, policies and practices for climate change, environmental, health and safety, and social well-being, including human rights, working conditions and responsible sourcing. The GSSC also receives an annual report on the annual codes of conduct certification process. For further information on the Board’s oversight of climate-related factors, please refer to the Climate Change Governance in Environmental, Social and Governance (“ESG”) section of this MD&A.

In regards to overseeing and seeking to ensure that the Company 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 Company’s business; iv) reviewing with management the EH&S policies of the Company; v) reviewing with management the health and safety practices implemented within the Company, as well as the evaluation and training processes put in place to address problem areas; vi) discussing with management ways to improve the EH&S processes and practices; and vii) reviewing the effectiveness of our response to EH&S issues and any new initiatives put in place to further improve the Company’s EH&S culture.

The HRC is empowered by the Board to review and approve key compensation and human resources policies of the Company that are intended to attract, recruit, retain and motivate employees of the Company. The HRC also makes recommendations to the Board regarding the compensation of the 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 IPC is empowered by the Board to oversee management’s investment conclusions and the execution of major, Board-approved capital expenditure projects that further the Company’s strategic plans. The IPC provides assistance to the Board in fulfilling its oversight responsibilities with respect to broadly reviewing and monitoring project management and control processes, financial profile, capital costs, procurement practices, and project schedules in a more in-depth manner than time permits during regularly scheduled Board meetings.

The responsibilities of other stakeholders within our risk management oversight structure are described below:

The CEO and executive management review and report on key risks quarterly. Specific Trading Risk Management reviews are held monthly by the Commodity Risk and Compliance Committee, and weekly by the commodity risk team, the commercial managers in Trading and Marketing, and the Executive Vice-President, Finance & Trading and Chief Financial Officer.

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Management’s Discussion and Analysis

The Investment Committee is a Management committee chaired by our Senior Vice President, M&A, Strategy and Treasurer and is also comprised of the CEO, Executive Vice-President, Finance & Trading and Chief Financial Officer, Chief Operating Officer, and Executive Vice-President, Legal, Commercial and External Affairs. It reviews and approves all major capital expenditures including growth, productivity, life extensions and major coal outages. Projects that are approved by the Investment Committee will then be put forward for approval by the Board, if required.

The Commodity Risk & Compliance Committee is chaired by our Executive Vice-President, Finance & Trading and Chief Financial Officer and is comprised of at least three members of senior management. 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.

The Hydro Operating Committee consists of two members who are Brookfield employees with expertise in hydro facility management, and two TransAlta members. This committee was formed in 2019 for the purpose of collaborating on matters in connection with the operation, and maximization of the value, of TransAlta’s Alberta Hydro Assets. It is delivering on its objectives by reviewing the operating, maintenance, safety and environmental aspects of TransAlta’s Alberta Hydro Assets and, following that review, providing expert advice and recommendations to TransAlta’s hydro operational team. The Hydro Operating Committee has an initial term of six years, which can be extended for an additional two years.

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 most recent management information circular.

Global Pandemic

We have adopted a number of risk mitigation measures in response to the COVID-19 pandemic. The Board and management is monitoring the development of the outbreak and are continually assessing its impact on the Company’s operations, supply chains and customers, as well as, more generally, to the business and affairs of the Company. Potential impacts of the pandemic on the business and affairs of the Company include, but are not limited to: potential interruptions of production, supply chain disruptions, unavailability of employees at TransAlta, potential delays in growth projects, increased credit risk with counterparties and increased volatility in commodity prices and the valuations of financial instruments. In addition, the broader impacts to the global economy and financial markets could have potential adverse impacts on the availability of capital for investment and the demand for power and commodity pricing.

To manage the risks resulting from COVID-19, we continue to take a number of steps in furtherance of the Company’s business continuity efforts:

Management Responses

• Regularly communicated with the Board and employees in regard to the Company’s response to COVID-19;

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Management’s Discussion and Analysis

• Maintained and updated COVID-19 safety protocols, including a back-to-office and site strategy, and a remote work strategy that will remain in place until the pandemic becomes an endemic; and

• Developed leadership plans, including contingent authorities.

Policy Changes

• We continue to align all non-essential travel and quarantine requirements with local jurisdictional guidance for all TransAlta employees and contractors for all jurisdictions in which we operate.

Employee Changes

• Provided continued assurances to employees that their employment with TransAlta would not be impacted by the COVID-19 pandemic;

• Implemented and have maintained health screening procedures, including questionnaires and temperature tests, enhanced cleaning measures and strict work protocols at the Company’s offices and facilities in accordance with our back-to-office and site strategy to ensure that employees remain safe;

• Maintained policies to seamlessly allow non-essential employees to work remotely, as appropriate; and

• Provided COVID-19 related town halls and information sessions for employees featuring medical and epidemiologists.

Operational Changes

• Modified our operating procedures and implemented restrictions to non-essential access to our facilities to support continued operations through the pandemic;

• Reviewed the supply chain risk associated with all key power-generation process inputs and implemented weekly monitoring for changes in risk;

• Reached out to key supply chain contacts to determine strategies and contingencies to ensure we are able to continue to progress our growth projects, wherever possible; and

• Identified new cybersecurity risks associated with phishing emails and enhanced security protocols and increased awareness of potential threats.

Financial Oversight

• Continued to maintain a comprehensive commodity hedging program for our merchant assets that can respond to changes in underlying market conditions;

• Continued to monitor counterparties for changes in creditworthiness, as well as monitor their ability to meet obligations; and

• Continued to monitor the situation and communicate with our key lenders on any foreseeable impacts and on our response to the crisis. We maintain a strong financial position and significant liquidity with our existing committed credit facilities.

Overall, we continue to actively monitor the situation and advice from public health officials with a view to responding to changing recommendations and adapting our response and approach as necessary.

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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 AFRC, 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 monthly 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 any laws or our code of conduct. These concerns can be submitted confidentially and anonymously, either directly to the AFRC or through TransAlta’s toll-free telephone or online Ethics Helpline. The AFRC Chair is immediately notified of any material complaints and, otherwise, the AFRC 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

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Management’s Discussion and Analysis

those prices and the relationships between those prices. We also employ additional risk mitigation measures. VaR at Dec. 31, 2021, associated with our proprietary commodity risk management activities was $2 million (2020 — $1 million). Please refer to the Risk Factors – Commodity Price Risk section of this MD&A below 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. Further information on the Company’s risk factors can be found in the Risk Factors section of the AIF, which risk factors are hereby incorporated by reference. and 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.

A reference herein to a material adverse effect on the Company means such an effect on the Company or its business, operations, financial condition, results of operations and/or its cash flows, as the context requires.

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 2021. 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.

Volume Risk

Volume risk relates to the variances from our expected production. The financial performance of our hydro, wind and solar operations is highly dependent upon the availability of their input resources in a given year. Shifts in weather or climate patterns, seasonal precipitation and the timing and rate of melting and runoff may impact the water flow to our facilities. The strength and consistency of the wind resource at our facilities impacts production. The operation of thermal facilities can also be impacted by ambient temperatures and the availability of water and fuel. 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 facility maintenance so that our facilities 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	$	12 million

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Management’s Discussion and Analysis

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 Company. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. Our facilities are exposed to operational risks such as failures due to cyclic, thermal and corrosion damage in boilers, generators and turbines, as well as other issues that can lead to outages and increased production risk. If facilities 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 facilities within defined industry standards that optimizes availability over their commercial operating life;

• Performing preventive maintenance in accordance with applicable industry practices, major equipment supplier recommendations and our operating experience;

• Adhering to comprehensive maintenance programs and regular turnaround schedules;

• Adjusting maintenance plans by facility to reflect equipment type, age and commercial risk;

• Having adequate business interruption insurance in place to cover extended forced outages;

• Having clauses in our PPAs and other long-term contracts that allow us to declare force majeure in the event of an unforeseen failure;

• Selecting and applying proven technology in our generating facilities, where practical;

• Where technology is newer, ensuring service agreements with equipment suppliers include appropriate availability and performance guarantees;

• Monitoring our fleet against industry performance to identify issues or advancements that may impact performance and adjusting our maintenance and investment programs accordingly;

• Negotiating strategic supply agreements with selected vendors to ensure key components are readily 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

• Implementing long-term asset management strategies that optimize the life cycles of our existing facilities and/or identify replacement requirements for 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 facilities 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 2021, we had approximately 78 per cent (2020 – 90 per cent) of production under short-term and long-term contracts and hedges . In the event of a planned or unplanned 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 facilities;

• Hedging emissions costs by entering into various emission trading arrangements; and

• Selectively using hedges, where available, to set prices for fuel.

In 2021, 70 per cent (2020 – 89 per cent) of our gas consumption used in generating electricity was contractually fixed or passed through to our customers and 80 per cent (2020 – 78 per cent) of our purchased coal was 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 Centralia, 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:

• Sourcing the coal used at Centralia from different mine sources to ensure sufficient coal is available at a competitive cost;

• Contracting sufficient trains to deliver the coal requirements at Centralia;

• Ensuring coal inventories on hand at Centralia 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 facilities;

• Monitoring the financial viability of Centralia suppliers; and

• Hedging diesel exposure in mining and transportation costs.

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Management’s Discussion and Analysis

Natural Gas Supply and Price Risk

Having sufficient natural gas and natural gas transportation services available at our Gas facilities is essential to maintaining the reliability and availability of those facilities. Ensuring adequate pipeline transportation service and natural gas supply for our Gas units may be impacted by, among other things, the timing of receiving regulatory and other approvals for firm transportation commitments, weather-related events, work stoppages, system maintenance, variability in pipeline hydraulics pressure and flows, and impacts due to other naturally created events. Pricing of natural gas is driven by market supply and demand fundamentals for natural gas in North America and globally. We are exposed to changes in natural gas prices, which may impact the profitability of our facilities and how the facilities are dispatched into the market.

We manage gas supply and price risk by:

• Working to ensure that we have at least two pipelines supplying the gas used in electrical generation in Alberta;

• Contracting for firm gas delivery and supply;

• Monitoring the financial viability of gas producers and pipelines;

• Hedging gas price exposure; and

• Monitoring pipeline maintenance schedules and transportation availability.

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, Australia 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 and imposing additional costs on the generation of electricity through such measures as emission caps or taxes, requiring additional capital investments in emission abatement technology or requiring us to 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 environmental health and safety management system audits to assess conformance to our Total Safety Management System, which is designed to continuously improve performance;

• Committing significant experienced resources to work with regulators in Canada, Australia 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, SO₂, and NO_x, which will be adjusted as regulations are finalized;

• Purchasing carbon emissions reduction offsets or credits;

• Investing in renewable energy projects, such as wind, solar and hydro generation, and storage technologies; and

• Incorporating change-in-law provisions in contracts that allow recovery of certain compliance costs from our customers.

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Management’s Discussion and Analysis

We are committed to remaining 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 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 fulfill 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.

As needed, additional risk mitigation tactics will be taken to reduce the risk to TransAlta. These risk mitigation tactics may include, but are not limited to, immediate follow-up on overdue amounts, adjusting payment terms to ensure a portion of funds are received sooner, requiring additional collateral, reducing transaction terms and working closely with impacted counterparties on negotiated solutions.

Our credit risk management profile and practices have not changed materially from Dec. 31, 2020. We had no material counterparty losses in 2021. 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.

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, 2021:

	Investment grade (%)		Non-investment grade (%)		Total (%)		Total amount
Trade and other receivables(1,2)		89		11		100		651
Long-term finance lease receivables		100		—		100		185
Risk management assets(1)		86		14		100		707
Total								1,543

(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.

(2) Includes loan receivable where the counterparties have no external credit ratings.

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Management’s Discussion and Analysis

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 $37 million (2020 – $22 million).

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 impact 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.

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, cash flows 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 senior 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 and Australian exposure, net of debt service and sustaining capital expenditures are 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 $0.03 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	$	0.03	$	12 million

Liquidity Risk

Liquidity risk relates to our ability to access capital to be used to fund capital projects, refinance debt and pay liabilities, engage in trading and hedging activities and general corporate purposes. Credit ratings facilitate these activities and changes in credit ratings may affect our ability and/or the cost of accessing capital markets, establishing normal course derivative or hedging transactions, including those undertaken by our Energy Marketing segment.

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Management’s Discussion and Analysis

We continue to focus on maintaining our financial position and flexibility. 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, 2021, we have liquidity of $2.2 billion comprised of amounts not drawn under our committed credit facilities and cash on hand that is available to draw on for projects in 2022.

We manage liquidity risk by:

• 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 AFRC;

• Maintaining a strong balance sheet;

• Maintaining sufficient undrawn committed credit lines to support potential liquidity requirements; and

• Monitoring trading positions.

Interest Rate Risk

Changes in interest rates can impact our borrowing costs. 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;

• Monitoring the mixture of floating and fixed rate debt and adjusting to ensure efficiency; and

• Opportunistically hedging for known debt issuances.

At Dec. 31, 2021, approximately 3 per cent (2020 – 7 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		30 bps	less than $	1 million before tax

IBOR reform could impact interest rate risk with respect to the Company’s credit facilities and the Poplar Creek non-recourse bond held by a TransAlta subsidiary. The facility references LIBOR for US-dollar drawings and the Canadian Dollar Offer Rate (“CDOR”) for Canadian-dollar drawings; in addition, the non-recourse bond references the three-month CDOR. To date, no US-dollar drawings have been made on the facility and there is currently a plan to discontinue the six- and 12-month CDOR, which does not impact the facility or the non-recourse bond.

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Management’s Discussion and Analysis

Outstanding US dollar forward starting interest rate swaps should not be affected as the three-month USD LIBOR will continue to be published until June 30, 2023. These are expected to to settle in 2022.

Project Management Risk

On capital projects, we face risks associated with cost overruns, delays and performance.

We manage project risks by:

• Ensuring all projects follow established corporate processes and policies;

• Identifying key risks during every stage of project development and ensuring mitigation plans are factored into capital estimates and contingencies;

• Reviewing project plans, key assumptions and returns with senior management prior to Board of Director approvals;

• Consistently applying project management methodologies and processes;

• Determining contracting strategies that are consistent with the project scope and scale to ensure key risks, such as labour and technology, are managed by contractors and equipment suppliers;

• Ensuring contracts for construction and major equipment include key terms for performance, delays and quality backed by appropriate levels of liquidated damages;

• Reviewing projects after achieving commercial operation to ensure learnings are incorporated into the next project;

• Negotiating contracts for construction and major equipment to lock-in key terms such as price, availability of long lead equipment, foreign currency rates and warranties as much as is economically feasible before proceeding with the project; and

• Entering into labour agreements to provide security around labour cost, supply and productivity.

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.

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Management’s Discussion and Analysis

In 2021, 33 per cent (2020 – 46 per cent) of our labour force was covered by 11 (2020 – 10) collective bargaining agreements. The increase in the number of collective agreements is the result of splitting one collective agreement into two collective agreements. The decrease in the percentage of our unionized workforce is the result of the coal-to-gas transition and subsequent retirement of Keephills Unit 1. In 2021, one (2020 – 2) agreement was renegotiated. We anticipate the successful negotiation of seven collective agreements in 2022.

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 within each of the jurisdictions in which we operate. 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 carbon pricing policies and funding.

We manage these risks systematically through our Legal and Regulatory groups and our Compliance program, which is reviewed periodically to ensure its effectiveness. We also 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 consultations 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 is key to our ability to deliver energy produced at our power facilities 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 faster than it is being added by new transmission developments.

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;

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Management’s Discussion and Analysis

• 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 partnerships and the payment of funds by our subsidiaries and partnerships in the form of distributions, loans, dividends or otherwise. In addition, our subsidiaries and partnerships 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 that we have in place 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. TransAlta’s cybersecurity model consists of three pillars: technology, processes and people. Each of these pillars can be reinforced independently to address specific cyber risks and threats that are confronting TransAlta. Significant cyber risks that could pose a threat to TransAlta include phishing, ransomware, social engineering, supplier chain, commodity hostage, state sponsored, artificial intelligence, machine learning attacks and a high risk of cybersecurity employee turnover. Proactive controls and safeguards to mitigate cybersecurity risk and threats posed to the organization include:

• Leveraging technologies to restrict communication within TransAlta’s networks thus limiting the ability for adversaries to achieve their aim;

• Partnering with a third-party cybersecurity specialty firm to outsource critical components of our cybersecurity program;

• Enhancing our policies and processes through the use of periodic reviews and table-top exercises;

• Maintaining an effective and robust cybersecurity awareness training and campaign;

• Integrating cybersecurity into our business processes and performing robust cybersecurity risk assessments; and

• Continuously improving our cybersecurity program to ensure it is effective in responding to and addressing cybersecurity risks.

SB-158

Management’s Discussion and Analysis

While we have cyber insurance (as well as 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.

Growth Risk

Our business plan includes growth through identifying suitable acquisitions or contracted new build opportunities. There can be no assurance that we will be able to identify attractive growth opportunities in the future, that we will be able to complete growth opportunities that increase the amount of cash available for distribution, or that growth opportunities will be successfully integrated into our existing operations. The successful execution of the growth strategy requires careful timing and business judgment, as well as the resources to complete the due diligence and evaluation of such opportunities and to acquire and successfully integrate those assets into our business.

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 constantly evolving. Our tax filings are subject to audit by taxation authorities. Management believes that it has adequately provided for income taxes as required by the Income Tax Act and IFRS, based on all information currently available.

The Company 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 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 Company.

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	$	6 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 and merits 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. Please refer to the Other Consolidated Analysis section of this MD&A for further details.

SB-159

Management’s Discussion and Analysis

Other Contingencies

We maintain a level of insurance coverage deemed appropriate by management. During renewal of the insurance policies on Dec. 31, 2021, a coverage restriction was added for losses resulting from a foundation failure at the Kent Hills 1 and 2 wind facilities only. There were no other significant changes to our insurance coverage during renewal of the insurance policies on Dec. 31, 2021. 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.

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”). For the year ended Dec. 31, 2021, the majority of our workforce supporting and executing our ICFR and DC&P worked remotely. There has been minimal impact to the design and performance of our internal controls. Management has reviewed the changes as a result of changes implemented in response to COVID-19 and is reasonably assured that adjustments to process have not 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 Company’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 is recorded, processed, summarized and reported within the time frame specified in applicable 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 applicable 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.

In accordance with the provisions of NI 52-109 and consistent with U.S. Securities and Exchange Commission guidance, the scope of the evaluation did not include internal controls over financial reporting of North Carolina Solar, which the Company acquired on Nov. 5, 2021. North Carolina Solar was excluded from management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as at Dec. 31, 2021, due to the proximity of the acquisition to year-end. Further details related to the acquisition are disclosed in Note 4 to the Company’s Consolidated Financial Statements for the year ended Dec. 31, 2021. Included in the 2021 Consolidated Financial Statements of TransAlta for North Carolina Solar is 2 per cent and 5 per cent of the Company’s total and net assets, respectively, as at Dec. 31, 2021.

SB-160

Management’s Discussion and Analysis

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 MD&A. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as at Dec. 31, 2021, the end of the period covered by this MD&A, our ICFR and DC&P were effective.

SB-161

EXHIBIT “C” – INTERIM UNAUDITED FINANCIAL STATEMENTS AS AT AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2022

See attached.

SC-1

Condensed Consolidated Financial Statements

Condensed Consolidated Statements of Earnings (Loss)

(in millions of Canadian dollars except per share amounts)

	3 months ended Sept. 30						9 months ended Sept. 30
Unaudited	2022			2021			2022			2021
Revenues (Note 3)		929			850			2,122			2,111
Fuel and purchased power (Note 4)		348			328			817			788
Carbon compliance (Note 4)		23			47			51			139
Gross margin		558			475			1,254			1,184
Operations, maintenance and administration (Note 4)		135			130			364			381
Depreciation and amortization (Note 14)		179			123			411			395
Asset impairment charges (Note 5)		70			575			4			620
Taxes, other than income taxes		8			9			25			26
Net other operating (income) loss (Note 6)		(11	)		47			(48	)		26
Operating income (loss)		177			(409	)		498			(264	)
Equity income		1			1			5			5
Finance lease income		4			6			15			19
Net interest expense (Note 7)		(66	)		(63	)		(195	)		(186	)
Foreign exchange gain		6			1			17			22
Gain on the sale of assets and other (Note 14)		4			23			6			56
Earnings (loss) before income taxes		126			(441	)		346			(348	)
Income tax expense (recovery) (Note 8)		30			(22	)		103			42
Net earnings (loss)		96			(419	)		243			(390	)
Net earnings (loss) attributable to:
TransAlta shareholders		72			(446	)		188			(478	)
Non-controlling interests (Note 9)		24			27			55			88
		96			(419	)		243			(390	)
Net earnings (loss) attributable to TransAlta shareholders		72			(446	)		188			(478	)
Preferred share dividends (Note 21)		11			10			21			20
Net earnings (loss) attributable to common shareholders		61			(456	)		167			(498	)
Weighted average number of common shares outstanding in the period (millions)		271			271			271			271
Net earnings (loss) per share attributable to common shareholders, basic and diluted		0.23			(1.68	)		0.62			(1.84	)

See accompanying notes.

SC-2

Condensed Consolidated Financial Statements

Condensed Consolidated Statements of Comprehensive Income (Loss)

(in millions of Canadian dollars)

	3 months ended Sept. 30						9 months ended Sept. 30
Unaudited	2022			2021			2022			2021
Net earnings (loss)		96			(419	)		243			(390	)
Other comprehensive income (loss)
Net actuarial gains on defined benefit plans, net of tax(1)		—			2			36			40
Losses on derivatives designated as cash flow hedges, net of tax		—			—			—			(1	)
Fair value losses on investments, net of tax (Note 13)		(1	)		—			(1	)		—
Total items that will not be reclassified subsequently to net earnings (loss)		(1	)		2			35			39
Gains (losses) on translating net assets of foreign operations, net of tax		24			17			18			(20	)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax(2)		(25	)		(11	)		(28	)		3
Losses on derivatives designated as cash flow hedges, net of tax(3)		(100	)		(107	)		(251	)		(238	)
Reclassification of losses (gains) on derivatives designated as cash flow hedges to net earnings (loss), net of tax(4)		39			19			21			(7	)
Total items that will be reclassified subsequently to net loss		(62	)		(82	)		(240	)		(262	)
Other comprehensive loss		(63	)		(80	)		(205	)		(223	)
Total comprehensive income (loss)		33			(499	)		38			(613	)
Total comprehensive income (loss) attributable to:
TransAlta shareholders		—			(533	)		44			(670	)
Non-controlling interests (Note 9)		33			34			(6	)		57
		33			(499	)		38			(613	)

(1) Net of income tax expense of nil and $11 million for the three and nine months ended Sept. 30, 2022 (Sept. 30, 2021 — $1 million and $12 million expense).

(2) Net of income tax recovery of $3 million and $4 million for the three and nine months ended Sept. 30, 2022 (Sept. 30, 2021 — nil for both periods).

(3) Net of income tax recovery of $29 million and $72 million for the three and nine months ended Sept. 30, 2022 (Sept. 30, 2021 — $29 million and $65 million recovery).

(4) Net of reclassification of income tax recovery of $10 million and $5 million for the three and nine months ended Sept. 30, 2022 (Sept. 30, 2021 — recovery of $5 million and expense of $2 million).

See accompanying notes.

SC-3

Condensed Consolidated Financial Statements

Condensed Consolidated Statements of Financial Position

(in millions of Canadian dollars)

Unaudited	Sept. 30, 2022			Dec. 31, 2021
Current assets
Cash and cash equivalents		816			947
Restricted cash (Note 18)		65			70
Trade and other receivables (Note 10)		1,327			651
Prepaid expenses		51			29
Risk management assets (Note 11 and 12)		755			308
Inventory		171			167
Assets held for sale		31			25
		3,216			2,197
Non-current assets
Investments (Note 13)		125			105
Long-term portion of finance lease receivables		143			185
Risk management assets (Note 11 and 12)		226			399
Property, plant and equipment (Note 14)
Cost		13,609			13,389
Accumulated depreciation		(8,315	)		(8,069	)
		5,294			5,320
Right-of-use assets		96			95
Intangible assets (Note 15)		257			256
Goodwill		465			463
Deferred income tax assets		60			64
Other assets (Note 16)		163			142
Total assets		10,045			9,226
Current liabilities
Accounts payable and accrued liabilities (Note 12)		1,279			689
Current portion of decommissioning and other provisions (Note 17)		49			48
Risk management liabilities (Note 11 and 12)		854			261
Current portion of contract liabilities (Note 22)		6			19
Income taxes payable		11			8
Dividends payable (Note 20 and 21)		39			62
Current portion of long-term debt and lease liabilities (Note 18)		722			844
		2,960			1,931
Non-current liabilities
Credit facilities, long-term debt and lease liabilities (Note 18)		2,487			2,423
Exchangeable securities		738			735
Decommissioning and other provisions (Note 17)		651			779
Deferred income tax liabilities		349			354
Risk management liabilities (Note 11 and 12)		247			145
Contract liabilities		12			13
Defined benefit obligation and other long-term liabilities (Note 19)		184			253
Total liabilities		7,628			6,633
Equity
Common shares (Note 20)		2,879			2,901
Preferred shares (Note 21)		942			942
Contributed surplus		33			46
Deficit		(2,318	)		(2,453	)
Accumulated other comprehensive income		2			146
Equity attributable to shareholders		1,538			1,582
Non-controlling interest (Note 9)		879			1,011
Total equity		2,417			2,593
Total liabilities and equity		10,045			9,226

Commitments and contingencies (Note 22)

See accompanying notes.

SC-4

Consolidated Financial Statements

Condensed Consolidated Statements of Changes in Equity

(in millions of Canadian dollars)

Unaudited

9 months ended Sept. 30, 2022	Common shares			Preferred shares		Contributed surplus			Deficit			Accumulated other comprehensive income			Attributable to shareholders			Attributable to non-controlling interests			Total
Balance, Dec. 31, 2021		2,901			942		46			(2,453	)		146			1,582			1,011			2,593
Net earnings		—			—		—			188			—			188			55			243
Other comprehensive income (loss):
Net losses on translating net assets of foreign operations, net of hedges and tax		—			—		—			—			(10	)		(10	)		—			(10	)
Net losses on derivatives designated as cash flow hedges, net of tax		—			—		—			—			(230	)		(230	)		—			(230	)
Net actuarial gains on defined benefits plans, net of tax		—			—		—			—			36			36			—			36
FVOCI investments		—			—		—			—			60			60			(61	)		(1	)
Total comprehensive income (loss)		—			—		—			188			(144	)		44			(6	)		38
Common share dividends		—			—		—			(27	)		—			(27	)		—			(27	)
Preferred share dividends		—			—		—			(21	)		—			(21	)		—			(21	)
Shares purchased under normal course issuer bid (“NCIB”) program (Note 20)		(29	)		—		—			(5	)		—			(34	)		—			(34	)
Effect of share-based payment plans		7			—		(13	)		—			—			(6	)		—			(6	)
Distributions paid and payable, to non-controlling interests (Note 9)		—			—		—			—			—			—			(126	)		(126	)
Balance, Sept. 30, 2022		2,879			942		33			(2,318	)		2			1,538			879			2,417

SC-5

Consolidated Financial Statements

9 months ended Sept. 30, 2021	Common shares		Preferred shares		Contributed surplus			Deficit			Accumulated other comprehensive income			Attributable to shareholders			Attributable to non-controlling interests			Total
Balance, Dec. 31, 2020		2,896		942		38			(1,826	)		302			2,352			1,084			3,436
Net loss		—		—		—			(478	)		—			(478	)		88			(390	)
Other comprehensive income (loss):
Net losses on translating net assets of foreign operations, net of hedges and tax		—		—		—			—			(17	)		(17	)		—			(17	)
Net gain (losses) on derivatives designated as cash flow hedges, net of tax		—		—		—			—			(247	)		(247	)		1			(246	)
Net actuarial gains on defined benefits plans, net of tax		—		—		—			—			40			40			—			40
Intercompany FVOCI investments		—		—		—			—			32			32			(32	)		—
Total comprehensive income (loss)		—		—		—			(478	)		(192	)		(670	)		57			(613	)
Common share dividends		—		—		—			(37	)		—			(37	)		—			(37	)
Preferred share dividends		—		—		—			(20	)		—			(20	)		—			(20	)
Effect of share-based payment plans		5		—		(1	)		—			—			4			—			4
Distributions paid and payable, to non-controlling interests (Note 9)		—		—		—			—			—			—			(117	)		(117	)
Balance, Sept. 30, 2021		2,901		942		37			(2,361	)		110			1,629			1,024			2,653

See accompanying notes.

SC-6

Condensed Consolidated Financial Statements

Condensed Consolidated Statements of Cash Flows

(in millions of Canadian dollars)

	3 months ended Sept. 30						9 months ended Sept. 30
Unaudited	2022			2021			2022			2021
Operating activities
Net earnings (loss)		96			(419	)		243			(390	)
Depreciation and amortization (Note 14 and 23)		179			197			411			574
Gain on sale of assets and other (Note 14)		(4	)		(23	)		(5	)		(56	)
Accretion of provisions (Note 7)		16			9			35			23
Decommissioning and restoration costs settled (Note 17)		(9	)		(5	)		(23	)		(13	)
Deferred income tax (recovery) expense (Note 8)		20			(46	)		68			(17	)
Unrealized loss (gain) from risk management activities		151			(67	)		111			(100	)
Unrealized foreign exchange loss (gain)		6			1			7			(24	)
Provisions and contract liabilities		(8	)		3			(4	)		(19	)
Asset impairment charges (Note 5)		70			575			4			620
Equity income, net of distributions from investments		—			(2	)		(2	)		(3	)
Other non-cash items		(37	)		9			(67	)		30
Cash flow from operations before changes in working capital		480			232			778			625
Change in non-cash operating working capital balances		(276	)		378			(252	)		322
Cash flow from operating activities		204			610			526			947
Investing activities
Additions to property, plant and equipment (Note 14)		(280	)		(127	)		(481	)		(344	)
Additions to intangible assets (Note 15)		(4	)		(1	)		(27	)		(4	)
Restricted cash (Note 18)		(22	)		(20	)		3			(5	)
Repayments in loan receivable (Note 16)		4			2			14			—
Proceeds on sale of Pioneer Pipeline (Note 14)		—			—			—			128
Proceeds on sale of property, plant and equipment		10			33			12			37
Realized gains (losses) on financial instruments		9			(1	)		8			(4	)
Decrease in finance lease receivable		12			10			34			30
Other		6			4			13			(14	)
Change in non-cash investing working capital balances		90			19			83			(26	)
Cash flow used in investing activities		(175	)		(81	)		(341	)		(202	)
Financing activities
Net decrease in borrowings under credit facilities		—			—			—			(114	)
Repayment of long-term debt		(21	)		(18	)		(80	)		(63	)
Dividends paid on common shares (Note 20)		(14	)		(13	)		(41	)		(37	)
Dividends paid on preferred shares (Note 21)		(11	)		(9	)		(31	)		(29	)
Repurchase of common shares under NCIB (Note 20)		(10	)		—			(28	)		(4	)
Net proceeds on issuance of common shares		—			—			1			8
Realized losses on financial instruments		—			(1	)		—			—
Distributions paid to subsidiaries’ non-controlling interests (Note 9)		(54	)		(50	)		(126	)		(117	)
Decrease in lease liabilities		(2	)		(2	)		(6	)		(6	)
Financing fees and other		(2	)		1			(4	)		(2	)
Change in non-cash financing working capital balances		—			1			—			—
Cash flow used in financing activities		(114	)		(91	)		(315	)		(364	)
Cash flow (used in) from operating, investing and financing activities		(85	)		438			(130	)		381
Effect of translation on foreign currency cash		3			—			(1	)		(4	)
(Decrease) increase in cash and cash equivalents		(82	)		438			(131	)		377
Cash and cash equivalents, beginning of period		898			642			947			703
Cash and cash equivalents, end of period		816			1,080			816			1,080
Cash taxes paid		10			13			53			40
Cash interest paid		52			49			159			161

See accompanying notes.

SC-7

Notes to Condensed Consolidated Financial Statements

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(Tabular amounts in millions of Canadian dollars, except as otherwise noted)

1. Corporate Information

A. Description of the Business

TransAlta Corporation (“TransAlta” or the “Company”) was incorporated under the Canada Business Corporations Act in March 1985. The Company became a public company in December 1992. Its head office is located in Calgary, Alberta.

Operating Segments

In 2021, the Company realigned its current operating segments to reflect a change in how TransAlta’s President and Chief Executive Officer (the chief operating decision maker) (“CODM”) reviews financial information in order to allocate resources and assess performance. The primary changes were the elimination of the Alberta Thermal and the Centralia segments, and the reorganization of the North American Gas and Australia Gas segments into a new “Gas” segment. The Alberta Thermal facilities that have been converted to gas have been included in the Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets and those facilities not converted to gas and the remaining Centralia unit, are included in a new “Energy Transition” segment. No changes were made to the Hydro and Wind and Solar segments. This change better aligns with the Company’s long-term strategy and reflects its Clean Electricity Growth Plan. Refer to Note 23 for further details.

B. Basis of Preparation

These unaudited interim condensed consolidated financial statements have been prepared in compliance with International Accounting Standard (“IAS”) 34 Interim Financial Reporting using the same accounting policies as those used in the Company’s most recent audited annual consolidated financial statements, except as outlined in Note 2. These unaudited interim condensed consolidated financial statements do not include all of the disclosures included in the Company’s audited annual consolidated financial statements. Accordingly, they should be read in conjunction with the Company’s most recent audited annual consolidated financial statements which are available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

The unaudited interim condensed consolidated financial statements include the accounts of the Company and its subsidiaries that it controls.

The unaudited interim condensed consolidated financial statements have been prepared on a historical cost basis, except for certain financial instruments, which are stated at fair value.

These unaudited interim condensed consolidated financial statements reflect all adjustments which consist of normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of results. Interim results will fluctuate due to plant maintenance schedules, the seasonal demands for electricity and changes in energy prices. Consequently, interim condensed results are not necessarily indicative of annual results. TransAlta’s results are partly seasonal due to the nature of the electricity market and related fuel costs.

These unaudited interim condensed consolidated financial statements were authorized for issue by the Audit, Finance and Risk Committee on behalf of TransAlta’s Board of Directors (the “Board”) on Nov. 7, 2022.

SC-8

Notes to Condensed Consolidated Financial Statements

C. Significant Accounting Judgments and Key Sources of Estimation Uncertainty

The preparation of these unaudited interim condensed consolidated financial statements in accordance with IAS 34 requires management to use judgment and make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosures of contingent assets and liabilities. These estimates are subject to uncertainty. Actual results could differ from these estimates due to factors such as fluctuations in interest rates, discount rates, foreign exchange rates, inflation and commodity prices and changes in economic conditions, legislation and regulations.

During the three and nine months ended Sept. 30, 2022, the global economy continued to recover from the COVID-19 pandemic. The Russia-Ukraine conflict has set off historic policy actions and global coordination of sanctions and commitments to reduce dependency on Russian energy including natural gas. This has contributed to global supply chain disruptions, commodity price volatility and potential increases to inherent cybersecurity risk. Energy prices have strengthened due to elevated uncertainty of global oil and natural gas supply given the war in Ukraine. Recent inflationary and supply chain dynamics coupled with rising interest rates and volatility in foreign exchange rates have created an environment that requires close monitoring. Estimates to the extent to which the geopolitical events may, directly or indirectly, impact the Company’s operations, financial results and conditions in future periods are also subject to significant uncertainty. Uncertainty related to COVID-19, geopolitical events and Consumer Price Index (“CPI”) inflation have been considered in the Company’s estimates as at and for the period ended Sept. 30, 2022.

During the three and nine months ended Sept. 30, 2022, there were changes in estimates relating to asset useful lives and depreciation (Note 14), decommissioning and other provisions (Note 17) and defined benefit obligations (Note 19).

Refer to Note 2(P) of the Company’s 2021 audited annual consolidated financial statements for further details on the Significant Accounting Judgments and Key Sources of Estimation Uncertainty.

2. Material Accounting Policies

The accounting policies adopted in the preparation of the unaudited interim condensed consolidated financial statements are consistent with those followed in the preparation of the Company’s annual consolidated financial statements for the year ended Dec. 31, 2021, except for the adoption of new standards effective as of Jan. 1, 2022, the early adoption of standards and interpretations or amendments that have been issued but are not yet effective.

A. Current Accounting Policy Changes

Amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets

On May 14, 2020, the International Accounting Standards Board (“IASB”) issued Onerous Contracts — Cost of Fulfilling a Contract and amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets to specify which costs to include when assessing whether a contract will be loss-making. The amendments are effective for annual periods beginning on or after Jan. 1, 2022, and the Company adopted these amendments as of Jan. 1, 2022. The amendments are effective for contracts for which an entity has not yet fulfilled all its obligations on or after the effective date. No adjustments resulted in the adoption of the amendments on Jan. 1, 2022.

SC-9

Notes to Condensed Consolidated Financial Statements

B. Future Accounting Policy Changes

Please refer to Note 3 of the audited annual 2021 consolidated financial statements for the future accounting policies impacting the Company. In the three and nine months ended Sept. 30, 2022, no additional future accounting policy changes impacting the Company were identified.

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 (loss).

3. Revenue

A. Disaggregation of Revenue

The majority of the Company’s revenues are derived from the sale of physical power, capacity and environmental attributes, leasing of power facilities and from asset optimization activities, which the Company disaggregates into the following groups for the purpose of determining how economic factors affect the recognition of revenue.

3 months ended Sept. 30, 2022	Hydro		Wind and Solar			Gas(1)			Energy Transition(2)			Energy Marketing		Corporate and Other			Total
Revenues from contracts with customers
Power and other		11		37			124			—			—		—			172
Environmental attributes		—		3			—			—			—		—			3
Revenue from contracts with customers		11		40			124			—			—		—			175
Revenue from leases(3)		—		—			12			—			—		—			12
Revenue from derivatives and other trading activities(4)		—		(49	)		(286	)		60			54		1			(220	)
Revenue from merchant sales		252		17			518			171			—		—			958
Other		2		3			4			—			—		(5	)		4
Total revenue		265		11			372			231			54		(4	)		929
Revenues from contracts with customers
Timing of revenue recognition
At a point in time		—		3			—			2			—		—			5
Over time		11		37			124			(2	)		—		—			170
Total revenue from contracts with customers		11		40			124			—			—		—			175

(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal segment. Refer to Note 1 for further details.

(3) Total rental income, including contingent rent related to other long-term contracts that meet the criteria of operating leases.

(4) Represents realized and unrealized gains or losses from hedging and derivative positions. Significant volatility and pricing in commodity markets resulted in higher than normal movements in derivative positions.

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Notes to Condensed Consolidated Financial Statements

3 months ended Sept. 30, 2021	Hydro		Wind and Solar			Gas(1)			Energy Transition(2)		Energy Marketing		Corporate and Other		Total
Revenues from contracts with customers
Power and other		8		37			103			10		—		—		158
Environmental attributes		—		14			—			—		—		—		14
Revenue from contracts with customers		8		51			103			10		—		—		172
Revenue from leases(3)		—		—			4			—		—		—		4
Revenue from derivatives and other trading activities(4)		—		(18	)		—			74		86		1		143
Revenue from merchant sales		86		15			275			147		—		—		523
Other		2		4			2			—		—		—		8
Total revenue		96		52			384			231		86		1		850
Revenues from contracts with customers
Timing of revenue recognition
At a point in time		—		14			(1	)		10		—		—		23
Over time		8		37			104			—		—		—		149
Total revenue from contracts with customers		8		51			103			10		—		—		172

(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal segment. Refer to Note 1 for further details.

(3) Total rental income, including contingent rent and other long-term contracts that meet the criteria of operating leases.

(4) Represents realized and unrealized gains or losses from hedging and derivative positions. Wind and Solar has been revised to present revenue classifications consistent with the current period.

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Notes to Condensed Consolidated Financial Statements

			Wind and						Energy			Energy		Corporate
9 months ended Sept. 30, 2022	Hydro		Solar			Gas(1)			Transition(2)			Marketing		and Other			Total
Revenues from contracts with customers
Power and other		29		155			340			6			—		—			530
Environmental attributes		1		33			—			—			—		—			34
Revenue from contracts with customers		30		188			340			6			—		—			564
Revenue from leases(3)		—		—			20			—			—		—			20
Revenue from derivatives and other trading activities(4)		—		(69	)		(359	)		174			116		3			(135	)
Revenue from merchant sales		411		61			925			253			—		—			1,650
Other		6		15			7			—			—		(5	)		23
Total revenue		447		195			933			433			116		(2	)		2,122
Revenues from contracts with customers
Timing of revenue recognition
At a point in time		1		33			—			8			—		—			42
Over time		29		155			340			(2	)		—		—			522
Total revenue from contracts with customers		30		188			340			6			—		—			564

(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal segment. Refer to Note 1 for further details.

(3) Total rental income, including contingent rent related to other long-term contracts that meet the criteria of operating leases.

(4) Represents realized and unrealized gains or losses from hedging and derivative positions. Significant volatility and pricing in commodity markets resulted in higher than normal movements in derivative positions.

			Wind and								Energy		Corporate and
9 months ended Sept. 30, 2021	Hydro		Solar			Gas(1)			Energy Transition(2)		Marketing		Other		Total
Revenues from contracts with customers
Power and other		21		149			275			20		—		—		465
Environmental attributes		—		23			—			—		—		—		23
Revenue from contracts with customers		21		172			275			20		—		—		488
Revenue from leases(3)		—		—			14			—		—		—		14
Revenue from derivatives and other trading activities(4)		—		(15	)		(57	)		137		185		6		256
Revenue from merchant sales		271		44			699			314		—		—		1,328
Other(5)		7		12			6			—		—		—		25
Total revenue		299		213			937			471		185		6		2,111
Revenues from contracts with customers
Timing of revenue recognition
At a point in time		—		23			1			19		—		—		43
Over time		21		149			274			1		—		—		445
Total revenue from contracts with customers		21		172			275			20		—		—		488

(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

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Notes to Condensed Consolidated Financial Statements

(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal segment. Refer to Note 1 for further details.

(3) Total rental income, including contingent rent and other long-term contracts that meet the criteria of operating leases.

(4) Represents realized and unrealized gains or losses from hedging and derivative positions. Wind and Solar has been revised to present revenue classifications consistent with the current period.

(5) Includes government incentives and other miscellaneous revenue.

B. Changes to Revenue Contracts

Wind and Solar

On Aug. 23, 2022, the Company announced that it was awarded a capacity contract with the Ontario Independent Electricity System Operator (the “IESO”) for the Melancthon 1 wind facility, which will extend the period of contracted revenues to April 30, 2031. The wind facility’s existing PPA with the IESO ends on March 3, 2026.

