40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F

[Check one]

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

OR

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

 

For the fiscal year ended Dec. 31, 2023 Commission file number 001-15214

TRANSALTA CORPORATION

(Exact name of Registrant as specified in its charter)

Not applicable

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

Canada

(Province or other jurisdiction of incorporation or organization)

4911

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

Not Applicable

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

1400, 1100 - 1st Street S.E.,

Calgary, Alberta, Canada, T2G 1B1,

(403) 267-7110

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

TransAlta Centralia Generation LLC

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

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

of agent for service in the United States)

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

 

Title of each class	Trading Symbols	Name of each exchange
		on which registered
Common Shares, no par value	TAC	New York Stock Exchange
Common Share Purchase Rights	TAC	New York Stock Exchange

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

None

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

Debt Securities

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

 

☒        Annual information form ☒        Audited annual financial statements

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

At Dec. 31, 2023, 306,933,951 common shares were issued and outstanding.

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

 

Yes  x No  o

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

 

Yes  x No  o

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

Emerging growth company ☐

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements  of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ¨

Indicate by check mark whether any of those error corrections are restatements that require a recovery analysis of incentive-based compensation received by an of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ¨

INCORPORATION BY REFERENCE

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

 

Form	Registration No.
S-8	333-72454
S-8	333-101470
S-8	333-236894
S-8	333-260935
F-10	333-271953

CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS

AND MANAGEMENT’S DISCUSSION & ANALYSIS

A.                                             Consolidated Audited Annual Financial Statements

For consolidated audited annual financial statements for the year ended Dec. 31, 2023, including the report of independent chartered professional accountants with respect thereto, see Exhibit 13.3 incorporated by reference herein.

B.                                              Management’s Discussion and Analysis

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

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DISCLOSURE CONTROLS AND PROCEDURES

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

Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of Dec. 31, 2023, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

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

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

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

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

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

Management evaluated the effectiveness of our internal control over financial reporting as of Dec. 31, 2023 using the Committee of Sponsoring Organizations of the Treadway Commission (COSO) 2013 framework.  Management concluded that our internal control over financial reporting was effective as of Dec. 31, 2023.  Certain matters relating to the scope of management’s evaluation

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and limitations of management’s conclusions are described below.  See “Limitations and Scope of Management’s Report on Internal Control over Financial Reporting.”

Our Chartered Professional Accountants, Ernst & Young LLP, has issued an attestation report on the effectiveness of our internal control over financial reporting as of Dec. 31, 2023 (PCAOB 1263). For the Report of Independent Registered Public Accounting Firm see page F3 of the Consolidated Audited Annual Financial Statements for the year ended Dec. 31, 2023, filed as Exhibit 13.3 and incorporated by reference herein, under the heading “Report of Independent Registered Public Accounting Firm - Public Company Accounting Oversight Board (United States) (“PCAOB”)".

There has been no change in our internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

LIMITATIONS AND SCOPE OF MANAGEMENT’S

REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

The 2023 consolidated financial statements of TransAlta, in accordance with EITF 00-1, included for joint operations and equity accounted investments are three per cent and 12 per cent of the Company's total and net assets, respectively, as of Dec. 31, 2023, and seven per cent and 16 per cent of the Company's revenues and net earnings, respectively, for the year then ended. Once the financial information is obtained from these Excluded Entities it falls within the scope of TransAlta’s internal control framework.

AUDIT COMMITTEE FINANCIAL EXPERT

TransAlta’s board of directors has determined that each member of the Audit, Finance and Risk Committee (the “AFRC”) is an audit committee financial expert. Mr. Alan J. Fohrer, Ms. Candace J. MacGibbon, Mr. Thomas M. O'Flynn, Mr. Bryan D. Pinney and Ms. Manjit K. Sharma have each been determined to be an audit committee financial expert, within the meaning of Section 407 of

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the United States Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”), and are independent, as that term is defined by the New York Stock Exchange’s (“NYSE”) listing standards applicable to TransAlta. For further information regarding the experience and qualification of Mr. Fohrer, Ms. MacGibbon, Mr. O'Flynn, Mr. Pinney and Ms. Sharma, see the section titled “Audit, Finance and Risk Committee” in our Annual Information Form for the year ended Dec. 31, 2023, filed as Exhibit 13.1 and incorporated by reference herein. Under the Commission rules, the designation of persons as audit committee financial experts does not make them “experts” for any other purpose, impose any duties, obligations or liability on them that are greater than those imposed on members of their committee and the board of directors who do not carry this designation or affect the duties, obligations or liability of any other member of their committee.

CODE OF ETHICS

TransAlta has adopted a code of ethics as part of its “Corporate Code of Conduct” that applies to all employees and officers which has been filed with the Commission. In addition, TransAlta has adopted a code of conduct applicable to all directors of the Company, a separate financial code of conduct which applies to all financial management employees and an Energy Trading code of conduct for our employees working within energy marketing. Our codes of conduct are available on our Internet website at www.transalta.com. There has been no waiver of the codes granted during the 2023 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended Dec. 31, 2023 and Dec. 31, 2022, Ernst & Young LLP and its affiliates billed or expect to bill, including out-of-pocket costs, $4,476,201 and $4,996,925, respectively, as detailed below:

Ernst & Young LLP

 

Year Ended Dec. 31	2023		2022
Audit Fees	$	3,206,475	$	3,175,932
Audit-related fees(1)	1,224,851		1,754,943
Tax fees	5,850		66,050
All other fees	39,025		—
Total	$	4,476,201	$	4,996,925

(1) Included in the audit-related fees are $354,570 (2022 - $$1,040,296 ) of fees billed to TransAlta Renewables.

All amounts are in Canadian dollars unless otherwise stated.

No other audit firms provided audit services in 2023 or 2022.

The nature of each category of fees is described below:

Audit Fees

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

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Audit-Related Fees

Assurance and related services that are reasonably related to the performance of the audit or review of our financial statements that are not included under "Audit Fees". Audit-Related fees include statutory audits, pension audits and other compliance audits. In 2023 and 2022, we have included the fees billed to TransAlta Renewables, a controlled and consolidated subsidiary of TransAlta.

Tax Fees

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

All Other Fees

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

Pre-Approval Policies and Procedures

The AFRC has considered whether the provision of services other than audit services is compatible with maintaining the auditors’ independence.  In May 2002, the AFRC adopted a policy that prohibits TransAlta from engaging the auditors for “prohibited” categories of non-audit services and requires pre-approval of the AFRC for other permissible categories of non-audit services, such categories being determined under the Sarbanes-Oxley Act of 2002. This policy also provides that the Chair of the AFRC may approve permissible non-audit services during the quarter and report such approval to the AFRC at its next regularly scheduled meeting.

Percentage of Services Approved by the AFRC

For the year ended Dec. 31, 2023, none of the services described above were approved by the AFRC pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

OFF-BALANCE SHEET ARRANGEMENTS

TransAlta currently has no off-balance sheet arrangements.  See page M44 of Exhibit 13.2, incorporated by reference herein under the heading “Unconsolidated Structured Entities or Arrangements”.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

See page M44 of Exhibit 13.2, incorporated by reference herein, under the heading “Other Consolidated Analysis” and page F94 under the heading “Commitments and Contingencies” of Exhibit 13.3, all incorporated by reference herein.

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IDENTIFICATION OF THE AUDIT COMMITTEE

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

Bryan D. Pinney (Chair)

Alan J. Fohrer

Candace J. MacGibbon

Thomas M. O'Flynn

Manjit K. Sharma

MINE SAFETY

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

FORWARD-LOOKING INFORMATION

This Form 40-F (the "Form 40-F"), including the documents incorporated herein by reference, includes "forward-looking information," within the meaning of applicable Canadian securities laws, and "forward-looking statements," within the meaning of applicable United States securities laws, including the 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 those set out in or implied by the forward-looking statements.

In particular, this Form 40-F (or a document incorporated herein by reference) contains forward-looking statements including, but not limited to, statements relating to: the acquisition of Heartland (as defined below) and its entire business operations in Alberta and British Columbia, including closing conditions and regulatory approvals pursuant to the Heartland acquisition and the anticipated timing and completion of the acquisition; the annual average earnings before interest, taxes, depreciation and amortization ("EBITDA") to be generated from the Heartland acquisition and other benefits expected to arise from such transaction; the Company’s 2024 Outlook, including adjusted EBITDA, free cash flow, annualized dividend per share, sustaining capital and energy marketing gross margin; the Company’s expanded growth targets to deliver 1.75 GW with a target investment of $3.5 billion by 2028 which is anticipated to deliver annual EBITDA of $350 million; the expansion of the Company's development pipeline to 10 GW by 2028; the Company’s investment strategy to deliver long-term value to shareholders; the common share dividend level through 2024; the Company's projects under construction, including capital costs, the timing of commercial operations and expected annual EBITDA; the impact of new asset additions in 2024 of Garden Plain, Northern Goldfields solar, Kent Hills, Mount Keith transmission, White Rock and Horizon Hill; the development of the early-stage and advanced-stage projects; achieving the anticipated benefits of the transfer of Production Tax Credits generated from the White Rock and Horizon Hill wind projects; executing growth with Hancock under the Joint

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Development Agreement; the proportion of EBITDA to be generated from renewable sources to increase to 70 per cent by the end of 2028; the Company’s ability to achieve its long-term decarbonization goal to be net zero by 2045; the reduction of carbon emissions by 75 per cent from 2015 emissions levels by 2026; the expected impact and quantum of carbon compliance costs; regulatory developments and their expected impact on the Company; expectations regarding refinancing debt; and the Company continuing to maintain adequate liquidity.

The forward-looking statements contained in this Form 40-F (or a document incorporated herein by reference) are based on many assumptions including, but not limited to, the following: 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 long-term investment and credit markets; no significant changes to power price and hedging assumptions, including hedged volumes and prices; no significant changes to gas commodity prices and transport costs; no significant changes to decommissioning and restoration costs; no significant changes to interest rates; no significant changes to the demand and growth of renewables generation; no significant changes to the integrity and reliability of our assets; and no significant changes to the Company's debt and credit ratings.

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 Form 40-F (or a document incorporated herein by reference) include risks relating to: fluctuations in power prices, including merchant pricing in Alberta, Ontario and Mid-Columbia; failure or delay in closing the Heartland acquisition; failure to realize the benefits of the Heartland acquisition, including the inability to advance the Battle River Carbon Hub Project to final investment decision or commercial operation, and any loss of value in the Heartland portfolio during the interim period prior to closing; reductions in production; restricted access to capital and increased borrowing costs, including any difficulty raising debt, equity or tax equity, as applicable, on reasonable terms or at all; labour relations matters, reduced labour availability and the ability to continue to staff our operations and facilities; reliance on key personnel; disruptions to our supply chains, including our ability to secure necessary equipment; force majeure claims; our ability to obtain regulatory and any other third-party approvals on the expected timelines or at all in respect of our growth projects; long-term commitments on gas transportation capacity that may not be fully utilized over time; adverse financial impacts arising from the Company's hedged position; risks associated with development and construction projects, including as it pertains to increased capital costs, permitting, labour and engineering risks, disputes with contractors and potential delays in the construction or commissioning of such projects; significant fluctuations in the Canadian dollar against the US dollar and Australian dollar; changes in short-term and long-term electricity supply and demand; counterparty credit risk and any higher rate of losses on our accounts receivables; inability to achieve our environmental, social and governance ("ESG") targets; the impact of the energy transition on our business; impairments and/or writedowns of assets; adverse impacts on our information technology systems and our internal control systems, including 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; our ability to contract our generation for prices that will provide expected returns and to 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 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, coal, 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; failure to meet financial expectations; general domestic and international economic and political developments, including armed hostilities, the threat of terrorism, adverse diplomatic developments or other similar events; industry risk and competition in the business in which we operate; structural subordination of securities; public

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health crisis risks; inadequacy or unavailability of insurance coverage; our provision for income taxes and any risk of reassessment; and legal, regulatory and contractual disputes and proceedings involving the Company.

The foregoing risk factors, among others, are described in further detail in the "Governance and Risk Management" section of our Management Discussion and Analysis for the year ended Dec. 31, 2023, filed as Exhibit 13.2.

Readers are urged to consider these factors carefully when 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.

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UNDERTAKING

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

CONSENT TO SERVICES OF PROCESS

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

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EXHIBIT INDEX

13.1	TransAlta Corporation Annual Information Form for the year ended Dec. 31, 2023
13.2	Management’s Discussion and Analysis for the year ended Dec. 31, 2023
13.3	Consolidated Audited Annual Financial Statements for the year ended Dec. 31, 2023
13.4	Management’s Annual Report on Internal Control over Financial Reporting (included on page F2 of Exhibit 13.3 filed herewith)
23.1	Consent of Independent Registered Public Accounting Firm
31.1	Certification of President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification of President and Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
97	Executive Compensation Clawback Policy
101	Interactive Data File (formatted as Inline XBRL)
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURES

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

 

	TRANSALTA CORPORATION
	/s/ Todd J. Stack
	Todd J. Stack
	Executive Vice-President, Finance and Chief Financial Officer
Dated: February 22, 2024

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EX-13.1

Contents

2	Presentation of Information
2	Special Note Regarding Forward-Looking Statements
4	Documents Incorporated by Reference
4	Corporate Structure
7	Overview
12	General Development of the Business
20	Business of TransAlta
42	Environmental Risk Management
46	Risk Factors
63	Employees
64	Capital and Loan Structure
79	Credit Ratings
82	Dividends
85	Market for Securities
92	Directors and Officers
102	Interests of Management and Others in Material Transactions
102	Indebtedness of Directors, Executive Officers and Senior Officers
102	Corporate Cease Trade Orders, Bankruptcies or Sanctions
103	Material Contracts
103	Conflicts of Interest
103	Legal Proceedings and Regulatory Actions
105	Transfer Agent and Registrar
105	Interests of Experts
105	Additional Information
105	Audit, Finance and Risk Committee
A- 1	Audit, Finance and Risk Committee Charter
B- 1	Glossary of Terms

Presentation of Information

The information contained in this Annual Information Form ("AIF") is given as of or for the year ended Dec. 31, 2023, unless otherwise noted. All dollar amounts are in Canadian dollars, unless otherwise noted. All references to the "Company" and to "TransAlta", "we", "our" and "us" refers to TransAlta Corporation and its subsidiaries, including TransAlta Renewables Inc., on a consolidated basis. Reference to "TransAlta Corporation" refers to TransAlta Corporation, including its subsidiaries. Capitalized terms not defined in the body of this AIF are defined in Appendix "B" – Glossary of Terms contained .

Special Note Regarding Forward-Looking Statements

This AIF, including the documents incorporated herein by reference, includes "forward-looking information," within the meaning of applicable Canadian securities laws, and "forward-looking statements," within the meaning of applicable United States securities laws, including the 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, and 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 those set out in or implied by the forward-looking statements.

In particular, this AIF (or a document incorporated herein by reference) contains forward-looking statements including, but not limited to: global trends for decarbonization, including the cost of carbon, cost effective technologies for storage, hydrogen and carbon capture, and customer demand; the role of natural gas generation in maintaining affordability and reliability in each of TransAlta's core markets; anticipated evolution of the Alberta merchant market; TransAlta's ability to execute its strategy, including meeting customer needs, achieving operational excellence, increasing shareholder value and delivering stable and predictable cash flows; TransAlta’s priorities to 2028, including optimizing the Alberta portfolio, maintaining financial strength and capital allocation discipline, defining the next generation of power solutions and leading environmental, social and governance ("ESG") and market policy; emissions reductions, including reducing emissions (scope 1 and 2) by 75 per cent below 2015 levels by 2026, achieving net-zero by 2045 and ending coal generation by 2025; TransAlta’s ability to execute its sustainability targets, including 80 per cent of procurement spend to be with suppliers committed to sustainability, 40 per cent company-wide female employment by 2030, and 50 per cent female Board representation by 2030; TransAlta’s acquisition of Heartland Generation Ltd. and Alberta Power (2000) Ltd. (collectively, “Heartland”), including the ability to obtain regulatory approval, the timing thereof, and the anticipated benefits arising from the transaction; the Alberta portfolio strategy and priorities, including optimizing value from the diversified fleet; the energy marketing business' ability to deliver value with low risk; expected earnings before interest, taxes, depreciation and amortization ("EBITDA") contribution from TransAlta's Energy Marketing segment; the ability to execute the updated Clean Electricity Growth Plan targets, including delivering up to an incremental 1.75 GW of clean electricity capacity, a 10 GW pipeline, deploying approximately $3.5 billion of growth capital, and achieving cumulative annual EBITDA from new growth projects of $350 million, in each case to 2028; the Company's future growth pipeline, including the timing of commercial operations and the costs of the advanced and early-stage projects; the ability to pursue and execute joint development projects with Hancock Prospecting; ability to proceed to construction and operation of the Company’s advanced development projects, including WaterCharger, Pinnacle and the Mount Keith Expansion, and the timing thereof and the expected EBITDA contribution thereof; the source of funding for the updated Clean Electricity Growth Plan; our transformation, growth and capital allocation; future growth opportunities; growth in renewables and on-site and cogeneration assets, including the timing of commercial operations such as the White Rock wind project, Horizon Hill wind project and Mount Keith transmission expansion; the ability to realize future growth opportunities with BHP (as defined below); the proportion of

TransAlta Corporation • Annual Information Form        2

EBITDA to be generated from renewable sources by the end of 2025, including the announced 800 MW of new renewable generation; the ability of the Company to realize benefits from Canadian, American and Australian regulatory developments, including receiving funding for clean electricity projects; the potential increase in value of emissions reduction credits; the cyclicality of the business, including as it relates to maintenance costs, production and loads; expectations regarding refinancing debt as it matures; and the Company continuing to maintain a strong financial position and significant liquidity.

The forward-looking statements contained in this AIF (or a document incorporated herein by reference) 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 unexpected delays in obtaining required regulatory approval; no material adverse impacts to long-term investment and credit markets; no significant changes to power price and hedging assumptions; no significant changes to gas commodity price assumptions and transport costs; no significant changes to decommissioning and restoration legislation or regulations; no significant changes to interest rates; no significant changes to the demand and growth of renewables generation; no significant changes to the integrity and reliability of our assets; no significant changes to the Company's debt and credit ratings; no unforeseen changes to economic and market conditions; no significant event occurring outside the ordinary course of business. These assumptions are based on information currently available to TransAlta, including information obtained from third-party sources. Actual results may differ materially from those predicted by such forward-looking information. While TransAlta does not know what impact any of these differences may have, TransAlta's business, results of operations, financial condition and credit stability may be materially adversely affected if any such differences occur.

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 AIF (or a document incorporated herein by reference) include, but are not limited to: fluctuations in power prices, including lower merchant pricing in Alberta, Ontario and Mid-Columbia; changes in demand for electricity and capacity; our ability to contract our electricity generation for prices that will provide expected returns; our ability to replace contracts as they expire; risks associated with development projects and acquisitions, including capital costs, permitting, land rights, engineering risks, and delays in the construction or commissioning of projects, including as it pertains to the White Rock and Horizon Hills wind projects; risks relating to our early stage development projects, including interconnection, offtake contracts and geotechnical and environmental conditions of such projects; any difficulty raising needed capital in the future, including debt, equity and tax equity, as applicable, on reasonable terms or at all; our ability to achieve our targets relating to ESG (as defined below); long term commitments on gas transportation capacity that may not be fully utilized over time; our ability to replace or renew contracts as they expire; failure or delay in closing the Heartland acquisition, including the inability to obtain regulatory approvals necessary for the acquisition of Heartland on terms satisfactory to TransAlta or at all; 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; restricted access to capital and increased borrowing costs; changes in short-term and/or long-term electricity supply and demand; reductions in production; a higher rate of losses on our accounts receivables due to credit defaults; impairments and/or writedowns 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; 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 and to obtain regulatory approvals on the expected timelines or at all in respect of our growth projects; 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, coal, 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, adverse diplomatic developments or other similar events; equipment failure and our ability to carry out or have completed repairs in a cost-effective manner or timely manner or at all;

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industry risk and competition; public health crises and the impacts of any restrictive directives of government and public health authorities; fluctuations in the value of foreign currencies; structural subordination of securities; counterparty credit risk; inadequacy or unavailability of insurance coverage; increases in Company's income taxes and any risk of reassessments; 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 under the heading "Risk Factors" in this AIF or in a document incorporated herein by reference, including our Management's Discussion and Analysis for the year ended Dec. 31, 2023.

Readers are urged to consider these factors carefully when evaluating the forward-looking statements and are cautioned not to place undue reliance on them, which reflect the Company's expectations only as of the date hereof. The forward-looking statements included in this AIF 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 (including as may be incorporated by reference) 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.

Non-IFRS Financial Measures

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-International Financial Reporting Standards (IFRS), and therefore are unlikely to be comparable to similar measures presented by other companies and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. In addition, TransAlta cautions the reader that information provided in this AIF regarding the Company's outlook on certain matters, including EBITDA, adjusted EBITDA and free cash flow are provided to give context to the nature of some of the Company's future plans and may not be appropriate for other purposes. Refer to the "Non-IFRS Financial Measures" section of our Management's Discussion and Analysis for the year ended Dec. 31, 2023, for more information, which is specifically incorporated by reference in this AIF. Refer to the section under the heading "Documents Incorporated by Reference" of this AIF for more information.

Documents Incorporated by Reference

The Company's audited consolidated financial statements for the year ended Dec. 31, 2023, and related annual Management's Discussion and Analysis (the "2023 Integrated Report"), are hereby specifically incorporated by reference in this AIF. Copies of these documents are available on SEDAR+ at www.sedarplus.ca and EDGAR at www.sec.gov.

Corporate Structure

Name and Incorporation

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

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Effective Jan. 1, 2009, we completed a reorganization, whereby the assets and business affairs of TAU and TransAlta Energy Corporation ("TransAlta Energy") (with the exception of the wind business) were transferred to TransAlta Generation Partnership, a then new Alberta general partnership, whose partners are the Company and TransAlta Generation Ltd., a wholly owned subsidiary of TransAlta. TransAlta Generation Partnership is managed by TransAlta Corporation pursuant to the terms of a partnership agreement and a management services agreement. Immediately following the transfer of assets by TAU and TransAlta Energy to TransAlta Generation Partnership, TransAlta Corporation amalgamated with TAU, TransAlta Energy and Keephills 3 GP Ltd. pursuant to the provisions of the CBCA. Effective June 1, 2023, TransAlta Corporation amalgamated with its wholly owned subsidiary TransAlta Investment Ltd. On Oct. 5, 2023, TransAlta Corporation acquired all of the outstanding common shares of TransAlta Renewables Inc. ("TransAlta Renewables") not already owned, directly or indirectly, by the Company.

We amended our articles on Dec. 7, 2010, to create the Series A Shares and Series B Shares; again on Nov. 23, 2011, to create the Series C Shares and Series D Shares; again on Aug. 3, 2012, to create the Series E Shares and Series F Shares; and again on Aug. 13, 2014, to create the Series G Shares and Series H Shares. We further amended our articles on Oct. 1, 2020, to create the Series I Shares, a new series of redeemable, retractable first preferred shares that were issued to an affiliate of Brookfield Renewable Partners ("Brookfield") in October 2020. See the "Capital and Loan Structure – Exchangeable Securities" section of this AIF.

Our registered and head office is located at TransAlta Place, Suite 1400, 1100 1st Street SE, Calgary, Alberta, Canada, T2G 1B1.

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Our Subsidiaries

As of Dec. 31, 2023, our principal subsidiaries and their respective jurisdictions of formation are set out in the organization chart below. The Company’s remaining subsidiaries and partnerships each account for (i) less than 10 per cent of the Company’s consolidated assets as at Dec. 31, 2023 and (ii) less than 10 per cent of the Company’s consolidated revenues for the year ended Dec. 31, 2023. In aggregate, TransAlta’s subsidiaries and partnerships not listed below did not exceed 20 per cent of the Company’s total consolidated assets or total consolidated revenues as at and for the year ended Dec. 31, 2023.

(1)    Unless otherwise stated, ownership is 100 per cent.

(2)    The remaining 0.01 per cent of TEC Limited Partnership is owned by TransAlta (Ft. McMurray) Ltd, a wholly owned subsidiary of the Company.

(3) The remaining 0.01 per cent of Keephills 3 Limited Partnership is owned by Vision Quest WindElectric Ltd., a wholly owned subsidiary of the Company.

(4) The remaining 0.01 per cent of TA Alberta Hydro LP is owned by TA Alberta Hydro Inc., a wholly owned subsidiary of the Company.

(5) The remaining 0.01 per cent of MW Intermediary LP is owned by MW Intermediary Inc., a wholly owned subsidiary of Canadian Hydro Developers, Inc.

(6) The remaining 0.01 per cent of Melancthon Wolfe Wind LP is owned by Melancthon Wolfe Wind Inc., a wholly owned subsidiary of MW Intermediary LP.

(7) The remaining 17.00 per cent of Kent Hills Wind LP is owned Natural Forces Technologies Inc. and the remaining 0.01 percent is owned by by Kent Hills Wind Inc.

(8) The remaining 49.99 per cent of TransAlta Cogeneration LP is owned by CPH Cogen Inc.

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TransAlta Renewables

On Sept. 26, 2023, shareholders of TransAlta Renewables approved a definitive arrangement agreement (the "Arrangement Agreement”) under which TransAlta acquired all of the outstanding common shares of TransAlta Renewables (each, a “RNW Share”) not already owned, directly or indirectly, by TransAlta and certain of its affiliates.

The Arrangement Agreement was approved by the Court of King’s Bench of Alberta on Oct. 4, 2023. The consideration paid totaled $1.3 billion which consisted of $800 million of cash and approximately 46 million common shares of the Company.

On Oct. 5, 2023, the Company announced the completion of the acquisition of TransAlta Renewables pursuant to the terms of the Arrangement Agreement. TransAlta's acquisition of TransAlta Renewables' common shares resulted in TransAlta Renewables becoming a wholly owned subsidiary of the Company. Prior to the Arrangement, TransAlta and its affiliates collectively held 160,398,217 RNW Shares, representing 60.1 per cent of the issued and outstanding RNW Shares, with the remaining 106,510,884 RNW Shares held by TransAlta Renewables shareholders other than TransAlta and its affiliates.

Overview

TransAlta

TransAlta and its predecessors have been engaged in the development, production and sale of electric energy since 1911. We are one of Canada's largest publicly traded power generators and are among Canada's largest non-regulated electricity generation and energy marketing companies with 6,761 megawatts ("MW") of gross installed capacity. We are one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta. We own, operate and manage a highly contracted and geographically diversified portfolio of generation assets that includes water, wind, solar, natural gas, battery storage and transition coal. We also have industry-leading energy marketing capabilities where we seek to maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions. Our energy marketing operations aim to maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions. Our mix of merchant and contracted assets along with our energy marketing business provides cash flows that support our ability to pay dividends to our shareholders and reinvest in growth.

Our Goal

The Company's goal is to be a leading clean electricity company that is committed to a sustainable future and a responsible energy transition. Our strategic priorities include accelerating growth into customer-centred renewables and storage, selectively expanding flexible generation and reliability assets to support the transition, defining the next generation of power solutions and maintaining financial strength and capital allocation discipline. We are primarily focused on opportunities within our core markets of Canada, the US and Western Australia. Our 112-year operating history allows us to apply our expertise, scale and diversified fuel mix to capitalize on opportunities in our core markets and grow in areas where we can employ our competitive advantages.

Our Values

Our values are grounded in safety, innovation, sustainability, respect and integrity, all of which enable us to work towards our common goals. These values are the principles that define our corporate culture. They reflect our skills and mindset while providing a framework for everything we do, guiding both internal conduct and external relationships. These values are at the heart of our success:

•Safety – Safeguard the health and safety of our people, partners and stakeholders.

•Innovation – Develop and embrace innovative solutions to challenges.

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•Sustainability – Reduce the impact of resource use in everything we do.

•Respect – Support our people, our partners, our communities and our environment.

•Integrity – Focus on honesty, transparency and doing what's right.

Our Corporate Strategy

Our strategic focus is to invest in clean electricity solutions that meet the needs of our customers and communities. We invest in a disciplined manner to deliver appropriately risk-adjusted returns to our shareholders, which includes investing in projects that help our customers and our communities meet their environment, social and governance ("ESG") objectives. To support this strategy, we maintain a growing pipeline of project opportunities focused on hydro, wind, solar, energy storage and low-emissions gas generation.

On Nov. 21, 2023, TransAlta updated its Clean Electricity Growth Plan and five-year strategic growth targets. These growth targets include adding up to 1.75 gigawatts ("GW") of new generating capacity to the Company’s fleet by investing approximately $3.5 billion to develop, construct or acquire new assets through 2024 to the end of 2028. The growth will focus on customer-centred renewables and storage through the development of those projects in our current 5.3 GW development pipeline, which we intend to expand to 10 GW by 2028.

The following provides an overview of our Clean Electricity Growth Plan and strategic priorities to 2028:

1. Optimize our Alberta portfolio

We will continue to optimize our existing asset base and maximize the value of our hydro and legacy gas fleet in Alberta. This fleet of assets is well positioned to meet the changing price dynamics of the market and the needs of the province of Alberta. With the acquisition of the Heartland Generation assets (See the "General Development of the Business" section of this AIF for further details), we will diversify and support our Alberta portfolio to deliver fast-responding peaking capacity as the market transitions into a higher concentration of renewables. The acquisition will include almost 400 MW of peaking capacity with a large base of contracted cogeneration assets that have strong and long-term contracts.

2. Execute the Clean Electricity Growth Plan

We are focused on growing our renewable generation capacity and plan to invest approximately $3.5 billion to deliver up to 1.75 GW of incremental renewable generation capacity by the end of 2028. We are targeting that this new capacity, once fully operational, will deliver incremental annual earnings before interest, taxes, depreciation and amortization ("EBITDA") of approximately $350 million.1 We are also targeting to expand the Company's development pipeline to 10 GW by the end of 2028.

3. Selectively expand flexible generation and reliability assets

We are focused on selectively expanding our portfolio offerings in flexible generation and reliability assets, such as peaking generation and short-term and long-term storage, to optimize our portfolio and address the increasing intermittency of renewables generation-based systems. The Company's Clean Electricity Growth Plan may also include efficient and flexible natural gas generation assets that are required to meet system reliability needs and support the addition of new intermittent renewable generation, especially where we can use the knowledge and skill set of our optimization and trading teams to realize additional value.

4. Maintain financial strength and capital allocation discipline

Our strong financial results have created higher operating cash flow that can be allocated to our funding priorities. Higher operating cash flow allows us to allocate more capital to growth, dividends, debt repayment and share repurchases. Our capital allocation is highly flexible, and during periods of limited growth opportunities and share price underperformance we view share repurchases as an opportunity to return capital to shareholders.

1AdjustedEBITDA is a non-IFRS financial measure; see the "Non-IFRS Financial Measures" section of the 2023 Integrated Report for more information.

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5. Define the next generation of power solutions

As we approach net-zero governmental mandates, it is important for TransAlta to be at the forefront of technology innovation to remain competitive and continue to deliver on our commitments to our customers. We have established an internal new technology team that monitors developments in new technologies including storage, hydrogen, fusion, carbon capture and small modular reactors ("SMRs") to assess their potential for deployment over the next decade. We intend to identify and define the next generation of power solutions that will meet the needs of our economy and communities in the second half of this decade and the decade to come.

6. Lead in sustainability and market policy development

Given the ambitious climate goals in all of our geographies, it is imperative that independent power producers ("IPPs"), like TransAlta, actively participate in policy development to ensure that decarbonization, affordability and reliability are properly balanced in order to promote a competitive and effective electricity sector in those geographies.

Our Capital Allocation and Financing Strategy

We are focused on remaining disciplined with our capital investment program and maintaining a strong financial position that provides sufficient capital to execute on our strategy.

Maintaining a strong financial position allows us to contract our portfolio with a variety of counterparties on terms and prices that are favourable to our financial results and provide us with better access to capital markets through commodity and credit cycles. We have an investment-grade BBB (low) credit rating from Morningstar DBRS, a corporate family rating of Ba1 from Moody's with a stable outlook, and S&P Global Ratings reaffirmed the Company’s unsecured debt rating and issuer rating of BB+ with a stable outlook. We believe that we have the ability to execute our Clean Electricity Growth Plan at these rating levels.

Our capital allocation and financing strategy balances the demands associated with meeting our goals around reinvestment, new growth and debt repayments along with providing shareholders an appropriate risk-adjusted return on their capital. Our capital allocation strategy considers sustaining capital, debt repayment, growth, dividend payments and share repurchases.

Our Business Segments

The following is a description of our business segments:

•The Hydro segment has a net ownership interest of approximately 922 MW of owned hydroelectric generating capacity. The facilities within this segment are located in Alberta, British Columbia and Ontario.

•The Wind and Solar segment has a net ownership interest of approximately 2,057 MW of owned wind and solar electrical-generating capacity, as well as battery storage, and includes facilities located in Alberta, Ontario, New Brunswick and Québec; the states of Massachusetts, Minnesota, New Hampshire, North Carolina, Pennsylvania, Washington and Wyoming; and the state of Western Australia. We currently have 500 MW of construction projects underway in this segment that are expected to be completed in 2024.

•The Gas segment has a net ownership interest of approximately 2,775 MW of owned gas electrical-generating capacity and includes facilities located in Alberta, Ontario, Michigan and the state of Western Australia. This segment includes our ownership interest in a natural gas pipeline located in Western Australia.

•The Energy Transition segment has a net ownership interest of approximately 671 MW of owned coal electrical-generating capacity. The segment includes one remaining operating unit at Centralia, the Skookumchuck hydro facility, the retired Centralia unit, retired Alberta thermal units, and the Highvale mine and the mine reclamation activities.

•The Energy Marketing segment is responsible for marketing production through short-term and long-term contracts, for securing cost-effective and reliable fuel supply, and for maximizing margins by optimizing certain assets as market conditions change. Our Energy Marketing segment is actively engaged in the trading of power, natural gas and environmental products across several markets and has allowed us to obtain more

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favourable pricing for uncommitted electricity, secure fuel supply on a cost-effective basis and fulfil electricity delivery obligations in the event of an outage.

•The Corporate segment supports each of the above segments and includes the Company's central finance, legal, human resources, administrative, business development, external affairs and investor relations functions.

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

Our Sustainability Leadership

Sustainability means ensuring that our financial returns consider short- and long-term economic, environmental and societal impacts as well as community needs. As we execute our strategy, our decisions are governed with a view to also delivering on our sustainability objectives. We have a long history of adopting leading sustainability practices, including 30 years of sustainability reporting and also voluntarily integrating our sustainability report into the 2023 Integrated Report. We adopt guidance from the International Sustainability Standards Board by the International Financial Reporting Standards ("IFRS") Foundation, the International Integrated Reporting Framework, the Global Reporting Initiative and the Sustainability Accounting Standards Board requirements for electric utilities and power generators. We continue to monitor the development of sustainability and climate-related disclosure requirements to assess our future reporting, such as the proposed climate-related disclosure rules by the Canadian Securities Administrators, the US Securities and Exchange Commission and the Australian government. Moreover, we align our sustainability targets with the UN Sustainable Development Goals.

Our key sustainability pillars build on our corporate strategy and weave through our entire business. Our track record in these areas illustrates our commitment to sustainability, including climate change leadership, safety and equity, diversity and inclusion ("ED&I"). Our sustainability pillars include:

•Clean, reliable and sustainable electricity production;

•Safe, healthy, diverse and engaged workplace;

•Positive Indigenous, stakeholder and customer relationships;

•Progressive environmental stewardship; and

•Technology and innovation.

In 1990, we were the first Canadian company to purchase carbon offsets and, in 2000, we were an early adopter of wind power generation. At the end of 2021, we no longer generated electricity with coal in Canada and we have also ceased all coal mining operations. Since 2015, we have reduced our scope 1 and 2 greenhouse gas ("GHG") emissions by 66 per cent. In 2023, our GHG emissions (scopes 1 and 2) were 10.9 million tonnes as a result of normal operating activities. We will cease generation from our single remaining US coal unit by the end of 2025, which will further reduce our emissions.

The key components of our sustainability targets include:

•By 2024, verifying and disclosing 80 per cent of TransAlta’s scope 3 emissions;

•By 2024, ensuring 80 per cent of our spend is with suppliers that have a sustainability policy or commitment;

•By 2026, achieving a company-wide reduction in GHG emissions (scope 1 and 2) of 75 per cent below 2015 levels;

•Enhancing our commitment to workplace gender diversity, including our target of 50 per cent representation of women on the board of directors of the Company (the "Board" or the "Board of Directors") by 2030 and a goal of 40 per cent representation of women in our workforce by 2030;

•By 2045, achieving net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions; and

•Continuing to focus on safe operations and environmentally sustainable practices, including undertaking significant reclamation work.

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•Undertaking initiatives that will enhance the environmental performance of the Company, including developing new renewable projects that support our customers' ESG goals to achieve both long-term power price affordability and carbon reductions;

•Supporting equal access to all levels of education for youth and Indigenous Peoples through financial assistance and employment opportunities; and

•Maintaining our commitment to leading ESG disclosures.

From 2000 to 2023, we grew our nameplate renewables capacity from approximately 900 MW to over 2,900 MW. In line with our goal to reduce scope 1 and 2 carbon emissions by 75 per cent from 2015 levels by 2026, we completed coal-to-gas conversions of our Canadian coal-fired facilities in 2021, nine years ahead of Alberta’s legislated coal phase-out plan and retired the remainder of our Canadian coal-fired facilities.

ESG factors are overseen primarily by the Governance, Safety and Sustainability Committee ("GSSC") of the Board of Directors of TransAlta. The GSSC assists the Board of Directors 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.

Our Corporate Code of Conduct sets out expected behaviours of all of our employees and our commitment to creating a work environment where all workers feel safe and are valued for the diversity that they bring to our business. Our Supplier Code of Conduct defines the principles and standards that we expect our suppliers, their employees and contractors to meet while providing goods and services to TransAlta, including but not limited to, environmental and climate-related leadership, ED&I, Indigenous relations, health and safety, ethical business conduct, cybersecurity, conflict of interest, and raising concerns through TransAlta’s Ethics Help Line.

Our Human Rights and Discrimination Policy outlines our commitment to human rights in our operations and supply chain to ensure that our personnel policies and practices in our global operations respect fundamental rights. In Australia, our policies related to the Modern Slavery Act demonstrate the actions that we have taken to assess and address modern slavery risks within our operations and supply chain. In 2024, we will report under Canada’s Fighting Against Forced Labour and Child Labour in Supply Chains Act. Our Indigenous Relations Policy focuses on four key areas: community engagement and consultation, business development, community investment, and employment. We follow TransAlta’s principles for engagement and strive to fulfil our commitments to Indigenous communities.

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. In case of a violation, we will seek to promptly remedy the impact by establishing a corrective action plan in collaboration with the relevant individuals and stakeholders.

Our Total Safety Management Policy formalizes our commitment to protecting the public and our assets, as well as the physical, psychological and social well-being of our people; it defines the personal responsibility of each employee and contractor working on TransAlta's behalf.

Our Environmental Policy defines how we are integrating the protection of nature and the environment within TransAlta’s strategy, our Total Safety Management System, as well as the principles of conduct for the management of natural resources.

Our commitment to ED&I in our workplace and among our co-workers at all levels of the Company is set out in our Board and Workforce Diversity Policy and Diversity and Inclusion Pledge. 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.

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TransAlta's Map of Operations

The following map outlines the Company's operations as of Dec. 31, 2023.

General Development of the Business

Summarized below are significant developments that have occurred in our business segments during the last three financial years. These events include growth, innovation, acquisitions, recontracting, retirement of assets, dispositions, corporate changes, and other events or conditions that have influenced the general development of the Company's business. See the "Business of TransAlta" section of this AIF.

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Three Year History

Growth

Northern Goldfields Solar Achieves Commercial Operation

On Nov. 22, 2023, the Company announced that the 48 MW Northern Goldfields solar and battery storage facilities achieved commercial operation. The facilities consist of the 27 MW Mount Keith solar facility, the 11 MW Leinster solar facility, the 10 MW Leinster battery energy storage system and interconnecting transmission infrastructure, all of which are now integrated into TransAlta’s existing 169 MW Southern Cross Energy North remote network in Western Australia. The facilities are fully contracted to BHP Nickel West for a term of 15 years and are expected to reduce BHP's scope 2 emissions at Mount Keith and Leinster by 12 per cent annually.

Hancock Prospecting Joint Development Agreement

The Company entered into a joint development agreement with Hancock Prospecting Pty Ltd. (“Hancock”), Australia’s fourth largest iron ore producer. This arrangement will build on TransAlta’s expertise in supplying power to remote mining operations in Western Australia. TransAlta will work collaboratively with Hancock to define and supply behind-the-fence generation solutions for Hancock in the Port Hedland area.

Garden Plain Wind Facility Reaches Commercial Operations

In August 2023, the Garden Plain wind facility was commissioned adding 130 MW to our gross installed capacity. The facility is fully contracted with Pembina Pipeline Corporation ("Pembina") and PepsiCo Canada ("PepsiCo"), with a weighted average contract life of approximately 17 years. The facility consists of 26 Siemens-Gamesa turbines.

Early-Stage Pumped Hydro Development Project

On April 24, 2023, the Company acquired a 50 per cent interest in the Tent Mountain Renewable Energy Complex (“Tent Mountain”), an early-stage 320 MW pumped storage hydro development project located in southwest Alberta, from Evolve Power Ltd. ("Evolve"), formerly known as Montem Resources Limited. The acquisition includes land rights, fixed assets and intellectual property associated with Tent Mountain.

The Company and Evolve own the Tent Mountain project within a special purpose partnership that is jointly managed, with the Company acting as project developer. The partnership is actively seeking an offtake agreement for the energy and environmental attributes that will be generated by the facility.

Mount Keith 132kV Transmission Expansion

On May 3, 2022, Southern Cross Energy, a subsidiary of the Company, entered into an engineering, procurement and construction agreement for the expansion of the Mount Keith 132kV transmission system in Western Australia. The project is being developed under the existing PPA with BHP, which expires in 2038. It is expected to be completed in the first quarter of 2024. 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.

Horizon Hill Wind Project and Corporate PPA with Meta

On April 5, 2022, TransAlta announced 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, located in Logan County, Oklahoma. Under this agreement, Meta receives both renewable electricity and environmental attributes from the Horizon Hill facility. The facility will consist of a total of 34 Vestas turbines. Construction began in the fall of 2022 with an expected commercial operation date in the first quarter of 2024. A substantial majority of the budgeted project costs are captured under executed fixed price turbine supply agreements and executed construction agreements with a top-tier construction provider.

White Rock Wind Projects and Corporate PPA with Amazon

On Dec. 22, 2021, the Company executed two long-term PPAs with Amazon Energy LLC (“Amazon”) for 100 per cent of the renewable electricity and environmental attributes from the projects. The 300 MW White Rock wind projects, located in Caddo County, Oklahoma, will consist of a total of 51 Vestas turbines. Construction began in late 2022 with a target for both White Rock projects to achieve full commercial operation in the first quarter of 2024. A substantial majority of the budgeted project costs are captured under executed fixed price turbine supply agreements and executed construction agreements with a top-tier construction provider.

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TransAlta Achieves Commercial Operation at Windrise

On Dec. 2, 2021, TransAlta announced that the 206 MW Windrise wind facility achieved commercial operation on Nov. 10, 2021. The Windrise facility is located approximately 20 kilometres southwest of Fort Macleod on approximately 11,000 acres of privately owned land. The Windrise wind facility has a 20-year offtake agreement with the Alberta Electric System Operator ("AESO").

Innovation

Energy Impact Partners Investment

On May 5, 2022, the Company entered into a commitment to invest US$25 million over the next four years in Energy Impact Partners ("EIP") Deep Decarbonization Frontier Fund 1 (the “Frontier Fund”). During 2022, the Company invested $10 million (US$8 million). In 2023, the Company invested $5 million (US$4 million).

This program invests in early-stage, innovative technology companies that will accelerate the transition to net-zero GHG emissions. TransAlta's investment in the Frontier Fund provides TransAlta with the opportunity to pool funds with some of the largest utilities in the United States and Europe to identify, pilot, commercialize and bring to market technologies that will support its decarbonization goals.

Investment in Ekona Power Inc.

On Feb. 1, 2022, the Company made an equity investment of $2 million in Ekona Power Inc.’s ("Ekona") 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. Built on the principles of combustion and high-speed gas dynamics, if successful, the platform could be low-cost, scalable, and situated wherever natural gas infrastructure exists.