On June 2, 2022, TransAlta Renewables Inc., a subsidiary of the Company (“TransAlta Renewables”) announced that it amended and extended its current power purchase agreements with New Brunswick Power Corporation (“NB Power”) in respect of each of the Kent Hills 1, 2 and 3 wind facilities, representing total generating capacity of 167 MW. The amending agreements provide for a blend-and-extend of the PPAs providing NB Power with an effective 10 per cent reduction to the original contract prices from January 2023 through December 2033 and the extension of the original contract term for an additional 10-year period through to December 2045.

Refer to Notes 14, 16 and 18 for further discussion related to the Kent Hills wind facilities.

Gas

On Aug. 23, 2022, the Company announced that it was awarded a capacity contract with the IESO for the Sarnia cogeneration facility, which will extend the period of contracted revenues to April 30, 2031. The current IESO contract ends on Dec. 31, 2025. The Company expects gross margin from the Sarnia cogeneration facility to be reduced by approximately 30 per cent per year as a result of the IESO price cap under the new contract.

During the second quarter of 2022, the Company executed contract extensions for the supply of electricity with three of its industrial customers and for the supply of steam for one of these customers, at the Sarnia cogeneration facility. These agreements extend the delivery term from Dec. 31, 2022 to April 30, 2031 in one case and to Dec. 31, 2032, for the other two.

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Notes to Condensed Consolidated Financial Statements

4. Expenses by Nature

A. Fuel, Purchased Power and Operations, Maintenance and Administration (“OM&A”)

Fuel and purchased power and OM&A expenses classified by nature are as follows:

	3 months ended Sept. 30								9 months ended Sept. 30
	2022				2021				2022				2021
	Fuel and				Fuel and				Fuel and				Fuel and
	purchased				purchased				purchased				purchased
	power		OM&A		power		OM&A		power		OM&A		power		OM&A
Gas fuel costs		152		—		80		—		409		—		200		—
Coal fuel costs(1)		48		—		53		—		96		—		123		—
Royalty, land lease and other direct costs		6		—		4		—		18		—		14		—
Purchased power(2)		141		—		108		—		290		—		246		—
Mine depreciation(3)		—		—		74		—		—		—		179		—
Salaries and benefits		1		66		9		67		4		180		26		174
Other operating expenses(2)(4)		—		69		—		63		—		184		—		207
Total		348		135		328		130		817		364		788		381

(1) During the three and nine months ended Sept. 30, 2021, $5 million and $16 million, respectively, was included in coal fuel costs related to the impairment of coal inventory recorded during 2021.

(2) During the three and nine months ended Sept. 30, 2021, $1 million and $6 million, respectively, related to station service costs for the Hydro segment was reclassified from OM&A to fuel and purchased power for comparative purposes. This did not impact previously reported net earnings.

(3) During the three and nine months ended Sept. 30, 2021, $19 million and $48 million, respectively, was included in mine depreciation, related to the impairment of mine depreciation recorded during 2021.

(4) During the three and nine months ended Sept. 30, 2021, OM&A costs included a writedown of $5 million and $30 million, respectively, for parts and material inventory related to the Highvale mine and coal operations at our gas converted facilities.

B. Carbon Compliance

During the nine months ended Sept. 30, 2022, the Company utilized 1,169,333 emission credits with a carrying value of $35 million to settle the 2021 carbon compliance obligation of $47 million. The difference of $12 million has been recognized as a reduction in the Company’s carbon compliance costs in the period.

As at Sept. 30, 2022, the Company currently holds 1,017,980 emission credits in inventory purchased externally with a recorded book value of $34 million (Dec. 31, 2021 — 2,033,752 emission credits with a recorded book value of $55 million). The Company also has approximately 1,922,972 of internally generated eligible emission credits with no recorded book value (Dec. 31, 2021 — 1,922,973). In addition, the Company holds approximately 1,750,000 eligible emission credits generated from assets formerly subject to the Hydro Power Purchase Arrangement (“Hydro PPA”) during the period 2018-2020, which also have no recorded book value. Refer to Note 22 for further details.

5. Asset Impairment Charges

The Company has determined that certain assets and/or facilities will be grouped together to form a cash generating unit (“CGU”) where requirements are met for the purposes of impairment testing. Property, Plant and

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Notes to Condensed Consolidated Financial Statements

Equipment (“PP&E”) and goodwill have been allocated to each of the CGUs or groups of CGUs in a segment that are expected to benefit from the synergies of the business combination in which the goodwill arose, to determine the carrying amount.

As part of the Company’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 Company 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 Company estimates a recoverable amount (the higher of value in use and fair value less costs of disposal) for each CGU by calculating an approximate fair value less costs of disposal using discounted cash flow projections based on the Company’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to the Company’s discount rates, 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 2072.

During the period, the Company recognized the following asset impairment charges (reversals):

	3 months ended Sept. 30				9 months ended Sept. 30
	2022		2021		2022			2021
Wind and Solar		14		10		35			10
Hydro		15		9		21			9
Energy Transition Facilities		—		509		—			519
Corporate		—		—		—			27
Changes in decommissioning and restoration provisions on retired assets		41		44		(52	)		38
Intangible asset impairment - Coal Rights(1)		—		3		—			17
Asset impairment charges		70		575		4			620

(1) Impaired to nil in 2021, as no future coal will be extracted from this area of the mine.

Wind and Solar

During the three and nine months ended Sept. 30, 2022, the Company recorded net impairment charges of $14 million and $35 million, respectively. During the second quarter, three wind facilities were impaired primarily as a result of an increase in discount rates. During the third quarter, two additional wind facilities and one solar facility were impaired as a result of changes in key assumptions including significant increases in discount rates and changes in estimated future cash flows. The recoverable amounts of $607 million for these six assets were estimated based on fair value less cost of disposal utilizing a discounted cash flow approach and is categorized as a Level III fair value measurement.

During the third quarter of 2021, the Company recorded an impairment charge of $8 million for a wind asset as result of an increase in estimated decommissioning costs after the review of a recent engineering study. The resulting fair value measurement less cost of disposal is categorized as a Level III fair value measurement and the Company adjusted the expected value down to $65 million as at Sept. 30, 2021 using discount rates of 5 per cent. The key assumptions impacting the determination of fair value are electricity production, sales prices and cost inputs, which are subject to measurement uncertainty.

As at Sept. 30, 2021, the Company recognized an impairment charge of $2 million related to the Kent Hills Wind LP tower failure.

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Notes to Condensed Consolidated Financial Statements

Hydro

During the three and nine months ended Sept. 30, 2022, the Company recorded net impairment charges of $15 million and $21 million, respectively. During the second quarter, an impairment of $6 million was recorded on one of the hydro facilities primarily from an increase in discount rates. During the third quarter, two additional hydro facilities were impaired as a result of changes in key assumptions including significant increases in discount rates and changes in estimated future cash flows and pricing. The recoverable amounts of $89 million in total for these three assets were estimated based on fair value less cost of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement.

During the third quarter of 2021, the Company recorded an impairment charge of $9 million in the Hydro segment on the balance of project development costs at one of the hydro facilities as there was uncertainty on timing of when the project will proceed.

The calculation of fair value less cost of disposal for all of the above facilities is most sensitive to the following assumptions:

	Location of assets		2022 Contract and Merchant discount rates		Prior period Contract and Merchant discount rates(1)
Wind and Solar		Canada United States (“US”)		6.4 and 7.1 per cent 6.5 and 7.3 per cent		5.0 and 5.0 per cent 5.1 and 5.1 per cent
Hydro		Canada		5.9 and 6.4 per cent		3.6 and 4.9 per cent

(1) Prior period discount rates were related to the most recent detailed valuation performed for the Wind and Solar segment in third quarter of 2021, and for the Hydro segment in the third quarter of 2019.

Energy Transition

During the third quarter of 2021, the Company recognized asset impairments charges in the Alberta Thermal segment as a result of the decision to suspend the Sundance Unit 5 repowering project of $190 million and planned retirements of Keephills Unit 1 of $78 million and Sundance Unit 4 of $56 million. Keephills Unit 1 and Sundance Unit 4 impairment assessments were based on the estimated salvage values of these units which were in excess of the expected economic benefits from these units. For the Sundance Unit 5 repowering project, impairment assessments were based on the estimated recoverable amount of estimated fair value less costs of disposal of reselling the equipment for assets under construction and estimated salvage value for the balance of the costs. The fair value measurement for assets under construction is categorized as a Level III fair value measurement. The total remaining estimated recoverable amount and salvage values for the Sundance Unit 5 repowering project was $33 million as at Sept. 30, 2021. Discounting did not have a material impact to these asset impairments. These asset retirement and project suspension decisions were based on the Company’s assessment of future market conditions, the age and condition of in-service units and TransAita’s strategic focus toward customer-centred renewable energy solutions.

During the third quarter of 2021, with the shut down of the Highvale Mine at the end of 2021, it was determined that the estimated salvage value exceeded the economic benefit to the Alberta Merchant CGU. The asset was removed from the Alberta Merchant CGU for impairment purposes and was assessed for impairment as an individual asset which resulted in the recognized impairment charge of $185 million within the Energy Transition segment, with the asset being written down to salvage value.

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Notes to Condensed Consolidated Financial Statements

Corporate

Energy Transfer Canada, formerly SemCAMS Midstream ULC, purported to terminate the agreements related to the development and construction of the Kaybob Cogeneration Project. As a result, during the first quarter of 2021, the Company recorded an impairment of $27 million in the Corporate segment as this facility was not yet operational. The recoverable amount was based on estimated fair value less costs of disposal of reselling the equipment purchased to date.

Changes in Decommissioning and Restoration Provisions on Retired Assets

During the third quarter of 2022, the Company accelerated the expected timing on decommissioning and restoration for certain retired gas assets. This resulted in an increase in the decommissioning and restoration provision with a $50 million impairment recorded in the quarter. In addition, for the three and nine months ended Sept. 30, 2022, the decommissioning and restoration provisions relating to retired assets have decreased due to an increase in discount rates, resulting in an impairment reversal of $9 million and $102 million, respectively. Refer to Note 14 and 17 for further details.

6. Net Other Operating (Income) Loss

Net other operating (income) loss includes the following:

	3 months ended Sept 30						9 months ended Sept 30
	2022			2021			2022			2021
Alberta Off-Coal Agreement		(10	)		(10	)		(30	)		(30	)
Liquidated damages recoverable		(1	)		—			(11	)		—
Insurance recoveries		—			—			(7	)		(1	)
Supplier settlements		—			43			—			43
Highvale Mine onerous contract provision		—			14			—			14
Net other operating (income) loss		(11	)		47			(48	)		26

Alberta Off-Coal Agreement

The Company receives payments from the Government of Alberta for the cessation of coal-fired emissions on or before Dec. 31, 2030. Under the terms of the agreement, the Company receives annual cash payments on or before July 31 of approximately $40 million ($37 million, net of the non-controlling interest related to Sheerness facility), which commenced Jan. 1, 2017 and will terminate at the end of 2030. Refer to Note 9 in the 2021 audited annual consolidated financial statements for further details.

Liquidated Damages Recoverable

During the three and nine months ended Sept. 30, 2022, the Company recorded $1 million and $11 million, respectively, related to requirements to be met by the contractor on turbine availability at the Windrise wind facility.

Insurance Recoveries

During the nine months ended Sept. 30, 2022, the Company received insurance proceeds of $7 million related to the replacement costs for the single collapsed tower at the Kent Hills wind facilities.

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Notes to Condensed Consolidated Financial Statements

Supplier Settlements

During the third quarter of 2021, $27 million was expensed for amounts due to contractors for not proceeding with the Sundance Unit 5 repowering project, $10 million (US$8 million) deferred asset was expensed as it was not likely that the Company would incur sufficient capital or operating expenditures to utilize the remaining credit and $6 million was expensed for amounts due to contractors for not proceeding with the construction of equipment for Keephills Unit 1 during the third quarter of 2021.

Highvale Mine Onerous Contract Provision

During the third quarter of 2021, an onerous contract provision for future royalty payments of $14 million was recognized as a result of a decision to accelerate the plans to shut down the Highvale Mine.

7. Net Interest Expense

The components of net interest expense are as follows:

	3 months ended Sept. 30						9 months ended Sept. 30
	2022			2021			2022			2021
Interest on debt		42			41			123			121
Interest on exchangeable debentures		7			8			22			22
Interest on exchangeable preferred shares		7			7			21			21
Interest income		(7	)		(2	)		(14	)		(8	)
Capitalized interest (Note 14)		(4	)		(5	)		(8	)		(13	)
Interest on lease liabilities		1			1			4			5
Credit facility fees, bank charges and other interest		5			4			16			14
Tax shield on tax equity financing		(1	)		—			(4	)		1
Accretion of provisions		16			9			35			23
Net interest expense		66			63			195			186

During the three and nine months ended Sept. 30, 2022, the Company capitalized interest at a weighted average rate of 6.1 per cent (Sept. 30, 2021 — 6.0 per cent).

On Nov. 7, 2022, the Company declared a dividend of $7 million in aggregate for Exchangeable Preferred Shares at the fixed rate of 1. 764 per cent per share payable on Nov. 30, 2022. The Exchangeable Preferred Shares are considered debt for accounting purposes and, as such, dividends are reported as interest expense.

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Notes to Condensed Consolidated Financial Statements

8. Income Taxes

The components of income tax expense are as follows:

	3 months ended Sept. 30					9 months ended Sept. 30
	2022		2021			2022			2021
Current income tax expense		10		24			35			59
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences		20		(125	)		168			(144	)
Deferred income tax expense (recovery) related to temporary difference on investment in subsidiary		—		2			(7	)		2
Deferred income tax expense (recovery) arising from the writedown (reversal of write-down) of deferred income tax assets(1)		—		77			(93	)		125
Income tax expense (recovery)		30		(22	)		103			42
	3 months ended Sept. 30					9 months ended Sept. 30
	2022		2021			2022			2021
Current income tax expense		10		24			35			59
Deferred income tax expense (recovery)		20		(46	)		68			(17	)
Income tax expense (recovery)		30		(22	)		103			42

(1) During the nine months ended Sept. 30, 2022, the Company recorded a write-down reversal of deferred tax assets $93 million mainly related to tax benefits of losses associated with the Company’s directly owned US and Canadian operations. The write-down of deferred income tax assets related to US and Canadian operations arose as it is not considered probable that sufficient future taxable income will be available to utilize the underlying tax losses. The Company evaluates at each period end whether it is probable that sufficient future taxable income would be available to utilize the underlying tax losses.

9. Non-Controlling Interests

The Company’s subsidiaries with significant non-controlling interests are TransAlta Renewables and TransAlta Cogeneration L.P. The net earnings, distributions and equity attributable to TransAlta Renewables’ non-controlling interests include the 17 per cent non-controlling interest in Kent Hills Wind LP, which owns the 167 MW Kent Hills wind farm located in New Brunswick.

	3 months ended Sept. 30					9 months ended Sept. 30
	2022			2021		2022			2021
Net earnings
TransAlta Cogeneration L.P.		32			17		45			48
TransAlta Renewables		(8	)		10		10			40
		24			27		55			88
Total comprehensive income (loss)
TransAlta Cogeneration L.P.		32			17		45			48
TransAlta Renewables		1			17		(51	)		9
		33			34		(6	)		57

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Notes to Condensed Consolidated Financial Statements

	3 months ended Sept. 30				9 months ended Sept. 30
	2022		2021		2022		2021
Cash distributions paid to non-controlling interests
TransAlta Cogeneration L.P.		29		25		51		42
TransAlta Renewables		25		25		75		75
		54		50		126		117

As at	Sept. 30, 2022		Dec. 31, 2021
Equity attributable to non-controlling interests
TransAita Cogeneration L.P.		135		142
TransAita Renewables		744		869
		879		1,011
Non-controlling interests share (per cent)
TransAita Cogeneration L.P.		49.99		49.99
TransAita Renewables		39.9		39.9

10. Trade and Other Receivables

As at	Sept. 30, 2022		Dec. 31, 2021
Trade accounts receivable		933		499
Collateral paid (Note 12)		315		55
Current portion of finance lease receivable		47		40
Loan receivable (Note 16)		9		55
Income taxes receivable		23		2
Trade and other receivables		1,327		651

11. Financial Instruments

A. Financial Assets and Liabilities — Measurement

Financial assets and financial liabilities are measured on an ongoing basis at fair value, or amortized cost.

B. Fair Value of Financial Instruments

I. Level I, II and III Fair Value Measurements

The Level I, II and III classifications in the fair value hierarchy utilized by the Company 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.

a. Level I

Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

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Notes to Condensed Consolidated Financial Statements

b. Level II

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

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.

The Company’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 interpolation formulas, where the inputs are readily observable.

In determining Level II fair values of other risk management assets and liabilities, the Company 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 Company 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.

For assets and liabilities that are recognized at fair value on a recurring basis, the Company determines whether transfers have occurred between levels in the hierarchy by re-assessing categorization (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period.

There were no changes in the Company’s valuation processes, valuation techniques and types of inputs used in the fair value measurements during the period. For additional information, refer to Note 15 of the 2021 audited annual 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 Sept. 30, 2022, are as follows: Level I — $76 million net asset (Dec. 31, 2021 — $12 million net asset), Level II — $350 million net asset (Dec. 31, 2021 — $122 million net asset) and Level III — $611 million net liability (Dec. 31, 2021 — $159 million net asset).

Significant changes in commodity net risk management assets (liabilities) during the nine months ended Sept. 30, 2022, are primarily attributable to volatility in market prices across multiple markets on both existing contracts and new contracts as well as contract settlements.

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Notes to Condensed Consolidated Financial Statements

The following tables summarize the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification during the nine months ended Sept. 30, 2022 and 2021, respectively:

	9 months ended Sept. 30, 2022									9 months ended Sept. 30, 2021
	Hedge			Non-hedge			Total			Hedge			Non-hedge			Total
Opening balance		285			(126	)		159			573			9			582
Changes attributable to:
Market price changes on existing contracts		(346	)		(371	)		(717	)		(249	)		(100	)		(349	)
Market price changes on new contracts		—			(114	)		(114	)		—			(123	)		(123	)
Contracts settled		(37	)		82			45			(83	)		(10	)		(93	)
Change in foreign exchange rates		20			(6	)		14			(4	)		—			(4	)
Transfers into (out of) Level III		—			2			2			—			—			—
Net risk management assets (liabilities) at end of period		(78	)		(533	)		(611	)		237			(224	)		13
Additional Level III information:
Losses recognized in other comprehensive income		(326	)		—			(326	)		(253	)		—			(253	)
Total gains (losses) included in earnings before income taxes		37			(491	)		(454	)		83			(223	)		(140	)
Unrealized losses included in earnings before income taxes relating to net liabilities held at period end		—			(409	)		(409	)		—			(233	)		(233	)

SC-22

Notes to Condensed Consolidated Financial Statements

As of Sept. 30, 2022, the total Level lll risk management asset balance was nil (Dec. 31, 2021 — $305 million) and Level lll risk management liability balance was $611 million (Dec. 31, 2021 — $146 million). The following information on risk management contracts or groups of risk management contracts that are included in level lll measurements, include the effects on fair value of discounting, liquidity and credit value adjustments; however, the potential offsetting effects of Level II positions are not considered. 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, volatility in commodity prices and correlations, delivery volumes, escalation rates and cost of supply.

As at	Sept. 30, 2022
Description	Sensitivity		Valuation technique	Unobservable input	Reasonable possible change
Long-term power sale — US		+19	Long-term price forecast	llliquid future power prices (per MWh)	Price decrease of US$5 or increase of US$31
		-120
Coal transportation — US		+14	Numerical derivative valuation	llliquid future power prices (per MWh)	Price decrease of US$5 or increase of US$31
				Volatility	80% to 120%
		-11		Rail rate escalation	zero to 10%
Full requirements — Eastern US		+4	Monte Carlo	Volume	95% to 105%
		-25		Cost of supply	US$(1) to US$3 per MWh
Long-term wind energy sale — Eastern US		+20	Long-term price forecast	llliquid future power prices (per MWh)	Price increase or decrease of US$6
				llliquid future REC prices (per unit)	Price decrease of US$2 or increase of US$1
		-15		Wind discounts	zero to 5%
Long-term wind energy sale — Canada		+68	Long-term price forecast	llliquid future power prices (per MWh)	Price decrease of C$75 or increase of C$4
		-16		Wind discounts	14% decrease or 5% increase
Long-term wind energy sale — Central US		+57	Long-term price forecast	llliquid future power prices (per MWh)	Price decrease of US$4 or increase of US$5
		-21		Wind discounts	3% decrease or 7% increase
Others		+8
		-8

SC-23

Notes to Condensed Consolidated Financial Statements

As at	Dec. 31, 2021
Description	Sensitivity		Valuation technique	Unobservable input	Reasonable possible change
Long-term power sale — US		+22	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$3 or increase of US$20
		-145
Coal transportation — US		+3	Numerical derivative valuation	Illiquid future power prices (per MWh)	Price decrease of US$3 or increase of US$20
		-18		Volatility	80% to 120%
				Rail rate escalation	zero to 4%
Full requirements — Eastern US		+9	Monte Carlo	Volume	95% to 105%
		-9		Cost of supply	(+/-) US$1 per MWh
Long-term wind energy sale — Eastern US		+17	Long-term price forecast	Illiquid future power prices (per MWh)	Price increase or decrease of US$6
		-16		Illiquid future REC prices (per unit)	Price decrease of US$3 or increase of
					US$2
Long-term wind energy sale — Canada		+21	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of C$24 or increase of C$5
		-11		Wind discounts	5% decrease or 5% increase
Long-term wind energy sale — Central US		+27	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$2 or increase of US$3
		-15		Wind discounts	3% decrease or 3% increase
Others		+6
		-6

Contracts that are entered into with customers for the off-take of energy and other outputs from Company owned facilities may not be eligible to be accounted for as own use contracts with customers and may either be classified and accounted for as derivatives or contain embedded derivatives. Conditions that result in derivative classification include, for example: net financial settlement of the contract; lack of physical delivery requirements; or, the contract is readily convertible to cash. When a contract with a customer is classified and accounted for as a derivative, the contract is recognized within risk management assets (liabilities) at fair value and subsequent changes in fair value of the contract are recognized in revenues as revenue from derivatives and other trading activities, unless hedge designation is available and made.

i. Long-Term Power Sale — US

The Company 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.

The contract is denominated in US dollars. The US dollar relative to the Canadian dollar strengthened from Dec. 31, 2021 to Sept. 30, 2022, resulting in a decrease in the base fair value and an increase in the sensitivity values by approximately $6 million and $8 million, respectively.

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Notes to Condensed Consolidated Financial Statements

ii. Coal Transportation — US

The Company has a coal rail transport agreement that includes an upside sharing mechanism until Dec. 31, 2025. Option pricing techniques have been utilized to value the obligation associated with this component of the agreement.

iii. Full Requirements — Eastern US

The Company has a portfolio of full requirement service contracts, whereby the Company agrees to supply specific utility customer needs for a range of products that may include electrical energy, capacity, transmission, ancillary services, renewable energy credits and independent system operator costs.

iv. Long-Term Wind Energy Sale — Eastern US

In relation to the Big Level wind facility, the Company has a long-term contract for differences whereby the Company 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. The contract matures in December 2034. The contract is accounted for as a derivative. Changes in fair value are presented in revenue.

v. Long-Term Wind Energy Sale — Canada

In relation to the Garden Plain wind project, the Company has entered into two virtual PPAs whereby the Company receives the difference between the fixed contract price per MWh and the Alberta Electric System Operator (“AESO”) settled pool price per MWh. Both contracts commence on commercial operation of the facility, which is expected by the the end of 2022 and extend for a weighted average of approximately 17 years.

In addition to the virtual PPA contracts, the Company has entered into a bridge contract that runs 16 months from Sept. 1, 2021 through Dec. 31, 2022, which automatically extends at the virtual PPA price should the commencement of commercial operations occur after Dec. 31, 2022.

The energy component of these contracts are accounted for as derivatives. Changes in fair value are presented in revenue.

vi. Long-Term Wind Energy Sale — Central US

The Company has entered into two long-term virtual PPAs for the off take of 100 per cent of the generation from its 300 MW White Rock East and White Rock West wind power projects (collectively, the “White Rock Wind projects”) to be located in Caddo County, Oklahoma. The Company receives the difference between the fixed contract price per MWh and the settled pool price per MWh. The contracts commence on commercial operation of the facilities, which is expected within the second half of 2023 and extend for more than 10 years past that date.

On April 5, 2022, the Company entered into a long-term virtual PPA for the offtake of 100 per cent of the generation from its 200 MW Horizon Hill wind project (“Horizon Hill wind project”) to be located in Logan County, Oklahoma. The Company receives the difference between the fixed contract price per MWh and the settled pool price per MWh. The contract commences on commercial operation of the facility, which is expected within the second half of 2023.

The energy component of these contracts are accounted for as derivatives. Changes in fair value are presented in revenue.

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Notes to Condensed Consolidated Financial Statements

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 asset fair value of $65 million as at Sept. 30, 2022 (Dec. 31, 2021 — $8 million net asset) are classified as Level II fair value measurements. The significant changes in other net risk management assets and liabilities during the nine months ended Sept. 30, 2022, are primarily attributable to favourable impacts of interest rate increases on existing contracts and favourable foreign exchange rates on new contracts entered into during 2022.

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 Value(1)
	Level I		Level II		Level III		Total
Exchangeable Securities — Sept. 30, 2022		—		718		—		718		738
Long-term debt — Sept. 30, 2022		—		2,790		—		2,790		3,105
Exchangeable securities — Dec. 31, 2021		—		770		—		770		735
Long-term debt — Dec. 31, 2021		—		3,272		—		3,272		3,167

(1) Includes current portion.

The fair values of the Company’s debentures, senior notes and exchangeable securities 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.

The carrying amount of other short-term financial assets and liabilities (cash and cash equivalents, restricted cash, 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 and the finance lease receivables approximate the carrying amounts and the amounts receivable represent cash flows from repayments of principal and interest.

C. Inception Gains and Losses

The majority of derivatives traded by the Company 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 11 above 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 condensed consolidated statements of financial position in risk management assets or liabilities and is recognized in net earnings (loss) over the term of the

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Notes to Condensed Consolidated Financial Statements

related contract. The difference between the transaction price and the fair value determined using a valuation model, yet to be recognized in net earnings (loss) and a reconciliation of changes is as follows:

	9 months ended Sept. 30
	2022			2021
Unamortized net loss at beginning of the period		(131	)		(33	)
New inception gains (losses)		(40	)		15
Change in foreign exchange rates		(11	)		—
Amortization recorded in net earnings during the period		(21	)		(6	)
Unamortized net loss at end of the period		(203	)		(24	)

12. Risk Management Activities

The Company is exposed to market risk from changes in commodity prices, foreign exchange rates, interest rates, credit risk and liquidity risk. These risks affect the Company’s earnings (loss) and the value of associated financial instruments that the Company holds. In certain cases, the Company seeks to minimize the effects of these risks by using derivatives to hedge its risk exposures. The Company’s risk management strategy, policies and controls are designed to ensure that the risks it assumes comply with the Company’s internal objectives and its risk tolerance. For additional information on the Company’s Risk Management Activities please refer to Note 16 of the 2021 audited annual consolidated financial statements.

A. Net Risk Management Assets and Liabilities

Aggregate net risk management assets (liabilities) are as follows:

As at Sept. 30, 2022	Cash flow hedges			Not designated as a hedge			Total
Commodity risk management
Current		(110	)		(54	)		(164	)
Long-term		32			(53	)		(21	)
Net commodity risk management liabilities		(78	)		(107	)		(185	)
Other
Current		59			6			65
Long-term		—			—			—
Net other risk management assets		59			6			65
Total net risk management liabilities		(19	)		(101	)		(120	)

As at Dec. 31, 2021	Cash flow hedges		Not designated as a hedge			Total
Commodity risk management
Current		33		12			45
Long-term		252		(4	)		248
Net commodity risk management assets		285		8			293

SC-27

Notes to Condensed Consolidated Financial Statements

As at Dec. 31, 2021	Cash flow hedges		Not designated as a hedge			Total
Other
Current		3		(1	)		2
Long-term		—		6			6
Net other risk management assets		3		5			8
Total net risk management assets		288		13			301

B. Nature and Extent of Risks Arising from Financial Instruments

I. Market Risk

i. Commodity Price Risk Management — Proprietary Trading

The Company’s Energy Marketing segment conducts proprietary trading activities and uses a variety of instruments to manage risk, earn trading revenue and gain market information. Value at risk (“VaR”) is used to determine the potential change in value of the Company’s proprietary trading portfolio, over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations. Changes in market prices associated with proprietary trading activities affect net earnings (loss) in the period that the price changes occur. VaR at Sept. 30, 2022, associated with the Company’s proprietary trading activities was $3 million (Dec. 31, 2021 — $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 by products, as considered appropriate. VaR at Sept. 30, 2022, associated with the Company’s commodity derivative instruments used in generation hedging activities was $34 million (Dec. 31, 2021 — $33 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 (loss) in the period in which the price change occurs. VaR at Sept. 30, 2022, associated with these transactions was $43 million (Dec. 31, 2021 — $51 million), of which $21 million related to virtual PPAs (Dec. 31, 2021 — $18 million).

iii. Interest Rate Risk

Interest rate risk arises as the fair value of future cash flows from a financial instrument fluctuates because of changes in market interest rates. Changes in interest rates can impact the Company’s borrowing costs. Changes in the cost of capital may also affect the feasibility of new growth initiatives.

The Company’s credit facility, Term Facility (“Term Facility”) and the Poplar Creek non-recourse bond are the only debt instruments subject to floating interest rates, which represent 3 per cent of the Company’s debt as at Sept. 30, 2022 (Dec. 31, 2021 — 3 per cent). The Poplar Creek non-recourse bond face value as at Sept. 30, 2022 was $98 million (Dec. 31, 2021 — $104 million), with interest expense based upon the three-month Canadian Dollar Offered Rate, which will be discontinued in 2024.

During the third quarter of 2022, the interest rate swap agreements with a notional amount of US$150 million referencing the three-month LIBOR were replaced with swap agreements referencing the Secured Overnight Financing Rate (“SOFR”). Existing interest rate swap agreements with a notional amount of US$150 million reference the US Treasury Bond yield. The maturity dates on all swap agreements have been extended.

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Notes to Condensed Consolidated Financial Statements

II. Credit Risk

The Company 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 Company’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at Sept. 30, 2022:

			Non-
	Investment grade		investment grade		Total		Total
	(Per cent)		(Per cent)		(Per cent)		amount
Trade and other receivables (1,2 )		86		14		100		1,318
Long-term finance lease receivables		100		—		100		143
Risk management assets(1)		81		19		100		981
Loan receivable(2)		—		100		100		41
Total								2,483

(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.

(2) Includes $41 million loan receivable included within Other Assets with a counterparty that has no external credit rating. The current portion of $9 million was excluded from trade and other receivables as it is included in loan receivable in the table above.

The Company did not have significant expected credit losses as at Sept. 30, 2022.

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 Sept. 30, 2022, was $98 million (Dec. 31, 2021 — $37 million).

III. Liquidity Risk

The Company has sufficient existing liquidity available to meet its upcoming debt maturities. The next major debt maturity is scheduled for November 2022. Our highly diversified asset portfolio, by both fuel type and operating region, provide stability in cash flows and highlight the strength of our long-term contracted asset base.

Liquidity risk relates to the Company’s ability to access capital to be used for capital projects, debt refinancing, proprietary trading activities, commodity hedging and general corporate purposes. A maturity analysis of the Company’s financial liabilities as well as financial assets that are expected to generate cash inflows to meet cash outflows on financial liabilities, is as follows:

	2022			2023			2024		2025			2026		2027 and thereafter			Total
Accounts payable and accrued liabilities		1,279			—			—		—			—		—			1,279
Long-term debt(1)		580			170			127		141			143		1,976			3,137
Exchangeable securities(2)		—			—			—		750			—		—			750
Commodity risk management (assets) liabilities		92			67			33		(43	)		9		27			185
Other risk management (assets) liabilities		(79	)		13			—		2			—		(1	)		(65	)
Lease liabilities(3)		(1	)		(3	)		4		4			4		96			104
Interest on long-term debt and lease liabilities(4)		47			133			128		120			113		830			1,371
Interest on exchangeable securities(2,4)		13			53			62		—			—		—			128
Dividends payable		39			—			—		—			—		—			39
Total		1,970			433			354		974			269		2,928			6,928

(1) Excludes impact of hedge accounting and derivatives.

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Notes to Condensed Consolidated Financial Statements

(2) Assumes the exchangeable securities will be exchanged on Jan. 1, 2025.

(3) Lease liabilities includes a lease incentive of $4 million expected to be received in 2022 and $8 million in 2023.

(4) Not recognized as a financial liability on the Condensed Consolidated Statements of Financial Position.

C. Collateral and Contingent Features in Derivative Instruments

I. Financial Assets Provided as Collateral

At Sept. 30, 2022, the Company provided $315 million (Dec. 31, 2021 — $55 million) in cash and cash equivalents as collateral to regulated clearing agents and certain utility customers as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents. The utility customers are obligated to pay interest on the outstanding balances. Collateral provided is included in trade and other receivables in the Condensed Consolidated Statements of Financial Position.

II. Financial Assets Held as Collateral

At Sept. 30, 2022, the Company held $395 million (Dec. 31, 2021 — $18 million) in cash collateral associated with counterparty obligations. Under the terms of the contracts, the Company 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 related to physical and financial derivative transactions in a net asset position and is included in accounts payable and accrued liabilities in the Condensed Consolidated Statements of Financial Position.

III. Contingent Features in Derivative Instruments

Collateral is posted in the normal course of business based on the Company’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs.

As at Sept. 30, 2022, the Company had posted collateral of $600 million (Dec. 31, 2021 — $356 million) in the form of letters of credit on physical and financial derivative transactions in a net liability position. Certain derivative agreements contain credit-risk-contingent features which, if triggered, and result in no unsecured credit being available to the Company, may result in having to post an additional $545 million (Dec. 31, 2021 — $120 million) of collateral to the Company’s counterparties.

13. Investments

The Company’s investments include its 49% interest in the Skookumchuck wind facility and its 30% interest in EMG International LLC (“EMG”) and the investments acquired in 2022, as discussed below:

Energy Impact Partners Investment (“EIP”)

On May 6, 2022, the Company entered into a commitment to invest US$25 million over the next four years in EIP’s Deep Decarbonization Frontier Fund 1 (the “Frontier Fund”). The investment in the Frontier Fund provides the Company with a portfolio approach to investing in emerging technologies and the opportunity to identify, pilot, commercialize and bring to market emerging technologies that will facilitate the transition to net-zero emissions. During the second quarter of 2022, the Company made an initial investment of $7 million (US$6 million). The investment is accounted for at fair value through profit or loss.

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Notes to Condensed Consolidated Financial Statements

Ekona Power Inc. (“Ekona”)

On Feb. 1, 2022, the Company made an equity investment of $2 million in Ekona’s Class B Preferred Shares. The investment will help support the commercialization of Ekona’s novel methane pyrolysis technology platform, which produces cleaner and lower-cost turquoise hydrogen. The investment is accounted for at fair value through other comprehensive income.

14. Property, Plant and Equipment

Assets under construction

During the three and nine months ended Sept. 30, 2022, the Company had additions of $249 million and $440 million, respectively, mainly related to assets under construction for the White Rock wind projects, Garden Plain wind project, Horizon Hill wind project, Northern Goldfields solar project and other planned major maintenance.

In addition, the Company has begun its rehabilitation plan at the Kent Hills wind facilities. For the three and nine months ended Sept. 30, 2022, the Company has capitalized additions of $31 million and $41 million, respectively.

During the three and nine months ended Sept. 30, 2021, the Company had additions of $127 million and $344 million, respectively, mainly related to assets under construction for the coal-to-gas conversions, Windrise wind facility, the Garden Plain wind project, Sundance Unit 5 repowering project and other planned major maintenance expenditures. During the nine months ended Sept. 30, 2021, the Company completed the conversions of Keephills Unit 2, Sheerness Unit 1 and Sundance Unit 6 and the costs were transferred to gas generation.

Renewable Generation

During the first quarter of 2022, $16 million of costs, related to transmission infrastructure at the Windrise wind facility, were reclassified from PP&E to Other Assets and will be amortized to net earnings (loss) over the useful life of the Windrise wind facility. In accordance with the asset transfer agreement, the ownership of these assets must be transferred to the transmission line owner upon completion of construction of the transmission infrastructure.

Gas Generation

On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. for the aggregate sale price of $255 million. The net cash proceeds to the Company from the sale of its 50 per cent interest, were approximately $128 million and the Company recognized a gain on sale of $31 million on the Condensed Consolidated Statements of Earnings. In addition, as part of the transaction, the natural gas transportation agreement with the Pioneer Pipeline Limited Partnership was terminated which resulted in a gain of $2 million.

Energy Transition

Keephills Unit 1 and Sundance Unit 5 were retired in 2021. Sundance Unit 4 was retired from service effective March 31, 2022.

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Notes to Condensed Consolidated Financial Statements

Change in Estimate — Useful Lives

During the third quarter of 2022, the Company adjusted the useful lives of certain assets included in the Gas segment to reflect changes made based on the future operating expectations of the assets. This resulted in an increase of $64 million in depreciation expense that was recognized in the Condensed Consolidated Statement of Earnings in the third quarter of 2022.

Change in Estimate — Decommissioning provision

During the nine months ended 2022, the Corporation adjusted certain gas assets decommissioning and restoration provisions to reflect the potential timing to begin reclamation efforts. The Corporation’s current best estimate of the decommissioning and restoration provision increased by $40 million.

In addition, during the nine months ended Sept. 30, 2022, the decommissioning and restoration provisions on operating assets have been updated to reflect an increase in discount rates, resulting in a decrease in the decommissioning and restoration provision and in the related assets in PP&E of $125 million.

Refer to Note 17 for further details.

15. Intangible Assets

The Company acquired a portfolio of wind development projects in the US in 2019. Upon moving forward with any of these projects, additional consideration may be payable on a project-by-project basis in the event a project achieves commercial operations prior to Dec. 31, 2025.

During the nine months ended Sept. 30, 2022, the Company recorded $16 million (Sept. 30, 2021 — nil) of contingent consideration relating to US wind development projects. Additionally, the Company reclassified development costs of $3 million from Other Assets to Intangible Assets comprised of initial acquisition costs.

16. Other Assets

Kent Hills LP Loan

Other Assets includes a $41 million (Dec. 31, 2021 — $55 million) unsecured loan related to an advancement by the Company’s subsidiary, Kent Hills Wind LP (“KHLP”), of the net financing proceeds of the Kent Hills Wind Bond (“KH Bonds”), to its 17 per cent partner. On June 1, 2022, the loan receivable agreement was amended and its original maturity date of Oct. 2, 2022 was extended to October 2027, resulting in the classification of a portion of the loan receivable to non-current assets. The remaining terms of the original loan remain unchanged and it continues to bear interest at 4.55 per cent, with interest payable quarterly. No scheduled principal repayments are required until maturity. However, repayments may be required for amounts associated with foundation replacement capital expenditures as outlined in the amendment made to the KH Bonds. During the nine months ended Sept. 30, 2022, the Company received repayments of $14 million which were required as part of the waiver and amendment made to the KH Bonds. As at Sept. 30, 2022, $9 million (Dec. 31, 2021 — $55 million) was recorded as current and included in Trade and Other Receivables.

Windrise Prepaid

During the first quarter of 2022, $16 million of costs related to transmission infrastructure at the Windrise wind facility were reclassified from PP&E to Other Assets and will be amortized to net earnings (loss) over the useful life of the Windrise wind facility. Refer to Note 14 for further detail.

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Notes to Condensed Consolidated Financial Statements

17. Decommissioning and Other Provisions

The change in decommissioning and other provision balances is as follows:

	Decommissioning and restoration			Other provisions			Total
Balance, Dec. 31, 2021		793			34			827
Liabilities settled		(23	)		(11	)		(34	)
Accretion		35			—			35
Transfers		(2	)		—			(2	)
Revisions in estimated cash flows		90			5			95
Revisions in discount rates		(227	)		—			(227	)
Reversals		—			(10	)		(10	)
Change in foreign exchange rates		16			—			16
Balance, Sept. 30, 2022		682			18			700

	Decommissioning and restoration		Other provisions		Total
Balance, Dec. 31, 2021		793		34		827
Current portion		35		13		48
Non-current portion		758		21		779
Balance, Sept. 30, 2022		682		18		700
Current portion		38		11		49
Non-current portion		644		7		651

For the three months ended Sept. 30, 2022, the Company accelerated the expected timing on decommissioning and restoration for certain gas assets. This increased the decommissioning and restoration provision by $79 million resulting in an increase in PP&E of $29 million on operating assets and recognition of a $50 million impairment charge in net earnings related to retired assets. In the second quarter of 2022, an additional increase to decommissioning and restoration of $11 million was recognized in relation to an asset in the Gas segment.

For the nine months ended Sept. 30, 2022, the decommissioning and restoration provisions have decreased by $227 million due to a significant increase in discount rates, largely driven by increases in market benchmark rates. On average, discount rates increased with rates ranging from 6.8 to 9.6 per cent as at Sept. 30, 2022 (Dec. 31, 2021 — 3.6 to 6.5 per cent). This has resulted in a corresponding decrease in PP&E of $125 million on operating assets and recognition of a $102 million impairment reversal in net earnings related to retired assets.

18. Credit Facilities and Long-Term Debt

The Company has $2 billion (Dec. 31, 2021 — $2 billion) of committed syndicated bank facilities and $0.2 billion of committed bilateral credit facilities, of which $1.5 billion was available as at Sept. 30, 2022 (Dec. 31, 2021 — $1.3 billion) including the undrawn letters of credit. During the second quarter of 2022, the committed syndicated credit facilities were extended by one year to June 30, 2026 and the committed bilateral credit facilities were extended by one year to June 30, 2024. The undrawn credit facilities are the primary source for short-term liquidity after the cash flow generated from the Company’s business. Interest rates on the credit facilities vary depending on the option selected (Canadian prime, bankers’ acceptances, SOFR or US base rate, etc.) in accordance with a pricing grid that is standard for such facilities.

During the third quarter of 2022, the Company closed a two year $400 million floating rate Term Facility with its banking syndicate with a maturity date of Sept. 7, 2024. The Term Facility has interest rates that vary depending

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Notes to Condensed Consolidated Financial Statements

on the option selected (Canadian prime, bankers’ acceptances, etc.) The Company is required to meet certain specific and customary affirmative and negative financial covenants under the Term Facility, including the maintenance of certain financial ratios. No amounts were drawn on the Term Facility as at Sept. 30, 2022.

As at Sept. 30, 2022, the Company was in compliance with all debt covenants.