Acquisitions

TransAlta to Acquire Heartland Generation from Energy Capital Partners

On Nov. 2, 2023, the Company announced that it had entered into a definitive share purchase agreement with an affiliate of Energy Capital Partners, the parent of Heartland Generation Ltd. and Alberta Power (2000) Ltd. (collectively, "Heartland"), pursuant to which TransAlta will acquire Heartland and its entire business operations in Alberta and British Columbia. The acquisition will add 10 facilities to TransAlta’s fleet, totalling 1,844 MW of new capacity. The transaction is expected to close in the first half of 2024, subject to customary closing conditions, including receipt of regulatory approvals.

The purchase price for the acquisition is $390 million, subject to working capital and other adjustments, as well as the assumption of $268 million of low-cost debt. The Company will finance the transaction using cash on hand and drawing on its credit facilities.

The assets are expected to add approximately $115 million of average annual EBITDA including synergies. Approximately 55 per cent of revenues are under contract with highly creditworthy counterparties, with a weighted-average remaining contract life of 16 years. Corporate pre-tax synergies are expected to exceed $20 million annually.

The acquisition will competitively position the Company to respond to the highly dynamic and shifting electricity landscape in Alberta given the expected significant increase in renewables and other large baseload generation coming online in the next several years in the province. The Clean Electricity Growth Plan continues to be at the heart of our strategy and is primarily focused on meeting the future needs of our customers with clean electricity solutions.

TransAlta Corporation Completes Acquisition of TransAlta Renewables Inc.
On Oct. 5, 2023, the Company completed the acquisition of TransAlta Renewables. Please see the "Our Subsidiaries" section of this AIF for details.

Acquisition of North Carolina Solar

On Nov. 5, 2021, the Company closed the acquisition of a 122 MW portfolio of 20 solar photovoltaic sites located in North Carolina (collectively, "North Carolina Solar"). 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. The facilities are all operational and were commissioned between November 2019 and May 2021. The facilities are

TransAlta Corporation • Annual Information Form        14

secured by long-term PPAs with Duke Energy, which at the time of purchase had an average remaining term of 12 years. Under the PPAs, Duke Energy receives the renewable electricity, capacity and environmental attributes from each site.

Recontracting

Pingston Successfully Recontracted

During 2023, the Company successfully recontracted the Pingston facility for a period of 20 years. Pingston is a 46 MW run-of-river hydroelectric facility located on Pingston Creek, British Columbia.

Executed Industrial Contract Extensions at Sarnia Cogeneration

During the second and fourth quarters of 2022, the Company executed contracts for the supply of electricity and steam from the Sarnia cogeneration facility with three of its legacy industrial customers, and with three of its new customers, who had previously been resold utilities as part of a legacy customer's contract. Following the contracting efforts in 2021 and 2022, the Sarnia cogeneration facility has been fully recontracted without interruption to the customers' delivery terms. The contracts extend to April 30, 2031, for four customers and to Dec. 31, 2032 for the other three customers.

Executed Contract Renewals with the IESO at Sarnia Cogeneration and Melancthon 1 Wind Facilities

On Aug. 23, 2022, TransAlta 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 IESO’s Medium-Term Capacity Procurement Request for Proposals. 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 existing contracts for the Sarnia cogeneration facility and the Melancthon 1 wind facility were extended from Dec. 31, 2025 and March 3, 2026, respectively, to April 30, 2026. The Company expects the gross margin from the Sarnia cogeneration facility to be reduced by approximately 30 per cent as a result of the IESO price cap under the new capacity contracts.

Kent Hills Wind

On Jan. 29, 2024, TransAlta hosted a celebration event with New Brunswick Power to mark the re-opening of our Kent Hills wind facility. The facilities were partially returned to service in the fourth quarter of 2023, with all turbines now commissioned and the remediation project completed in the first quarter of 2024. On June 2, 2022, TransAlta announced the rehabilitation plan for the Kent Hills 1 and 2 wind facilities. In addition to the announcement, TransAlta amended and extended PPAs 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 was also obtained from the project bondholders and a supplemental indenture was entered into with the bondholders that facilitates the rehabilitation of the Kent Hills 1 and 2 wind facilities. See the "Wind and Solar" and "Financial Capital" sections of the 2023 Integrated Report. See Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2023, which financial statements are incorporated by reference herein.

Coal Retirement Updates and Coal-to-Gas Conversions

TransAlta and Lafarge Canada Advance Low-Carbon Fly Ash Repurposing Project

During the fourth quarter of 2022, the Company entered into an agreement with Lafarge Canada that will advance low-carbon concrete projects in Alberta. The project will repurpose landfilled fly ash, a waste product from the Company's previously operated Canadian coal-fired electricity facilities, which ceased operating on coal at the end of 2021. The ash will be used to replace cement in concrete manufacturing.

TransAlta Achieves Full Phase-Out of Coal in Canada

On Dec. 29, 2021, the Company announced the completion of the full conversions of each 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 maintain the same generator nameplate capacity of 395 MW, 463 MW and 401 MW, respectively. As of Dec. 31, 2021, the Company no longer generates electricity with coal in Canada.

TransAlta Corporation • Annual Information Form        15

Retirement of Sundance Unit 4 and Keephills Unit 1 and Suspension of Sundance Unit 5 Repowering

On Sept. 28, 2021, the Company announced its decision to suspend the Sundance Unit 5 repowering project and retired Keephills Unit 1 on Dec. 31, 2021, and Sundance Unit 4 on April 1, 2022. Sundance Unit 5 retired on Nov. 1, 2021.

Dispositions

Appleton and Galetta Disposition

On Dec. 2, 2022, the Company sold the Appleton and Galetta hydro facilities located in Ontario. The Appleton facility is a 1 MW run-of-river hydroelectric facility located on the Mississippi River near Almonte, Ontario. The Galetta facility is a 2 MW run-of-river hydroelectric facility located on the Mississippi River near Galetta, Ontario. The Appleton and Galetta facilities were sold following consideration of the expected ongoing maintenance expense and sustaining capital required for the facilities relative to their annual revenue contribution.

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 NOVA Gas Transmission Ltd. ("NGTL") and ATCO's 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 entered into long-term gas transportation agreements with NGTL for a new and existing transportation service of 400 terajoules per day by the end of 2023.

Corporate

Production Tax Credit ("PTC") Sale Agreements

On Feb. 22, 2024, the Company entered into 10-year transfer agreements with an AA- rated customer for the sale of approximately 80 per cent of the expected PTCs to be generated from the White Rock wind projects and the Horizon Hill wind project. The expected annual average EBITDA from these contracts is approximately $57 million (US$43 million).

Financing Activities, Credit Facility Updates and Dividend Declaration

Normal Course Issuer Bid and Automatic Share Purchase Plan

During the year ended Dec. 31, 2023, the Company purchased and cancelled a total of 7,537,500 common shares, pursuant to its Normal Course Issuer Bid ("NCIB") programs at an average price of $11.49 per common share, for a total cost of $87 million.

On May 26, 2023, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement an 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 7.29 per cent of its public float of common shares as at May 17, 2023. 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, 2023, and ends on May 30, 2024, 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.

On Dec. 19, 2023, the Company entered into an ASPP to facilitate repurchases of TransAlta’s common shares under its NCIB.

Declared Dividend Increases

On Nov. 18, 2023, TransAlta's approved an annualized $0.02 per share increase, or 9 per cent increase to our common share dividend and declared a dividend of $0.06 per common share to be paid on April 1, 2024. The quarterly dividend of $0.06 per common share represents an annualized dividend of $0.24 per common share.

On Nov. 7, 2022, the Company announced that the Board of Directors approved a 10 per cent increase in its common share dividend and declared a dividend of $0.055 per common share that was paid on Jan. 1, 2023.

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The quarterly dividend of $0.055 per common share represents an annualized dividend of $0.22 per common share.

On Sept. 28, 2021, the Company announced that the Board of Directors approved an 11 per cent increase to 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.

Public Offering of US Senior Green Bonds and release of inaugural Green Bond Framework

On Nov. 17, 2022, the Company issued US$400 million Senior Notes ("Senior Green Bonds"), which have a coupon rate of 7.750 per cent per annum and mature on Nov. 15, 2029. Including the effects of settled interest rate swaps, the notes have an effective yield of approximately 5.982 per cent. The notes are an unsecured obligation and rank equally in right of payment with all of our existing and future senior indebtedness, and are senior in right of payment to all of our future subordinated indebtedness. The interest payments on the Senior Green Bonds are made semi-annually, on November 15 and May 15, with the first payment being made on May 15, 2023.

The Company will allocate an amount equal to the net proceeds from this offering to finance or refinance new and/or existing eligible green projects in accordance with its Green Bond Framework (the “Framework”). The Framework received a second-party opinion from Sustainalytics, which verified that it aligned with the Green Bond Principles from the International Capital Market Association.

New Term Facility

During the third quarter of 2022, the Company closed a two-year $400 million floating-rate term facility ("Term Facility") with its banking syndicate with a maturity date of Sept. 7, 2024. As at Dec. 31, 2023, the full amount was drawn on the Term Facility.

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, no Series E Shares were converted into Series F Shares.

Conversion Results for Series C and D Preferred Shares

On June 30, 2022, the Company converted 1,044,299 of its 11,000,000 Cumulative Redeemable Rate Reset First Preferred Shares, Series C (“Series C Shares”), on a one-for-one basis, into Cumulative Redeemable Floating Rate First Preferred Shares, Series D (“Series D Shares”).

TransAlta Debuts New Brand Reiterating Commitment to a Clean Energy Future

On June 20, 2022, the Company announced and launched a new brand, including a new Company 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 net-zero future.

Windrise Wind LP Closed $173 Million Green Bond

On Dec. 6, 2021, Windrise Wind LP, secured a Green Bond financing by way of private placement for $173 million. The bonds are amortizing, bear interest from their date of issue at a rate of 3.41 per cent per annum and mature on Sept. 30, 2041. The bonds are aligned with the four components of the 2021 International Capital Market Association Green Bond Principles.

Windrise Wind LP used proceeds of the bonds to, among other things, repay all amounts owing pursuant to an intercompany construction loan agreement entered into in connection with the Windrise facility, make advances to TransAlta Renewables on a subordinated basis pursuant to an intercompany loan agreement, finance or refinance eligible green projects, including renewable energy facilities, and to fund a construction reserve account.

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Sustainability-Linked Loan

On March 30, 2021, TransAlta extended its $1.25 billion syndicated credit facility to June 30, 2025, and converted the facility into a Sustainability-Linked Loan (“SLL”). On June 8, 2023, the SLL was further extended to June 30, 2027. On Sept. 6, 2023, the SLL was increased to $1.95 billion. The facility's financing terms 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 commitment to sustainability leadership, including ED&I and emissions reduction.

Sustainability

2024 Board of Directors Change

The Honourable Rona Ambrose has decided that she will not stand for re-election and will retire from the Board following the annual shareholder meeting on April 25, 2024. The Board extends its gratitude for her service to the Company. She has been a valuable contributor to the Board since 2017 and we thank her for her leadership and insights during her tenure, especially as Chair of the Governance, Safety and Sustainability Committee of the Board.

TransAlta Tops List of Newsweek’s World’s Most Trustworthy Companies

On Sept. 14, 2023, the Company announced that it ranked first on Newsweek's inaugural “World's Most Trustworthy Companies 2023” list for the Energy and Utilities category. The list identifies the top 1,000 companies in 21 countries and across 23 industries. Newsweek’s 2023 World’s Most Trustworthy Companies were chosen based on a holistic approach to evaluating three pillars of public trust – customers, investors and employees. The list was compiled based on an extensive survey of over 70,000 participants, gathering 269,000 evaluations of companies that people trust as a customer, as an investor or as an employee.

2023 Management and Board of Directors Changes

At our annual shareholder meeting held on April 28, 2023, shareholders elected our Board of Directors, which included director nominee Ms. Candace MacGibbon. Ms. MacGibbon brings to the Board attributes and skills focused on leadership, collaboration and integrity, which she has demonstrated through her prior successful senior leadership roles, including as a chief executive officer and a chief financial officer. Ms. MacGibbon is a Chartered Professional Accountant.

In November 2023, the responsibilities and accountabilities of the Company's executive team were reorganized, which resulted in Jane Fedoretz becoming the Executive Vice President, People, Culture and Chief Administrative Officer, Kerry O'Reilly Wilks becoming the Executive Vice President, Growth and Energy Marketing, Aron Willis becoming the Executive Vice President, Project Delivery and Construction, Blain van Melle becoming the Executive Vice President, Commercial and Customer Relations and David Little joining the Company as Senior Vice President, Growth.

2022 Management and Board of Directors Changes

On Dec. 15, 2022, the Company announced the appointment of Ms. Manjit Sharma to the Board of Directors effective Jan. 1, 2023. Ms. Sharma brings over 30 years of experience that spans a variety of industries, most recently serving as Chief Financial Officer of WSP Canada Inc. Ms. Sharma holds a Bachelor of Commerce degree (with Honours) from the University of Toronto, is a Fellow Chartered Accountant and holds the ICD.D Directors designation and the GCB.D Global Competent Boards designation. In 2019, Ms. Sharma was recognized as one of Canada’s Top 100 Most Powerful Women by the Women’s Executive Network.

On Sept. 30, 2022, Mr. Michael Novelli retired from his role as the Executive Vice President, Generation of the Company and on Nov. 3, 2022, Mr. Novelli was appointed to the TransAlta Renewables Board of Directors as the Company's nominee pursuant to the Governance Agreement between the Company and TransAlta Renewables.

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 May 2022.

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MSCI Environmental, Social and Governance Rating Upgrade

During the second quarter of 2022, TransAlta's MSCI ESG Rating was upgraded to 'AA' from 'A'. The upgrade reflects the Company's strong renewable energy growth compared to its peers. From 2000 to 2022, we grew our nameplate renewables capacity from approximately 900 MW to over 2,900 MW. 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 our Canadian coal-fired facilities in 2021, nine years ahead of Alberta’s coal phase-out plan.

2021 Clean Electricity Growth Plan

On Sept. 28, 2021, we held our 2021 Investor Day and announced our Clean Electricity Growth Plan. The targets were to deliver 2 GW of incremental renewable capacity with a targeted investment of $3.6 billion by 2025. The Clean Electricity Growth Plan was updated with new targets from 2024 to 2028 at our Nov. 21, 2023, Investor Day. See the section "Overview - Our Corporate Strategy" of this AIF for further details.

ED&I Program

TransAlta’s commitment and focus on excellence in ED&I is found in our workplace and among our co-workers who advocate for the values of equity and inclusion at all working levels. This commitment is outlined in our Board and Workforce Diversity Policy and Diversity and Inclusion Pledge. In 2023, TransAlta executed the third year of our five-year ED&I strategy to achieve the goals and aspirations defined in our ED&I Pledge, which is publicly available in the Governance section of the Investor Centre on our website.

2021 Management and Board of Directors Changes

On March 31, 2021, Dawn Farrell retired from the Board of Directors and as President and Chief Executive Officer of the Company. John Kousinioris succeeded Ms. Farrell as President and Chief Executive Officer and joined the Board of Directors on April 1, 2021.

On May 4, 2021, the Company announced the election of four new directors: Ms. Laura W. Folse, Ms. Sarah Slusser, Mr. Thomas O'Flynn and Mr. Jim Reid. Ms. Georgia Nelson, Mr. Richard Legault and Mr. Yakout Mansour did not stand for re-election and retired from the Board of Directors immediately following the annual shareholder meeting on May 4, 2021.

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Business of TransAlta

Our Hydro, Wind and Solar, Gas and Energy Transition segments are responsible for operating and maintaining our electrical generation facilities in Canada, the US and Australia. Our Energy Marketing segment is responsible for marketing and scheduling our merchant asset fleet in North America along with the procurement of gas, transport and storage for our gas fleet, providing knowledge to support our growth team, and generating a stand-alone gross margin separate from our asset business through a leading North American energy marketing platform. These segments are all supported by a Corporate segment.

As the Company continues its transformation to achieve the Clean Electricity Growth Plan, it is expected that the proportion of revenue attributable to the Energy Transition business unit will decline relative to the other business units. In addition, we continue to evolve into a leaner organization through continuous optimization.

The following table identifies each revenue-generating segment's contribution to revenues as at Dec. 31, 2023:

	2023 Revenues		2022 Revenues
Hydro	16	%	20	%
Wind and Solar	10	%	10	%
Gas	45	%	41	%
Energy Transition	22	%	24	%
Energy Marketing	7	%	5	%

For further information on our segment earnings and assets see the audited consolidated financial statements for the year ended Dec. 31, 2023, which are incorporated by reference herein. Also, see the "Documents Incorporated by Reference" section of this AIF.

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

Hydro Segment

The Hydro segment holds an interest in 922 net MW. The facilities are located in Alberta, British Columbia, and Ontario.

As well as contracting for power, we enter into long-term and short-term contracts to sell the environmental attributes from our merchant hydro facilities. These activities help to ensure earnings stability from these assets. Generally, for facilities under long-term contract, the benefit of the environmental attributes generated is provided to the contract holder.

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The following table summarizes our hydroelectric facilities as at Dec. 31, 2023:

Facility Name	Province/ State	Nameplate Capacity (MW)(1)	Consolidated Interest		Gross Installed Capacity(1)	Ownership		Net Capacity Ownership Interest (MW)(1)	Commercial Operation Date(2)	Revenue Source(3)	Contract Expiry Date(4)
Alberta - Bow River System
Barrier(5)(6)	AB	13	100	%	13	100	%	13	1947	Merchant	‑
Bearspaw(5)(6)	AB	17	100	%	17	100	%	17	1954	Merchant	‑
Cascade(5)(6)	AB	36	100	%	36	100	%	36	1942, 1957	Merchant	‑
Ghost(5)(6)	AB	54	100	%	54	100	%	54	1929, 1954	Merchant	‑
Horseshoe(5)(6)	AB	14	100	%	14	100	%	14	1911	Merchant	‑
Interlakes(5)(6)	AB	5	100	%	5	100	%	5	1955	Merchant	‑
Kananaskis(5)(6)	AB	19	100	%	19	100	%	19	1913, 1951	Merchant	‑
Pocaterra(6)	AB	15	100	%	15	100	%	15	1955	Merchant	‑
Rundle(5)(6)	AB	50	100	%	50	100	%	50	1951, 1960	Merchant	‑
Spray(5)(6)	AB	112	100	%	112	100	%	112	1951, 1960	Merchant	‑
Three Sisters(5)	AB	3	100	%	3	100	%	3	1951	Merchant	‑
Alberta - Oldman River System
Belly River(6)	AB	3	100	%	3	100	%	3	1991	Merchant	‑
St. Mary(6)	AB	2	100	%	2	100	%	2	1992	Merchant	‑
Taylor(6)	AB	13	100	%	13	100	%	13	2000	Merchant	‑
Waterton(6)	AB	3	100	%	3	100	%	3	1992	Merchant	‑
Alberta - North Saskatchewan River System(6)
Bighorn(5)(6)	AB	120	100	%	120	100	%	120	1972	Merchant	‑
Brazeau(5)(6)	AB	355	100	%	355	100	%	355	1965, 1967	Merchant	‑
BC Hydro
Akolkolex(6)	BC	10	100	%	10	100	%	10	1995	LTC	2046
Bone Creek(6)	BC	19	100	%	19	100	%	19	2011	LTC	2031
Pingston(6)	BC	45	50	%	22.5	100	%	23	2003, 2004	LTC	2043
Upper Mamquam(6)	BC	25	100	%	25	100	%	25	2005	LTC	2025
Ontario Hydro
Misema	ON	3	100	%	3	100	%	3	2003	LTC	2027
Moose Rapids(6)	ON	1	100	%	1	100	%	1	1997	LTC	2030
Ragged Chute	ON	7	100	%	7	100	%	7	1991	LTC	2029
Total Hydroelectric Capacity		944			921.5			922

(1) MW are rounded to the nearest whole number. The gross installed capacity reflects the basis of consolidation of
underlying assets owned, whereas net capacity ownership interest deducts capacity attributable to the non-controlling interest in these assets and is calculated after the consolidation of underlying assets.

(2) A second date in this column refers to a second unit that was subsequently operational.

(3) The large majority of the Company’s contracted operating facilities benefit from inflation adjustment provisions that apply to all or a portion of our revenues under such contracts.

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

(5) These facilities form part of the hydro assets that are subject to an Investment Agreement. See the "Capital and Loan Structure - Investment Agreement and E&O Agreement" section of this AIF for further details.

(6) These facilities are EcoLogo® certified. EcoLogo certification is granted to products with an environmental performance
that meets or exceeds all government, industrial safety and performance standards.

TransAlta Corporation • Annual Information Form        21

Bow River System

Barrier

Barrier is a hydroelectric facility with installed capacity of 13 MW located on the Kananaskis River near Seebe, Alberta. This facility uses a Dominion Engineering Francis turbine and a Westinghouse generator, commercial operations began in 1947. Generation from the facility is currently sold in the Alberta electricity market and creates Emission Performance Credits ("EPCs") under the Alberta Technology Innovation and Emissions Reduction ("TIER") system.

Bearspaw

Bearspaw is a hydroelectric facility with installed capacity of 17 MW located on the Bow River in Calgary, Alberta. This facility uses a Karlstads Mekaniska Werkstad ("KMW") Kaplan turbine and a Westinghouse generator. Commercial operations began in 1954. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Cascade

Cascade is a hydroelectric facility with installed capacity of 36 MW located on the Cascade River in Banff National Park, Alberta. This facility was purchased from the Government of Canada in 1941. The following year, we built a new dam and power plant to replace the original, and then, in 1957, added a second generating unit. This facility uses two Dominion Engineering Francis turbines and two Westinghouse generators. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Ghost

Ghost is a hydroelectric facility with installed capacity of 54 MW located on the Bow River near Cochrane, Alberta. This facility uses two Dominion Engineering Francis turbines, an English Electric turbine and three Westinghouse generators. Commercial operations began in 1929. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Horseshoe

Horseshoe is a run-of-river hydroelectric facility with installed capacity of 14 MW located on the Bow River near Seebe, Alberta. This facility uses two KMW Twin Francis turbines and two Canadian General Electric generators. Commercial operations began in 1911. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Interlakes

Interlakes is a hydroelectric facility with installed capacity of 5 MW located at Kananaskis Lakes, Alberta. This facility uses an Allis Chalmers Francis turbine and a Westinghouse generator. Commercial operations began in 1955. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Kananaskis

Kananaskis is a run-of-river hydroelectric facility with installed capacity of 19 MW located on the Bow River in Seebe, Alberta. This facility uses two Allis Chalmers Francis turbines, a General Electric Barber Hymac impeller, two ASEA generators and a Westinghouse generator. Commercial operations began in 1913. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Pocaterra

Pocaterra is a hydroelectric facility with installed capacity of 15 MW located at Kananaskis Lakes, Alberta. This facility uses an Allis Chalmers Francis turbine and a Westinghouse generator. Commercial operations began in 1955. Generation from the facility is sold in the Alberta electricity market and creates EPCs under the TIER system.

Rundle

Rundle is a hydroelectric facility with installed capacity of 50 MW located in Canmore, Alberta, on the Spray system. The facility uses water from the Spray Lakes storage reservoir. This facility uses two Dominion Engineering Francis turbines and two Westinghouse generators. Commercial operations began in 1951. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

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Spray

Spray is a hydroelectric facility with installed capacity of 112 MW located in Canmore, Alberta, on the Spray system. The plant uses water from the Spray Lakes storage reservoir. This facility uses two Dominion Engineering Francis turbines and two Westinghouse generators. Commercial operations began in 1951. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Three Sisters

Three Sisters is a hydroelectric facility with installed capacity of 3 MW located at the base of the Three Sisters Dam near Canmore, Alberta, on the Spray system. The facility uses water from the Spray Lakes storage reservoir. This facility uses a Dominion Engineering Impeller turbine and a Westinghouse turbine. Commercial operations began in 1951. Generation from the facility is currently sold in the Alberta electricity market.

Oldman River System

Belly River

Belly River is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Waterton-St. Mary Headworks Irrigation Canal System, east of the Waterton Reservoir, approximately 75 kilometres southwest of Lethbridge in southern Alberta. Due to its location along the irrigation canal, Belly River operates from April to October when water is diverted through the canal as part of the St. Mary Irrigation District Water Management Plan. This facility uses a double Alstom Francis turbine and an Alstom generator. Commercial operations began in March 1991. Generation from the facility is currently sold in the Alberta electricity market.

St. Mary

St. Mary is a run-of-river hydroelectric facility with installed capacity of 2 MW located at the base of the dam impounding the St. Mary Reservoir, near Magrath, in southern Alberta. This facility uses a horizontal double Alstom Francis turbine and a Kato generator. Commercial operations began in 1992. Generation from the facility is currently sold in the Alberta electricity market.

Taylor

Taylor is a run-of-river hydroelectric facility with installed capacity of 13 MW and is located adjacent to the Taylor Coulee Chute on the Waterton-St. Mary Headworks Irrigation Canal System, which is owned by the Government of Alberta. The facility uses a horizontal Andritz Kaplan turbine and a GE generator. Commercial operations began in 2000. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Waterton

Waterton is a run-of-river hydroelectric facility with installed capacity of 3 MW located at the base of the Waterton Dam on the Waterton Reservoir, near Hill Spring, southwest of Lethbridge, Alberta. This facility uses a horizontal double Alstom Francis turbine and a Kato generator. Commercial operations began in 1992. Generation from the facility is currently sold in the Alberta electricity market.

North Saskatchewan River System

Bighorn

Bighorn is a hydroelectric facility with installed capacity of 120 MW located near Nordegg, Alberta. This facility uses two Dominion Engineering Francis turbines and two English Electric generators. Commercial operations began in 1972. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Brazeau

Brazeau is a hydroelectric facility with installed capacity of 355 MW located near Drayton Valley, Alberta. This facility uses two Dominion Engineering Francis turbines and two Westinghouse generators. Commercial operations began in 1967. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

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BC Hydro Facilities

Akolkolex

Akolkolex is a run-of-river hydroelectric facility with installed capacity of 10 MW and is located on the Akolkolex River, south of Revelstoke, British Columbia. This facility uses two horizontal Chongqing Francis turbines on a common shaft with a single Chongqing generator. Commercial operations began in 1995. The output from the facility is sold to British Columbia Hydro and Power Authority ("BC Hydro") under a PPA that terminates in 2046.

Bone Creek

Bone Creek is a run-of-river hydroelectric facility with installed capacity of 19 MW and is located on Bone Creek, 90 kilometres south of Valemount, British Columbia. The facility uses two 9.5 MW horizontal turbine generator units, with twin Francis double draft tube Litostroj turbines and direct-drive INDAR horizontal generators. Commercial operations began in 2011. The output from the facility is sold to BC Hydro under a PPA that terminates in 2031.

Pingston

Pingston is a run-of-river hydroelectric facility with installed capacity of 46 MW and is located on Pingston Creek, southwest of Revelstoke, British Columbia, and downriver of the Akolkolex facility. Pingston is equally owned with Evolugen Trading and Marketing LP, a subsidiary of Brookfield. The facility uses three 15 MW horizontal Pelton turbines and Leroy-Somer generators. Commercial operations began in 2003. The output from the facility is sold to BC Hydro under a recontracted 20-year PPA that expires on May 8, 2043.

Upper Mamquam

Upper Mamquam is a run-of-river hydroelectric facility with installed capacity of 25 MW located on the Mamquam River, east of Squamish, British Columbia, and north of Vancouver. The facility uses two horizontal axis double Litostroj Francis turbines and Voith generators. Commercial operations began in 2005. The output from the facility is sold to BC Hydro under a PPA that terminates in 2025.

Ontario Hydro Facilities

Misema

Misema is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Misema River, close to Englehart, in northern Ontario. This facility uses one horizontal axis double Litostroj Francis turbine with a Leroy-Somer generator. Commercial operations began in 2003. Generation from this facility is sold to the IESO under a contract that terminates on May 3, 2027.

Moose Rapids

Moose Rapids is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Wanapitei River, near Sudbury, in northern Ontario. This facility uses two Canadian Hydro Components slant-axis fixed-blade propeller mini-turbines and one slant-axis adjustable-speed Andritz Kaplan mini turbine with three Siemens generators. Commercial operations began in 1997. Generation from this facility is sold to the IESO under a contract that terminates on Dec. 31, 2030.

Ragged Chute

Ragged Chute is a run-of-river hydroelectric facility with installed capacity of 7 MW located on the Montréal River, south of Temiskaming Shores, in northern Ontario. The Company leases this facility from Ontario Power Generation Inc. ("OPG"). The facility has been operating since 1991. The facility uses a single 6.6 MW horizontal Kaplan unit and a GE generator. Generation from this facility is sold to the IESO under a contract that terminates on June 30, 2029. Upon termination, the asset will transfer to OPG together with a payment of $6.6 million to the Company.

TransAlta Corporation • Annual Information Form        24

Wind and Solar Segment

As at Dec. 31, 2023, the Wind and Solar segment held interests in approximately 2,057 MW of net wind generating capacity. This capacity consists of 12 wind facilities in Western Canada, four in Ontario, two in Québec, three in New Brunswick and five in the US, more specifically in the states of Washington, Wyoming, Minnesota, Pennsylvania and New Hampshire. The Company also holds a 10 MW utility-scale battery energy storage system in Alberta, 143 MW of solar facilities in the states of Massachusetts and North Carolina, and a 38 MW solar facility and a 10 MW battery energy storage system in Western Australia.

Wind and solar are not generally dispatchable sources of generation. Therefore, in merchant markets, wind and solar assets may not be able to secure the annual average pool price. As such, we make different assumptions in forecast revenue for generation from a wind or solar asset compared to a dispatchable asset. If these price assumptions and generation production forecasts are not correct, the corresponding revenue received may vary from our forecast. Generation production forecasts are based on the long-term average production forecast for a site, reflecting historical climatic conditions. Within any year there may be variations from this long-term average. To forecast generation production, numerous factors have to be assumed based on historic on-site data. For a wind facility, this includes the wind facility design, including wake and array losses, wind shear and the electrical losses within the site. For a solar facility, the long-term production depends on panel angle and row spacing, amount of sun, and ambient and environmental conditions at the site. If these assumptions are incorrect then actual production will be higher or lower than the long-term forecast for the site.

In addition to contracting for the sale of the power generation, we also enter into long-term and short-term contracts to sell the environmental attributes from the merchant wind and solar facilities. These activities help to ensure earnings consistency from these assets. Generally, for facilities under a long-term power purchase agreement, the purchaser under such long-term contracts also benefits from any environmental attributes associated with the facility.

TransAlta Corporation • Annual Information Form        25

The following table summarizes our Wind and Solar generation facilities as at Dec. 31, 2023:

Facility Name	Province/ State	Nameplate Capacity (MW)(1)	Consolidated Interest		Gross Installed Capacity(1)	Ownership		Net Capacity Ownership Interest (MW)(1)	Commercial Operation Date(2)	Revenue Source(3)	Contract Expiry Date(4)
Alberta Wind
Ardenville(5)	AB	69	100	%	69	100	%	69	2010	Merchant	‑
Blue Trail and Macleod Flats(5)	AB	69	100	%	69	100	%	69	2009 and 2004	Merchant	‑
Castle River(5)(6)	AB	44	100	%	44	100	%	44	1997‑2001	Merchant	-
Cowley North(5)	AB	20	100	%	20	100	%	20	2001	Merchant	‑
Garden Plain	AB	130	100	%	130	100	%	130	2023	LTC	2035-2041
McBride Lake(5)	AB	75	50	%	38	100	%	38	2004	LTC	2024
Oldman(5)	AB	4	100	%	4	100	%	4	2007	Merchant	-
Sinnott(5)	AB	7	100	%	7	100	%	7	2001	Merchant	‑
Soderglen(5)	AB	71	50	%	36	100	%	36	2006	Merchant	‑
Summerview 1(5)	AB	68	100	%	68	100	%	68	2004	Merchant	‑
Summerview 2 (5)	AB	66	100	%	66	100	%	66	2010	Merchant	‑
Windrise	AB	206	100	%	206	100	%	206	2021	LTC	2041
Alberta Battery Energy Storage
WindCharger	AB	10	100	%	10	100	%	10	2020	Merchant	‑
Eastern Canada Wind
Kent Breeze	ON	20	100	%	20	100	%	20	2011	LTC	2031
Kent Hills 1	NB	96	100	%	96	83	%	80	2008	LTC	2045
Kent Hills 2	NB	54	100	%	54	83	%	45	2010	LTC	2045
Kent Hills 3	NB	17	100	%	17	83	%	14	2018	LTC	2045
Le Nordais(5)(7)	QC	98	100	%	98	100	%	98	1999	LTC	2033
Melancthon 1	ON	68	100	%	68	100	%	68	2006	LTC	2031
Melancthon 2	ON	132	100	%	132	100	%	132	2008	LTC	2028
New Richmond(5)	QC	68	100	%	68	100	%	68	2013	LTC	2033
Wolfe Island	ON	198	100	%	198	100	%	198	2009	LTC	2029
US Wind
Antrim	NH	29	100	%	29	100	%	29	2019	LTC	2039
Big Level	PA	90	100	%	90	100	%	90	2019	LTC	2034
Lakeswind	MN	50	100	%	50	100	%	50	2014	LTC	2034
Skookumchuck Wind	WA	137	49	%	67	100	%	67	2020	LTC	2040
Wyoming Wind	WY	140	100	%	140	100	%	140	2003	LTC	2028
US Solar
Mass Solar (7)	MA	21	100	%	21	100	%	21	2012-2015	LTC	2032-2045
North Carolina Solar(7)	NC	122	100	%	122	100	%	122	2019-2021	LTC	2033
Australian Solar
Northern Goldfields(7)	WA	38	100	%	38	100	%	38	2023	LTC	2038
Australia Battery Energy Storage
Northern Goldfields Battery	WA	10	100	%	10	100	%	10	2023	LTC	2038
Total Wind and Solar Capacity (8)		2,227			2,085			2,057

(1)    MW are rounded to the nearest whole number. The gross installed capacity reflects the basis of consolidation of the underlying assets owned, whereas net capacity ownership interest deducts capacity attributable to non-controlling interest in these assets and is calculated after consolidation of the underlying assets.

(2)    A second date in this column refers to a second facility that was subsequently operational.

(3)    The large majority of the Company’s contracted operating facilities benefit from inflation adjustment provisions that apply to all or a portion of our revenues under such contracts.

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

(5)    These facilities are EcoLogo® certified. EcoLogo certification is granted to products with an environmental performance that meets or exceeds all government, industrial safety and performance standards.

TransAlta Corporation • Annual Information Form        26

(6)    Includes seven additional turbines at other locations.

(7)    Includes multiple facilities.

(8)    Excludes White Rock East and White Rock West wind projects, which are expected to reach commercial operation in the first quarter of 2024.

Alberta Wind Facilities

Ardenville

Ardenville is a 69 MW wind facility consisting of 23 3.0 MW Vestas V90 wind turbines on 80-metre towers that is located approximately 14 kilometres south of Fort Macleod. The facility began commercial operations in November 2010. In 2018, the Ardenville wind facility was granted an extension to create offset credits under the TIER system until Oct. 31, 2023, and thereafter the facility became a facility that satisfies the eligibility criteria for an opted in facility under Section 4 of the TIER regulation and is voluntarily choosing to participate in the regulation for the purposes of being able to generate emission performance credits ("opt-in facility"). An opt-in facility is not considered a large emitter of GHGs and as such we elected to participate in TIER. Generation from the facility is currently sold in the Alberta electricity market.

Blue Trail and Macleod Flats

Blue Trail is a 66 MW wind facility consisting of 22 3.0 MW Vestas V90 wind turbines on 80-metre towers that is located in southern Alberta. The facility began commercial operations in November 2009. The Blue Trail wind facility created carbon offset credits under TIER until Sept. 16, 2022, at which time the facility became an opt-in facility under TIER.

Macleod Flats is a 3 MW wind facility that consists of a single 3.0 MW Vestas V90 wind turbine on a 67-metre tower that is located near Fort Macleod. It was commissioned in 2004 and was acquired by TransAlta in 2009. This facility generates Renewable Energy Certificate ("REC") credits. Generation from the facilities is currently sold in the Alberta electricity market.

Castle River

Castle River is a 39.5 MW wind facility consisting of 66 Vestas wind turbines (three Vestas V44 600 kW wind turbines and 63 Vestas V47 660 kW wind turbines) on 50-metre towers that is located southwest of Pincher Creek. This facility also includes an additional six turbines, totalling 4 MW that are located individually in the Cardston County and Hill Spring areas of southwestern Alberta. The facility began commercial operations in stages from November 1997 through to July 2001. This facility generates EPCs under the TIER system. Generation from the facility is currently sold in the Alberta electricity market.

Cowley North

Cowley North is a 19.5 MW wind facility consisting of 15 1.3 MW Nordex N60 wind turbines on 50-metre towers that is located near the towns of Cowley and Pincher Creek, in southern Alberta. The facility began commercial operations in the fall of 2001. The Cowley North facility creates EPCs under the TIER system. Generation from the facility is currently sold in the Alberta electricity market.

Garden Plain

Garden Plain is a 130 MW wind facility consisting of 26 5 MW Siemens 145 turbines on 102.5-metre towers that is located approximately 30 kilometres north of Hanna. This facility began commercial operations in August 2023. The facility is fully contracted with 100 MW being sold under a PPA with Pembina that terminates in 2041 and the remaining 30 MW of generation being contracted to PepsiCo under a PPA and terminates in 2035.

McBride Lake

McBride Lake is a 75.2 MW wind facility consisting of 114 660 kW Vestas V47 wind turbines on 50-metre towers that is located south of Fort Macleod. The McBride Lake facility is co-owned with ENMAX Generation Portfolio Inc. The facility began commercial operations on April 30, 2004. Generation from this facility is sold under a 20-year PPA with ENMAX Energy Corporation that terminates April 30, 2024. The Company expects generation from this facility will be sold into the Alberta electricity market after the PPA expires.

Oldman

Oldman is a 3.6 MW wind facility consisting of two 1.8 MW Vestas V80 turbines on 67-metre towers that is located east of the Oldman River Dam, near Pincher Creek in southern Alberta. The facility has been in operation since March 2007. In 2021, TransAlta acquired 100 per cent of the facility from a subsidiary of Boralex. This facility sells energy into the Alberta electricity market.

TransAlta Corporation • Annual Information Form        27

Sinnott

Sinnott is a 7 MW wind facility consisting of five 1.3 MW Nordex N60 wind turbines on 65-metre towers that is located directly east of the Cowley North wind facility and north of Pincher Creek. The facility began commercial operations in the fall of 2001. The facility sells energy into the Alberta electricity market and generates EPCs under the TIER system.

Soderglen

Soderglen is a 71 MW wind facility consisting of 47 1.5 MW GE SLE wind turbines on 65-metre towers that is located southwest of Fort Macleod. The facility is co-owned with CNOOC Petroleum North America ULC. The facility began commercial operations in September 2006. The Soderglen wind facility creates EPCs under the TIER system, of which TransAlta receives 25 per cent. The Company is entitled to 50 per cent of the generation that is sold into the Alberta electricity market.

Summerview 1

Summerview 1 is a 68 MW wind facility consisting of 38 1.8 MW Vestas V80 wind turbines on 67-metre towers that is located approximately 15 kilometres northeast of Pincher Creek. The facility began commercial operations in September 2004. The facility sells energy into the Alberta electricity market and generates EPCs under the TIER system.

Summerview 2

Summerview 2 is a 66 MW wind facility consisting of 22 3.0 MW Vestas V90 wind turbines on 80-metre towers that is located approximately 15 kilometres northeast of Pincher Creek. The facility began commercial operations in February 2010. The facility sells energy into the Alberta electricity market and generated carbon offset credits under TIER until November 2022, after which it became an opt-in facility under TIER.

Windrise

Windrise is a 206 MW wind facility consisting of 43 4.8 MW Siemens 145 wind turbines on 90-metre towers that is located in the county of Willow Creek. The facility began commercial operations in November 2021. Generation from the facility is sold to the AESO under a 20-year PPA that expires in 2041.

Alberta Battery Energy Storage

WindCharger

WindCharger is Alberta's first utility-scale battery storage facility. The facility consists of a lithium-ion battery using Tesla Megapack technology that has a nameplate capacity of 10 MW and a total storage capacity of 20 MWh. WindCharger is located in southern Alberta in the Municipal District of Pincher Creek, next to the Summerview wind facility substation. The storage project achieved commercial operations on Oct. 15, 2020. WindCharger stores energy produced by the nearby Summerview 2 wind facility and discharges this energy for ancillary services. The facility is an opt-in facility under TIER. The project received funding support from Emissions Reduction Alberta.

Eastern Canada Wind Facilities

Kent Breeze

Kent Breeze is a 20 MW wind facility consisting of eight 2.5 MW GE XL wind turbines on 85-metre towers that is located in Thamesville, Ontario. The facility began commercial operations in 2011. Generation from this facility is sold to the IESO under a 20-year PPA that expires in 2031.

Kent Hills 1

Kent Hills 1 is a 96 MW wind facility consisting of 32 3 MW Vestas V90's on 80-metre towers that is located near Moncton, New Brunswick. The facility began commercial operations in December 2008. The Company owns 83 per cent of the facility and Natural Forces Technologies Inc., a wind developer based in Atlantic Canada that co-developed the project with TransAlta, owns 17 per cent of the facility. Generation from this facility is sold under a PPA with NB Power.

On June 2, 2022, we announced the rehabilitation plan for the wind facilities, to address the single tower failure that occurred at the Kent Hills 2 facility in September 2021. The plan consisted of dismantling all 49 remaining turbines, demolishing and removing all existing tower foundations and replacing them with newly designed foundations, reassembling the wind turbine towers and generators and replacing the wind turbine

TransAlta Corporation • Annual Information Form        28

that collapsed. We also announced the extension of the PPA for an additional 10-year period through to December 2045. NB Power has also been provided with an effective 10 per cent reduction to the current contract price until 2033.

The facilities were partially returned to service in the fourth quarter of 2023, with all turbines now commissioned and the remediation project completed in the first quarter of 2024. See the "General Development of the Business - Three-Year History" section of this AIF for further details.

Kent Hills 2

Kent Hills 2 is a 54 MW wind facility consisting of 17 3 MW Vestas V90 wind turbines on 80-metre towers and one 3 MW Vestas V126 wind turbine on an 87-meter tower that is located near Moncton, New Brunswick. The facility began commercial operations in November 2010. The Company owns 83 per cent of the facility and Natural Forces Technologies Inc., a wind developer based in Atlantic Canada that co-developed the project with TransAlta, owns 17 per cent of the facility. On June 2, 2022, the Company announced the extension of the previous 2035 PPA term for an additional 10-year period through to December 2045. NB Power has also been provided with an effective 10 per cent reduction to the current contract price until 2033.

See "Kent Hills 1" section of this AIF and the "General Development of the Business - Three-Year History" section of this AIF for further details.

Kent Hills 3

Kent Hills 3 is a 17.25 MW wind facility consisting of five 3.45 MW Vestas V126 turbines on 117-metre towers that is located near Moncton, New Brunswick. The facility began commercial operations in November 2018 and brought the total generating capacity of the three Kent Hills facilities to 167 MW. On June 2, 2022, we announced the extension of the previous 2035 PPA term for an additional 10-year period through to December 2045. NB Power has also been provided with an effective 10 per cent reduction to the current contract price until 2033.

Le Nordais

Le Nordais is a 97.5 MW wind facility consisting of 130 750 kW NEG Micon wind turbines on 55-metre towers that is located on the Gaspé Peninsula of Québec. The facility has two sites, Cap-Chat with 74 turbines and Matan with 56 turbines. The facility began commercial operations in 1999. Generation from this facility is sold to Hydro-Québec pursuant to an energy supply agreement that terminates in 2033, and the facility generates RECs.

Melancthon 1

Melancthon 1 is a 67.5 MW wind facility consisting of 45 1.5 MW GE SLE wind turbines on 80-metre towers that is located in Melancthon Township near Shelburne, Ontario. The facility began commercial operations in March 2006. Generation from this facility is sold to the IESO pursuant to a PPA that expires in 2026; a new capacity contract with the IESO will begin on May 1, 2026, and terminate on April 30, 2031. Revenues will be provided through the IESO market and are expected to decrease by approximately 40 per cent from the current PPA pricing levels based on forecasted Ontario energy prices. The Company is exploring options to contract the energy output instead of relying on market prices.

Melancthon 2

Melancthon 2 is a 132 MW wind facility consisting of 88 1.5 MW GE SLE wind turbines on 80-metre towers that is located adjacent to Melancthon 1, in the Melancthon and Amaranth townships, Ontario. The facility began commercial operations in November 2008. Generation from this facility is sold to the IESO pursuant to a PPA that terminates in 2028. The Company anticipates future contract opportunities will become available with the IESO beyond 2028.

New Richmond

New Richmond is a 68 MW wind facility consisting of 27 2.0 MW and six 2.3 MW Enercon E82 wind turbines on 100-metre towers that is located in New Richmond, Québec. The facility began commercial operations in March 2013. Generation from this facility is sold under a 20-year electricity supply agreement with Hydro-Québec Distribution that terminates in 2033.