Kent Hills Wind Bonds

In fourth quarter of 2021, the Company disclosed that events of default may have occurred under the trust indenture governing the terms of the KH Bonds. Accordingly, the Company classified the entire carrying value of the bonds as current as at Dec. 31, 2021.

During the second quarter of 2022, the Company obtained a waiver and entered into a supplemental indenture that facilitated the rehabilitation of the Kent Hills 1 and 2 wind facilities. Upon receipt of the waiver, the Company reclassified a portion of the carrying value outstanding for the KH Bonds to non-current liabilities with the exception of the scheduled principal repayments due within the next twelve months from June 30, 2022. In accordance with the supplemental indenture, Kent Hills Wind LP cannot make any distributions to its partners until the foundation replacement work has been completed.

The KH Bonds, issued in October 2017, bear interest at 4.45 per cent, with principal and interest payable quarterly in blended payments until maturity on Nov. 30, 2033. The KH Bonds are secured by a first ranking charge over all of the assets of the issuer, Kent Hills Wind LP, which primarily includes the Kent Hills 1, 2 and 3 wind facilities, which at Sept. 30, 2022, had a combined PP&E carrying value of $210 million (Dec. 31, 2021 — $182 million).

Restricted Cash

The Company has $18 million (Dec. 31, 2021 — $17 million) of restricted cash related to bonds (“TransAlta OCP bonds”) issued by the Company’s subsidiary, TransAlta OCP LP, which is required to be held in a debt service reserve account to fund scheduled future debt repayments.

The Company also had $47 million (Dec. 31, 2021 — $53 million) of restricted cash related to the TEC Hedland PTY Ltd bond; reserves are required to be held under commercial arrangements and for debt service. Cash reserves may be replaced by letters of credit in the future.

Currency Impacts

The strengthening of the US dollar has increased the US-denominated long-term debt balances, mainly the senior notes and tax equity financing, by $70 million as at Sept. 30, 2022 (Sept. 30, 2021 — decreased by $7 million due to weakening of the US dollar). Almost all of the US-denominated debt is hedged either through financial contracts or net investments in the US operations.

Additionally, the weakening of the Australian dollar has decreased the Australian-denominated non-recourse senior secured notes by approximately $43 million as at Sept. 30, 2022 (Sept. 30, 2021 — $41 million). As this debt is issued by an Australian subsidiary, the foreign currency translation impacts are recognized within other comprehensive income.

19. Defined Benefit Obligations

The liability for pension and post-employment benefits and associated costs included in compensation expenses are impacted by estimates related to changes in key actuarial assumptions, including discount rates. As a result of increases in discount rates, largely driven by increases in market benchmark rates, the defined benefit obligation

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Notes to Condensed Consolidated Financial Statements

decreased by approximately $46 million for the nine months ended Sept. 30, 2022, compared to Dec. 31, 2021. A 1 per cent increase in discount rates would have a $38 million impact on the defined benefit obligation.

During the third quarter of 2022, the Company made a voluntary contribution of $35 million to further improve the funded status of the Sunhills Mining Ltd. Pension Plan for the Highvale Mine. The contribution reduces the amount of the Company’s future funding obligations, including amounts secured by the letters of credit.

The liability for defined benefit obligations is $148 million as at Sept. 30, 2022 (Dec. 31, 2021 — $228 million).

20. Common Shares

A. Issued and Outstanding

TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.

	9 months ended Sept. 30
	2022						2021
	Common shares (millions)			Amount			Common shares (millions)		Amount
Issued and outstanding, beginning of period		271.0			2,901			269.8		2,896
Purchased and cancelled under the NCIB		(2.7	)		(29	)		—		—
Effects of share-based payment plans		0.9			6			—		(3	)
Stock options exercised		0.2			1			1.2		8
Issued and outstanding, end of period		269.4			2,879			271.0		2,901

B. Normal Course Issuer Bid Program

On May 24, 2022, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to renew its normal course issuer bid (“NCIB”) for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 Common Shares, representing approximately 7.16 per cent of its public float of common shares. Any common shares purchased under the NCIB are cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2022 and ends on May 30, 2023.

Shares purchased by the Company 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 deficit.

The following are the effects of the Company’s purchase and cancellation of the common shares during the period:

As at	Sept. 30, 2022		Dec. 31, 2021
Total shares purchased		2,741,400		—
Average purchase price per share	$	12.50		—
Total cost (millions)(1)	$	34		—
Weighted average book value of shares cancelled	$	29		—
Amount recorded in deficit	$	5		—

(1) During the nine months ended Sept. 30, 2022, the Company paid $28 million with the remaining costs paid subsequent to the period.

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Notes to Condensed Consolidated Financial Statements

C. Dividends

On July 27, 2022, the Company declared a quarterly dividend of $0.05 per common share, payable on Oct. 1, 2022.

On Nov. 7, 2022, the Company declared a quarterly dividend of $0.055 per common share, payable on Jan. 1, 2023.

There have been no other transactions involving common shares between the reporting date and the date of completion of these unaudited interim condensed consolidated financial statements.

21. Preferred Shares

A. Issued and Outstanding

All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares.

As at	Sept. 30, 2022				Dec. 31, 2021
Series	Number of shares (millions)		Amount		Number of shares (millions)		Amount
Series A		9.6		235		9.6		235
Series B(1)		2.4		58		2.4		58
Series C(2)		10.0		243		11.0		269
Series D(2)(3)		1.0		26		—		—
Series E		9.0		219		9.0		219
Series G		6.6		161		6.6		161
Issued and outstanding, end of period		38.6		942		38.6		942

(1) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.03 per cent.

(2) During the second quarter of 2022, the Company has converted 1,044,299 of its 11,000,000 currently outstanding Series C Shares, on a one-for-one basis, into Series D Shares.

(3) Series D Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 3.10 per cent.

On Sept. 21, 2022, the Company announced that, after taking into account all election notices received 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 89,945 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. 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, 2022 to but excluding Sept. 30, 2027, will be 6.894% which is equal to the five-year Government of Canada bond yield of 3.244 per cent, determined as of Aug. 31, 2022, plus 3.65 per cent, in accordance with the terms of the Series E Shares.

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Notes to Condensed Consolidated Financial Statements

B. Dividends

On July 27, 2022, the Company declared a quarterly dividend of $0.17981 per share on the Series A preferred shares, $0.22099 per share on the Series B preferred shares, $0.36588 per share on the Series C preferred shares, $0.28841 per share on the Series D preferred shares, $0.32463 per share on the Series E preferred shares and $0.31175 per share on the Series G preferred shares, payable on Sept. 30, 2022.

On Nov. 7, 2022, the Company declared a quarterly dividend of $$0.17981 per share on the Series A preferred shares, $0.337 per share on the Series B preferred shares, $0.36588 per share on the Series C preferred shares, $0.40442 per share on the Series D preferred shares, $0.43088 per share on the Series E preferred shares and $0.31175 per share on the Series G preferred shares, payable on Dec. 31, 2022.

22. Commitments and Contingencies

A. Commitments

For the significant commitments and contingencies outstanding, refer to Note 36 of the 2021 annual consolidated financial statements. The Company has entered into the following material contractual commitments, as at Sept. 30, 2022:

During the second quarter of 2022, the Company entered into an engineering, procurement and construction agreement for approximately $37 million (AU$41 million) related to the Mount Keith 132kV Expansion.

During 2022, the Company has entered into agreements for $100 million for the rehabilitation efforts at the Kent Hills 1 and 2 wind facilities.

The Company has not incurred any other material contractual commitments, either directly or through its interests in joint ventures or associates during 2022.

B. 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 Company’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 Company responds as required. For the current material outstanding contingencies, please refer to Note 36 of the 2021 audited annual consolidated financial statements. Material changes to the contingencies have been described below.

Hydro Power Purchase Arrangement (“Hydro PPA”)—Emission Performance Credits

The Balancing Pool is claiming entitlement to the emission performance credits (“EPCs”) earned by the Alberta Hydro facilities as a result of TransAlta opting those facilities into the Carbon Competitiveness Incentive Regulation and Technology Innovation and Emissions Reduction Regulation from 2018-2020 inclusive. The Balancing Pool claims ownership of the EPCs because it believes the change-in-law provisions under the Hydro PPA require the EPCs to be passed through to the Balancing Pool. TransAlta has not received any benefit from the EPCs nor from any purported change-in-law and believes that the Balancing Pool has no rights to these credits. An arbitration has commenced and the hearing is scheduled for Feb. 6—10, 2023. TransAlta holds approximately 1,750,000 EPCs with no recorded book value that were created between 2018-2020, which are at risk as a result of the Balancing Pool’s claim.

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Notes to Condensed Consolidated Financial Statements

Keephills Unit 1 Stator Force Majeure

The Balancing Pool and ENMAX were seeking to set aside an arbitration award on the basis that they did not receive a fair hearing. The Alberta Court of Queen’s Bench dismissed the Balancing Pool and ENMAX’s allegations of unfairness on June 26, 2019. The Balancing Pool and ENMAX appealed this decision to the Court of Appeal, which was heard on Jan. 27, 2022.

On June 9, 2022, the Court of Appeal released a unanimous decision dismissing ENMAX and the Balancing Pool’s application. The Court of Appeal upheld the Company’s claim of force majeure that arose when its Keephills Unit 1 generating unit tripped offline in 2013. As a result of the decision, the Company’s claim of force majeure remains valid and the associated costs of the force majeure event will not be reassessed against TransAlta. ENMAX and the Balancing Pool did not seek leave to appeal this decision to the Supreme Court of Canada, which concludes this matter.

Keephills Unit 2 Stator Force Majeure

After the Keephills Unit 1 stator force majeure outage in 2013, it was determined that Keephills Unit 2 could face a similar stator failure before the next planned outage. In response, the Company took Keephills Unit 2 offline between January 31, 2014, and March 15, 2014, to perform a full rewind of the generator stator and claimed force majeure. The Balancing Pool disputed this force majeure event but the dispute was held in abeyance pending the outcome of the Keephills Unit 1 stator force majeure dispute, which was recently concluded. The Company and the Balancing Pool recently settled this dispute and so both stator force majeure claims have been resolved.

Sarnia Outages

The Sarnia cogeneration facility experienced three separate events between May 19, 2021, and June 9, 2021, that resulted in steam interruptions to its industrial customers. As a result, the customers have submitted claims for liquidated damages. Steam supply disruptions of this nature are atypical and infrequent at the Sarnia cogeneration facility. A root cause failure analysis was completed for the three outages, which concluded that all three outages were within TransAlta (SC) LP’s control. As such, liquidated damages previously included in contract liabilities in the amount of $12 million have been paid by TransAlta (SC) LP during the second quarter of 2022.

There have been no other material updates to any of the contingencies in the three and nine months ended Sept. 30, 2022.

23. Segment Disclosures

A. Description of Reportable Segments

The Company has six reportable segments as described in Note 1.

The following tables provide each segment’s results in the format that the CODM reviews the Company’s segments to make operating decisions and assess performance. The tables below show the reconciliation of the total segmented results and adjusted EBITDA to the statement of earnings (loss) reported under IFRS. Prior periods have been adjusted for comparable purposes.

For internal reporting purpose, the earnings information from the Company’s investment in the Skookumchuck wind facility has been presented in the Wind and Solar segment on a proportionate basis. Information on a proportionate basis reflects the Company’s share of Skookumchuck’s statement of earnings on a line-by-line basis. Proportionate financial information is not and is not intended to be, presented in accordance with IFRS. Under IFRS, the investment in Skookumchuck has been accounted for as a joint venture using the equity method.

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Notes to Condensed Consolidated Financial Statements

B. Reported Adjusted Segment Earnings (Loss) and Segment Assets

Reconciliation of Adjusted EBITDA to Earnings (Loss) Before Income Tax

3 months ended Sept. 30, 2022	Hydro		Wind & Solar(1)			Gas(2)			Energy Transition(3)		Energy Marketing			Corporate			Total			Equity accounted investments(1)			Reclass Adjustments			IFRS Financials
Revenues		265		14			372			231		54			(4	)		932			(3	)		—			929
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		53			47			6		46			—			152			—			(152	)		—
Realized (gain) loss on closed exchange positions		—		—			(4	)		—		(38	)		—			(42	)		—			42			—
Decrease in finance lease receivable		—		—			12			—		—			—			12			—			(12	)		—
Finance lease income		—		—			4			—		—			—			4			—			(4	)		—
Adjusted revenues		265		67			431			237		62			(4	)		1,058			(3	)		(126	)		929
Fuel and purchased power		7		6			167			167		—			1			348			—			—			348
Reclassifications and adjustments:
Australian interest income		—		—			(1	)		—		—			—			(1	)		—			1			—
Adjusted fuel and purchased power		7		6			166			167		—			1			347			—			1			348
Carbon compliance		—		—			26			2		—			(5	)		23			—			—			23
Gross margin		258		61			239			68		62			—			688			(3	)		(127	)		558
OM&A		12		19			49			17		9			30			136			(1	)		—			135
Taxes, other than income taxes		1		1			5			—		—			1			8			—			—			8
Net other operating income		—		(1	)		(10	)		—		—			—			(11	)		—			—			(11	)
Adjusted EBITDA(4)		245		42			195			51		53			(31	)		555
Equity income																											1
Finance lease income																											4
Depreciation and amortization																											(179	)
Asset impairment charges																											(70	)
Net interest expense																											(66	)
Foreign exchange gain																											6
Gain on sale of assets and other																											4
Earnings before income taxes																											126

(1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

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Notes to Condensed Consolidated Financial Statements

3 months ended Sept. 30, 2021	Hydro		Wind & Solar(1)		Gas(2)			Energy Transition(3)			Energy Marketing			Corporate			Total			Equity accounted investments(1)			Reclass Adjustments			IFRS Financials
Revenues		96		55		384			231			86			1			853			(3	)		—			850
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		21		(71	)		(2	)		(14	)		—			(66	)		—			66			—
Realized loss on closed exchange positions		—		—		—			—			21			—			21			—			(21	)		—
Decrease in finance lease receivable		—		—		10			—			—			—			10			—			(10	)		—
Finance lease income		—		—		6			—			—			—			6			—			(6	)		—
Unrealized foreign exchange gain on commodity		—		—		(3	)		—			—			—			(3	)		—			3			—
Adjusted revenues		96		76		326			229			93			1			821			(3	)		32			850
Fuel and purchased power(4)		4		4		129			190			—			1			328			—			—			328
Reclassifications and adjustments:
Australian interest income		—		—		(1	)		—			—			—			(1	)		—			1			—
Mine depreciation		—		—		(26	)		(48	)		—			—			(74	)		—			74			—
Coal inventory write-down		—		—		—			(5	)		—			—			(5	)		—			5			—
Adjusted fuel and purchased power		4		4		102			137			—			1			248			—			80			328
Carbon compliance		—		—		33			14			—			—			47			—			—			47
Gross margin		92		72		191			78			93			—			526			(3	)		(48	)		475
OM&A(4)		10		14		42			28			14			23			131			(1	)		—			130
Reclassifications and adjustments:
Parts and materials write-down		—		—		—			(5	)		—			—			(5	)		—			5			—
Adjusted OM&A		10		14		42			23			14			23			126			(1	)		5			130
Taxes, other than income taxes		—		3		4			1			—			1			9			—			—			9
Net other operating (income) loss		—		—		(10	)		57			—			—			47			—			—			47
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties		—		—		—			(58	)		—			—			(58	)		—			58			—
Adjusted net other operating income		—		—		(10	)		(1	)		—			—			(11	)		—			58			47
Adjusted EBITDA(5)		82		55		155			55			79			(24	)		402
Equity income																											1
Finance lease income																											6
Depreciation and amortization																											(123	)
Asset impairment charges																											(575	)
Net interest expense																											(63	)
Foreign exchange gain																											1
Gain on sale of assets and other																											23
Loss before income taxes																											(441	)

(1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) During the three months ended Sept. 30, 2021, $1 million related to station service costs for the Hydro segment was reclassified from OM&A to fuel and purchased power for comparative purposes. This did not impact previously reported net earnings.

(5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

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Notes to Condensed Consolidated Financial Statements

9 months ended Sept. 30, 2022	Hydro		Wind & Solar(1)			Gas(2)			Energy Transition(3)			Energy Marketing		Corporate			Total			Equity accounted investments(1)			Reclass Adjustments			IFRS Financials
Revenues		447		205			933			433			116		(2	)		2,132			(10	)		—			2,122
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		81			13			17			—		—			111			—			(111	)		—
Realized (gain) loss on closed exchange positions		—		—			(11	)		—			27		—			16			—			(16	)		—
Decrease in finance lease receivable		—		—			34			—			—		—			34			—			(34	)		—
Finance lease income		—		—			15			—			—		—			15			—			(15	)		—
Adjusted revenues		447		286			984			450			143		(2	)		2,308			(10	)		(176	)		2,122
Fuel and purchased power		17		20			445			332			—		3			817			—			—			817
Reclassifications and adjustments:
Australian interest income		—		—			(3	)		—			—		—			(3	)		—			3			—
Adjusted fuel and purchased power		17		20			442			332			—		3			814			—			3			817
Carbon compliance		—		1			56			(1	)		—		(5	)		51			—			—			51
Gross margin		430		265			486			119			143		—			1,443			(10	)		(179	)		1,254
OM&A		33		50			138			50			23		71			365			(1	)		—			364
Taxes, other than income taxes		3		7			13			2			—		1			26			(1	)		—			25
Net other operating income		—		(18	)		(30	)		—			—		—			(48	)		—			—			(48	)
Reclassifications and adjustments:
Insurance recovery		—		7			—			—			—		—			7			—			(7	)		—
Adjusted net other operating income		—		(11	)		(30	)		—			—		—			(41	)		—			(7	)		(48	)
Adjusted EBITDA(4)		394		219			365			67			120		(72	)		1,093
Equity income																											5
Finance lease income																											15
Depreciation and amortization																											(411	)
Asset impairment charges																											(4	)
Net interest expense																											(195	)
Foreign exchange gain																											17
Gain on sale of assets and other																											6
Earnings before income taxes																											346

(1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

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Notes to Condensed Consolidated Financial Statements

9 months ended Sept. 30, 2021	Hydro		Wind & Solar(1)		Gas(2)			Energy Transition(3)			Energy Marketing			Corporate			Total			Equity accounted investments(1)			Reclass Adjustments			IFRS Financials
Revenues		299		225		937			471			185			6			2,123			(12	)		—			2,111
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		22		(122	)		27			(26	)		—			(99	)		—			99			—
Realized loss on closed exchange positions		—		—		1			—			49			—			50			—			(50	)		—
Decrease in finance lease receivable		—		—		30			—			—			—			30			—			(30	)		—
Finance lease income		—		—		19			—			—			—			19			—			(19	)		—
Unrealized foreign exchange gain on commodity		—		—		(3	)		—			—			—			(3	)		—			3			—
Adjusted revenues		299		247		862			498			208			6			2,120			(12	)		3			2,111
Fuel and purchased power(4)		13		11		347			411			—			6			788			—			—			788
Reclassifications and adjustments:
Australian interest income		—		—		(3	)		—			—			—			(3	)		—			3			—
Mine depreciation		—		—		(79	)		(100	)		—			—			(179	)		—			179			—
Coal inventory write-down		—		—		—			(16	)		—			—			(16	)		—			16			—
Adjusted fuel and purchased power		13		11		265			295			—			6			590			—			198			788
Carbon compliance		—		—		104			35			—			—			139			—			—			139
Gross margin		286		236		493			168			208			—			1,391			(12	)		(195	)		1,184
OM&A(4)		29		42		129			97			31			55			383			(2	)		—			381
Reclassifications and adjustments:
Parts and materials write-down		—		—		(2	)		(28	)		—			—			(30	)		—			30			—
Adjusted OM&A		29		42		127			69			31			55			353			(2	)		30			381
Taxes, other than income taxes		2		8		11			5			—			1			27			(1	)		—			26
Net other operating (income) loss		—		—		(30	)		56			—			—			26			—			—			26
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties		—		—		—			(58	)		—			—			(58	)		—			58			—
Adjusted net other operating income		—		—		(30	)		(2	)		—			—			(32	)		—			58			26
Adjusted EBITDA(5)		255		186		385			96			177			(56	)		1,043
Equity income																											5
Finance lease income																											19
Depreciation and amortization																											(395	)
Asset impairment charges																											(620	)
Net interest expense																											(186	)
Foreign exchange gain																											22
Gain on sale of assets and other																											56
Loss before income taxes																											(348	)

(1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.

SC-42

Notes to Condensed Consolidated Financial Statements

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) During the nine months ended Sept. 30, 2021, $6 million related to station service costs for the Hydro segment was reclassified from OM&A to fuel and purchased power for comparative purposes. This did not impact previously reported net earnings.

(5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

SC-43

Notes to Condensed Consolidated Financial Statements

Depreciation and Amortization on the Condensed Consolidated Statements of Cash Flows

The reconciliation between depreciation and amortization reported on the condensed consolidated statements of earnings (loss) and the condensed consolidated statements of cash flows is presented below:

	3 months ended Sept. 30				9 months ended Sept. 30
	2022		2021		2022		2021
Depreciation and amortization expense on the condensed consolidated statements of earnings (loss)		179		123		411		395
Depreciation included in fuel and purchased power (Note 4)		—		74		—		179
Depreciation and amortization on the condensed consolidated statements of cash flows		179		197		411		574

SC-44

EXHIBIT “D” – INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See attached.

SD-1

TRANSALTA CORPORATION

Management’s Discussion and Analysis

Third Quarter Report for 2022

This Management’s Discussion and Analysis (“MD&A”) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. Refer to the Forward-Looking Statements section of this MD&A for additional information.

Table of Contents
Forward-Looking Statements	M2
Description of the Business	M4
Highlights	M6
Significant and Subsequent Events	M9
Performance by Segment with Supplemental Geographical Information	M13
Alberta Electricity Portfolio	M14
Segmented Financial Performance and Operating Results	M17
Selected Quarterly Information	M25
Strategy and Capability to Deliver Results	M26
2022 Financial Outlook	M33
Financial Position	M35
Financial Capital	M37
Other Consolidated Analysis	M41
Cash Flows	M43
Financial Instruments	M44
Additional IFRS Measures and Non-IFRS Measures	M44
Financial Highlights on a Proportional Basis of TransAlta Renewables	M53
Key Non-IFRS Financial Ratios	M55
Critical Accounting Policies and Estimates	M60
Accounting Changes	M62
Governance and Risk Management	M62
Regulatory Updates	M63
Disclosure Controls and Procedures	M64

This MD&A should be read in conjunction with the unaudited interim condensed consolidated financial statements of TransAlta Corporation as at and for the three and nine months ended Sept. 30, 2022 and 2021, and should also be read in conjunction with the audited annual consolidated financial statements and MD&A (“2021 Annual MD&A”) contained within our 2021 Annual Integrated Report. In this MD&A, unless the context otherwise requires, “we”, “our”, “us”, the “Company” and “TransAlta” refers to TransAlta Corporation and its subsidiaries. Our unaudited interim condensed consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) International Accounting Standards (“IAS”) 34 Interim Financial Reporting for Canadian publicly accountable enterprises as issued by the International Accounting Standards Board (“IASB”) and in effect at Sept. 30, 2022. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. This MD&A is dated Nov. 7, 2022. Additional information respecting TransAlta, including our Annual Information Form (“AIF”) for the year ended Dec. 31, 2021, 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.

SD-2

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 (“US”) securities laws, including the US 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 assumptions were 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, statements relating to: our Clean Electricity Growth Plan and ability to achieve the target of 2 gigawatts (“GW”) of incremental renewables capacity with an estimated capital investment of $3 billion that is expected to deliver incremental average annual EBITDA of $250 million; the Company’s projects under construction, including the timing of commercial operations, expected annual EBITDA and associated costs, including the Horizon Hill wind project (“Horizon Hill wind project”), the White Rock East and White Rock West wind power projects (“White Rock wind projects”), Northern Goldfields solar project, Garden Plain wind project and the Mount Keith 132kV transmission expansion; the execution of the Company’s early and advanced stage development pipeline, including the size, cost and expected EBITDA from such projects; the expansion of the Company’s early stage development pipeline to 5 GW; the proportion of EBITDA to be generated from renewable sources by the end of 2025; the 2022 Financial Outlook (defined below), including adjusted EBITDA and free cash flow; the Company’s ability to enhance shareholder value through its NCIB (as defined below); the reduction of carbon emissions by 75 per cent from 2015 emissions levels by 2026; the remediation of the Kent Hills 1 and 2 wind facilities, including, the timing and cost of such remediation, the resulting impact of such remediation on the Company’s revenues and the potential battery storage project at and repowering of, the Kent Hills facilities; the expected impact and quantum of carbon compliance costs; the ability to realize future growth opportunities with BHP (as defined below); regulatory developments and their expected impact on the Company, including the Canadian federal climate plan and the implementation of the major aspects thereof (including increased carbon pricing and increased funding for clean technology), the proposed new Clean Electricity Regulation, the Clean Fuel Regulations and Canadian Greenhouse Gas Offset Credit System Regulations and the ability of the Company to realize benefits from Canadian, United States and Australian regulatory developments, including receiving funding for clean electricity projects; the potential increase in value of emission reduction credits; sustaining and productivity capital in 2022; expected power prices in Alberta, Ontario and the Pacific Northwest; AECO gas price assumptions; the cyclicality of the business, including as it relates to maintenance costs, production and loads; expectations regarding refinancing the debt maturing in 2022; and the Company continuing to maintain a strong financial position and significant liquidity without any significant impact from the current economic environment.

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 beyond those that have already been announced; no significant changes to fuel and purchased power costs; no material adverse impacts to the long-term investment and credit markets; no significant changes to power price and hedging assumptions including, Alberta spot prices of $125/MWh to $150/MWh in 2022 and Mid-Columbia spot prices of US$55/MWh to US$65/MWh in 2022; AECO gas prices of between $5.00/GJ and $6.00/GJ; sustaining capital of 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.

SD-3

Management’s Discussion and Analysis

$145 million to $155 million; Energy Marketing adjusted gross margin of $145 to $160 million; no significant changes to gas commodity prices and transport costs; the Company’s proportionate ownership of TransAlta Renewables Inc. (“TransAlta Renewables”) not changing materially; no decline in the dividends to be received from TransAlta Renewables; and the impacts arising from COVID-19 not becoming significantly more onerous on the Company.

Forward-looking statements are subject to a number of significant risks and uncertainties 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 risks relating to: increased force majeure claims; reduced labour availability and ability to continue to staff our operations and facilities; disruptions to our supply chains, including our ability to secure necessary equipment; our ability to obtain regulatory and any other third party approvals on the expected timelines or at all in respect of our growth projects; risks associated with development and construction projects, including as it pertains to increased capital costs, permitting, labour and engineering risks and potential delays in the construction or commissioning of such projects; restricted access to capital and increased borrowing costs; changes in short-term and long-term electricity supply and demand; fluctuations in market prices, including lower merchant pricing in Alberta, Ontario and Mid-Columbia; reductions in production; a higher rate of losses on our accounts receivable; impairments and/or write-downs of assets; adverse impacts on our information technology systems and our internal control systems, including increased cybersecurity threats; commodity risk management and energy trading risks, including the effectiveness of the Company’s risk management tools associated with hedging and trading procedures to protect against significant losses; 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; changes to the legislative, regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; disruptions in the transmission and distribution of electricity; the effects of weather, including man made or natural disasters and other climate-change related risks; increases in costs; reductions to our generating units’ relative efficiency or capacity factors; disruptions in the source of fuels, including natural gas, water, solar or wind resources required to operate our facilities; operational risks, unplanned outages and equipment failure and our ability to carry out or have completed any repairs in a cost-effective or timely manner or at all, including as it applies to the remediation and replacement of turbine foundations of the Kent Hills 1 and 2 wind facilities; general economic risks, including deterioration of equity markets, increasing interest rates or rising inflation; failure to meet financial expectations; general domestic and international economic and political developments; armed hostilities, including the war in Ukraine and associated impacts; the threat of terrorism; adverse diplomatic developments or other similar events that could adversely affect our business; industry risk and competition; fluctuations in the value of foreign currencies; structural subordination of securities; counterparty credit risk; changes to our relationship with, or ownership of, TransAlta Renewables; changes in the payment or receipt of future dividends, including from TransAlta Renewables; inadequacy or unavailability of insurance coverage; our provision for income taxes and any risk of reassessment; legal, regulatory and contractual disputes and proceedings involving the Company; reliance on key personnel; labour relations matters; and the impact of COVID-19. The foregoing risk factors, among others, are described in further detail in the Governance and Risk Management section of our 2021 Annual MD&A and the Risk Factors section in our AIF for the year ended Dec. 31,2021.

Readers are urged to consider these factors carefully in evaluating the forward-looking statements, which reflect the Company’s expectations only as of the date hereof and are cautioned not to place undue reliance on them. 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. The purpose of the financial outlooks contained herein is to give the reader information about management’s current expectations and plans and readers are cautioned that such information may not be appropriate for other purposes. In light of these risks, uncertainties and assumptions, the forward-looking statements

SD-4

Management’s Discussion and Analysis

Description of the Business

Portfolio of Assets

TransAlta is a Canadian corporation and one of Canada’s largest publicly traded power generators with over 111 years of operating experience. We own, operate and manage a geographically diversified portfolio of assets utilizing a broad range of fuels that includes water, wind, solar, natural gas and battery storage.

The following table provides our consolidated ownership of our facilities across the regions in which we operate as at Sept. 30, 2022:

As at Sept. 30, 2022		Hydro			Wind and Solar		Gas(5)		Energy Transition(6)		Total
	Gross installed capacity (MW)(1)		834			636		1,960		—		3,430
Alberta	Number of facilities		17			13		7		—		37
	Weighted average contract life(2)(3)(4)		—			6		1		—		2
	Gross installed capacity (MW)(1)		91			751		645		—		1,487
Canada, Excl. Alberta	Number of facilities		9			9		3		—		21
	Weighted average contract life(3)		6	��		12		10		—		9
	Gross installed capacity (MW)(1)		—			519		29		671		1,219
United States	Number of facilities		—			7		1		2		10
	Weighted average contract life(3)		—			11		3		3		7
	Gross installed capacity (MW)(1)		—			—		450		—		450
Australia	Number of facilities		—			—		6		—		6
	Weighted average contract life(3)		—			—		16		—		16
	Gross installed capacity (MW)(1)		925			1,906		3,084		671		6,586
Total	Number of facilities		26			29		17		2		74
	Weighted average contract life(3)		1			10		5		3		6

(1) Gross Installed capacity for consolidated reporting represents 100 per cent output of a facility. Capacity figures for Wind and Solar Includes 100 per cent of the Kent Hills wind facilities; Gas includes 100 per cent of the Ottawa and Windsor facilities, 100 per cent of the Poplar Creek facility, 50 per cent of the Sheerness facility and 60 per cent of the Fort Saskatchewan facility.

(2) The weighted average contract life for Hydro and certain gas and wind assets in Alberta are nil as they are operating primarily on a merchant basis in the Alberta market. Refer to the Alberta Electricity Portfolio section for more information.

(3) For power generated under long-term power purchase agreements (“PPA”), power hedge contracts and short-term and long-term industrial contracts, the PPAs have a weighted average remaining contract life based on long-term average gross installed capacity.

SD-5

Management’s Discussion and Analysis

(4) The weighted average remaining contract life is related to the contract period for McBride Lake (38 MW), Windrise Wind (206 MW), Poplar Creek (115 MW) and Fort Saskatchewan (71 MW), with the remaining wind and gas facilities operated on a merchant basis in the Alberta market.

(5) The Gas segment includes the segments previously known as Australian Gas and North American Gas and the coal-fired generation assets converted to gas from the segment previously known as Alberta Thermal.

(6) The Energy Transition segment includes Centralia Unit 2 and the Skookumchuck dam.

The Company has retired all coal-fired generating assets located in Alberta within the Energy Transition segment. Effective Dec. 31, 2021, Keephills Unit 1 was retired and Sundance Unit 4 was retired from service effective March 31, 2022, resulting in a reduction in capacity of 801 MW within the Energy Transition segment from Dec. 31, 2021.

SD-6

Management’s Discussion and Analysis

Highlights

Unaudited Interim Condensed Consolidated Financial Highlights

	3 months ended Sept. 30					9 months ended Sept. 30
	2022		2021			2022		2021
Adjusted availability (%)		93.8		89.2			90.1		87.5
Production (GWh)		5,432		6,053			15,253		16,282
Revenues		929		850			2,122		2,111
Fuel and purchased power(1)		348		328			817		788
Carbon compliance		23		47			51		139
Operations, maintenance and administration(1)		135		130			364		381
Adjusted EBITDA(2)		555		402			1,093		1,043
Earnings (loss) before income taxes		126		(441	)		346		(348	)
Net earnings (loss) attributable to common shareholders		61		(456	)		167		(498	)
Cash flow from operating activities		204		610			526		947
Funds from operations(2)		488		318			887		808
Free cash flow(2)		393		210			646		506
Net earnings (loss) per share attributable to common shareholders, basic and diluted		0.23		(1.68	)		0.62		(1.84	)
Dividends declared per common share(3)		0.050		0.045			0.100		0.090
Dividends declared per preferred share(3)		0.2896		0.2484			0.5453		0.5075
Funds from operations per share(2)(4)		1.80		1.17			3.27		2.98
Free cash flow per share(2)(4)		1.45		0.77			2.38		1.87

As at	Sept. 30, 2022		Dec. 31, 2021
Total assets		10,045		9,226
Total consolidated net debt(5)		2,700		2,636
Total long-term liabilities		4,668		4,702
Total liabilities		7,628		6,633

(1) During the three and nine months ended Sept. 30, 2021, $1 million, and $6 million, respectively, related to station service costs for the Hydro segment was reclassified from OM&A to fuel and purchased power for comparative purposes. This did not impact previously reported net earnings.

(2) These items are not defined and have no standardized meaning under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings (loss) trends more readily in comparison with prior periods’ results. Please refer to the Segmented Financial Performance and Operating Results Section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. Please see also the Additional IFRS Measures and NON-IFRS Measures section of this MD&A.

(3) Weighted average of the Series A, B, C, D, E and G preferred share dividends declared. Dividends declared vary period over period due to the timing or dividend declarations and quarterly floating rates.

(4) Funds from operations (“FFO”) per share and free cash flow (“FCF”) per share are calculated using the weighted average number of common shares outstanding during the Period. The weighted average number

SD-7

Management’s Discussion and Analysis

of common shares outstanding for the three and nine months ended Sept. 30, 2022, was 271 million shares (Sept. 30, 2021 — 271 million for both periods). Please refer to the Additional IFRS Measures and Non-IFRS Measures section in this MD&A for the purpose of these non-IFRS ratios.

(5) Total consolidated net debt includes long-term debt, including current portion, amounts due under credit facilities, exchangeable securities, US tax equity financing and lease liabilities, net of available cash and cash equivalents, the principal portion of restricted cash on our subsidiary TransAlta OCP LP (“TransAlta OCP”) and the fair value of economic hedging instruments on debt. Please refer to the table in the Financial Capital section of this MD&A for more details on the composition of total consolidated net debt.

For the three and nine months ended Sept. 30, 2022, we have generated exceptional performance from our Alberta Electricity Portfolio, driving overall strong performance for the Company. Both the Hydro and the Gas segments had high availability during periods of peak pricing. Higher power prices were mainly due to above normal temperatures increasing the demand for electricity, higher power prices in adjacent markets reducing electricity imports, and periods of significant planned and unplanned thermal and transmission outages. The Alberta merchant portfolio was positioned to capture opportunities from the strong spot market conditions through both energy and ancillary services revenues. Subsequent to the third quarter, we revised and increased our guidance for adjusted EBITDA and FCF based on the strong financial performance attained to date and our expectations for the balance of year. Please refer to the 2022 Financial Outlook section of this MD&A for more details on our updated guidance.

Adjusted availability for the three and nine months ended Sept. 30, 2022, was 93.8 per cent and 90.1 per cent, respectively, compared to 89.2 per cent and 87.5 per cent for the same periods in 2021. The increase was primarily due to lower planned outages within the Gas segment with the completion of the coal-to-gas conversions in 2021, and lower planned and unplanned outages at our Alberta Hydro Assets, partially offset by the extended outage at the Kent Hills 1 and 2 wind facilities. In addition, adjusted availability for the nine months ended Sept. 30, 2022, was further offset by the early-stage operational issues associated with the commissioning of the Windrise wind facility in the Wind and Solar segment.

Production for the three and nine months ended Sept. 30, 2022, was 5,432 gigawatt hours (“GWh”) and 15,253 gigawatt hours, respectively, compared to 6,053 GWh and 16,282 GWh in the same periods in 2021. The decrease in production was primarily due to the retirement of Keephills Unit 1 and Sundance Unit 4, portfolio optimization activities and the extended outage at the Kent Hills 1 and 2 wind facilities. This was partially offset by an increase in production from the addition of the Windrise wind facility commissioned in the fourth quarter of 2021 and North Carolina Solar facility acquired in the fourth quarter of 2021 in our Wind and Solar segment. Production for the three months ended Sept. 30, 2022, was also impacted by higher water resources and lower wind resources across North America driven by higher than average temperatures. Production for the nine months ended Sept. 30, 2022, was impacted by higher water resources and lower availability at the Windrise wind facility.

Revenues increased by $79 million and $11 million, respectively, for the three and nine months ended Sept. 30, 2022, compared to the same periods in 2021, mainly as a result of capturing higher realized energy prices within the Alberta electricity market through our optimization and operating activities and higher realized ancillary services prices and volumes in the Hydro segment. Revenues also increased due to higher merchant prices at Centralia partially offset by lower production. In addition, revenues during the third quarter of 2022, were partially offset by lower environmental credit sales. During the second quarter of 2021, the Company experienced unfavourable adjustments for unplanned steam supply outages and steam reconciliation adjustments that did not reoccur within the current period within the Gas segment.

Fuel and purchased power costs increased by $20 million and $29 million, respectively, for the three and nine months ended Sept. 30, 2022, compared to the same periods in 2021. Fuel and purchased power costs increased

SD-8

Management’s Discussion and Analysis

compared to 2021 due to higher natural gas prices and increased natural gas consumption for our converted units in 2022, partially offset by our hedged positions on gas, lower coal costs and no mine depreciation due to the termination of all coal-mining activities in Canada as of Dec. 31, 2021.

Carbon compliance costs decreased by $24 million and $88 million, respectively, for the three and nine months ended Sept. 30, 2022, compared to the same periods in 2021, primarily due to reductions in greenhouse gas (“GHG”) emissions, lower production and utilization of our compliance credits to settle a portion of the GHG obligation, partially offset by an increase in the carbon price per tonne. Lower GHG emissions were a direct result of operating exclusively on natural gas in Alberta rather than coal, resulting in changes in the fuel mix ratio.

Operations, maintenance and administration (“OM&A”) expenses increased by $5 million for the three months ended Sept. 30, 2022, compared to the same period in 2021. For the three months ended Sept. 30, 2021, the Company recorded a write-down of $5 million on parts and material inventory related to the Highvale mine and coal operations at our converted gas facilities. Excluding the impact of this write-down, OM&A increased by $10 million in 2022, mainly due to higher contractor costs, higher incentive accruals reflecting the Company’s performance, OM&A related to the addition of the Windrise wind and North Carolina Solar facilities and higher general operating expenses.

For the nine months ended Sept. 30, 2022, OM&A decreased by $17 million. For the nine months ended Sept. 30, 2021, the Company recorded a write-down of $30 million on parts and material inventory related to the retirement of the Highvale mine and coal operations at our converted gas facilities. In addition, during the first quarter of 2021, the Company recognized the Canada Emergency Wage Subsidy (“CEWS”) proceeds of $8 million. Excluding the impact of the write-downs and the CEWS funding, OM&A expenses were higher by $5 million in 2022, mainly due to higher contractor costs, higher incentive accruals reflecting Company’s performance, OM&A related to the addition of the Windrise wind and North Carolina Solar facilities and higher general operating expenses.

Adjusted EBITDA increased by $153 million for the three months ended Sept. 30, 2022, compared to the same period in 2021, largely due to strong performance from our Alberta Electricity Portfolio, driven primarily by the Hydro and Gas segments as a result of strong weather-adjusted demand and higher power prices. This was partially offset by lower adjusted EBITDA from the retirement of units in the Energy Transition segment, lower production and lower revenues in the Wind and Solar segment, lower gross margin in Energy Marketing and higher corporate expenses.

Adjusted EBITDA increased by $50 million for the nine months ended Sept. 30, 2022, compared to the same period in 2021, largely due to higher adjusted EBITDA from higher production and merchant power pricing in the Hydro segment, continuing strong performance and contribution from the Gas segment for Alberta, incremental production from new facilities, liquidated damages related to turbine availability at the Windrise wind facility, higher environmental credit sales in the Wind and Solar segment and lower carbon compliance costs in both the Gas and Energy Transition segments. This was partially offset from lower production from the Gas and Energy Transition segments, higher fuel and purchased power costs within the Gas segment. On a year-to-date basis, the Energy Marketing segment results were lower but in line with expectations compared with the exceptional results in the prior period. Significant changes in segmented adjusted EBITDA are highlighted in the Segmented Financial Performance and Operating Results section of this MD&A.

Earnings (loss) before income taxes increased by $567 million and $694 million, respectively, for the three and nine months ended Sept. 30, 2022, compared to the same periods in 2021. Net earnings attributable to common shareholders for the three and nine months ended Sept. 30, 2022, increased by $517 million and $665 million, respectively, to net earnings of $61 million and $167 million, respectively, compared to a net loss of $456 million and $498 million, respectively, for the same period in 2021. Net earnings attributable to common

SD-9

Management’s Discussion and Analysis

shareholders in 2021 were significantly impacted by asset impairment charges resulting from the Company’s decisions to shut down the Highvale mine, suspend the Sundance Unit 5 repowering project, and retire Sundance Unit 4 and Keephills Unit 1. The Company benefited from higher revenues and lower carbon compliance costs, partially offset by higher fuel and purchased power, higher depreciation due to the acceleration of useful lives on certain facilities and higher tax expense. In addition, during the nine months ended Sept. 30, 2022, the Company recognized liquidated damages payable to the Company related to turbine availability at the Windrise wind facility and insurance proceeds related to the replacement costs for a tower at the Kent Hills facility. During the nine months ended Sept. 30, 2021, the Company recognized a gain on the sale of the Pioneer Pipeline.

Cash flow from operating activities decreased by $406 million and $421 million, respectively, for the three and nine months ended Sept. 30, 2022, compared to the same periods in 2021, mainly due to unfavourable changes in working capital from higher accounts receivable and movements in the collateral accounts related to high commodity prices and volatility in the markets.