TransAlta Corporation • Annual Information Form        29

Wolfe Island

Wolfe Island is a 197.8 MW wind facility consisting of 86 2.3 MW Siemens 93 wind turbines on 80-metre towers that is located on Wolfe Island, near Kingston, Ontario. The facility began commercial operations in June 2009. Generation from this facility is sold to the IESO pursuant to a PPA that terminates in 2029.

US Wind and Solar Facilities

Antrim

Antrim is a 28.8 MW wind facility consisting of 9 3.2 MW Siemens 113 wind turbines with eight 92.5-metre towers and one 79.5 metre tower that is located in Antrim, New Hampshire. The wind facility was commissioned in December 2019. The wind facility is fully operational and contracted under two long-term PPAs until 2039 with Partners Healthcare and New Hampshire Electric. Ninety-nine per cent of production tax credits are allocated to tax equity partners and the remainder is allocated to TransAlta.

Big Level

Big Level is a 90 MW wind facility consisting of 25 3.6 MW GE wind turbines on 131-metre and 110-metre towers, and is located in Potter County, Pennsylvania. The wind facility was commissioned in December 2019. Generation from the facility is sold under a PPA with Microsoft that terminates in 2034. Ninety-nine per cent of production tax credits are allocated to tax equity partners and the remainder is allocated to TransAlta.

Lakeswind

Lakeswind is a 50 MW wind facility consisting of 32 1.62 MW GE XLE wind turbines on 80-metre towers, and is located near Rollag, Minnesota. The wind facility is fully operational and contracted under a long-term PPA until 2034 with several high-quality counterparties. Ninety-nine per cent of production tax credits are allocated to tax equity partners and the remainder is allocated to TransAlta.

Mass Solar

Mass Solar is a 21 MW solar portfolio consisting of multiple sites located in Massachusetts. The solar facility is contracted under long-term PPAs expiring between 2032 and 2045 with several high-quality counterparties, and the facility generated solar RECs that expired in 2023.

North Carolina Solar

North Carolina Solar is a 122 MW solar portfolio consisting of 20 sites located in North Carolina. The facilities were commissioned between November 2019 and May 2021. The facilities are secured by long-term PPAs with two subsidiaries of Duke Energy, with an average remaining term of 11 years. The PPAs are automatically extended unless terminated by either party.

Skookumchuck

Skookumchuck is a 137 MW wind facility that consists of 38 3.6 MW Vestas V136 wind turbines on 82-metre towers that is located in Lewis and Thurston counties, Washington. The facility began commercial operations in November 2020, and is secured by a long-term PPA with Puget Sound Energy Inc. that expires in 2040. Ninety-nine per cent of production tax credits are allocated to tax equity partners and the remainder are allocated to the Company and our partner Southern Power Company.

Wyoming

Wyoming is a 140 MW wind facility consisting of 78 1.8 MW Vestas V80 (Mark 3) wind turbines on 67-metre towers that is located near Evanston, Wyoming. The facility began commercial operations in December 2003. The wind facility is contracted under a long-term PPA until 2028 with an investment-grade counterparty. The Company is exploring recontracting the facility post-PPA expiry.

TransAlta Corporation • Annual Information Form        30

Australia Battery and Solar Facilities

Northern Goldfields Solar

Northern Goldfields Solar facilities consists of the 27 MW Mount Keith solar facility, 11 MW Leinster solar facility, 10 MW/5 MWh Leinster battery energy storage system facility and interconnecting transmission infrastructure, all of which are integrated into the existing Southern Cross Energy North remote electrical network in Western Australia. The combined solar and energy storage facilities began commercial operations in November 2023 and is contracted with BHP for 16 years. See the "General Development of the Business" section of this AIF for further details.

Facilities Under Construction

We have internal development expertise with teams that are able to manage every aspect and every stage of new project development from resource assessment to site control, permitting, contracting, engineering, construction and project management. Customers are increasingly looking not just to pricing for the procurement of clean electricity, but also to a developer's ability to bring projects through to full completion.

The following table summarizes our wind facilities under construction as at Dec. 31, 2023:

Facility Name	Type	Province/ State	Nameplate Capacity (MW)(1)	Target Commercial Operation Date	Revenue Source
US Facilities
Horizon Hill	Wind	OK	200	Q1 2024	LTC
White Rock	Wind	OK	300	Q1 2024	LTC
Total Facilities Under Construction			500

(1)    MW are estimated and rounded to the nearest whole number.

US Facilities

Horizon Hill

Horizon Hill is a 201.6 MW wind facility located in Logan County, Oklahoma, consisting of 34 Vestas V162 and V136 turbines, of which 33 have 119-metre towers and one has a 105-metre tower, respectively. One hundred per cent of the generation offtake from the project will be sold to Meta, formerly known as Facebook, under a long-term PPA. Under the PPA, Meta will receive both renewable electricity and environmental attributes. The Horizon Hill project is currently under construction with a target commercial operation date in the first quarter of 2024. See the "General Development of the Business" section of this AIF for further details

White Rock East and White Rock West

White Rock East and White Rock West are 201.6 MW and 99.6 MW facilities consisting of 34 and 17 (6.0 MW and 3.6 MW) Vestas wind turbines, of which 49 have 199-metre towers and two have 105-metre towers, respectively, located in Caddo County, Oklahoma. On Dec. 22, 2021, TransAlta executed two long-term Power PPAs with Amazon for the offtake of 100 per cent of the generation from its 300 MW White Rock East and White Rock West wind power projects. The White Rock wind projects are both expected to reach full commercial operation in the first half of 2024. See the "General Development of the Business" section of this AIF for further details.

TransAlta Corporation • Annual Information Form        31

Gas Segment

The Gas segment holds a net capacity ownership interest in 2,775 MW. The facilities are located in Alberta, Ontario, Michigan and Western Australia.

The following table summarizes our natural-gas-fired generation facilities as at Dec. 31, 2023:

Facility Name	Province/ State	Nameplate Capacity (MW)(1)	Consolidated Interest		Gross Installed Capacity(1)	Ownership		Net Capacity Ownership Interest (MW)(1)	Commercial Operation Date	Revenue Source(2)	Contract Expiry Date(3)
Alberta
Fort Saskatchewan(4)	AB	118	60	%	71	50	%	35	1999	LTC/Merchant	2029
Keephills Unit No. 2	AB	395	100	%	395	100	%	395	1984	Merchant	-
Keephills Unit No. 3	AB	463	100	%	463	100	%	463	2011	Merchant	-
Poplar Creek(5)	AB	230	100	%	230	100	%	230	2001	LTC	2030
Sheerness Unit No.1(4)	AB	400	50	%	200	50	%	100	1986	Merchant	-
Sheerness Unit No.2(4)	AB	400	50	%	200	50	%	100	1990	Merchant	-
Sundance Unit No. 6	AB	401	100	%	401	100	%	401	1980	Merchant	-
Total Alberta Gas Capacity		2,407			1,960			1,724
Ontario and US
Ada	MI	29	100	%	29	100	%	29	1991	LTC	2026
Ottawa(4)	ON	74	100	%	74	50	%	37	1992	LTC/Merchant	2033
Sarnia	ON	499	100	%	499	100	%	499	2003	LTC	2031
Windsor(4)	ON	72	100	%	72	50	%	36	1996	LTC/Merchant	2031
Total Ontario and US Gas Capacity		674			674			601
Australia
Fortescue River Gas Pipeline	WA	N/A	100	%	N/A	43	%	N/A	2015	LTC	2035
Parkeston	WA	110	50	%	55	100	%	55	1996	LTC/Merchant	2026
South Hedland	WA	150	100	%	150	100	%	150	2017	LTC	2042
Southern Cross (6)	WA	245	100	%	245	100	%	245	1996	LTC	2038
Total Australian Gas Capacity		505			450			450
Total Gas Capacity		3,586			3,084			2,775

(1)    MW are rounded to the nearest whole number. The gross installed capacity reflects the basis of consolidation of the underlying assets owned, whereas net capacity ownership interest deducts capacity attributable to non-controlling interest in these assets and is calculated after the consolidation of the underlying assets.

(2)    The large majority of the Company’s contracted operating facilities benefit from inflation adjustment provisions that apply to all or a portion of our revenues under such contracts.

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

(4)    Our interests in these facilities are through our ownership interest in TransAlta Cogeneration, LP ("TA Cogen").

(5)    The Poplar Creek facility is operated by Suncor Energy Inc.

(6)    Includes four facilities. Excludes the Northern Goldfields facilities, which are in the Wind and Solar segment.

TransAlta Corporation • Annual Information Form        32

Alberta Gas Facilities

Fort Saskatchewan

We have a net ownership interest of 30 per cent in the Fort Saskatchewan facility. See the "Business of TransAlta - Non-Controlling Interests" section of this AIF for further details. The 118 MW natural gas-fired combined-cycle cogeneration facility is owned by TA Cogen and Prairie Boys Capital Corporation. The contract at the facility has an initial 10-year term, which began on Jan. 1, 2020, with the option for two five-year extensions. The contract allows our customer to continue to benefit from the operational flexibility of the facility. Generation from the facility is currently sold in the Alberta electricity market.

Keephills 2

The Keephills 2 facility is located approximately 70 kilometres west of Edmonton, and is wholly owned by TransAlta. Keephills 2 is a 395 MW gas-fired unit that completed its conversion to natural gas in the spring of 2021, after which commercial operation was announced on July 19, 2021. The end of regulatory life for this unit is set for 2037. Generation from the facility is currently sold in the Alberta electricity market.

Keephills 3

The Keephills 3 facility is located approximately 70 kilometres west of Edmonton, and is wholly owned by TransAlta. Keephills 3 is a 463 MW gas-fired unit that completed its conversion to natural gas in the second half of 2021, after which commercial operation was announced on Dec. 29, 2021. The end of regulatory life for this unit is set for 2039. Generation from the facility is currently sold in the Alberta electricity market.

Poplar Creek

The Poplar Creek cogeneration facility is located in Fort McMurray. The Poplar Creek cogeneration facility had been built and contracted to provide steam and electricity to Suncor's oil sands operations. On Aug. 31, 2015, the Company restructured its contractual arrangement for the facility's power generation services. Under the terms of the arrangement, Suncor acquired the Company's two steam turbines with an installed capacity of 126 MW and certain transmission interconnection assets. In addition, Suncor assumed full operational control of the cogeneration facility and has the right to use the full 230 MW capacity of the Company's gas generators until Dec. 31, 2030. The ownership of the entire Poplar Creek cogeneration facility will transfer to Suncor on Dec. 31, 2030.

Sheerness 1 and 2

The Sheerness facilities are located approximately 200 kilometres northeast of Calgary, and are jointly owned by TA Cogen and Heartland Generation Ltd. Heartland is responsible for the operation and maintenance of these units. On April 4, 2020, Sheerness Unit 2 was converted to natural gas and the unit capacity was increased from 390 MW to 400 MW following a generator rewind and final testing. On March 31, 2021, Sheerness Unit 1 was converted to natural gas. The Sheerness facility received its last coal shipment in the first quarter of 2021, with the coal stock being fully depleted in July 2021. On Nov. 9, 2021, Heartland announced that it had completed the transition off coal at Sheerness. The end of regulatory life for these units is set for 2037. Generation from the facility is currently sold in the Alberta electricity market.

Since Jan. 1, 2021, each owner separately offers their share of generation into the Alberta electricity market. See the "Business of TransAlta - Non-Controlling Interests" section of this AIF for further details.

Sundance 6

The Sundance 6 facility is located approximately 70 kilometres west of Edmonton, and is wholly owned by TransAlta. Sundance 6 is a 401 MW gas-fired unit that completed its conversion to gas in the first half of 2021, after which it announced its commercial operation on Jan. 31, 2021. The end of regulatory life for this unit is set for 2037. Generation from the facility is currently sold in the Alberta electricity market.

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Off-Coal Agreement

On Nov. 24, 2016, we entered into the Off-Coal Agreement with the Government of Alberta pertaining to our cessation of emissions from the Keephills 3 and Sheerness coal-fired facilities. Under the Off-Coal Agreement we are entitled to receive annual cash payments of approximately $37.4 million, net to TransAlta, from the Government of Alberta that commenced in 2017, and will terminate in 2030, subject to satisfaction of certain terms and conditions including our cessation of all coal-fired emissions on or before Dec. 31, 2030. Other conditions include maintaining prescribed spending on investment and investment-related activities in Alberta, maintaining a significant business presence in Alberta (including through the maintenance of prescribed employment levels), maintaining spending on programs and initiatives to support the communities surrounding the facilities and the employees of the Company negatively impacted by the phase-out of coal generation, and the fulfilment of all obligations to affected employees, in each case as prescribed by the Off-Coal Agreement.

Eastern Canada and US Gas Facilities

Ada

Ada is a 29 MW contracted cogeneration facility located in Ada, Michigan. The facility has been in operation since 1991, and produces approximately 18,000 tonnes of steam hourly. The electricity and steam output of the facility are fully contracted until 2026 with Consumers Energy and Amway, and the Company is seeking to recontract the facility.

Ottawa

The Ottawa facility is owned by TA Cogen. See the "Business of TransAlta - Non-Controlling Interests" section of this AIF for further details. It is a 74 MW combined-cycle cogeneration facility located in Ottawa, Ontario. On Aug. 30, 2013, the Company announced the recontracting of the facility with the IESO for a 20-year term, effective January 2014. The Ottawa facility also provides thermal energy to the member hospitals and treatment centres of the Ottawa Health Sciences Centre and the National Defence Medical Centre. The thermal energy contract with the Ottawa Health Sciences Centre has a term to Dec. 31, 2033, with an automatic renewal of a five-year term unless terminated by either party.

Sarnia

The Sarnia cogeneration facility is a 499 MW combined-cycle cogeneration facility located in Sarnia, Ontario, that provides power and/or steam to nearby industrial facilities owned by ARLANXEO Canada Inc. (formerly LANXESS AG, successor to Bayer Inc.); Nova Chemicals Corporation (Canada) Ltd., INEOS Styrolution Canada Ltd., a styrene production facility formerly owned by NOVA; Suncor Energy Products Partnership; Bitfury Holding BV, a full service blockchain technology company; and three new industrial customers. The contracts with the new customers are with respect to loads that had previously been supplied to and resold by ARLANXEO and TransAlta administers the contact in relation to sub-customers. The facility also provides electricity to the IESO under a contract that terminates on April 30, 2031, with the industrial customer contract terminations occurring from April 30, 2031, through December 31, 2032. The gross margin from the Sarnia cogeneration facility has been reduced by approximately 30 per cent as a result of the IESO price cap under the new contract.

Windsor

The Windsor facility is owned by TA Cogen. See the "Business of TransAlta - Non-Controlling Interests" section of this AIF for further details. It is a 72 MW combined-cycle cogeneration facility located in Windsor, Ontario. Effective Dec. 1, 2016, the Windsor facility began operating under an agreement with the IESO with a 15-year term for up to 72 MW of capacity. The Windsor facility also provides thermal energy to Stellantis Canada (formerly, FCA Canada, Inc. and Chrysler Canada) in Windsor under a contract that expires in 2028, with a series of six successive renewal terms of one year each. 

Australian Gas Facilities

Fortescue River Gas Pipeline

In 2014, we established the Fortescue River Gas Pipeline joint venture with AGI Fortescue River Pty Limited, formerly known as DBP Development Group. The joint venture (of which TransAlta is a 43 per cent partner) was successfully awarded the contract to design, build, own and operate the 270-kilometre Fortescue River Gas Pipeline, located in the Pilbara region of Western Australia, to deliver natural gas to Fortescue Metal Group's ("FMG") Solomon facility. The pipeline was completed in the first quarter of 2015 and operates under a take-or-

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pay gas transport agreement with a subsidiary of FMG for an initial term of 20 years. The 16-inch diameter pipeline has an initial free-flow capacity of 64 terajoules per day. Under the gas tariff agreement, FMG has the option to purchase the Fortescue River Gas Pipeline commencing March 2020. FMG maintains its option and the joint venture continues to deliver natural gas transportation to the Solomon facility.

Parkeston

The Parkeston facility is a 110 MW dual-fuel natural gas and diesel-fired power station located near Kalgoorlie, Western Australia, which is owned in partnership through a 50/50 joint venture with Northern Star (NPK) Pty Ltd., a subsidiary of Northern Star Resources Limited. The Parkeston facility primarily supplies energy to Kalgoorlie Consolidated Gold Mines pursuant to a supply contract that extends to October 2026, with options for early termination available to either party. We are evaluating potential opportunities to renew or extend the supply contract. Any merchant capacity and energy are sold into Western Australia's wholesale electricity market.

South Hedland

The South Hedland Power Station is a 150 MW combined-cycle power station located near South Hedland, Western Australia. Construction began in early 2015 and the plant achieved commercial operation on July 28, 2017. The facility is contracted with two customers until 2042. Capacity of 110 MW is contracted to Horizon Power to 2042. Horizon Power is the state-owned electricity supplier in the region. The second customer is the port operations of FMG for 35 MW of capacity.

Southern Cross Energy

Southern Cross Energy Partnership ("SCE") has power stations at Mount Keith, Leinster, Kalgoorlie and Kambalda. Each of the four sites has an LM6000 gas turbine. A TM2500 turbine is also located at Mount Keith. Backup diesel generation is located at both Mount Keith and Leinster. In total, a combined gas and diesel-fired capacity of about 240 MW is available from these facilities. In 2023, SCE added battery and renewable energy capacity to the SCE fleet with separate solar facilities at Leinster (11 MW) and Mount Keith (27 MW), as well as a battery energy storage system at Leinster (10 MW/5 MWh).

The PPA with BHP for the facilities was amended in 2020, which includes an extension of the term of the PPA to Dec. 31, 2038, and a restructuring of the PPA that results in the traditional capacity payment being removed as of 2024. From 2024, the main payments under the PPA that SCE receives consist of (a) an annual payment to provide operations and general maintenance of the facility, (b) an agreed margin on all life extension and major maintenance work performed on the assets, and (c) capacity charges from all new-build assets such as the new solar farms. In 2024, this change in payment structure is expected to result in a decrease in capacity charge revenues of approximately AU$51 million partially offset by increases in new-build asset charges, such as for the Northern Goldfield solar facilities commissioned in November 2023 and the Mount Keith 132kV expansion project. In addition, the PPA provides SCE with the exclusive right to supply electricity and transmission and distribution infrastructure from the SCE facilities for BHP's mining operations located within a specified area in the Goldfields region of Western Australia for the duration of the PPA.

The PPA supports BHP's future power requirements and emission reduction targets by providing BHP participation rights in integrating renewable electricity generation, including solar, wind and energy storage technologies, into BHP's mining operations located in the Goldfields region, subject to the satisfaction of certain conditions. New-build projects have already been completed under this contract, including the Northern Goldfields solar and battery project in Mount Keith and Leinster that reached commercial operation in November 2023. Additional projects are in the development and construction stages. See the "General Development of the Business" section of this AIF for further details.

Evaluation of additional renewable energy supply and carbon emissions reduction initiatives under the extended PPA with BHP are underway.

Facility Under Construction

The following project is approved by the Board of Directors, has an executed PPA and is currently under construction or in the process of being commissioned.

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The following table summarizes our transmission expansion that is under construction as at Dec. 31, 2023:

Facility Name	Type	Province/ State	Nameplate Capacity (MW)	Target Commercial Operation Date	Revenue Source
Mount Keith 132kV Expansion	Transmission	WA	N/A	Q1 2024	LTC

Mount Keith 132kV Expansion

The Mount Keith 132kV transmission project is currently under construction and is located near Mount Keith, Western Australia. Southern Cross Energy is completing the expansion of the Mount Keith 132kV transmission system to support the BHP's Northern Goldfields-based operations. The project is being developed under the existing 15 year PPA with BHP. The project will facilitate the connection of additional generating capacity to our network to support BHP's operations and increase BHP's competitiveness as a supplier of low-carbon nickel. It is expected to be completed in the first quarter of 2024. See the "General Development of the Business" section of this AIF for further details.

Energy Transition Segment

The Energy Transition segment holds a net ownership interest in 671 MW. The two facilities are located in the US.

The following table summarizes our energy transition facilities as at Dec. 31, 2023:

Facility Name	Province/ State	Nameplate Capacity (MW)(1)	Consolidated Interest		Gross Installed Capacity(1)	Ownership		Net Capacity Ownership Interest (MW)(1)	Commercial Operation Date	Revenue Source	Contract Expiry Date
US
Centralia	WA	670	100	%	670	100	%	670	1971	LTC/Merchant	2025
Skookumchuck(2)	WA	1	100	%	1	100	%	1	1970	LTC	2025
Total Energy Transition Capacity		671			671			671

(1)MW are rounded to the nearest whole number. The gross installed capacity reflects the basis of consolidation of underlying assets owned, whereas net capacity ownership interest deducts capacity attributable to non-controlling interest in these assets and is calculated after consolidation of underlying assets.

(2)    This facility is used to provide a reliable water supply to the Centralia facility.

Centralia

The Centralia coal-fired facility is located in Washington, US, and consists of one 670 MW unit.

On July 25, 2012, we announced that we entered into an 11-year PPA to provide electricity from our Centralia thermal facility to Puget Sound Energy. The contract terminates in 2025 when the facility is scheduled to stop burning coal. Under the agreement, Puget Sound Energy purchases 380 MW of baseload power to December 2024 and 300 MW in 2025. The coal used to fuel the Centralia facility is sourced from the Powder River Basin in Montana and Wyoming. The Centralia facility has coal contracts in place that expire at the end of 2025.

We sell electricity from the Centralia thermal facility into the Western Electricity Coordinating Council and, in particular, to the US Pacific Northwest electricity market. Our strategy is to balance contracted and non-contracted sales of electricity to manage production and price risk.

On July 30, 2015, we announced that we will invest US$55 million over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State. The initiative is part of Centralia's transition from coal-fired operations in Washington, beginning on Dec. 31, 2020. The US$55 million community investment is part of the TransAlta Energy Transition Bill (chapter 180, Laws of 2011) (the "Bill''). The Bill was an agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State. As at Dec. 31, 2023, we have fully funded the US$55 million commitment.

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Skookumchuck Hydro

We own a 1 MW hydroelectric generating facility that is located on the Skookumchuck River near Centralia, Washington, and related assets that are used to provide water supply to our generation facilities in Centralia. On Dec. 7, 2020, we entered into a PPA with Puget Sound Energy for the Skookumchuck hydro facility. The contract terminates in 2025 when the facility is scheduled to retire.

Reclamation Activities

Centralia Mine

We own a coal mine adjacent to the Centralia facility, although mining operations were discontinued at the Centralia coal mine on Nov. 27, 2006. The mine is currently in the reclamation phase and we continue to perform reclamation and associated work.

Under the US Federal Mine Safety and Health Act, we must report all citations at our Centralia mine. There was one injury incident reported at the mine during 2023. The total dollar value of all Mine Safety and Health Administration ("MSHA") assessments is not material.

Mine or Operating Name/MSHA Identification Number	Total Number of Section 104 Violations for which Citations Received	Total Number of Orders Issued Under Section 104(b))	Total Number of Citations and Orders for Unwarrantable Failure to Comply with Mandatory Health or Safety Standards Under Section 104(d)	Total Number of Flagrant Violations Under Section 110(b)(2)	Total Number of Imminent Danger Orders Issued Under Section 107(a)	Total Dollar Value of MSHA Assessments Proposed	Total Number of Mining Related Fatalities	Received Notice of Pattern Violations Under Section 104(e) (yes/no)	Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no)	Number of Legal Actions Initiated or Pending During Period
4500416	10(1)	0	0	0	0	1,430 (2)	0	No	No	0

(1)    Section 104 Violations: TransAlta Centralia Mining (9 violations) and Dickson Company (contractor) (1 violation).

(2)    Citations in Contest: Coalview Centralia LLC ($1,287) and Dickson Company ($143).

Highvale Mine

We own the Highvale mine that supplied coal to the previously coal-fired Sundance and Keephills facilities. As part of the Clean Electricity Growth Plan, the Company discontinued all mining operations at the Highvale mine at the end of 2021 and the mine is currently in the reclamation phase as of Jan. 1, 2022.

Coal Retirements

In aggregate, TransAlta has retired 4,464 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to cleaner-burning natural gas. The following seven units have been retired: Centralia Thermal No. 1, Keephills 1, and Sundance 1, 2, 3, 4 and 5. The retirements remain consistent with our strategy to transition to clean electricity. Pursuant to the Bill, Centralia Unit 2 will retire effective Dec. 31, 2025.

Energy Marketing Segment

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

•Gathering and analyzing market trends to enable more effective strategic planning and decision-making;

•Actively engaging in the trading of power, natural gas and environmental products across a variety of North American markets, excluding Alberta;

•Negotiating and managing fuel supply arrangements with third parties for our generation assets, including scheduling, billing and settlement of physical deliveries of natural gas and other fuels; and

•Negotiating and entering into contractual agreements with customers for the sale of output from our generation assets outside of Alberta, including electricity, steam or other energy-related commodities.

The Energy Marketing segment derives all of its revenue by trading electricity and other energy commodities (i.e., fuels and environmental products), by providing fee-based asset management services to third parties and earning margins on third-party gas and power transactions. The origination and trading activities are primarily focused on proprietary trading, with additional focus on the existing assets and customers of the Company.

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The key risk control activities of the Energy Marketing segment include the measurement and management of market, credit, operational, reputational, compliance and legal risks. The segment uses value at risk, gross margin at risk and tail risk measures to monitor and manage the risks within our asset and trading portfolios. Value at risk and gross margin at risk measure the potential losses that could occur over a given time period due to changes in market risk factors. Back tests are used to provide further sensitivities to the market risks within the portfolio. Compliance, goodwill and legal risks are managed within our legal and compliance policies, and monitoring tools are used to flag compliance risks. The Energy Marketing segment actively manages the risks within approved limits of our governance policies.

Corporate Segment

Our Corporate segment includes the Company's finance, sustainability, legal, human resources, administrative, business development and investor relations functions.

Non-Controlling Interests

Our subsidiaries and operations in which we have non-controlling interests are as follows:

TA Cogen

We hold a 50.01 per cent limited partnership interest in TA Cogen, which is an Ontario limited partnership. The remaining 49.99 per cent ownership is held by CPH Cogen Inc., a subsidiary of CK Infrastructure Holdings Limited.

TA Cogen holds a 50 per cent interest in the 800 MW Sheerness dual-fuel generating facility in Alberta and a 60 per cent interest in the 118 MW Fort Saskatchewan natural-gas-fired cogeneration facility in Alberta. TA Cogen also holds an interest in two natural-gas-fired cogeneration facilities located in Ontario: the 74 MW Ottawa plant and the 72 MW Windsor plant. See the "Gas Segment" section of this AIF for further details.

Kent Hills Wind LP

We hold an 83 per cent partnership interest in Kent Hills Wind LP, which owns and operates the 167 MW Kent Hills (1, 2 and 3) wind facilities located in New Brunswick. As at Dec. 31, 2023, the Company owned 83 per cent of Kent Hills Wind LP, with the remaining 17 per cent being held by Natural Forces Technologies Inc., a wind developer based in Atlantic Canada that helped develop the Kent Hills wind projects with TransAlta.

TransAlta Renewables

Prior to Oct. 5, 2023, we held a 60.1 per cent interest in TransAlta Renewables. 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. On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. TransAlta Renewables is now a wholly owned subsidiary of the Company. See the "Three Year History" section of this AIF for further details.

Competitive Environment

Power generation is an industry in the midst of an exciting transformation and the demand for electricity is expected to grow significantly over the long- term. We also anticipate the generation mix to undergo a major shift in our key markets. In addition to the need to keep pace with ongoing demand growth for electricity, there are several key factors driving the need for significant investment in new generating capacity, which include, without limitation:

•Coal-based generation is being retired. These retirements are being driven by asset age, as well as government policy that places an escalating price on GHG emissions and, in some cases, mandates the retirement of these assets;

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•Government policies that impose costs or provide incentives for lower emission technologies are creating opportunities for renewable generation technologies. These opportunities are coinciding with a significant decline in the installed costs of wind and solar generation and battery storage. As a result, these technologies now account for the majority of the new generating capacity added to many of the world's electricity grids; and

•Electrification is seen as one of the most effective levers to reduce GHG emissions in many sectors, such as transportation. We expect that renewable power generation will continue to be one of the fastest-growing sources of power generation in Canada, the US and Australia.

Alberta

Approximately 53 per cent of our gross installed capacity is located in Alberta. As of Dec. 31, 2023, our portfolio of merchant assets in Alberta is a combination of hydro facilities, wind facilities, a battery storage facility and co-fired 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. In order to reduce the exposure from variable spot power prices on our merchant generation, we will enter in financial hedges and/or physical retail supply contracts through our Commercial and Industrial Business. The combined liquidity provided by these channels enables us to actively secure revenue, and also to respond to changing market conditions and adjust the proportion of our hedges we have in relation to the expected generation from our asset portfolio.

Alberta's annual electricity demand was flat from 2022 to 2023. There was a significant negative impact on demand due to the wildfires in 2023 and weather-driven demand in the third and fourth quarters of 2022 was more significant than 2023. Those factors contributed to a decrease in the average pool price in Alberta from $162/MWh in 2022 to $134/MWh in 2023. Although pool prices were higher in the first half of 2023 compared to 2022 due to stronger prices in adjacent markets and lower available import capacity, they were lower during the second half of 2023 when weather-driven demand was not as pronounced as in 2022.

We expect additional compliance costs as a result of the Canadian federal government’s Greenhouse Gas Pollution Pricing Act, which sets a national price on GHG emissions with each province expected to implement a GHG policy equivalent to a carbon price of $170 per tonne by 2030. We believe our portfolio of assets provides us with brownfield development opportunities in wind, solar, hydro and gas that give us an advantage over competitors when constructing generation facilities that use these fuel types.

US Pacific Northwest

Our generating capacity in the US Pacific Northwest includes the remaining Centralia coal unit and our 49 per cent interest in the Skookumchuck wind facility. The Centralia coal unit is committed to be phased out within the next two years with the plant capacity scheduled to be legislatively retired on Dec. 31, 2025.

System capacity in the region is primarily composed of hydro and gas generation, with some wind additions over the last few years in response to government programs favouring renewable generation. Demand growth in the region has been limited and further constrained by an emphasis on energy efficiency. We expect to see significant change in this market over the next decade as coal generation is retired and renewable portfolio standard requirements continue to strengthen.

Our competitiveness is enhanced by our long-term contract with Puget Sound Energy for up to 380 MW over the remaining life of the Centralia facility (dropping to 300 MW in 2025). The contract and our hedges allow us to satisfy power requirements from the market during low-priced periods. The Centralia site also holds potential value for future redevelopment opportunities given its access to existing infrastructure and transmission interconnection.

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Australia

Our business is solely in Western Australia, and is focused on the large, remote mining industry in that state. The primary exports from Western Australia are iron ore, nickel and gold. Iron ore exports from Western Australia are forecasted to rise, driven by large-scale producers ramping up production with new mines. Remote mining operations are exploring options to add renewable generation to their existing and new sites in an effort to reduce the amount of gas and diesel required in these operations. Our SCE facilities in the Goldfields region have a number of projects in development under our extended contractual arrangement to support BHP in achieving its decarbonization objectives. We expect this trend to continue and to create further opportunities for our business in Western Australia.

Contracted Gas and Renewables

We develop and acquire gas and renewable generation facilities in highly competitive markets. Our track record as an experienced operator and developer supports our competitive position. We try, where possible, to reduce our cost of capital and improve our competitive profile through efficient financing structures. In the US, our substantial tax attributes further increase our competitiveness.

In renewables, we are primarily evaluating greenfield opportunities in Western Canada and the US along with acquisitions in markets where we have existing operations. We maintain highly qualified and experienced development teams to identify and develop these opportunities. In cogeneration, we are working with customers to evaluate behind-the-fence solutions.

Some of our older gas facilities are now reaching the end of their original contract life. These facilities generally have a substantial cost advantage over new builds and we have been able to add value by recontracting these facilities without incurring the significant capital expenditures required for a new facility.

Seasonality and Cyclicality

Our business is cyclical due to: (a) the nature of electrical generation and the limited storage capacity; and (b) the nature of wind, solar and run-of-river hydroelectric resources, which fluctuate based on both seasonal patterns and annual weather variation.

Typically, run-of-river hydroelectric facilities and solar facilities generate most of their electricity and revenues during the spring and summer months when the melting snow starts feeding the watersheds and the rivers, and the sun is at its highest peak. Inversely, wind speeds are historically greater during the cold winter months when the air density is at its peak. Our strategy of technological and geographical diversification reduces our exposure to the variations of any one natural resource in any one region. Financial results in any one quarter may not, however, be representative of all quarters. See the "Risk Factors" section of this AIF for further details.

Regulatory Framework

Below is a description of the regulatory framework in the markets that are material to the Company.

Canadian Federal Government

In November 2016, the Canadian federal government announced that coal-fired generation would be phased out by 2030, following a similar commitment by the Alberta provincial government in November 2015. On Dec. 12, 2018, Environment and Climate Change Canada ("ECCC") published two final regulations in the Canada Gazette, Part II to phase out coal-fired generation by 2030, as well as regulations for gas-fired electricity generation including provisions for the conversion of boiler units from coal-fired generation to natural gas-fired generation. See the "Environmental Risk Management - Climate-Related Financial Disclosure" section of this AIF for further details.

Regulatory changes are not expected to have a material impact in the near-term on generation from our facilities in New Brunswick, British Columbia and Québec as generation from these facilities is fully contracted to creditworthy counterparties.

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Alberta

Alberta remains an energy-only market where generators make power supply offers that clear against power demand. The demand and supply dynamics determine market clearing prices. On Aug. 3, 2023, the Government of Alberta announced the pause on the issuance of new power plant approvals for new renewable electricity generation projects over one megawatt. This pause is planned to be lifted on Feb. 29, 2024. The AESO is also progressing its Market Pathways initiative to identify future market design options and make recommendations to the Government by the second quarter of 2024. The AESO's initiative is expected to enter an implementation phase in the second quarter of 2025.

Ontario

Ontario's electricity market is a hybrid market that includes a wholesale electricity market, as well as regulated prices for certain electricity consumers and long-term contracts for the purchase of power by the IESO from power producers. The Ontario Ministry of Energy supports the IESO in defining the electricity mix to be procured by the IESO. The IESO has the mandate to undertake long-term planning of the electric power system, procure the electricity generation in that plan and manage contracts for privately owned generation. The IESO is responsible for managing the Ontario wholesale market and ensuring the reliability of the electricity system in Ontario. The electricity sector is regulated by the Ontario Energy Board.

The IESO is currently in the stages of settlement rules testing and market manual and rule development to implement the market renewal program. The program includes the introduction of a day-ahead market, locational pricing, enhanced unit commitment and market power mitigation. Implementation of market renewal is planned for the second quarter of 2025. The impacts on existing facilities is mitigated due to existing contracts. The IESO is coordinating its changes to its energy market with new resource adequacy procurements, including medium- and long-term requests for proposals ("RFP"), re-contracting with existing facilities (small hydro re-contracting) and improving market operations and reliability. Our Ontario facilities are generally contracted, and therefore we expect market rule changes to have minimal near-term impact on the Company.

US Wholesale Power Market

The Federal Power Act gives the Federal Energy Regulatory Commission ("FERC") rate-making jurisdiction over public utilities engaged in wholesale sales of electricity and the transmission of electricity in interstate commerce. FERC oversees the market structure for all integrated market rules and wholesale sales from generators. The Federal Power Act also provides FERC with the authority to certify and oversee an electric reliability organization that promulgates and enforces mandatory reliability standards applicable to all users, owners and operators of the bulk-power system. FERC has certified the North American Electric Reliability Corporation ("NERC") as the electric reliability organization. NERC has promulgated mandatory reliability standards and, in conjunction with the regional reliability organizations that operate under FERC's and NERC's authority and oversight, enforces those mandatory reliability standards.

Regulatory changes are not expected to have a material impact in the near term on generation from our facilities in Minnesota, Massachusetts, New Hampshire, North Carolina, Oklahoma, Pennsylvania and Wyoming as generation from these facilities is fully contracted to creditworthy counterparties.

Washington

Centralia and Skookumchuck are operated in Washington State. The Washington Transportation and Utilities Commission ("WTUC") has the power to regulate and supervise every "public utility," which includes investor-owned electric utilities. For regulated electric utilities, the WTUC approves regulated rates, reviews integrated resource plans, approves mergers and acquisitions ("M&A") and grants certificates of public convenience and necessity for large facilities (i.e., power plants and transmission lines). The Centralia facility, the Skookumchuck hydro facility and the Skookumchuck wind facility are not regulated by the WTUC as they only sell wholesale electricity and do not sell retail electricity in the state. Only FERC and NERC requirements apply to these facilities. As a result, the Company does not expect any material impacts on revenue streams from any decisions of the WTUC.

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Australia

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

The Australian Energy Market Operator is the market operator for both the WEM and the NEM. The two markets are completely independent of each other with different market rules and no physical interconnection between them. The WEM includes both a market for generation capacity and a gross pool to trade energy with a single reference node for wholesale prices. The NEM is a pure energy-only market with five regional reference nodes for wholesale prices corresponding to each of the participating states of Queensland, New South Wales, Victoria, Tasmania and South Australia.

In October 2023, significant reforms to the WEM were implemented, including security constrained dispatch in the energy market and the introduction of additional ancillary services to support the transition to renewable energy sources.

Reforms to the NWIS have been gradually implemented, including providing third-party access to the transmission networks, coordination of outage planning and ensuring generation adequacy.

Environmental Risk Management

We are subject to federal, provincial, state and local environmental laws, regulations and guidelines concerning the generation and transmission of energy. We are committed to complying with legal requirements and to minimizing the environmental impact of our operations. We work with governments, stakeholders and the public to develop appropriate frameworks to protect the environment, as well as to promote sustainable development.

Climate-Related Financial Disclosure

We have prepared an assessment of climate-related risks and opportunities to align with the IFRS S2 Climate-related Disclosures Standard and Task Force on Climate-related Financial Disclosure describing our climate change strategy, governance, risk management approach, metrics and targets. In 2023, we reviewed and updated our climate transition plan and prepared climate-related financial metrics. See the "Environmental, Social and Governance" section of the 2023 Integrated Report for further details.

Canadian Federal Government

Federal Carbon Pricing and Regulations on GHG Emissions

On June 21, 2018, the Canadian Federal Greenhouse Gas Pollution Pricing Act ("GGPPA") came into force. Under the GGPPA, the Canadian federal government implemented a national price on GHG emissions. In April 2021, the Government of Canada announced a revised GHG emissions target of 40 to 45 per cent below 2005 levels by 2030. Amendments to the GGPPA were completed in October 2022 to align facility emission charges with the government's updated carbon price trajectory of $65 per tonne of CO2e in 2023 with increases of $15 per year to $170 per tonne by 2030.

In March 2022, the Government of Canada’s Department of ECCC released a discussion document regarding the Clean Electricity Regulations ("CER") to achieve a net-zero electricity sector in Canada by 2035. It is expected to be promulgated under the Canadian Environmental Protection Act. The draft CER was published in Canada Gazette I in August 2023. We continue to engage with ECCC directly and via our trade association to seek an appropriate balance of system reliability, affordability and emissions reductions from the regulations. The final regulations from Canada Gazette II are expected to be published later in 2024.

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In addition to carbon pricing and the CER, the Canadian federal government continues to further develop federal incentives for renewable generation and new and emerging technology and infrastructure. We continue to actively engage with the Canadian federal government to understand the implications of these initiatives to our business in order to manage risks and identify opportunities.

Regulatory Framework for an Oil and Gas Sector Greenhouse Gas Emissions Cap

In December 2023, the Canadian federal government introduced a draft framework to cap emissions from the oil and gas sector. Consultation on the draft framework is currently underway with draft regulations anticipated by mid-2024. The interplay between the proposed cap-and-trade system and regulations like TIER remains unclear. Given that the use of provincial offsets as a compliance mechanism has implications for TransAlta, we will continue to follow developments and engage where appropriate in the development of the framework.

Alberta

Large Emitter Greenhouse Gas Regulations

Facilities with emissions above the set benchmark must comply with TIER by: (a) paying into the TIER Fund (a provincial government-controlled fund that invests in emissions reduction in the province) at the current carbon price; (b) making reductions at their facility; (c) remitting EPCs from other facilities; or (d) remitting emission offset credits.

On Dec. 15, 2022, amendments to TIER and the Administrative Penalty Regulation were announced following approval from the Canadian federal government, which included the following changes:

•TIER fund schedule via a Ministerial Order for the 2023 to 2030 period from $65 per tonne of carbon dioxide equivalent (CO2e) in 2023, and increasing by $15 per tonne CO2e annually to $170 per tonne CO2e by 2030;

•Starting in 2023, a two per cent annual tightening rate will apply to the electricity high performance benchmark from 0.3626 tonnes CO2e per MWh in 2023 to 0.3108 CO2e tonnes per MWh by 2030;

•The maximum allowable emissions offsets, emissions performance standards or sequestration credits that can be used by a given facility in a year was set to 60 per cent in 2023, 70 per cent in 2024, 80 per cent in 2025, and 90 per cent in 2026 and beyond; and

•EPCs issued in 2023 or a subsequent year may only be used within the five-year period after the EPC was issued, while offsets may only be used within a six-year period, including the reduction year.

These changes will result in lower emissions crediting for new renewables projects but, all things being equal, should also result in higher demand for emissions credits from TransAlta's renewables facilities. TransAlta's gas-fired facilities will face more stringent performance standards. TIER will remain in effect through 2030, and will be reviewed on or before Dec. 31, 2026.

Ontario

Large Emitter Greenhouse Gas Regulations

As of Jan. 1, 2022, the Emissions Performance Standards ("EPS") system applies in Ontario and the federal Output Based Performance Standards no longer directly applies to covered emitters.

In December 2022, Ontario announced changes to the EPS that were approved by the Canadian federal government. Two electricity-related changes will impact TransAlta's gas-fired facilities in Ontario:

•Changing the electricity performance standard from 0.37 tonnes CO2e per MWh in 2022 to 0.31 tonnes CO2e per MWh starting in 2023, remaining flat to 2030; and

•Allowing cogeneration units to utilize separate performance standards for electricity and heat to enable a level playing field for all electricity under the EPS.

The change in cogeneration performance standard treatment will benefit TransAlta's facilities by removing a previous, single cogeneration standard that was more stringent than utilizing separate standards for heat and electricity. The value from this change flows to contracted customers but helps make cogeneration more competitive as an energy solution.

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Ontario is continuing its work on the natural gas transition and has developed a voluntary clean energy credit market for assets directly connected to the IESO grid or a distribution system. TransAlta will continue to engage the government on relevant policy initiatives to mitigate risk and identify areas of potential opportunity.

United States

The US government has set out ambitious objectives for carbon emissions reductions, including achieving a 50 to 52 per cent national emissions reduction below 2005 levels by 2030, a net-zero electricity grid by 2035 and a net-zero national economy by 2050. Although the US does not have a national carbon pricing regime, it does offer significant federal incentives for renewable generation and new technology and infrastructure, including spending under the Inflation Reduction Act.

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.

Washington State

Large Emitter Cap and Trade Program

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

On May 17, 2021, Governor Inslee signed Washington State's Climate Commitment Act ("CCA"). which came into effect on Jan. 1, 2023. This law covers entities that emit over 25,000 tonnes of CO2e per year. It creates a “cap-and-invest” program, which sets a state-wide cap on greenhouse gas emissions and then auctions or allocates emissions allowances. TransAlta’s Centralia facility will be exempt from the cap-and-invest program until it closes in 2025, as per the agreement with the state of Washington. The Washington Department of Ecology held quarterly auctions for compliance all through 2023. The auctions offered year 2023 vintage allowances. TransAlta continues to track the cap and invest program as it develops and moves into its second year of implementation. We will engage when necessary with relevant government departments should there be any future implementation changes that impacts our operations or energy trading in Washington.

Australia

In October 2021, the Australian government announced a target to reach net-zero emissions by 2050. Following the May 2022 federal election, the newly elected Labor government enacted a more ambitious near-term target through the Climate Change Act 2022, which commits Australia to a 43 per cent emissions reduction below 2005 levels by 2030. The government also confirmed its intent to boost renewable electricity production to 82 per cent of electricity supply by 2030. Large GHG emitters are required to reduce their scope 1 emissions under the Australian Government's National Safeguard Mechanism ("SGM"). While the government made recent changes to the SGM, these changes are not expected to have a material impact on TransAlta's assets.