FCF, one of the Company’s key financial metrics, for the three and nine months ended Sept. 30, 2022, totaled $393 million and $646 million, respectively, compared to $210 million and $506 million, respectively, for the same periods in 2021. This represents an increase to FCF of $183 million and $140 million, respectively, driven primarily by higher adjusted EBITDA, higher realized foreign exchange gains, lower current income tax expenses and a decrease in sustaining capital spending related to fewer planned maintenance turnarounds.

Significant and Subsequent Events

Changes to the Board of Directors

On Sept. 30, 2022, Ms. Beverlee Park retired from TransAlta’s Board of Directors. Ms. Park served on the Board of Directors since 2015 and as Chair of the Audit, Finance and Risk Committee from April 2018 to April 2022. The Company recognizes her for the many contributions made by Ms. Park to TransAlta and thanks her for the many years of service.

New Term Facility

During the third quarter of 2022, the Company closed a two year $400 million floating rate Term Facility with its banking syndicate with a maturity date of Sept. 7, 2024.

Conversion Results for Series E and F Preferred Shares

On Sept. 21, 2022, there were 89,945 Cumulative Redeemable Rate Reset First Preferred Shares, Series E (“Series E Shares”) tendered for conversion, which was less than the one million shares required to give effect to conversions into Cumulative Redeemable Rate Reset First Preferred Shares, Series F (“Series F Shares”). As a result, the Series E Shares were not converted into Series F Shares.

Executed Contract Renewals with the IESO at Sarnia Cogeneration and Melancthon 1 Wind Facilities

On Aug. 23, 2022, TransAlta Renewables Inc., a subsidiary of the Company (“TransAlta Renewables”) announced that it was awarded capacity contracts for the Sarnia cogeneration facility and the Melancthon 1 wind facility from the Ontario Independent Electricity System Operator (“IESO”) as part of the lESO’s Medium-Term Capacity Procurement Request For Proposals (the “RFP”). The new capacity contracts for the Sarnia cogeneration facility and the Melancthon 1 wind facility run from May 1, 2026 to April 30, 2031. The Company expects the gross margin from the Sarnia cogeneration facility to be reduced by approximately 30 per cent per year as a result of the IESO price cap under the new contract.

SD-10

Management’s Discussion and Analysis

Sarnia Industrial Contract Extensions

During the second quarter of 2022, the Company executed contract extensions for the supply of electricity with three industrial customers, and steam with one of these customers, at the Sarnia cogeneration facility. These agreements will extend the delivery term from Dec. 31, 2022 to April 30, 2031, in one case, and to Dec. 31, 2032, for the other two.

TransAlta Debuts New Brand Reiterating Commitment to a Clean Energy Future

On June 20, 2022, the Company announced a new visual identity including logo and tagline, “Energizing the Future”. The new visual identity encapsulates the TransAlta of today while reinforcing the Company’s focus as a leader in creating a carbon-neutral future for our customers.

Conversion Results for Series C and D Preferred Shares

On June 16, 2022, the Company announced that 1,044,299 of its 11,000,000 currently outstanding Cumulative Redeemable Rate Reset First Preferred Shares, Series C (“Series C Shares”) were tendered for conversion, on a one-for-one basis, into Cumulative Redeemable Floating Rate First Preferred Shares, Series D (“Series D Shares”) after having taken into account all election notices.

Court of Appeal Upholds TransAlta’s Favourable Force Majeure Arbitration Decision

On June 9, 2022, the Alberta Court of Appeal released a unanimous decision dismissing ENMAX Energy Corporation’s (“ENMAX”) and the Balancing Pool’s application seeking to set aside an arbitration decision in favour of the Company. The Court of Appeal upheld the Company’s claim of force majeure that arose when its Keephills Unit 1 generating unit tripped offline in 2013. As a result of the decision, the Company’s claim of force majeure remains valid and the associated costs of the force majeure event will not be reassessed against TransAlta.

Keephills Unit 2 Stator Force Majeure Dispute Settled

After the Keephills Unit 1 stator force majeure outage in 2013, it was determined that Keephills Unit 2 could face a similar stator failure before the next planned outage. In response, the Company took Keephills Unit 2 offline between January 31, 2014 and March 15, 2014 to perform a full rewind of the generator stator and claimed force majeure. The Balancing Pool disputed this force majeure event but the dispute was held in abeyance pending the outcome of the Keephills Unit 1 stator force majeure dispute, which was recently concluded. The Company and the Balancing Pool recently settled this dispute and so both stator Force majeure claims have been resolved.

Kent Hills Wind Facilities Update

On June 2, 2022, TransAlta Renewables announced the rehabilitation plan for the Kent Hills 1 and 2 wind facilities together with the execution of amended and extended contracts with New Brunswick Power Corporation (“NB Power”) in respect of each of the Kent Hills 1, 2 and 3 wind facilities providing for an additional 10-year contract term to December 2045 and an effective 10 per cent reduction to the original contract prices from January 2023 through December 2033. In addition, both parties have agreed to work in good faith to evaluate the installation of a battery energy storage system at Kent Hills and to consider a potential repowering of Kent Hills at the end of life in 2045. A waiver for the Kent Hills wind non-recourse bonds (“KH Bonds”) was also obtained from the project bond holders and a supplemental indenture was entered into with the bond holders that facilitates the rehabilitation of the Kent Hills 1 and 2 wind facilities. Refer to the Wind and Solar section and Financial Capital section of this MD&A for further details.

SD-11

Management’s Discussion and Analysis

TSX Acceptance of Normal Course Issuer Bid

On May 24, 2022, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to renew its normal course issuer bid (“NCIB”) for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 17, 2022. 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 May 31, 2022 and ends on May 30, 2023, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election.

The NCIB provides the Company with a capital allocation alternative with a view to ensuring long-term shareholder value. TransAlta’s Board of Directors and Management believe that, from time to time, the market price of the common shares does not reflect their underlying value and purchases of common shares for cancellation under the NCIB may provide an opportunity to enhance shareholder value.

During the nine months ended Sept. 30, 2022, the Company purchased and cancelled a total of 2.7 million common shares at an average price of $12.50 per common share, for a total cost of $34 million.

Mount Keith 132kV Transmission Expansion

On May 3, 2022, TransAlta Renewables exercised its option to acquire an economic interest in the expansion of the Mount Keith 132kV transmission system in Western Australia, to support the Northern Goldfields-based operations of BHP Nickel West (“BHP”). Total construction capital is estimated at between AU$50 million and AU$53 million. Southern Cross Energy, a subsidiary of the Company, has entered into an engineering, procurement and construction agreement for the expansion. The project is being developed under the existing PPA with BHP, which has a term of 15 years. It is expected to be completed in the second half of 2023 and will generate annual adjusted EBITDA in the range of AU$6 million and AU$7 million. The project will facilitate the connection of additional generating capacity to our network to support BHP’s operations and increase its competitiveness as a supplier of low-carbon nickel.

Executed Long-term PPA for the Remaining 30 MW at Garden Plain

During the second quarter of 2022, the Company entered into a long-term PPA for the remaining 30 MW of renewable electricity and environmental attributes for the Garden Plain wind project in Alberta with a new investment-grade globally-recognized customer. The 130 MW Garden Plain wind project, which was announced in May 2021 with a 100 MW PPA contracted to Pembina Pipeline Corporation (“Pembina”), is now fully contracted with a weighted average contract life of approximately 17 years. Construction is underway with a target commercial operation date in the fourth quarter of 2022.

Energy Impact Partners (“EIP”) Investment

During the second quarter of 2022, the Company entered into a commitment to invest US$25 million over the next four years in EIP’s Deep Decarbonization Frontier Fund 1 (the “Frontier Fund”). The Company invested US$6 million in May 2022. The investment in the Frontier Fund provides the Company with a portfolio approach to investing in emerging technologies and the opportunity to identify, pilot, commercialize and bring to market emerging technologies that will facilitate the transition to net-zero emissions.

SD-12

Management’s Discussion and Analysis

Customer Update at White Rock Wind Projects

During the second quarter of 2022, TransAlta identified Amazon Energy LLC (“Amazon”) as the customer for the 300 MW White Rock wind projects, to be located in Caddo County, Oklahoma. On Dec. 22, 2021, Amazon and TransAlta entered into two long-term PPAs for the supply of 100 per cent of the generation from the projects. Construction activities started in the fall of 2022 with a target commercial operation date in the second half of 2023. TransAlta will construct, operate and own the facility.

MSCI Environmental, Social and Governance (“ESG”) Rating Upgrade

During the second quarter of 2022, TransAlta’s MSCI ESG Rating was upgraded to ‘A’ from ‘BBB’. The upgrade reflects the Company’s strong renewable energy growth compared to peers. In 2021, the Company grew its installed renewable energy capacity by 15 per cent through the acquisition and construction of solar and wind facilities and secured 600 MW in additional renewable energy projects. In line with its goal to reduce carbon emissions by 75 per cent from 2015 emissions levels by 2026, TransAlta also completed coal-to-gas conversions of its Canadian coal-fired facilities in 2021, nine years ahead of Alberta’s coal phase-out plan.

Horizon Hill Wind Project and Fully Executed Corporate PPA with Meta

On April 5, 2022, TransAlta executed a long-term renewable energy PPA with a subsidiary of Meta Platforms Inc. (“Meta”), formerly known as Facebook, Inc., for 100 per cent of the generation from its 200 MW Horizon Hill wind project to be located in Logan County, Oklahoma. Under this agreement, Meta will receive both renewable electricity and environmental attributes from the Horizon Hill facility. The facility will consist of a total of 34 Vestas turbines. Construction commenced in the fall of 2022 with a target commercial operation date in the second half of 2023. TransAlta will construct, operate and own the facility.

Refer to the audited annual 2021 consolidated financial statements within our 2021 Annual Integrated Report and our unaudited interim condensed consolidated financial statements for the three and nine months ended Sept. 30, 2022, for significant events impacting both prior and current year results.

SD-13

Management’s Discussion and Analysis

Performance by Segment with Supplemental Geographical Information

The following table provides the performance of our facilities across the regions in which we operate:

3 months ended Sept. 30, 2022	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)			Energy Marketing		Corporate and Other			Total
Alberta		239		14		139		(6	)		53		(31	)		408
Canada, excluding Alberta		6		14		21		—			—		—			41
United States		—		14		2		57			—		—			73
Australia		—		—		33		—			—		—			33
Adjusted EBITDA(3)		245		42		195		51			53		(31	)		555
Earnings before income taxes																126
3 months ended Sept. 30, 2021	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)			Energy Marketing		Corporate and Other			Total
Alberta		78		21		94		18			79		(24	)		266
Canada, excluding Alberta		4		21		22		—			—		—			47
United States		—		13		3		37			—		—			53
Australia		—		—		36		—			—		—			36
Adjusted EBITDA(3)		82		55		155		55			79		(24	)		402
Loss before income taxes																(441	)
9 months ended Sept. 30, 2022	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)			Energy Marketing		Corporate and Other			Total
Alberta		382		85		194		(12	)		120		(72	)		697
Canada, excluding Alberta		12		70		64		—			—		—			146
United States		—		64		6		79			—		—			149
Australia		—		—		101		—			—		—			101
Adjusted EBITDA(3)		394		219		365		67			120		(72	)		1,093
Earnings before income taxes																346
9 months ended Sept. 30, 2021	Hydro		Wind and Solar		Gas(1)		Energy Transition(2)			Energy Marketing		Corporate and Other			Total
Alberta		245		41		227		33			177		(56	)		667
Canada, excluding Alberta		10		92		51		—			—		—			153
United States		—		53		8		63			—		—			124
Australia		—		—		99		—			—		—			99
Adjusted EBITDA(3)		255		186		385		96			177		(56	)		1,043
Loss before income taxes																(348	)

(1) The Gas segment includes the segments previously known as Australian Gas and North American Gas and the coal-fired generation assets converted to gas from the segment previously known as Alberta Thermal.

(2) The Energy Transition segment includes the segment previously known as Centralia and the coal-fired generation assets not converted to gas and the mining assets from the segment previously known as Alberta Thermal. Keephills Unit 1 was retired Dec. 31, 2021 and Sundance Unit 4 was retired March 31, 2022.

(3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Presenting this from period to period provides management and investors with the ability to evaluate earnings (loss) trends more readily in comparison with prior periods’ results. Please refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

SD-14

Management’s Discussion and Analysis

Alberta Electricity Portfolio

Approximately 52 per cent of our gross installed capacity is located in Alberta. Our portfolio of merchant assets in Alberta consists of hydro facilities, wind facilities, a battery storage facility, cogeneration facilities and converted natural gas-fired thermal facilities. Some of the wind and gas facilities within the Alberta Electricity Portfolio operate on long-term contracts. Optimization of portfolio performance is driven by the diversity of fuel types, which enables portfolio management and allows for maximization of operating margins. It also provides us with capacity that can be monetized as ancillary services or dispatched into the energy market during times of supply tightness. A portion of the installed generation capacity in the portfolio has been hedged to provide cash flow certainty.

Generating energy in Alberta is subject to market forces, rather than rate regulation. Energy from commercial generation is cleared through a wholesale electricity market. Energy is dispatched in accordance with an economic merit order administered by the Alberta Electric System Operator (“AESO”), based upon offers by generators to sell energy in the real-time energy-only market. Our merchant Alberta fleet operates under this framework and we internally manage our offers to sell energy.

	2022											2021
3 months ended Sept. 30	Hydro		Wind and Solar		Gas		Energy Transition			Total		Hydro		Wind and Solar		Gas		Energy Transition		Total
Total Production (GWh)(1)		614		259		1,993		—			2,866		513		259		2,025		600		3,397
Contract Production (GWh)		4		111		127		—			242		—		55		117		—		172
Merchant Production (GWh)		610		148		1,866		—			2,624		513		204		1,908		600		3,225
Revenues(2)		256		25		290		(2	)		569		90		29		205		59		383
Fuel and purchased power(3)		6		3		110		—			119		3		2		68		17		90
Carbon compliance		—		1		23		2			26		—		—		27		15		42
Gross margin		250		21		157		(4	)		424		87		27		110		27		251
	2022											2021
9 months ended Sept. 30	Hydro		Wind and Solar		Gas		Energy Transition			Total		Hydro		Wind and Solar		Gas		Energy Transition		Total
Total Production (GWh)(1)		1,356		1,211		5,537		19			8,123		1,263		819		5,953		1,416		9,451
Contract Production (GWh)		4		433		385		—			822		—		108		367		—		475
Merchant Production (GWh)		1,352		778		5,152		19			7,301		1,263		711		5,586		1,416		8,976
Revenues(2)		426		109		588		5			1,128		282		64		544		149		1,039
Fuel and purchased power(3)		14		12		294		5			325		5		5		187		48		245
Carbon compliance		—		1		47		(1	)		47		—		—		87		35		122
Gross margin		412		96		247		1			756		277		59		270		66		672

(1) Units in the Gas and Energy Transition segments in the prior periods operated on coal. Keephills Unit 1 was retired Dec. 31, 2021, and Sundance Unit 4 was retired March 31, 2022.

(2) Adjustments to revenues include the impact of unrealized mark-to-market gains or losses and realized gains and losses on closed exchange positions.

(3) Adjustments to fuel and purchased power include the impact of coal mine depreciation and coal inventory write-downs at the Highvale mine in 2021.

SD-15

Management’s Discussion and Analysis

For the three and nine months ended Sept. 30, 2022, the Alberta Electricity Portfolio generated 2,866 GWh and 8,123 GWh of energy, respectively, a decrease of 531 GWh and 1,328 GWh, respectively, compared to the same periods in 2021. Production was impacted by the retirement of Keephills Unit 1 on Dec. 31, 2021, and Sundance Unit 4 on March 31, 2022, dispatch optimization, lower wind resources impacted the three-month period, partially offset by increased production from the addition of the Windrise wind facility commissioned in the fourth quarter of 2021. Production in the three months ended Sept. 30, 2022, benefited from higher water resources from a delayed spring runoff.

Gross margin for the three and nine months ended Sept. 30, 2022, was $424 million and $756 million, respectively, an increase of $173 million and $84 million, respectively, compared to the same periods in 2021. Gross margin for the three months ended Sept. 30, 2022, was positively impacted by higher merchant pricing resulting from strong weather-driven demand, higher natural gas prices and higher power prices in adjacent markets compared to 2021. Energy and ancillary services revenue from the Hydro segment was higher as a result of higher power prices and market volatility. Gross margin for the nine months ended Sept. 30, 2022, was positively impacted by strong weather-driven demand, partially offset by a better-supplied market. The Gas and Energy Transition segment results were impacted by lower production due to unit retirements and higher dispatch optimization in response to lower market heat rates and higher gas prices.

The following table provides information about the Company’s Alberta Electricity Portfolio:

	3 months ended Sept. 30				9 months ended Sept. 30
	2022		2021		2022		2021
Spot power price average per MWh	$	221	$	100	$	145	$	100
Natural gas price (AECO) per GJ	$	4.04	$	3.29	$	5.14	$	3.04
Carbon compliance price per tonne	$	50	$	40	$	50	$	40
Realized merchant power price per MWh(1)	$	253	$	113	$	164	$	112
Hydro energy spot power price per MWh	$	246	$	110	$	177	$	116
Hydro ancillary spot price per MWh	$	128	$	47	$	74	$	58
Wind energy spot power price per MWh	$	136	$	73	$	86	$	58
Gas and Energy Transition spot power price per MWh	$	264	$	121	$	171	$	115
Hedged volume(2)		1,681		1,863		5,320		5,158
Hedged power price average per MWh	$	80	$	76	$	79	$	67
Fuel and purchased power per MWh(3)	$	60	$	34	$	58	$	33
Carbon compliance cost per MWh(3)	$	13	$	16	$	8	$	17

(1) Realized power price for the Alberta Electricity Portfolio is the average price realized as a result of the Company’s merchant power sales (excluding assets under long-term contract and ancillary revenues) and portfolio optimization activities divided by total merchant GWh produced.

(2) Hedge volumes are for expected production volumes primarily from the Gas segment.

(3) Fuel and purchased power per MWh and carbon compliance cost per MWh are calculated on production from carbon-emitting generation segments in Gas and Energy Transition and carbon compliance cost per MWh includes compliance credits to settle a portion of our GHG carbon pricing obligations.

For the three and nine months ended Sept. 30, 2022, the spot power price increased to $221 per MWh and $145 per MWh, respectively, from $100 per MWh in both periods in 2021.

For the three and nine months ended Sept. 30, 2022, the realized merchant power price per MWh of production increased by $140 and $52 per MWh, respectively, compared with the same periods in 2021. Higher realized merchant power pricing for energy across the fleet was due to higher market prices, increased price volatility and

SD-16

Management’s Discussion and Analysis

optimization of our available capacity across all fuel types. The segment spot prices exclude gains and losses from hedging positions that are entered into in order to mitigate the impact of unfavourable market pricing.

For the three and nine months ended Sept. 30, 2022, the Hydro ancillary spot power price increased to $128 and $74 per MWh, respectively, compared with the same periods in 2021, due to higher power prices mainly related to higher natural gas prices and stronger weather-driven demand compared to the same periods in 2021.

For the three and nine months ended Sept. 30, 2022, the fuel and purchased power cost per MWh of production increased by $26 per MWh and $25 per MWh, respectively, compared to the same periods in 2021, due to higher natural gas pricing, higher fixed gas transportation costs, partially offset by our hedge positions for gas prices and lower coal costs due to the cessation of mining operations in 2021.

For the three and nine months ended Sept. 30, 2022, carbon compliance costs per MWh of production decreased by $3 per MWh and $9 per MWh, respectively, compared to the same periods in 2021, primarily due to lower carbon emissions from the retirement of our coal fleet and the utilization of compliance credits to settle a portion of our GHG carbon pricing obligation for 2021. Carbon compliance prices have increased to $50 per tonne from $40 per tonne; however, the shift to gas-fired generation effectively lowered our GHG compliance costs as natural gas combustion produces lower GHG emissions than coal combustion.

SD-17

Segmented Financial Performance and Operating Results

Reporting Segment Changes

Segmented information is prepared on the same basis that the Company manages its business, evaluates financial results and makes key operating decisions. With the completion of the Clean Energy Transition plan and the announcement of our strategic focus on customer-centered renewable generation, the Company realigned its current operating segments during the fourth quarter of 2021 to better reflect the Company’s current strategic focus and to align with the Company’s Clean Electricity Growth Plan. The segment reporting changes reflect a corresponding change in how the President and Chief Executive Officer assess the performance of the Company.

The primary changes in 2021, were the elimination of the Alberta Thermal and the Centralia segments and the reorganization of the North American Gas and Australia Gas segments into a new “Gas” segment. The Alberta Thermal facilities that have been converted to gas are included in the Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets, those facilities not converted to gas and the remaining Centralia unit are included in a new “Energy Transition” segment. No changes have been made to the Hydro, Wind and Solar, Energy Marketing or the Corporate and Other segments. The prior year’s metrics were restated to reflect the re-alignment of the operating segments.

Consolidated Results

The following table reflects the generation and summary financial information on a consolidated basis for each of our segments:

	LTA Generation (GWh)(1)				Actual Production (GWh)(2)				Adjusted EBITDA(3)
3 months ended Sept. 30	2022		2021		2022		2021		2022			2021
Hydro		617		617		738		611		245			82
Wind and Solar		930		783		685		718		42			55
Renewables		1,547		1,400		1,423		1,329		287			137
Gas						2,842		2,913		195			155
Energy Transition						1,167		1,811		51			55
Energy Marketing										53			79
Corporate										(31	)		(24	)
Total						5,432		6,053		555			402
Total earnings (loss) before income taxes										126			(441	)
	LTA Generation (GWh)(1)				Actual Production (GWh)(2)				Adjusted EBITDA(3)
9 months ended Sept. 30	2022		2021		2022		2021		2022			2021
Hydro		1,592		1,592		1,644		1,525		394			255
Wind and Solar		3,451		2,860		3,026		2,675		219			186
Renewables		5,043		4,452		4,670		4,200		613			441
Gas						8,073		8,370		365			385
Energy Transition						2,510		3,712		67			96
Energy Marketing										120			177
Corporate										(72	)		(56	)
Total						15,253		16,282		1,093			1,043
Total earnings (loss) before income taxes										346			(348	)

(1) Long-term average production (“LTA Generation (GWh)”) is calculated based on our portfolio as at Sept. 30, 2022, on an annualized basis from the average annual energy yield predicted from our simulation model based on historical resource data performed over a period of typically 30-35 years for the Wind and Solar segments and 36 years for Hydro segment. LTA Generation (GWh) for Energy Transition is not considered

SD-18

as we are currently transitioning these units completely by the end of 2025 and the LTA Generation (GWh) for Gas is not considered as it is largely dependent on market conditions and merchant demand. LTA Generation (GWh) for the three and nine months ended Sept. 30, 2022, excluding the Kent Hills 1 and 2 wind facilities which are currently not in operation, is approximately 846 GWh and 3,176 GWh, respectively.

(2) Actual production levels are compared against the long-term average to highlight the impact of an important factor that affects the variability in our business results. In the short-term, for each of the Hydro and Wind and Solar segments, the conditions will vary from one period to the next and over time facilities will continue to produce in line with their long-term averages, which have proven to be reliable indicators of performance.

(3) These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Hydro

	3 months ended Sept. 30				9 months ended Sept. 30
	2022		2021		2022		2021
Gross installed capacity (MW)		925		925		925		925
LTA Generation (GWh)		617		617		1,592		1,592
Availability (%)		97.7		90.3		96.6		91.8
Contract production (GWh)		125		98		292		262
Merchant production (GWh)		613		513		1,352		1,263
Total energy production (GWh)		738		611		1,644		1,525
Ancillary service volumes (GWh)(1)		797		657		2,324		2,155
Alberta Hydro Assets(2)		151		54		240		145
Other Hydro assets and other revenue(2)(3)		12		12		34		32
Alberta Hydro Ancillary services(1)		102		30		172		125
Environmental attribute revenue		—		—		1		1
Total gross revenues		265		96		447		303
Net payment relating to Alberta Hydro PPA(4)		—		—		—		(4	)
Revenues		265		96		447		299
Fuel and purchased power(5)		7		4		17		13
Gross margin		258		92		430		286
OM&A(5)		12		10		33		29
Taxes, other than income taxes		1		—		3		2
Adjusted EBITDA		245		82		394		255
Supplemental Information:
Gross Revenues per MWh
Alberta Hydro Assets energy ($/MWh)		246		110		177		116
Alberta Hydro Assets ancillary ($/MWh)		128		46		74		58
Sustaining capital		8		6		20		18

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

(2) Alberta Hydro Assets include 13 hydro facilities on the Bow and North Saskatchewan river systems. Other Hydro energy include our hydro facilities in BC and Ontario, hydro facilities in Alberta other than the Alberta Hydro Assets and transmission revenues.

(3) Other revenue includes revenues from our transmission business and other contractual arrangements including the flood mitigation agreement with the Alberta government and black start services.

SD-19

(4) The net payment relating to the Alberta Hydro PPA represents the Company’s financial obligations for notional amounts of energy and ancillary services in accordance with the Alberta Hydro PPA that expired on Dec. 31, 2020. The amount in the first and second quarters of 2021 related to adjustments for the final payment under the Alberta PPA.

(5) During the three and nine months ended Sept. 30, 2021, $1 million and $6 million, respectively, related to station service costs for the Hydro segment were reclassified from OM&A to fuel and purchased power for comparative purposes. This did not impact previously reported net earnings.

Availability, for the three and nine months ended Sept. 30, 2022, increased compared to the same periods in 2021, primarily due to lower planned and unplanned outages at our Alberta Hydro Assets.

Production, for the three and nine months ended Sept. 30, 2022, increased by 127 GWh and 119 GWh, respectively, compared to the same periods in 2021, mainly due to higher water resources in the third quarter from a delayed spring runoff.

Ancillary service volumes, for the three and nine months ended Sept. 30, 2022, increased by 140 GWh and 169 GWh, respectively, compared to the same periods in 2021, due to higher availability and higher water resources in the third quarter from a delayed spring runoff.

Adjusted EBITDA, for the three and nine months ended Sept. 30, 2022, increased by $163 million and $139 million, respectively, compared to the same periods in 2021, primarily due to higher merchant pricing and higher ancillary services realized prices in the Alberta market as well as higher energy and ancillary services volumes due to higher water resources. OM&A costs for the year are higher due to increased insurance premiums for updated replacement value coverage. For further discussion on the Alberta market conditions and pricing, refer to the 2022 Financial Outlook section and Alberta Electricity Portfolio section of this MD&A.

Sustaining capital expenditures for the three and nine months ended Sept. 30, 2022, were consistent, compared with the same periods in 2021.

Wind and Solar

	3 months ended Sept. 30					9 months ended Sept. 30
	2022			2021		2022			2021
Gross installed capacity (MW)(1)		1,906			1,682		1,906			1,682
LTA Generation (GWh)		930			783		3,451			2,860
Availability (%)		85.0			94.0		83.1			94.8
Contract production (GWh)		537			514		2,247			1,964
Merchant production (GWh)		148			204		779			711
Total energy production (GWh)		685			718		3,026			2,675
Wind and Solar revenues		64			62		253			224
Environmental attribute revenue		3			14		33			23
Revenues(2)		67			76		286			247
Fuel and purchased power		6			4		20			11
Carbon compliance		—			—		1			—
Gross margin(2)		61			72		265			236
OM&A		19			14		50			42
Taxes, other than income taxes		1			3		7			8
Net other operating income(2)		(1	)		—		(11	)		—
Adjusted EBITDA(2)		42			55		219			186

SD-20

	3 months ended Sept. 30				9 months ended Sept. 30
	2022		2021		2022			2021
Supplemental information:
Sustaining capital		5		4		12			8
Kent Hills wind rehabilitation expenditures(3)		31		—		41			—
Insurance proceeds—Kent Hills		—		—		(7	)		—

(1) The gross installed capacity in 2022 includes incremental capacity related to new facilities: Windrise wind facility (206 MW), North Carolina Solar (122 MW) and Oldman wind facility (4 MW).

(2) For details of the adjustments to revenues and net other operating income included in adjusted EBITDA, refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.

(3) The Kent Hills wind facilities rehabilitation capital expenditures are segregated from the sustaining capital expenditures due to the extraordinary nature of the expenditures and have been reflected separately.

Availability, for the three and nine months ended Sept. 30, 2022, decreased compared to the same periods in 2021, primarily as a result of the extended outage at the Kent Hills 1 and 2 wind facilities. For the three months ended Sept. 30, 2022, availability was further impacted by planned and unplanned outages in Ontario. For the nine months ended Sept. 30, 2022, availability was also impacted by early-stage operational issues at our Windrise wind facility.

Production, for the three months ended Sept. 30, 2022, decreased by 33 GWh compared to the same period in 2021, primarily due to lower wind resources across North America driven by higher than average temperatures and lower availability, partially offset by increased production from the addition of the Windrise wind facility commissioned, and North Carolina Solar facility acquired, in the fourth quarter of 2021.

Production, for the nine months ended Sept. 30, 2022, increased by 351 GWh compared to the same period in 2021, primarily due to higher production from the addition of the Windrise wind and North Carolina Solar facilities and higher wind resources across North America, partially offset by lower production from the extended outage at the Kent Hills 1 and 2 wind facilities.

Adjusted EBITDA, for the three months ended Sept. 30, 2022, decreased by $13 million, compared to the same period in 2021, primarily due to lower production, lower environmental attribute revenues and an increase in OM&A related to the addition of the Windrise wind and North Carolina Solar facilities. This was partially offset by higher realized merchant pricing in Alberta.

Adjusted EBITDA, for the nine months ended Sept. 30, 2022, increased by $33 million, compared to the same period in 2021, primarily due to higher production, higher realized merchant pricing in Alberta, higher environmental attribute revenues and recognition of liquidated damages payable to the Company related to turbine availability at the Windrise wind facility. This was partially offset by an increase in transmission rates and OM&A related to the addition of the Windrise wind and North Carolina Solar facilities. A one-time favourable adjustment as a result of the AESO transmission line loss ruling was included in the nine months ended Sept. 30, 2021.

Sustaining capital expenditures for the three months ended Sept. 30, 2022, were consistent with the same period in 2021. Sustaining capital expenditures for the nine months ended Sept. 30, 2022, were $4 million higher compared to the same period in 2021, due to one-time sustaining capital investments in wind control systems in 2022.

The Kent Hills 1 and 2 wind facilities are not currently in operation following the tower failure event that occurred in September 2021. This event has taken approximately 150 MW of gross production offline temporarily as the Company replaces all 50 turbine foundations at the Kent Hills 1 and 2 wind facilities. The extended outage is expected to result in foregone revenue of approximately $3 million per month on an

SD-21

annualized basis (assuming all 50 turbines at the Kent Hills 1 and 2 wind facilities are offline), based on average historical wind production, with revenue expected to be earned as the wind turbines are returned to service.¹ Each turbine at Kent Hills 1 and 2 wind facilities will return to service as soon as its foundation is replaced and the turbine is reassembled and tested.

Kent Hills Wind LP (“KHLP”) has entered into agreements with vendors to complete the rehabilitation of the Kent Hills 1 and 2 wind facilities and has commenced execution of its rehabilitation plan. The current estimate of the capital expenditures is approximately $120 million, inclusive of insurance proceeds. Rehabilitation for the Kent Hills 1 and 2 wind facilities is well underway including turbine disassembly and foundation demolition. During the third quarter of 2022, over half of the towers have been fully disassembled including foundation removal. Construction of new foundations has begun with the first concrete pours completed and the new wind turbine components delivered to replace the unit that was damaged. Rehabilitation is targeted to be completed by the second half of 2023 for the Kent Hills 1 and 2 wind facilities.

The Company is actively evaluating all options that may be available to recover the rehabilitation costs from third parties and their insurance providers and intends to pursue claims to recover costs and related damages from those parties.

Gas

	3 months ended Sept. 30						9 months ended Sept. 30
	2022			2021			2022			2021
Gross installed capacity (MW)		3,084			3,084			3,084			3,084
Availability (%)		97.8			88.0			95.2			85.6
Contract production (GWh)		887			900			2,657			2,665
Merchant production (GWh)		1,974			2,038			5,460			5,834
Purchased power (GWh)		(19	)		(25	)		(44	)		(129	)
Total production (GWh)		2,842			2,913			8,073			8,370
Revenues(1)		431			326			984			862
Fuel and purchased power(1)		166			102			442			265
Carbon compliance		26			33			56			104
Gross margin(1)		239			191			486			493
OM&A(1)		49			42			138			127
Taxes, other than income taxes		5			4			13			11
Net other operating income		(10	)		(10	)		(30	)		(30	)
Adjusted EBITDA(1)		195			155			365			385
Supplemental information:
Sustaining capital		8			31			16			97

(1) For details of the adjustments to revenues, fuel and purchased power and OM&A included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

The Gas segment is a new segment as described in the Segmented Financial Performance and Operating Results section of this MD&A. Included in the Gas segment is the previous North American Gas segment, Australian Gas segment and the facilities from the previous Alberta Thermal segment which have been converted to gas. The previous Alberta thermal facilities included in the Gas segment include Sheerness Units 1 and 2, Keephills Units 2 and 3 and Sundance Unit 6. Prior periods have been adjusted to be comparable to the current period and reflect operations as coal units.

Availability, for the three and nine months ended Sept. 30, 2022, increased compared to the same periods in 2021, primarily due to higher reliability of the coal-to-gas converted units compared to coal.

¹  The Kent Hills 1 and 2 wind facilities lost production is based on average historical wind production.

SD-22

Production for the three and nine months ended Sept. 30, 2022, decreased by 71 GWh and 297 GWh, respectively, compared to the same periods in 2021, mainly due to dispatch optimization of our Alberta assets and lower customer demand in Ontario due to a customer outage, partially offset by higher demand in Australia at our South Hedland facility due to the Fortescue Metals Group Ltd. contract and higher production from our Ada cogeneration facility. The nine months ended Sept. 30, 2022, production was positively impacted by higher merchant demand in Ontario.

Adjusted EBITDA, for the three months ended Sept. 30, 2022, increased by $40 million, compared to the same period in 2021. The increase was primarily due to higher merchant pricing in Alberta, net of hedging, lower carbon costs and a favourable change in legal provisions, partially offset by lower production, higher natural gas prices and increased natural gas consumption. Lower carbon costs and increased natural gas consumption in the period were a result of no longer operating on coal.

Adjusted EBITDA, for the nine months ended Sept. 30, 2022, decreased by $20 million, compared to the same period in 2021. The decrease was primarily due to lower production, higher natural gas prices and increased OM&A due to higher incentive accruals related to the Company’s performance and increased general operating expenses, partially offset by lower carbon compliance costs and higher merchant pricing in Alberta, net of hedging. Carbon compliance costs were lower due to reductions in GHG emissions, lower production and utilization of our compliance credits to settle a portion of the GHG obligation, partially offset by an increase in the carbon price per tonne. Lower GHG emissions were a direct result of operating exclusively on natural gas in Alberta rather than coal, resulting in changes in the fuel mix ratio. The nine months ended Sept. 30, 2021, was also impacted by the unplanned short-term steam supply outages at the Sarnia cogeneration facility in 2021. Refer to the Alberta Electricity Portfolio section of this MD&A for further details.

Sustaining capital expenditures for the three and nine months ended Sept. 30, 2022, decreased by $23 million and $81 million, respectively, compared to the same periods in 2021, mainly due to the coal-to-gas conversions being completed in 2021.

Energy Transition

	3 months ended Sept. 30						9 months ended Sept. 30
	2022			2021			2022			2021
Gross installed capacity (MW)(1)		671			1,876			671			1,876
Availability (%)		96.6			85.6			77.4			76.1
Adjusted availability (%)(2)		96.6			85.6			79.8			80.8
Contract sales volume (GWh)		839			839			2,489			2,490
Merchant sales volume (GWh)		1,251			1,898			2,780			3,960
Purchased power (GWh)		(923	)		(926	)		(2,759	)		(2,738	)
Total production (GWh)		1,167			1,811			2,510			3,712
Revenues(3)		237			229			450			498
Fuel and purchased power(3)		167			137			332			295
Carbon compliance		2			14			(1	)		35
Gross margin(3)		68			78			119			168
OM&A(3)		17			23			50			69
Taxes, other than income taxes		—			1			2			5
Net other operating income		—			(1	)		—			(2	)
Adjusted EBITDA(3)		51			55			67			96

SD-23

	3 months ended Sept. 30				9 months ended Sept. 30
	2022		2021		2022		2021
Supplemental information:
Highvale mine reclamation spend		2		2		7		4
Centralia mine reclamation spend		4		4		11		8
Sustaining capital		2		—		18		13

(1) The gross installed capacity for the three and nine months ended Sept. 30, 2022, excludes Keephills Unit 1 (395 MW retired on Dec. 31, 2021), Sundance Unit 5 (406 MW retired on Nov. 1 2021) and Sundance Unit 4 (406 MW retired on March 31, 2022).

(2) Adjusted for dispatch optimization.

(3) For details of the adjustments to revenues, fuel and purchased power and OM&A included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Energy Transition segment is a new segment as described in the Segmented Financial Performance and Operating Results section of this MD&A. Included in the Energy Transition segment are the previous Centralia segment, mine assets and the previous Alberta Thermal segment facilities that were not converted to gas. The previous Alberta thermal facilities included in the Energy Transition segment include Keephills Unit 1 and Sundance Unit 4. Both units have since been retired. Previous periods have been adjusted to be comparable to the current period.

Adjusted availability, increased for the three months ended Sept. 30, 2022, compared to the same period in 2021, mainly due to lower unplanned outages at Centralia Unit 2. Adjusted availability for the nine months ended Sept. 30, 2022, decreased primarily due to the retirement of Sundance Unit 4 and Keephills Unit 1, partially offset by lower planned and unplanned outages at Centralia Unit 2.

Production, for the three and nine months ended Sept. 30, 2022, decreased by 644 GWh and 1,202 GWh, respectively, compared to the same periods in 2021, primarily due to the retirements of Keephills Unit 1 and Sundance Unit 4 and higher economic dispatch at Centralia Unit 2. For the nine months ended Sept. 30, 2022, the decrease in production is partially offset by increased production from higher availability at Centralia Unit 2.

Adjusted EBITDA, for the three and nine months ended Sept. 30, 2022, decreased by $4 million and $29 million, respectively, compared to the same periods in 2021. The decreases were primarily due to lower production and higher purchased power costs incurred due to higher power prices during outages at Centralia Unit 2 in 2022, partially offset by higher merchant pricing at Centralia and lower carbon costs in Alberta. Carbon costs were lower as the facilities in Alberta no longer operated on coal and have now been retired. For the nine months ended Sept. 30, 2022, the Company utilized 0.5 million tonnes of emission credits to settle the 2021 carbon compliance obligation, reducing our carbon compliance costs by $5 million.

Mine reclamation spend for the Highvale and Centralia mines for the three and nine months ended Sept. 30, 2022, increased due to the advancement of reclamation activities compared to the same periods in 2021.

The sustaining capital expenditures for the three and nine months ended Sept. 30, 2022, increased by $2 million and $5 million, respectively, compared to the same period in 2021, primarily due to major maintenance for the Centralia Unit 2.

SD-24

Energy Marketing

	3 months ended Sept. 30				9 months ended Sept. 30
	2022		2021		2022		2021
Revenues(1)		62		93		143		208
OM&A		9		14		23		31
Adjusted EBITDA(1)		53		79		120		177

(1) For details of the adjustments to revenues included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Adjusted EBITDA, for the three and nine months ended Sept. 30, 2022, decreased by $26 million and $57 million, respectively, compared to the same periods in 2021. The decrease for the three and nine months ended Sept. 30, 2022, exceeded segment expectations due to short-term trading of both physical and financial power and gas products across all North American markets but was below 2021 due to the exceptional results in the prior period. The Company was able to capitalize on short-term volatility in the trading markets without materially changing the risk profile of the business unit.

Corporate

	3 months ended Sept. 30						9 months ended Sept. 30
	2022			2021			2022			2021
OM&A		30			23			71			55
Taxes, other than income taxes		1			1			1			1
Adjusted EBITDA		(31	)		(24	)		(72	)		(56	)
Adjusted EBITDA		(31	)		(24	)		(72	)		(56	)
Total return swap (gains) losses		(1	)		1			—			(4	)
CEWS funding received		—			—			—			(8	)
CEWS funding applied to incremental employment		1			1			4			2
Adjusted EBITDA excluding impact of total return swap and CEWS		(31	)		(22	)		(68	)		(66	)
Supplemental information:
Total sustaining capital		4			3			9			8

Adjusted EBITDA, for the three and nine months ended Sept. 30, 2022, decreased by $7 million and $16 million, respectively, compared to the same periods in 2021. The decrease was mainly due to higher contractor costs, higher incentive accruals reflecting the Company’s performance and higher general operating expenses. For the nine months ended Sept. 30, 2021, adjusted EBITDA was positively impacted by the receipt of CEWS proceeds and gains on the total return swap.

For the three and nine months ended Sept. 30, 2022, sustaining capital expenditures were consistent with the same period in 2021.

SD-25

Selected Quarterly Information

Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are often 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 Centralia. Typically, hydroelectric 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.

	Q4 2021			Q1 2022			Q2 2022			Q3 2022
Revenues		610			735			458			929
Adjusted EBITDA(1)(2)		243			259			279			555
Earnings (loss) before income taxes		(32	)		242			(22	)		126
Cash flow (used in) from operating activities(3)		54			451			(129	)		204
FFO(1)(2)		186			179			220			488
FCF(1)(2)		79			108			145			393
Net earnings (loss) attributable to common shareholders		(78	)		186			(80	)		61
Net earnings (loss) per share attributable to common shareholders, basic and diluted(4)		(0.29	)		0.69			(0.30	)		0.23
	Q4 2020			Q1 2021			Q2 2021			Q3 2021
Revenues		544			642			619			850
Adjusted EBITDA(1)(2)		223			322			319			402
Earnings (loss) before income taxes		(168	)		21			72			(441	)
Cash flow from operating activities		110			257			80			610
FFO(1)(2)		150			223			267			318
FCF(1)(2)		41			141			155			210
Net loss attributable to common shareholders		(167	)		(30	)		(12	)		(456	)
Net loss per share attributable to common shareholders, basic and diluted(4)		(0.61	)		(0.11	)		(0.04	)		(1.68	)

(1) These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(2) The current quarter composition was updated and the previous periods have been reported to be consistent. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(3) The cash flow used in operating activities for the second quarter of 2022, decreased compared to prior quarters due to unfavourable changes in working capital mainly due to movements in our collateral accounts related to higher commodity prices and volatility in the markets.

(4) Basic and diluted earnings (loss) per share attributable to common shareholders is calculated each period using the weighted average common shares outstanding during the period. As a result, the sum of the earnings (loss) per share for the four quarters making up the calendar year may sometimes differ from the annual earnings (loss) per share.