The Australian government’s plan to achieve the necessary reductions is focused on a combination of technology development and cost reduction, enabling deployment at scale through incentives and infrastructure development as well as updating some of its regulatory mechanisms. In particular, an AU$20 billion fund has been set aside to support infrastructure investment, such as transmission network reinforcement, and enable the shift to renewables. Decarbonization efforts have been centred on funding for clean technologies, upgrading the electricity grid to support more renewables, regulating and reporting of GHGs, and incentivizing zero-emission vehicle adoption.

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Australian state-level policies continue to focus on moving toward greater reliance on renewables, hydrogen and energy storage and away from coal.

TransAlta does not see any significant risk to our existing Australian assets. Policy and funding supporting continued industrial decarbonization could provide additional growth opportunities in the Australian market.

TransAlta Activities

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

Our environmental management programs include the elements summarized below:

Environmental Management Systems

Our facilities operate in line with best practices related to environmental management standards. Our environmental management system ("EMS") processes are verified annually to ensure we continuously improve our environmental performance. Our knowledge of EMS has matured since we aligned our processes in accordance with the internationally recognized ISO 14001 standard. Currently, the most material natural or environmental capital impacts to our business are GHG emissions, air emissions (i.e., pollutants) and energy use. Other material impacts that we manage and track performance on using our EMS practices include land use, water use and waste management.

Renewable Power

We continue to invest in and build renewable power resources.

•In November 2023, the 48 MW Northern Goldfields solar and battery storage facilities in Western Australia achieved commercial operation. The facilities consist of the 27 MW Mount Keith solar facility, 11 MW Leinster solar farm and 10 MW/5 MWh Leinster battery energy storage system and interconnecting transmission infrastructure.

•In August 2023, the Garden Plain wind facility in Alberta was commissioned adding 130 MW to our gross installed capacity. The facility is fully contracted with Pembina Pipeline Corporation (100 MW) and PepsiCo Canada (30 MW).

•In April 2022, we entered into a long-term PPA with Meta for the offtake of 100 per cent of the generation from the 200 MW Horizon Hill wind project located in Oklahoma.

•In December 2021, we entered into two long-term PPAs with Amazon for the offtake of 100 per cent of the generation from our 300 MW White Rock East and White Rock West wind projects located in Oklahoma.

•In November 2021, we completed the construction of the 206 MW Windrise wind facility and achieved commercial operation.

•In November 2021, we acquired the 122 MW North Carolina Solar facility.

In addition, we have developed policies and procedures to comply with regulations and to lessen any environmental disruption caused by our renewable power resources, which include monitoring noise and avian impacts at our wind generation facilities.

Environmental Controls and Efficiency

We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity.

•In the US, the remaining coal unit at Centralia is set to retire on Dec. 31, 2025.

•Effective Jan. 1, 2022, we discontinued the firing of coal in Canada.

•On Dec. 31, 2021, Keephills Unit 1 was retired and, on April 1, 2022, Sundance Unit 4 was retired.

•We have retired our Sundance Unit 5 coal unit and suspended our plan to repower the unit with natural gas.

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•At the end of 2021, we successfully completed the transition of our coal units in Alberta to natural gas.

•The Keephills Unit 3 conversion to natural gas began during the third quarter of 2021 and was completed in December 2021.

•In early 2021, Keephills Unit 2, Sundance Unit 6 and our non-operated Sheerness Unit 1 completed their conversions to natural gas, resulting in all these units now running solely on natural gas.

The combination of these actions has significantly reduced environmental impacts from air emissions, GHG emissions, water usage and land disturbance, and reduced energy usage at the respective facilities. For example, we have reduced scope 1 and 2 GHG emissions by 21.3 million tonnes of CO2e or (66 per cent) since 2015. See the "Environmental, Social and Governance" section of the 2023 Integrated Report for further details.

Emission Offset Portfolio

TransAlta maintains a GHG emission offset portfolio with a variety of instruments that can be used for compliance purposes or otherwise banked or sold. We continue to examine additional emission offset opportunities that also allow us to meet our emission compliance obligations at a competitive cost. We invest in offsets that we expect will meet certification criteria in the market in which they are to be used.

Environmental Regulations

Recent or future changes to environmental laws or regulations may materially adversely affect us. See the "Risk Factors" section of this AIF for further details and the "Governance and Risk Management" section of our annual Management's Discussion and Analysis for the year ended Dec. 31, 2023. Many of our activities and properties are subject to environmental requirements, as well as changes in our liabilities and obligations under these requirements, which may have a material adverse effect upon our consolidated financial results, operations or performance.

Risk Factors

Readers should consider the risk factors set forth below as well as the other information contained and incorporated by reference in this AIF. For a further discussion of risk factors affecting TransAlta, see the "Governance and Risk Management" section of our annual Management's Discussion and Analysis for the year ended Dec. 31, 2023, which is incorporated by reference herein.

A reference herein to a material adverse effect on the Company means such an effect on the Company or its business, financial condition, results of operations or cash flows, as the context requires.

Equipment failure and the operation and maintenance of our facilities involve risks that may materially and adversely affect our business.

There is a risk of equipment failure to our operations due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse effect on our business. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. Our facilities are exposed to operational risks such as failures due to cyclic, thermal and corrosion damage in boilers, generators and turbines, and other issues that can lead to outages and increased production risk. An extended outage could have a material adverse effect on our business, financial condition, results of operations or our cash flows.

The operation, maintenance, refurbishment, construction and expansion of power generation facilities involve risks, including breakdown or failure of equipment or processes, fuel interruption and performance below expected levels of output or efficiency. Some of our generation facilities were constructed many years ago and may require significant capital expenditures to maintain peak efficiency or operations. There can be no assurance that our maintenance program will be able to detect potential failures in our facilities before they occur or eliminate all adverse consequences in the event of failure. In addition, weather-related interference, work stoppages and any other unforeseen problems may disrupt the operation and maintenance of our facilities and may materially adversely affect our business.

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We have entered into ongoing maintenance and service agreements with the manufacturers of certain critical equipment. If a manufacturer is unable or unwilling to provide satisfactory maintenance or warranty support on reasonable terms, we may have to enter into alternative arrangements with other providers or perform the services ourselves. These arrangements could be more expensive to us than our current arrangements and if we are unable to enter into satisfactory alternative arrangements, our inability to access technical expertise or parts could have a material adverse effect on us. It is possible that potential cross-border travel and transportation restrictions could impact the timely availability of services, parts and equipment.

While we maintain an inventory of, or otherwise make arrangements to obtain, spare parts to replace critical equipment and maintain insurance for property damage and business interruption to protect against certain operating risks, these protections may not be adequate to cover lost revenues or increased expenses and penalties that could result if we were unable to operate our generation facilities at a level necessary to comply with our contracts. In addition, circumstances could arise in the future whereby the Company may be obligated to produce power or steam at a cost that exceeds the revenues being derived therefrom.

There can be no assurance that any applicable insurance coverage would be adequate to protect our business from material adverse effects. In addition, there can be no assurance that we will be able to restore equipment or assets that have reached the end of their useful lives.

Unexpected changes in the cost of maintenance or in the cost and durability of components for the Company's facilities may adversely affect the results of our operations.

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

Changes in the price of electricity may materially adversely affect our business.

A significant portion of our revenues are tied, either directly or indirectly, to the market price for electricity in the markets in which we operate, and in particular in the Alberta electricity market. Market electricity prices are impacted by a number of factors, including the strength of the economy, the available transmission capacity, the price of fuel that is used to generate electricity (and, accordingly, certain of the factors that affect the price of fuel described below), the management of generation, the amount of excess generating capacity relative to load in a particular market, the cost of controlling emissions and cost of carbon, the structure of the particular market, availability of transmission (including from other jurisdictions), increased adoption of energy-efficiency and conservation initiatives, and weather conditions that impact electrical load. As a result, we cannot precisely predict future electricity prices and electricity price volatility (particularly lower Alberta electricity prices) that could have a material and adverse effect on us. It is currently anticipated that a significant amount of new generation will come online in the near term in Alberta, including 900 MW and 806 MW combined-cycle facilities that have targeted commercial operation dates for the first half of 2024 and the fourth quarter of 2024 respectively, which could result in lower Alberta electricity prices and also push some of the Company's production out of merit. Further, the Alberta market is the only fully deregulated electricity market in Canada and this market structure may incent corporate offtakers to invest in new renewable generation in the province solely for ESG reasons (i.e., to align with decarbonization goals) that may not align with supply and demand fundamentals. This could potentially result in an oversupply of intermittent electricity in the Alberta electricity market and could put downward pressure on electricity prices and contribute to significant price volatility in the near term.

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Our facilities, construction projects and operations are exposed to the effects of natural disasters, public health crises and other catastrophic events beyond our control and such events could result in a material adverse effect.

Our facilities, construction projects and operations are exposed to potential interruption and damage, partial or full loss, resulting from environmental disasters (e.g., floods, high winds, fires, ice storms, earthquakes and public health crises, such as pandemics and epidemics), other seismic activity and equipment failures. Climate change can also increase the frequency and severity of these extreme weather events. There can be no assurance that in the event of an earthquake, flood, cyclone, hurricane, tornado, tsunami, terrorist attack, act of war or other natural, man-made or technical catastrophe, all or some parts of our generation facilities and infrastructure systems will not be disrupted. The occurrence of a significant event that disrupts the ability of our power generation assets to produce power for an extended period, including events that preclude existing customers under PPAs from purchasing electricity, could have a material negative impact on our business. Our facilities, construction projects and operations could be exposed to the effects of severe weather conditions, natural and man-made disasters and other potentially catastrophic events. The occurrence of such an event may not release us from performing our obligations pursuant to PPAs or other agreements with third parties. In addition, many of our generation facilities are located in remote areas, which can make repair of damage costly or difficult to access. Catastrophic events, including public health crises, could result in volatility and disruption to global supply chains, disruption to global financial markets, trade and market sentiment, risks to employee health and safety, a slowdown or temporary suspension of operations in impacted locations, postponements in the initiation and/or completion of the Company's development or construction projects, and delays in the completion of services, any of which may result in the Company incurring penalties under contracts, additional costs or the cancellation of contracts.

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

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

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

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

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With respect to acquisitions, we cannot make assurances that we will identify suitable transactions or that we will have access to sufficient resources, through our credit facilities, the capital markets or otherwise, to pursue and complete any identified acquisition opportunities on a timely basis and at a reasonable cost. Any acquisition that we propose or complete would be subject to regulatory approvals and other normal commercial risks that could result in the transaction not being completed on the terms anticipated, on time, or at all. In the event we are unable to close a transaction that we've entered into, we may be subject to termination fees that could become payable to the vendor. An unavoidable level of risk remains regarding potential undisclosed or unknown liabilities relating to any acquisition. The existence of such undisclosed liabilities may have a material adverse impact on our business, financial condition, results of operations and cash flows.

The Company may not close the Heartland acquisition and if closing does occur there can be no assurance that the Company will realize the anticipated benefits in respect of such transaction.

There are specific risks relating to the closing and expected timing of the Heartland acquisition. These risks include that the transaction remains subject to receipt of regulatory approval and there can be no assurance that the Company will receive such regulatory approval on terms that are acceptable to the Company, within the time period currently anticipated or at all. The transaction may also not deliver the anticipated benefits expected to arise from such transaction, including as it pertains to accretion to free cash flow, the remaining life of the Heartland assets and the ability for such assets to generate sufficient EBITDA to meet the Company's expectations. Furthermore, as with all development projects, there are risks related to the development of the 400 MW Battle River Carbon Hub Project held by Heartland, including risk relating to the project’s continued development, the ability to obtain regulatory approval and the economic outlook required to support a final investment decision.

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

The ability of our facilities to generate the maximum amount of power or steam that can be sold under PPAs is an important determinant of our revenues. Under certain PPAs, if the facility is not capable of generating electricity or steam for the required availability in a given contract year, penalty payments may be payable to the relevant purchaser by us and could give rise to termination rights. The payment of any such penalties or the termination of such PPAs could adversely affect our revenues and profitability.

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

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

We depend on certain joint venture, strategic and other partners that may have interests or objectives that conflict with our objectives and such differences could have a negative impact on us.

We have entered into various arrangements with communities or joint venture, strategic or other partners in connection with the operation of our facilities and assets. Certain of these partners may have or develop interests or objectives that are different from, or in conflict with, our objectives. Any such differences could

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have a negative impact on the Company's ability to realize the anticipated benefits of, or the anticipated increase in the value of facilities or assets subject to, these arrangements. We are sometimes required through the permitting and approval processes to notify and consult with various stakeholder groups, including landowners, Indigenous groups and municipalities. Any unforeseen delays in this process may negatively impact our ability to complete any given facility on time or at all and could result in write-offs or give rise to reputational harm.

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

A natural or man-made disaster, and certain other events, including natural or induced seismic activity, could potentially cause dam failures at our hydroelectric facilities. The occurrence of dam or dyke failures at any of our hydroelectric facilities could result in a loss of generating capacity, damage to the environment or damages and harm to third parties or the public, and such failures could require us to incur significant expenditures of capital and other resources or expose us to significant liabilities for damages. There can be no assurance that our dam safety program will be able to detect potential dam failures prior to their occurrence or eliminate all adverse consequences in the event of failure. Other safety regulations could change from time to time, potentially impacting our costs and operations. Reinforcing all dams or dykes to enable them to withstand more severe events could require us to incur significant expenditures of capital and other resources. The consequences of dam or dyke failures could have a material adverse effect on us. This includes any increased risk of dam failure due to induced seismic activity triggered by fracking near our hydroelectric facilities, which could increase the risk of dam failure or require the Company to incur potentially significant capital investments to mitigate such risk and that would not otherwise be required. See the "Legal Proceedings and Regulatory Actions - Brazeau Facility - Claim against the Government of Alberta" section of this AIF.

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

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

Climate change and other variations in weather can affect demand for electricity and our ability to generate electricity.

Due to the nature of our business, our earnings are sensitive to weather variations from period to period, as well as long-term changes due to climate change. 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 can translate into electricity market price volatility. Variations in precipitation also affect water supplies, which in turn affect our hydroelectric assets. Also, variations in sunlight and wind conditions can have an effect on energy production levels from our solar and wind facilities. Typically, when winters are warmer or summers are cooler, demand for energy is lower than expected, resulting in less

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electricity consumption than forecasted and often resulting in lower than expected market prices for electricity. Conversely, when winters are colder or summers are warmer, market prices for natural gas or electricity tend to be higher; however, in these circumstances, if we have entered into hedges and are unable to produce or consume the amount of natural gas or electricity that we have hedged we could be required to purchase additional volumes at higher prices in order to cover our hedge position.

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, which could make it difficult for the Company to continue to generate electricity during such periods, and such circumstances could pose threats to the Company's equipment and personnel.

The accumulation of ice on wind turbine blades depends on a number of factors including temperature and ambient humidity, and 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. Sudden temperature changes can create an increased risk of ice crystals that can pose a number of constraints on our hydro operations.

Climate change is expected to change the volume and timing of precipitation which may impact the ability of the hydro facilities to maximize the generation from the available water. These changes in flow may result in additional operational costs to manage the water through the hydro plants.

Variations in weather may be impacted by climate change resulting in sustained higher temperatures, rising sea levels and altered precipitation patterns that could have an impact on our generating assets. Furthermore, climate change could result in increased variability or sustained long-term changes to our water and wind resources impacting hydroelectric and wind electricity generation, which could adversely affect our revenues and profitability.

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

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

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

There can be no assurance that we will achieve or be able to adhere to our sustainability targets and any failure to do so may present adverse consequences to our business.

The Company annually establishes sustainability targets to, among things, manage current and emerging material sustainability issues, which includes targets relating to decarbonization. The Board of Directors has the discretion to determine the sustainability targets being adopted by the Company and may modify or cancel any previously established sustainability target at any time. The Board of Director's determination to establish, alter or cancel any sustainability target will depend on, among other things: the United Nations Sustainable Development Goals; results of operations; technological considerations; financial condition; market opportunities; legal, regulatory and contractual considerations; and other relevant factors. Further, there is no certainty that the Company will be successful in achieving any particular sustainability target within the stated

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time frame, or at all. If we are not able to achieve, or adhere to, our sustainability targets, we may not satisfy our stakeholders' current and future expectations, which could negatively impact our reputation and could result in certain investors being unable to hold our common shares.

Many of our activities and properties are subject to environmental regulations, and any liabilities arising under these requirements may materially adversely affect our business.

Our operations are subject to federal, provincial, state and local environmental laws, regulations and guidelines relating to the generation and transmission of electrical and thermal energy and surface mine reclamation (collectively, "environmental regulations"). These environmental regulations pertain to pollution and the protection of the environment, health and safety, and govern, among other things, air emissions, water usage and discharges, storage, treatment and disposal of waste and other materials, and remediation of sites and responsible land use. These laws and regulations can impose liability and obligations for costs to investigate and remediate contamination without regard to fault, and under certain circumstances liability may be joint and several, resulting in one responsible party being held responsible for the entire obligation. Environmental regulations can also impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transport, treatment and disposal of hazardous substances and waste, and can impose cleanup, disclosure or other responsibilities with respect to spills, releases and emissions of various substances to the environment. Environmental regulations can also require that facilities and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, there is an increasing level of environmental regulation regarding the use, treatment and discharge of water and we anticipate the adoption of new or additional emission regulations at a national level in Canada, the US and Australia, which may impose different compliance requirements or standards on our business. These various compliance standards may result in additional costs for our business and may impact our ability to operate our facilities.

Stricter standards, new or greater regulation, increased enforcement by regulatory authorities, more extensive permitting requirements, an increase in the number and types of assets operated by the Company subject to environmental regulation and the implementation of provincial, state and national environmental regulations may impose varying obligations on us in the jurisdictions in which we operate, and could increase our expenditures. To the extent these expenditures cannot be passed through to our customers under our PPAs or otherwise, our costs could be material. In addition, compliance with environmental regulation might result in restrictions on some of our operations. If we do not comply with environmental regulations, regulatory agencies could seek to impose statutory, administrative and/or criminal liabilities on us, curtail our operations, or require significant expenditures on compliance, new equipment or technology, reporting obligations and research and development. A number of recent federal, provincial, state and local regulatory efforts continue to focus on potential climate change or GHG emissions regulation; mandatory GHG reporting requirements are in effect in Canada, the US and Australia.

In addition to environmental regulations, we could also face civil liability in the event that private parties seek to impose liability on us for property damage, personal injury or other costs and losses. We cannot guarantee that lawsuits or administrative or investigative actions will not be commenced against us and otherwise affect our operations and assets. If an action is filed against us or may otherwise affect our operations and assets, we could be required to make substantial expenditures to defend against, or evidence our activities or to bring our Company, our operations and assets into compliance, which could have a material adverse effect on our business.

The estimated reclamation costs applicable to the Company's operations may be inaccurate and could require greater financial resources than currently anticipated. As an owner of mines that were previously in operation, we maintain permits from the applicable regulatory body providing for the authorization of certain mining operations that result in a disturbance of the surface. These requirements sought to limit the adverse impacts of coal mining with more restrictive requirements potentially being adopted from time to time. As an owner of mines that were previously in operation, we may also be required to submit a bond or otherwise secure payment of certain long-term obligations including mine closure or reclamation costs. Surety bond costs have increased in recent years and the market terms of such bonds have generally become more unfavourable. In

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addition, the number of companies willing to issue surety bonds has decreased. We could be required to self-fund these obligations should we be unable to renew or secure the required surety bonds for our mining operations or if it becomes more economical to do so.

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

Most of the markets in which we operate and intend to operate are subject to significant regulatory oversight and control. We are not able to predict whether there will be any further changes in the regulatory environment, including potential carbon and other environmental regulations, changes in market structure or market design, or changes in other laws and regulations. Existing market rules, regulations and reliability standards are often dynamic and may be revised or re-interpreted, and new laws and regulations may be adopted or become applicable to us or our facilities, which could have a material adverse effect on us. Many of our projects must also comply with reliability standards, including those established by the North American Electric Reliability Corporation and Alberta Reliability Standards. Failure to comply with these mandatory reliability standards could result in sanctions, including substantial monetary penalties.

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

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

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

Any changes in the rules and regulations of provincial or state public utility commissions or other regulatory bodies in the other markets in which we compete, or may compete in the future, may materially adversely affect us.

The reduction, elimination or expiration of government subsidies and economic incentives could adversely affect our prospects for growth.

We seek to take full advantage of government policies that promote renewable power generation and enhance the economic feasibility of renewable power projects. Renewable power generation sources currently benefit from various incentives in the form of feed-in tariffs, rebates, tax credits, renewable portfolio standards (such as the US government policy mechanism that supports the adoption of renewable power by setting a targeted percentage of a jurisdiction's total electricity procurement from renewable power) and other incentives throughout the markets in which we participate or intend to participate. The removal or phasing out of any such incentives could adversely affect our revenues as well as our prospects for growth as these incentives enhance the economic feasibility of developing and building renewable power projects.

We may be adversely affected if our supply of water is materially reduced.

Our hydroelectric and natural gas facilities and our coal-fired facility require continuous water flow for their operation. Shifts in weather or climate patterns, seasonable precipitation, the timing and rate of melting, run-off and other factors beyond our control may reduce the water flow to our facilities. Any material reduction in the water flow to our facilities would limit our ability to produce and market electricity from these facilities and could have a material adverse effect on us. There is an increasing level of regulation respecting the use, treatment and discharge of water, and respecting the licensing of water rights in jurisdictions where we operate. Any such change in regulations could have a material adverse effect on us.

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Availability or disruption of fuel supply to our thermal plants could have an adverse impact on the operation of our facilities and our financial condition.

Our gas facilities rely on having adequate supplies of natural gas and our Centralia facility requires adequate supplies of coal to run the facility reliably and at full capacity. As a result, we face the risk of not having adequate fuel supplies available due to insufficient natural gas transportation service, disruptions in fuel supplies due to weather, strikes, lockouts, or breakdowns of equipment, the timing of receiving regulatory approvals or we could be materially adversely affected if the cost of fuel that we must buy to generate electricity increases to a greater degree than the price that we can obtain for the electricity that we sell. Several factors affect the price of fuel, many of which are beyond our control, including:

•Prevailing market prices for fuel;

•Global demand for energy products;

•The cost of carbon and other environmental concerns;

•Weather-related disruptions affecting the ability to deliver fuels or near-term demand for fuels;

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

•Political instability, including the war in Ukraine;

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

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

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

In the event the Company secures more natural gas than required to operate its facilities, the Company may have difficulty reselling such natural gas and it could be exposed to the market price for natural gas in respect of any such resales. There is no certainty that the Company will be successful in reselling or recovering its costs in respect of such resales of natural gas.

As well, the coal used to fuel the Centralia facility is sourced from the Powder River Basin in Montana and Wyoming through contracts to purchase and transport such coal to our Centralia facility. The loss of our suppliers or inability to receive coal at Centralia under our existing coal contracts at sufficient quantities, or at all, could also significantly affect our ability to serve our customers and have an adverse impact on our financial condition and results of operations. We could face the risk of inadequate supply service due to our reliance on the Pioneer Pipeline and on the ATCO Pipeline as a significant provider of natural gas for our Sundance and Keephills units.

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

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

Our power generation facilities may also be subject to changes in regulations governing the cost and characteristics of use of the transmission and distribution systems to which our power generation facilities are connected. Our power generation facilities in the future may not be able to secure access to this interconnection or transmission capacity at reasonable prices, in a timely fashion or at all, which could then cause delays and additional costs in attempting to negotiate or renegotiate PPAs or to construct new projects.

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In addition, we may not benefit from preferential arrangements in the future. Any such increased costs and delays could delay the commercial operation dates of any new projects and negatively impact our revenues and financial condition.

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

We rely on our information technology to process, transmit and store electronic information and data used for the safe operation of our assets. Over the past few years, geopolitical tensions and the pandemic have significantly impacted the cybersecurity ecosystem, increasing the frequency and diversity of cyberattacks, including threats of war driven cyberattacks (i.e., terrorism) against critical infrastructure and threat actors taking advantage of the pandemic (e.g., charity scams) and hybrid working environments. In the continuously evolving cybersecurity threat landscape, any attacks or breaches of network or information systems may cause disruptions to our business operations or compromise the proprietary, confidential or personal information of the Company, its customers, partners or others with whom the Company has dealings. Cyberattackers may use a range of techniques, from exploiting vulnerabilities within our user base (social engineering attacks), to using sophisticated malicious code on a single or distributed basis to try to breach our network security controls. We anticipate that the cyber threat landscape will continue to evolve, with increasing threats of ransomware, compromised insider threats, supply chain attacks, advanced targeted phishing and artificial intelligence. Cyber threats originate from various sources and vectors, from nation states, organized hacking groups or malware/ransomware. The cyber threat landscape continues to evolve, as we see cyber threats shift their focus from traditional attacks against perimeter information technology systems, to more effective attacks, such as phishing and ransomware. A successful cyberattack may allow for the unauthorized interception, destruction, use or dissemination of proprietary, confidential or personal information and may cause disruptions to our operations.

We are subject to regulatory, legislative and business requirements (e.g., North American Electric Reliability Corporation Critical Infrastructure Protection, SOX, Privacy) and also adopt industry endorsed standards and frameworks (e.g., National Institute of Standards and Technology, Critical Infrastructure Projection/Reliability Standards) as it pertains to our cybersecurity program and the implementation of our cybersecurity controls and processes.

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

Our technology and systems for communication and monitoring may be vulnerable to security breaches or interruptions, which could result in increased operating expenses and other liabilities.

We rely on technology, mainly on computer, telephone, satellite, cellular and related networks and infrastructure, to conduct our business and monitor the production of our generation facilities. These systems and infrastructure could be vulnerable to unforeseen problems including, but not limited to, cyberattacks, breaches, vandalism and theft. Our operations are dependent upon our ability to protect our information and operating technology against damage from fire, power loss, telecommunications failure or a similar catastrophic event. While we have dedicated resources for maintaining appropriate levels of cybersecurity and we use third-party technology to help protect us against security breaches and cyber incidents, our measures may not be effective and our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such security breaches and cyber incidents or other disruptions could jeopardize the security of information stored in and transmitted through our systems and network infrastructure, and could result in significant setbacks and potential liabilities and deter future customers. Additionally, we must be able to protect our generation facility infrastructure against physical damage and any service disruptions.

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Any damage or failure that causes an interruption in operations could have an adverse effect on our customers. While we have systems, policies, hardware, practices and procedures designed to prevent or limit the effect of failure or interruptions of our generation facilities and infrastructure, there can be no assurance that these measures will be sufficient and that any such failures or interruptions will not occur or, if they do occur, that they will be adequately addressed in a timely manner.

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

We operate in a number of Canadian provinces, as well as in the US and Australia. These areas of operation are affected by competition ranging from large utilities to small IPPs, as well as private equity, pension funds, international conglomerates, traditional energy companies and technology firms. In addition, potential customers may look to deploy their own capital to self-supply their own electricity needs. Some competitors have significantly greater financial and other resources than we do. Such competition could have a material adverse effect on our business. Emerging technology affecting the demand, generation, distribution or storage of electricity may also significantly impact our business and ability to compete. Climate change and regulatory incentives are expected to drive innovation and transformation of the power generation sector, including energy production and consumption, and there can be no certainty that the Company will benefit from such innovation or transformation. Furthermore, older facilities may over time be unable to compete with newer more efficient facilities utilizing improvements to existing power technologies and cost-efficient new technologies, including gas turbines with lower heat rates. In Alberta, certain industrial customers rely on behind-the-fence generation, resulting in such customers not being supplied electricity from the grid, which reduces the competitive load in the province and puts downward pressure on pool prices. Further, certain large industrial companies in Alberta operate significant cogeneration facilities, which generate steam required for their operations and often results in large amounts of excess generation being offered to the power pool. These cogeneration facilities offer their energy into the market at low prices to ensure it is dispatched, which results in the facility realizing an achieved price close to the average pool price, which potentially puts downward pressure on the pool price and could result in certain of the Company's facilities not being dispatched.

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

Adverse changes in general economic and market conditions and, more specifically, in the markets in which we operate, could negatively impact demand for electricity, revenue, operating costs, timing and extent of capital expenditures, the net recoverable value of plant, property and equipment, results of financing efforts, or credit risk and counterparty risk, which could cause us to suffer a material adverse effect. Furthermore, a period of prolonged inflation may negatively impact our revenue, operating costs, maintenance costs and capital expenditures.

We may be unsuccessful in legal actions.

We are occasionally named as a defendant in claims and legal actions and as a party in commercial disputes that are resolved by arbitration or other legal proceedings. We may also bring legal actions against third parties as part of a commercial dispute through an arbitration or other legal proceeding. There can be no assurance that we will be successful in any such claim or defence or that any claim or legal action that is decided adverse to us will not materially and adversely affect us. See the "Legal Proceedings and Regulatory Actions" section of this AIF.

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

To the extent that our sources of cash and cash flow from operations are insufficient to fund our activities or we are unable to divest assets to generate capital, we may need to raise additional funds. Additional financing may not be available when needed, and if such financing is available, it may not be available on terms that are favourable to our business.

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

We are subject to certain financial covenants under our credit facility that could limit the amount of additional debt that the Company could raise in certain circumstances. An inability to raise project debt or tax equity financing could reduce the number of projects that we are able to finance. If we are unable to raise additional funds when needed, we could be required to delay the acquisition and construction of growth projects, reduce the scope of projects, abandon or sell some of our projects or generation facilities, or default on our contractual commitments in the future, any of which could adversely affect our business, financial condition and results of operations.

TransAlta's debt securities will be structurally subordinated to any debt of our subsidiaries that is currently outstanding or may be incurred in the future.

We operate our business through, and a majority of our assets are held by, our subsidiaries, including partnerships. Our results of operations and ability to service indebtedness are dependent upon the results of operations of our subsidiaries and the payment of funds by these subsidiaries to TransAlta in the form of loans, dividends or otherwise. Our subsidiaries may be restricted in their ability to pay amounts due, or make any funds available to TransAlta, whether by dividends, interests, loans, advances or other payments. In addition, the payment of dividends and the making of loans, advances and other payments to us by our subsidiaries may be subject to statutory or contractual restrictions or tax withholding amounts.

In the event of the liquidation of any subsidiary, the assets of the subsidiary would be used first to repay the indebtedness of the subsidiary, including trade payables or obligations under any guarantees, before being used to pay TransAlta's indebtedness, including any debt securities issued by TransAlta. Such indebtedness and any other future indebtedness of such subsidiaries would be structurally senior for such subsidiary to any debt securities issued by TransAlta.

Our subsidiaries have financed some investments using non-recourse project financing. Each non-recourse project loan is structured to be repaid out of cash flow provided by the project. In the event of a default under a financing agreement that is not secured, the lenders would generally have rights to the related assets. In the event of foreclosure after a default, our subsidiary may lose its equity in the asset or may not be entitled to any cash that the asset may generate. Although a default under a project loan should not cause a default with respect to any debt securities issued by TransAlta, it may materially affect our ability to service our outstanding indebtedness.

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

Rating agencies regularly evaluate us, basing their ratings of our long-term and short-term debt, along with our issuer rating, on a number of factors. There can be no assurance that one or more of our credit ratings and the corresponding outlook will not be changed. Our borrowing costs and ability to raise funds are directly impacted by our credit ratings. Credit ratings may be important to suppliers or counterparties when they seek to engage in certain transactions with us. A credit rating downgrade could potentially impair our ability to enter into arrangements with suppliers or counterparties, to engage in certain transactions, and could limit our access to private and public credit markets and increase the costs of borrowing under our existing credit facilities. See Note 15 of our audited consolidated financial statements for the year ended Dec. 31, 2023, which financial statements are incorporated by reference herein. Also, see the "Documents Incorporated by Reference" section of this AIF for further details.

Changes to our reputation may have a material adverse effect on us.

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

We may fail to meet financial expectations.

Our quarterly revenue, earnings, cash flows and results of operations are difficult to predict and fluctuate from quarter to quarter. Our quarterly results of operations are influenced by a number of factors, including the risks described in this AIF, many of which are outside of our control and that may cause such results to fall below market expectations. Although we base our planned operating expenses in part on our expectations of future revenue, a significant portion of our expenses are relatively fixed in the short-term. If revenue for a particular quarter is lower than expected, we likely will be unable to proportionately reduce our operating expenses for that quarter, which will adversely affect our results of operations for that quarter.

Our cash dividend payments are not guaranteed.

The payment of dividends is not guaranteed and could fluctuate. The Board of Directors has the discretion to determine the amount and timing of any dividends to be declared and paid to our shareholders. In addition, the payment of dividends on common shares is, in all cases, subject to prior satisfaction of preferential dividends applicable to each series of our first preferred shares. We may alter our dividend on common shares at any time. The Board of Directors' determination to declare dividends will depend on, among other things: results of operations; financial condition; current and expected future levels of earnings; operating cash flow; liquidity requirements; market opportunities; income taxes; maintenance and growth capital expenditures; debt repayments; legal, regulatory and contractual constraints; working capital requirements; tax payable; and other relevant factors. Our short- and long-term borrowings may prohibit us from paying dividends at any time at which a default or event of default would exist under such debt, or if a default or event of default would exist as a result of paying the dividend.

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

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

The market price for our common shares may be volatile.

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

Financial markets have experienced significant price and volume fluctuations in recent years that have particularly affected the market prices of equity securities of companies and such fluctuations have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the market price of our common shares may decline even if our operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause decreases in asset values that may result in impairment losses. Certain institutional investors may base their investment decisions on consideration of our environmental, governance and social practices and performance against such institutions' respective investment guidelines and criteria, and failure to meet such criteria may result in limited or no investment in our common shares by those institutions, which could adversely affect the trading price of our common shares.

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

We sell power under PPAs that expire at various times. In addition, these PPAs may be subject to termination in certain circumstances, including default by the facility or plant owner or operator. When a PPA expires or is terminated, it could result in us having less stable cash flows and it is possible that the price received by the relevant facility or plant for power under subsequent selling arrangements may be reduced significantly. It is also possible that to the extent a PPA is negotiated after the initial PPAs have run their course, the new contract may not be available at prices that permit the continued operation of the affected facility or plant on a profitable basis. If this occurs, the affected facility or plant may be forced to permanently cease operations.

We may fail to fully or effectively hedge our supply and price risk exposure.

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. The efficacy of our risk management and hedging program may be adversely impacted by unanticipated events and costs that we are not able to effectively mitigate, including unanticipated events that impact supply and demand, such as extreme weather and unplanned outages. We may also be adversely impacted if we make incorrect assumptions that were relied upon in establishing our hedges. We are exposed to changes in electricity prices and natural gas prices on purchases of electricity or natural gas from the market to fulfil our supply obligations under these short- and long-term hedge contracts. If we are unable to produce or consume the amount of natural gas or electricity that we have hedged, we could incur losses as we could be required to purchase additional volumes in the market at higher prices in order to

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cover our hedge position. Comparably, if the market price for electricity is higher than the hedged price we would be subject to the opportunity cost associated with not realizing the higher market price.

We are also exposed to basis risk as certain of our generating facilities receives the "node" price for the electricity it delivers to the grid while the financial PPA for such generating facility settles at the "hub" price. These differences between the "node" price and "hub" price can be significant from time to time.

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

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

In addition, from time to time, we may have a trading strategy consisting of simultaneously holding a long position and a short position, from which we expect to earn a profit based on changes in the relative value of the two positions. If, however, the relative value of the two positions changes in a direction or manner that we did not anticipate, we would realize losses from such a paired position.

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

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

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

We are exposed to risk under certain arrangements, including financial derivative contracts and electricity and natural gas purchase and sale contracts entered into for the purposes of hedging and proprietary trading. The terms and conditions of these contracts may require us to provide collateral when the fair value of these contracts is in excess of any credit limits granted by our counterparties and the contract obliges that we provide the collateral. The change in fair value of these contracts often occurs due to changes in commodity prices. These contracts include: (a) financial derivative contracts when forward commodity prices are more or less than contracted prices, depending on the transactions; (b) purchase agreements, when forward commodity prices are less than contracted prices; and (c) sales agreements, when forward commodity prices exceed contracted prices. Downgrades in our creditworthiness by certain credit rating agencies may decrease the credit limits granted by our counterparties and, accordingly, increase the amount of collateral that we may have to provide. Any increase in the amount of collateral provided by the Company could reduce our liquidity and materially adversely affect us.

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

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

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

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

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

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

Our business is exposed to the risks inherent in the construction and operation of electricity generation facilities, such as breakdowns, manufacturing defects, natural disasters, injury, damage to third parties, theft, terrorist attacks, cyberattacks and sabotage. We are also exposed to environmental risks. We maintain insurance policies, covering usual and customary risks associated with our business, with creditworthy insurance carriers. Our insurance policies, however, may not cover losses, or may be subject to limitations in coverage as a result of force majeure, natural disasters, terrorist or cyberattacks or sabotage, armed hostilities, or other perils. Our insurance policies may be subject to increase resulting from climate change, for example due to storm severity and frequency. In addition, we generally do not maintain insurance for certain environmental risks, such as environmental contamination. Our insurance policies are subject to annual review by the respective insurers and may not be renewed at all or on similar or favourable terms. A significant uninsured loss or a loss significantly exceeding the limits of our insurance policies or the failure to renew such insurance policies on similar or favourable terms could have a material adverse effect on our business, financial condition and results of operations.

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

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Provision for income taxes may not be sufficient.

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

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

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

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

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

While we believe we have a satisfactory relationship with our unionized employees, we cannot guarantee that we will be able to successfully negotiate or renegotiate our collective bargaining agreements on terms agreeable to TransAlta. In 2023 we successfully renegotiated three collective bargaining agreements. We expect to renegotiate five collective bargaining agreements in 2024. Any hurdles in negotiating these collective bargaining agreements could lead to higher employee costs and a work stoppage or strike, which could have a material adverse effect on us.

We are subject to risks associated with our ownership interests in projects that are under construction, which could result in our inability to complete construction projects on time or at all, and make projects too expensive to complete or cause the return on an investment to be less than expected.

TransAlta has interests in certain projects that have not yet commenced operations or are under construction. There may be delays or unexpected developments in completing any future construction projects, which could cause the construction costs of these projects to exceed our expectations, result in substantial delays or prevent the project from commencing commercial operations. Various factors could contribute to construction-cost overruns, construction halts or delays or the failure to commence commercial operations, including: delays in obtaining, or the inability to obtain, necessary land rights, permits and licences; delays and increased costs related to the interconnection of new projects to the transmission system; the inability to acquire or maintain land use and access rights; the failure to receive contracted third-party services; interruptions to dispatch at the projects; supply chain disruptions, including as a result of changes in international trade laws, regulations, agreements, treaties, taxes, tariffs, duties or policies of Canada, the US or other countries in which the Company's suppliers are located; work stoppages; labour disputes; weather interferences; unforeseen engineering, environmental and geological problems, including, but not limited to, discoveries of contamination, protected plant or animal species or habitat, archaeological or cultural resources or other environment-related factors; unanticipated cost overruns in excess of budgeted contingencies; and failure of contracting parties to perform under contracts.

TransAlta Corporation • Annual Information Form        62

In addition, if we or one of our subsidiaries has an agreement for a third party to complete construction of any project, TransAlta is subject to the viability and performance of the third party. Our inability to find a replacement contracting party, if the original contracting party has failed to perform, could result in the abandonment of the construction of such project, while we could remain obligated under other agreements associated with the project, including, but not limited to, offtake PPA's.

We may not be able to extend, renew or replace expiring or terminated PPAs, or other customer contracts at favourable rates or on a long-term basis.

Our ability to extend, renew or replace our existing PPAs or other customer contracts depends on a number of factors beyond our control, including, but not limited to: whether the PPA counterparty has a continued need for energy at the time of the agreement’s expiration; the presence or absence of governmental incentives or mandates which prevails market prices; the availability of other electricity sources; the satisfactory performance of our obligations under such PPAs; the regulatory environment applicable to our contractual counterparties at the time; macroeconomic factors present at the time, such as population, business trends, international trade laws, regulations, agreements, treaties, policies or other countries and related energy demand; and the effects of regulation on the contracting practices of our contractual counterparties.

If we are not able to extend, renew or replace on acceptable terms existing PPAs before contract expiration, or if such agreements are otherwise terminated prior to their expiration, we may not have any ability to sell electricity to the market or to other customers. If we are able to sell electricity on an uncontracted basis, we would sell electricity at prevailing market prices that could be materially lower than under the applicable contract. If there is no satisfactory market for a project’s uncontracted energy, we may decommission the project before the end of its useful life. Any failure to extend, renew or replace a significant portion of our existing PPAs, or other customer contracts, or extending, renewing or replacing them at lower prices or with other unfavourable terms, or the decommissioning of a project could have a material adverse effect on our business, financial condition, results of operations and ability to pay dividends to our shareholders.

New technology and artificial intelligence may present emerging risks that could have a material adverse affect on the Company.

We are introducing artificial intelligence and robotics at some of our facilities. The use of artificial intelligence and robotics at our facilities may not yield materially better results, higher outputs or increased productivity and there is no certainty that we will realize benefits from investments in these technologies. Additionally, the use of artificial intelligence is subject to the risk that privacy concerns relating to such technology could deter current and potential customers.

The global energy transition may have an adverse effect on the Company.

The decarbonization of the global energy system in order to achieve net-zero emissions and minimize a global temperature rise poses several risks to TransAlta's business, including but not limited to, changing regulations and policies, market risks from the volatility of and uncertainty of the energy supply and demand, and operational risks from new technologies.

Employees

The Company is required to develop and retain a skilled workforce for its operations. Many of the employees of the Company possess specialized skills and training and the Company must compete in the marketplace for these workers. As at Dec. 31, 2023, we had 1,257 active employees, which includes full-time, part-time and temporary employees. Approximately 30 per cent of our employees are represented by labour unions. We are currently a party to 11 different collective bargaining agreements. As at Dec. 31, 2023, women accounted for 27 per cent of all employees and 26 per cent of our executive team.

TransAlta Corporation • Annual Information Form        63

Capital and Loan Structure

Our authorized share capital consists of an unlimited number of common shares and an unlimited number of first preferred shares, issuable in series. As at Feb. 22, 2024, there were 307,100,000 common shares outstanding and 9,629,913 Series A Shares, 2,370,087 Series B Shares, 9,955,701 Series C Shares, 1,044,299 Series D Shares, 9,000,000 Series E Shares, 6,600,000 Series G Shares, and 400,000 Series I Shares outstanding (as defined below). The Company does not have any escrowed securities.

Common Shares

Each common share of the Company entitles the holder thereof to one vote for each common share held at all meetings of shareholders of the Company, 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, subject to prior satisfaction of preferential dividends applicable to any first preferred shares, and to participate rateably in any distribution of our assets upon a liquidation, dissolution or winding up and subject to prior rights and privileges attaching to first preferred shares. The common shares are not convertible and are not entitled to any preemptive rights. The common shares are not entitled to cumulative voting.

Normal Course Issuer Bid

On May 26, 2023, the TSX accepted the Company's notice to implement an NCIB for a portion of its common shares. The Board of Directors has authorized repurchases of up to a maximum of 14,000,000 common shares, representing approximately 7.29 per cent of TransAlta's public float. Purchases under the NCIB are expected to be made through open market transactions on the TSX and any alternative Canadian trading platforms, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.

Under TSX rules, not more than 150,222 common shares (being 25 per cent of the average daily trading volume on the TSX of 600,891 common shares for the six months ended April 30, 2023) can be purchased on the TSX on any single trading day under the NCIB, with the exception that one block purchase in excess of the daily maximum is permitted per calendar week.

The period during which TransAlta is authorized to make purchases under the NCIB began on May 31, 2023, and ends on May 30, 2024, 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.

During the year ended Dec. 31, 2023, the Company purchased and cancelled a total of 7,537,500 common shares under its 2022 NCIB (which expired on May 30, 2023) and the 2023 NCIB (which will expire on May 30, 2024), including those purchased under automatic share purchase plans, at an average price of $11.49 per common share, for a total cost of $87 million. See Note 27 of our audited consolidated financial statements for the year ended Dec. 31, 2023, which financial statements are incorporated by reference herein. Also, see the "Documents Incorporated by Reference" section of this AIF for further details.

Automatic Share Purchase Plan

###

All purchases of common shares made under the ASPP will be included in determining the number of common shares purchased under the NCIB. Any common shares purchased by the Company pursuant to the NCIB will be cancelled. The ASPP will terminate on the earliest of the date on which: (a) the maximum purchase limits under the ASPP are reached; (b) Feb. 24, 2024; or (c) the Company terminates the ASPP in accordance with its terms.

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 might not be reflective of the underlying value and purchases of common shares for cancellation under the NCIB may provide an opportunity to enhance shareholder value.