Net earnings (loss) attributable to common shareholders has also been impacted by the following variations and events:

• The continued extended outage of the Kent Hills 1 and 2 wind facilities from the fourth quarter of 2021 to the third quarter of 2022;

• Accelerated timing of decommissioning cash flows and change in useful lives recognized in the third quarter of 2022;

SD-26

• Insurance proceeds for the single collapsed tower at Kent Hills wind facilities of $7 million recognized in the second quarter of 2022;

• Liquidated damages payable to the Company related to the turbine availability at the Windrise wind facility were recorded at $3 million, $7 million and $1 million in the first three quarters, respectively, of 2022;

• Lower carbon costs in 2022 related to going off coal and the utilization of renewable energy compliance credits to settle a portion of our GHG obligation in the second quarter of 2022;

• Keephills Unit 1 being retired in the fourth quarter of 2021 and Sundance Unit 4 being retired in the first quarter of 2022;

• Acquisition of North Carolina Solar facility in the fourth quarter of 2021;

• The Sundance Unit 5 Repowering project was suspended in the third quarter of 2021 and Sundance Unit 5 was retired during 2021;

• Gains relating to the sale of the Pioneer Pipeline in the second quarter of 2021 and gains on sale of Gas equipment in the third quarter of 2021;

• The unplanned steam supply outages at the Sarnia facility in the second quarter of 2021;

• Alberta Hydro Assets, Keephills Units 1 and 2 and Sheerness began operating on a merchant basis in the Alberta electricity market effective Jan. 1,2021;

• Revenues declined due to weaker market conditions in 2020;

• Receipt of CEWS funding in 2021;

• Accelerated plans to shut down the Highvale mine resulting in remaining future royalty payments being recognized as an onerous contract in the third quarter of 2021;

• Sheerness going off coal resulting in the remaining coal supply payments of the existing coal supply agreement being recognized as an onerous contract in the fourth quarter of 2020;

• Accelerated shut-down of the Highvale mine increasing mine depreciation included in the cost of coal. Coal inventory write-down incurred in the first three quarters of 2021 and fourth quarter of 2020;

• Coal-related parts and materials inventory write-down incurred in the second and third quarters of 2021;

• The impact of the updated provision estimates for the AESO transmission line loss ruling during the first quarter of 2021 and the fourth quarter of 2020;

• The effects of asset impairment charges and reversals during all periods shown;

• The effects of changes in decommissioning provisions for retired assets in all periods shown; and

• Current and future tax expense consistently fluctuates with earnings before tax across the quarters. Future tax expense increased from 2021 mainly due to a deferred tax write down taken against part of the Canadian operations and losses on mark to market hedging.

Strategy and Capability to Deliver Results

The Corporate strategy remains unchanged from that disclosed in the 2021 Annual MD&A.

Our goal is to be a leading customer-centered electricity company, committed to a sustainable future, focused on increasing shareholder value by growing our portfolio of high-quality generation facilities with stable and predictable cash flows. Our strategy includes meeting our customer needs for clean, low-cost, reliable electricity and providing operational excellence and continuous improvement in everything we do.

SD-27

The Company’s enhanced focus on renewable generation and storage solutions for customers is driven largely by global decarbonization policies and the increase in demand and growth projections in the renewable sector, namely for companies to achieve their environment, social and governance (“ESG”) ambitions. Refer to the ESG sections within our 2021 Annual MD&A for further details.

We expect the Company’s adjusted EBITDA generated from renewable sources, including hydro, wind, solar and storage technologies, to increase from 35 per cent in 2020 to approximately 70 per cent by the end of 2025.

On Sept. 28, 2021, the Company announced the strategic targets and a five-year Clean Electricity Growth Plan that sets a focus towards investing in clean energy solutions that meets the needs of our industrial and corporate customers and communities. The Clean Electricity Growth Plan will largely be funded from current cash balances, cash generated from operations and asset-level financing.

As of Nov. 7, 2022, we have made significant progress in achieving the targets of the Clean Electricity Growth Plan.

SD-28

Our progress towards achieving our strategic targets is summarized below:

Strategic Targets

Goals	Target	Results	Comments
Accelerate Growth in Customer-centered Renewables and Storage	Deliver 2 GW of renewable capacity with an estimated capital investment of $3 billion by the end of 2025.	Ahead of Plan	In 2022, the Company delivered 200 MW of growth during the first quarter with the Horizon Hill wind project. We have begun construction of the Mount Keith 132kV transmission expansion in Australia. Our cumulative progress toward our plan target is 800 MW
	Deliver incremental average annual EBITDA of $250 million.	Ahead of Plan	The Horizon Hill wind project will add incremental EBITDA in the range of US$30 - US$33 million and the Mount Keith 132kV transmission expansion will add incremental EBITDA in the range of AU$6 - AU$7 million. Our cumulative progress towards our incremental EBITDA target is approximately $155 million.
	Expand the Company’s development pipeline to 5 GW by 2025 to enable a two-fold increase in its renewables fleet between 2025 and 2030.	On track	The Company continues to evaluate opportunities to add new development sites to our pipeline. These include acquisitions of individual early-stage development sites, small development portfolios and prospecting of new sites. For the third quarter of 2022, we have grown our renewable development pipeline by approximately 553 MW, in the United States and Canada.
Take a Targeted Approach to Diversification	Grow our asset base in our core geographies of Canada, Australia and the United States to realize diversification and value creation.	On track	The Company has successfully added new contracted renewable assets in each of its three core geographies. We have diversified within the United States market through our North Carolina Solar facility acquisition and the new Oklahoma investments which added three new investment-grade customers.

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Goals	Target	Results	Comments
Maintain Our Financial Strength and Capital Allocation Discipline	Deliver strong cash flow from our existing portfolio to allocate towards our funding priorities including growth, dividends and share buybacks.	On track	The Company had liquidity of $2.3 billion as at Sept. 30, 2022. The Company returned $34 million in share buybacks in the nine months ended Sept. 30, 2022. The Company increased the annual common share dividend by 10% to $0.22 per year effective Jan. 1,2023.
Define the Next Generation of Energy Solutions and Technologies	Meet the needs of our customers and communities through the implementation of innovative energy solutions and parallel investments in new complementary sectors by the end of 2025.	On track	The Company established an Energy Innovation team to progress our goals in this area. The team has recently completed an investment in Ekona Power Inc., an early-stage hydrogen production company, in order to pursue commercialization of low cost, net-zero aligned, hydrogen. The Company also committed to an investment in the Energy Impact Partners Investment (“EIP”) Deep Decarbonization Frontier Fund 1, which provides a portfolio approach to investing in emerging technologies focused on net-zero emissions. In the second quarter of 2022, the Company made an initial investment of $7 million (US$6 million).
Lead in ESG Policy Development	Actively participate in policy development to ensure the electricity we provide contributes to emissions reduction, grid reliability and competitive energy prices to enable the successful evolution of the markets in which we operate and compete.	On track	The Company is actively engaging the Government of Canada and Government of Alberta regarding the proposed federal Clean Electricity Regulation. Throughout the engagement, TransAlta continues to provide input regarding how to achieve emissions reduction while maintaining necessary reliability and affordability.
Successfully Navigate through the COVID-19 Pandemic	Continue to maintain an effective response to COVID-19 and plan a safe return to our offices.	On track	Continuing to monitor local public health authority and government guidelines in all jurisdictions in which we operate to promote the health and safety of all employees and contractors with our health and safety protocols.

SD-30

Growth

The Company announced 200 MW of new build projects in the second quarter of 2022. We have established and are continuing to grow our pipeline of potential growth projects. Our pipeline includes 322 MW of advanced stage development projects along with 3,321 to 4,421 MW of projects in earlier stages of development.

We are primarily evaluating greenfield opportunities in Alberta, Western Australia and the United States along with acquisitions in markets in which we have existing operations.

Projects Under Construction

The following projects have been approved by the Board of Directors, have executed PPAs and are currently under construction. The projects under construction will be financed through existing liquidity in the near term. We will continue to explore project financing or tax equity as a long-term financing solution on an asset-by-asset basis.

Project

Type

Region

MW

Total project

Target completion date(1)

PPA Term (2)

Average annual EBITDA(3)

Status

Estimated spend

Spent to date

Canada

Garden Plain(4)

Wind

AB

130

$190 — $200

$

151

Q4 2022

17

$

14 - $15

•  Fully contracted •  Construction underway •  All wind turbine components are on site •  Turbine erection and commissioning is now underway

United States

White Rock(5)

Wind

OK

300

US$470 — US$490

US$

154

H2 2023

—

US$

48 - US$52

•  Long-term PPAs executed •  All major equipment supply and EPC agreements executed •  Detailed design and final permitting on track •  Wind turbine component deliveries in-progress •  Commenced site construction •  On track to be completed on schedule

Horizon Hill (5)

Wind

OK

200

US$300 — US$315

US$

44

H2 2023

—

US$

30 - US$33

•  Long-term PPA executed •  All major equipment supply and EPC agreements executed •  Wind turbine component deliveries inprogress

SD-31

Project

Type

Region

MW

Total project

Target completion date(1)

PPA Term (2)

Average annual EBITDA(3)

Status

Estimated spend

Spent to date

•  Commenced site construction •  On track to be completed on schedule

Australia

Northern Goldfields Solar

Hybrid Solar

WA

48

AU$69 — AU$73

AU$

53

H1 2023

16

AU$

9 - AU$10

•  Construction underway •  Solar panel installation is nearing completion •  On track to be completed in early 2023

Mount Keith 132kV Expansion

Transmission

WA

n/a

AU$50 — AU$53

AU$

10

H2 2023

15

AU$

6 - AU$7

•  EPC Agreement executed •  On track to be completed on schedule

(1) H1 or H2 is defined as the first or second half of the year.

(2) The PPA term is confidential for the White Rock wind projects and Horizon Hill wind project.

(3) This item is not defined and has no standardized meaning under IFRS and is forward-looking. Please refer to the Additional IFRS measures and Non-IFRS Measures section of this MD&A for further discussion.

(4) The Garden Plain wind project PPA is fully contracted, with Pembina off-taking 100 MW of the total 130 MW capacity of the facility and the remaining 30 MW contracted to an investment-grade globally recognized customer. Refer to the Significant and Subsequent Events section of this MD&A for further details.

(5) The expected average annual EBITDA and estimated capital spending for the White Rock wind projects and Horizon Hill wind projects have been revised upwards based on the impact of the Inflation Reduction Act of 2022 (”IRA”) which results in projects qualifying for 100 per cent production tax credits and incremental payments to the turbine supplier.

Advanced-stage Development

These projects have detailed engineering, advanced positions in the interconnection queue and are progressing off-take opportunities. The following table shows the pipeline of future growth projects currently under advanced-stage development:

Project	Type	Region	Gross Installed Capacity (MW)	Estimated Spend	Average annual EBITDA(1)
Tempest	Wind	Alberta	100	$210 - $230	$20 - $23
SCE Capacity Expansion	Gas	Western Australia	42	AU$80 - AU$100	AU$9 - AU$12
WaterCharger	Battery Storage	Alberta	180	$150 - $180	$14 - $17
Australia Transmission Expansion	Transmission	Western Australia	n/a	AU$34 - AU$36	AU$3 - AU$4

(1) This item is not defined and has no standardized meaning under IFRS and is forward-looking. Please refer to the Additional IFRS measures and Non-IFRS Measures section of this MD&A for further discussion.

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Early-stage Development

These projects are in the early stages and may or may not move ahead. Generally, these projects will have:

• Collected meteorological data;

• Begun securing land control;

• Started environmental studies;

• Confirmed appropriate access to transmission; and

• Started preliminary permitting and other regulatory approval processes.

The following table shows the pipeline of future growth projects currently under early-stage development:

Project	Type		Region			Gross Installed Capacity (MW)
Early Stage Development
Canada
Riplinger Wind		Wind		Alberta			300
Red Rock		Wind		Alberta			100
Willow Creek 1		Wind		Alberta			70
Willow Creek 2		Wind		Alberta			70
Sunhills Solar		Solar		Alberta			80
McNeil Solar		Solar		Alberta			57
Canadian Battery Opportunity		Battery		New Brunswick			10
Canadian Wind Opportunities		Wind		Various			370
Brazeau Pumped Hydro		Hydro		Alberta			300 - 900
Alberta Thermal Redevelopment		Various		Alberta			250 - 500
					Total		1,607 - 2,457
United States
Old Town		Wind		Illinois			185
Trapper Valley		Wind		Wyoming			225
Monument Road		Wind		Nebraska			152
Dos Rios		Wind		Oklahoma			242
Prairie Violet		Wind		Illinois			130
Big Timber		Wind		Pennsylvania			50
Oklahoma Solar		Solar		Oklahoma			100
Other Wind Prospects in the United States		Wind		Various			160
Centralia site Redevelopment		Various		Washington			250 - 500
					Total		1,494 - 1,744
Australia
Goldfields Expansions		Gas, Solar, Wind		Western Australia			170
South Hedland Solar		Solar		Western Australia			50
					Total		220
Canada, United States and Australia					Total		3,321 - 4,421

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2022 Financial Outlook

Our overall performance for the third quarter of 2022 was ahead of expectations. During the third quarter of 2022, the Company delivered significantly above financial expectations from its Alberta Electricity Portfolio, including superior revenues through sales of energy and ancillary services of the Alberta Hydro fleet. The Company has revised its guidance upwards, including raising the FCF guidance ranges by approximately $245 million at the midpoint, or 49 per cent. On Nov. 7, 2022, the Board of Directors approved an increase to the annualized dividend to $0.22 per share, beginning with the Jan. 1, 2023 dividend.

Based on results attained to date and our expectations for the balance of the year performance, the Company is revising upwards its outlook range for 2022, which is reflected in the table below:

Measure	Updated Target 2022		Original Target 2022		2021 Actual
Adjusted EBITDA(1)(2)	$	1,380 million - $1,460 million	$	1,065 million - $1,185 million	$	1,286 million
FCF(1)(2)	$	725 million - $775 million	$	455 million - $555 million	$	585 million
Dividend	$	0.20 per share annualized	$	0.20 per share annualized	$	0.20 per share annualized

(1) These items are not defined and have no standardized meaning under IFRS. Please refer to the Reconciliation of Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS measures and Non-IFRS Measures section of this MD&A.

(2) The 2021 actual adjusted EBITDA and FCF were revised during the second quarter of 2022 to be consistent with the currently defined composition on adjusted EBITDA and FCF. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Range of key 2022 power and gas price assumptions

Market	Updated 2022 Expectations		Original Expectations
Alberta Spot ($/MWh)	$	125 - $150	$	80 - $90
Mid-C Spot (US$/MWh)	US$	55 - US$65	US$	45 - US$55
AECO Gas Price ($/GJ)	$	5.00 - $6.00	$	3.60

Alberta spot price sensitivity: a +/- $1/MWh change in spot price is expected to have a +/- $2 million impact on adjusted EBITDA for the balance of 2022.

Other assumptions relevant to the 2022 financial outlook

	Updated 2022 Expectations	Original Expectations
Sustaining capital	$145 million - $155 million	$150 million - $170 million
Energy Marketing adjusted gross margin	$145 million - $160 million	$95 million - $115 million

Alberta Hedging

Range of hedging assumptions	Q4 2022		Full year 2023
Hedged production (GWh)		1,850		5,427
Hedge price ($/MWh)	$	95	$	78
Hedged gas volumes (GJ)		19 million		58 million
Hedge gas prices ($/GJ)	$	3.62	$	2.24

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Refer to the 2022 Financial Outlook section in our 2021 Annual MD&A for further details relating to our Outlook and related assumptions.

Operations

The following provides updates to our original assumptions included in the 2022 Financial Outlook.

Market Pricing

For the third quarter of 2022, strong merchant pricing levels continued in Alberta and the Pacific Northwest as a result of higher natural gas prices and robust weather-driven demand in both regions. Higher power prices in Alberta were also supported by periods of planned or unplanned outages in the province coinciding with strong demand. Prices in Alberta and the Pacific Northwest for the balance of year are now trading above last year prices primarily due to higher natural gas prices. However, actual power prices will depend on weather in the fourth quarter of 2022. Ontario power prices for both periods of 2022 were higher primarily due to higher natural gas prices.

AECO natural gas prices for nine months ended Sept. 30, 2022, are approximately $2/GJ higher than for the same periods in 2021 due to overall tighter market conditions across North America.

Sustaining Capital Expenditures

Our estimate for total sustaining capital is as follows:

Category	Spend for 3 months ended Sept. 30, 2022		Spend to date for 9 months ended Sept. 30, 2022		Expected spend in 2022
Total sustaining capital	$	27	$	75	$	145 - $155

Total sustaining capital expenditures for the nine months ended Sept. 30, 2022, were $69 million lower compared to the same period in 2021, mainly due to lower planned major maintenance turnarounds on the coal-to-gas conversions related to Keephills Unit 2, Sundance Unit 6 and Sheerness Unit 1.

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The Kent Hills wind facilities rehabilitation capital expenditure has been segregated from our sustaining capital assumptions range due to the extraordinary nature of this expenditure. Refer to the Wind and Solar section of this MD&A for further details.

Liquidity and Capital Resources

We expect to maintain adequate available liquidity under our committed credit facilities, including the Term Facility (as defined below), the Company entered into during the third quarter of 2022. We currently have access to $2.3 billion in liquidity, including $0.8 billion in cash. We expect to be well-positioned to refinance the upcoming November 2022 debt maturity and the Company plans on utilizing the $400 million Term Facility for refinancing due to timing. The funds required for committed growth, Kent Hills wind facilities rehabilitation, and sustaining capital and productivity projects are not expected to be significantly impacted by the current economic environment.

Financial Position

The following table highlights significant changes in the unaudited interim condensed consolidated statements of financial position from Dec. 31, 2021 to Sept. 30, 2022:

Assets	Sept. 30, 2022		Dec. 31, 2021		Increase/(decrease)
Current assets
Cash and cash equivalents		816		947		(131	)
Trade and other receivables		1,327		651		676
Risk management assets		755		308		447
Other current assets(1)		318		291		27
Total current assets		3,216		2,197		1,019
Non-current assets
Risk management assets		226		399		(173	)
Property, plant and equipment, net		5,294		5,320		(26	)
Other non-current assets(2)		1,309		1,310		(1	)
Total non-current assets		6,829		7,029		(200	)
Total assets		10,045		9,226		819
Liabilities
Current liabilities
Accounts payable and accrued liabilities		1,279		689		590
Risk management liabilities		854		261		593
Long-term debt and lease liabilities (current)		722		844		(122	)
Other current liabilities(3)		105		137		(32	)
Total current liabilities		2,960		1,931		1,029
Non-current liabilities
Credit facilities, long-term debt and lease liabilities		2,487		2,423		64
Decommissioning and other provisions (long-term)		651		779		(128	)
Risk management liabilities (long-term)		247		145		102
Defined benefit obligation and other long-term liabilities		184		253		(69	)
Other non-current liabilities(4)		1,099		1,102		(3	)
Total non-current liabilities		4,668		4,702		(34	)
Total liabilities		7,628		6,633		995

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Assets	Sept. 30, 2022		Dec. 31, 2021		Increase/(decrease)
Equity
Equity attributable to shareholders		1,538		1,582		(44	)
Non-controlling interests		879		1,011		(132	)
Total equity		2,417		2,593		(176	)
Total liabilities and equity		10,045		9,226		819

(1) Includes restricted cash, prepaid expenses, inventory and assets held for sale.

(2) Includes investments, long-term portion of finance lease receivables, right-of-use assets, intangible assets, goodwill, deferred income tax assets and other assets.

(3) Includes current portion of decommissioning and other provisions, current portion of contract liabilities, income taxes payable and dividends payable.

(4) Includes exchangeable securities, deferred income tax liabilities and contract liabilities.

Significant changes in TransAlta’s unaudited interim condensed consolidated statements of financial position were as follows:

Working Capital

The excess of current assets over current liabilities, including the current portion of long-term debt and lease liabilities, was $256 million as at Sept. 30, 2022, (Dec. 31, 2021 — $266 million). Our working capital decreased compared to the previous period mainly due to a net increase in risk management liabilities and movements in the collateral accounts. Our collateral received (included in accounts payable and accrued liabilities) is significantly higher at Sept. 30, 2022, compared to Dec. 31, 2021, and is partially offset by the collateral paid to counterparties (included in trade and other receivables). The changes in risk management assets and liabilities and collateral posted and received are largely related to high commodity prices and volatility in the markets. These decreases were partially offset by an increase in trade and other receivables due to higher revenues and the reclassification of the KH Bonds to long-term liabilities as a result of the waiver obtained in the second quarter of 2022.

Current assets increased by $1,019 million to $3,216 million as at Sept. 30, 2022, from $2,197 million as at Dec. 31, 2021, mainly due to higher trade and other receivables due to higher revenues, higher collateral posted and higher risk management assets resulting from volatility in market prices, partially offset by lower cash and cash equivalents. As at Sept. 30, 2022, the Company had provided $315 million (Dec. 31, 2021 — $55 million) of cash collateral related to derivative instruments in a net liability position.

Current liabilities increased by $1,029 million from $1,931 million as at Dec. 31, 2021, to $2,960 million as at Sept. 30, 2022, mainly due to an increase in accounts payable and accrued liabilities due to higher collateral received associated with counterparty obligations and an increase in risk management liabilities primarily due to volatility in market prices across multiple markets; partially offset by repayments of the current portion of long- term debt and the reclassification of the KH Bonds to long-term as a result of the waiver obtained. As at Sept. 30, 2022, the Company held $395 million (Dec. 31, 2021 — $18 million) of cash collateral received related to derivative instruments in a net asset position.

Non-current Assets

Non-current assets as at Sept. 30, 2022, are $6,829 million, a decrease of $200 million from $7,029 million as at Dec. 31, 2021. The decrease was primarily due to lower risk management assets due to volatility in market pricing across multiple markets and contract settlements. PP&E decreased as a result of increased discount rates on decommissioning provisions by $125 million, impairment of assets of $56 million, and depreciation, including an adjustment to the useful lives of certain gas assets which increased depreciation expense by approximately

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$64 million. These decreases to PP&E were partially offset by additions of $481 million primarily for the construction of the White Rock wind projects, the Garden Plain wind project, the Horizon Hill wind project, the Northern Goldfields solar project, Kent Hills rehabilitation costs and other planned major maintenance and $40 million related to change in timing of estimates for decommissioning and restoration provisions.

Non-current Liabilities

Non-current liabilities as at Sept. 30, 2022, are $4,668 million, a decrease of $34 million from $4,702 million as at Dec. 31, 2021, mainly due to an increase in discount rates driven by market benchmark rates resulting in a decrease in the long-term decommissioning provision of $227 million and a decrease in the defined benefit obligation of $46 million. In addition, these decreases were partially offset by a $90 million increase in the decommissioning provision related to revisions of estimated cash flows, a voluntary contribution of $35 million to improve the funded status of the Sunhills Mining Ltd. Pension Plan, a $64 million increase in long-term debt, net of the scheduled debt repayments, resulting from the reclassification of the KH Bonds to long-term as a result of the waiver obtained and an increase in risk management liabilities of $102 million due to the volatility in across multiple markets and new contracts.

Total Equity

As at Sept. 30, 2022, the decrease in total equity of $176 million was mainly due to net losses on cash flow hedges of $230 million, distributions to non-controlling interests of $126 million, share repurchases under the NCIB of $34 million, and common share and preferred share dividends of $27 million and $21 million, respectively, partially offset by net earnings for the period of $243 million and actuarial gains on defined benefit plans of $36  million.

Financial Capital

The Company is focused on maintaining a strong balance sheet and financial position to ensure access to sufficient financial capital.

Capital Structure

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

	Sept. 30, 2022						Dec. 31, 2021
	$			%			$			%
TransAlta Corporation
Net senior unsecured debt
Recourse debt - CAD debentures		251			5			251			4
Recourse debt - US senior notes		951			17			888			16
Other		2			—			4			—
Less: cash and cash equivalents		(587	)		(11	)		(703	)		(12	)
Less: other cash and liquid assets(1)		(32	)		(1	)		(19	)		—
Net senior unsecured debt		585			10			421			8
Other debt liabilities
Exchangeable debentures		338			6			335			6
Non-recourse debt
TAPC Holdings LP bond		96			2			102			2
OCP bond		241			4			263			5
Lease liabilities		81			2			78			1
Total net debt - TransAlta Corporation		1,341			24			1,199			22

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	Sept. 30, 2022						Dec. 31, 2021
	$			%			$			%
TransAlta Renewables
Net TransAlta Renewables reported debt
Pingston bond		45			1			45			1
Melancthon Wolfe Wind bond		219			4			235			4
New Richmond Wind bond		116			2			120			2
Kent Hills Wind bond		209			4			221			4
Windrise Wind bond		170			3			171			3
Lease liabilities		23			—			22			—
Less: cash and cash equivalents		(229	)		(3	)		(244	)		(4	)
Debt on TransAlta Renewables Economic Investments
US tax equity financing(2)		127			2			135			2
South Hedland non-recourse debt(3)		679			12			732			13
Total net debt - TransAlta Renewables		1,359			25			1,437			25
Total consolidated net debt(4)(5)		2,700			49			2,636			47
Non-controlling interests		879			16			1,011			18
Exchangeable preferred securities(5)		400			7			400			7
Equity attributable to shareholders
Common shares		2,879			52			2,901			51
Preferred shares		942			17			942			17
Contributed surplus, deficit and accumulated other comprehensive income		(2,283	)		(41	)		(2,261	)		(40	)
Total capital		5,517			100			5,629			100

(1) Includes principal portion of OCP restricted cash and fair value asset (liability) of hedging instruments on debt.

(2) TransAlta Renewables has an economic interest in the entities holding these debts.

(3) TransAlta Renewables has an economic interest in the Australia entities, which includes the AU$789 million senior secured notes.

(4) The tax equity financing for Skookumchuck wind facility, an equity accounted joint venture, is not represented in these amounts.

(5) The total consolidated net debt excludes the exchangeable preferred securities as they are considered equity with dividend payments for credit purposes.

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Credit Facilities

The Company’s credit facilities are summarized in the table below:

			Utilized
As at Sept. 30, 2022	Facility size		Outstanding letters of credit(1)		Actual drawings		Available capacity		Maturity date
TransAlta Corporation
Committed syndicated bank facility(2)		1,250		753		—		497		Q2 2026
Canadian committed bilateral credit facilities		240		208		—		32		Q2 2024
Term Facility		400		—		—		400		Q3 2024
TransAlta Renewables
Committed credit facility(2)		700		102		—		598		Q2 2026
Total		2,590		1,063		—		1,527

(1) TransAlta has 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, pension plan obligations, construction projects and purchase obligations. As at Sept. 30, 2022, we provided cash collateral of $315 million.

(2) TransAlta has letters of credit of $154 million and TransAlta Renewables has letters of credit of $102 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities.

During the second quarter of 2022, the committed syndicated credit facilities were extended by one year to June 30, 2026, and the committed bilateral credit facilities were extended by one year to June 30, 2024.

During the third quarter of 2022, the Company closed a two-year floating rate term facility with its banking syndicate for $400 million (“Term Facility”) with a maturity date of Sept. 7, 2024. The Term Facility has interest rates that vary depending on the option selected (Canadian prime and bankers’ acceptances, etc.)

Non-Recourse Debt

The Melancthon Wolfe Wind LP, Pingston Power Inc., TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland PTY Ltd notes, Windrise Wind LP and TransAlta OCP LP non-recourse bonds are subject to customary financing conditions and covenants that may restrict the Company’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 third quarter of 2022, except in relation to the KH Bonds as discussed below. The next debt service coverage ratio is calculated in the fourth quarter of 2022.

Kent Hills Wind Facilities Rehabilitation

During the second quarter of 2022, the Company obtained a waiver and entered into a supplemental indenture that facilitated the rehabilitation of the Kent Hills 1 and 2 wind facilities. Upon receipt of the waiver, the Company reclassified a portion of the carrying value outstanding for the KH Bonds to non-current liabilities with the exception of the scheduled principal repayments due within the next twelve months from June 30, 2022. In accordance with the supplemental indenture, KHLP cannot make any distributions to its partners until the foundation replacement work has been completed.

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Scheduled Debt Maturities

Between 2022 and 2024, we have $877 million of debt maturing, including $548 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments. We currently expect to refinance the maturing senior notes.

Returns to Providers of Capital

Net Interest Expense

The components of net interest expense are shown below:

	3 months ended Sept. 30						9 months ended Sept. 30
	2022			2021			2022			2021
Interest on debt		42			41			123			121
Interest on exchangeable debentures		7			8			22			22
Interest on exchangeable preferred shares		7			7			21			21
Interest income		(7	)		(2	)		(14	)		(8	)
Capitalized interest		(4	)		(5	)		(8	)		(13	)
Interest on lease liabilities		1			1			4			5
Credit facility fees, bank charges and other interest		5			4			16			14
Tax shield on tax equity financing		(1	)		—			(4	)		1
Accretion of provisions		16			9			35			23
Net interest expense		66			63			195			186

Net interest expense for the three and nine months ended Sept. 30, 2022, increased mainly due to higher accretion of provisions and lower capitalized interest, partially offset by higher interest income due to favourable interest rates.

Share Capital

The following tables outline the common and preferred shares issued and outstanding:

As at	Nov. 7, 2022		Sept. 30, 2022		Dec. 31, 2021
	Number of shares (millions)
Common shares issued and outstanding, end of period		269.4		269.4		271.0
Preferred shares
Series A		9.6		9.6		9.6
Series B		2.4		2.4		2.4
Series C(1)		10.0		10.0		11.0
Series D(1)		1.0		1.0		—
Series E		9.0		9.0		9.0
Series G		6.6		6.6		6.6
Preferred shares issued and outstanding in equity, end of period		38.6		38.6		38.6
Series I - Exchangeable Securities(2)		0.4		0.4		0.4
Preferred shares issued and outstanding, end of period		39.0		39.0		39.0

(1) During the second quarter of 2022, the Company has converted 1,044,299 of its 11,000,000 currently outstanding Series C Shares, on a one-for-one basis, into Series D Shares.

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(2) Brookfield invested $400 million in consideration for redeemable, retractable, first preferred shares. For accounting purposes, these preferred shares are considered debt and disclosed as such in the audited annual consolidated financial statements.

Non-Controlling Interests

As at Sept. 30, 2022, the Company owns 60.1 per cent (Sept. 30, 2021 - 60.1 per cent) of 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.

The Company also own 50.01 per cent (Sept. 30, 2021 - 50.01 per cent) of TA Cogen, which owns, operates or has an interest in five natural-gas-fired facilities (Ottawa, Windsor, Fort Saskatchewan and Sheerness Unit 1 and Unit 2).

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.

Reported earnings attributable to non-controlling interests for the three and nine months ended Sept. 30, 2022, were $24 million and $55 million, respectively, a decrease of $3 million and $33 million compared to the same periods in 2021.

Earnings from TA Cogen increased by $15 million for the three months ended Sept. 30, 2022, compared with the same period in 2021, due to higher realized pricing in Alberta, partially offset by higher gas prices, higher gas transportation costs and lower production at Sheerness. Earnings from TA Cogen decreased by $3 million for the nine months ended Sept. 30, 2022, compared to the same period in 2021 due to lower production, higher gas prices and higher transportation rates partially offset by higher realized pricing and lower coal costs.

Earnings from TransAlta Renewables for the three and nine months ended Sept. 30, 2022, decreased by $18 million and $30 million, respectively, compared with the same periods in 2021. This was primarily due to lower finance income related to subsidiaries of TransAlta, higher asset impairment charges, higher interest expense and lower foreign exchange gains. For the nine months ended Sept. 30, 2022, these were partially offset by the recognition of insurance proceeds for the replacement costs for the single collapsed tower at the Kent Hills facility, lower income tax expense and liquidated damages recognized related to turbine availability at the Windrise wind facility. Finance income related to subsidiaries of TransAlta was lower as more distributions were classified as return of capital.

Other Consolidated Analysis

Kent Hills Loan

During the nine months ended Sept. 30, 2022, the loan receivable agreement with KHLP’s 17 per cent partner, Natural Forces Technologies Inc., was amended and its original maturity date of Oct. 2, 2022, was extended to October 2027. In addition, KHLP received repayment of $14 million of the KHLP loan receivable, which was required as part of the waiver and amendment made to the KH Bonds. As at Sept. 30, 2022, $41 million (Dec. 31,

2021 — $55 million) was outstanding.

Commitments

Please refer to our Other Consolidated Analysis section of the 2021 Annual MD&A for a complete listing of commitments we have incurred either directly or through interests in joint operations. The Company has entered into the following material contractual commitments, as at Sept. 30, 2022:

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During the second quarter of 2022, the Company entered into an engineering, procurement and construction agreement for approximately $37 million (AU$41 million) related to the Mount Keith 132kV Expansion. In addition, the Company entered into agreements for $100 million to complete the rehabilitation at the Kent Hills 1 and 2 wind facilities in 2022.

For updates on the Company’s growth projects, refer to the Strategy and Capability to Deliver Results section of this MD&A for further details.

Contingencies

For the current material outstanding contingencies, please refer to Note 36 of the 2021 audited annual consolidated financial statements. Material changes to the contingencies have been described below.

Hydro Power Purchase Arrangement (“Hydro PPA”) Emission Performance Credits

The Balancing Pool is claiming entitlement to the emission performance credits (“EPCs”) earned by the Alberta Hydro facilities as a result of TransAlta opting those facilities into the Carbon Competitiveness Incentive Regulation and Technology Innovation and Emissions Reduction Regulation from 2018-2020 inclusive. The Balancing Pool claims ownership of the EPCs because it believes the change-in-law provisions under the Hydro PPA require the EPCs to be passed through to the Balancing Pool. TransAlta has not received any benefit from the EPCs nor from any purported change in law and believes that the Balancing Pool has no rights to these credits. An arbitration has commenced and the hearing is scheduled for Feb. 6 to 10, 2023. TransAlta holds approximately 1,750,000 EPCs with no recorded book value that were created between 2018-2020, which are at risk as a result of the Balancing Pool’s claim.

Keephills Unit 1 Stator Force Majeure

The Balancing Pool and ENMAX were seeking to set aside an arbitration award on the basis that they did not receive a fair hearing. The Alberta Court of Queen’s Bench dismissed the Balancing Pool and ENMAX’s allegations of unfairness on June 26, 2019. The Balancing Pool and ENMAX appealed this decision to the Court of Appeal, which was heard on Jan. 27, 2022.

On June 9, 2022, the Court of Appeal released a unanimous decision dismissing ENMAX and the Balancing Pool’s application. The Court of Appeal upheld the Company’s claim of force majeure that arose when its Keephills Unit 1 generating unit tripped offline in 2013. As a result of the decision, the Company’s claim of force majeure remains valid and the associated costs of the force majeure event will not be reassessed against TransAlta. ENMAX and the Balancing Pool did not seek leave to appeal this decision to the Supreme Court of Canada, which concludes this matter.

Keephills Unit 2 Stator Force Majeure

After the Keephills Unit 1 stator force majeure outage in 2013, it was determined that Keephills Unit 2 could face a similar stator failure before the next planned outage. In response, the Company took Keephills Unit 2 offline between January 31, 2014, and March 15, 2014, to perform a full rewind of the generator stator and claimed force majeure. The Balancing Pool disputed this force majeure event but the dispute was held in abeyance pending the outcome of the Keephills Unit 1 stator force majeure dispute, which was recently concluded. The Company and the Balancing Pool recently settled this dispute and so both stator force majeure claims have been resolved.

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Sarnia Outages

The Sarnia cogeneration facility experienced three separate events between May 19, 2021, and June 9, 2021, that resulted in steam interruptions to its industrial customers. As a result, the customers have submitted claims for liquidated damages. Steam supply disruptions of this nature are atypical and infrequent at the Sarnia cogeneration facility. A root cause failure analysis was completed for the three outages, which concluded that all three outages were within TransAlta (SC) LP’s control. As such, liquidated damages previously included in contract liabilities in the amount of $12 million have been paid by TransAlta (SC) LP during the second quarter of 2022.

There have been no other material updates to any of the contingencies in the three and nine months ended Sept. 30, 2022.

Cash Flows

The following chart highlights significant changes in the consolidated statements of cash flows:

	9 months ended Sept. 30						Increase/(decrease)
	2022			2021
Cash and cash equivalents, beginning of period		947			703			244
Provided by (used in):
Operating activities		526			947			(421	)
Investing activities		(341	)		(202	)		(139	)
Financing activities		(315	)		(364	)		49
Translation of foreign currency cash		(1	)		(4	)		3
Cash and cash equivalents, end of period		816			1,080			(264	)

Cash provided by operating activities for the nine months ended Sept. 30, 2022, decreased compared with the same period in 2021 primarily due to unfavourable changes in working capital mainly from higher accounts receivable and movements in the collateral accounts related to high commodity prices and volatility in the markets.

Cash used in investing activities for the nine months ended Sept. 30, 2022, increased compared with the same period in 2021, largely due to:

• Previous year included proceeds received on the sale of the Pioneer Pipeline ($128 million); and

• Higher cash spend on project construction activities in PP&E ($137 million) partially offset by:

• Lower non-cash working capital related to the timing of construction payables for the assets under construction ($109 million);

• Higher loan receivable receipts ($14 million); and

• Higher restricted cash receipts related to funding principal debt repayments ($8 million).

Cash used in financing activities for the nine months ended Sept. 30, 2022, decreased compared with the same period in 2021, largely due to:

• Lower repayments under the Company’s credit facilities ($114 million); partially offset by:

• Higher repayments on long-term debt ($17 million);

• Higher common share repurchases under the NCIB ($24 million);

• Higher dividends paid on common shares and preferred shares ($6 million);

• Increased distributions paid to subsidiaries’ non-controlling interests ($9 million); and

• Lower proceeds on issuances of common shares ($7 million).

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Financial Instruments

Refer to Note 15 of the notes to the audited annual 2021 consolidated financial statements, and Note 11 and 12 of our unaudited interim condensed consolidated financial statements as at and for the nine months ended Sept. 30, 2022, for details on Financial Instruments.

We may enter into commodity transactions involving non-standard features for which observable market data is not available. These are defined under IFRS as Level III financial instruments. Level III financial instruments are not traded in an active market and fair value is, therefore, developed using valuation models based upon internally developed assumptions or inputs. Our Level III fair values are determined using data such as unit availability, transmission congestion, or demand profiles. Fair values are validated every quarter by using reasonably possible alternative assumptions as inputs to valuation techniques and any material differences are disclosed in the notes to the financial statements.

At Sept. 30, 2022, Level III instruments had a net liability carrying value of $611 million (Dec. 31, 2021—net asset of $159 million), which are primarily attributable to volatility in market prices across multiple markets on both existing contracts and new contracts as well as contract settlements.

Our risk management profile and practices have not changed materially from Dec. 31, 2021.

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 unaudited interim condensed 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 unaudited interim condensed consolidated statements of earnings (loss) for the three and nine months ended Sept. 30, 2022, and 2021. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.

We use a number of financial measures to evaluate our performance and the performance of our business segments, including measures and ratios that are presented on a non-IFRS basis, as described below. Unless otherwise indicated, all amounts are in Canadian dollars and have been derived from our audited annual 2021 consolidated financial statements and the unaudited interim condensed consolidated statements of earnings (loss) for the three and nine months ended Sept. 30, 2022, prepared in accordance with IFRS. We believe that these non-IFRS amounts, measures and ratios, read together with our IFRS amounts, provide readers with a better understanding of how management assesses results.

Non-IFRS amounts, measures and ratios do not have standardized meanings under IFRS. They are unlikely to be comparable to similar measures presented by other companies and should not be viewed in isolation from, or as an alternative for, or more meaningful than our IFRS results.

Non-IFRS Financial Measures

Adjusted EBITDA, FFO, FCF, total net debt, total consolidated net debt and adjusted net debt are non-IFRS measures that are presented in this MD&A. Refer to the Segmented Financial Performance and Operating Results, Selected Quarterly Information, Financial Capital and Key Financial Non-IFRS Ratios sections of this MD&A for additional information, including a reconciliation of such non-IFRS measures to the most comparable IFRS measure.

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Adjusted EBITDA

In the fourth quarter of 2021, comparable EBITDA was relabeled as adjusted EBITDA to align with industry standard terminology. Each business segment assumes responsibility for its operating results measured by adjusted EBITDA. Adjusted EBITDA is an important metric for management that represents our core business profitability. In the second quarter of 2022, our adjusted EBITDA composition was adjusted to include the impact of closed positions that are effectively settled by offsetting positions with the same counterparty to reflect the performance of the assets and Energy Marketing segment in the period in which the transactions occur. Accordingly, the Company has applied this composition to all previously reported periods. Interest, taxes, depreciation and amortization are not included, as differences in accounting treatments may distort our core business results. In addition, certain reclassifications and adjustments are made to better assess results excluding those items that may not be reflective of ongoing business performance. This presentation may facilitate the readers’ analysis of trends. Adjusted EBITDA is a non-IFRS measure. The following are descriptions of the adjustments made.

Adjustments to revenue

• Certain assets we own in Canada and 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.

• Adjusted EBITDA is adjusted to exclude the impact of unrealized mark-to-market gains or losses and unrealized foreign exchange gains or losses on commodity transactions.

• Gains and losses related to closed positions effectively settled by offsetting positions with exchanges have been recorded in the period the positions are settled.

Adjustments to fuel and purchased power

• We adjust for depreciation on our mining equipment included in fuel and purchased power.

• We adjust for items resulting from the decision to accelerate being off-coal and accelerating the shut-down of the Highvale mine at the end of 2021 as it is not reflective of ongoing business performance. Within fuel and purchased power this included coal inventory write-downs.

• On the commissioning of the South Hedland facility 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.

Adjustments to earnings (loss) in addition to interest, taxes, depreciation and amortization

• Asset impairment charges are removed as these are accounting adjustments that impact depreciation and amortization and do not reflect current business performance.

• Any gains or losses on asset sales or foreign exchange gains or losses are not included as these are not part of operating income.

Adjustments to Net Other Operating (Income) loss

• Insurance recoveries related to the Kent Hills tower collapse are not included as these relate to investing activities and are not reflective of ongoing business performance. Refer to the Wind and Solar section of this MD&A for further details.

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Adjustments for equity accounted investments

• During the fourth quarter of 2020, we acquired a 49 per cent interest in the Skookumchuck wind facility, which is treated as an equity investment under IFRS and our proportionate share of the net earnings is reflected as equity income on the statement of earnings under IFRS. As this investment is part of our regular power-generating operations, we have included our proportionate share of the adjusted EBITDA of Skookumchuck wind facility in our total adjusted EBITDA. In addition, in the Wind and Solar segment adjusted results, we have included our proportionate share of revenues and expenses to reflect the full operational results of this investment. We have not included equity interest for the EMG International LLC (“EMG”) adjusted EBITDA in our total adjusted EBITDA as it does not represent our regular power-generating operations.