TransAlta Corporation • Annual Information Form        64

First Preferred Shares

We are authorized to issue an unlimited number of first preferred shares, issuable in series and, with respect to each series, the Board of Directors 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 the Company 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 Company, 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 of Directors at the rate established by the Board of Directors at the time of issue of shares of a series. No dividends may be declared or paid on any other shares of the Company 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 Company, or a reduction of stated capital, no sum shall be paid or assets distributed to holders of other shares of the Company until the holders of first preferred shares shall have been paid the subscription price of the shares, plus a sum equal to the premium payable on a redemption, plus a sum equal to the arrears of dividends accumulated on the first preferred shares to the date of such liquidation, dissolution, winding up or reduction of stated capital, as applicable. After the payment of such amount, the holders of first preferred shares shall not be entitled to share further in the distribution of our assets.

The Board of Directors may include, in the share conditions attaching to a particular series of first preferred shares, certain voting rights effective upon our failing to make payment of six quarterly dividend payments, whether or not consecutive. These voting rights continue for so long as any dividends remain in arrears. These voting rights are the right to one vote for each $25.00 of subscription price on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of TransAlta if the Board of Directors then consists of less than 16 directors, or three directors if the Board of Directors consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Company.

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

Series A Shares

On Dec. 10, 2010, 12 million cumulative redeemable fixed rate first preferred shares, Series A ("Series A Shares") were issued for gross proceeds of $300 million. On March 31, 2016, 1,824,620 of the Series A Shares were converted into cumulative redeemable floating rate first preferred shares, Series B ("Series B Shares") on a one-for-one basis. On March 31, 2021, 1,417,338 of the Series A Shares were converted into Series B Shares on a one-for-one basis and 871,871 Series B Shares were converted into Series A Shares on a one-for-one basis. Certain provisions of the Series A Shares are discussed below.

Dividends on Series A Shares

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

TransAlta Corporation • Annual Information Form        65

For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series A Shares shall be entitled to receive, as and when declared by the Board of Directors, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 2.03 per cent. This spread will apply to both the Series A Shares and the Series B Shares described below, and will remain unchanged over the life of the Series A Shares. The most recently declared Annual Dividend Rate for Series A Shares is 2.877 per cent.

Redemption of Series A Shares

The Series A Shares were redeemable by TransAlta, at its option, in whole or in part, on March 31, 2016, and on March 31, 2021, and will be redeemable on March 31 in every fifth year thereafter by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).

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

Conversion of Series A Shares into Series B Shares

The holders of the Series A Shares had the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series B of TransAlta (the "Series B Shares"), subject to certain conditions, on March 31, 2016, and on March 31, 2021, and will again have the right to convert on March 31 in every fifth year thereafter.

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

Voting Rights

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

Modification

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

Series B Shares

On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares on a one-for-one basis. On March 31, 2021, 1,417,338 of the Series A Shares were converted into Series B Shares on a one-for-one basis and 871,871 Series B Shares were converted into Series A Shares on a one-for-one basis. Certain provisions of the Series B Shares are discussed below.

TransAlta Corporation • Annual Information Form        66

Dividends on Series B Shares

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

For each five-year period after conversion, the holders of Series B Shares shall be entitled to receive, as and when declared by the Board of Directors, quarterly floating rate cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate (which means the average yield expressed as an annual rate on the 90-day Government of Canada treasury bill, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable Floating Rate Calculation Date) on the applicable date and 2.03 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 2.03 per cent. This spread will apply to both the Series A Shares described above and the Series B Shares and will remain unchanged over the life of the Series B Shares. The most recently declared Annual Dividend Rate for Series B Shares is 7.072 per cent.

Redemption of Series B Shares

The Series B Shares were redeemable by TransAlta, at its option, in whole or in part, on March 31, 2021, and will be redeemable on March 31 in every fifth year thereafter by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).

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

Conversion of Series B Shares into Series A Shares

The holders of the Series B Shares had the right to convert all or any of their shares into cumulative redeemable fixed rate first preferred shares, Series A, subject to certain conditions, on March 31, 2021, and will again have the right to convert on March 31 in every fifth year thereafter.

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

Voting Rights

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

TransAlta Corporation • Annual Information Form        67

Modification

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

Series C Shares

On Nov. 30, 2011, 11 million cumulative redeemable rate reset first preferred shares, Series C (the "Series C Shares") were issued for gross proceeds of $275 million. On June 30, 2022, 1,044,299 of the Series C Shares were converted into cumulative redeemable floating rate first preferred shares, Series D ("Series D Shares") on a one-for-one basis. Certain provisions of the Series C Shares are discussed below.

Dividends on Series C Shares

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

For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series C Shares shall be entitled to receive, as and when declared by the Board of Directors, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 3.10 per cent. This spread will apply to both the Series C Shares and the Series D Shares described below, and will remain unchanged over the life of the Series C Shares. The most recently declared Annual Dividend Rate for Series C Shares is 5.854 per cent.

Redemption of Series C Shares

The Series C Shares were redeemable by TransAlta, at its option, in whole or in part, on June 30, 2017, and on June 30, 2022, and will be redeemable on June 30 in every fifth year thereafter by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).

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

Conversion of Series C Shares into Series D Shares

The holders of the Series C Shares had the right to convert all or any of their shares into Series D Shares, subject to certain conditions, on June 30, 2017, and on June 30, 2022, and will again have the right to convert on June 30 in every fifth year thereafter.

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

On June 15, 2017, 827,628 Series C Shares were tendered for conversion into Series D Shares, which is less than the one million shares required to give effect to conversions into Series D Shares. As a result, none of the Series C Shares were converted into Series D Shares on June 30, 2017. On June 30, 2022, 1,044,299 of the Series C Shares were converted to Series D Shares on a one-for-one basis.

TransAlta Corporation • Annual Information Form        68

Voting Rights

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

Modification

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

Series D Shares

On June 30, 2022, 1,044,299 of the Series C Shares were converted into Series D Shares on a one-for-one basis. Certain provisions of the Series D Shares are discussed below.

Dividends on Series D Shares

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

For each five-year period after conversion, the holders of Series D Shares shall be entitled to receive, as and when declared by the Board of Directors, quarterly floating rate cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest, (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate (which means, the average yield expressed as an annual rate on the 90-day Government of Canada treasury bill, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable Floating Rate Calculation Date) on the applicable date and 3.10 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.10 per cent. This spread will apply to both the Series C Shares described above and the Series D Shares and will remain unchanged over the life of the Series D Shares. The most recently declared Annual Dividend Rate for Series D Shares is 8.142 per cent.

Redemption of Series D Shares

The Series D Shares are redeemable by TransAlta, at its option, in whole or in part, on June 30, 2027, and on June 30 in every fifth year thereafter by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).

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

TransAlta Corporation • Annual Information Form        69

Conversion of Series D Shares into Series C Shares

The holders of the Series D Shares have the right to convert all or any of their shares into cumulative redeemable fixed rate first preferred shares, Series C Shares, subject to certain conditions, on June 30, 2027, and on June 30 in every fifth year thereafter.

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

Voting Rights

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

Modification

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

Series E Shares

On Aug. 10, 2012, nine million cumulative redeemable rate reset first preferred shares, Series E (the "Series E Shares") were issued for gross proceeds of $225 million. Certain provisions of the Series E Shares are discussed below.

Dividends on Series E Shares

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

For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series E Shares shall be entitled to receive, as and when declared by the Board of Directors, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by the Company on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 3.65 per cent. This spread will apply to both the Series E Shares and the cumulative redeemable floating rate first preferred shares, Series F ("Series F Shares") described below, and will remain unchanged over the life of the Series E Shares. The most recently declared Annual Dividend Rate for Series E Shares is 6.894 per cent.

TransAlta Corporation • Annual Information Form        70

Redemption of Series E Shares

The Series E Shares were redeemable by the Company, at its option, in whole or in part, on Sept. 30, 2017, and on Sept. 30, 2022, and will be redeemable on September 30 in every fifth year thereafter by the payment of an amount of $25.00 in cash for each share to be redeemed plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold). On Sept. 30, 2017 and Sept. 30, 2022, none of the Class E Shares were redeemed.

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

Conversion of Series E Shares into Series F Shares

The holders of the Series E Shares had the right to convert all or any of their shares into Series F Shares, subject to certain conditions, on Sept. 30, 2017, and on Sept. 30, 2022, and will again have the right to convert on Sept. 30 in every fifth year thereafter. The holders of the Series F Shares will be entitled to receive, as and when declared by the Board of Directors, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September, and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.65 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.65 per cent.

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

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

On Sept. 15, 2022, 89,945 Series E Shares were tendered for conversion into Series F Shares, which is less than the one million shares required to give effect to conversions into Series F Shares. As a result, none of the Series E Shares were converted into Series F Shares on Sept. 30, 2022.

Voting Rights

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

TransAlta Corporation • Annual Information Form        71

Modification

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

Series G Shares

On Aug. 15, 2014, 6.6 million cumulative redeemable rate reset first preferred shares, Series G ("Series G Shares") were issued for gross proceeds of $165 million. Certain provisions of the Series G Shares are discussed below.

Dividends on Series G Shares

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

For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series G Shares shall be entitled to receive, as and when declared by the Board of Directors, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by the Company on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 3.80 per cent. This spread will apply to both the Series G Shares and the cumulative redeemable floating rate first preferred shares, Series H ("Series H Shares") described below, and will remain unchanged over the life of the Series G Shares. The most recently declared Annual Dividend Rate for Series G Shares is 4.988 per cent.

Redemption of Series G Shares

The Series G Shares were redeemable by the Company, at its option, in whole or in part, on Sept. 30, 2019, and will be redeemable on September 30 in every fifth year thereafter by the payment of an amount of $25.00 in cash for each share to be redeemed plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).

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

TransAlta Corporation • Annual Information Form        72

Conversion of Series G Shares into Series H Shares

The holders of the Series G Shares had the right to convert all or any of their shares into Series H Shares, subject to certain conditions, on Sept. 30, 2019, and will again have the right to convert on September 30 in every fifth year thereafter. The holders of the Series H Shares will be entitled to receive, as and when declared by the Board of Directors, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.80 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.80 per cent.

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

On Sept. 17, 2019, 140,730 Series G Shares were tendered for conversion into Series H Shares, which is less than the one million shares required to give effect to conversions into Series H Shares. As a result, none of the Series G Shares were converted into Series H Shares on Sept. 30, 2019.

Voting Rights

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

Modification

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

Series I Shares

The cumulative redeemable first preferred shares, Series I ("Series I Shares") are issued to an affiliate of Brookfield Renewable Partners ("Brookfield") and have a perpetual term and rank pari passu to all existing series of first preferred shares of the Company with respect to dividends and liquidation preferences. The Series I Shares are entitled to a seven per cent cumulative dividend payable quarterly in cash.

Under the Investment Agreement with Brookfield, redemption of the Series I Shares will be satisfied through the Hydro Equity Interest (as defined below), or in some cases cash, based on their redemption price. The redemption price payable is equal to the subscription price paid by Brookfield together with all accrued but unpaid dividends thereon (the “Redemption Price”). Upon the occurrence of an Optional Redemption, as defined and described below, or a Cash Acceleration Event, as defined and described below, the Company will pay the Redemption Price in cash (the “Cash Redemption Amount”).

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Except in the case of an Optional Redemption by the Company or a Cash Acceleration Event, as described below, the Series I Shares will be exchangeable into interests (“Hydro Equity Interest”) in the equity (the “Hydro Equity”) of TA Alberta Hydro LP (“Hydro Assets Owner”), a special purpose vehicle formed by the Company. At any time after Dec. 31, 2024, but prior to Dec. 31, 2028, Brookfield will be entitled to exchange all, but not less than all, of the Series I Shares requiring the Company to redeem or exchange all of the Series I Shares held by Brookfield (minus the number of Series I Shares that have been redeemed pursuant to an Optional Redemption) (the “Exchange Right”).

Prior to any Optional Redemption by the Company, the exercise of the Exchange Right or the occurrence of an Equity Acceleration Event, as defined and described below, will entitle Brookfield to receive that percentage of a Hydro Equity Interest that is equal to the aggregate Redemption Price for all Series I Shares issued to Brookfield divided by the tax-affected equity value of the Hydro Assets Owner, as further described in the Investment Agreement (“Equity Redemption Amount”). The maximum Hydro Equity Interest issuable to Brookfield upon the exercise of the Exchange Right is 49 per cent of the total Hydro Equity. The balance of the Redemption Price will be paid by the Company in cash.

If, at the time the Exchange Right is exercised, the Equity Redemption Amount is insufficient to permit Brookfield to acquire 49 per cent of the Hydro Equity, Brookfield has a one-time top-up option, exercisable until Dec. 31, 2028, to acquire an additional amount of Hydro Equity. As long as Brookfield holds at least 8.5 per cent of the Company's issued and outstanding common shares, Brookfield may purchase: (a) if the 20-day volume weighted average price (“VWAP”) of the common shares is not less than $14, up to an additional 10 per cent of Hydro Equity, to a maximum interest of 49 per cent of the Hydro Equity; or (b) if the 20-day VWAP of the common shares is not less than $17, the additional percentage required that would bring Brookfield’s ownership level up to but not exceeding 49 per cent of the Hydro Equity. If the Exchange Right is exercised and the Equity Redemption Amount is insufficient to permit Brookfield to acquire at least 25 per cent of the Hydro Equity, Brookfield will have an option to acquire that additional percentage of Hydro Equity that would result in Brookfield having 25 per cent of the Hydro Equity upon payment in cash. If Brookfield exercises its top-up option, the cash amount payable by Brookfield is calculated as the same price as in the case of an exchange for the Hydro Equity Interest; however, in such a case, the price is based on the equity value of the Hydro Assets Owner without any reduction for the tax deficiency value associated with certain tax pools. Exercise of this top-up option triggers a lock-up obligation of Brookfield for a further period of 18 months following its exercise.

At any time after Dec. 31, 2028, the Company may redeem the Series I Shares and the related debentures, in whole or in part, at the Redemption Price (the “Optional Redemption”) provided that the minimum proceeds to Brookfield for each such redemption (other than the final redemption) may not be less than $100,000,000 and further provided that all Series I Shares and related debentures must be redeemed by the Company within 36 months of the date of the first Optional Redemption.

The Investment Agreement also provides for certain acceleration events. In the event of bankruptcy or a breach of certain material covenants by the Company (each, an “Equity Acceleration Event”), Brookfield will be entitled to give notice and will be entitled to the Equity Redemption Amount. If an Equity Acceleration Event occurs before Dec. 31, 2024, a true-up payment will be made by Brookfield to the Company or by the Company to Brookfield to account for the difference between $1.95 billion and the tax-affected value of the Hydro Equity Interest calculated as of a date (to be determined by Brookfield) within the period commencing Jan. 1, 2025, and ending Dec. 31, 2027. Any difference in favour of Brookfield between the true-up value and the value of the Hydro Equity Interest issued to Brookfield is to be satisfied by delivery of additional Hydro Equity. If the Company does not obtain the requisite regulatory approvals for the exchange of Hydro Equity contemplated by the Exchange Right or the Equity Redemption Amount or a final order is made that enjoins the completion of the Exchange Right (“Cash Acceleration Event”), then Brookfield will be entitled to the Cash Redemption Amount.

TransAlta Corporation • Annual Information Form        74

Share Capital

The following table outlines the Company's common shares and preferred shares issued and outstanding:

	Number of shares (millions)
As at	Feb. 22, 2024	Dec. 31, 2023	Dec. 31, 2022
Common shares issued and outstanding, end of period	307.1	308.6	268.1
Preferred shares
Series A	9.6	9.6	9.6
Series B	2.4	2.4	2.4
Series C	10.0	10.0	10.0
Series D	1.0	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	38.6	38.6	38.6
Series I - Exchangeable Securities	0.4	0.4	0.4
Preferred shares issued and outstanding	39.0	39.0	39.0

Related-Party Articles Provisions

The articles of the Company contain provisions restricting the ability of the Company 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 Company, 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 per cent of the outstanding voting shares of the Company. The articles contain a broad definition of beneficial ownership, and in particular, a person is considered to beneficially own shares owned by their associates and affiliates, as those terms are defined in the articles. Transactions that are considered to be Specified Transactions include the following: a merger or amalgamation of the Company with a Major Shareholder; the furnishing of financial assistance by the Company to a Major Shareholder; certain sales of assets or provision of services by the Company to a Major Shareholder or vice versa; certain issuances of securities by the Company that increase the proportionate voting interest of a Major Shareholder; a reorganization or recapitalization of the Company that increases the proportionate voting interest of a Major Shareholder; and the creation of a class or series of non-voting shares of the Company that has a residual right to participate in earnings of the Company and assets of the Company upon dissolution or winding up.

Shareholder Rights Plan

The Company implemented a shareholder rights plan ("Rights Plan") pursuant to a Shareholder Rights Plan Agreement ("Rights Plan Agreement") dated as of Oct. 13, 1992, as amended and restated as of April 28, 2022, between the Company and Computershare Trust Company of Canada. The Shareholder Rights Plan was last confirmed at our annual and special meeting of shareholders on April 28, 2022, and will expire at the close of business on the date of our 2025 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, TransAlta Place, Suite 1400, 1100 1 St SE, Calgary, Alberta T2G 1B1; 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.sedarplus.ca, and on the SEC's EDGAR system at www.sec.gov.

TransAlta Corporation • Annual Information Form        75

Credit Facilities

In 2023, we renewed our syndicated credit agreement ("Syndicated Facility") giving us access to a $1.25 billion committed credit facility. The Syndicated Facility is fully committed and expires in 2027. The Syndicated Facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. The cost of borrowing of the Syndicated Facility is aligned to our GHG emission reductions and gender diversity targets, which are part of our overall ESG strategy, and will result in a cumulative pricing adjustment to the borrowing costs on the Syndicated Facility as well as a corresponding adjustment to the standby fee. The Syndicated Facility has been made available for general corporate purposes, including financing ongoing working capital requirements, providing financing for construction capital, pursuing growth opportunities and repaying outstanding borrowings.

On Oct. 5, 2023, the Syndicated Facility was further amended to effectively consolidate the TransAlta Renewables syndicated credit facility and non-committed demand facility into the TransAlta Syndicated Facility. The TransAlta Renewables credit facilities were then terminated. This resulted in the TransAlta Syndicated Facility increasing by $700 million to approximately $2.0 billion. See Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2023, which financial statements are incorporated by reference herein. Also, see the "Documents Incorporated by Reference" section of this AIF for further details.

During the third quarter of 2022, the Company closed a two-year $400 million floating rate term facility ("Term Facility") with its banking syndicate with a maturity date of Sept. 7, 2024. The Term Facility has interest rates that vary depending on the option selected (e.g. Canadian prime and bankers' acceptances). We are required to meet certain specific and customary affirmative and negative financial covenants under the Term Facility, including the maintenance of certain financial ratios. As of Dec. 31, 2023, the full $400 million remained drawn under the Term Facility and proceeds were used for general corporate purposes.

Long-Term Debt

The long-term debt of the Company consists of $251 million face value of debentures outstanding as at Dec. 31, 2023, which bear interest at fixed rates ranging from 6.9 per cent to 7.3 per cent and have maturity dates ranging from 2029 to 2030. In addition, we have US$700 million face value in senior notes outstanding that bear interest at fixed rates of 6.5 and 7.8 per cent and mature in 2029 and 2040. See Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2023, which financial statements are incorporated by reference herein. Also, see the "Documents Incorporated by Reference" section of this AIF for further details.

Non-Recourse Debt and Restrictions on Debt

The Company has non-recourse debt outstanding in an amount equal to approximately $1.7 billion face value, which is represented by bonds and debentures that bear fixed interest at rates ranging from 3.41 per cent to 4.51 per cent and a variable interest rate bond at 9.40 per cent and have maturity dates ranging from 2028 to 2043. See Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2023, which financial statements are incorporated by reference herein. Also, see the "Documents Incorporated by Reference" section of this AIF for further details.

On Sept. 14, 2023, the Company closed a non-recourse bond financing for approximately $39 million ("Pingston bond") as a replacement for the non-recourse bond that matured on May 8, 2023. The Pingston bond is secured by a first ranking charge over all the respective assets of the Company's subsidiaries that issued the bonds, amortizes and bears interest at a rate of 6.145 per cent per annum, payable semi-annually, and matures on May 8, 2043. The Pingston bond is subject to customary financing conditions and covenants that may restrict the Company's ability to access funds generated by the facility's operations.

The Melancthon Wolfe Wind LP, TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd., 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

TransAlta Corporation • Annual Information Form        76

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 2023, with the exception of Kent Hills Wind LP, which cannot make any distributions to its partners until the foundation replacement work has been completed (see the "General Development of the Business" section of this AIF for further details), and TAPC Holdings LP, which has been impacted by higher interest rates in 2023. The funds in these entities that have accumulated since the fourth quarter test will not be capable of being distributed until the next debt service coverage ratio is calculated in the first quarter of 2024. At Dec. 31, 2023, $79 million (Dec. 31, 2022 – $50 million) could not be distributed due to these financial restrictions. Additionally, certain non-recourse bonds require that reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit.

In addition, our syndicated credit facilities include a number of customary covenants and restrictions in order to maintain access to the funding commitments.

Exchangeable Securities

On March 22, 2019, we entered into the Investment Agreement, whereby Brookfield invested $750 million in the Company through the purchase of Exchangeable Securities, which are exchangeable into an equity ownership interest of TA Alberta Hydro LP. See the "Capital and Loan Structure - Series I Shares" section of this AIF for further details.

Investment Agreement and E&O Agreement

The following description of certain provisions of the Investment Agreement and the E&O Agreement is a summary only, it is not comprehensive and is qualified in its entirety by reference to the full text of each of the Investment Agreement and E&O Agreement, copies of which can be found on SEDAR+ under our profile at www.sedarplus.ca and on EDGAR under our profile at www.sec.gov.

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 ### per cent by May 1, 2021. As of Dec. 31, 2023, Brookfield, through its affiliates, held, owned or had control over an aggregate of 35,489,201 common shares, representing 11.6 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.

The Investment Agreement contemplates that the Exchangeable Securities will be a long-term investment and therefore may not be transferred except by Brookfield to one of its affiliates. Brookfield has agreed to be the sole representative of all of its permitted transferees for the purpose of the Investment Agreement.

The Investment Agreement included certain standstill commitments by Brookfield that are extended for so long as Brookfield has nominees on the Board of Directors, including restrictions on Brookfield's ability to solicit proxies from the Company's shareholders or making a shareholder proposal.

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 provide advice and recommendations in connection with the operation and value maximization of the Alberta hydro assets. In connection with this, the Company committed to pay Brookfield an annual management fee of $1.5 million for six years commencing on May 1, 2019.

Registration Rights Agreement

The following description of certain provisions of the registration rights agreement entered into between Eagle Hydro II (an affiliate of Brookfield) and the Company on May 1, 2019 (“Registration Rights Agreement”) is a summary only, it is not comprehensive and is qualified in its entirety by reference to the full text of the Registration Rights Agreement, a copy of which can be found on SEDAR+ under our profile at www.sedarplus.ca.

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 (“Demand Registration”) to the Company to file a Prospectus Supplement with the securities

TransAlta Corporation • Annual Information Form        77

commissions or similar authorities in each of the provinces of 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 Company of a Demand Registration, the Company will promptly file a Prospectus Supplement in order to permit the offer and sale or other disposition or distribution in Canada of all or any portion of the Registrable Securities held, directly or indirectly, by the Holder (a “Demand Offering”). The Company will not be obligated to effect: (a) more than three Demand Offerings in total during the term of the Registration Rights Agreement; or (b) a Demand Offering if the Registrable Securities have an aggregate market price of less than $50 million.

If at any time the Company proposes to file a prospectus supplement with respect to the distribution of any TransAlta common shares to the public, then the Company 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 that 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 Company will use commercially reasonable efforts to include in such Prospectus Supplement such Registrable Securities (a “Piggy Back Offering”), unless the Company’s managing underwriter or underwriters determine, in good faith, that including such Registrable Securities in the distribution would, in their opinion, adversely affect the Company’s distribution or sales price of the securities being offered by the Company.

The Demand Offerings and Piggy Back Offerings are subject to various conditions and limitations. The Company 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 Company 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.

In the case of a prospectus supplement filed in connection with a Demand Offering or Piggy Back Offering, the Company will pay all applicable fees and expenses incidental to the Company’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 the Company receives the offering request, the Company 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 Company in such offering. The Company 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 Company will pay all selling expenses with respect to any Securities sold for the account of the Company. The Company 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 Company, 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 owns in the aggregate less than three per cent of the issued and outstanding common shares.

Additional details about the Brookfield Investment can be found in our material change report dated March 26, 2019, available electronically on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. Copies of the Investment Agreement, together with copies of the exchangeable debenture, the E&O Agreement and the Registration Rights Agreement are also available on SEDAR+ and on EDGAR. Shareholders are encouraged to read these documents in their entirety.

TransAlta Corporation • Annual Information Form        78

Tax Equity

As of Dec. 31, 2023, $110 million in tax equity remains outstanding.

In 2023, US tax laws were amended to allow entities to monetize certain clean energy tax credits, including PTCs, by transferring (selling) them to third-party taxpayers, in exchange for cash consideration.

In November 2021, the Company assumed US$16 million in tax equity financing as part of the acquisition of the North Carolina Solar portfolio.

In December 2020, coinciding with the commercial operation of the Skookumchuck wind facility, approximately US$121 million was raised from a tax equity partner in respect of the Skookumchuck project entity, which had the effect of lowering the cost of TransAlta's 49 per cent investment in the Skookumchuck wind facility from approximately US$125 million to approximately US$66 million.

In December 2019, coinciding with the Big Level and Antrim wind projects achieving commercial operation, TransAlta received funding of approximately US$126 million from a tax equity partner.

The Company also assumed US$24 million in tax equity financing as part of the acquisition of the Lakeswind wind facility in 2015.

Under IFRS, tax equity financings are included as debt in our consolidated financial statements. See Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2023, which financial statements are incorporated by reference herein. Also, see the "Documents Incorporated by Reference" section of this AIF for further details.

Credit Ratings

Credit ratings provide information relating to our financing costs, liquidity and operations and affect our ability to obtain short-term and long-term financing and/or the cost of such financing. Maintaining a strong balance sheet also allows our commercial team to contract the Company’s portfolio with a variety of counterparties on terms and prices that are favourable to our financial results and provides us with better access to capital markets through commodity and credit cycles. We remain focused on maintaining a strong balance sheet and financial position with strong cash flow coverage ratios in order to access sufficient financial capital. Our credit ratings as at Dec. 31, 2023, are as follows:

	Morningstar DBRS	Moody's	S&P Global Ratings
Issuer Rating	BBB (low)	Not applicable	BB+
Corporate Family Rating	Not applicable	Ba1	Not applicable
Preferred Shares	Pfd-3 (low)(1)	Not applicable	P-4(High)
Unsecured Debt/MTNs	BBB (low)	Ba1/LGD4	BB+
Rating Outlook	Stable	Stable	Stable

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

In 2023, Moody’s reaffirmed the Company's long term rating of Ba1 with a stable outlook. Morningstar DBRS ("DBRS") reaffirmed 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 outlook. In addition, S&P Global Ratings reaffirmed the Company’s senior unsecured debt rating and issuer credit rating of BB+ with stable outlook.

TransAlta Corporation • Annual Information Form        79

DBRS

DBRS' corporate rating analysis begins with evaluation of the fundamental creditworthiness of the issuer and also takes the issuer's business and financial risks into account, which is reflected in an "issuer rating." Issuer ratings address the overall credit strength of the issuer. Unlike ratings on individual securities or classes of securities, issuer ratings are based on the entity itself and do not include consideration for security or ranking. Ratings that apply to actual securities (secured or unsecured) may be higher, lower or equal to the issuer rating for a given entity. As at Dec. 31, 2023, our issuer rating was BBB (low) with a stable outlook from DBRS. A BBB rating is the fourth highest out of 10 categories.

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

The DBRS long-term rating scale provides an opinion on the risk of default, which is the risk that an issuer will fail to satisfy its financial obligations in accordance with the terms under which an obligation has been issued. Ratings are based on quantitative and qualitative considerations relevant to the issuer, and the relative ranking of claims. All rating categories other than AAA and D also contain subcategories "high" and "low". The absence of either a "high" or "low" designation indicates the rating is in the middle of the category. Debt securities rated BBB are of adequate credit quality. The capacity for the payment of financial obligations is considered acceptable, but may be vulnerable to future events.

Moody's

Moody's Corporate Family Ratings (CFRs) are long-term ratings that reflect the relative likelihood of a default on a corporate family's debt and debt-like obligations and the expected financial loss suffered in the event of default. A CFR is assigned to a corporate family as if it had a single class of debt and a single consolidated legal entity structure. A CFR does not reference an obligation or class of debt and thus does not reflect priority of claim. As at Dec. 31, 2023, our Corporate Family Rating was Ba1 with a stable outlook from Moody's. Obligations rated Ba are judged to have speculative elements and are subject to substantial credit risk. Moody's appends the numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking, and the modifier 3 indicates a ranking in the lower end of that generic rating category. The Ba rating category is the fifth-highest rating out of nine rating categories.

Moody's long-term ratings are assigned to issuers or obligations with an original maturity of one year or more and reflect both on the likelihood of a default on contractually promised payments and the expected financial loss suffered in the event of default. As at Dec. 31, 2023, our senior unsecured long-term debt is rated Ba1/LGD4 by Moody's. The Ba rating category is the fifth-highest rating out of nine rating categories. Obligations rated Ba are judged to have speculative elements and are subject to substantial credit risk.

Moody's Loss Given Default ("LGD") assessments are opinions about expected loss given default expressed as a per cent of principal and accrued interest at the resolution of the default. One of the six LGD assessments are assigned to individual loan, bond and preferred stock issues. The firm-wide or enterprise expected LGD rate generally approximates a weighted average of the expected LGD rates on the firm's liabilities (excluding preferred stock), where the weights equal each obligation's expected share of the total liabilities at default. As at Dec. 31, 2023, our LGD assessment from Moody's was LGD4, which represents a loss range of greater than or equal to 50 per cent and less than 70 per cent. LGD4 is the fourth-highest assessment category out of six categories.

TransAlta Corporation • Annual Information Form    80

S&P Global Ratings

The S&P Global Ratings issue credit rating is a forward-looking opinion about the creditworthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the creditworthiness of guarantors, insurers or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion reflects S&P Global Ratings' view of the obligor's capacity and willingness to meet its financial commitments as they come due, and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. As at Dec. 31, 2023, our issuer credit rating was BB+ with a stable outlook with S&P. This is the fifth highest of 11 ratings categories. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.

The S&P Global Ratings Canadian preferred share rating scale serves issuers, investors and intermediaries in the Canadian financial markets by expressing preferred share ratings (determined in accordance with global rating criteria) in terms of rating symbols that have been actively used in the Canadian market over a number of years. The S&P Global Ratings preferred share rating on the Canadian scale is a forward-looking opinion about the creditworthiness of an obligor with respect to a specific preferred share obligation issued in the Canadian market, relative to preferred shares issued by other issuers in the Canadian market. There is a direct correspondence between the specific ratings assigned on the Canadian preferred share scale and the various rating levels on the global debt rating scale of S&P Global Ratings. Each of our outstanding Preferred Shares Series has been rated P-4 (High) by S&P. The P-4 (High) rating is the fourth highest of eight categories. A P-4 (High) rating corresponds to a B+ rating on the global preferred share rating scale. Obligors rated BB, B, CCC, CC and C are regarded as having significant speculative characteristics, of which BB indicates the least degree of speculation and C the highest. While some obligors will likely have some quality and protective characteristics, these may be outweighed by large uncertainties or major exposures to adverse conditions. An obligor rated B is less vulnerable in the near term than other lower-rated obligors. However, it faces major ongoing uncertainties and exposure to adverse business, financial or economic conditions that could impair the obligor's capacity or willingness to meet its financial commitments.

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

Note Regarding Credit Ratings

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

We have paid fees for rating services to DBRS, Moody's and S&P Global Ratings during the last two years. We have also paid fees to S&P Global Ratings, DBRS and Kroll Bond Rating Agency for certain other services provided to the Company during the last two years.

TransAlta Corporation • Annual Information Form    81

Dividends

Common Shares

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

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

Period		Dividend per Common Share
2021	First Quarter	$0.0450
	Second Quarter	$0.0450
	Third Quarter	$0.0450
	Fourth Quarter	$0.0500
2022	First Quarter	$0.0500
	Second Quarter	$0.0500
	Third Quarter	$0.0500
	Fourth Quarter	$0.0550
2023	First Quarter	$0.0550
	Second Quarter	$0.0550
	Third Quarter	$0.0550
	Fourth Quarter	$0.0550
2024	First Quarter(1)	$0.0600

(1)    Dividends have been declared but not yet paid.

Preferred Shares

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

Series A Shares

Period		Dividend per Series A Share
2021	First Quarter	$0.16931
	Second Quarter	$0.17981
	Third Quarter	$0.17981
	Fourth Quarter	$0.17981
2022	First Quarter	$0.17981
	Second Quarter	$0.17981
	Third Quarter	$0.17981
	Fourth Quarter	$0.17981
2023	First Quarter	$0.17981
	Second Quarter	$0.17981
	Third Quarter	$0.17981
	Fourth Quarter	$0.17981
2024	First Quarter(1)	$0.17981

(1)    Dividends have been declared but not yet paid.

TransAlta Corporation • Annual Information Form    82

Series B Shares

Period		Dividend per Series B Share
2021	First Quarter	$0.13186
	Second Quarter	$0.13108
	Third Quarter	$0.13479
	Fourth Quarter	$0.13970
2022	First Quarter	$0.13309
	Second Quarter	$0.16505
	Third Quarter	$0.22099
	Fourth Quarter	$0.33700
2023	First Quarter	$0.37991
	Second Quarter	$0.41100
	Third Quarter	$0.41545
	Fourth Quarter	$0.45288
2024	First Quarter(1)	$0.43958

(1)    Dividends have been declared but not yet paid.

Series C Shares

Period		Dividend per Series C Share
2021	First Quarter	$0.25169
	Second Quarter	$0.25169
	Third Quarter	$0.25169
	Fourth Quarter	$0.25169
2022	First Quarter	$0.25169
	Second Quarter	$0.25169
	Third Quarter	$0.36588
	Fourth Quarter	$0.36588
2023	First Quarter	$0.36588
	Second Quarter	$0.36588
	Third Quarter	$0.36588
	Fourth Quarter	$0.36588
2024	First Quarter(1)	$0.36588

(1)    Dividends have been declared but not yet paid.

Series DShares

Period		Dividend per Series D Share
2022	Third Quarter	$0.28841
	Fourth Quarter	$0.40442
2023	First Quarter	$0.45578
	Second Quarter	$0.47769
	Third Quarter	$0.48287
	Fourth Quarter	$0.52030
2024	First Quarter(1)	$0.50609

(1)    Dividends have been declared but not yet paid.

TransAlta Corporation • Annual Information Form    83

Series E Shares

Period		Dividend per Series E Share
2021	First Quarter	$0.32463
	Second Quarter	$0.32463
	Third Quarter	$0.32463
	Fourth Quarter	$0.32463
2022	First Quarter	$0.32463
	Second Quarter	$0.32463
	Third Quarter	$0.32463
	Fourth Quarter	$0.43088
2023	First Quarter	$0.43088
	Second Quarter	$0.43088
	Third Quarter	$0.43088
	Fourth Quarter	$0.43088
2024	First Quarter(1)	$0.43088

(1)    Dividends have been declared but not yet paid.

Series G Shares

Period		Dividend per Series G Share
2021	First Quarter	$0.31175
	Second Quarter	$0.31175
	Third Quarter	$0.31175
	Fourth Quarter	$0.31175
2022	First Quarter	$0.31175
	Second Quarter	$0.31175
	Third Quarter	$0.31175
	Fourth Quarter	$0.31175
2023	First Quarter	$0.31175
	Second Quarter	$0.31175
	Third Quarter	$0.31175
	Fourth Quarter	$0.31175
2024	First Quarter(1)	$0.31175

(1)    Dividends have been declared but not yet paid.

Series I Shares

TransAlta also declared an aggregate cash dividend in respect to the issued and outstanding Series I Shares for the period starting from and including Dec. 31, 2022, up to but excluding Dec. 31, 2023. The Series I Shares are entitled to a seven per cent cumulative dividend payable quarterly in cash.

TransAlta Corporation • Annual Information Form    84

Market for Securities

Common Shares

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

	Price ($)
Month	High	Low	Volume
2023
January	13.64	11.85	10,563,874
February	12.87	11.02	13,935,699
March	11.93	10.60	14,287,018
April	12.47	11.65	10,688,815
May	13.48	12.04	12,229,463
June	13.45	12.02	11,660,760
July	13.68	11.54	11,732,249
August	13.97	12.92	13,230,445
September	13.24	11.76	14,112,624
October	12.00	10.11	23,842,700
November	11.68	10.02	17,583,646
December	11.22	10.20	14,301,948
2024
January	11.17	9.72	16,050,874
February 1-22	9.89	9.16	8,843,459

TransAlta Corporation • Annual Information Form    85

Preferred Shares

Series A Shares

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

Date of Issuance	Number of Securities(1)(2)	Issue Price per Security	Description of Transaction
Dec. 10, 2010(1)	12,000,000 Series A Shares	$25.00	Public Offering
March 31, 2021(2)	871,871 Series A Shares	N/A	Conversion of Series B Shares

(1)    Series A Shares were issued pursuant to a public offering by way of a prospectus supplement dated Dec. 3, 2010, to a short form base shelf prospectus dated Oct. 19, 2009.

(2)    On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares on a one-for-one basis. On March 31, 2021, 1,417,338 of the Series A Shares were converted into Series B Shares on a one-for-one basis, and 871,871 Series B Shares were converted to Series A Shares on a one-for-one basis.

	Price ($)
Month	High	Low	Volume
2023
January	14.17	13.11	57,996
February	14.17	13.54	104,594
March	13.95	12.81	123,624
April	12.98	12.67	195,787
May	12.99	12.30	55,875
June	12.51	12.05	73,649
July	12.30	12.00	80,427
August	12.28	11.51	860,451
September	11.95	11.52	100,471
October	11.91	11.35	69,987
November	12.67	11.67	94,725
December	12.82	11.70	139,058
2024
January	13.97	12.16	111,246
February 1-22	14.30	13.33	58,871

TransAlta Corporation • Annual Information Form    86

Series B Shares

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

Date of Issuance	Number of Securities(1)(2)	Issue Price per Security	Description of Transaction
March 31, 2016(1)	1,824,620 Series B Shares	N/A	Conversion of Series A Shares
March 31, 2021(2)	1,417,338 Series B Shares	N/A	Conversion of Series A Shares

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

(2)    On March 31, 2021, 1,417,338 of the Series A Shares were converted into Series B Shares on a one-for-one basis. Also, on March 1, 2021, 871,871 of the Series B Shares were converted into Series A Shares on a one-for-one basis.

	Price ($)
Month	High	Low	Volume
2023
January	16.94	15.20	24,040
February	16.95	16.20	19,346
March	16.71	15.81	11,575
April	16.29	15.32	6,438
May	15.95	15.07	20,696
June	15.34	14.90	32,390
July	15.43	14.95	18,212
August	15.43	14.83	68,244
September	14.90	13.55	31,294
October	15.00	13.60	76,142
November	15.35	14.21	72,928
December	15.40	14.25	83,476
2024
January	16.23	14.34	85,144
February 1-22	16.71	16.00	37,358

TransAlta Corporation • Annual Information Form    87

Series C Shares

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

Date of Issuance	Number of Securities(1)(2)	Issue Price per Security	Description of Transaction
Nov. 30, 2011(1)	11,000,000 Series C Shares	$25.00	Public Offering
June 30, 2022(2)	9,955,701 Series C Shares	N/A	Conversion of Series D Shares

(1)    Series C Shares were issued pursuant to a public offering by way of a prospectus supplement dated Nov. 23, 2011, to a short form base shelf prospectus dated Nov. 15, 2011.

(2)    On June 30, 2022, 1,044,299 of the Series C Shares were converted into Series D Shares on a one-for-one basis.

	Price ($)
Month	High	Low	Volume
2023
January	21.13	18.94	122,303
February	20.89	19.87	33,135
March	20.20	18.46	94,206
April	19.00	18.60	56,167
May	18.92	17.86	109,117
June	18.78	17.92	33,155
July	18.40	17.90	60,132
August	18.32	17.32	76,745
September	17.71	16.25	153,207
October	16.88	15.88	84,963
November	18.47	16.45	99,711
December	18.14	17.45	89,476
2024
January	18.68	17.85	105,265
February 1-22	18.70	18.24	61,931

TransAlta Corporation • Annual Information Form    88

Series D Shares

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

Date of Issuance	Number of Securities(1)	Issue Price per Security	Description of Transaction
June 30, 2022(1)	1,044,299 Series E Shares	N/A	Conversion of Series C Shares

(1)    On June 30, 2022, 1,044,299 of the Series C Shares were converted into Series D Shares on a one-for-one basis.

	Price ($)
Month	High	Low	Volume
2023
January	23.40	21.35	2,150
February	22.50	21.65	4,700
March	22.50	20.65	1,015
April	21.00	19.40	3,250
May	21.00	19.40	3,250
June	20.00	19.00	10,100
July	20.00	19.10	2,900
August	20.00	18.20	15,100
September	18.90	17.50	5,916
October	19.79	17.19	1,800
November	19.99	17.51	7,585
December	19.65	17.75	4,500
2024
January	20.10	18.40	6,770
February 1-22	21.00	19.25	5,288

TransAlta Corporation • Annual Information Form    89

Series E Shares

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

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

(1)    Series E Shares were issued pursuant to a public offering by way of a prospectus supplement dated Aug. 3, 2012, to a short form base shelf prospectus dated Nov. 15, 2011.

	Price ($)
Month	High	Low	Volume
2023
January	23.36	22.08	139,424
February	23.68	22.70	69,503
March	23.09	21.71	72,576
April	21.86	21.17	79,646
May	21.74	20.80	81,612
June	21.44	20.80	48,456
July	21.56	20.80	91,039
August	21.74	20.00	64,826
September	20.40	19.60	63,719
October	19.85	18.25	81,082
November	22.00	18.52	115,144
December	21.83	20.45	199,707
2024
January	21.99	21.17	97,836
February 1-22	21.78	21.33	52,931

TransAlta Corporation • Annual Information Form    90

Series G Shares

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

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

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

	Price ($)
Month	High	Low	Volume
2023
January	21.48	20.04	57,218
February	21.98	21.22	66,452
March	21.89	20.04	72,473
April	20.38	19.89	51,270
May	20.10	19.01	49,851
June	19.55	18.99	59,824
July	19.96	18.92	88,652
August	20.11	18.90	99,684
September	20.49	18.60	68,908
October	19.18	18.18	63,364
November	20.30	18.50	158,554
December	19.75	18.60	103,796
2024
January	21.48	19.60	96,742
February 1-22	21.49	20.61	35,569

Series I Shares

On Oct. 30, 2020, the Company issued 400,000 redeemable first preferred shares, Series I ("Series I Shares"), at a price of $1,000 per Series I Share, for aggregate proceeds of $400 million. The Series I Shares were issued to Brookfield under the Investment Agreement and are not listed or quoted on a marketplace.

TransAlta Corporation • Annual Information Form    91

Directors and Officers

The name, province or state and country of residence of each of our directors as at Feb. 22, 2024, their respective position and office and their respective principal occupation during the five preceding years, are set out below. The year in which each director was appointed to serve on the Board of Directors is also set out below. Each director is appointed to serve until the next annual meeting of TransAlta or until his or her successor is elected or appointed.

Name, Province (State) and Country of Residence	Year First Became Director	Principal Occupation
Rona H. Ambrose Alberta, Canada	2017	The Honourable Rona Ambrose is Chair of the Governance, Safety and Sustainability Committee. Ms. Ambrose is the Deputy Chairwoman of TD Securities. She was the former Leader of Canada's Official Opposition in the House of Commons and former leader of the Conservative Party of Canada until 2017. As a key member of the federal cabinet for a decade, she solved problems as a minister of the Crown across nine government departments, including serving as Vice Chair of the Treasury Board for several years and Chair of the cabinet committee for public safety, justice and Aboriginal issues. As the former environment minister responsible for the GHG regulatory regime across several industrial sectors, she understands the challenges facing the fossil fuel industry. Ms. Ambrose was personally responsible for the development of several federal policies, ranging from industrial strategies in military procurement to health innovation and improvements to sexual assault laws. She is a passionate advocate for women in Canada and around the world and led the global movement to create the "International Day of the Girl" at the United Nations. She was also responsible for ensuring that Aboriginal women in Canada were granted equal matrimonial rights. She successfully fought for the creation of a Canadian refugee program to bring Yazidi women and girls who have been sexually enslaved by ISIS to safety in Canada. She is Chair of Plan International Canada Inc., a charity dedicated to girls rights globally which is working in 80 countries presently. She is a Global Fellow at the Wilson Centre's Canada Institute in Washington, DC, serves on the advisory board of the Canadian Global Affairs Institute and is a director of Andlauer Healthcare Group. She has a Bachelor of Arts from the University of Victoria and a Master of Arts from the University of Alberta. She is also a graduate of the Harvard Kennedy School of Government Senior Leaders Program. Ms. Ambrose brings to the Company and the Board an extensive track record of strong leadership acquired through a wide range of experience at the most senior levels of the Canadian government.