Average Annual EBITDA

Average annual EBITDA is a non-IFRS financial measure that is forward-looking, used to show the average annual EBITDA that the project currently under construction is expected to generate upon completion.

Funds From Operations (“FFO”)

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. FFO is a non-IFRS measure.

Adjustments to cash from operations

• Includes FFO related to the Skookumchuck wind facility, which is treated as an equity accounted investment under IFRS and equity income, net of distributions from joint ventures is included in cash flow from operations under IFRS. As this investment is part of our regular power-generating operations, we have included our proportionate share of FFO.

• Payments received on finance lease receivables reclassified to reflect cash from operations.

• We adjust for items included in cash from operations related to the decision in 2020 to accelerate being off-coal and accelerating the shut-down of the Highvale mine by the end of 2021, the write-down on parts and material inventory for our coal operations and voluntary contribution made to fund the Sunhills Mining Ltd. Pension Plan (under the “Clean energy transition provisions and adjustments”).

• Cash received/paid on closed positions are reflected in the period that the position is settled.

Free Cash Flow (“FCF”)

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 the timing of receipts and payments. FCF is a non-IFRS measure.

Non-IFRS Ratios

FFO per share, FCF per share and adjusted net debt to adjusted EBITDA are non-IFRS ratios that are presented in the MD&A. Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF and Key Financial Non-IFRS Ratios sections of this MD&A for additional information.

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FFO per share and FCF per share

FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period. FFO per share and FCF per share are a non-IFRS ratios.

Supplementary Financial Measures

Financial highlights presented on a proportional basis of TransAlta Renewables, deconsolidated adjusted EBITDA, deconsolidated FFO and deconsolidated net debt to deconsolidated adjusted EBITDA are supplementary financial measures the Company uses to present adjusted EBITDA on a deconsolidated basis and excludes the portion of TransAlta Renewables and TA Cogen that are not owned by TransAlta. Refer to the Financial Highlights on a Proportional Basis of TransAlta Renewables and Key Financial Non-IFRS Ratios sections of this MD&A for additional information.

The Alberta Electricity Portfolio metrics disclosed are also supplementary financial measures used to present the gross margin by segment within the Alberta Electricity Portfolio. Refer to the Alberta Electricity Portfolio section of this MD&A for additional information.

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Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment

The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the three months ended Sept. 30, 2022:

	Hydro		Wind & Solar(1)			Gas(2)			Energy Transition(3)		Energy Marketing			Corporate			Total			Equity accounted investments(1)			Reclass Adjustments			IFRS Financials
Revenues		265		14			372			231		54			(4	)		932			(3	)		—			929
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		53			47			6		46			—			152			—			(152	)		—
Realized (gain) loss on closed exchange positions		—		—			(4	)		—		(38	)		—			(42	)		—			42			—
Decrease in finance lease receivable		—		—			12			—		—			—			12			—			(12	)		—
Finance lease income		—		—			4			—		—			—			4			—			(4	)		—
Adjusted revenues		265		67			431			237		62			(4	)		1,058			(3	)		(126	)		929
Fuel and purchased power		7		6			167			167		—			1			348			—			—			348
Reclassifications and adjustments:
Australian interest income		—		—			(1	)		—		—			—			(1	)		—			1			—
Adjusted fuel and purchased power		7		6			166			167		—			1			347			—			1			348
Carbon compliance		—		—			26			2		—			(5	)		23			—			—			23
Gross margin		258		61			239			68		62			—			688			(3	)		(127	)		558
OM&A		12		19			49			17		9			30			136			(1	)		—			135
Taxes, other than income taxes		1		1			5			—		—			1			8			—			—			8
Net other operating income		—		(1	)		(10	)		—		—			—			(11	)		—			—			(11	)
Adjusted EBITDA(4)		245		42			195			51		53			(31	)		555
Equity income																											1
Finance lease income																											4
Depreciation and amortization																											(179	)
Asset impairment charges																											(70	)
Net interest expense																											(66	)
Foreign exchange gain																											6
Gain on sale of assets and other																											4
Earnings before income taxes																											126

(1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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The following table reflects adjusted EBITDA by segment and provides reconciliation to loss before income taxes for the three months ended Sept. 30, 2021:

	Hydro		Wind & Solar(1)		Gas(2)			Energy Transition(3)			Energy Marketing			Corporate			Total			Equity accounted investments(1)			Reclass Adjustments			IFRS Financials
Revenues		96		55		384			231			86			1			853			(3	)		—			850
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		21		(71	)		(2	)		(14	)		—			(66	)		—			66			—
Realized loss on closed exchange positions		—		—		—			—			21			—			21			—			(21	)		—
Decrease in finance lease receivable		—		—		10			—			—			—			10			—			(10	)		—
Finance lease income		—		—		6			—			—			—			6			—			(6	)		—
Unrealized foreign exchange gain on commodity		—		—		(3	)		—			—			—			(3	)		—			3			—
Adjusted revenues		96		76		326			229			93			1			821			(3	)		32			850
Fuel and purchased power(4)		4		4		129			190			—			1			328			—			—			328
Reclassifications and adjustments:
Australian interest income		—		—		(1	)		—			—			—			(1	)		—			1			—
Mine depreciation		—		—		(26	)		(48	)		—			—			(74	)		—			74			—
Coal inventory write-down		—		—		—			(5	)		—			—			(5	)		—			5			—
Adjusted fuel and purchased power		4		4		102			137			—			1			248			—			80			328
Carbon compliance		—		—		33			14			—			—			47			—			—			47
Gross margin		92		72		191			78			93			—			526			(3	)		(48	)		475
OM&A(4)		10		14		42			28			14			23			131			(1	)		—			130
Reclassifications and adjustments:
Parts and materials write-down		—		—		—			(5	)		—			—			(5	)		—			5			—
Adjusted OM&A		10		14		42			23			14			23			126			(1	)		5			130
Taxes, other than income taxes		—		3		4			1			—			1			9			—			—			9
Net other operating (income) loss		—		—		(10	)		57			—			—			47			—			—			47
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties		—		—		—			(58	)		—			—			(58	)		—			58			—
Adjusted net other operating income		—		—		(10	)		(1	)		—			—			(11	)		—			58			47
Adjusted EBITDA(5)		82		55		155			55			79			(24	)		402
Equity income																											1
Finance lease income																											6
Depreciation and amortization																											(123	)
Asset impairment charges																											(575	)
Net interest expense																											(63	)
Foreign exchange gain																											1
Gain on sale of assets and other																											23
Loss before income taxes																											(441	)

(1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) During the three months ended Sept. 30, 2021, $1 million related to station service costs for the Hydro segment was reclassified from OM&A to fuel and purchased power for comparative purposes. This did not impact previously reported net earnings.

(5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the 9 months ended Sept. 30, 2022:

	Hydro		Wind & Solar(1)			Gas(2)			Energy Transition(3)			Energy Marketing		Corporate			Total			Equity accounted investments(1)			Reclass Adjustments			IFRS Financials
Revenues		447		205			933			433			116		(2	)		2,132			(10	)		—			2,122
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		81			13			17			—		—			111			—			(111	)		—
Realized (gain) loss on closed exchange positions		—		—			(11	)		—			27		—			16			—			(16	)		—
Decrease in finance lease receivable		—		—			34			—			—		—			34			—			(34	)		—
Finance lease income		—		—			15			—			—		—			15			—			(15	)		—
Adjusted revenues		447		286			984			450			143		(2	)		2,308			(10	)		(176	)		2,122
Fuel and purchased power		17		20			445			332			—		3			817			—			—			817
Reclassifications and adjustments:
Australian interest income		—		—			(3	)		—			—		—			(3	)		—			3			—
Adjusted fuel and purchased power		17		20			442			332			—		3			814			—			3			817
Carbon compliance		—		1			56			(1	)		—		(5	)		51			—			—			51
Gross margin		430		265			486			119			143		—			1,443			(10	)		(179	)		1,254
OM&A		33		50			138			50			23		71			365			(1	)		—			364
Taxes, other than income taxes		3		7			13			2			—		1			26			(1	)		—			25
Net other operating income		—		(18	)		(30	)		—			—		—			(48	)		—			—			(48	)
Reclassifications and adjustments:
Insurance recovery		—		7			—			—			—		—			7			—			(7	)		—
Adjusted net other operating income		—		(11	)		(30	)		—			—		—			(41	)		—			(7	)		(48	)
Adjusted EBITDA(4)		394		219			365			67			120		(72	)		1,093
Equity income																											5
Finance lease income																											15
Depreciation and amortization																											(411	)
Asset impairment charges																											(4	)
Net interest expense																											(195	)
Foreign exchange gain																											17
Gain on sale of assets and other																											6
Earnings before income taxes																											346

(1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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The following table reflects adjusted EBITDA by segment and provides reconciliation to loss before income taxes for the 9 months ended Sept. 30, 2021:

	Hydro		Wind & Solar(1)		Gas(2)			Energy Transition(3)			Energy Marketing			Corporate			Total			Equity accounted investments(1)			Reclass Adjustments			IFRS Financials
Revenues		299		225		937			471			185			6			2,123			(12	)		—			2,111
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss		—		22		(122	)		27			(26	)		—			(99	)		—			99			—
Realized loss on closed exchange positions		—		—		1			—			49			—			50			—			(50	)		—
Decrease in finance lease receivable		—		—		30			—			—			—			30			—			(30	)		—
Finance lease income		—		—		19			—			—			—			19			—			(19	)		—
Unrealized foreign exchange gain on commodity		—		—		(3	)		—			—			—			(3	)		—			3			—
Adjusted revenues		299		247		862			498			208			6			2,120			(12	)		3			2,111
Fuel and purchased power(4)		13		11		347			411			—			6			788			—			—			788
Reclassifications and adjustments:
Australian interest income		—		—		(3	)		—			—			—			(3	)		—			3			—
Mine depreciation		—		—		(79	)		(100	)		—			—			(179	)		—			179			—
Coal inventory write-down		—		—		—			(16	)		—			—			(16	)		—			16			—
Adjusted fuel and purchased power		13		11		265			295			—			6			590			—			198			788
Carbon compliance		—		—		104			35			—			—			139			—			—			139
Gross margin		286		236		493			168			208			—			1,391			(12	)		(195	)		1,184
OM&A(4)		29		42		129			97			31			55			383			(2	)		—			381
Reclassifications and adjustments:
Parts and materials write-down		—		—		(2	)		(28	)		—			—			(30	)		—			30			—
Adjusted OM&A		29		42		127			69			31			55			353			(2	)		30			381
Taxes, other than income taxes		2		8		11			5			—			1			27			(1	)		—			26
Net other operating (income) loss		—		—		(30	)		56			—			—			26			—			—			26
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties		—		—		—			(58	)		—			—			(58	)		—			58			—
Adjusted net other operating income		—		—		(30	)		(2	)		—			—			(32	)		—			58			26
Adjusted EBITDA(5)		255		186		385			96			177			(56	)		1,043
Equity income																											5
Finance lease income																											19
Depreciation and amortization																											(395	)
Asset impairment charges																											(620	)
Net interest expense																											(186	)
Foreign exchange gain																											22
Gain on sale of assets and other																											56
Loss before income taxes																											(348	)

(1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.

(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

(4) During the nine months ended Sept. 30, 2021, $6 million related to station service costs for the Hydro segment was reclassified from OM&A to fuel and purchased power for comparative purposes. This did not impact previously reported net earnings.

(5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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

	3 months ended Sept. 30						9 months ended Sept. 30
	2022			2021			2022			2021
Cash flow from operating activities		204			610			526			947
Change in non-cash operating working capital balances		276			(378	)		252			(322	)
Cash flow from operations before changes in working capital		480			232			778			625
Adjustments
Share of adjusted FFO from joint venture(1)		2			3			7			7
Decrease in finance lease receivable		12			10			34			30
Clean energy transition provisions and adjustments(2)(4)		27			49			35			85
Realized (gain) loss on closed exchange positions		(42	)		21			16			50
Other(3)		9			3			17			11
FFO(5)		488			318			887			808
Deduct:
Sustaining capital(1)		(27	)		(44	)		(75	)		(144	)
Productivity capital		(1	)		(1	)		(3	)		(2	)
Dividends paid on preferred shares		(11	)		(9	)		(31	)		(29	)
Distributions paid to subsidiaries’ non-controlling interests		(54	)		(52	)		(126	)		(121	)
Principal payments on lease liabilities and other(1)		(2	)		(2	)		(6	)		(6	)
FCF(5)		393			210			646			506
Weighted average number of common shares outstanding in the period		271			271			271			271
FFO per share(5)		1.80			1.17			3.27			2.98
FCF per share(5)		1.45			0.77			2.38			1.87

(1) Includes our share of amounts for Skookumchuck wind facility, an equity accounted joint venture.

(2) Includes a write-down on parts and material inventory, and coal inventory for our coal operations in 2021 to net realizable value, amounts due to contractors for not proceeding with the Sundance Unit 5 repowering project and impairment of a previously recognized deferred asset, as it is no longer likely that we will incur sufficient capital or operating expenditures to utilize the remaining credit.

(3) Other consists of production tax credits which is a reduction to tax equity debt.

(4) During the third quarter of 2022, to support the employees affected by the closure of the Highvale mine and our transition off coal to cleaner sources, the Company made a voluntary special contribution of $35 million.

(5) These items are not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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

	3 months ended Sept. 30						9 months ended Sept. 30
	2022			2021			2022			2021
Adjusted EBITDA(1)		555			402			1,093			1,043
Provisions		(5	)		(20	)		5			(25	)
Interest expense		(47	)		(50	)		(151	)		(149	)
Current income tax expense		(11	)		(23	)		(36	)		(58	)
Realized foreign exchange gain (loss)		3			5			18			2
Decommissioning and restoration costs settled		(9	)		(5	)		(23	)		(13	)
Other non-cash items		2			9			(19	)		8
FFO(3)		488			318			887			808
Deduct:
Sustaining capital(2)		(27	)		(44	)		(75	)		(144	)
Productivity capital		(1	)		(1	)		(3	)		(2	)
Dividends paid on preferred shares		(11	)		(9	)		(31	)		(29	)
Distributions paid to subsidiaries’ non-controlling interests		(54	)		(52	)		(126	)		(121	)
Principal payments on lease liabilities and other(2)		(2	)		(2	)		(6	)		(6	)
FCF(3)		393			210			646			506

(1) Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to earnings (loss) before income taxes above.

(2) Includes our share of amounts for Skookumchuck wind facility, an equity accounted joint venture.

(3) These items are not defined and has no standardized meaning under IFRS. FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to cash flow from operating activities above.

Financial Highlights on a Proportional Basis of TransAlta Renewables

The proportionate financial information below reflects TransAlta’s share of TransAlta Renewables relative to TransAlta’s total consolidated figures. The financial highlights presented on a proportional basis of TransAlta Renewables are supplementary financial measures to reflect TransAlta Renewables’ portion of the consolidated figures.

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Consolidated Results

The following table reflects the generation and summary financial information on a consolidated basis during the period:

	Actual Generation (GWh)						Adjusted EBITDA(1)						Earnings (loss) before income taxes
3 months ended Sept. 30	2022			2021			2022			2021			2022			2021
TransAlta Renewables
Hydro		168			136			7			6
Wind and Solar(2)		685			718			32			40
Gas(2)		836			862			54			60
Corporate		—			—			(5	)		(4	)
TransAlta Renewables before adjustments		1,689			1,716			88			102			(26)			21
Less: Proportion of TransAlta Renewables not owned by TransAlta Corporation		(674	)		(676	)		(35	)		(40	)		10			(8	)
Portion of TransAlta Renewables owned by TransAlta Corporation		1,015			1,040			53			62			(16	)		13
Add: TransAlta Corporation’s owned assets excluding TransAlta Renewables
Hydro		570			475			238			76
Wind and Solar		—			—			10			15
Gas		2,006			2,051			141			95
Energy Transition		1,167			1,811			51			55
Energy Marketing		—			—			53			79
Corporate		—			—			(26	)		(20	)
TransAlta Corporation with Proportionate Share of TransAlta Renewables		4,758			5,377			520			362			136			(449	)
Non-controlling interests		674			676			35			40			(10	)		8
TransAlta Consolidated		5,432			6,053			555			402			126			(441	)

(1) Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to earnings (loss) before income taxes above.

(2) Wind and Solar and Gas segments include those assets that TransAlta Renewables holds an economic interest in.

	Actual Generation (GWh)						Adjusted EBITDA(1)						Earnings (loss) before income taxes
9 months ended Sept. 30	2022			2021			2022			2021			2022			2021
TransAlta Renewables
Hydro		368			338			15			14
Wind and Solar(2)		3,026			2,675			188			172
Gas(2)		2,505			2,374			166			151
Corporate		—			—			(16	)		(15	)
TransAlta Renewables before adjustments		5,899			5,387			353			322			41			110
Less: Proportion of TransAlta Renewables not owned by TransAlta Corporation		(2,354	)		(2,141	)		(141	)		(127	)		(16	)		(43	)
Portion of TransAlta Renewables owned by TransAlta Corporation		3,545			3,246			212			195			25			67

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	Actual Generation (GWh)				Adjusted EBITDA(1)						Earnings (loss) before income taxes
9 months ended Sept. 30	2022		2021		2022			2021			2022		2021
Add: TransAlta Corporation’s owned assets excluding TransAlta Renewables
Hydro		1,276		1,187		379			241
Wind and Solar		—		—		31			14
Gas		5,568		5,996		199			234
Energy Transition		2,510		3,712		67			96
Energy Marketing		—		—		120			177
Corporate		—		—		(56	)		(41	)
TransAlta Corporation with Proportionate Share of TransAlta Renewables		12,899		14,141		952			916			330		(391	)
Non-controlling interests		2,354		2,141		141			127			16		43
TransAlta Consolidated		15,253		16,282		1,093			1,043			346		(348	)

(1) Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to earnings (loss) before income taxes above.

(2) Wind and Solar and Gas segments include those assets that TransAlta Renewables holds an economic interest in.

Key Non-IFRS 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 and have no standardized meaning under IFRS and may not be comparable to those used by other entities or by rating agencies.

Adjusted Net Debt to Adjusted EBITDA

	Sept. 30, 2022			Dec. 31, 2021
Period-end long-term debt(1)		3,209			3,267
Exchangeable securities		338			335
Less: Cash and cash equivalents		(816	)		(947	)
Add: 50 per cent of issued preferred shares and exchangeable preferred shares(2)		671			671
Other(3)		(32	)		(19	)
Adjusted net debt(4)		3,370			3,307
Adjusted EBITDA(5)		1,336			1,286
Adjusted net debt to adjusted EBITDA (times)		2.5			2.6

(1) Consists of current and long-term portion of debt, which includes lease liabilities and tax equity financing.

(2) Exchangeable preferred shares are considered equity with dividend payments for credit-rating purposes. For accounting purposes, they are accounted for as debt with interest expense in the unaudited interim condensed consolidated financial statements. For purposes of this ratio, we consider 50 per cent of issued preferred shares, including these, as debt.

(3) Includes principal portion of TransAlta OCP restricted cash ($17 million for the nine months ended Sept. 30, 2022) and fair value of hedging instruments on debt (included in risk management assets and/or liabilities on the unaudited interim condensed consolidated statements of financial position).

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(4) The tax equity financing for Skookumchuck wind facility, an equity accounted joint venture, is not represented in the amounts. Adjusted net debt is not defined and has no standardized meaning 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 Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(5) Last 12 months.

The Company’s capital is managed internally and evaluated by management using a net debt position. We use the adjusted net debt to adjusted EBITDA ratio as a measurement of financial leverage and assess our ability to pay off debt. Our adjusted net debt to adjusted EBITDA ratio was lower as at Sept. 30, 2022 compared to 2021 as a result of debt repayments, lower cash and cash equivalents and higher adjusted EBITDA.

Deconsolidated Adjusted EBITDA by Segment

We invest in our assets directly as well as with joint venture partners. Deconsolidated financial information is a supplementary financial measure and is not intended to be, presented in accordance with IFRS.

Adjusted EBITDA is a key metric for TransAlta and TransAlta Renewables and provides management and shareholders a representation of core business profitability. Deconsolidated EBITDA is used in key planning and credit metrics and segment results highlight the operating performance of assets held directly at TransAlta that are comparable from period to period.

A reconciliation of adjusted EBITDA to deconsolidated adjusted EBITDA by segment results is set out below:

	3 months ended Sept. 30, 2022									3 months ended Sept. 30, 2021
	TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated			TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated
Hydro		245			7						82			6
Wind and Solar		42			32						55			40
Gas		195			54						155			60
Energy Transition		51			—						55			—
Energy Marketing		53			—						79			—
Corporate		(31	)		(5	)					(24	)		(4	)
Adjusted EBITDA		555			88			467			402			102			300
Less: TA Cogen adjusted EBITDA								(70	)								(41	)
Less: EBITDA from joint venture investments(1)								—									(2	)
Add: Dividend from TransAlta Renewables								38									38
Add: Dividend from TA Cogen								18									22
Deconsolidated TransAlta adjusted EBITDA(1)								453									317

(1) As of the second quarter of 2021, our share of amounts for the Skookumchuck wind equity accounted joint venture is excluded from the TransAlta deconsolidated results due to the sale of an economic interest in the 137 MW Skookumchuck wind facility to TransAlta Renewables.

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	9 months ended Sept. 30, 2022									9 months ended Sept. 30, 2021
	TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated			TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated
Hydro		394			15						255			14
Wind and Solar		219			188						186			172
Gas		365			166						385			151
Energy Transition		67			—						96			—
Energy Marketing		120			—						177			—
Corporate		(72	)		(16	)					(56	)		(15	)
Adjusted EBITDA		1,093			353			740			1,043			322			721
Less: TA Cogen adjusted EBITDA								(99	)								(104	)
Less: EBITDA from joint venture investments(1)								—									(9	)
Add: Dividend from TransAlta Renewables								113									113
Add: Dividend from TA Cogen								28									25
Deconsolidated TransAlta adjusted EBITDA(1)								782									746

(1) As of the second quarter of 2021, our share of amounts for the Skookumchuck wind equity accounted joint venture is excluded from the TransAlta deconsolidated results due to the sale of an economic interest in the 137 MW Skookumchuck wind facility to TransAlta Renewables.

Deconsolidated FFO

The Company has set capital allocation targets based on deconsolidated FFO available to shareholders. Deconsolidated financial information is a supplementary financial measure and is not defined and has no standardized meaning under IFRS and may not be comparable to those used by other entities or by rating agencies. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further details. Deconsolidated FFO for the periods ended Sept. 30, 2022 and 2021 is detailed below:

	3 months ended Sept. 30, 2022							3 months ended Sept. 30, 2021
	TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated	TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated
Cash flow from operating activities		204			37				610			83
Change in non-cash operating working capital balances		276			(4	)			(378	)		(23	)
Cash flow from operations before changes in working capital		480			33				232			60
Adjustments:
Decrease in finance lease receivable		12			—				10			—
Clean energy transition provisions and adjustments(1)		27			—				49			—
Realized (gain) loss on closed exchange positions		(42	)		—				21			—
Share of FFO from joint venture(2)		2			—				3			—
Finance income - economic interests		—			(2	)			—			(19	)

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	3 months ended Sept. 30, 2022							3 months ended Sept. 30, 2021
	TransAlta Consolidated		TransAlta Renewables		TransAlta Deconsolidated			TransAlta Consolidated		TransAlta Renewables		TransAlta Deconsolidated
FFO - economic interests(3)		—		37					—		46
Other(4)		9		—					3		—
FFO		488		68		420			318		87		231
Dividend from TransAlta Renewables						38							38
Distributions to TA Cogen’s Partner						(29	)						(25	)
Less: Share of adjusted FFO from joint venture(2)						—							(3	)
Deconsolidated TransAlta FFO						429							241

(1) Clean energy transition adjustments during the third quarter of 2021, include write-down on parts and material inventory for the coal operations, write-down on coal inventory to net realizable value, amounts due to contractors for not proceeding with the Sundance Unit 5 repowering project and impairment of previously recognized deferred asset, as there were no sufficient capital or operating expenditures incurred to utilize the remaining credit. During the third quarter of 2022, to support the employees affected by the closure of the Highvale mine and our transition off coal to cleaner sources, the Company made a voluntary special contribution of $35 million.

(2) As of the second quarter of 2021, our share of amounts for the Skookumchuck wind equity accounted joint venture is excluded from the TransAlta deconsolidated results due to the sale of an economic interest in the 137 MW Skookumchuck wind facility to TransAlta Renewables.

(3) FFO - economic interests calculated as Free Cash Flow economic interests plus sustaining capital expenditures economic interests and tax equity distributions and plus/minus currency adjustment.

(4) Other consists of production tax credits, which is a reduction to tax equity debt, less distributions from equity accounted joint venture.

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	9 months ended Sept. 30, 2022								9 months ended Sept. 30, 2021
	TransAlta Consolidated		TransAlta Renewables			TransAlta Deconsolidated			TransAlta Consolidated			TransAlta Renewables			TransAlta Deconsolidated
Cash flow from operating activities		526		168						947			265
Change in non-cash operating working capital balances		252		(2	)					(322	)		(57	)
Cash flow from operations before changes in working capital		778		166						625			208
Adjustments:
Decrease in finance lease receivable		34		—						30			—
Clean energy transition provisions and adjustments(1)		35		—						85			—
Realized loss on closed exchange positions		16		—						50			—
Share of FFO from joint venture(2)		7		—						7			—
Finance income - economic interests		—		(24	)					—			(68	)
FFO - economic interests(3)		—		136						—			131
Other(4)		17		—						11			—
FFO		887		278			609			808			271			537
Dividend from TransAlta Renewables							113									113
Distributions to TA Cogen’s Partner							(51	)								(42	)
Less: Share of adjusted FFO from joint venture(2)							—									(7	)
Deconsolidated TransAlta FFO							671									601

(1) Clean energy transition adjustments during the third quarter of 2021, include write-down on parts and material inventory for the coal operations, write-down on coal inventory to net realizable value, amounts due to contractors for not proceeding with the Sundance Unit 5 repowering project and impairment of previously recognized deferred asset, as there were no sufficient capital or operating expenditures incurred to utilize the remaining credit. During the third quarter of 2022, to support the employees affected by the closure of the Highvale mine and our transition off coal to cleaner sources, the Company made a voluntary special contribution of $35 million.

(2) As of the second quarter of 2021, our share of amounts for the Skookumchuck wind equity accounted joint venture is excluded from the TransAlta deconsolidated results due to the sale of an economic interest in the 137 MW Skookumchuck wind facility to TransAlta Renewables.

(3) FFO - economic interests calculated as Free Cash Flow economic interests plus sustaining capital expenditures economic interests and tax equity distributions and plus/minus currency adjustment.

(4) Other consists of production tax credits, which is a reduction to tax equity debt, less distributions from equity accounted joint venture.

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Deconsolidated Net Debt to Deconsolidated Adjusted EBITDA

In addition to reviewing fully consolidated ratios and results, management reviews net debt to adjusted EBITDA on a deconsolidated basis to highlight TransAlta’s financial flexibility, balance sheet strength and leverage. Deconsolidated financial information is a supplementary financial measure and is not defined under IFRS and may not be comparable to those used by other entities or by rating agencies. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further details.

As at	Sept. 30, 2022			Dec. 31, 2021
Adjusted net debt(1)		3,370			3,307
Add: TransAlta Renewables cash and cash equivalents		229			244
Less: TransAlta Renewables long-term debt		(782	)		(814	)
Less: US tax equity financing and South Hedland debt(2)		(806	)		(867	)
Deconsolidated net debt		2,011			1,870
Deconsolidated adjusted EBITDA(3)(5)		911			875
Deconsolidated net debt to deconsolidated adjusted EBITDA(4) (times)		2.2			2.1

(1) Refer to the Adjusted Net Debt to Adjusted EBITDA calculation under the Key Financial Non-IFRS Ratios section of this MD&A for the reconciliation and composition of Adjusted net debt.

(2) Relates to assets where TransAlta Renewables has economic interests.

(3) Refer to the Deconsolidated Adjusted EBITDA by Segment section of this MD&A for the reconciliation and composition of deconsolidated adjusted EBITDA and the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for the composition of adjusted EBITDA.

(4) The non-IFRS ratio is not a standardized financial measure under IFRS and might not be comparable to similar financial measures disclosed by other issuers.

(5) Last 12 months.

Our deconsolidated net debt to deconsolidated adjusted EBITDA ratio for the nine months ended Sept. 30, 2022, increased compared with 2021, due to higher deconsolidated net debt and deconsolidated adjusted EBITDA. Higher deconsolidated net debt is a result of decreases in cash balances offset by scheduled repayments on corporate debt.

Critical Accounting Policies and Estimates

The preparation of unaudited interim condensed consolidated 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 these 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.

Estimates to the extent to which geopolitical events such as the Russia-Ukraine conflict may, directly or indirectly, impact the Company’s operations, financial results and conditions in future periods are also subject to significant uncertainty. Uncertainty related to COVID-19 and the geopolitical events has been considered in our estimates as at and for the nine months period ended Sept. 30, 2022. Refer to the Governance and Risk Management section of this MD&A for further details.

The following were material changes in estimates:

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Asset Impairments

Wind and Solar

During the three and nine months ended Sept. 30, 2022, the Company recorded net impairment charges of $14 million and $35 million, respectively. During the second quarter of 2022, three wind facilities were impaired primarily as a result of an increase in discount rates. During the third quarter of 2022, two additional wind facilities and one solar facility were impaired as a result of changes in key assumptions including significant increases in discount rates and changes in estimated future cash flows.

Hydro

During the three and nine months ended Sept. 30, 2022, the Company recorded net impairment charges of $15 million and $21 million, respectively. During the second quarter of 2022, an impairment of $6 million was recorded on one of the hydro facilities primarily from an increase in discount rates. During the third quarter of 2022, two additional hydro facilities were impaired as a result of changes in key assumptions including significant increases in discount rates and changes in estimated future cash flows.

Change in Estimate - Decommissioning provision

The Company recognizes provisions for decommissioning obligations. Initial decommissioning provisions, and subsequent changes thereto, are determined using the Company’s best estimate of the required cash expenditures, adjusted to reflect the risks and uncertainties inherent in the timing and amount of settlement.

For the three months ended Sept. 30, 2022, the Company accelerated the expected timing on decommissioning and restoration for certain gas assets. This increased the decommissioning and restoration provision by $79 million resulting in an increase in PP&E of $29 million on operating assets and recognition of a $50 million impairment charge in net earnings related to retired assets. In the second quarter of 2022, an additional increase to decommissioning and restoration of $11 million was recognized in relation to an asset in the Gas segment.

For the nine months ended Sept. 30, 2022, the decommissioning and restoration provisions have decreased by $227 million due to a significant increase in discount rates, largely driven by increases in market benchmark rates. On average, discount rates increased with rates ranging from 6.8 to 9.6 per cent as at Sept. 30, 2022 (Dec. 31, 2021 - 3.6 to 6.5 per cent). This has resulted in a corresponding decrease in PP&E of $125 million on operating assets and recognition of $102 million impairment reversal in net earnings related to retired assets.

Change in Estimate - Useful Lives

During the third quarter of 2022, the Company adjusted the useful lives of certain assets included in the Gas segment to reflect changes made based on the future operating expectations of the assets. This resulted in an increase of $64 million in depreciation expense that was recognized in the Condensed Consolidated Statement of Earnings in the third quarter of 2022.

Defined Benefit Obligation

The liability for pension and post-employment benefits and associated costs included in compensation expenses are impacted by estimates related to changes in key actuarial assumptions, including discount rates. As a result of increases in discount rates, largely driven by increases in market benchmark rates, the defined benefit obligation decreased by $46 million for the nine months ended Sept. 30, 2022. A 1 per cent increase in discount rates would have a $38 million impact on the defined benefit obligation.

In addition, during the third quarter of 2022, the Company made a voluntary contribution of $35 million to further improve the funded status of the Sunhills Mining Ltd. Pension Plan and to support the employees affected

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by the closure of the Highvale mine and our transition off-coal to cleaner sources. This contribution reduces the amount of the Company’s future funding obligations, including amounts secured by the letter of credit.

Refer to Note 2(P) of the Company’s 2021 audited annual consolidated financial statements for further details on the Significant Accounting Judgments and Key Sources of Estimation Uncertainty.

Accounting Changes

Current Accounting Policy Changes

The accounting policies adopted in the preparation of the unaudited interim condensed consolidated financial statements are consistent with those followed in the preparation of the Company’s audited annual consolidated financial statements for the year ended Dec. 31, 2021, except for the adoption of new standards effective as of Jan. 1, 2022.

Amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets

On May 14, 2020, the International Accounting Standards Board (“IASB”) issued Onerous Contracts - Cost of Fulfilling a Contract and amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets to specify which costs to include when assessing whether a contract will be loss-making. The amendments are effective for annual periods beginning on or after Jan. 1, 2022, and the Company adopted these amendments as of Jan. 1, 2022. The amendments are effective for contracts for which an entity has not yet fulfilled all its obligations on or after the effective date. No adjustments resulted in the adoption of the amendments on Jan. 1, 2022.

Future Accounting Policy Changes

Please refer to Note 3 of the audited annual 2021 consolidated financial statements for the future accounting policies impacting the Company. In the three and nine months ended Sept. 30, 2022, no additional future accounting policy change impacting the Company were identified.

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 (loss).

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 a 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 multi-level 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.

During the three and nine months ended Sept. 30, 2022, the global economy continued to recover from the COVID-19 pandemic. On Feb. 24, 2022, the Russian government’s invasion of Ukraine set off historic policy actions and global coordination of sanctions and commitments to reduce dependency on Russian energy including natural gas. This has contributed to global supply chain disruptions, commodity price volatility and potential increases to inherent cybersecurity risk. The Company continues to mitigate inflationary and supply chain risks pertaining to current development projects by locking in the prices of key materials where possible

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and employing the other supply chain risk mitigation strategies described in our 2021 Annual MD&A. A prolonged conflict and recent inflationary and supply chain dynamics may impact future construction project costs with the risk of rising prices on key materials. Accordingly, as the Russia-Ukraine conflict continues to evolve and the indirect impacts of the Russia-Ukraine conflict and rising inflation rates within the global markets remain uncertain at this time, management continues to monitor and assess the impacts.

Interest Rate Risk

Interest rate risk arises as the fair value of future cash flows from a financial instrument fluctuates because of changes in market interest rates. Changes in interest rates can impact our borrowing costs. Changes in our cost of capital may also affect the feasibility of new growth initiatives.

At Sept. 30, 2022, approximately 3 per cent (Dec. 31, 2021 - 3 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. During the third quarter of 2022, the interest rate swap agreements with a notional amount of US$150 million referencing the three-month LIBOR were replaced with swap agreements referencing the Secured Overnight Financing Rate (“SOFR”). Existing interest rate swap agreements with a notional amount of US$150 million reference the US Treasury Bond yield. The maturity dates on all swap agreements have been extended.

The Company has US$400 million of debt maturing in November 2022 and we have hedged US$300 million of the underlying debt to reduce the interest rate risk.

Please refer to the Governance and Risk Management section of our 2021 Annual MD&A and Note 12 of our unaudited interim condensed consolidated financial statements for details on our risks and how we manage them. Our risk management profile and practices have not changed materially from Dec. 31, 2021.

Regulatory Updates

Refer to the Policy and Legal Risks discussion in our 2021 annual MD&A for further details that supplement the recent developments as discussed below:

Canada

Federal

The Government of Canada’s Department of Environment and Climate Change Canada (“ECCC”) continues engagement on the proposed new Clean Electricity Regulation (“CER”), originally known as the Clean Electricity Standards (“CES”), to achieve a net-zero electricity sector in Canada by 2035. ECCC is consulting on the CER design through the fall of 2022. It is expected that the draft regulation will be published in the Canada Gazette, Part I at the end of 2022 or early in 2023. Further consultation on the draft regulation will occur in 2023.

On Nov. 3, 2022, the Government of Canada announced new tax credits for renewable generation, energy storage, and hydrogen production. TransAlta will engage the Department of Finance as it finalizes the parameters of these tax credits.

Ontario

In the third quarter of 2022, the Ontario government undertook a consultation on proposed changes to its Emissions Performance Standards (“EPS”) carbon pricing system in advance of the provincial submission into the federal review process. The federal review process will occur in the fourth quarter of 2022.

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TransAlta has been actively involved in the consultation process and continues to advocate for an approach that supports our operations in the province. We do not anticipate any adverse impact from these policy proposals as TransAlta passes compliance costs and savings on to customers through our existing contracts.

In 2022, the IESO moved forward with procurement and planning to meet the upcoming capacity needs in the province in the short, medium and long-term. The IESO completed its medium-term RFP to procure capacity from existing generators and awarded five facilities including TransAlta’s Sarnia cogeneration facility and Melancthon 1 wind facility with new contracts that will run from May 1, 2026 to April 30, 2031. It is expected that Sarnia’s existing capacity contract with the IESO will be extended to the start date of the new contract. In addition, the IESO is moving forward with long-term procurement processes to secure up to 4,000 MW of capacity with commercial delivery by 2025-2027. TransAlta has qualified in the long-term procurement process. The contract awards for the procurements will be announced in 2023.

Alberta

In August 2022, the Government of Alberta launched a consultation on changes to the Technology Innovation and Emissions Reduction (“TIER”) Regulation, which governs the province’s carbon pricing regime. The review is meant to amend the regulations to meet the federal carbon pricing benchmark.

Key issues under consideration include aligning with the federal carbon price escalator to $170/tonne by 2030, increasing the stringency of TIER emissions performance standards and ensuring net demand for emissions credits deliver a consistent marginal price of carbon. TransAlta has been closely engaging in the consultations and continues to advocate for an approach that supports a predictable investment and operating environment.

United States

On Aug. 16, 2022, the Inflation Reduction Act of 2022 was signed into law by President Biden. This Act will invest approximately US$369 billion in Energy Security and Climate Change programs over the next 10 years. The administration estimates this funding will help reduce national carbon emissions by approximately 40 per cent by 2030, lower energy costs and increase clean energy production.

The US mid-term elections will be held on Nov. 8, 2022. Changes in Congress and the Senate could shift the focus of the government, specifically in terms of climate policy. TransAlta will continue to monitor the results of the mid-term elections along with the developments in the implementation of the IRA.

Australia

Since the Labour Party formed the government on May 21, 2022, Australia has increased its Nationally Determined Contribution (“NDC”) commitment to increase the country’s 2030 emissions reduction goal to 43 per cent below 2005 levels. The government also confirmed its intent to boost renewable electricity production to 82 per cent of the electricity supply by 2030.

We continue to see state-level policy announcements focused on moving away from coal and toward greater reliance on renewables, hydrogen and energy storage. We see low risk to our existing Australian assets, but policy support for continued industrial decarbonization that may support future growth.

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’’). During the nine months ended Sept. 30, 2022, the majority of our workforce supporting and executing our ICFR and DC&P returned to work and continue to work remotely on a hybrid basis. The Company has implemented appropriate controls and oversight for both in-office and remote work. There has been minimal impact to the design and performance of our internal controls.

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ICFR is a framework designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of audited annual 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 Company’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 is recorded, processed, summarized and reported within the time frame specified in applicable 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 applicable 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.

In accordance with the provisions of National Instrument 52-109 and consistent with U.S. Securities and Exchange Commission guidance, the scope of the evaluation did not include internal controls over financial reporting of North Carolina Solar, which the Company acquired on Nov. 5, 2021. North Carolina Solar facility was excluded from management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as at Dec. 31, 2021, due to the proximity of the acquisition to year-end. Further details related to the acquisition are disclosed in Note 4 to the Company’s audited annual consolidated financial statements for the year ended Dec. 31, 2021.

Consistent with the evaluation at Dec. 31, 2021, the scope of the evaluation does not include controls over financial reporting of the assets acquired through the North Carolina Solar facility acquisition, which the Company acquired on Nov. 5, 2021. North Carolina Solar’s total and net assets represented approximately 2 per cent and 3 per cent of the Company’s total and net assets and 1 per cent of the Company’s total net earnings, respectively, as at Sept. 30, 2022.

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 MD&A. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as at Sept. 30, 2022, the end of the period covered by this MD&A, our ICFR and DC&P were effective.

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Glossary of Key Terms

Alberta Electric System Operator (“AESO”)

The independent system operator and regulatory authority for the Alberta Interconnected Electric System.

Alberta Hydro Assets

The Company’s hydroelectric assets, owned through a wholly owned subsidiary, TransAlta Renewables Inc. These assets are located in Alberta consisting of the Barrier, Bearspaw, Cascade, Ghost, Horseshoe, Interlakes, Kananaskis, Pocaterra, Rundle, Spray, Three Sisters, Bighorn and Brazeau hydro facilities.

Ancillary Services

As defined by the Electric Utilities Act, Ancillary Services are those services required to ensure that the interconnected electric system is operated in a manner that provides a satisfactory level of service with acceptable levels of voltage and frequency.

Alberta Thermal

The business segment previously disclosed as Canadian Coal has been renamed to reflect the ongoing conversion of the boilers to burn gas in place of coal. The segment includes the legacy and converted generating units at our Sundance and Keephills sites and includes the Highvale mine.

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 energy, regardless of whether or not it is actually generating energy.

Adjusted Availability

Availability is adjusted when economic conditions exist, such that planned routine and major maintenance activities are scheduled to minimize expenditures. In high price environments, actual outage schedules would change to accelerate the generating unit’s return to service.

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. Its 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.balancingpool.ca.

Capacity

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

Centralia

The business segment previously disclosed as US Coal has been renamed to reflect the sole asset.

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.

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Disclosure Controls and Procedures (“DC&P”)

Refers to controls and other procedures designed to ensure that information required to be disclosed in the reports filed by the Company or submitted under securities legislation is recorded, processed, summarized and reported within the time frame specified in applicable securities legislation. DC&P include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in its reports that it files or submits under applicable securities legislation is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Dispatch optimization

Purchasing power to fulfill contractual obligations, when economical.

Emissions Performance Standards (“EPS”)

Under the Government of Ontario, emission performance standards establish greenhouse gas (GHG) emissions limits for covered facilities.

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.

Free Cash Flow (“FCF”)

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. Amount is calculated as cash generated by the Company through its operations (cash from operations) minus the funds used by the Company for the purchase improvement, or maintenance of the long-term assets to improve the efficiency or capacity of the Company (capital expenditures).

Funds from Operations (“FFO”)

Represents 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. Amount is calculated as cash flow from operating activities before changes in working capital and is adjusted for transactions and amounts that the Company believes are not representative of ongoing cash flows from operations.