TransAlta Corporation • Annual Information Form    92

Name, Province (State) and Country of Residence	Year First Became Director	Principal Occupation
John P. Dielwart Alberta, Canada	2014	Mr. Dielwart is the Chair of the Board of Directors. He was formerly Chief Executive Officer of ARC Resources Ltd., overseeing the growth of the company from a start-up in 1996 to a company with a total capitalization of approximately $10 billion at the time of his retirement in 2013. After his retirement from ARC Resources, Mr. Dielwart re-joined ARC Financial Corp. as Vice-Chair and Partner. ARC Financial is Canada's leading energy-focused private equity manager. In 2020, Mr. Dielwart resigned from the Board of ARC Financial but remained as Partner and a member of ARC Financial's Investment Committee. He is currently representing ARC Financial on the board of Aspenleaf Energy Limited. He is a past-Chair of the Board of Governors of the Canadian Association of Petroleum Producers and a member of the Association of Professional Engineers and Geoscientists of Alberta. Mr. Dielwart has a Bachelor of Science with distinction (civil engineering) from the University of Calgary. The Board believes that Mr. Dielwart is a diligent, independent director who provides the Company with a wealth of experience in leadership, finance and entrepreneurship along with a strong understanding of the commodity markets in which we operate, specifically the oil and gas markets.
Alan J. Fohrer California, US	2013	Mr. Fohrer is the former Chair and Chief Executive Officer of Southern California Edison Company, a subsidiary of Edison International ("Edison") that is one of the largest electric utilities in the US. Mr. Fohrer served as President and Chief Executive Officer of Edison Mission Energy ("EME") from 2000 to 2001, a former subsidiary of Edison that owned and operated independent power facilities. During his tenure at EME, Mr. Fohrer restructured a number of international projects, which enhanced the value of the assets sold in subsequent years. Mr. Fohrer also served as Vice-President, Senior Vice-President, Executive Vice-President and Chief Financial Officer of both Edison and Southern California Edison from 1991 to 2000. After 37 years with Edison, Mr. Fohrer retired in December 2010. Mr. Fohrer is currently an independent member of the board of PNM Resources, Inc., a publicly traded energy holding company. He is also a member of the Viterbi School of Engineering Board of Councilors for the University of Southern California and on the Board of the California Science Center Foundation. Mr. Fohrer has served on boards of directors of the Institute of Nuclear Power Operations, the California Chamber of Commerce, Duratek, Inc., Osmose Utilities Services, Inc., MWH, Inc., Blue Shield of California and Synagro. Mr. Fohrer holds a Master of Science in civil engineering from the University of Southern California, Los Angeles, as well as a Master of Business Administration from California State University in Los Angeles. Mr. Fohrer brings to the Company and the Board experience in accounting, finance, dam safety and the power industry from both a regulated and unregulated market perspective.

TransAlta Corporation • Annual Information Form    93

Name, Province (State) and Country of Residence	Year First Became Director	Principal Occupation
Laura W. Folse Texas, US	2021	Ms. Folse was the Chief Executive Officer of BP Wind Energy North America Inc. until 2016. As Chief Executive Officer for BP Wind Energy she led a business with over 500 employees and contractors that consisted of 14 wind farms across eight states with an operating capacity of over 2.5 gigawatts. Prior to her role as Chief Executive Officer of BP Wind Energy, she served at BP p.l.c. as Executive Vice President, Science, Technology, Environment and Regulatory Affairs, in which she led the operational, scientific and technological programs within the multi-billion dollar cleanup and restoration effort in response to the 2010 BP Macondo well explosion off the coast of Louisiana. At its peak, the cleanup project team that she led consisted of over 45,000 people working across the US Gulf and Mexico. She successfully negotiated with federal, state and local government officials to implement and conclude the offshore and onshore cleanup efforts. Prior thereto, she held numerous leadership roles with increasing responsibility and complexity within BP p.l.c. Ms. Folse is currently an independent member of the Board of Directors of Enerflex Ltd., a publicly traded energy services company and she is an independent member of the Board of Directors of Pacolet Milliken, a private investment company operating in real estate and power and infrastructure. Ms. Folse is a Board member for the Auburn University College of Arts and Sciences and was a Board member for the American Wind Energy Association from 2016 to 2019. Ms. Folse has a Master of Management in Business from Stanford University, a Master of Science in Geology from the University of Alabama and a Bachelor of Science in Geology from Auburn University. Ms. Folse brings to the Company and the Board experience in corporate risk management, large-scale crisis management, leveraging data analysis, leading large and complex organizations, and driving cultural change while realizing improvements in safety, operational and financial performance.

TransAlta Corporation • Annual Information Form    94

Name, Province (State) and Country of Residence	Year First Became Director	Principal Occupation
Harry A. Goldgut Ontario, Canada	2019	Mr. Goldgut is Vice Chair of Brookfield's Infrastructure and Renewable Power and Transition groups and provides strategic advice related to Brookfield's open-ended Infrastructure Fund. He is also one of two Brookfield nominees to the Board. Mr. Goldgut was the Chief Executive Officer or Co-CEO and Chair of Brookfield Renewable Power Inc., from 2000 to 2008, and thereafter, until 2015, he was Chair of Brookfield's Power and Utilities Group. From 2015 to 2018, he served as Executive Chair of Brookfield's Infrastructure and Renewable Power groups. He joined Brookfield in 1997 and led the expansion of Brookfield's renewable power and utilities operations. He had primary responsibility for strategic initiatives, acquisitions and senior regulatory relationships. He was responsible for the acquisition of the majority of Brookfield's renewable power assets. He also played a role in the restructuring of the electricity industry in Ontario as a member of several governmental committees, including the Electricity Market Design Committee, the Minister of Energy's Advisory Committee, the Clean Energy Task Force, the Ontario Energy Board Chair's Advisory Roundtable and the Ontario Independent Electricity Operator CEO Roundtable on Market Renewal. Mr. Goldgut also serves on the board of directors of Isagen S.A. ESP, the third-largest power generation company in Colombia, and the Princess Margaret Cancer Foundation in Toronto. He holds a Bachelor of Laws degree from Osgoode Hall Law School at York University. Mr. Goldgut brings to the Company and the Board extensive experience in regulatory and government affairs, as well as experience in acquiring and operating renewable energy assets. Mr. Goldgut's background in renewable energy provides important insight to the Board.
John H. Kousinioris Alberta, Canada	2021	Mr. Kousinioris is President and Chief Executive Officer of TransAlta. Prior to his appointment as President and CEO in 2021, Mr. Kousinioris served as Chief Operating Officer of the Company. As Chief Operating Officer, he was responsible for overseeing operations, shared services, commercial, trading, customer solutions, hedging and optimization at the Company. Prior thereto, Mr. Kousinioris was TransAlta's Chief Growth Officer and Chief Legal and Compliance Officer. Mr. Kousinioris’ prior leadership roles have provided him with responsibility for almost every aspect of the Company’s business. He was also the President of TransAlta Renewables Inc. until Feb. 5, 2021. Prior to joining TransAlta, Mr. Kousinioris was a partner and co-head of the corporate commercial department at Bennett Jones LLP with 30 years of experience in securities law, mergers and acquisitions and corporate governance matters. He is also Vice Chair of the Board of Governors of Bow Valley College and a member of the Board of Directors of the Calgary Stampede Foundation. Mr. Kousinioris has a Bachelor of Arts degree in Honors Business Administration from the Ivey Business School at the University of Western Ontario, a Master of Business Administration degree from York University and a Bachelor of Laws degree from Osgoode Hall Law School at York University. He has attended the Advanced Management Program at Harvard University. Mr. Kousinioris is responsible for the overall stewardship of the Company, including providing strategic leadership. Mr. Kousinioris has demonstrated outstanding vision and leadership with an unwavering commitment to the Company's long-term success.

TransAlta Corporation • Annual Information Form    95

Name, Province (State) and Country of Residence	Year First Became Director	Principal Occupation
Candace J. MacGibbon Ontario, Canada	2023	Ms. MacGibbon is the former Chief Executive Officer and Director of INV Metals Inc., a TSX-listed mining company, from 2015 to 2021, where she was responsible for determining and implementing corporate strategy. Prior thereto, Ms. MacGibbon was the former President and Chief Financial Officer of INV Metals Inc. from 2008 to 2015, responsible for financial and regulatory reporting and for the company's treasury, financial strength and investment policy. Ms. MacGibbon previously held roles within global mining institutional equity sales with RBC Capital Markets and in base metals research as an equity research associate with BMO Capital Markets. Ms. MacGibbon was a former manager at Deloitte LLP and cost analyst with Inco Limited. She is also a board member of Osisko Gold Royalties and a member of Osisko Gold Royalties Audit and Human Resources Committees. Ms. MacGibbon is the president-elect of the Canadian Institute of Mining, Petroleum and Metallurgy. She is a Chartered Professional Accountant with over 25 years’ experience in the mining sector and capital markets. She holds a Bachelor of Arts degree in Economics from the University of Western Ontario and a Diploma in Accounting from Sir Wilfred Laurier University. Ms. MacGibbon brings to the Board attributes and skills focused on leadership, collaboration and integrity, which she has demonstrated through her prior successful senior leadership roles, including as a chief executive officer and a chief financial officer of INV Metals Inc. Ms. MacGibbon provides the Company and the Board energy and motivation with a focus on delivering results, which is complemented by her expertise in strategy, risk management, finance and accounting.

TransAlta Corporation • Annual Information Form    96

Name, Province (State) and Country of Residence	Year First Became Director	Principal Occupation
Thomas M. O'Flynn New Jersey, US	2021	Mr. O’Flynn was the Chief Executive Officer and Chief Investment Officer, AES Infrastructure Advisors. Prior thereto, until 2019, he was Executive Vice President and Chief Financial Officer at AES Corporation and responsible for all aspects of global finance and merger and acquisition teams across six global regions. During his tenure, Mr. O’Flynn helped lead AES through a significant transformation, including strategic exits of non-core markets, which resulted in improved financial stability and allowed for the redeployment of cash to primary growth markets. AES's total shareholder return increased 54 per cent during his tenure and its credit rating improved significantly. Mr. O’Flynn was also a key driver in initiating a major transition to renewables and green energy to significantly improve AES’s growth profile and reduce its carbon footprint. Mr. O'Flynn is the Lead Operating Director of Dimension Renewable Energy, a community solar company. He is a Director of Exus Management Partners, a renewables management and development company. Mr. O'Flynn is a Senior Advisor with Energy Impact Partners, a private energy technology fund investing in high-growth companies in the energy, utility and transportation industries. Mr. O’Flynn was Chief Financial Officer of Powin Energy from December 2021 until December 2022, a battery energy storage company in which Energy Impact Partners is a significant investor. Mr. O’Flynn was with The Blackstone Group Inc. where he was Senior Advisor, Power and Utility Sector, and Chief Operating Officer and Chief Financial Officer of Transmission Developers Inc., a Blackstone-controlled entity that develops innovative power transmission projects in an environmentally responsible manner. Prior thereto he was Executive Vice President and Chief Financial Officer at Public Service Enterprise Group Incorporated and was Head of North American Power at Morgan Stanley. Mr. O’Flynn has a Bachelor of Arts in Economics from Northwestern University and a Master of Business Administration in Finance from the University of Chicago. He is also an adjunct professor at Northwestern University for a master’s program at the Institute for Sustainability and Energy. He has led successful organizational transformations, including by focusing on acquisitions and greenfield development. Mr. O’Flynn provides the Company and Board with demonstrated ability to realize shareholder value through his significant senior executive experience at large electricity companies.

TransAlta Corporation • Annual Information Form    97

Name, Province (State) and Country of Residence	Year First Became Director	Principal Occupation
Bryan D. Pinney Alberta, Canada	2018	Mr. Pinney has over 30 years of experience serving many of Canada's largest corporations, primarily in energy and resources and construction. Mr. Pinney served as Calgary Managing Partner of Deloitte LLP from 2002 through 2007 and as National Managing Partner of Audit & Assurance from 2007 to 2011 and Vice-Chair until June 2015. Mr. Pinney was a past member of Deloitte LLP's Board of Directors. He was a partner at Andersen LLP and served as Calgary Managing Partner from 1991 through May 2002. Mr. Pinney is currently the lead director for North American Construction Group Ltd. (NYSE, TSX) and a director of SNDL Inc. (NASDAQ). Mr. Pinney is the former chair of the Board of Governors of Mount Royal University and has served on a number of non-profit boards. He is a Fellow of the Institute of Chartered Accountants, a Chartered Business Valuator and is a graduate of the Ivey Business School at the University of Western Ontario with an undergraduate honours degree in Business Administration. He is also a graduate of the Canadian Institute of Corporate Directors. Mr. Pinney's extensive leadership accomplishments, financial expertise, knowledge of regulatory and compliance matters and diverse range of industry experience make him an important contributor to the Board.
James Reid Alberta, Canada	2021	Mr. Reid is a former Managing Partner of Brookfield Asset Management Inc. who led Brookfield's Private Equity Group in Calgary, Alberta, until 2021. In that role he was responsible for originating, evaluating and structuring investments and financings in the energy sector and overseeing operations in Brookfield's private equity energy segment. Prior to moving into the private equity group, Mr. Reid was the Chief Investment Officer, Energy for Brookfield’s Infrastructure Group. He established Brookfield’s Calgary office in 2003 after spending several years as Chief Financial Officer for two oil and gas exploration and production companies in Western Canada. Mr. Reid is also one of two Brookfield nominees to the Board pursuant to the Investment Agreement. Mr. Reid obtained his Chartered Accountant designation at PricewaterhouseCoopers in Toronto and holds a Bachelor of Arts in commerce from the University of Toronto. Mr. Reid brings to the Company and the Board considerable experience in leadership, finance, mergers and acquisitions and organizational change. His wealth of knowledge in the energy sector and his former role with Brookfield, our long-term shareholder, makes him an important addition to the Board.

TransAlta Corporation • Annual Information Form    98

Name, Province (State) and Country of Residence	Year First Became Director	Principal Occupation
Manjit K. Sharma Ontario, Canada	2023	Ms. Sharma has over 30 years of experience that spans a variety of industries (power generation, oil and gas, financial services, manufacturing, engineering services and others). Until 2021, she was the Chief Financial Officer of WSP Canada Inc. In this role, she was responsible for leading the finance, real estate, procurement, tax and shared services functions across Canada. She is a former member of the national executive team of General Electric Canada ("GE Canada"), serving as Chief Financial Officer from 2016 to 2019. From 1999 to 2016, she held various senior positions with GE Canada, with responsibilities that spanned business strategy development and execution, business product and services development, mergers and acquisitions, tax oversight, risk, governance, key components of human resources strategy (including compensation, union negotiations, pension and benefits), and diversity and inclusion. Ms. Sharma currently serves as a board member of each of Vermilion Energy Inc., Finning International Inc. and Export Development Canada. Ms. Sharma holds a Bachelor of Commerce degree (with Honours) from the University of Toronto, is a Fellow Chartered Accountant and holds the ICD.D Directors designation and the GCB.D Global Competent Boards designation. Ms. Sharma provides the Company and Board with diverse board experience, including executive, finance and leadership within different industries and businesses.

TransAlta Corporation • Annual Information Form    99

Name, Province (State) and Country of Residence	Year First Became Director	Principal Occupation
Sandra R. Sharman Ontario, Canada	2020	Ms. Sharman is the Senior Vice President and Group Head, People, Culture and Brand of Canadian Imperial Bank of Commerce ("CIBC"). In this role, she leads the Human Resources, Communications, Marketing and Enterprise Real Estate teams at CIBC, supporting execution of business strategy, transforming to a purpose-driven bank and enabling a world-class culture. Ms. Sharman and her team are responsible for developing and delivering the Global Human Capital Strategy designed to challenge conventional thinking, drive business solutions and shape the culture of the bank. Her key areas of accountabilities also include workplace transformation, compensation and benefits, employee relations, policy and governance, talent management, marketing, corporate real estate, including the bank’s new global headquarters, CIBC Square, and all aspects of internal and external communications and public affairs, including government relations and awards. Ms. Sharman is a proven business leader with over 30 years of human resources and financial services experience in both Canada and the US, and she has played a leading role in shaping an inclusive and collaborative culture at CIBC, focused on empowering and enabling employees to reach their full potential. Ms. Sharman assumed the leadership of Human Resources at CIBC in 2014 and added accountability for communications and public affairs in 2017. Since then, her portfolio has expanded to encompass purpose, brand, marketing and, most recently, corporate real estate. Ms. Sharman earned her Master of Business Administration from Dalhousie University. Ms. Sharman provides the Company and Board with executive experience, diversity and inclusion related competencies and leadership accomplishments within an international and complex business.
Sarah A. Slusser Washington, US	2021	Ms. Slusser is the Chief Executive Officer of Cypress Creek Renewables, LLC ("Cypress Creek"), a solar and storage independent power producer that develops, owns and operates projects in the US. She joined Cypress Creek as Chief Executive Officer in 2019 to reposition the company for sustainable growth. Prior to this, she founded Point Reyes Energy Partners LLC, a solar and energy storage advisory and development company, where she provided strategic advice to a number of large companies in the renewable sector until 2016. She remains a founding partner of Point Reyes Energy Partners. Prior to this, she co-founded GeoGlobal Energy LLC, a geothermal company in the US, Chile and Germany, which was sold to its cornerstone investor in 2015. Before co-founding GeoGlobal Energy, Ms. Slusser worked at AES for 21 years, where she advanced into increasingly significant leadership roles, ultimately being appointed Senior Vice President and Managing Director reporting directly to the Chief Executive Officer and leading the corporate group. She was President of one of eight divisions of AES that was responsible for all development, construction and operations in the Caribbean, Mexico and Central America. Ms. Slusser is a member of the Board of Directors of the Redwood Foundation, a family foundation promoting education and the environment and Our Food Chain, a non-profit promoting healthy eating. Ms. Slusser holds a Bachelor of Arts (cum laude) in geology from Harvard University and a Master of Business Administration from the Yale School of Management. Ms. Slusser’s brings to the Company and the Board a broad range of experience in the electricity sector at innovative, competitive renewable and electricity companies and provides the Board with significant capital allocation and M&A expertise.

TransAlta Corporation • Annual Information Form    100

Officers

The name, province or state and country of residence of each of our executive officers as at Feb. 22, 2024, their respective position and office and their respective principal occupation are set out below.

Name	Principal Occupation	Residence
John H. Kousinioris	President and Chief Executive Officer	Alberta, Canada
Todd J. Stack	Executive Vice President, Finance and Chief Financial Officer	Alberta, Canada
Jane N. Fedoretz	Executive Vice President, People, Culture and Chief Administrative Officer	Alberta, Canada
Kerry L. O'Reilly Wilks	Executive Vice President, Growth and Energy Marketing	Alberta, Canada
Christopher D. Fralick	Executive Vice President, Generation	Alberta, Canada
Blain M. van Melle	Executive Vice President, Commercial and Customer Relations	Alberta, Canada
Aron J. Willis	Executive Vice President, Project Delivery and Construction	Alberta, Canada
Scott T. Jeffers	Acting Executive Vice President, Legal and Corporate Secretary	Alberta, Canada
Brent V. Ward	Senior Vice President, M&A, Strategy and Treasurer	Alberta, Canada
David C. Little	Senior Vice President, Growth	California, USA

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

•On April 1, 2021, Mr. Kousinioris was appointed President and Chief Executive Officer. Prior to April 2021, Mr. Kousinioris was Chief Operating Officer of TransAlta. Prior to September 2019, Mr. Kousinioris was Chief Growth Officer of TransAlta.

•Prior to February 2021, Mr. Stack was Chief Financial Officer of TransAlta. Prior to May 2019, Mr. Stack was Managing Director and Corporate Controller of TransAlta.

•Prior to November 2023, Ms. Fedoretz was Executive Vice President, People, Talent and Transformation of TransAlta. Prior to February 2021, Ms. Fedoretz was Chief Talent and Transformation Officer of TransAlta.

•Prior to November 2023, Ms. O'Reilly Wilks was Executive Vice President, Legal, Commercial and External Affairs of TransAlta. Prior to February 2021, Ms. O'Reilly Wilks was Chief Officer, Legal, Regulatory and External Affairs of TransAlta. Prior to August 2019, Ms. O'Reilly Wilks was Chief Legal and Compliance Officer of TransAlta.

•Prior to September 2022, Mr. Fralick was President and Chief Executive Officer of Atura Power, a Canadian power generation company. Prior to 2020, Mr. Fralick was Chief Operating Officer of Ontario Power Generation.

•Prior to November 2023, Mr. van Melle was Executive Vice President, Alberta Business of TransAlta. Prior to February 2021, Mr. van Melle was Senior Vice President, Trading and Commercial of TransAlta. Prior to August 2019, Mr. van Melle was Managing Director and Head Trader of TransAlta.

•Prior to November 2023, Mr. Willis was Executive Vice President, Growth of TransAlta. Prior to February 2021, Mr. Willis was Senior Vice President, Growth of TransAlta. Prior to August 2019, Mr. Willis was Senior Vice President, Growth and Commercial of TransAlta. Prior to April 2019, Mr. Willis was Senior Vice President, Commercial, Gas and Renewables Operations of TransAlta.

•Prior to November 2023, Mr. Jeffers was Vice President and Corporate Secretary of TransAlta. Prior to September 2021, Mr. Jeffers was Managing Director and Corporate Secretary of TransAlta.

•Prior to February 2021, Mr. Ward was Managing Director and Treasurer of TransAlta.

•Prior to November 2023, Mr. Little was Vice President and Managing Director - USA of Innergex Renewable Energy Inc. Prior to July 2021, Mr. Little was Senior Director and Head of USA of Innergex Renewable Energy Inc.

TransAlta Corporation • Annual Information Form    101

As of Feb. 22, 2024, the directors and executive officers of TransAlta, as a group, beneficially owned, directly or indirectly, or exercised control or direction over less than one per cent of our outstanding common shares.

Interests of Management and Others in Material Transactions

No director or executive officer of TransAlta, no person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over more than 10 per cent of our common shares, and no associate or affiliate of any of them, has or has had any material interest, direct or indirect, in any transaction involving TransAlta within the three most recently completed financial years or to date in 2024 or in any proposed transactions that have materially affected or will materially affect TransAlta.

In connection with the Brookfield Investment, Mr. James Reid and Mr. Harry Goldgut were initially nominated by Brookfield and elected to the Board of Directors on May 4, 2021, and April 26, 2019, respectively. See the "Directors and Officers" section of this AIF for further details. Brookfield is also entitled to receive certain funding fees, management fees and interest and dividends on its $750 million investment.

Indebtedness of Directors, Executive Officers and Senior Officers

Since Jan. 1, 2023, there has been no indebtedness outstanding to TransAlta from any of our directors, executive officers, senior officers or associates of any such directors, executive officers or senior officers.

Corporate Cease Trade Orders, Bankruptcies or Sanctions

Corporate Cease Trade Orders and Bankruptcies

Except as noted below, no director, executive officer or controlling security holder of the Company is, as at the date of this AIF, or has been, within the past 10 years before the date hereof, a director or executive officer of any other issuer that, while that person was acting in that capacity:

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

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

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

Mr. Reid is a director of Second Wave Petroleum Inc. ("SWP"), a private oil and gas exploration and production company. On June 30, 2017, SWP made an assignment into bankruptcy pursuant to the Bankruptcy and Insolvency Act (Canada) ("BIA"). On Sept. 7, 2017, SWP made a proposal under the BIA and on Oct. 5, 2017, the proposal was approved by the Court of Queen's Bench of Alberta and the bankruptcy was annulled.

Mr. Dielwart was Chair of the board of directors of Denbury Resources Inc., which filed for bankruptcy protection in the US on July 29, 2020, under a prepackaged reorganization plan with its bondholders. Denbury emerged from Chapter 11 on Sept. 18, 2020, at which time the board of directors was reconstituted and Mr. Dielwart ceased being a director.

TransAlta Corporation • Annual Information Form    102

Personal Bankruptcies

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

Penalties or Sanctions

No director, executive officer or controlling security holder of the Company has been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, other than penalties for late filing of insider reports; or been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

Material Contracts

Other than contracts entered into in the ordinary course of business, the Company believes that the following are material contracts, the particulars of which are disclosed elsewhere in this AIF, to which the Company or its subsidiaries are a party:

•Investment Agreement – See the "Capital and Loan Structure – Investment Agreement and E&O Agreement" section of this AIF for further details.

•E&O Agreement – See the "Capital and Loan Structure – Investment Agreement and E&O Agreement" section of this AIF for further details.

•Registration Rights Agreement – See the "Capital Structure – Registration Rights Agreement" section of this AIF for further details.

•Off-Coal Agreement – See the "Business of TransAlta – Gas Segment – Off-Coal Agreement" section of this AIF for further details.

Conflicts of Interest

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

Legal Proceedings and Regulatory Actions

TransAlta is occasionally named as a party in claims and legal proceedings that arise during the normal course of its business. We review each of these claims, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in our favour or that such claim may not have a material adverse effect on TransAlta. For further information, refer to our audited consolidated financial statements for the year ended Dec. 31, 2023, which financial statements are incorporated by reference herein. Also, see the "Documents Incorporated by Reference" section of this AIF for further details.

TransAlta Corporation • Annual Information Form    103

Brazeau Facility – Claim against the Government of Alberta

On Sept. 9, 2022, the Company filed a Statement of Claim against the Alberta Government in the Alberta Court of King’s Bench seeking a declaration that: (a) granting mineral leases within five kilometres of the Brazeau facility is a breach of the 1960 agreement between the Company and the Alberta Government; and (b) the Alberta Government is required to indemnify the Company for any costs or damages that result from the risks of hydraulic fracturing near the Brazeau facility. On Sept. 29, 2022, the Alberta Government filed its Statement of Defence, which asserts, among other things, that the Company: (a) is trying to usurp the jurisdiction of the AER; and (b) is out of time under the Limitations Act (Alberta). The trial was scheduled for two weeks starting Feb. 26, 2024. The parties to the matter, along with Cenovus Energy Inc., sought an adjournment when AER Proceeding 379 was adjourned. The trial is scheduled to resume in February 2025 in the event the parties are unable to resolve the dispute prior to such date.

Brazeau Facility – Well Licence Applications to Consider Hydraulic Fracturing

The Alberta Energy Regulator ("AER") issued a subsurface order on May 27, 2019, which does not permit any hydraulic fracturing within three kilometres of the Brazeau facility but permits hydraulic fracturing in all formations (except the Duvernay) within three to five kilometres of the Brazeau facility. Subsequently, two oil and gas operators submitted applications to the AER for 10 well licences (which include hydraulic fracturing activities) within three to five kilometres of the Brazeau facility.

The Company's position, based on independent expert analysis commissioned by the Government of Alberta, is that hydraulic fracturing activities within five kilometres of the Brazeau facility pose an unacceptable risk and that the applications should be denied. The regulatory hearing to consider these applications - Proceeding 379 - was adjourned to April 2025. The other parties to the hearing, including the Company, have supported the adjournment.

Garden Plain

Garden Plain I LP, a wholly owned subsidiary of the Company, retained a third-party contractor to construct the Garden Plain wind project near Hanna, Alberta. The contractor experienced scheduling delays, challenges with construction and significant cost overruns, resulting in overdue deadlines, and has asserted a claim for $49 million in damages. The Company disputes this claim in its entirety and asserts a counterclaim. The parties have initiated the dispute resolution procedure, and the arbitration hearing is set down for three weeks starting April 14, 2025.

Hydro Power Purchase Arrangement Emission Performance Credits

The Balancing Pool claimed entitlement to 1,750,000 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 EPCs under dispute had no recorded book value as they were internally generated. The Balancing Pool claimed ownership of the EPCs because it believed the change-in-law provisions under the Hydro PPA required the EPCs to be passed through to the Balancing Pool. TransAlta disputed this claim. The parties have reached a confidential settlement and this matter is now resolved.

Sundance A Decommissioning

TransAlta filed an application with the Alberta Utilities Commission 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. The application is being heard in the first quarter of 2024 with a decision expected to be rendered in the third quarter of 2024.

TransAlta Corporation • Annual Information Form    104

Transfer Agent and Registrar

The transfer agent and registrar for our common shares and Series A Shares, Series B Shares, Series C Shares, Series D Shares, Series E Shares and Series G Shares is Computershare Investor Services Inc. Common shares are transferable in Vancouver, Calgary, Toronto, Montréal and Halifax. Series A Shares, Series B Shares, Series C Shares, Series D Shares, Series E Shares and Series G Shares are transferable in Calgary and Toronto. The transfer agent and registrar for our common shares in the US is Computershare Trust Company at its principal office in Jersey City, New Jersey.

Interests of Experts

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

Our auditors, Ernst & Young LLP, are independent with respect to the Company in the context of 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.

Additional Information

Additional information in relation to TransAlta may be found on our website at www.transalta.com and under TransAlta's profile on SEDAR+ at www.sedarplus.ca and EDGAR at www.sec.gov.    

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

Additional financial information is provided in our audited consolidated financial statements as at and for the year ended Dec. 31, 2023, and in the related annual Management's Discussion and Analysis, each of which is incorporated by reference in this AIF. See the "Documents Incorporated by Reference" section of this AIF.

Audit, Finance and Risk Committee

General

The members of TransAlta's Audit, Finance and Risk Committee ("AFRC") satisfy the requirements for independence under the provisions of the Canadian Securities Administrators, National Instrument 52-110 – Audit Committees, Section 303A of the NYSE Rules and Rule 10A-3 under the US Securities and Exchange Act of 1934. The AFRC's Charter requires that it be made up of a minimum of three independent directors. The AFRC currently consists of five independent members: Bryan D. Pinney (Chair), Alan J. Fohrer, Thomas M. O'Flynn, Manjit K. Sharma and Candace J. MacGibbon.

All members of the committee are financially literate pursuant to both Canadian and US securities requirements and each member of the AFRC has also been determined by the Board of Directors to be an "audit committee financial expert," within the meaning of Section 407 of the US Sarbanes-Oxley Act of 2002.

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Mandate of the Audit, Finance and Risk Committee

The AFRC provides assistance to the Board of Directors in fulfilling its oversight responsibilities with respect to:

•The integrity of the Company's financial statements and financial reporting process;

•The systems of internal financial controls and disclosure controls established by management;

•The risk identification and assessment process conducted by management, including the programs established by management to respond to such risks;

•The internal audit function;

•Financings and financing strategy;

•Compliance with financial, legal and regulatory requirements; and

•The external auditors' qualifications, independence and performance.

In so doing, it is the AFRC's responsibility to maintain an open avenue of communication between it and the external auditors, the internal auditors and management of the Company.

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

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

The AFRC must also designate at least one member as an "audit committee financial expert." The designation of a member or members as an "audit committee financial expert" is based on that individual's education and experience, which the individual will bring to bear in carrying out his or her duties on the AFRC. Designation as an "audit committee financial expert" does not impose on such person any duties, obligations and liability that are greater than the duties, obligations and liability imposed on another member of the AFRC and Board of Directors in the absence of such designation.

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

Audit, Finance and Risk Committee Charter

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

Relevant Education and Experience of Audit, Finance and Risk Committee Members

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

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Name of AFRC Member	Relevant Education and Experience
Bryan D. Pinney (Chair)	Mr. Pinney has 40 years of experience in financial auditing, valuation and advising companies in energy and natural resources. He is an independent director of North American Construction Group Ltd. and chair of its Audit and Finance Committee. He is also an independent director of SNDL, Inc. and chair of its Audit and Finance Committee. He served as a member of Deloitte’s Board of Directors and chair of the Finance and Audit Committee. He was the recent Chair and a member of the Board of Governors of Mount Royal University and has previously served on a number of non-profit boards. He has been a Chartered Accountant since December 1978, a Fellow of the Chartered Professional Accountants of Alberta since January 2009 and a Chartered Business Valuator of Canada since December 1990. Mr. Pinney obtained a Bachelor of Arts in business administration from the University of Western Ontario in 1975 and also completed the Directors Education Program offered by the Institute of Corporate Directors in Canada in 2012.
Alan J. Fohrer	Prior to his retirement in December 2010, Mr. Fohrer was Chair and Chief Executive Officer of Southern California Edison Company, a subsidiary of Edison and one of the largest electric utilities in the US. Prior to that, Mr. Fohrer served as Vice-President, Senior Vice-President, Executive Vice-President and Chief Financial Officer of both Edison and Southern California Edison Company. Mr. Fohrer also serves on the audit committee of PNM Resources Inc., a public company. Mr. Fohrer holds a Master of Business Administration from California State University in Los Angeles.
Thomas M. O'Flynn	Mr. O'Flynn was the Chief Financial Officer of Powin Energy, an entity in which Energy Impact Partners LP (a private energy technology fund) is a major investor. Prior thereto, Mr. O'Flynn was Chief Executive Officer and Chief Investment Officer at the AES Corporation, Executive Vice President and Chief Financial Officer at Public Service Enterprise Group Incorporated and Head of North American Power at Morgan Stanley. Mr. O'Flynn has a Bachelor of Arts in economics from Northwestern University and a Master of Business Administration, Finance from the University of Chicago.
Manjit K. Sharma	Ms. Sharma was the Chief Financial Officer of WSP Canada Inc. Prior to WSP Canada Inc., she was on the National Executive Team of General Electric Canada (GE Canada), serving as Chief Financial Officer from 2016 to 2019. Ms. Sharma currently serves as a board member of each of Vermilion Energy Inc., Finning International Inc. and Export Development Canada. Ms. Sharma holds a Bachelor of Commerce degree (with honours) from the University of Toronto, is a Fellow Chartered Accountant and holds the ICD.D Directors designation and the GCB.D Global Competent Boards designation.
Candace J. MacGibbon(1)	Ms. MacGibbon was the former Chief Executive Officer and Chief Financial Officer of INV Metals Inc. Prior to this, she was a former manager at Deloitte LLP and held roles within RBC Capital Markets and BMO Capital Markets. Ms. MacGibbon currently serves as a board member of each of Carbon Streaming Corp. and Osisko Gold Royalties, and she is a member of the Audit of Human Resources Committees of Osisko Gold Royalties. Ms. MacGibbon holds a Bachelor of Arts degree in economics from the University of Western Ontario and is a Chartered Professional Accountant with over 25 years of experience in the mining sector and capital markets.

(1)    Ms. MacGibbon was appointed to the AFRC on April 28, 2023.

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Other Board Committees

In addition to the AFRC, TransAlta has three other standing committees: the Governance, Safety and Sustainability Committee, the Human Resources Committee and the Investment Performance Committee. The members of these committees as at Dec. 31, 2023, are:

Governance, Safety and Sustainability Committee	Human Resources Committee
Chair: Rona H. Ambrose	Chair: Sandra R. Sharman
Alan J. Fohrer	Rona H. Ambrose
Laura W. Folse	Bryan D. Pinney
Sandra R. Sharman	Sarah A. Slusser
Candace J. MacGibbon	Manjit K. Sharma
Investment Performance Committee
Chair: Laura W. Folse
Thomas M. O'Flynn
Harry A. Goldgut
James Reid
Sarah A. Slusser

Mr. John P. Dielwart also attends each of the Committee meetings in his capacity as Chair of the Board of Directors.

Charters of the Governance, Safety and Sustainability Committee, the Human Resources Committee and the Investment Performance Committee may be found on our website under Governance, Board Committees at www.transalta.com. Further information about the Board of Directors and our corporate governance may also be found on our website or in our Management Proxy Circular, which is filed on SEDAR+ at www.sedarplus.ca and EDGAR at www.sec.gov.

Fees Paid to Ernst & Young LLP

For the years ended Dec. 31, 2023, and Dec. 31, 2022, Ernst & Young LLP and its affiliates billed $4,788,655 and $4,608,258, respectively, as detailed below.

Ernst & Young LLP
Year Ended Dec. 31	2023		2022
Audit Fees	$	3,368,977	$	2,873,395
Audit-related fees(1)		1,374,803		1,618,751
Tax fees		5,850		116,112
All other fees		39,025		—
Total	$	4,788,655	$	4,608,258

(1)    Included in the audit-related fees are $504,522 (2022 – $966,515) of fees billed to TransAlta Renewables.

No other audit firms provided audit services in 2023 or 2022.

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The nature of each category of fees is described below:

Audit Fees

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

Audit-Related Fees

Assurance and related services that are reasonably related to the performance of the audit or review of our financial statements that are not included in the Audit Fees. Audit-related fees include statutory audits, pension audits and other compliance audits.

Tax Fees

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

All Other Fees

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

Pre-Approval Policies and Procedures

The AFRC has considered whether the provision of services other than audit services is compatible with maintaining the auditors' independence. In May 2002, the AFRC adopted a policy that prohibits TransAlta from engaging the auditors for "prohibited" categories of non-audit services and requires pre-approval of the AFRC for other permissible categories of non-audit services, such categories being determined under the Sarbanes Oxley Act of 2002. This policy also provides that the Chair of the AFRC may approve permissible non-audit services during the quarter and report such approval to the AFRC at its next regularly scheduled meeting.

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Appendix "A"

TransAlta Corporation (the “Corporation”)

Audit, Finance and Risk Committee Charter

A.    Establishment of Committee and Procedures

1.    Composition of Committee

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

2.    Appointment of Committee Members

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

3.    Vacancies

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

4.    Committee Chair

The Board shall appoint a Chair for the Committee on the recommendation of the GSSC.

5.    Absence of Committee Chair

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

6.    Secretary of Committee

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

7.    Meetings

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

The Committee shall also meet in separate executive session.

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8.    Quorum

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

9.    Notice of Meetings

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

10.    Attendance at Meetings

At the invitation of the Chair of the Committee, other Board members, the President and Chief Executive Officer ("CEO") of the Corporation, other officers or employees of the Corporation, the external auditors, and other experts or consultants may attend a meeting of the Committee.

11.    Procedure, Records and Reporting

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

12.    Review of Charter and Evaluation of Committee

The Committee shall evaluate its performance and review and assess the adequacy of its Charter at least annually or otherwise, as it deems appropriate. All changes proposed by the Committee are reviewed and approved by the GSSC and the Board.

13.    Outside Experts and Advisors

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

B.    Duties and Responsibilities of the Chair

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

The Chair is responsible for:

1.    Chairing meetings of the Committee and ensuring that the Committee is properly organized so that it functions effectively and meets its obligations and responsibilities.

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

3.    Working with the CEO, the Executive Vice President, Finance and Chief Financial Officer (the "CFO") of the Corporation, and the Corporate Secretary of the Corporation, as applicable, on the development of agendas and related materials for the meetings.

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

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

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The Chair of the Committee shall review all expense accounts and perquisites of the Chair of the Board and the CEO not less than quarterly to ensure compliance with the Corporation’s policies, and shall report to the Committee on an annual basis.

C.    Mandate of the Committee

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

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

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

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

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

D.    Duties and Responsibilities of the Committee

1.    Financial Reporting, External Auditors and Financial Planning

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

(a)    Review with Management and the external auditors the Corporation's financial reporting process the work to be conducted in conjunction with the annual audit and the preparation of the financial statements, including, without limitation, the annual audit plan of the external auditors, the judgment of the external auditors as to the quality, not just the acceptability, of and the appropriateness of the Corporation's accounting principles as applied in its financial reporting and the degree of aggressiveness or conservatism of the Corporation's accounting principles and underlying estimates;

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

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(c)    Review with Management and the external auditors the Corporation's interim financial statements, including the notes thereto, "Management's Discussion and Analysis," the related earnings release, and approve their release to the public as required;

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

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

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

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

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

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

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

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

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

(f)    Review quarterly with senior Management, the Executive Vice President, Legal and Corporate Secretary (or, as necessary, outside legal advisors) of the Corporation, and the Corporation's internal and external auditors, the effectiveness of the Corporation's internal controls to ensure the Corporation is in compliance with legal and regulatory requirements and the Corporation's policies;

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

(h)    Discuss with Management and the external auditors any correspondence from or with regulators or governmental agencies, any employee complaints or any published reports that raise material issues regarding the Corporation's financial statements or accounting policies.

B)    Duties and Responsibilities Related to the External Auditors

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

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

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

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

(iv)    review and discuss annually with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors' independence, including, without limitation, (a) requesting, receiving and reviewing, at least annually, a formal written statement from the external auditors delineating all relationships that may reasonably be thought to bear on their independence with the Corporation; (b) discussing with the external auditors any relationships or services that the external auditors believe may affect their objectivity and professional skepticism; (c) reviewing with the external auditors the experience and qualifications of the senior personnel who are providing audit services to the Corporation; (d) reviewing the quality control procedures of the external auditors, including obtaining confirmation that the external auditors are in compliance with Canadian and US regulatory registration requirements; and (e) evaluating the communication and interaction with the external auditor including quality of service considerations;

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

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

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

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

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C)    Duties and Responsibilities Related to Financial Planning

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

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

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

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

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

2.    Internal Audit

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

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

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

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

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

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

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

3.    Risk Management

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

The Committee shall:

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

(b)    Receive and review Managements' quarterly risk update including an update on residual risks;

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

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

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

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

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

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

(i)    Annually, together with Management, report and review with the Board:

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

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

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

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

4.    Governance

A)    Public Disclosure, Legal and Regulatory Reporting

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

(b)    Review quarterly with the Executive Vice President, Legal and Corporate Secretary, and, if necessary, outside legal advisors, significant legal, compliance or regulatory matters that may have a material effect on the Corporation's financial statements;

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

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

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

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

B)    Pension Plan Governance

(a)    Review annually the Annual Pension Report and financial statements of the Corporation's pension plans including the actuarial valuation, asset/liability forecast, asset allocation, manager performance and plan operating costs, and reporting thereon to the Board annually; and

(b)    Together with the Human Resources Committee of the Board, review annually, and as required, the overall governance of the Corporation's pension plans, approving the broad

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objectives of the plans, the statement of investment policy, the appointment of investment managers, and reporting thereon to the Board annually.

C)    Information Technology – Cybersecurity

(a)    Receive biannually a system status update with respect to the Corporation's core IT operating systems; and

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

D)    Administrative Responsibilities

(a)    Review the annual audit of expense accounts and perquisites of the directors, the CEO and the CEO's direct reports and their use of corporate assets;

(b)    Establish procedures for the receipt, retention and treatment of complaints relating to securities law, accounting, internal accounting controls, or auditing matters;

(c)    Review incidents, complaints or information reported through the Ethics Help Line addressed to the Committee or relating to securities law, accounting, internal accounting controls, or auditing matters;

(d)    Establish procedures for the investigation of complaints or allegations, and, in respect of potentially material complaints or allegations, report to the Board thereon and ensure that appropriate action is taken as necessary to address such matter;

(e)    Review and consider any related party transaction and to recommend, if necessary, the use of a standing committee or an ad hoc special committee to assist the Board in the evaluation of any such related party transaction;

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

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

E.    Compliance and Powers of the Committee

(a)    The responsibilities of the Committee comply with applicable Canadian laws and regulations, such as the rules of the Canadian Securities Administrators, and with the disclosure and listing requirements of the Toronto Stock Exchange, as they exist on the date hereof. In addition, this Charter complies with applicable US laws, such as the Sarbanes-Oxley Act and the rules and regulations adopted thereunder, and with the New York Stock Exchange's corporate governance standards, as they exist on the date hereof.

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

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Appendix "B"

Glossary of Terms

This Annual Information Form includes the following defined terms:

"AESO" – The independent system operator and regulatory authority for the Alberta Interconnected Electric System.

"ASPP" – Automatic share purchase plan.

"Arrangement Agreement" - An arrangement agreement between TransAlta and TransAlta Renewables under which TransAlta acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly, or indirectly, by TransAlta and certain of its affiliates, resulting in TransAlta Renewables becoming a wholly owned subsidiary of TransAlta.

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

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

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

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

"Brookfield" – Brookfield Renewable Partners.

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

"CBCA" – Canada Business Corporations Act.

"CO2e" – Carbon dioxide equivalent.

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

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

"EBITDA" – Earnings before interest, taxes, depreciation, and amortization.

"ED&I" – Equity, Diversity and Inclusion.

"EPCs" – Emission Performance Credits.

"ESG" – Environment, Sustainability and Governance.

"FERC" – Federal Energy Regulatory Commission.

TransAlta Corporation • 2023 Annual Information Form        B-1

"forcemajeure" – 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.

"FMG" - Fortescue Metals Group Ltd.

"GGPPA" – Greenhouse Gas Pollution Pricing Act (Canada).