Gigajoule (“GJ”)

A metric unit of energy commonly used in the energy industry. One GJ equals 947,817 British Thermal Units (“Btu”). One GJ is also equal to 277.8 kilowatt hours (“kWh”).

Gigawatt (“GW”)

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

Gigawatt hour (GWh)

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

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Greenhouse Gas (GHG)

A gas that has the potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons and perfluorocarbons.

IFRS

International Financial Reporting Standards.

ICFR

Internal control over financial reporting.

KH Bonds

The Kent Hills Wind LP (“KHLP”) non-recourse project bonds secured by, among other things, the Kent Hills 1, 2 and 3 wind facilities.

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.

Merchant

A term used to describe assets that are not contracted and are exposed to market pricing.

OM&A

Operations, maintenance and administration costs.

Other Hydro Assets

The Company’s hydroelectric assets located in British Columbia, Ontario and assets owned by TransAlta Renewables which include the Taylor, Belly River, Waterton, St. Mary, Upper Mamquam, Pingston, Bone Creek, Akolkolex, Ragged Chute, Misema, Galetta, Appleton and Moose Rapids facilities.

Power Purchase Agreement (“PPA”)

A long-term commercial agreement for the sale of electric energy to PPA buyers.

PP&E

Property, plant and equipment.

Turbine

A machine for generating rotary mechanical power from the energy of a stream of fluid (such as water, steam or hot gas). Turbines convert the kinetic energy of fluids to mechanical energy through the principles of impulse and reaction or a mixture of the two.

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Planned outage

Periodic planned shutdown of a generating unit for major maintenance and repairs. Duration is normally in weeks. The time is measured from unit shutdown to putting the unit back on line.

Unplanned outage

The shutdown of a generating unit due to an unanticipated breakdown.

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TransAlta Corporation

110 - 12th Avenue S.W.

Box 1900, Station “M”

Calgary, Alberta T2P 2M1

Phone

403.267.7110

Website

www.transalta.com

Computershare Trust Company of Canada

Suite 600, 530 - 8th Avenue SW

Calgary, Alberta T2P 3S8

Phone

Toll-free in North America: 1.800.564.6253

Outside North America: 514.982.7555

Fax

Toll-free in North America: 1.800.453.0330

Outside North America: 403.267.6529

Website

www.investorcentre.com

FOR MORE INFORMATION

Investor Inquiries

Phone

Toll-free in North America: 1.800.387.3598

Calgary or Outside North America: 403.267.2520

E-mail

investor_relations@transalta.com

Media Inquiries

Phone

Toll-free 1.855.255.9184

or 403.267.2540

E-mail

TA_Media_Relations@transalta.com

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Base Shelf Prospectus

TRANSALTA CORPORATION

US$2,000,000,000

Common Shares

First Preferred Shares

Warrants

Subscription Receipts

Debt Securities

Units

We may from time to time offer and issue (i) common shares (“Common Shares”), (ii) first preferred shares (“First Preferred Shares”), (iii) warrants to purchase Common Shares, First Preferred Shares or other securities (“Warrants”), (iv) subscription receipts that entitle the holder thereof to receive upon satisfaction of certain release conditions, and for no additional consideration, Common Shares (“Subscription Receipts”), (v) debt securities (“debt securities”), (vi) any combination of such securities, or (vii) units (“units”) comprised of one or more of such securities (the Common Shares, First Preferred Shares, Warrants, Subscription Receipts, debt securities and units are collectively referred to herein as the “Securities”) with an aggregate initial offering price not to exceed US$2,000,000,000 (or its equivalent in any other currency or currency unit used to denominate the Securities at the time of offering) during the 25 month period that this short form base shelf prospectus (the “Prospectus”), including any amendments hereto, remains valid. Eagle Hydro II LP (“Eagle Hydro II”) or certain affiliates of Brookfield Asset Management Inc. (“Brookfield” and collectively, the “Selling Shareholder”) may also offer and sell Common Shares from time to time pursuant to this Prospectus. See “Selling Shareholder” in this Prospectus. The debt securities may consist of debentures, notes or other types of debt and may be issuable in one or more series. The basis for calculating the dollar value of debt securities distributed under this Prospectus will be the aggregate principal amount of debt securities that we issue hereunder except in the case of any debt securities that are issued hereunder at an original issue discount, the dollar value of which will be calculated on the basis of the gross proceeds that we receive pursuant to such issuance(s).

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION (THE “SEC”) OR ANY UNITED STATES STATE SECURITIES COMMISSION NOR HAS THE SEC OR ANY UNITED STATES STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

We are permitted, under the multijurisdictional disclosure system adopted in the United States, to prepare this Prospectus in accordance with Canadian disclosure requirements. Prospective investors should be aware that such requirements are different from those of the United States. The financial statements incorporated herein by reference have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). As a result, such financial statements may not be comparable to financial statements of United States companies. See “About this Prospectus”.

The date of this prospectus is June 28, 2021.

Prospective investors should be aware that the acquisition of the Securities may have tax consequences both in the United States and Canada. Such tax consequences for investors who are resident in, or citizens of, the United States may not be described fully herein or in any applicable Prospectus Supplement (as defined herein). You should read the tax discussion under “Certain Income Tax Considerations” and in any relevant Prospectus Supplement.

The enforcement by investors of civil liabilities under United States federal securities laws may be affected adversely by the fact that the Corporation (as defined herein) is incorporated and organized under the laws of Canada, that most of TransAlta’s officers and directors are residents of Canada, that some or all of the underwriters or experts named in this Prospectus or a Prospectus Supplement may be residents of Canada, and that all or a substantial portion of the assets of the Corporation and of said persons may be located outside the United States.

The Securities offered hereby have not been qualified for sale under the securities laws of any province or territory of Canada (other than the Province of Alberta) and will not be offered or sold in Canada or to any resident of Canada.

The Securities may be offered separately or together, in amounts, at prices and on terms to be determined based on market conditions and other factors. The specific terms of any offering of Securities will be set forth in a prospectus supplement or supplements (each, a “Prospectus Supplement”) which will accompany this Prospectus. We reserve the right to include in a Prospectus Supplement specific terms pertaining to the Securities being offered that are not within the options and parameters set forth in this Prospectus. You should read this Prospectus and any applicable Prospectus Supplement before you invest in any Securities.

Our outstanding Common Shares are listed on the Toronto Stock Exchange (“TSX”) and on the New York Stock Exchange. Our outstanding First Preferred Shares, other than Series I, are listed on the TSX.

We may offer and sell the Securities and the Selling Shareholder may offer and sell Common Shares to or through underwriters or dealers purchasing as principals, directly to one or more purchasers or through agents. See “Plan of Distribution”. The Prospectus Supplement relating to a particular offering of Securities will identify each underwriter, dealer or agent engaged by TransAlta in connection with the offering and sale of the Securities, or by the Selling Shareholder in connection with the offering and sale of Common Shares, and will set forth the terms of the offering of such Securities, including the method of distribution, the proceeds to us and/or the Selling Shareholder and any fees, discounts or any other compensation payable to underwriters, dealers or agents and any other material terms of an offering of such Securities. The Securities may be sold from time to time in one or more transactions at a fixed price or prices or at non-fixed prices. If offered on a non-fixed price basis the Securities may be offered at market prices prevailing at the time of sale, at prices related to such prevailing market prices or at prices to be negotiated with purchasers, in which case the price at which the Securities will be offered and sold may vary from purchaser to purchaser and during the distribution period.

Our head and registered office is located at 110 - 12^th Avenue S.W., Calgary, Alberta, T2R 0G7.

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TABLE OF CONTENTS

ABOUT THIS PROSPECTUS	2
DOCUMENTS INCORPORATED BY REFERENCE	2
CERTAIN AVAILABLE INFORMATION	4
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	4
TRANSALTA CORPORATION	6
CONSOLIDATED CAPITALIZATION	6
USE OF PROCEEDS	6
EARNINGS COVERAGE RATIOS	7
DESCRIPTION OF SHARE CAPITAL	7
DESCRIPTION OF WARRANTS	9
DESCRIPTION OF SUBSCRIPTION RECEIPTS	10
DESCRIPTION OF UNITS	11
DESCRIPTION OF DEBT SECURITIES	12
PRIOR SALES	25
MARKET FOR SHARES	25
CERTAIN INCOME TAX CONSIDERATIONS	25
SELLING SHAREHOLDER	26
PLAN OF DISTRIBUTION	27
RISK FACTORS	28
LEGAL MATTERS	28
EXPERTS	28
INTEREST OF EXPERTS	28
TRANSFER AGENT AND REGISTRAR	28
DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT	29
ENFORCEMENT OF CERTAIN CIVIL LIABILITIES	29

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ABOUT THIS PROSPECTUS

In this Prospectus, in any Prospectus Supplement and in documents incorporated by reference in this Prospectus, unless otherwise specified or the context otherwise requires, all dollar amounts are expressed in Canadian dollars. “U.S. dollars” or “US$” means lawful currency of the United States. Our consolidated financial statements have been prepared in accordance with IFRS and are stated in Canadian dollars. Unless otherwise indicated, all financial information included and incorporated by reference in this Prospectus has been determined using IFRS. Except as set forth under “Description of Debt Securities” or unless the context otherwise requires, all references in this Prospectus and any Prospectus Supplement to “TransAlta”, the “Corporation”, “we”, “us” and “our” mean TransAlta Corporation and its consolidated subsidiaries including any consolidated partnerships of which the Corporation or any of its subsidiaries are partners.

We may, from time to time, sell any combination of the Securities described in this Prospectus, and the Selling Shareholder may, from time to time, sell Common Shares, in one or more offerings with an aggregate initial offering price not to exceed US$2,000,000,000. This Prospectus provides a general description of the Securities that we and, in the case of the Common Shares, that we and the Selling Shareholder may offer. Each time we offer and sell Securities or the Selling Shareholder sells Common Shares under this Prospectus, we will provide you with a Prospectus Supplement that will contain specific information about the terms of that offering. The Prospectus Supplement may also add, update or change information contained in this Prospectus. Before investing in any Securities, you should read both this Prospectus and any applicable Prospectus Supplement together with the additional information described below under “Documents Incorporated by Reference” and “Certain Available Information”.

All information permitted under applicable laws to be omitted from this Prospectus will be contained in one or more Prospectus Supplements. Each Prospectus Supplement will be incorporated by reference into this Prospectus for purposes of securities legislation as of the date of the Prospectus Supplement and only for the purposes of the distribution of the Securities to which such Prospectus Supplement pertains.

You should rely only on the information contained in or incorporated by reference in this Prospectus or any applicable Prospectus Supplement and on the other information included in the registration statement on Form F-10 of which this Prospectus forms a part. References herein to this “Prospectus” include documents incorporated by reference herein. We have not authorized anyone to provide you with different or additional information. We are not making an offer to sell these Securities and the Selling Shareholder is not making an offer to sell Common Shares in any jurisdiction where the offer or sale is not permitted by law. You should not assume that the information in this Prospectus, any applicable Prospectus Supplement or any documents incorporated by reference in this Prospectus or any applicable Prospectus Supplement is accurate as of any date other than the date on the front of those documents as our business, operating results, financial condition and prospects may have changed since that date.

DOCUMENTS INCORPORATED BY REFERENCE

The following documents of TransAlta, filed with the Alberta Securities Commission and filed with or furnished to the SEC, are specifically incorporated by reference in, and form an integral part of, this Prospectus:

(a) our consolidated audited annual financial statements, comprising the consolidated statements of financial position as at December  31, 2020 and 2019 and the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the years in the three-year period ended December 31, 2020 and the notes thereto (“Annual Financial Statements”) and the auditors’ report thereon and the auditors’ report on our internal control over financial reporting;

(b) our management’s discussion and analysis of financial condition and results of operations (“Annual MD&A”) in respect of our Annual Financial Statements;

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(c) our annual information form dated March 2, 2021 (the “Annual Information Form”) for the year ended December 31, 2020;

(d) our management proxy circular dated March 24, 2021 prepared in connection with TransAlta’s annual and special meeting of shareholders held on May 4, 2021;

(e) our unaudited interim condensed consolidated financial statements, comprising the condensed consolidated statement of financial position as at March 31, 2021 and the condensed consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the three-month periods ended March 31, 2021 and 2020 and the notes thereto (“Interim Financial Statements”); and

(f) our management’s discussion and analysis of financial condition and results of operations (“Interim MD&A”) in respect of our Interim Financial Statements.

Any documents of the type required to be incorporated by reference in a short form prospectus pursuant to National Instrument 44-101 Short Form Prospectus Distributions (“NI 44-101”) of the Canadian Securities Administrators, including any documents of the type referred to above, material change reports (excluding confidential material change reports) and business acquisition reports, and any updated earnings coverage ratio information that we file with the Alberta Securities Commission after the date of this Prospectus and prior to 25 months from the date hereof shall be deemed to be incorporated by reference into this Prospectus. These documents are available through the internet on the System for Electronic Document Analysis and Retrieval (“SEDAR”), which can be accessed at www.sedar.com. In addition, any similar documents that we file with or furnish to the SEC, including our current reports on Form 6-K or annual reports on Form 40-F and any other documents filed with or furnished to the SEC, pursuant to Sections 13(a), 13(c) or 15(a) of the United States Securities Exchange Act of 1934, as amended (the “U.S. Exchange Act”), in each case after the date of this Prospectus, shall be deemed to be incorporated by reference into this Prospectus and the registration statement on Form F-10 of which this Prospectus forms a part, if and to the extent expressly provided in such filings. Our U.S. filings are electronically available from the SEC’s Electronic Document Gathering and Retrieval System, which is commonly known by the acronym EDGAR and may be accessed at www.sec.gov.

Any statement contained in this Prospectus or in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for the purposes of this Prospectus to the extent that a statement contained herein or in any other subsequently filed document that also is or is deemed to be incorporated by reference herein modifies or supersedes such statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement is not to be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not constitute or be deemed to constitute a part of this Prospectus, except as so modified or superseded.

Upon a new annual information form and related annual audited comparative consolidated financial statements and accompanying management’s discussion and analysis being filed by TransAlta with, and where required, accepted by, the Alberta Securities Commission during the term of this Prospectus, the previous annual information form, the previous annual audited financial statements and accompanying management’s discussion and analysis, all interim financial statements and accompanying management’s discussion and analysis and all material change reports that we filed prior to the end, and all management information circulars and business acquisition reports that we filed prior to the beginning, of the financial year in respect of which our new annual information form and related annual audited comparative consolidated financial statements and accompanying management’s discussion and analysis are filed, shall be deemed no longer to be incorporated by reference into this Prospectus for purposes of future offers and sales of Securities hereunder. Upon a new management information circular in connection with an annual

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general meeting being filed by TransAlta with the Alberta Securities Commission during the term of this Prospectus, any information circular prepared in connection with a prior annual general meeting of TransAlta shall be deemed no longer to be incorporated into this Prospectus for purposes of future offers and sales of Securities hereunder. Upon interim financial statements and accompanying management’s discussion and analysis being filed by TransAlta with the Alberta Securities Commission during the term of this Prospectus, all interim financial statements and accompanying management’s discussion and analysis filed prior to the new interim consolidated financial statements shall be deemed no longer to be incorporated into this Prospectus for purposes of future offers and sales of Securities hereunder.

Information has been incorporated by reference in this Prospectus from documents filed with the Alberta Securities Commission and filed with or furnished to the SEC. Copies of the documents incorporated herein by reference may be obtained on request without charge from the Corporate Secretary of TransAlta at P.O. Box 1900, Station “M”, 110 - 12^th Avenue S.W., Calgary, Alberta, T2P 2M1; telephone (403) 267-7110.

CERTAIN AVAILABLE INFORMATION

We have filed with the SEC under the United States Securities Act of 1933, as amended (the “U.S. Securities Act”), a registration statement on Form F-10 relating to the Securities and of which this Prospectus forms a part. This Prospectus does not contain all of the information set forth in such registration statement, certain items of which are incorporated by reference in or contained in the exhibits to such registration statement as permitted or required by the rules and regulations of the SEC. See “Documents Filed as Part of the Registration Statement”. Statements made in this Prospectus as to the contents of any contract, agreement or other document referred to are only summaries, and in each instance, reference is made to the exhibit, if applicable, for a more complete description of the relevant matter, each such statement being qualified in its entirety by such reference. Items of information omitted from this Prospectus but contained in the registration statement on Form F-10 may be inspected and copied at the public reference facilities maintained at the offices of the SEC described below.

We are subject to the information requirements of the U.S. Exchange Act and, in accordance therewith, file reports and other information with the SEC. Under the multijurisdictional disclosure system adopted in the United States and Canada, such reports and other information may be prepared in accordance with the disclosure requirements of Canada, which requirements are different from those of the United States. We are exempt from the rules under the U.S. Exchange Act prescribing the furnishing and content of proxy statements, and our officers, directors and principal shareholders are exempt from the reporting and short swing profit recovery provisions contained in Section 16 of the U.S. Exchange Act. Under the U.S. Exchange Act, we are not required to publish financial statements as promptly as United States companies. Such reports and other information may be inspected without charge, and copied upon payment of prescribed fees, at the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549 and are also are available on the SEC’s EDGAR system, accessible at www.sec.gov.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Prospectus, including certain documents incorporated by reference herein, contains “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, results and expected future developments, as well as other factors deemed appropriate in the circumstances. These forward-looking statements are not facts, but only predictions and generally can be identified by the use of

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statements that include phrases such as “may”, “will”, “believe,” “expect,” “anticipate,”, “contemplate”, “estimate”, “propose”, “might”, “shall”, “project”, “should”, “could”, “would”, “predict”, “forecast”, “pursue”, “capable”, “intend”, “plan”, “foresee”, “potential”, “enable”, “continue” or other words or phrases of similar import. Similarly, statements that describe the Corporation’s objectives, plans or goals also are forward-looking statements. These forward-looking statements are subject to known and unknown risks, uncertainties and other important factors, many of which are beyond the Corporation’s control, that could cause actual events, outcomes or results to differ materially from those expressed or implied in the forward-looking statement. Although the Corporation believes that the assumptions and expectations conveyed by such forward-looking statements are reasonable based on information available on the date they are made, there can be no assurance that such assumptions and expectations will prove to be correct. In addition to the forward-looking statements contained in certain documents incorporated by reference herein, this Prospectus contains, without limitation, forward-looking statements pertaining to certain terms of the Securities and any offering made under this Prospectus.

The forward-looking statements contained in this Prospectus 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; merchant power prices in Alberta and the Pacific Northwest; discount rates; our proportionate ownership of TransAlta Renewables Inc. (“TransAlta Renewables”) not changing materially; no 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 energy-only market; and assumptions regarding our current strategy and priorities, including as it pertains to our current priorities relating to our conversions to gas, growing TransAlta Renewables and being able to realize the full economic benefit from the capacity, energy and ancillary services from our Alberta hydro assets. Additional assumptions on which we have based our 2021 guidance are disclosed with such guidance in the Annual MD&A.

Certain factors that could materially affect these forward-looking statements are described below and are incorporated by reference in this Prospectus, as described under “Risk Factors” in this Prospectus. Potential investors and other 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 and to not use future-oriented information or financial outlooks for anything other than their intended purpose. The forward-looking statements included in this document are made only as of the date of this Prospectus and the Corporation does not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties and assumptions, the forward-looking events might or might not occur. The Corporation cannot assure you that projected results or events will be achieved.

Factors that may cause the Corporation’s actual plans, actions or results to differ materially from those estimated or projected and expressed in, or implied by, these forward-looking statements include 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 outcome of pending legal proceedings being adverse to TransAlta; 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; exposure of our facilities, construction projects and operations to effects of natural disasters, public health crises (such as pandemics and epidemics, including the COVID-19 coronavirus or any other similar illness) and other catastrophic events beyond our control, which could decrease the willingness of the general population to travel, cause staff shortages, reduce demand for the Corporation’s products and services, cause supply shortages and

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cause increased government regulation; 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; 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, or sourcing sufficient quantities of natural gas, for the converted units; changes in expectations in the payment of future dividends, including from TransAlta Renewables; insurance coverage; credit ratings; our provision for income taxes; legal, regulatory, and contractual disputes and proceedings involving the Corporation; outcomes of investigations and disputes; reliance on key personnel; labour relations matters; and development projects and acquisitions. The foregoing risk factors, among others, are described in further detail under the heading “Risk Factors” in this Prospectus and in the documents incorporated by reference in this Prospectus, including the Annual MD&A and the Annual Information Form (or, as applicable, our annual information form and our management’s discussion and analysis for subsequent periods). The Corporation cautions that the foregoing list of factors that may affect future plans, actions or results is not exhaustive. The forward-looking statements contained and incorporated by reference in this Prospectus are expressly qualified by this cautionary statement.

TRANSALTA CORPORATION

TransAlta is a corporation amalgamated under the Canada Business Corporations Act. The registered office and principal place of business of TransAlta is located at 110 - 12th Avenue S.W., Calgary, Alberta, Canada, T2R 0G7. For further information on the intercorporate relationships among TransAlta and its subsidiaries, please refer to our most recent annual information form.

TransAlta and its predecessors have been engaged in the development, production and sale of electric energy since 1911 and are among Canada’s largest non-regulated electricity generation and energy marketing companies. We are focused on generating and marketing electricity in Canada, the United States and Western Australia through our diversified portfolio of facilities fuelled by hydro, wind, solar, energy storage, natural gas and thermal coal.

TransAlta Corporation is the majority owner of TransAlta Renewables, with an approximate 60 per cent direct and indirect ownership interest as of the date of this Prospectus. TransAlta Renewables is one of the largest generators of wind power and among the largest publicly traded renewable power generation companies in Canada. TransAlta Renewables, or one or more of its wholly-owned subsidiaries, directly own certain of our wind, hydro, natural gas and energy storage facilities. TransAlta Renewables also owns economic interests 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 certain agreements.

CONSOLIDATED CAPITALIZATION

There have been no material changes in our share and loan capital, on a consolidated basis, since March 31, 2021 to the date of this Prospectus.

USE OF PROCEEDS

Unless otherwise specified in a Prospectus Supplement, the net proceeds from the sale of the Securities will be used for general corporate purposes, which may include the repayment of indebtedness, the financing of our

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long-term investment plan and growth projects. The amount of net proceeds expected to be received from the sale of Securities, and each of the principal purposes for which we will use those net proceeds, will be set forth in the applicable Prospectus Supplement. We may, from time to time, issue securities (including Securities) other than pursuant to this Prospectus. The Corporation will not receive any proceeds from the sale of Common Shares sold by the Selling Shareholder under this Prospectus.

EARNINGS COVERAGE RATIOS

Information regarding our earnings coverage ratios will be provided in the applicable Prospectus Supplement relating to any offering of debt securities having a term to maturity in excess of one year or Preferred Shares pursuant to this Prospectus as required by applicable securities laws.

DESCRIPTION OF SHARE CAPITAL

General

As of the date of this Prospectus, the Corporation’s authorized share capital consists of an unlimited number of Common Shares and an unlimited number of First Preferred Shares, issuable in series.

Common Shares

The following description is a summary of the material attributes and characteristics of the Common Shares.

Each Common Share of the Corporation entitles the holder thereof to one vote for each Common Share held at all meetings of shareholders of the Corporation, except meetings at which only holders of another specified class or series of shares are entitled to vote, to receive dividends if, as and when declared by the board of directors (the “Board”), subject to prior satisfaction of preferential dividends applicable to any First Preferred Shares and any other class of shares of the Corporation ranking prior to the Common Shares, and to participate rateably in any distribution of the assets of the Corporation upon a liquidation, dissolution or winding up, subject to prior rights and privileges attaching to the First Preferred Shares and any other class of shares of the Corporation ranking prior to the Common 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.

The Common Shares offered pursuant to this Prospectus may include Common Shares issuable upon conversion or exchange of any First Preferred Shares of any series or upon exercise of any Warrants or upon conversion of any Subscription Receipts.

First Preferred Shares

The following description is a summary of the material attributes and characteristics of the First Preferred Shares.

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

The First Preferred Shares of all series rank senior to all other shares of TransAlta 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

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other shares of TransAlta unless all cumulative dividends accrued upon all outstanding First Preferred Shares have been paid or declared and set apart. In the event of the liquidation, dissolution or winding up of the Corporation, or a reduction of stated capital, no sum shall be paid or assets distributed to holders of other shares of the Corporation until the holders of First Preferred Shares shall have been paid the subscription price of their shares, plus a sum equal to the premium payable on a redemption, plus a sum equal to the arrears of dividends accumulated on the First Preferred Shares to the date of such liquidation, dissolution, winding up, or reduction of stated capital, as applicable. After payment of such amount, the holders of First Preferred Shares shall not be entitled to share further in the distribution of the assets of the Corporation.

The Board may include in the share conditions attaching to a particular series of First Preferred Shares certain voting rights effective upon the Corporation failing to make payment of six quarterly dividend payments, whether or not consecutive. These voting rights continue for so long as any dividends remain in arrears. These voting rights are the right to one vote for each $25 of subscription price on all matters in respect of which shareholders vote, and additionally, the right of all series of First Preferred Shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of First Preferred Shares shall not be entitled to vote or to receive notice of or to attend at any meeting of the shareholders of TransAlta.

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

The Prospectus Supplement will set forth the following terms relating to the First Preferred Shares being offered:

• the maximum number of First Preferred Shares;

• the designation of the series;

• the offering price;

• the annual dividend rate and whether the dividend rate is fixed or variable, the date from which dividends will accrue, and the dividend payment dates;

• the price and the terms and conditions for redemption, if any, including redemption at TransAlta’s option or at the option of the holder, including the time period for redemption, and payment of any accumulated dividends;

• the terms and conditions, if any, for conversion or exchange for shares of any other class of TransAlta or any other series of First Preferred Shares, or any other securities or assets, including the price or the rate of conversion or exchange and the method, if any, of adjustment;

• whether such First Preferred Shares will be listed on any securities exchange;

• the voting rights, if any; and

• any other rights, privileges, restrictions, or conditions.

Related Party Articles Provisions

The following description is a summary of the material attributes and characteristics of the related party provisions of the articles of the Corporation. Prospective investors are encouraged to review the full text of the articles of the Corporation, a copy of which can be found on SEDAR under our profile at www.sedar.com.

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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 26, 2019, between the Corporation and Computershare Trust Company of Canada (as successor rights agent). The Rights Plan was last confirmed at our annual and special meeting of shareholders on April 26, 2019 and will expire at the close of business on the date of our 2022 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.

DESCRIPTION OF WARRANTS

General

The Corporation may issue Warrants independently or together with other Securities, and Warrants sold with other Securities may be attached to or separate from the other Securities. Warrants will be issued under and governed by the terms of one or more warrant agreements or indentures that the Corporation will enter into with one or more banks or trust companies acting as warrant agent or trustee that will be named in the applicable Prospectus Supplement.

Selected provisions of the Warrants and the warrant agreements or indentures are summarized below. This summary is not complete. The statements made in this Prospectus relating to any warrant agreement or indenture and Warrants to be issued thereunder are summaries of certain anticipated provisions thereof and should be read together with the applicable warrant agreement or indenture.

A description of the material terms of any Warrants that we offer, and the extent to which the general terms and provisions described in this section apply to those Warrants, will be set out in the applicable Prospectus Supplement. The Prospectus Supplement will describe some or all of the following terms relating to the Warrants being offered:

• the designation of the Warrants;

• the aggregate number of Warrants offered and the offering price, if any;

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• the designation, number and terms of the Common Shares, First Preferred Shares or other Securities purchasable upon exercise of the Warrants, and procedures that will result in the adjustment of those numbers;

• the exercise price of the Warrants;

• the dates or periods on, after or during which the Warrants are exercisable;

• the designation and terms of any Securities with which the Warrants are issued and the number of Warrants that will be issued with each such Security;

• if the Warrants are issued as a unit with another Security, the date on and after which the Warrants and the other Security will be separately transferable;

• the currency or currency unit in which the offering price, if any, and exercise price are denominated;

• any minimum or maximum amount of Warrants that may be exercised at any one time;

• whether such Warrants will be listed on any securities exchange;

• any terms, procedures and limitations relating to the transferability, exchange or exercise of the Warrants;

• whether the Warrants will be subject to redemption or call and, if so, the terms of such redemption or call provisions; and

• any other terms of the Warrants.

Warrant certificates will be exchangeable for new warrant certificates of different denominations at the office indicated in the Prospectus Supplement. Prior to the exercise of their Warrants, holders of Warrants will not have any of the rights of holders of the securities underlying the Warrants.

Modifications

The Corporation may amend the warrant agreements or indentures and the Warrants, without the consent of the holders of the Warrants, to cure any ambiguity, to cure, correct or supplement any defective or inconsistent provision, or in any other manner that will not materially and adversely affect the interests of holders of the outstanding Warrants. Other amendment provisions shall be as indicated in the Prospectus Supplement.

Enforceability

The warrant agent or trustee, as applicable, will act solely as the Corporation’s agent. The warrant agent or trustee, as applicable, will not have any duty or responsibility if the Corporation defaults under the warrant agreements or indentures or the warrant certificates. A Warrant holder may, without the consent of the warrant agent or trustee, as applicable, enforce by appropriate legal action on its own behalf the holder’s right to exercise the holder’s Warrants.

DESCRIPTION OF SUBSCRIPTION RECEIPTS

The Corporation may issue Subscription Receipts, independently or together with other Securities, and Subscription Receipts sold with other Securities may be attached to or separate from the other Securities. Subscription Receipts will be issued under one or more subscription receipt agreements that we will enter into with one or more escrow agents. If underwriters or agents are involved in the sale of Subscription Receipts, one or more of such underwriters or agents may also be parties to the subscription receipt agreement governing those Subscription Receipts. The relevant subscription receipt agreement will establish the terms of the Subscription Receipts.

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A Subscription Receipt is a security of the Corporation that will entitle the holder to receive upon satisfaction of one or more release conditions, and for no additional consideration, a specified number of Securities. A description of the material terms of any Subscription Receipts that we offer, and the extent to which the general terms and provisions described in this section apply to those Subscription Receipts, will be set out in the applicable Prospectus Supplement. The Prospectus Supplement will describe some or all of the following terms relating to the Subscription Receipts being offered:

• the designation of the Subscription Receipts;

• the aggregate number of Subscription Receipts offered and the offering price;

• the currency or currency unit in which the Subscription Receipts will be offered;

• the terms, conditions and procedures for which the holders of Subscription Receipts will become entitled to receive Securities;

• the number of Securities that may be obtained upon the conversion of each Subscription Receipt, the anti-dilution provisions that will result in the adjustment of that number and the period or periods during which any conversion must occur;

• the designation and terms of any other Securities with which the Subscription Receipts will be offered and the number of Subscription Receipts that will be offered with each Security;

• the gross proceeds from the sale of such Subscription Receipts, including (if applicable) the terms applicable to the escrow agent holding in escrow all or a portion of the gross proceeds from the sale of such Subscription Receipts, plus any interest earned thereon, pending satisfaction of the release conditions;

• the material income tax consequences of owning, holding and disposing of such Subscription Receipts;

• whether such Subscription Receipts will be listed on any securities exchange;

• procedures for the refund by the escrow agent to holders of Subscription Receipts of all or a portion of the subscription price for their Subscription Receipts, plus any pro rata entitlement to interest earned or income generated on such amount, if the release conditions are not satisfied;

• any entitlement of ours to purchase the Subscription Receipts in the open market by private agreement or otherwise;

• whether we will issue the Subscription Receipts as global securities and, if so, who the depository will be;

• provisions as to modification, amendment or variation of the subscription receipt agreement or any rights or terms attaching to the Subscription Receipts;

• any terms, procedures and limitations relating to the transferability, exchange or conversion of the Subscription Receipts; and

• any other material terms and conditions of the Subscription Receipts.

DESCRIPTION OF UNITS

We may issue units comprised of one or more of the other Securities described in this Prospectus in any combination. Each unit will be issued so that the holder of the unit is also the holder of each Security included in the unit. Thus, the holder of a unit will have the rights and obligations of a holder of each included Security. The unit agreement under which a unit is issued may provide that the Securities included in the unit may not be held or transferred separately, at any time or at any time before a specified date.

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A description of the material terms of any units that we offer, and the extent to which the general terms and provisions described in this section apply to those units, will be set out in the applicable Prospectus Supplement. The Prospectus Supplement will describe some or all of the following terms relating to the units being offered:

• the designation and terms of the units and of the Securities comprising the units, including whether and under what circumstances those Securities may be held or transferred separately;

• any provisions for the issuance, payment, settlement, transfer or exchange of the units or of the Securities comprising the units; and

• whether the units will be issued as global securities and, if so, who the depositary will be.

DESCRIPTION OF DEBT SECURITIES

In this section, the terms “Corporation” and “TransAlta” refer only to TransAlta Corporation without its subsidiaries through which it operates. The following description of debt securities sets forth certain general terms and provisions of the debt securities that may be offered under this Prospectus and in respect of which a Prospectus Supplement may be filed. The Corporation will provide particular terms and provisions of a series of debt securities and a description of how the general terms and provisions described below may apply to that series in a Prospectus Supplement. Prospective investors should rely on information in the applicable Prospectus Supplement if it is different from the following information.

This Prospectus does not qualify the distribution of debt securities in respect of which the payment of principal and/or interest may be determined, in whole or in part, by reference to one or more underlying interests including, for example, an equity or debt security, a statistical measure of economic or financial performance including, but not limited to, any currency, consumer price or mortgage index, or the price or value of one or more commodities, indices or other items, or any other item or formula, or any combination or basket of the foregoing items. For greater certainty, the debt securities that may be distributed under this Prospectus include debt securities in respect of which the payment of principal and/or interest may be determined, in whole or in part, by reference to published rates of a central banking authority or one or more financial institutions, such as a prime rate or bankers’ acceptance rate, or to recognized market benchmark interest rates such as LIBOR, EURIBOR or a United States federal funds rate.

Unless otherwise specified in the applicable Prospectus Supplement, the debt securities will be issued under an indenture (the “Indenture”) dated as of June 25, 2002 between TransAlta and The Bank of New York Mellon (formerly known as The Bank of New York) as trustee (the “Trustee”). The Indenture is subject to, and governed by, the U.S. Trust Indenture Act of 1939, as amended. The Indenture has been filed as an exhibit to the registration statement on Form F-10 of which this Prospectus is a part and is available as described above under “Certain Available Information”. The following is a summary of the Indenture. Whenever there are references to particular provisions of the Indenture, those provisions are qualified in their entirety by reference to the Indenture. References in parentheses are to section numbers of the Indenture.

The Corporation may issue debt securities and incur additional indebtedness other than through the offering of debt securities pursuant to this Prospectus.

General

The Indenture does not limit the aggregate principal amount of debt securities which may be issued under the Indenture. It provides that debt securities may be issued from time to time in one or more series and may be denominated and payable in U.S. dollars or any other currency. Material Canadian and United States federal income tax considerations applicable to any debt securities, and special tax considerations applicable to the debt securities denominated in a currency or currency unit other than Canadian or U.S. dollars, will be described in the Prospectus Supplement relating to the offering of debt securities.

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The Prospectus Supplement will set forth the following terms relating to the debt securities being offered:

• the specific designation and any limit on the aggregate principal amount of the debt securities;

• the extent and manner, if any, to which payment on or in respect of the debt securities will be senior or will be subordinated to the prior payment of other liabilities and obligations of TransAlta;

• the percentage or percentages of principal amount at which the debt securities will be issued;

• the date or dates on which the principal (and premium, if any) on the debt securities will be payable;

• the rate or rates (whether fixed or variable) at which the debt securities will bear interest, if any (or the manner of calculation thereof) and the date or dates from which such interest will accrue;

• the dates on which any interest will be payable and the regular record dates for the payment of interest on debt securities in registered form;

• the place or places where the principal of (and premium, if any) and interest, if any, on the debt securities will be payable and each office or agency where the debt securities may be presented for registration of transfer or exchange;

• the currency or currency unit in which the debt securities are denominated or in which payment of the principal of (and premium, if any) and interest, if any, on such debt securities will be payable;

• whether debt securities will be issuable in the form of one or more global securities and if so the identity of the depository for the global securities;

• any mandatory or optional sinking fund provisions;

• the period or periods, if any, within which, the price or prices at which, the currency or currency unit in which, and the terms and conditions upon which the debt securities may be redeemed or purchased by TransAlta;

• the terms and conditions, if any, upon which TransAlta or the purchaser may redeem debt securities prior to maturity and the price or prices at which and the currency or currency unit in which the debt securities are payable;

• any index used to determine the amount of payments of principal of (and premium, if any) or interest, if any, on the debt securities;

• the terms, if any, on which the debt securities may be converted or exchanged for other securities of TransAlta or other entities;

• whether and under what circumstances TransAlta will pay additional amounts on the debt securities in respect of certain taxes (and the terms of any such payment) and, if so, whether TransAlta has the right to redeem the debt securities of any series rather than pay the additional amounts (and terms of any such right);

• whether debt securities are to be listed on any securities exchange;

• whether the debt securities of the series are to be issuable as registered securities, bearer securities (with or without coupons) or both;

• if other than denominations of US$1,000 and any integral multiple thereof, the denominations in which any registered securities of the series shall be issuable and, if applicable, the denomination of any bearer securities; and

• any other terms of the debt securities including covenants and Events of Default which apply solely to a particular series of debt securities being offered which do not apply generally to the debt securities, or any covenants or Events of Default generally applicable to debt securities which do not apply to a particular series of debt securities (Section 3.1).

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Unless otherwise indicated in the applicable Prospectus Supplement, the Indenture does not afford the holders the right to tender debt securities to TransAlta for repurchase or provide for any increase in the rate or rates of interest at which the debt securities will bear interest, in the event TransAlta should become involved in a highly leveraged transaction or in the event of a change in control of TransAlta.

Debt securities may be issued under the Indenture bearing no interest or interest at a rate below the prevailing market rate at the time of issuance, and may be offered and sold at a discount below their stated principal amount. The Canadian and United States federal income tax consequences and other special considerations applicable to any such discounted debt securities or other debt securities offered and sold at par which are treated as having been issued at a discount for Canadian and/or United States federal income tax purposes will be described in the applicable Prospectus Supplement.

Unless otherwise indicated in the applicable Prospectus Supplement, TransAlta may, without the consent of the holders thereof reopen a previous issue of a series of debt securities and issue additional debt securities of such series.

Ranking and Other Indebtedness

Unless otherwise indicated in an applicable Prospectus Supplement, the debt securities will be unsecured obligations and will rank equally with all of TransAlta’s other unsecured and unsubordinated indebtedness. TransAlta conducts a significant amount of its operations through its subsidiaries. The debt securities issued under this Prospectus will be structurally subordinated to all existing and future liabilities, including trade payables and other indebtedness of our subsidiaries.

Form, Denominations and Exchange

Debt securities of a series are issuable as registered securities in denominations of US$1,000 and integral multiples of US$1,000 or in such other denominations as may be set out in the terms of the debt securities of any particular series (Section 3.2). The Indenture also provides that debt securities of a series may be issuable in global form (Section 3.1).

Registered securities of any series will be exchangeable for other registered securities of the same series and of a like aggregate principal amount and tenor of different authorized denominations (Section 3.5).

The applicable Prospectus Supplement may indicate the places to register a transfer of debt securities. Except for certain restrictions set forth in the Indenture, no service charge will be made for any registration of transfer or exchange of the debt securities, but the Corporation may, in certain instances, require a sum sufficient to cover any tax or other governmental charges payable in connection with these transactions (Section 3.5).

We shall not be required to: (i) issue, register the transfer of or exchange debt securities of any series during a period beginning at the opening of business 15 days before any selection of debt securities of that series to be redeemed and ending at the close of business on the day of mailing of the relevant notice of redemption; (ii) register the transfer of or exchange any registered security, or portion thereof, called for redemption, except the unredeemed portion of any registered security being redeemed in part; or (iii) issue, register the transfer of or exchange any debt securities which have been surrendered for repayment at the option of the holder, except the portion, if any, thereof not to be so repaid (Section 3.5).

Under limited circumstances, we may issue debt securities in bearer form, in which case the applicable Prospectus Supplement will contain information regarding form, denomination and exchange of those bearer securities.

Payment

Unless otherwise indicated in the applicable Prospectus Supplement, payment of principal of and premium, if any, and interest, if any, on debt securities (other than global securities) will be made at the office or agency of

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the Trustee, at 240 Greenwich Street, New York, New York, 10286, or TransAlta can pay principal, interest and any premium by (i) cheque, mailed or delivered to the address of the person entitled at the address appearing in the security register of the Trustee or (ii) wire transfer to an account located in the United States of the person entitled to receive payments (Sections 3.7, 10.1 and 10.2).

Unless otherwise indicated in the applicable Prospectus Supplement, payment of any interest will be made to the persons in whose name the debt securities are registered at the close of business on the day or days specified by TransAlta (Section 3.7).

Global Securities

The registered debt securities of a series may be issued in whole or in part in global form (a “Global Security”) and will be registered in the name of and be deposited with a depository (the “Depositary”), or its nominee, each of which will be identified in the Prospectus Supplement (Section 3.1). Unless and until exchanged, in whole or in part, for debt securities in definitive registered form, a Global Security may not be transferred except as a whole by the Depositary for such Global Security to a nominee of the Depositary, by a nominee of the Depositary to the Depositary or another nominee of the Depositary or by the Depositary or any such nominee to a successor of the Depositary or a nominee of the successor (Section 3.5).

The specific terms of the depository arrangement with respect to any portion of a particular series of debt securities to be represented by a Global Security will be described in the Prospectus Supplement relating to such series. The Corporation anticipates that the following provisions will apply to all depository arrangements.

Upon the issuance of a Global Security, the Depositary therefor or its nominee will credit, on its book entry and registration system, the respective principal amounts of the debt securities represented by the Global Security to the accounts of such persons having accounts with such Depositary or its nominee (“participants”). Such accounts shall be designated by the underwriters, dealers or agents participating in the distribution of the debt securities or by TransAlta if such debt securities are offered and sold directly by the Corporation. Ownership of beneficial interests in a Global Security will be limited to participants or persons that may hold beneficial interests through participants. Ownership of beneficial interests in a Global Security will be shown on, and the transfer of that ownership will be effected only through, records maintained by the Depositary therefor or its nominee (with respect to interests of participants) or by participants or persons that hold through participants (with respect to interests of persons other than participants). The laws of some states in the United States may require that certain purchasers of securities take physical delivery of such securities in definitive form.

So long as the Depositary for a Global Security or its nominee is the registered owner of the Global Security, such Depositary or such nominee, as the case may be, will be considered the sole owner or holder of the debt securities represented by the Global Security for all purposes under the Indenture. Except as provided below, owners of beneficial interests in a Global Security will not be entitled to have debt securities of the series represented by the Global Security registered in their names, will not receive or be entitled to receive physical delivery of debt securities of such series in definitive form and will not be considered the owners or holders thereof under the Indenture.

Any payments of principal, premium, if any, and interest on Global Securities registered in the name of a Depositary or its nominee will be made to the Depositary or its nominee, as the case may be, as the registered owner of the Global Security representing such debt securities. None of TransAlta, the Trustee or any paying agent for debt securities represented by the Global Security will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests of the Global Security or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests.

The Corporation expects that the Depositary for a Global Security or its nominee, upon receipt of any payment of principal, premium or interest, will credit participants’ accounts with payments in amounts

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proportionate to their respective beneficial interests in the principal amount of the Global Security as shown on the records of such Depositary or its nominee. The Corporation also expects that payments by participants to owners of beneficial interests in a Global Security held through such participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers registered in “street name”, and will be the responsibility of such participants.

If a Depositary for a Global Security representing a particular series of debt securities is at any time unwilling or unable or no longer qualified to continue as depository and a successor depository is not appointed by TransAlta within 90 days, the Corporation will issue debt securities of such series in definitive form in exchange for a Global Security representing such series of debt securities. Further, if an Event of Default under the Indenture occurs and is continuing, debt securities of a series in definitive form will be printed and delivered. In addition, the Corporation may at any time and in its sole discretion determine not to have debt securities of a series represented by a Global Security and, in such event, will issue debt securities of a series in definitive form in exchange for all of the Global Securities representing the series of debt securities (Section 3.5).

Definitions

The Indenture contains, among others, definitions substantially to the following effect:

“Attributable Amount” means with respect to any sale and leaseback transaction (as defined herein under the heading “Covenants—Restrictions on Sales and Leasebacks” below), as at the time of determination, the present value (discounted at the rate of interest set forth or implicit in the terms of such lease, compounded annually) of the total obligations of the lessee for rental payments during the remaining term of the lease included in such sale and leaseback transaction.

“Consolidated Net Tangible Assets” means all consolidated assets of the Corporation as shown on the most recent audited consolidated balance sheet of the Corporation, less the aggregate of the following amounts reflected upon such balance sheet:

(a) all goodwill, deferred assets, trademarks, copyrights and other similar intangible assets;

(b) to the extent not already deducted in computing such assets and without duplication, depreciation, depletion, amortization, reserves and any other account which reflects a decrease in the value of an asset or a periodic allocation of the cost of an asset; provided that no such deduction shall be made to the extent such account reflects a decrease in the value or periodic allocation of the cost of any assets referred to in (a) above;

(c) minority interests;

(d) current liabilities; and

(e) assets created, developed, constructed or acquired with or in respect of which Non-Recourse Debt has been incurred, and any and all receivables, inventory, equipment, chattel paper, intangibles and other rights or collateral arising from or connected with those assets (including the shares or other ownership interests of a single purpose entity which holds only such assets and other rights and collateral arising from or connected therewith) and to which recourse of the lender of such Non-Recourse Debt is limited to the extent of the outstanding Non-Recourse Debt financing such assets.

“Consolidated Shareholders’ Equity” means, without duplication, the aggregate amount of shareholders’ equity (including, without limitation, common share capital, preferred share capital, contributed surplus and retained earnings) of the Corporation as shown on the most recent audited consolidated balance sheet of the Corporation, adjusted by the amount by which common share capital, preferred share capital and contributed surplus has been increased or decreased (as the case may be) from the date of such balance sheet to the relevant date of determination, in accordance with Generally Accepted Accounting Principles, together with the aggregate principal amount of obligations of the Corporation in respect of Preferred Securities.

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“Financial Instrument Obligations” means obligations arising under:

(a) any interest swap agreement, forward rate agreement, floor, cap or collar agreement, futures or options, insurance or other similar agreement or arrangement, or any combination thereof, entered into or guaranteed by the Corporation where the subject matter of the same is interest rates or the price, value, or amount payable thereunder is dependent or based upon the interest rates or fluctuations in interest rates in effect from time to time (but, for certainty, shall exclude conventional floating rate debt);

(b) any currency swap agreement, cross currency agreement, forward agreement, floor, cap or collar agreement, futures or options, insurance or other similar agreement or arrangement, or any combination thereof, entered into or guaranteed by the Corporation where the subject matter of the same is currency exchange rates or the price, value or amount payable thereunder is dependent or based upon currency exchange rates or fluctuations in currency exchange rates in effect from time to time; and

(c) any agreement for the making or taking of any commodity (including natural gas, oil or electricity), any commodity swap agreement, floor, cap or collar agreement or commodity future or option or other similar agreements or arrangements, or any combination thereof, entered into or guaranteed by the Corporation where the subject matter of the same is any commodity or the price, value or amount payable thereunder is dependent or based upon the price of any commodity or fluctuations in the price of any commodity;

to the extent of the net amount due or accruing due by the Corporation thereunder (determined by marking to market the same in accordance with their terms).

“Generally Accepted Accounting Principles” means generally accepted accounting principles which are in effect from time to time in Canada.

“Indebtedness” means all items of indebtedness in respect of any amounts borrowed (including obligations with respect to bankers’ acceptances and contingent reimbursement obligations relating to letters of credit and other financial instruments) and all Purchase Money Obligations which, in accordance with Generally Accepted Accounting Principles, would be recorded in the financial statements as at the date as of which Indebtedness is to be determined, and in any event including, without duplication:

(a) obligations secured by any Security Interest existing on property owned subject to such Security Interest, whether or not the obligations secured thereby shall have been assumed; and

(b) guarantees, indemnities, endorsements (other than endorsements for collection in the ordinary course of business) or other contingent liabilities in respect of obligations of another person for indebtedness of that other person in respect of any amounts borrowed by them.

“Material Subsidiary” means, at any time, a Subsidiary:

(a) the total assets of which represent more than 10% of the total assets of the Corporation determined on a consolidated basis as shown in the most recent audited consolidated balance sheet of the Corporation; or

(b) the total revenues of which represent more than 10% of the total revenues of the Corporation determined on a consolidated basis as shown in the consolidated income statement of the Corporation for the four most recent fiscal quarters of the Corporation.

“Non-Recourse Debt” means any Indebtedness incurred to finance the creation, development, construction or acquisition of assets and any increases in or extensions, renewals or refundings of any such Indebtedness, provided that the recourse of the lender thereof or any agent, trustee, receiver or other person acting on behalf of the lender in respect of such Indebtedness in respect thereof is limited in all circumstances (other than in respect of false or misleading representations or warranties and customary indemnities provided with respect to such financings) to the assets created, developed, constructed or acquired in respect of which such Indebtedness has

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been incurred and to any receivables, inventory, equipment, chattel paper, intangibles and other rights or collateral arising from or connected with the assets so created, developed, constructed or acquired (including the shares or other ownership interests of a single purpose entity which holds only such assets and other rights and collateral arising from or connected therewith) and to which the lender has recourse.

“Permitted Encumbrance” means any of the following:

(a) any Security Interest existing as of the date of the first issuance by the Corporation of debt securities issued pursuant to the Indenture, or arising thereafter pursuant to contractual commitments entered into prior to such issuance;

(b) any Security Interest created, incurred or assumed to secure any Purchase Money Obligation;

(c) any Security Interest created, incurred or assumed to secure any Non-Recourse Debt;

(d) any Security Interest in favour of any Wholly owned Subsidiary;

(e) any Security Interest on property of a corporation or its Subsidiaries which Security Interest exists at the time such corporation is merged into, or amalgamated or consolidated with the Corporation or such property is otherwise directly or indirectly acquired by the Corporation, other than a Security Interest incurred in contemplation of such merger, amalgamation, consolidation or acquisition;

(f) any Security Interest securing any Indebtedness to any bank or banks or other lending institution or institutions incurred in the ordinary course of business and for the purpose of carrying on the same, repayable on demand or maturing within 12 months of the date when such Indebtedness is incurred or the date of any renewal or extension thereof;

(g) any Security Interest on or against cash or marketable debt securities pledged to secure Financial Instrument Obligations;

(h) certain Security Interests in respect of liens or other encumbrances, not related to the borrowing of money, incurred or arising by operation of law or in the ordinary course of business;

(i) any extension, renewal, alteration or replacement (or successive extensions, renewals, alterations or replacements) in whole or in part, of any Security Interest referred to in the foregoing clauses (a) through (h) inclusive, provided the extension, renewal, alteration or replacement of such Security Interest is limited to all or any part of the same property that secured the Security Interest extended, renewed, altered or replaced (plus improvements on such property) and the principal amount of the Indebtedness secured thereby is not increased; and

(j) any other Security Interest if the aggregate amount of Indebtedness secured pursuant to this clause (j) (together with the Attributable Amount of any sale and leaseback) does not exceed 20% of Consolidated Net Tangible Assets.

“Preferred Securities” means securities which on the date of issue thereof by a person:

(a) have a term to maturity of more than 30 years;

(b) rank subordinate to the unsecured and unsubordinated Indebtedness of such person outstanding on such date;

(c) entitle such person to defer the payment of interest thereon for more than four years without thereby causing an event of default in respect of such securities to occur; and

(d) entitle such person to satisfy the obligation to make payments of deferred interest thereon from the proceeds of the issuance of its shares.

“Purchase Money Obligation” means any monetary obligation created or assumed as part of the purchase price of real or tangible personal property, whether or not secured, any extensions, renewals, alterations or

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replacements of any such obligation, provided that the principal amount of such obligation outstanding on the date of such extension, renewal, alteration or replacement is not increased and further provided that any security given in respect of such obligation shall not extend to any property other than the property acquired in connection with which such obligation was created or assumed and fixed improvements, if any, erected or constructed thereon.

“Security Interest” means any mortgage, charge, pledge, lien, encumbrance, assignment by way of security, title retention agreement or other security interest whatsoever, howsoever created or arising, whether absolute or contingent, fixed or floating, perfected or not, which secures payment or performance of an obligation.

“Subsidiary” means, in relation to a person:

(a) any corporation of which at least a majority of the outstanding shares having by the terms thereof ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether at the time shares of any other class or classes of such corporation might have voting power by reason of the happening of any contingency, unless the contingency has occurred and then only for as long as it continues) is at the time directly, indirectly or beneficially owned or controlled by the person or one or more of its Subsidiaries, or the person and one or more of its Subsidiaries;

(b) any partnership of which the person or one or more of its Subsidiaries, or the person and one or more of its Subsidiaries: (i) directly, indirectly or beneficially own or control more than 50% of the income, capital, beneficial or ownership interests (however designated) thereof; and (ii) is a general partner, in the case of a limited partnership, or is a partner that has authority to bind the partnership, in all other cases; or

(c) any other person of which at least a majority of the income, capital, beneficial or ownership interests (however designated) are at the time directly, indirectly or beneficially owned or controlled by the first mentioned person or one or more of its Subsidiaries, or the first mentioned person and one or more of its Subsidiaries.

“Wholly owned Subsidiary” means any Subsidiary that the Corporation directly or indirectly beneficially owns 100% of the outstanding shares having by the terms thereof ordinary voting power to elect a majority of the board of directors of such Subsidiary or owns, directly or indirectly, 100% of the income, capital, beneficial or ownership interests (however designated) thereof.

Covenants

The Indenture contains covenants substantially to the following effect:

Negative Pledge

So long as any debt securities remain outstanding the Corporation and its Subsidiaries will not create, assume or otherwise have outstanding any Security Interest, except for Permitted Encumbrances, on or over its or their respective assets (present or future) in respect of any Indebtedness of any person unless, in the opinion of legal counsel to the Corporation or the Trustee, the obligations of the Corporation in respect of all debt securities then outstanding shall be secured equally and rateably therewith (Section 10.12).

Restriction on Sales and Leasebacks

The Corporation will not, and will not permit any Subsidiary to, enter into any sale and leaseback transaction unless the Corporation and its Subsidiaries comply with this restrictive covenant. A “sale and leaseback transaction” is an arrangement between the Corporation or any Subsidiary and a bank, insurance company or other lender or investor where the Corporation or any Subsidiary lease real or personal property

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which was or will be sold by the Corporation or any Subsidiary to that lender or investor. The Corporation can comply with this restrictive covenant if it meets either of the following conditions:

(a) the sale and leaseback transaction is entered into prior to, concurrently with or within 270 days after the acquisition, the completion of construction (including any improvements on an existing property) or the commencement of commercial operations of the property; or

(b) the Corporation or its Subsidiaries could otherwise grant a Security Interest on the property as permitted by the provisions of the covenant described in “—Negative Pledge” (Section 10.10).

Mergers, Consolidations, Amalgamations and Sale of Assets

The Corporation will not enter into any transaction whereby all or substantially all of its undertaking, property and assets would become the property of any other person (the “Successor”), whether by reorganization, consolidation, amalgamation, arrangement, merger, transfer, sale, or otherwise, unless:

(a) the Successor expressly assumes all of the covenants and obligations of the Corporation under the Indenture and the transaction otherwise meets all of the requirements of the Indenture;

(b) the entity formed by or continuing from such consolidation or amalgamation or into which the Corporation is merged or with which the Corporation enters into such arrangement or the person which acquires or leases all or substantially all of the Corporation’s properties and assets is organized and existing under the laws of the United States, any state thereof or the District of Columbia or the laws of Canada or any province thereof;

(c) immediately before and after giving effect to such transaction, no Event of Default, and no event which, after notice or lapse of time or both, would become an Event of Default, shall have happened and be continuing; and

(d) no condition or event will exist as to the Corporation (at the time of such transaction) or the Successor (immediately after such transaction) and after giving full effect thereto or immediately after the Successor will become liable to pay the principal monies, premium, if any, interest and other monies due or which may become due hereunder, which constitutes or would constitute an Event of Default under the Indenture.

In addition to the above conditions, such transaction will, to the satisfaction of the Trustee, substantially preserve and not impair any of the rights and powers of the Trustee or of the debt security holders (Section 8.1).

If, as a result of any consolidation, amalgamation, arrangement, merger or upon any sale, conveyance, transfer or lease of all or substantially all of the properties and assets of the Corporation to any other person, any of the properties or assets of the Corporation or its Subsidiaries become subject to a Security Interest, then, unless such Security Interest could be created pursuant to the Indenture provisions described under “Negative Pledge” above without equally and rateably securing debt securities, the Corporation, simultaneously with or prior to such transaction, will cause any debt securities of the Corporation then outstanding to be secured equally and rateably with or prior to the Indebtedness secured by such Security Interest (Section 8.4).

Payment of Additional Amounts

Unless otherwise specified in an applicable Prospectus Supplement, TransAlta will, subject to the exceptions and limitations set forth below, pay to the holder of any debt security who is a non resident of Canada under the Income Tax Act (Canada) such additional amounts as may be necessary so that the amount received by such holder on any payment made under or with respect to such debt security, after deduction or withholding by TransAlta or any of its paying agents for or on account of any present or future tax, duty, assessment or other governmental charge (including penalties, interest and other liabilities related thereto) imposed or levied by or on behalf of the government of Canada or any province or territory thereof or by any authority or agency therein or

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thereof having power to tax (collectively, “Canadian Taxes”) upon or as a result of such payment, will not be less than the amount that the holder would have received if such Canadian Taxes had not been withheld or deducted. However, TransAlta will not be required to make any payment of additional amounts:

(a) to any person in respect of whom such Canadian Taxes are required to be withheld or deducted as a result of such person not dealing at arm’s length with TransAlta (within the meaning of the Income Tax Act (Canada));

(b) to any person by reason of such person being connected with Canada (otherwise than merely by holding or ownership of any series of debt securities or receiving any payments or exercising any rights thereunder), including without limitation a non resident insurer who carries on an insurance business in Canada and in a country other than Canada;

(c) for or on account of any Canadian Taxes which would not have been so imposed but for: (i) the presentation by the holder of such debt security or coupon for payment on a date more than 30 days after the date on which such payment became due and payable or the date on which payment thereof is duly provided for, whichever occurs later; or (ii) the holder’s failure to comply with any certification, identification, information, documentation or other reporting requirements if compliance is required by law, regulation, administrative practice or an applicable treaty as a precondition to exemption from or a reduction in the rate of deduction or withholding of any such taxes, assessment or charge;

(d) for or on account of any estate, inheritance, gift, sales, transfer, personal property tax or any similar tax, assessment or other governmental charge;

(e) for or on account of any Canadian Taxes required to be withheld by any paying agent from any payment to a person on a debt security if such payment can be made to such person without such withholding by at least one other paying agent the identity of which is provided to such person;

(f) for or on account of any Canadian Taxes which are payable otherwise than by withholding from a payment on a debt security; or

(g) for any combination of items (a), (b), (c), (d), (e) and (f);

nor will additional amounts be paid with respect to any payment on a debt security to a holder who is a fiduciary or partnership or other than the sole beneficial owner of such payment to the extent such payment would be required by the laws of Canada (or any political subdivision thereof) to be included in the income for Canadian federal income tax purposes of a beneficiary or settlor with respect to such fiduciary or a member of such partnership or a beneficial owner who would not have been entitled to payment of the additional amounts had such beneficiary, settlor, member or beneficial owner been the holder of such debt security.

The Corporation will furnish to the holders of the debt securities, within 30 days after the date of the payment of any Canadian Taxes is due pursuant to applicable law, certified copies of tax receipts or other documents evidencing such payment by the Corporation.

Wherever in the Indenture there is mentioned, in any context, the payment of principal (and premium, if any), redemption price, interest or any other amount payable under or with respect to a debt security, such mention shall be deemed to include mention of the payment of additional amounts to the extent that, in such context, additional amounts are, were or would be payable in respect thereof (Section 10.5).

Redemption

If and to the extent specified in an applicable Prospectus Supplement, the debt securities of a series will be subject to redemption at the time or times specified therein, at a redemption price equal to the principal amount thereof together with accrued and unpaid interest to the date fixed for redemption, upon the giving of a notice. Notice of redemption of the debt securities of such series will be given not more than 60 nor less than 30 days prior to the date fixed for redemption and will specify the date fixed for redemption (Section 11.4).

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Provision of Financial Information

TransAlta will file with the Trustee, within 15 days after it files them with the SEC, copies of its annual report and of the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) which TransAlta is required to file with the SEC pursuant to Section 13 or 15(d) of the U.S. Exchange Act. Notwithstanding that TransAlta may not be required to remain subject to the reporting requirements of Section 13 or 15(d) of the U.S. Exchange Act or otherwise report on an annual and quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, TransAlta will continue to provide the Trustee (a) within 140 days after the end of each fiscal year, the information required to be contained in annual reports on Form 20-F or Form 40-F as applicable (or any successor form); and (b) within 60 days after the end of each of the first three fiscal quarters of each fiscal year, the information required to be contained in reports on Form 6-K (or any successor form), which, regardless of applicable requirements shall, at a minimum, consist of such information required to be provided in quarterly reports under the laws of Canada or any province thereof to security holders of a corporation with securities listed on the Toronto Stock Exchange, whether or not TransAlta has any of its securities listed on such exchange. Such information will be prepared in accordance with Canadian disclosure requirements and Generally Accepted Accounting Principles (Section 7.5).

Events of Default

Unless otherwise specified in the Prospectus Supplement relating to a particular series of debt securities, the following events are defined in the Indenture as “Events of Default” with respect to debt securities of any series: (a) the failure of the Corporation to pay when due the principal of or premium (if any) on any debt securities; (b) the failure of the Corporation, continuing for 30 days, to pay any interest due on any debt securities; (c) the breach or violation of any covenant or condition (other than as referred to in (a) and (b) above), which continues for a period of 60 days after notice from the Trustee or from holders of at least 25% in principal amount of all outstanding debt securities of any series affected thereby (or such longer period as may be agreed to by the Trustee); (d) the failure of the Corporation or any Subsidiary to pay when due (after giving effect to any applicable grace periods) any amount owing in respect of any Indebtedness other than Non-Recourse Debt, or the Corporation or any Subsidiary otherwise defaults in connection with such Indebtedness, and if such Indebtedness has not matured it shall have been accelerated, provided that the aggregate principal amount of such Indebtedness is in excess of the greater of US$75 million and 3% of Consolidated Shareholders’ Equity (provided that if such default is waived by the persons entitled to do so, then the Event of Default in this clause (d) will be deemed to be waived without further action on the part of the Trustee or the holders of the debt securities); (e) the entry of certain judgments or decrees against the Corporation or any Material Subsidiary for the payment of money in excess of the greater of US$75 million and 3% of Consolidated Shareholders’ Equity, in the aggregate, if the Corporation or any such Material Subsidiary, as the case may be, fails to pay such decree or judgment within 60 days or file an appeal thereof within 60 days or, if the Corporation or such Material Subsidiary, as the case may be does file an appeal, that judgment or decree is not and does not remain vacated, discharged or stayed as provided in the Indenture; (f) certain events of bankruptcy, insolvency or reorganization involving the Corporation or a Material Subsidiary; or (g) any other Event of Default provided with respect to debt securities of that series (Section 5.1).

If an Event of Default occurs and is continuing with respect to any series of debt securities, then and in every such case the Trustee or the holders of at least 25% in aggregate principal amount of the outstanding debt securities of such affected series may, subject to any subordination provisions thereof, declare the entire principal amount (or, if the debt securities of that series are original issue discount debt securities, such portion of the principal amount as may be specified in the terms of that series) of all debt securities of such series and all interest thereon to be immediately due and payable. However, at any time after a declaration of acceleration with respect to any series of debt securities has been made, but before a judgment or decree for payment of the money due has been obtained, the holders of a majority in principal amount of the outstanding debt securities of that series, by written notice to the Corporation and the Trustee under certain circumstances (which include payment or deposit with the Trustee of a sum sufficient to pay all unpaid principal and premium, if any, of, and all

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overdue interest, if any, on, those outstanding debt securities and sums paid or advanced by the Trustee under the Indenture and the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, unless the Prospectus Supplement applicable to an issue of debt securities otherwise provides), may rescind and annul such declaration and its consequences (Section 5.2).

Reference is made to the Prospectus Supplement relating to each series of debt securities which are original issue discount securities for the particular provisions relating to acceleration of the maturity of a portion of the principal amount of such original issue discount securities upon the occurrence of any Event of Default and the continuation thereof.

The Indenture provides that, subject to the duty of the Trustee during default to act with the required standard of care, the Trustee shall be under no obligation to exercise any of its rights and powers under the Indenture at the request or direction of any of the holders, unless such holders shall have offered to the Trustee reasonable indemnity (Section 6.2). Subject to such provisions for indemnification of the Trustee and certain other limitations set forth in the Indenture, the holders of a majority in principal amount of the outstanding debt securities of all series affected by an Event of Default shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee, with respect to the outstanding debt securities of all series affected by such Event of Default (Section 5.12).

No holder of a debt security of any series will have any right to institute any proceeding with respect to the Indenture, or for the appointment of a receiver or a trustee, or for any other remedy thereunder, unless (a) such holder has previously given to the Trustee written notice of a continuing Event of Default with respect to the debt securities of such series affected by such Event of Default, (b) the holders of at least 25% in aggregate principal amount of the outstanding debt securities of such series affected by such Event of Default have made written request, and such holder or holders have offered reasonable indemnity, to the Trustee to institute such proceeding as Trustee, and (c) the Trustee has failed to institute such proceeding, and has not received from the holders of a majority in aggregate principal amount of the outstanding debt securities of such series affected by such Event of Default a direction inconsistent with such request, within 60 days after such notice, request and offer (Section 5.7). However, such limitations do not apply to a suit instituted by the holder of a debt security for the enforcement of payment of the principal of or any premium or interest on such debt security on or after the applicable due date specified in such debt security (Section 5.8).

The Corporation will be required to furnish to the Trustee annually a statement by certain of its officers as to whether or not the Corporation, to the best of their knowledge, is in compliance with all conditions and covenants of the Indenture and, if not, specifying all such known defaults (Section 10.4).

Modification and Waiver

Modifications and amendments of the Indenture may be made by the Corporation and the Trustee with the consent of the holders of a majority in principal amount of the outstanding debt securities of each series issued under the Indenture affected by such modification or amendment; provided, however, that no such modification or amendment may, without the consent of the holder of each outstanding debt security of such affected series: (1) change the stated maturity of the principal of, or any instalment of interest, if any, on any debt security; (2) reduce the principal amount of, or the premium, if any, or the rate of interest, if any, on any debt security; (3) change the place of payment; (4) change the currency or currency unit of payment of principal of (or premium, if any) or interest, if any, on any debt security; (5) impair the right to institute suit for the enforcement of any payment on or with respect to any debt security; (6) adversely affect any right to convert or exchange any debt security; (7) reduce the percentage of principal amount of outstanding debt securities of such series, the consent of the holders of which is required for modification or amendment of the applicable Indenture or for waiver of compliance with certain provisions of the Indenture or for waiver of certain defaults; (8) reduce the voting or quorum requirements relating to meetings of holders of debt securities; or (9) modify any provisions of

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the Indenture relating to the modification and amendment of the Indenture or the waiver of past defaults or covenants except as otherwise specified in the Indenture (Section 9.2). In addition, any amendment to, or waiver of, the provisions of the Indenture relating to subordination that adversely affects the rights of the holders of debt securities will require the consent of holders of at least 75% in aggregate principal amount of such debt securities then outstanding (Section 9.2).

The holders of a majority in principal amount of the outstanding debt securities of any series may on behalf of the holders of all debt securities of that series waive, insofar as that series is concerned, compliance by the Corporation with certain restrictive provisions of the Indenture (Section 10.13). The holders of a majority in principal amount of outstanding debt securities of any series may waive any past default under the Indenture with respect to that series, except a default in the payment of the principal of (or premium, if any) and interest, if any, on any debt security of that series or in respect of a provision which under the Indenture cannot be modified or amended without the consent of the holder of each outstanding debt security of that series (Section 5.13). The Indenture or the debt securities may be amended or supplemented, without the consent of any holder of debt securities, to cure any ambiguity or inconsistency or to make any change that does not have an adverse effect on the rights of any holder of debt securities (Section 9.1).

Defeasance

The Indenture provides that, at its option, TransAlta will be discharged from any and all obligations in respect of the outstanding debt securities of any series upon irrevocable deposit with the Trustee, in trust, of money, government securities or a combination thereof which will provide money in an amount sufficient in the opinion of a nationally recognized firm of independent chartered accountants to pay the principal of and premium, if any, and each instalment of interest, if any, on the outstanding debt securities of such series (“Defeasance”) (except with respect to the authentication, transfer, exchange or replacement of debt securities or the maintenance of a place of payment and certain other obligations set forth in the Indenture). Such trust may only be established if among other things (1) TransAlta has delivered to the Trustee an opinion of counsel in the United States stating that (a) TransAlta has received from, or there has been published by, the Internal Revenue Service a ruling, or (b) since the date of execution of the Indenture, there has been a change in the applicable United States federal income tax law, in either case to the effect that the holders of the outstanding debt securities of such series will not recognize income, gain or loss for United States federal income tax purposes as a result of such Defeasance and will be subject to United States federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Defeasance had not occurred; (2) TransAlta has delivered to the Trustee an opinion of counsel in Canada or a ruling from the Canada Revenue Agency (“CRA”) to the effect that the holders of such outstanding debt securities of such series will not recognize income, gain or loss for Canadian federal, provincial or territorial income or other tax purposes as a result of such Defeasance and will be subject to Canadian federal or provincial income and other tax on the same amounts, in the same manner and at the same times as would have been the case had such Defeasance not occurred (and for the purposes of such opinion, such Canadian counsel shall assume that holders of the outstanding debt securities of such series include holders who are not resident in Canada); (3) no Event of Default or event that, with the passing of time or the giving of notice, or both, shall constitute an Event of Default shall have occurred and be continuing on the date of such deposit; (4) TransAlta is not an “insolvent person” within the meaning of the Bankruptcy and Insolvency Act (Canada); (5) TransAlta has delivered to the Trustee an opinion of counsel to the effect that such deposit shall not cause the Trustee or the trust so created to be subject to the United States Investment Company Act of 1940, as amended; and (6) TransAlta has delivered to the Trustee an officer’s certificate and opinion of counsel stating that certain conditions precedent are satisfied. TransAlta may exercise its Defeasance option notwithstanding its prior exercise of its Covenant Defeasance option described in the following paragraph if TransAlta meets the conditions described in the preceding sentence at the time TransAlta exercises the Defeasance option (Sections 14.1, 14.2 and 14.4).

The Indenture provides that, at its option, unless and until TransAlta has exercised its Defeasance option described in the preceding paragraph, TransAlta may omit to comply with covenants, including the covenants described above under the heading “Covenants”, and such omission shall not be deemed to be an Event of

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Default under the Indenture and the outstanding debt securities upon irrevocable deposit with the Trustee, in trust, of money and/or government securities which will provide money in an amount sufficient in the opinion of a nationally recognized firm of independent chartered accountants to pay the principal of and premium, if any, and each instalment of interest, if any, on the outstanding debt securities (“Covenant Defeasance”). If TransAlta exercises its Covenant Defeasance option, the obligations under the Indenture other than with respect to such covenants and the Events of Default other than with respect to such covenants shall remain in full force and effect. Such trust may only be established if, among other things, (1) TransAlta has delivered to the Trustee an opinion of counsel in the United States to the effect that the holders of the outstanding debt securities will not recognize income, gain or loss for United States federal income tax purposes as a result of such Covenant Defeasance and will be subject to United States federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred; (2) TransAlta has delivered to the Trustee an opinion of counsel in Canada or a ruling from the CRA to the effect that the holders of such outstanding debt securities will not recognize income, gain or loss for Canadian federal, provincial or territorial income or other tax purposes as a result of such Covenant Defeasance and will be subject to Canadian federal or provincial income and other tax on the same amounts, in the same manner and at the same times as would have been the case had such Covenant Defeasance not occurred (and for the purposes of such opinion, such Canadian counsel shall assume that holders of the outstanding debt securities include holders who are not resident in Canada); (3) no Event of Default or event that, with the passing of time or the giving of notice, or both, shall constitute an Event of Default shall have occurred and be continuing on the date of such deposit; (4) TransAlta is not an “insolvent person” within the meaning of the Bankruptcy and Insolvency Act (Canada); (5) TransAlta has delivered to the Trustee an opinion of counsel to the effect that such deposit shall not cause the Trustee or the trust so created to be subject to the United States Investment Company Act of 1940, as amended; and (6) TransAlta has delivered to the Trustee an officer’s certificate and opinion of counsel stating that certain conditions precedent are satisfied (Sections 14.3 and 14.4).

Consent to Jurisdiction and Service

Under the Indenture, TransAlta irrevocably appoints CT Corporation System, 28 Liberty Street, New York, New York 10005, as its authorized agent for service of process in any suit or proceeding arising out of or relating to the debt securities or the Indenture and for actions brought under federal or state securities laws in any federal or state court located in the City of New York, and irrevocably submits to such jurisdiction (Section 1.13).

Governing Law

The debt securities and the Indenture will be governed by and construed in accordance with the laws of the State of New York (Section 1.11).

PRIOR SALES

Prior sales will be provided as required in a Prospectus Supplement with respect to the issuance of Securities pursuant to such Prospectus Supplement.

MARKET FOR SHARES

Trading prices and volume will be provided as required in a Prospectus Supplement with respect to the issuance of Securities pursuant to such Prospectus Supplement.

CERTAIN INCOME TAX CONSIDERATIONS

The applicable Prospectus Supplement may describe certain Canadian and United States federal income tax consequences generally applicable to investors described therein with respect to the acquisition, ownership and disposition of any Securities offered thereunder.

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SELLING SHAREHOLDER

The terms under which the Common Shares will be offered by the Selling Shareholder will be described in the applicable Prospectus Supplement. The Prospectus Supplement for or including any offering of Common Shares by the Selling Shareholder will include, without limitation, where applicable: (i) the name of the Selling Shareholder; (ii) the number of Common Shares owned, controlled or directed by the Selling Shareholder; (iii) the number of Common Shares being distributed for the account of the Selling Shareholder; (iv) the number of Common Shares to be owned, controlled or directed by the Selling Shareholder after the distribution and the percentage that number or amount represents out of the total number of outstanding Common Shares; (v) whether the Common Shares are owned by the Selling Shareholder, both of record and beneficially, of record only or beneficially only; (vi) if the Selling Shareholder purchased any of the Common Shares held by it in the 24 months preceding the date of the Prospectus Supplement, the date or dates on which the Selling Shareholder acquired the Common Shares; and (vii) if the Selling Shareholder acquired the Common Shares held by it in the 12 months preceding the date of the Prospectus Supplement, the cost thereof to the Selling Shareholder in the aggregate and on a per security basis.

Registration Rights Agreement

The following is a summary of certain material provisions of the registration rights agreement entered into between Eagle Hydro II (an affiliate of Brookfield) and the Corporation on May 1, 2019 (the “Registration Rights Agreement”) and is to be read together with the Registration Rights Agreement, a copy of which can be found on SEDAR under our profile at www.sedar.com.

The Registration Rights Agreement provides that Eagle Hydro II and any affiliate of Brookfield that becomes party to the Registration Rights Agreement (each a “Holder”) may, at any time and from time to time, make a written request (a “Demand Registration”) to the Corporation to file a Prospectus Supplement with the Alberta Securities Commission and the SEC pursuant to the multijurisdictional disclosure system between the United States and Canada in respect of the distribution of all or part of the Common Shares then held by the Holder (“Registrable Securities”), subject to certain restrictions set forth in the Registration Rights Agreement. Upon receipt by the Corporation of a Demand Registration, the Corporation will promptly file a Prospectus Supplement in order to permit the offer and sale or other disposition or distribution in the United States of all or any portion of the Registrable Securities held, directly or indirectly, by the Holder (a “Demand Offering”). The Corporation will not be obligated to effect: (i) more than three Demand Offerings in total during the term of the Registration Rights Agreement; or (ii) a Demand Offering if the Registrable Securities have an aggregate market price of less than $50 million.

If at any time the Corporation proposes to file a Prospectus Supplement with respect to the distribution of any Common Shares to the public, then the Corporation will give notice of the proposed distribution to each Holder not less than five business days in advance of the anticipated filing date of the Prospectus Supplement ( or, in the case of a “bought deal” or another public offering which is not expected to include a road show, such notice as is practicable under the circumstances), which notice will offer each Holder the opportunity to qualify for distribution such number of Registrable Securities as such Holder may request. The Corporation will use commercially reasonable efforts to include in such Prospectus Supplement such Registrable Securities (a “Piggy Back Offering”), unless the Corporation’s managing underwriter or underwriters determine, in good faith, that including such Registrable Securities in the distribution would, in their opinion, adversely affect the Corporation’s distribution or sales price of the Securities being offered by the Corporation.

The Demand Offerings and Piggy Back Offerings are subject to various conditions and limitations. The Corporation is entitled to defer any Demand Offering in certain circumstances, including during a regular annual and quarterly blackout period in respect of the release of its financial results.

The Registration Rights Agreement includes provisions providing for each of the Corporation and the Holders to indemnify each other for losses or claims caused by the applicable party’s inclusion of a misrepresentation in disclosure included in any prospectus and for breaches of applicable securities laws.

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In the case of a Prospectus Supplement filed in connection with a Demand Offering or Piggy Back Offering, the Corporation will pay all applicable fees and expenses incident to the Corporation’s performance of, or compliance with, the terms of such offering, provided that in the event any Registrable Securities are freely tradeable at the time that the Corporation receives the offering request, the Corporation and the Holders will be jointly and severally responsible for the proportionate share of registration fees and expenses of any Holders based on the total offering price of the freely tradeable securities sold by the Holders to the total offering price of all the Securities sold by the Corporation in such offering. The Corporation and the Holders will be jointly and severally responsible for paying all selling expenses (including fees or commissions payable to an underwriter, investment banker, manager or agent and any transfer taxes attributable to the sale of Registrable Securities) with respect to Registrable Securities sold by the Holders and the Corporation will pay all selling expenses with respect to any Securities sold for the account of the Corporation. The Corporation and the Holders will be solely responsible on a joint and several basis for all out-of- pocket expenses incurred by any Holders in connection with a Demand Offering or Piggy Back Offering.

If a Holder ceases to be affiliated with the Corporation, the Holder will cease to have any rights or obligations under the Registration Rights Agreement. The Registration Rights Agreement will terminate when Brookfield together with its affiliates beneficially own in the aggregate less than 3% of the issued and outstanding Common Shares.

PLAN OF DISTRIBUTION

We may sell the Securities and the Selling Shareholder may, in accordance with the terms of the Registration Rights Agreement, sell Common Shares, to or through one or more underwriters or dealers and also may sell the Securities directly to one or more purchasers or through agents.

The distribution of the Securities may be effected from time to time in one or more transactions at a fixed price or prices or at non-fixed prices. If offered on a non-fixed price basis the Securities may be offered at market prices prevailing at the time of sale, at prices related to such prevailing market prices or at prices to be negotiated with purchasers, in which case the price at which the Securities will be offered and sold may vary from purchaser to purchaser and during the distribution period.

In connection with the sale of the Securities, underwriters may receive compensation from TransAlta, the Selling Shareholder or from purchasers of the Securities for whom they may act as agents in the form of concessions or commissions. Underwriters, dealers and agents that participate in the distribution of the Securities may be deemed to be underwriters and any commissions received by them from TransAlta and/or the Selling Shareholder and any profit on the resale of the Securities by them may be deemed to be underwriting commissions.

The Prospectus Supplement relating to any Securities being offered will set forth the terms of the offering of those Securities, including, to the extent applicable, the initial offering price of, and form of consideration for, those Securities and the proceeds to us and/or the Selling Shareholder from such sale, the name or names of any underwriters, dealers or other placement agents, the underwriting concessions or commissions, and any other discounts, commissions or concessions to be allowed or re-allowed or paid to dealers and any securities exchanges on which those Securities may be listed. Only underwriters named in a Prospectus Supplement are deemed to be underwriters in connection with the Securities offered by that Prospectus Supplement.

Without limiting the generality of the foregoing, we also may issue Securities in exchange for property, including for other securities issued by us or for securities or assets of other companies that we may acquire in the future.

The Securities offered hereby have not been qualified for sale under the securities laws of any province or territory of Canada (other than the Province of Alberta) and will not be offered or sold in Canada or to any

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resident of Canada. Each underwriter, dealer or agent engaged by us in the distribution of any Securities offered hereby will agree that it will not, to the best of that underwriter’s, dealer’s or agent’s, as applicable, knowledge, after reasonable inquiry, distribute any such Securities under this Prospectus to a purchaser resident in Canada.

Under agreements which may be entered into by TransAlta and/or the Selling Shareholder, underwriters, dealers and agents who participate in the distribution of the Securities may be entitled to indemnification by the Corporation and/or the Selling Shareholder against certain liabilities, including liabilities under the U.S. Securities Act, or to contributions with respect to payments which such underwriters, dealers or agents may be required to make in respect thereof.

RISK FACTORS

Prospective purchasers of the Securities should consider carefully the risk factors and the other information contained and incorporated by reference in this Prospectus and the applicable Prospectus Supplement before purchasing the Securities offered hereby. Information regarding the risks affecting TransAlta and its business are provided in certain documents incorporated by reference in this Prospectus, including the Annual MD&A under the heading “Governance and Risk Management”, the Annual Information Form under the heading “Risk Factors” (or, as applicable, our annual information form and our management’s discussion and analysis for subsequent periods). See “Documents Incorporated by Reference”. These are not the only risks and uncertainties that we face. Additional risks not presently known to us or that we currently consider immaterial may also materially and adversely affect us. If any of the events identified in these risks and uncertainties were to actually occur, our business, financial condition or results of operations could be materially harmed.

LEGAL MATTERS

Unless otherwise specified in the Prospectus Supplement relating to the Securities, certain legal matters relating to Canadian law and United States law in connection with the offering of Securities will be passed upon on behalf of TransAlta by Osler, Hoskin & Harcourt LLP.

EXPERTS

The audited consolidated statements of financial position of the Corporation as at December 31, 2020 and 2019 and the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each year in the three-year period ended December 31, 2020 have been incorporated by reference herein and in the registration statement in reliance upon the reports of Ernst & Young LLP, Chartered Professional Accountants, incorporated by reference herein, and given the authority of said firm as experts in accounting and auditing.

INTEREST OF EXPERTS

In connection with the audit of our Annual Financial Statements, Ernst & Young LLP confirmed that they are independent with respect to TransAlta in the context of the Rules of Professional Conduct of the Institute of Chartered Professional Accountants of Alberta and in compliance with Rule 3520 of the Public Company Accounting Oversight Board.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Common Shares and our outstanding First Preferred Shares, other than Series I, in Canada is AST Trust Company (Canada) at its principal transfer offices in Calgary, Alberta, and Toronto, Ontario. The transfer agent and registrar for the Common Shares in the United States is Computershare Trust Company at its principal office in Canton, Massachusetts.

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DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT

The following documents have been filed with the SEC either separately or as exhibits to the registration statement on Form F-10 of which this Prospectus forms a part: the documents listed herein under “Documents Incorporated by Reference” and “Certain Available Information”; the consent of Ernst & Young LLP, Chartered Professional Accountants; certain powers of attorney; the Indenture; and the statement of eligibility of the trustee on Form T-1.

ENFORCEMENT OF CERTAIN CIVIL LIABILITIES

TransAlta is a corporation existing under the laws of Canada, and the majority of our assets and operations are located, and the majority of our revenues are derived, outside the United States. We have appointed our U.S. subsidiary, TransAlta Centralia Generation LLC, Centralia, Washington, as our agent to receive service of process in the United States in connection with any investigations or administrative proceeding conducted by the SEC and any civil suit or action brought against or involving TransAlta in a United States court arising from any offering of Securities made under the registration statement on Form F-10 of which this Prospectus forms a part. However, it may not be possible for investors to enforce, outside the United States, judgments against TransAlta obtained in the United States in any such actions, including actions predicated upon the civil liability provisions of United States federal or state securities laws. In addition, certain of the directors and officers of TransAlta are residents of Canada or other jurisdictions outside of the United States, and all or a substantial portion of the assets of those directors and officers are or may be located outside the United States. As a result, it may not be possible for investors to effect service of process within the United States upon those persons or to enforce, outside the United States, judgments against them obtained in United States courts, including judgments predicated upon the civil liability provisions of United States federal or state securities laws. In addition, there is substantial doubt whether an action could be brought in Canadian courts in the first instance on the basis of liability predicated solely upon United States federal or state securities laws.

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US$400,000,000

7.750% Senior Notes due 2029

TransAlta Corporation

PROSPECTUS SUPPLEMENT

RBC Capital Markets

CIBC Capital Markets

BofA Securities

Scotiabank

BMO Capital Markets

TD Securities

National Bank of Canada Financial Markets

MUFG

Desjardins Capital Markets

ATB Capital Markets

Mizuho

Loop Capital Markets

US$400,000,000

November 14, 2022