"GHG"–Greenhousegases that have the potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons.

"GW" – Gigawatt, which is a measure of electric power equal to 1,000 MW.

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

"IESO" – Independent Electricity System Operator.

"IFRS" – International Financial Reporting Standards.

"IPPs" – Independent power producers

"LTC" – Long-term contract.

"M&A" - Mergers and Acquisitions.

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

"MSHA" – Mine Safety and Health Administration.

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

"NCIB" – Normal Course Issuer Bid.

"NERC" – North American Electric Reliability Corporation.

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

"NGTL" – NOVA Gas Transmission Ltd.

"NYSE" – New York Stock Exchange.

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

"opt-in facility" – A facility that satisfies the eligibility criteria for an opted in facility under Section 4 of the TIER regulation and is voluntarily choosing to participate in the regulation for the purposes of being able to generate emission performance credits.

"PPA" – Power purchase agreement, also referred to as a long-term commercial agreement for the sale of electric energy to a buyer.

"RECs" – Renewable Energy Credits.

"SCE" – Southern Cross Energy Partnership.

"TA Cogen" – TransAlta Cogeneration LP.

"TIER" – Technology Innovation and Emission Reduction Regulation in Alberta.

"TransAlta Renewables" – TransAlta Renewables Inc.

"TSX" – Toronto Stock Exchange.

TransAlta Corporation • 2023 Annual Information Form        B-2

EX-13.2

TRANSALTA CORPORATION

Management’s Discussion and Analysis

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

M2	Forward-Looking Statements	M59	Key Non-IFRS Financial Ratios
M4	Description of the Business	M59	2024 Outlook
M6	Highlights	M62	Material Accounting Policies and Critical Accounting Estimates
M11	Capital Expenditures	M67	Accounting Changes
M12	Significant and Subsequent Events	M67	Environmental, Social and Governance
M15	Segmented Financial Performance and Operating Results	M69	Accelerating Our Business Transformation with a Target to Become Net-Zero by 2045
M23	Performance by Segment with Supplemental Geographical Information	M70	Our 2023 Sustainability Performance
M23	Optimization of the Alberta Portfolio	M72	2024+Sustainability Targets
M26	Fourth Quarter Highlights	M75	Decarbonizing Our Energy Mix
M28	Segmented Financial Performance and Operating Results for the Fourth Quarter	M81	Key Climate Scenario Findings
M29	Selected Quarterly Information	M84	Managing Climate Change Risks and Opportunities
M31	Strategy and Capability to Deliver Results	M94	Enabling Innovation and Technology Adoption
M31	Strategic Priorities and Clean Electricity Growth Plan to 2028	M97	Engaging with Our Stakeholders to Create Positive Relationships
M36	Financial Position	M103	Building a Diverse and Inclusive Workforce
M37	Financial Capital	M106	Progressive Environmental Stewardship
M42	Cash Flows	M112	Delivering Reliable and Affordable Energy
M44	Other Consolidated Analysis	M113	Sustainability Governance
M46	Financial Instruments	M114	Governance and Risk Management
M48	Additional IFRS Measures and Non-IFRS Measures	M125	Disclosure Controls and Procedures

This MD&A should be read in conjunction with our 2023 audited annual consolidated financial statements (the "consolidated financial statements") and our 2023 Annual Information Form ("AIF"), each for the fiscal year ended Dec. 31, 2023. In this MD&A, unless the context otherwise requires, “we”, “our”, “us”, the “Company” and “TransAlta” refer to TransAlta Corporation and its subsidiaries. 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, 2023. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted, except amounts per share, which are in whole dollars to the nearest two decimals. This MD&A is dated Feb. 22, 2024. Additional information respecting TransAlta, including our AIF for the year ended Dec. 31, 2023, is available on SEDAR+ at www.sedarplus.ca, on EDGAR at www.sec.govand on our website at www.transalta.com. Information on or connected to our website is not incorporated by reference herein.

TransAlta Corporation 2023 Integrated Report M1

Forward-Looking Statements

This MD&A includes "forward-looking information" within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of applicable United States securities laws, including the 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 those 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: the acquisition of Heartland (as defined below) and its entire business operations in Alberta and British Columbia, including closing conditions and regulatory approvals pursuant to the Heartland acquisition and the anticipated timing and completion of the acquisition; the annual average earnings before interest, taxes, depreciation and amortization ("EBITDA") to be generated from the Heartland acquisition and other benefits expected to arise from such transaction; the Company’s 2024 Outlook, including Adjusted EBITDA, free cash flow, annualized dividend per share, sustaining capital and energy marketing gross margin; the Company’s expanded growth targets to deliver 1.75 GW with a target investment of $3.5 billion by 2028 which is anticipated to deliver annual EBITDA of $350 million; the expansion of the Company's development pipeline to 10 GW by 2028; the Company’s investment strategy to deliver long-term value to shareholders; the common share dividend level through 2024; the Company's projects under construction, including capital costs, the timing of commercial operations and expected annual EBITDA; the impact of new asset additions in 2024 of Garden Plain, Northern Goldfields solar, Kent Hills, Mount Keith transmission, White Rock and Horizon Hill; the development of the early-stage and advanced-stage projects; achieving the anticipated benefits of the transfer of PTCs (defined below) generated

from the White Rock and Horizon Hill wind projects; executing growth with Hancock under the Joint Development Agreement; the proportion of EBITDA to be generated from renewable sources to increase to 70 per cent by the end of 2028; the Company’s ability to achieve its long-term decarbonization goal to be net zero by 2045; the reduction of carbon emissions by 75 per cent from 2015 emissions levels by 2026; the expected impact and quantum of carbon compliance costs; regulatory developments and their expected impact on the Company; expectations regarding refinancing debt; and the Company continuing to maintain adequate liquidity.

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 long-term investment and credit markets; no significant changes to power price and hedging assumptions, including hedged volumes and prices; no significant changes to gas commodity prices and transport costs; no significant changes to decommissioning and restoration costs; no significant changes to interest rates; no significant changes to the demand and growth of renewables generation; no significant changes to the integrity and reliability of our assets; planned and unplanned outages and use of our assets; and no significant changes to the Company's debt and credit ratings.

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: fluctuations in power prices, including merchant pricing in Alberta, Ontario and Mid-Columbia; failure or delay in closing the Heartland acquisition; failure to realize the benefits of the Heartland acquisition, including the inability to advance the Battle River Carbon Hub Project to final investment decision or commercial operation, and any loss of value in the Heartland portfolio during the interim period prior to closing; reductions in production; restricted access to capital and increased borrowing costs, including any difficulty raising debt, equity or tax equity, as applicable, on reasonable terms or at all; labour relations matters, reduced labour availability and the ability to continue to staff our operations and facilities; reliance on key personnel; disruptions to our supply chains, including our ability to secure necessary equipment; force majeure claims; our ability to obtain regulatory and any other third-party approvals on the expected timelines or at all in respect of our growth projects; long-term commitments on

M2 TransAlta Corporation 2023 Integrated Report

gas transportation capacity that may not be fully utilized over time; adverse financial impacts arising from the Company's hedged position; risks associated with development and construction projects, including as it pertains to increased capital costs, permitting, labour and engineering risks, disputes with contractors and potential delays in the construction or commissioning of such projects; significant fluctuations in the Canadian dollar against the US dollar and Australian dollar; changes in short-term and long-term electricity supply and demand; counterparty credit risk and any higher rate of losses on our accounts receivables; inability to achieve our environmental, social and governance ("ESG") targets; the impact of the energy transition on our business; impairments and/or writedowns of assets; adverse impacts on our information technology systems and our internal control systems, including 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; our ability to contract our generation for prices that will provide expected returns and to 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, coal, 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; failure to meet financial expectations; general domestic and international economic and political developments, including armed hostilities, the threat of terrorism, adverse diplomatic developments or other similar events; industry risk and competition in the business in which we operate; structural subordination of securities; public health crisis risks; inadequacy or unavailability of insurance coverage; our provision for income taxes and any risk of reassessment; and legal, regulatory and contractual disputes and proceedings involving the Company. 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, 2023.

Readers are urged to consider these factors carefully when 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.

TransAlta Corporation 2023 Integrated Report M3

Description of the Business

TransAlta is a Canadian corporation and one of Canada's largest publicly traded power generators. Established in 1911, the Company now has over 112 years of operating experience in the development, production and sale of electricity. We own, operate and manage a geographically diversified portfolio of generation assets that include water, wind, solar, battery storage, natural gas and transition coal. We are one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta. We also have industry-leading energy marketing capabilities where we seek to maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions. Our mix of merchant and contracted assets along with our energy marketing business provides resilient and growing cash flows that support our ability to pay dividends to our shareholders and reinvest in growth.

The Company's goal is to be a leading clean electricity company that is committed to a sustainable future and a responsible energy transition. Our strategic priorities include accelerating growth into customer-centred renewables and storage, selectively expanding flexible generation and reliability assets to support the transition, defining the next generation of power solutions and maintaining financial strength and capital allocation discipline. We are primarily focused on opportunities within our core markets of Canada, the US and Western Australia.

Our sustainability goals and our Clean Electricity Growth Plan remain the focus of our strategy, which includes our commitment to retire our last remaining operational coal facility at the end of 2025. We remain on track to achieve our 2026 greenhouse gas ("GHG") emissions reduction target of 75 per cent scope 1 and 2 GHG emissions reductions since 2015 and our carbon net-zero goal by 2045. Since 2005, we have reduced our scope 1 and 2 GHG emissions by 31 million tonnes ("MT") of CO2e or a 74 per cent reduction, proudly representing approximately 10 per cent of Canada's Paris Agreement 2030 decarbonization target(1).

Portfolio of Assets

Our asset portfolio is geographically diversified with operations across Canada, the United States and Australia. The portfolio also generates power using a diverse set generation technologies and reliably supplies a broad cross section of counterparties.

Our Hydro, Wind and Solar, Gas and Energy Transition segments are responsible for operating and maintaining our electrical generation facilities. Our Energy Marketing segment is responsible for marketing and scheduling our merchant asset fleet in North America (excluding Alberta) along with the procurement of gas, transport and storage for our gas fleet, providing knowledge to support our growth team, and generating a stand-alone gross margin separate from our asset business through a leading North American energy marketing and trading platform.

Our highly diversified portfolio consists of both high-quality contracted assets and merchant assets. Approximately, 56 percent of our total installed capacity, including 81 per cent of our Wind and Solar fleet and 53 per cent of our Gas fleet, is contracted with investment-grade or creditworthy counterparties. The weighted-average contract life for these contracted facilities is 10 years.

Our merchant assets include our unique hydro merchant portfolio and our merchant legacy thermal portfolio and wind assets. Our merchant exposure is primarily in Alberta, where 53 per cent of our capacity is located and 75 per cent of our Alberta capacity is available to participate in the merchant market. The Alberta optimization team is responsible for marketing and scheduling our merchant asset fleet in Alberta.

A significant portion of the thermal generation capacity in the portfolio has been hedged to provide cash flow certainty. The Company's hedging strategy includes maintaining a significant base of commercial and industrial customers and is supplemented with financial hedges. In 2023, 78 per cent of our energy production in Alberta was sold under long term contracts or fixed price hedges. Refer to the 2024 Outlook section and the Optimization of the Alberta Portfolio of this MD&A for further details.

Our diversified fleet is a key success factor in our ability to deliver resilient cash flows while capturing higher risk-adjusted returns for our shareholders.

(1)In 2005, TransAlta's estimated scope 1 and 2 GHG emissions were 41.9 MT of CO2e, which did not receive independent limited assurance. Canada's Paris Agreement 2030 decarbonization target assumed 293 MT of CO2e or a 40 per cent reduction from a 2005 baseline of 732 MT of CO2e.

M4 TransAlta Corporation 2023 Integrated Report

The following table provides our consolidated ownership of our facilities across the regions in which we operate as of
Dec. 31, 2023:

	Hydro		Wind & Solar		Gas		Energy Transition		Total
Year ended Dec. 31, 2023	Gross Installed Capacity (MW)	Number of facilities	Gross Installed Capacity (MW)(1)	Number of facilities	Gross Installed Capacity (MW)(1)	Number of facilities	Gross Installed Capacity (MW)	Number of facilities	Gross Installed Capacity (MW)(1)	Number of facilities
Alberta	834	17	766	14	1,960	7	—	—	3,560	38
Canada, excluding Alberta	88	7	751	9	645	3	—	—	1,484	19
US	—	—	519	7	29	1	671	2	1,219	10
Australia	—	—	48	3	450	6	—	—	498	9
Total	922	24	2,084	33	3,084	17	671	2	6,761	76

(1)Gross installed capacity for consolidated reporting represents 100 per cent output of a facility. Capacity figures for the Wind and Solar segment includes 100 per cent of the Kent Hills wind facilities, and capacity figures for the Gas segment include 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.

Stable and Predictable Cash Flows

The following table provides our contracted capacity by MW and as a percentage of total gross installed capacity of our facilities across the regions in which we operate as of Dec. 31, 2023:

As at Dec. 31, 2023	Hydro		Wind & Solar		Gas		Energy Transition		Total
Alberta	—		374		511		—		885
Canada, excluding Alberta	88		751		645		—		1,484
US	—		519		29		381		929
Australia	—		48		450		—		498
Total contracted capacity (MW)	88		1,692		1,635		381		3,796
Contracted capacity as a % of total capacity (%)	10	%	81	%	53	%	57	%	56	%

The weighted average contract life (years) of our facilities across the regions in which we operate as of Dec. 31, 2023 is:

As at Dec. 31, 2023	Hydro	Wind & Solar	Gas	Energy Transition	Total
Alberta(1)(2)	—	16	7	—	11
Canada, excluding Alberta(2)	10	10	8	—	9
US(2)	—	10	2	2	7
Australia(2)	—	15	15	—	15
Total weighted contract life (years)(2)	10	12	10	2	10

(1)The weighted-average remaining contract life in the Wind and Solar segment is related to the contract period for Garden Plain (130 MW), McBride Lake (38 MW), and Windrise (206 MW). The weighted-average remaining contract life in the Gas segment is related to the contract period for Poplar Creek (230 MW), Fort Saskatchewan (71 MW) and a capacity-contract that is not directly contracted with any one facility (210 MW).

(2)For power generated under long-term power purchase agreements ("PPAs") and other long-term contracts, the weighted-average remaining contract life is based on long-term average gross installed capacity.

The majority of TransAlta's long-term power purchase agreements are with investment-grade rated or creditworthy counterparties.

TransAlta Corporation 2023 Integrated Report M5

Highlights

For the year ended Dec. 31, 2023, the Company demonstrated strong performance mainly due to the continued strong market conditions in Alberta in the first half of the year, higher production in the Gas and Energy Transition segments, and higher hedged volumes and

lower realized gas prices in the Gas segment, partially offset by lower wind and water resources. The Energy Marketing segment's performance was lower compared to 2022 due to the lower realized settled trades during the year on market positions compared to the prior year.

Year ended Dec. 31	2023	2022	2021
Operational information
Adjusted availability (%)	88.8	90.0	86.6
Production (GWh)	22,029	21,258	22,105
Select financial information
Revenues	3,355	2,976	2,721
Earnings (loss) before income taxes	880	353	(380)
Adjusted EBITDA(1)	1,632	1,634	1,286
Net earnings (loss) attributable to common shareholders	644	4	(576)
Cash flows
Cash flow from operating activities	1,464	877	1,001
Funds from operations(1)	1,351	1,346	994
Free cash flow(1)	890	961	585
Per share
Weighted average number of common shares outstanding	276	271	271
Net earnings (loss) per share attributable to common shareholders, basic and diluted	2.33	0.01	(2.13)
Dividends declared per common share	0.22	0.21	0.19
Funds from operations per share(1)(2)	4.89	4.97	3.67
Free cash flow per share(1)(2)	3.22	3.55	2.16
Liquidity and capital resources
Available liquidity	1,738	2,118	2,177
Adjusted net debt to adjusted EBITDA(1) (times)	2.5	2.2	2.6
Total consolidated net debt(1)(3)	3,453	2,854	2,636
As at Dec. 31	2023	2022	2021
Total assets	8,659	10,741	9,226
Total long-term liabilities	5,253	5,864	4,702
Total liabilities	6,995	8,752	6,633

(1)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. 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. Also, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(2)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. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for the purpose of these non-IFRS ratios.

(3)Refer to the table in the Financial Capital section of this MD&A for more details on the composition of total consolidated net debt.

M6 TransAlta Corporation 2023 Integrated Report

Operating Performance

Adjusted Availability

The following table provides adjusted availability (%) by segment:

Year ended Dec. 31	2023	2022	2021
Hydro	90.8	96.7	92.4
Wind and Solar	86.9	83.8	91.9
Gas	91.6	94.6	85.7
Energy Transition(1)	79.8	79.0	78.8
Adjusted availability (%)	88.8	90.0	86.6

(1)Availability, not adjusted for dispatch optimization, was 79.8 per cent for the year ended Dec. 31, 2023 (2022 - 77.2 per cent; 2021 - 75.3 per cent).

Availability is an important measure for the Company as it represents the percentage of time a facility is available to produce electricity and is therefore an important indicator of the overall performance of the fleet.

Availability is impacted by planned and unplanned outages, including the extended outage at the Kent Hills wind facility within the Wind and Solar fleet. Availability adjusted to exclude the Kent Hills extended outage for the years ended Dec. 31, 2022 and 2023, was 91.0 per cent and 92.8 per cent, respectively. The Company schedules dedicated time (planned outages) to maintain, repair or make improvements to the facilities at a time that will minimize the impact to the operations. In high price environments, actual outage schedules may change to accelerate the return to service of the unit.

Adjusted availability for the year ended Dec. 31, 2023, was 88.8 per cent, compared to 90.0 per cent in 2022, and was consistent with management's expectations. Lower adjusted availability was primarily due to:

•Planned outages in the Hydro segment, mainly at our Alberta Hydro Assets, to perform scheduled maintenance and

•Planned outages at Sundance Unit 6, Sheerness Unit 1, Keephills Units 2 and 3 and Sarnia for scheduled maintenance in the Gas segment, partially offset by

•Lower planned outages at Centralia Unit 2 in the Energy Transition segment and

•The partial return to service of the Kent Hills wind facilities.

Production and Long-Term Average Generation

	2023				2022				2021
Year ended Dec. 31	Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA		Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA		Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA
Hydro	1,769	2,015	88	%	1,988	2,015	99	%	1,936	2,030	95	%
Wind and Solar	4,243	5,387	79	%	4,248	4,950	86	%	3,898	4,345	90	%
Gas	11,873				11,448				10,565
Energy Transition	4,144				3,574				5,706
Total	22,029				21,258				22,105

In addition to adjusted availability, the Company utilizes long-term average production ("LTA generation") as another indicator of performance for the renewable assets whereby actual production levels are compared against the expected long-term average. In the short term, for each of the Hydro and Wind and Solar segments, the conditions will vary from one period to the next. Over longer durations, facilities are expected to produce in line with their long-term averages, which is considered a reliable indicator of performance.

LTA generation is calculated 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 greater than 25 years.

LTA generation for Energy Transition is not considered as we are currently transitioning these units with the expectation that they will retire by the end of 2025 and the LTA generation for Gas is not applicable as these units are dispatchable and their production is largely dependent on market conditions and merchant demand.

TransAlta Corporation 2023 Integrated Report M7

Total production for 2023, increased by 771 GWh or 4 per cent compared to 2022.

Production from the Centralia facility within the Energy Transition segment benefited from fewer planned and unplanned outage hours compared to the prior year and was able to be dispatched during periods of higher merchant pricing for the region.

The Company's Gas segment had a strong performance, resulting in production that was both higher than the prior year as well as higher than expectations for the year. The Gas segment was available during periods of supply tightness, allowing for the Company to operate during periods of peak pricing. The Gas segment was unfavourably impacted by relatively mild weather in the fourth quarter of 2023, as the Company did not experience

the same weather conditions compared to the same period in 2022, which had tighter supply due to the extreme cold weather in Alberta.

Production for our renewables assets for the year ended Dec. 31, 2023, was lower by 224 GWh, or 4 per cent, compared to 2022 and was 81 per cent of LTA generation.

Lower than average renewable resources in the year impacted production in both the Hydro and the Wind and Solar segments. Hydro production was further impacted by lower availability due to increased planned maintenance outages compared to 2022, while the Wind and Solar segment production was positively impacted by the addition of the Garden Plain wind facility, the partial return to service of the Kent Hills wind facility and the addition of the Northern Goldfields solar facilities during the year.

Market Pricing

Year ended Dec. 31, 2023	2023	2022	2021
Alberta spot power price ($/MWh)	134	162	102
Mid-Columbia spot power price (US$/MWh)	76	82	49
Ontario spot power price ($/MWh)	28	47	30
Natural gas price (AECO) per GJ ($)	2.54	5.08	3.39

For the year ended Dec. 31, 2023, spot electricity prices in Alberta and the Pacific Northwest were lower compared to 2022. Lower prices in both regions resulted from lower natural gas prices and overall weaker weather-driven demand in the second half of 2023, with notably lower prices due to above normal weather patterns in the fourth quarter of 2023. For Alberta specifically, warm weather in

the fourth quarter resulted in a strong wind resource pattern which, combined with new installed capacity, added supply in the market compared to the prior year.

AECO natural gas prices for the year ended Dec. 31, 2023, were lower compared to 2022 mainly due to improved production and storage levels in Alberta and North America.

Financial Performance review on Consolidated Information

Year ended Dec. 31	2023	2022	2021
Revenues	3,355	2,976	2,721
Fuel and purchased power	1,060	1,263	1,054
Carbon compliance	112	78	178
Operations, maintenance and administration	539	521	511
Depreciation and amortization	621	599	529
Asset impairment charges (reversals)	(48)	9	648
Interest income	59	24	11
Earnings (loss) before income taxes	880	353	(380)
Income tax expense	84	192	45
Net earnings (loss) attributable to common shareholders	644	4	(576)
Net earnings attributable to non-controlling interests	101	111	112

M8 TransAlta Corporation 2023 Integrated Report

Current Year Variance Analysis (2023 versus 2022)

Revenuestotalling $3,355 million, increased by $379 million, or 13 per cent, compared to 2022, primarily due to:

•Higher realized and unrealized gains from hedging and derivative positions across the segments, partially offset by

•Lower revenue from merchant sales due to lower spot power prices and production in Alberta.

Fuel and purchased power costs totalling $1,060 million, decreased by $203 million, or 16 per cent, compared to 2022, primarily due to:

•Lower natural gas commodity pricing, partially offset by

•Higher fuel usage in both the Gas and Energy Transition segments.

Carbon compliance costs totalling $112 million, increased by $34 million, or 44 per cent, compared to 2022, primarily due to:

•An increase in the carbon price per tonne from $50 per tonne in 2022 to $65 per tonne in 2023,

•Higher production in the Gas segment and

•No utilization of emission credits to settle GHG obligations as was done in the prior year.

Operations, maintenance and administration ("OM&A") expenses totalling $539 million, increased by $18 million, or 3 per cent, compared to 2022, primarily due to:

•Higher spending on strategic and growth initiatives,

•Higher costs associated with the relocation of the Company's head office and

•Increased costs due to inflationary pressures.

Depreciation and amortization totalling $621 million, increased by $22 million, or 4 per cent, compared to 2022, primarily due to:

•Revisions to useful lives on certain facilities and

•Commercial operation of new facilities.

Asset impairment reversals totalling $48 million, increased by $57 million, or 633 per cent, compared to an asset impairment charge in 2022, primarily due to:

•Decommissioning and restoration provisions for retired assets being favourably impacted by a change in timing of expected cash outflows, partially offset by lower discount rates, resulting in a net impairment reversal of $34 million and

•A Hydro segment impairment reversal of $10 million due to a contract extension and favourable changes in power price assumptions.

Interest income totalling $59 million increased by $35 million, or 146 per cent, compared to 2022,primarily due to higher cash balances and favourable interest rates.

Earnings before income taxes totalling $880 million, increased by $527 million, or 149 per cent, compared to 2022, due to the above noted items.

Income tax expense totalling $84 million, decreased by $108 million, or 56 per cent, compared to 2022, due to a recovery relating to the reversal of previously derecognized Canadian deferred tax assets and lower US non-deductible expenses relating to the US operations, partially offset by higher earnings from Canadian operations.

Net earnings attributable to non-controlling intereststotalling $101 million, decreased by $10 million, or 9 per cent, compared to 2022, primarily due to lower net earnings for TA Cogen.

TransAlta Corporation 2023 Integrated Report M9

Adjusted EBITDA

For the year ended Dec. 31, 2023, the Company's adjusted EBITDA was $1,632 million as compared to $1,634 million in 2022, a decrease of $2 million. The major factors impacting adjusted EBITDA are summarized in the following table:

	Year ended Dec. 31
Adjusted EBITDA for the year ended Dec. 31, 2022	1,634
Hydro: lower primarily due to lower ancillary services volumes, lower spot power and ancillary services prices and lower than average water resources, partially offset by realized gains from hedging and sales of environmental attributes.	(68)
Wind and Solar: lower primarily due to lower environmental attribute revenues, lower spot power pricing in Alberta, lower wind resource across the operating fleets, lower liquidated damages recognized at the Windrise wind facility and higher OM&A, partially offset by the commercial operation of the Garden Plain wind facility, the Northern Goldfields solar facilities and the partial return of service of the Kent Hills wind facilities.	(54)
Gas: higher primarily due to higher power price hedges partially offsetting the impacts of lower Alberta spot prices, lower natural gas commodity costs and higher production, partially offset by lower thermal revenues, higher carbon prices and higher carbon costs and fuel usage related to production. The Gas fleet significantly exceeded management's expectations.	172
Energy Transition: higher primarily due to higher production from higher availability and higher merchant sales volumes, partially offset by lower market prices compared to the prior year.	36
Energy Marketing: lower primarily due to lower realized settled trades during the year on market positions in comparison to prior year and higher OM&A. Energy Marketing results were in line with management's expectations and performance was consistent with our revised full year financial guidance provided in the second quarter of 2023.	(74)
Corporate: lower primarily due to increased spending to support strategic and growth initiatives and higher costs associated with the relocation of the Company's head office.	(14)
Adjusted EBITDA(1) for the year ended Dec. 31, 2023	1,632

(1)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.

M10 TransAlta Corporation 2023 Integrated Report

Free Cash Flow

During the second quarter of 2023, the Company revised and increased our 2023 guidance for FCF based on the strong financial performance attained in the first half of the year and our expectations for the balance of the year. For

the year ended Dec. 31, 2023, the Company's FCF decreased by $71 million, or 7 per cent, compared to 2022, and was in line with our revised expected full year financial guidance. The major factors impacting FCF are summarized in the following table:

	Year ended Dec. 31
FCF for the year ended Dec. 31, 2022	961
Lower adjusted EBITDA: lower FCF due to the items noted in Adjusted EBITDA above.	(2)
Higher interest income: Higher cash balances and favourable interest rates positively impacting FCF.	35
Lower current income tax expense: Previously restricted non-capital loss carryforwards were utilized to offset taxable income resulting in higher FCF.	15
Higher sustaining capital expenditures: Higher planned major maintenance costs for the Hydro and Gas segments, partially offset by lower planned major maintenance in Wind and Solar and Energy Transition segments, resulting in lower FCF.	(31)
Higher distributions paid to subsidiaries' non-controlling interests: Related to timing of distributions paid to TA Cogen, partially offset by lower distributions paid to TransAlta Renewables resulting in lower FCF.	(36)
Lower provisions: Lower provisions being accrued compared to the prior year, with no notable settlements being recorded in either year resulting in lower FCF due to the timing of provisions accrued.	(26)
Other non-cash items(1)	(12)
Other(2)	(14)
FCF(3) for the year ended Dec. 31, 2023	890

(1)Other non-cash items consists of Alberta market pool incentives, carbon obligation, contract liabilities, and the SunHills royalty onerous contract. Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF section tables in this MD&A for more details.

(2)Other consists of higher realized foreign exchange loss, higher decommissioning and restoration costs settled, higher dividends paid on preferred shares and higher principal payments on lease liabilities. Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF section tables in this MD&A for more details.

(3)FCF 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.

Capital Expenditures

We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake sustaining capital expenditures that ensure our facilities operate reliably and safely.

Year ended Dec. 31	2023	2022	2021
Hydro	41	35	26
Wind and Solar	15	18	13
Gas	76	41	128
Energy Transition	15	19	19
Corporate	27	29	13
Total sustaining capital expenditures	174	142	199

Total sustaining capital expenditures in 2023 were $32 million higher compared to 2022, primarily due to:

•Higher planned major maintenance at our Alberta Hydro Assets,

•Higher planned major maintenance at our Sarnia, Sundance Unit 6 and Keephills Units 2 and 3 facilities in the Gas segments, partially offset by

•Lower planned major maintenance in the Wind and Solar segment primarily due to a reduction in major component replacements and

•Lower planned outage work performed in the Energy Transition segment.

TransAlta Corporation 2023 Integrated Report M11

Total sustaining capital expenditures in 2022 were $57 million lower compared to 2021, primarily due to:

•Coal-to-gas conversions being completed in 2021, partially offset by

•Higher planned major maintenance in 2022 in the Hydro segment and a higher level of major component replacements in 2022 in the Wind and Solar segment and

•Higher spend on leasehold improvements associated with the planned relocation of the Company's head office.

Year ended Dec. 31	2023	2022	2021
Hydro	6	2	3
Wind and Solar	659	759	124
Gas	13	3	38
Energy Transition	—	—	70
Corporate(1)	61	10	47
Total growth and development expenditures	739	774	282

(1)Expenditures related to projects in the development phase are included in the Corporate segment.

In 2023 and 2022, the growth and development expenditures incurred primarily related to:

•The Garden Plain wind facility, which achieved commercial operation in August 2023;

•The Northern Goldfields solar facilities, which achieved commercial operation in November 2023;

•The White Rock wind projects, which are expected to reach commercial operation in the first quarter of 2024;

•The Horizon Hill wind project, which is expected to reach commercial operation in the first quarter of 2024; and

•The Mount Keith 132kV expansion, which is on track to be completed in the first quarter of 2024.

Refer to the Strategic Priorities and Clean Electricity Growth Plan to 2028 section of this MD&A for more details.

Significant and Subsequent Events

Change to Board of Directors

The Honourable Rona Ambrose has decided that she will not stand for re-election and will retire from the Board of Directors ("the Board") following the annual shareholder meeting on April 25, 2024. The Board extends its gratitude for her service to the Company. She has been a valuable contributor to the Board since 2017 and we thank her for her leadership and insights during her tenure, especially as Chair of the Governance, Safety and Sustainability Committee of the Board.

Production Tax Credit ("PTC") Sale Agreements

On Feb. 22, 2024, the Company entered into 10-year transfer agreements with an AA- rated customer for the sale of approximately 80 per cent of the expected PTCs to be generated from the White Rock wind projects and the Horizon Hill wind project. The expected annual average EBITDA from these contracts is approximately $57 million (US$43 million).

Normal Course Issuer Bid ("NCIB") and Automatic Share Purchase Plan ("ASPP")

On May 26, 2023, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement an 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 7.29 per cent of its public float of common shares as at May 17, 2023. 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, 2023, and ends on May 30, 2024, 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.

M12 TransAlta Corporation 2023 Integrated Report

On Dec. 19, 2023, the Company entered into an ASPP to facilitate repurchases of TransAlta’s common shares under its NCIB.

Under the ASPP, the Company’s broker may purchase common shares from the effective date of the ASPP until the end of the ASPP. All purchases of common shares made under the ASPP will be included in determining the number of common shares purchased under the NCIB. The ASPP will terminate on the earliest of the date on which: (a) the maximum purchase limits under the ASPP are reached; (b) Feb. 24, 2024; or (c) the Company terminates the ASPP in accordance with its terms.

During the year ended Dec. 31, 2023, the Company purchased and cancelled a total of 7,537,500 common shares, at an average price of $11.49 per common share, for a total cost of $87 million.

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 might not be reflective of the underlying value and purchases of common shares for cancellation under the NCIB may provide an opportunity to enhance shareholder value.

Northern Goldfields Solar Achieves Commercial Operation

On Nov. 22, 2023, the Company announced that the 48 MW Northern Goldfields solar and battery storage facilities achieved commercial operation. The facilities consist of the 27 MW Mount Keith solar facility, the 11 MW Leinster solar facility, the 10 MW Leinster battery energy storage system and interconnecting transmission infrastructure, all of which are now integrated into TransAlta’s existing 169 MW Southern Cross Energy North remote network in Western Australia. The facilities are fully contracted to BHP Nickel West for a term of 15 years and are expected to reduce BHP's scope 2 emissions at Mount Keith and Leinster by 12 per cent annually.

TransAlta Announces Growth Targets to 2028 and Declares 9% Dividend Increase

On Nov. 21, 2023, the Company held its 2023 Investor Day event and announced it had updated its strategic growth targets to 2028, which strengthens the Company’s commitment to being a leader in clean electricity by delivering customer-centred power solutions. The growth targets include:

•Adding up to 1.75 GW of new capacity to the Company's fleet by investing approximately $3.5 billion to develop, construct or acquire new assets through to the end of 2028,

•A focus on customer-centred renewables and storage through the development of its 4.8 GW development pipeline and

•Expanding the Company’s development pipeline to 10 GW by 2028.

The Board approved an annualized $0.02 per share increase, or 9 per cent increase to our common share dividend and declared a dividend of $0.06 per common share to be paid on April 1, 2024. The quarterly dividend of $0.06 per common share represents an annualized dividend of $0.24 per common share.

TransAlta Enters Joint Development Agreement with Hancock

On Nov. 21, 2023, the Company entered into a joint development agreement with Hancock Prospecting Pty Ltd. (“Hancock”), Australia’s fourth largest iron ore producer. This arrangement will build on TransAlta’s expertise in supplying power to remote mining operations in Western Australia. TransAlta will work collaboratively with Hancock to define and supply behind-the-fence generation solutions for Hancock in the Port Hedland area.

TransAlta to Acquire Heartland Generation from Energy Capital Partners

On Nov. 2, 2023, the Company announced that it had entered into a definitive share purchase agreement with an affiliate of Energy Capital Partners, the parent of Heartland Generation Ltd. and Alberta Power (2000) Ltd. (collectively, "Heartland"), pursuant to which TransAlta will acquire Heartland and its entire business operations in Alberta and British Columbia. The acquisition will add 10 facilities to TransAlta’s fleet, totalling 1,844 MW of new capacity. The transaction is expected to close in the first half of 2024, subject to customary closing conditions, including receipt of regulatory approvals.

The purchase price for the acquisition is $390 million, subject to working capital and other adjustments, as well as the assumption of $268 million of low-cost debt. The Company will finance the transaction using cash on hand and drawing on its credit facilities.

The assets are expected to add approximately $115 million of average annual EBITDA including synergies. Approximately 55 per cent of revenues are under contract with highly creditworthy counterparties, with a weighted-average remaining contract life of 16 years. Corporate pre-tax synergies are expected to exceed $20 million annually.

The acquisition will competitively position the Company to respond to the highly dynamic and shifting electricity landscape in Alberta given the expected significant increase in renewables and other large baseload generation coming online in the next several years in the

TransAlta Corporation 2023 Integrated Report M13

province. The Clean Electricity Growth Plan continues to be at the heart of our strategy and is primarily focused on meeting the future needs of our customers with clean electricity solutions.

TransAlta Corporation Completes Acquisition of TransAlta Renewables Inc.

On Oct. 5, 2023, the Company completed the acquisition of TransAlta Renewables pursuant to the terms of the previously announced arrangement agreement between the parties (the "Arrangement"). TransAlta acquired all of the outstanding common shares of TransAlta Renewables ("RNW Shares") not already owned, directly or indirectly, by TransAlta and certain of its affiliates, resulting in TransAlta Renewables becoming a wholly owned subsidiary of the Company. Prior to the Arrangement, TransAlta and its affiliates collectively held 160,398,217 RNW Shares, representing 60.1 per cent of the issued and outstanding RNW Shares, with the remaining 106,510,884 RNW Shares held by TransAlta Renewables shareholders ("RNW Shareholders") other than TransAlta and its affiliates.

The Arrangement was approved by RNW Shareholders at a special meeting of shareholders held on Sept. 26, 2023, and by the Court of King’s Bench of Alberta on Oct. 4, 2023. The consideration paid totalled $1.3 billion which consisted of $800 million of cash and approximately 46 million common shares of the Company.

The closing of the acquisition of TransAlta Renewables represents a key milestone for the Company and the simplified and unified corporate structure positions it well for future success.

TransAlta Tops Newsweek's Inaugural List of World's Most Trustworthy Companies

On Sept. 14, 2023, the Company announced that it ranked first on Newsweek's inaugural “World's Most Trustworthy Companies 2023” list for the Energy and Utilities category. The list identifies the top 1,000 companies in 21 countries and across 23 industries. Newsweek’s 2023 World’s Most Trustworthy Companies were chosen based on a holistic approach to evaluating three pillars of public trust – customers, investors and employees. The list was compiled based on an extensive survey of over 70,000 participants, gathering 269,000 evaluations of companies that people trust as a customer, as an investor or as an employee.

Garden Plain Wind Facility Achieved Commercial Operation

In August 2023, the Garden Plain wind facility was commissioned adding 130 MW to our gross installed capacity. The facility is fully contracted with Pembina

Pipeline Corporation and PepsiCo Canada, with a weighted average contract life of approximately 17 years.

Tent Mountain Pumped Hydro Development Project

On April 24, 2023, the Company acquired a 50 per cent interest in the Tent Mountain Renewable Energy Complex (“Tent Mountain”), an early-stage 320 MW pumped storage hydro development project located in southwest Alberta, from Evolve Power Ltd. ("Evolve"), formerly known as Montem Resources Limited. The acquisition includes land rights, fixed assets and intellectual property associated with Tent Mountain.

The Company and Evolve own the Tent Mountain project within a special purpose partnership that is jointly managed, with the Company acting as project developer. The partnership is actively seeking an offtake agreement for the energy and environmental attributes that will be generated by the facility.

Annual Shareholder Meeting

On April 28, 2023, the Company held its annual meeting of shareholders. All director nominees were elected to the Board, including Candace MacGibbon, a new member to the Board.

The Company also received strong support on all other items of business, including say-on-pay and an amendment to the Company's Share Unit Plan.

M14 TransAlta Corporation 2023 Integrated Report

Segmented Financial Performance and Operating Results

Segmented information is prepared on the same basis that the Company manages its business, evaluates financial results and makes key operating decisions. The following table reflects the summary financial information on a consolidated basis for the year ended Dec. 31:

	Adjusted EBITDA(1)
Year ended Dec. 31	2023	2022	2021
Hydro	459	527	322
Wind and Solar	257	311	262
Gas	801	629	488
Energy Transition	122	86	133
Energy Marketing	109	183	166
Corporate	(116)	(102)	(85)
Total adjusted EBITDA(1)	1,632	1,634	1,286
Earnings (loss) before income taxes	880	353	(380)

(1)This item 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.

TransAlta Corporation 2023 Integrated Report M15

Hydro

Year ended Dec. 31	2023	2022	Change			2021	Change
Gross installed capacity (MW)(1)	922	922	—	—	%	925	(3)	—	%
LTA generation (GWh)(2)	2,015	2,015	—	—	%	2,030	(15)	(1)	%
Availability (%)	90.8	96.7	(5.9)	(6)	%	92.4	4.3	5	%
Production
Contract production (GWh)	277	323	(46)	(14)	%	434	(111)	(26)	%
Merchant production (GWh)	1,492	1,665	(173)	(10)	%	1,502	163	11	%
Total energy production (GWh)	1,769	1,988	(219)	(11)	%	1,936	52	3	%
Ancillary service volumes (GWh)(3)	2,582	3,124	(542)	(17)	%	2,897	227	8	%
Alberta Hydro Assets revenues(4)(5)	291	328	(37)	(11)	%	185	143	77	%
Other Hydro Assets and other revenues(4)(6)	51	42	9	21	%	41	1	2	%
Alberta Hydro ancillary services revenues(3)	173	236	(63)	(27)	%	160	76	48	%
Environmental attribute revenues	14	1	13	1300	%	1	—	—	%
Total gross revenues	529	607	(78)	(13)	%	387	220	57	%
Net payment relating to Alberta Hydro PPA	—	—	—	—	%	(4)	4	(100)	%
Revenues(7)	529	607	(78)	(13)	%	383	224	58	%
Fuel and purchased power	19	22	(3)	(14)	%	16	6	38	%
Gross margin(8)	510	585	(75)	(13)	%	367	218	59	%
OM&A	48	55	(7)	(13)	%	42	13	31	%
Taxes, other than income taxes	3	3	—	—	%	3	—	—	%
Adjusted EBITDA(8)	459	527	(68)	(13)	%	322	205	64	%
Supplemental Information:
Gross revenues per MWh
Alberta Hydro Assets energy ($/MWh)(4)(5)	175	197	(22)	(11)	%	123	74	60	%
Alberta Hydro Assets ancillary ($/MWh)(3)	67	76	(9)	(12)	%	55	21	38	%

(1)In the fourth quarter of 2022, the Company closed the sale of two Hydro assets resulting in a reduction in capacity of 3 MW.

(2)2022 and 2021 LTA generation revised for consistency with calculation methodology used in 2023.

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

(4)Alberta Hydro Assets include 13 hydro facilities on the Bow and North Saskatchewan river systems. Other Hydro assets includes our hydro facilities in BC and Ontario, hydro facilities in Alberta (other than the Alberta Hydro Assets) and transmission revenues.

(5)The Company entered into forward hedges for the first and third quarter of 2023 that are included in the Alberta Hydro Asset revenues.

(6)Other revenue includes revenues from our transmission business and other contractual arrangements, including the flood mitigation agreement with the Government of Alberta and Black Start services.

(7)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.

(8)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.

M16 TransAlta Corporation 2023 Integrated Report

2023

Revenues for the year ended Dec. 31, 2023, decreased compared to 2022, primarily due to:

•Lower ancillary services volumes due to the AESO procuring lower volumes given its decision to reduce the cumulative volume of imports into Alberta,

•Lower spot power prices and ancillary services prices in the Alberta market and

•Lower production due to lower availability from planned outages at our Alberta Hydro Assets and lower than average water resources, partially offset by

•Realized gains from our hedging strategy for the Alberta Hydro Assets and

•Sales of environmental attributes driven by an increase in emission credit sales.

Adjusted EBITDA for the year ended Dec. 31, 2023, decreased compared to 2022, primarily due to:

•Lower revenues as explained by the factors above.

For further discussion on the Alberta market conditions and pricing, refer to the Alberta Electricity Portfolio section of this MD&A.

2022

Revenues for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:

•Higher merchant and ancillary service prices and volumes in the Alberta market,

•Higher production and higher availability due to lower planned and unplanned outages at our Alberta Hydro Assets and

•Higher ancillary service volumes due to higher availability and demand.

Adjusted EBITDA for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:

•Higher revenues as explained by the factors above, partially offset by

•Higher OM&A costs for the year related to increased insurance premiums for updated replacement value coverage and the Company's performance-related incentive accruals.

TransAlta Corporation 2023 Integrated Report M17

Wind and Solar

Year ended Dec. 31	2023	2022	Change			2021	Change
Gross installed capacity (MW)(1)	2,084	1,906	178	9	%	1,906	—	—	%
LTA generation (GWh)	5,387	4,950	437	9	%	4,345	605	14	%
Availability (%)	86.9	83.8	3.1	4	%	91.9	(8.1)	(9)	%
Production
Contract production (GWh)	3,095	3,182	(87)	(3)	%	2,850	332	12	%
Merchant production (GWh)	1,148	1,066	82	8	%	1,048	18	2	%
Total production (GWh)	4,243	4,248	(5)	—	%	3,898	350	9	%
Wind and Solar revenues	347	357	(10)	(3)	%	320	37	12	%
Environmental attribute revenues	26	50	(24)	(48)	%	28	22	79	%
Revenues(2)	373	407	(34)	(8)	%	348	59	17	%
Fuel and purchased power	30	31	(1)	(3)	%	17	14	82	%
Carbon compliance	—	1	(1)	(100)	%	—	1	100	%
Gross margin(3)	343	375	(32)	(9)	%	331	44	13	%
OM&A	80	68	12	18	%	59	9	15	%
Taxes, other than income taxes	12	12	—	—	%	10	2	20	%
Net other operating income(2)	(6)	(16)	10	(63)	%	—	(16)	(100)	%
Adjusted EBITDA(3)	257	311	(54)	(17)	%	262	49	19	%
Supplemental information:
Kent Hills wind rehabilitation expenditures(4)	87	77	10	13	%	—	77	100	%
Insurance proceeds - Kent Hills	(1)	(7)	6	(86)	%	—	(7)	(100)	%

(1)Gross installed capacity and availability for 2023 includes the 130 MW Garden Plain wind facility that achieved commercial operation in August 2023 and the 48 MW Northern Goldfields solar facilities that achieved commercial operation in November 2023.

(2)For details of the adjustments to revenues and net other operating income included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(3)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.

(4)The Kent Hills wind facilities rehabilitation capital expenditures are segregated from the sustaining capital expenditures due to the extraordinary nature of the expenditures.

M18 TransAlta Corporation 2023 Integrated Report

2023

Revenues for the year ended Dec. 31, 2023, decreased compared to 2022 primarily due to:

•Lower environmental attribute revenues driven by a reduction of offsets and emission credit sales,

•Lower spot power pricing in Alberta and

•Weaker than long-term average wind resource across the operating fleets, partially offset by

•Commercial operation of the Garden Plain wind facility and the Northern Goldfield Solar facilities in the third and fourth quarter, respectively and

•The partial return to service of the Kent Hills wind facilities.

Adjusted EBITDA for the year ended Dec. 31, 2023, decreased compared to the same period in 2022, primarily due to:

•Lower revenues as explained by the factors above,

•Higher OM&A related to salary escalations, higher insurance costs and long-term service agreement escalations and

•Lower liquidated damages recognized at the Windrise wind facility.

2022

Revenues for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:

•Higher production from the addition of the Windrise wind facility and the acquisition of the North Carolina Solar facilities in the fourth quarter of 2021 and higher wind resources in Eastern Canada,

•Higher realized merchant and spot power pricing in Alberta and

•Higher environmental attribute revenue, partially offset by

•Lower availability as a result of the extended outage at the Kent Hills 1 and 2 wind facilities.

Adjusted EBITDA for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:

•Higher revenue as explained by the factors above and

•The recognition of liquidated damages recoverable from turbine availability being below the contractual target at the Windrise wind facility, partially offset by

•Higher fuel and purchased power from increases in transmission rates,

•Higher OM&A related to the addition of the Windrise wind and North Carolina Solar facilities during the year and

•A one-time favourable adjustment as a result of the AESO transmission line loss ruling that was included in 2021.

TransAlta Corporation 2023 Integrated Report M19

Gas

Year ended Dec. 31	2023	2022	Change			2021	Change
Gross installed capacity (MW)	3,084	3,084	—	—	%	3,084	—	—	%
Availability (%)	91.6	94.6	(3.0)	(3)	%	85.7	8.9	10	%
Production
Contract sales volume (GWh)	4,172	3,609	563	16	%	3,622	(13)	—	%
Merchant sales volume (GWh)	7,889	7,927	(38)	—	%	7,084	843	12	%
Purchased power (GWh)(1)	(188)	(88)	(100)	114	%	(141)	53	(38)	%
Total production (GWh)	11,873	11,448	425	4	%	10,565	883	8	%
Revenues(2)	1,525	1,521	4	—	%	1,126	395	35	%
Fuel and purchased power(2)	449	637	(188)	(30)	%	374	263	70	%
Carbon compliance	112	83	29	35	%	118	(35)	(30)	%
Gross margin(3)	964	801	163	20	%	634	167	26	%
OM&A	192	195	(3)	(2)	%	173	22	13	%
Taxes, other than income taxes	11	15	(4)	(27)	%	13	2	15	%
Net other operating income	(40)	(38)	(2)	5	%	(40)	2	(5)	%
Adjusted EBITDA(3)	801	629	172	27	%	488	141	29	%

(1)Power required to fulfill contractual obligations during planned and unplanned outages is included in purchased power.

(2)For details of the adjustments to revenues and fuel and purchased power included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(3)Adjusted EBITDA and gross margin 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.

2023

Revenues for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:

•Higher production due to the fleet being available during periods of supply tightness and peak pricing and

•Higher power price hedges, partially offsetting the impact of lower Alberta spot prices, partially offset by

•Lower thermal revenues due to lower steam revenue pricing at the Sarnia facility compared to 2022.

Adjusted EBITDA for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:

•Lower natural gas commodity costs for the Alberta gas assets and

•Higher revenues explained above, partially offset by

•Higher carbon costs and fuel usage related to production with the utilization of emission credits to settle a portion of the GHG obligation in 2022 and

•Carbon price increases from $50 per tonne to $65 per tonne, impacting our Canadian gas assets.

The Gas fleet significantly exceeded management's expectations for the segment.

2022

Revenues for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:

•Higher production due to higher availability and dispatch optimization of the Alberta assets,

•Higher realized energy prices through dispatch optimization of our Alberta assets, net of hedging and

•Higher Ontario merchant pricing and steam generation.

Adjusted EBITDA for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:

•Higher revenues explained above and

•Lower carbon compliance costs due to reductions in GHG emissions as a result of operating exclusively on natural gas in Alberta rather than coal, and the utilization of compliance credits to settle a portion of the GHG obligation, partially offset by

•Increased natural gas consumption on recently converted units and higher natural gas prices,

•Carbon price increases from $35 per tonne to $50 per tonne and

•Higher OM&A due to the Company's performance-related incentive accruals and increased general operating expenses.

M20 TransAlta Corporation 2023 Integrated Report

Energy Transition

Year ended Dec. 31	2023	2022	Change			2021	Change
Gross installed capacity (MW)(1)	671	671	—	—	%	1,472	(801)	(54)	%
Availability (%)	79.8	77.2	2.6	3	%	75.3	1.9	3	%
Adjusted availability (%)(2)	79.8	79.0	0.8	1	%	78.8	0.2	—	%
Production
Contract sales volume (GWh)	3,329	3,329	—	—	%	3,329	—	—	%
Merchant sales volume (GWh)	4,417	3,951	466	12	%	6,052	(2,101)	(35)	%
Purchased power (GWh)(3)	(3,602)	(3,706)	104	(3)	%	(3,675)	(31)	1	%
Total production (GWh)	4,144	3,574	570	16	%	5,706	(2,132)	(37)	%
Revenues(4)	746	724	22	3	%	728	(4)	(1)	%
Fuel and purchased power	557	566	(9)	(2)	%	432	134	31	%
Carbon compliance	—	(1)	1	(100)	%	60	(61)	(102)	%
Gross margin(5)	189	159	30	19	%	236	(77)	(33)	%
OM&A	64	69	(5)	(7)	%	97	(28)	(29)	%
Taxes, other than income taxes	3	4	(1)	(25)	%	6	(2)	(33)	%
Adjusted EBITDA(5)	122	86	36	42	%	133	(47)	(35)	%
Supplemental information:
Highvale mine reclamation spend	15	12	3	25	%	6	6	100	%
Centralia mine reclamation spend	13	16	(3)	(19)	%	9	7	78	%

(1)The gross installed capacity for 2023 and 2022, excludes Keephills Unit 1 (395 MW retired on Dec. 31, 2021) and Sundance Unit 4 (406 MW retired on March 31, 2022).

(2)Adjusted for dispatch optimization.

(3)All of the power produced by Centralia is sold by the Energy Marketing segment for physical market delivery, which is shown as merchant sales volumes. Power required to fulfil contractual obligations is included in purchased power. Total production from the facility includes the net result of merchant sales volumes and purchased power.

(4)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.

(5)Adjusted EBITDA and gross margin 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.

2023

Revenues for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:

•Higher production from higher availability due to lower planned and unplanned outages at Centralia Unit 2 and

•Less economic dispatch leading to higher merchant sales volumes, partially offset by

•Lower market prices.

Adjusted EBITDA for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:

•Higher revenues as explained by the factors above,

•Lower purchased power costs due to lower pricing and increased volumes of production and

•Lower OM&A expenses due to the retirement of Sundance Unit 4 in the first quarter of 2022.

Mine reclamation spend for the year ended Dec. 31, 2023, was consistent compared to 2022.

2022

Revenues for the year ended Dec. 31, 2022, decreased compared to 2021, primarily due to:

•Lower production due to the retirements of the Keephills Unit 1 and Sundance Unit 4, partially offset by

•Increased production from higher availability at Centralia Unit 2 from lower planned and unplanned outages and

•Higher merchant and contract prices at Centralia.

Adjusted EBITDA for the year ended Dec. 31, 2022, decreased compared to 2021 primarily due to:

•Lower revenues as explained by the factors above and

•Higher purchased power costs during outages at Centralia, partially offset by

TransAlta Corporation 2023 Integrated Report M21

•Lower OM&A as a result of lower operating costs relating to retirements on the coal fleet in 2021 and

•Lower carbon costs in Alberta related to the retirements on the coal fleet, thereby reducing emissions generated.

Mine reclamation spend for the Highvale and Centralia mines increased compared to 2021, primarily due to the advancement of reclamation activities.

Energy Marketing

Year ended Dec. 31	2023	2022	Change			2021	Change
Revenues(1)	152	218	(66)	(30)	%	202	16	8	%
OM&A	43	35	8	23	%	36	(1)	(3)	%
Adjusted EBITDA(2)	109	183	(74)	(40)	%	166	17	10	%

(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 is not defined and has no standardized meaning under IFRS.

(2)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.

2023

Adjusted EBITDA for the year ended Dec. 31, 2023, decreased compared to 2022. This was in line with management's expectations, but lower year over year, primarily due to:

•Lower realized settled trades during the year on market positions in comparison to the prior year and

•OM&A increased mainly due to higher incentives related to revenues before adjustments.

The Company was able to capitalize on volatility in the trading of both physical and financial power and gas products across North American deregulated markets while maintaining the overall risk profile of the business unit.

2022

Adjusted EBITDA for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:

•Higher realized settled trades during the year on market positions in comparison to prior year and

•The Company capitalizing on short-term volatility in the trading markets without materially changing the risk profile of the business unit.

Corporate

Year ended Dec. 31	2023	2022	Change			2021	Change
OM&A	115	101	14	14	%	84	17	20	%
Taxes, other than income taxes	1	1	—	—	%	1	—	—	%
Adjusted EBITDA(1)	(116)	(102)	(14)	14	%	(85)	(17)	20	%

(1)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.

2023

Adjusted EBITDA for the year ended Dec. 31, 2023, decreased compared to 2022, primarily due to:

•Increased spending to support strategic and growth initiatives,

•Higher costs associated with the relocation of the Company's head office and

•Increased costs due to inflationary pressures.

2022

Adjusted EBITDA for the year ended Dec. 31, 2022, decreased compared to 2021, primarily due to:

•Higher incentive accruals reflecting the Company's performance;

•No additional receipts of Canada Emergency Wage Subsidy proceeds as occurred in 2021 and

•Higher losses on the total return swap.

M22 TransAlta Corporation 2023 Integrated Report

Performance by Segment with Supplemental Geographical Information

The following table provides adjusted EBITDA performance of our facilities across the regions we operate in:

Year ended Dec. 31, 2023	Hydro	Wind & Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Alberta	451	77	571	(10)	109	(116)	1,082
Canada, excluding Alberta	8	95	89	—	—	—	192
US	—	84	10	132	—	—	226
Australia	—	1	131	—	—	—	132
Adjusted EBITDA(1)	459	257	801	122	109	(116)	1,632
Earnings before income taxes							880
Year ended Dec. 31, 2022	Hydro	Wind & Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Alberta	515	114	404	(18)	183	(102)	1,096
Canada, excluding Alberta	12	106	87	—	—	—	205
US	—	91	8	104	—	—	203
Australia	—	—	130	—	—	—	130
Adjusted EBITDA(1)	527	311	629	86	183	(102)	1,634
Earnings before income taxes							353

(1)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. 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. Also, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Optimization of the Alberta Portfolio

Our merchant exposure is primarily in Alberta, where 53 per cent of our capacity is located, and 75 per cent of our Alberta assets are available to participate in the merchant market. Our portfolio of merchant assets in Alberta consists of hydro facilities, wind facilities, a battery storage facility and natural gas generation facilities.

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 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.

Optimization of portfolio performance in the Alberta merchant market is driven by the diversity of fuel types and enables portfolio management. 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 significant portion of the thermal generation capacity in the portfolio has been hedged to provide cash

flow certainty. The Company's hedging strategy includes maintaining a significant base of commercial and industrial customers and is supplemented with financial hedges. In 2023, 78 per cent of our energy production in Alberta was sold under long-term contracts or fixed price hedges.

The Alberta hydro fleet provides ancillary services and grid reliability products such as Black Start service in the event of a system-wide blackout in the province and drought mitigation by systematically regulating river flows. Our Alberta wind and hydro fleets provide a steady stream of environmental credits to meet ESG goals.

During 2023, the Company entered into a definitive share purchase agreement relating to Heartland Generation Ltd. and Alberta Power (2000) Ltd. (collectively "Heartland") and expects to close the transaction in the first half of 2024, subject to certain customary closing conditions being met. The Heartland acquisition will further expand our portfolio capabilities. The fast-ramping nature of certain of the Heartland units will be ideally positioned to capture expected price swings and periodic higher realized prices in the Alberta market.

TransAlta Corporation 2023 Integrated Report M23

	2023										2022										2021
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
Gross installed capacity (MW)	834		766		1,960		—		3,560		834		636		1,960		—		3,430		834		636		1,960		801		4,231
Total production (GWh)	1,492		1,907		8,360		—		11,759		1,665		1,686		8,106		19		11,476		1,586		1,319		7,281		2,591		12,777
Contract production (GWh)	—		774		861		—		1,635		—		620		526		—		1,146		—		271		509		—		780
Merchant production (GWh)	1,492		1,133		7,499		—		10,124		1,665		1,066		7,580		19		10,330		1,586		1,048		6,772		2,591		11,997
Hedged production (GWh)	378		—		7,172		—		7,550		—		—		7,228		—		7,228		—		—		6,992		—		6,992
Production contracted or hedged (%)	25	%	41	%	96	%	—	%	78	%	—	%	37	%	96	%	—	%	73	%	—	%	21	%	103	%	—	%	61	%
Revenues(1) ($)	509		130		1,083		5		1,727		583		155		989		6		1,733		358		97		674		257		1,386
Fuel and purchased power ($)	17		20		336		—		373		18		21		442		5		486		13		9		258		92		372
Carbon compliance ($)	—		—		106		—		106		—		1		70		(1)		70		—		—		96		60		156
Gross margin ($)	492		110		641		5		1,248		565		133		477		2		1,177		345		88		320		105		858

(1)Revenues have been adjusted to exclude the impact of unrealized mark-to-market gains or losses and to include realized gains and losses on closed exchange positions.

Total production for the year ended Dec. 31, 2023, was 11,759 GWh compared to 11,476 GWh of electricity in 2022. The increase of 283 GWh, or 2 per cent, was primarily due to:

•The commercial operation of the Garden Plain wind facility in the third quarter of 2023,

•Higher production from our Gas assets due to strong market conditions in the first half of 2023, partially offset by

•Lower water resources in the Alberta Hydro assets.

Hedged production for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:

•The opportunity to secure additional margins with strategic hedges for the hydro assets.

Gross margin for the year ended Dec. 31, 2023, was $1,248 million compared to $1,177 million in 2022. The increase of $71 million, or 6 per cent, was primarily due to:

•Higher power price hedges, partially offsetting the impacts of lower Alberta spot prices and

•Lower natural gas prices compared to 2022, partially offset by

•Lower ancillary services revenues due to the AESO procuring lower volumes given its decision to reduce the cumulative volume of imports into Alberta.

M24 TransAlta Corporation 2023 Integrated Report

The following table provides information for the Company's Alberta electricity portfolio:

Year ended Dec. 31, 2023	2023	2022	2021
Alberta Market
Spot power price average per MWh	134	162	102
Natural gas price (AECO) per GJ	2.54	5.08	3.39
Carbon compliance price per tonne	65	50	40
Alberta Portfolio Results
Realized merchant power price per MWh(1)	136	126	91
Hydro energy spot power price per MWh	175	197	122
Hydro ancillary spot price per MWh	67	76	55
Wind energy spot power price per MWh	73	90	63
Gas and Energy Transition spot power price per MWh	162	194	114
Hedged power price average per MWh	111	86	72
Hedged volume (GWh)	7,550	7,228	6,992
Fuel and purchased power per MWh(2)	45	60	38
Carbon compliance cost per MWh(2)	13	9	16

(1)Realized merchant power price for the Alberta electricity portfolio is the average price realized as a result of the Company's merchant power sales and portfolio optimization activities (excluding assets under long-term contract and ancillary revenues) divided by total merchant GWh produced.

(2)Fuel and purchased power per MWh and carbon compliance cost per MWh are calculated on production from carbon-emitting generation in the Gas and Energy Transition segments, and carbon compliance cost per MWh includes emission credits used to settle a portion of GHG carbon pricing obligations.

The average spot power price per MWh for the year ended Dec. 31, 2023 decreased from $162 per MWh in 2022 to $134 per MWh in 2023, primarily due to:

•Moderate temperatures in the last six months of the year compared with the prior year;

•Higher total renewable generation in the Alberta market from new wind and solar facilities and higher wind resources during the fourth quarter of 2023; and

•Lower natural gas prices.

Realized merchant power price per MWh of production for the year ended Dec. 31, 2023, increased by $10 per MWh, compared to 2022, primarily due to:

•Optimization of our available capacity across all fuel types; and

•Higher hedge prices compared to the prior year.

Fuel and purchased power cost per MWh for the year ended Dec. 31, 2023, decreased by $15 per MWh, compared to 2022, primarily due to lower natural gas prices.

Carbon compliance cost per MWh of production for the year ended Dec. 31, 2023, increased by $4 per MWh, compared to 2022, primarily due to:

•Carbon compliance prices increasing from $50 per tonne in 2022 to $65 per tonne in 2023; and

•No utilization of emission credits to settle the GHG obligation during the year. In the prior year, the Company used emission credits to settle a portion of the carbon compliance obligation resulting in a lower carbon cost per MWh.

TransAlta Corporation 2023 Integrated Report M25

Fourth Quarter Highlights

The Hydro, Wind and Gas facilities in the Alberta electricity portfolio in the fourth quarter of 2022 had high availability during periods of peak pricing, which resulted from extreme cold weather and periods of province-wide planned and unplanned outages resulting in exceptional

financial performance during the quarter. The Company did not experience the same weather conditions in the fourth quarter of 2023; with the weather being relatively mild compared to the fourth quarter of 2022.

Consolidated Financial Highlights

Three months ended Dec. 31	2023	2022
Operational information
Adjusted availability (%)	86.9	89.5
Production (GWh)	5,783	6,005
Select financial information
Revenues	624	854
Earnings (loss) before income taxes	(35)	7
Adjusted EBITDA(1)	289	541
Net (loss) attributable to common shareholders	(84)	(163)
Cash flows
Cash flow from operating activities	310	351
Funds from operations(1)	229	459
Free cash flow(1)	121	315
Per share
Weighted average number of common shares outstanding	308	269
Net (loss) per share attributable to common shareholders, basic and diluted	(0.27)	(0.61)
Dividends declared per common share	0.12	0.11
Funds from operations per share(1)(2)	0.74	1.71
Free cash flow per share(1)(2)	0.39	1.17

(1)These items are not defined and have no standardized meaning under IFRS. 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. Also, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(2)FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for the purpose of these non-IFRS ratios.

Operating Performance

Adjusted Availability

The following table provides adjusted availability (%) by segment:

Three months ended Dec. 31	2023	2022
Hydro	76.6	96.8
Wind and Solar	90.3	85.7
Gas	89.5	92.8
Energy Transition	79.6	76.4
Adjusted availability (%)	86.9	89.5

M26 TransAlta Corporation 2023 Integrated Report

Adjusted availability for the three months ended Dec. 31, 2023, was 86.9 per cent compared to 89.5 per cent for the same period in 2022, primarily due to:

•Planned outages in the Gas segment and Hydro segment, partially offset by

•Higher availability for the Wind and Solar segment, mainly due to the partial return to service of the Kent Hills wind facilities and

•Lower unplanned outages in the Energy Transition segment.

Production and Long-Term Average Generation

	2023				2022
Three months ended Dec. 31	Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA		Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA
Hydro	326	447	73	%	344	435	79	%
Wind and Solar	1,479	1,621	91	%	1,222	1,499	82	%
Gas	2,892				3,375
Energy Transition	1,086				1,064
Total	5,783				6,005

Production for the three months ended Dec. 31, 2023, was 5,783 GWh compared to 6,005 GWh for the same period in 2022. The decrease was primarily due to:

•Lower dispatch of the Alberta Gas assets due to warmer temperatures and

•Lower availability, partially offset by

•Higher production in the Wind and Solar segment with the addition of the Garden Plain wind facility.

During the fourth quarter of 2023, weather impacts were relatively mild compared to the prior period, as the Company did not experience the same weather conditions as the fourth quarter of 2022, which had extreme cold weather in Alberta, resulting in periods of exceptional peak pricing in 2022.

Financial Performance review on Consolidated Information

Three months ended Dec. 31	2023	2022
Revenues	624	854
Fuel and purchased power	278	446
Carbon compliance	27	27
Operations, maintenance and administration	150	157
Depreciation and amortization	132	188
Gain on sale of assets and other	—	46
Earnings (loss) before income taxes	(35)	7
Income tax expense	19	89
Net loss attributable to common shareholders	(84)	(163)
Net earnings attributable to non-controlling interests	5	56

Current Year Variance Analysis (Fourth quarter 2023 versus 2022)

Revenuesfor the three months ended Dec. 31, 2023, decreased by $230 million, or 27 per cent, compared to the same period in 2022, primarily due to:

•Lower merchant sales due to lower spot power prices and production in Alberta and

•Lower realized ancillary services prices and volumes in the Hydro segment, partially offset by

•Higher realized and unrealized gains from hedging and derivative positions across the segments.

Fuel and purchased power costs for the three months ended Dec. 31, 2023, decreased by $168 million, or 38 per cent, compared to the same period in 2022, primarily due to:

TransAlta Corporation 2023 Integrated Report M27

•Lower natural gas commodity costs and

•Lower consumption of natural gas within our Gas segment.

Carbon compliance costs for the three months ended Dec. 31, 2023, were consistent with the same period in 2022 due to:

•Carbon price increases from $50 per tonne to $65 per tonne, offset by

•Reduced production volumes.

OM&A expenses for the three months ended Dec. 31, 2023, decreased by $7 million, or 4 per cent, compared to the same period in 2022, primarily due to:

•Lower incentive accruals in line with the Company's performance in comparison to the Company's exceptional performance in the fourth quarter of 2022, partially offset by

•The write-down of parts and material inventory for the gas facilities.

Depreciation and amortization for the three months ended Dec. 31, 2023, decreased by $56 million, or 30 per cent, compared to the same period in 2022, primarily due to:

•Revisions to useful lives on certain facilities, partially offset by

•Commercial operation of new facilities.

Gain on sale of assets and otherfor the three months ended Dec. 31, 2023, decreased by $46 million, or 100 per cent, compared to the same period in 2022, primarily due to the sale of certain gas generation assets in 2022.

Loss before income taxes totalling $35 million, decreased by $42 million, or 600 per cent, compared to earnings before income taxes of $7 million in 2022, due to the above noted items.

Income tax expense for the three months ended Dec. 31, 2023, decreased by $70 million, or 79 per cent, compared to 2022, due to lower earnings before tax in 2023 and the reduction of non-deductible expenses in the U.S.

Net loss attributable to common shareholdersin the three months ended Dec. 31, 2023 was $84 million compared to a net loss of $163 million in the same period of 2022, an improvement of $79 million, or 48 percent, primarily due to the above noted items.

Net earnings attributable to non-controlling interests for the three months ended Dec. 31, 2023, decreased by $51 million, or 91 per cent, compared to the same period in 2022, primarily due to lower net earnings for TA Cogen and the acquisition of TransAlta Renewables on Oct. 5, 2023.

Segmented Financial Performance and Operating Results for the Fourth Quarter

A summary of our adjusted EBITDA by segment and earnings (loss) before income taxes for the three months ended Dec. 31, 2023, and 2022 is as follows:

	Adjusted EBITDA(1)
Three months ended Dec. 31	2023	2022
Hydro	56	133
Wind and Solar	82	92
Gas	141	264
Energy Transition	26	19
Energy Marketing	14	63
Corporate	(30)	(30)
Total adjusted EBITDA(1)	289	541
Earnings (loss) before income taxes	(35)	7

(1)This item 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.

M28 TransAlta Corporation 2023 Integrated Report

The major factors impacting adjusted EBITDA for the three months ended Dec. 31, 2023, are summarized in the following table:

	Three months ended Dec. 31
Adjusted EBITDA for the three months ended Dec. 31, 2022	541
Hydro: lower due to decreased revenues from lower merchant and ancillary prices in the Alberta market and lower ancillary services volumes.	(77)
Wind and Solar: lower due to lower merchant pricing in Alberta, lower wind resource in Eastern Canada and the US and higher OM&A due to new long-term service agreements, partially offset by higher revenues related to the partial return to service of the Kent Hills facilities and the addition of the Garden Plain wind facility and Northern Goldfields solar facilities.	(10)
Gas: lower due to lower realized prices and production volume in the Alberta market, lower thermal revenues due to lower steam revenue pricing at the Sarnia facility compared to 2022, and higher OM&A with the inventory writedown at the Sundance and Keephills 2 facilities.	(123)
Energy Transition: higher due to higher production due to lower unplanned outages, partially offset by lower revenues as a result of lower market prices.	7
Energy Marketing: lower realized settled trades during the fourth quarter on market positions in comparison to the prior period in 2022.	(49)
Corporate: consistent with the same period in 2022.	—
Adjusted EBITDA(1) for the three months ended Dec. 31, 2023	289

(1)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.

FCF for the three months ended Dec. 31, 2023, decreased by $194 million or 62 per cent, compared to the same period in 2022.

	Three months ended Dec. 31
FCF for the three months ended Dec. 31, 2022	315
Lower adjusted EBITDA: lower FCF due to the items noted above.	(252)
Lower distributions paid to subsidiaries' non-controlling interests: lower net earnings in TA Cogen and no dividends paid to TransAlta Renewables shareholders resulting in higher FCF.	42
Other(1)	16
FCF(2) for the three months ended Dec. 31, 2023	121

(1)Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF section tables in this MD&A for more details.

(2)FCF 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.

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; 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.

TransAlta Corporation 2023 Integrated Report M29

	Q1 2023	Q2 2023	Q3 2023	Q4 2023
Revenues	1,089	625	1,017	624
Earnings (loss) before income taxes	383	79	453	(35)
Net earnings (loss) attributable to common shareholders	294	62	372	(84)
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1)	1.10	0.23	1.41	(0.27)
Cash flow from operating activities	462	11	681	310

	Q1 2022	Q2 2022	Q3 2022	Q4 2022
Revenues	735	458	929	854
Earnings (loss) before income taxes	242	(22)	126	7
Net earnings (loss) attributable to common shareholders	186	(80)	61	(163)
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1)	0.69	(0.30)	0.23	(0.61)
Cash flow from (used in) operating activities(2)	451	(129)	204	351

(1)Basic and diluted earnings (loss) per share attributable to common shareholders is calculated in each period using the basic and diluted weighted average common shares outstanding during the period, respectively. 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.

(2)The cash flow used in operating activities for the second quarter of 2022 was negative 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.

Net earnings (loss) attributable to common shareholders over the prior eight quarters has also been impacted by the following variations and events:

•Higher revenues arising from higher overall availability during periods of peak pricing and higher power prices in Alberta in the second, third and fourth quarters of 2022 and the first and second quarters of 2023;

•Lower natural gas pricing in 2023 and higher natural gas pricing in 2022;

•Lower carbon costs in 2022 were realized as the Company utilized emission credits to settle a portion of our GHG obligation in the second quarter of 2022. In 2023, the Company settled its carbon obligation with cash. Higher carbon costs in the first three quarters of 2023 were due to higher carbon price per tonne and were also due to higher production in the second quarter of 2023;

•The continued extended outage of the Kent Hills 1 and 2 wind facilities from the first quarter of 2022 through to the third quarter of 2023. The facilities were partially returned to service in the fourth quarter of 2023, with all turbines now commissioned and the remediation project completed in the first quarter of 2024;

•The effects of asset impairment reversals recognized in the first, second and third quarters of 2023 and the effects of asset impairment charges and reversals during all periods shown;

•The effects of changes in decommissioning provisions for retired assets from changes in estimated cash flows and discount rates in all periods shown, and changes in useful

lives, recognized in the third quarter of 2022 and the third and fourth quarters of 2023;

•Insurance proceeds for the single tower failure at Kent Hills wind facilities of $7 million recognized in the second quarter of 2022;

•Liquidated damages recoverable from turbine availability being below the contractual target at the Windrise wind facility recorded in each quarter in 2022 and in each quarter in 2023;

•Sundance Unit 4 being retired in the first quarter of 2022;

•Commissioning of the Garden Plain wind facility in the third quarter of 2023 and the Northern Goldfields solar facilities in the fourth quarter of 2023;

•Gains relating to the sale of assets being recognized in the fourth quarter of 2022;

•Fluctuations in the Canadian dollar relative to the US dollar resulting in foreign exchange gains and losses on our US-denominated long-term debt balances not designated as hedges; and

•Fluctuations in current and deferred tax expense with earnings before tax across the quarters. Deferred tax expense decreased from 2022 mainly due to a lower non-deductible tax adjustment relating to the US along with a deferred tax recovery of a previous derecognition of Canadian tax assets.

M30 TransAlta Corporation 2023 Integrated Report

Strategy and Capability to Deliver Results

Our strategic focus is to invest in clean electricity solutions that meet the needs and objectives of our customers and communities. We invest in a disciplined and prudent manner to deliver appropriately risk-adjusted returns to our shareholders. To support this strategy, we maintain a growing pipeline of project opportunities focused on hydro, wind, solar, energy storage and low emissions gas generation.

In 2021, we set out clear targets under the Clean Electricity Growth Plan. These targets included delivering 2 GW of incremental renewable capacity with a target capital investment of $3.6 billion in order to drive additional cumulative annual EBITDA of $315 million from new growth projects. Over the last two years, the Company achieved over 40 per cent of that original target by adding 800 MW of new capacity, together with the transmission expansion project for BHP Nickel West.

In 2023, given the market challenges of rising equipment and capital costs, we remained disciplined and patient with our greenfield efforts and shifted our focus towards priorities of simplification, contracted renewables and flexible generation. We looked to two strategic acquisitions that would position the Company well for the future, TransAlta Renewables and Heartland Generation Ltd.

We deployed $1.3 billion toward the acquisition of TransAlta Renewables which provided economic

contribution from an incremental 1.2 GW of generating capacity, increasing the proportionate EBITDA and contractedness of the Company.

We also entered into a definitive share purchase agreement to acquire Heartland Generation Ltd. for an estimated total cost of $658 million. The acquisition will competitively position the Company in response to the changing dynamics in Alberta, given the expected significant increase in renewables and other large baseload generation coming online in the next several years in the highly dynamic and shifting electricity landscape in the province.

In 2023, our growth and execution teams progressed construction on new facilities, in all three of our core geographies, through one of the largest construction programs that the Company has ever undertaken. The fully contracted 130 MW Garden Plain and 48 MW Northern Goldfields solar and battery storage facilities reached commercial operation, adding $21-$23 million in incremental EBITDA. The 300 MW White Rock East and the White Rock West projects and the 200 MW Horizon Hill wind project are expected to reach commercial operation in the first quarter of 2024, adding $76-$82 million and $41-$44 million, respectively, in incremental EBITDA.

Strategic Priorities and Clean Electricity Growth Plan to 2028

On Nov. 21, 2023, the Company updated its five-year strategic growth targets and Clean Electricity Growth Plan. The Company established six strategic priorities to focus our path from 2024 to 2028. They are outlined below and include goals for growth, investment and ESG priorities.

The Company's growth targets include adding up to 1.75 GW of new generating capacity to the Company’s fleet while targeting cumulative annual EBITDA from new growth of $350 million by investing approximately $3.5 billion to develop, construct and acquire new assets through 2024 to the end of 2028. The growth will focus on customer-centered renewables and storage through the execution of its current 5.3 GW development pipeline that it plans to expand to reach 10 GW by 2028.

We expect the Company's adjusted EBITDA generated from renewable sources, including hydro, wind and solar technologies, to increase to 70 per cent by the end of 2028. The Clean Electricity Growth Plan will largely be funded from current cash balances, cash generated from operations and debt financing.

Our investment focus to 2028 will focus on renewables and storage, but may also include efficient and flexible natural gas generation and new technology. The Company has a long-term decarbonization goal of net-zero by 2045.

Our current progress towards achieving these strategic targets is summarized below:

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Strategic Targets 2024 to 2028

Goals	Target	Results	Comments
Optimize Alberta portfolio	Continue to optimize our existing asset base and maximize the value of our hydro fleet in Alberta.	On Track	The acquisition of Heartland will add 1,844 MW of complementary flexible capacity to the Alberta portfolio including contracted cogeneration, peaking generation, transmission capacity and development opportunities in hydrogen.
Execute Clean Electricity Growth Plan	Deliver up to 1.75 GW of renewable capacity with an estimated capital investment of $3.5 billion by the end of 2028.	On Track	The Company is currently advancing 418 MW of advanced-stage projects towards final investment decision in 2024.
	Deliver incremental average annual EBITDA of $350 million by the end of 2028.	On Track	In 2024, the Company plans to make investment decisions on new projects that will produce at least $80 million in incremental EBITDA.
	Expand the Company's development pipeline to 10 GW by the end of 2028.	On Track	In 2024, The Company plans to add an additional 1,500 MW to its development pipeline to further support our Clean Electricity Growth Plan.
Selective Expansion of Flexible Generation and Reliability Assets	Selectively expand our portfolio offerings in flexible generation and reliability assets such as peaking generation and short-term and long-term storage.	On Track	The Company plans to selectively invest in peaking generation and battery storage assets to optimize our portfolio. The acquisition of Heartland will add 387 MW of peaking gas capacity to our portfolio, the peaking assets will be optimized by the Company to address increasing intermittency in Alberta.
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, debt repayments and share repurchases.	On Track	The Company had liquidity of $1.7 billion as at Dec. 31, 2023. The Company increased the annual common share dividend by 9 per cent to $0.24 per year effective April 1, 2024. In 2024, the Company announced that it intends to repurchase up to $150 million of common shares. The increased annual common share dividend, along with the share repurchase commitment, will represent a return of up to approximately 40 per cent of the midpoint of our 2024 FCF guidance to shareholders.
Define the Next Generation of Power Solutions	Meet the needs of our customers and communities through the implementation of innovative electricity solutions and parallel investments in new complementary sectors by the end of 2028.	On Track	The Company established an Energy Innovation team to progress our goals in this area. The team has completed an equity investment in Ekona Power Inc. ("Ekona"), an early-stage hydrogen production company, in order to pursue commercialization of low cost, net-zero aligned hydrogen. The Company also committed to invest US$25 million over the next four years in the Energy Impact Partners Frontier Fund, which provides a portfolio approach to investing in emerging technologies focused on net-zero emissions. In total, the Company invested US$12 million to this fund as at Dec. 31, 2023.
Lead in ESG and Market Policy Development	Actively participate in policy development to ensure the electricity that 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 on the proposed federal Clean Electricity Regulations, as well as electricity market and renewable approval changes under review in Alberta. This includes participation in the AESO's Executive Working Group and the Canada Electricity Advisory Council. TransAlta's input is focused on how to achieve emissions reductions while maintaining reliability and affordability. The Company continues to work with the Government of Canada on the design details of the investment tax credits and clean technology funding provided through the Government of Canada, as well as exploring funding opportunities through the Government of Alberta.

M32 TransAlta Corporation 2023 Integrated Report

Advanced-Stage Development

These projects have detailed engineering, advanced positions in the interconnection queue and/or are progressing offtake opportunities. Projects in advanced-stage development are progressing towards

final investment decision and do not have final approval from the Board of Directors at time of reporting. The following table shows the pipeline of future growth projects currently under advanced-stage development:

Project	Type	Region	Target investment date	MW	Estimated spend	Average annual EBITDA(1)
Tempest	Wind	Alberta	2024	100	$260-$280	$22-$26
SCE Capacity Expansion	Gas	Western Australia	2024	94	AU$210-AU$230	AU$28-AU$32
WaterCharger	Battery Storage	Alberta	2024	180	$160-$180(2)	$15-$17
Pinnacle 1 & 2	Gas	Alberta	2024	44	$65-$75	$13-$15
Total(3)				418	$740 - $813	$82 - $94

(1)This item is not defined, has no standardized meaning under IFRS and is forward-looking. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

(2)Estimated spend is net of government funding and anticipated tax credits.

(3)Total expected spending and average annual EBITDA was converted using a Canadian dollar forward exchange rate for 2023.

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.

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The following table shows the pipeline of future growth projects currently under early-stage development:

Project	Type	Region	Potential investment date(1)	MW
Canada
Riplinger Wind	Wind	Alberta	2025	300
Sunhills Solar	Solar	Alberta	2025	170
McNeil Solar	Solar	Alberta	2025	57
New Brunswick Battery	Battery	New Brunswick	2025	10
Tent Mountain Pumped Storage(2)	Hydro	Alberta	2026	160
Provost	Wind	Alberta	2026	170
Antelope Coulee	Wind	Saskatchewan	2027+	200
Red Rock	Wind	Alberta	2027	100
Willow Creek 1	Wind	Alberta	2027	70
Willow Creek 2	Wind	Alberta	2027	70
Other Canadian Opportunities	Wind	Various	2026+	190
Brazeau Pumped Hydro	Hydro	Alberta	TBD	300-900
Alberta Thermal Redevelopment(3)	Various	Alberta	TBD	250-500
		Total		2,047 - 2,897
United States
Monument Road	Wind	Nebraska	2025	152
Swan Creek	Wind	Nebraska	2025	126
Dos Rios	Wind	Oklahoma	2025	242
Cotton Belle 1	Solar	Texas	2025	104
Cotton Belle 2	Solar	Texas	2025	81
Square Top	Solar	Oklahoma	2026	195
Old Town	Wind	Illinois	2026	185
Canadian River	Wind	Oklahoma	2026	250
Prairie Violet	Wind	Illinois	2026	130
Quick Draw	Wind	Texas	2026	174
Big Timber	Wind	Pennsylvania	2026	50
Trapper Valley	Wind	Wyoming	2027	225
Wild Waters	Wind	Minnesota	2027+	40
Coolspring	Wind	Pennsylvania	2027+	120
Other US Opportunities	Wind	Various	2026+	144
Centralia Site Redevelopment(3)	Various	Washington	TBD	250-500
		Total		2,468 - 2,718
Australia
Boodarie Solar	Solar	Western Australia	2024	50
Southern Cross Energy	Wind and Solar	Western Australia	TBD	120
Other Australian Opportunities	Gas, Solar, Transmission	Western Australia	2024+	230
		Total		400
Canada, United States and Australia		Total		4,915 - 6,015

(1)Potential investment date is to be determined ("TBD").

(2)This represents the Company's 50 per cent interest in Tent Mountain. See the Significant and Subsequent Events section of this MD&A for more details.

(3)The Company is currently evaluating redevelopment opportunities at these brownfield sites.

M34 TransAlta Corporation 2023 Integrated Report

Projects under Construction

The following projects have been approved by the Board of Directors, have executed PPAs and are currently under construction or in the process of being commissioned. The projects under construction will be financed through existing liquidity in the near term. We will continue to explore permanent financing solutions on an asset-by-asset basis.

We are continually monitoring the timing and costs on our projects under construction. Our US projects have

experienced schedule delays and increased costs attributable to complexities relating to transmission interconnections and wind turbine erection. The 300 MW White Rock wind projects and the 200 MW Horizon Hill wind project transmission lines are fully energized. The projects are expected to achieve commercial operation in the first quarter of 2024.

				Total project (millions)
Project	Type	Region	MW	Estimated spend			Spent to date	Target completion date	PPA Term(1)	Average annual EBITDA(2)	Status
United States
White Rock	Wind	OK	300	US$510	—	US$530	US$477	Q1 2024	—	US$53-US$57	•Long-term PPAs executed •Installation/assembly complete •Final stages of commissioning underway
Horizon Hill	Wind	OK	200	US$330	—	US$340	US$307	Q1 2024	—	US$31-US$33	•Long-term PPA executed •Installation/assembly complete •Final stages of commissioning underway
Australia
Mount Keith 132kV Expansion	Transmission	WA	n/a	AU$54	—	AU$57	AU$45	Q1 2024	15	AU$6 - AU$7	•Installation/assembly complete •Final stages of commissioning underway
Mount Keith West Network Upgrade	Transmission	WA	n/a	AU$37	—	AU$40	AU$12	Q2 2025	14	AU$6 - AU$7	•Major equipment orders placed •Detailed design and execution planning underway •On track to be completed on schedule
Total(3)			500	$1,228	—	$1,274	1,360			$125 - $135

(1)The PPA term is confidential for the White Rock wind projects and Horizon Hill wind project.

(2)This item is not defined and has no standardized meaning under IFRS and is forward-looking. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

(3)Total expected spending and average annual EBITDA were converted using a Canadian dollar forward exchange rate for 2023. Spend to date was converted using the period-end closing rate.

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Financial Position

The following table highlights significant changes in the Consolidated Statements of Financial Position from Dec. 31, 2022, to Dec. 31, 2023:

	Dec. 31, 2023	Dec. 31, 2022	Increase/(decrease)
Assets
Current assets
Cash and cash equivalents	348	1,134	(786)
Trade and other receivables	807	1,589	(782)
Risk management assets	151	709	(558)
Other current assets(1)	274	282	(8)
Total current assets	1,580	3,714	(2,134)
Non-current assets
Risk management assets	52	161	(109)
Property, plant and equipment, net	5,714	5,556	158
Long-term portion of finance lease receivable	171	129	42
Other non-current assets(2)	1,142	1,181	(39)
Total non-current assets	7,079	7,027	52
Total assets	8,659	10,741	(2,082)
Liabilities
Current liabilities
Accounts payable and accrued liabilities	797	1,346	(549)
Risk management liabilities	314	1,129	(815)
Income taxes payable	9	73	(64)
Credit facilities, long-term debt and lease liabilities	532	178	354
Other current liabilities(3)	90	162	(72)
Total current liabilities	1,742	2,888	(1,146)
Non-current liabilities
Credit facilities, long-term debt and lease liabilities	2,934	3,475	(541)
Risk management liabilities (long-term)	274	333	(59)
Defined benefit obligation and other long-term liabilities	251	294	(43)
Deferred income tax liabilities	386	352	34
Other non-current liabilities(4)	1,408	1,410	(2)
Total non-current liabilities	5,253	5,864	(611)
Total liabilities	6,995	8,752	(1,757)
Equity
Equity attributable to shareholders	1,537	1,110	427
Non-controlling interests	127	879	(752)
Total equity	1,664	1,989	(325)
Total liabilities and equity	8,659	10,741	(2,082)

(1)Includes restricted cash, prepaid expenses and other, and inventory.

(2)Includes investments, right-of-use assets, intangible assets, goodwill, deferred income tax assets and other assets.

(3)Includes bank overdraft, current portion of decommissioning and other provisions, current portion of contract liabilities and dividends payable.

(4)Includes exchangeable securities, long-term decommissioning and other provisions and contract liabilities.

(5)Significant changes in TransAlta's Consolidated Statements of Financial Position were as follows:

M36 TransAlta Corporation 2023 Integrated Report

Working Capital

The deficit of current assets over current liabilities, including the current portion of long-term debt and lease liabilities, was $162 million as at Dec. 31, 2023 (Dec. 31, 2022 – excess of current assets over current liabilities of $826 million), primarily as a result of the $400 million Term Facility being reclassified from long-term to current liabilities in the period as it is due to be repaid in September 2024, along with lower receivables and collateral provided in the Energy Marketing segment due to reduced volatility in the market and market prices.

Current assets decreased by $2,134 million to $1,580 million as at Dec. 31, 2023, from $3,714 million as at Dec. 31, 2022, primarily due to:

•Lower trade receivables related to collections from higher revenues recognized in December 2022, and lower receivables and collateral provided in the Energy Marketing segment due to lower market prices,

•Lower cash and cash equivalents, mainly from the use of cash to complete the acquisition of the RNW Shares and

•Lower risk management assets mainly due to lower market prices and higher contract settlements.

Current liabilities decreased by $1,146 million from $2,888 million as at Dec. 31, 2022, to $1,742 million as at Dec. 31, 2023, mainly due to:

•Lower risk management liabilities due to lower market prices, as well as higher contract settlements during the year,

•Lower accounts payable and accrued liabilities including returning collateral received in the Energy Marketing segment due to lower market prices and

•Lower income taxes payable, partially offset by

•Higher debt classified as current as the $400 million Term Facility matures in the third quarter of 2024.

Non-Current Assets

Non-current assets as at Dec. 31, 2023, were $7,079 million, an increase of $52 million from $7,027 million as at Dec. 31, 2022, primarily due to:

•Higher property, plant and equipment ("PP&E") resulting from higher capital additions of $875 million, mainly related to the construction of growth projects and the rehabilitation of the Kent Hills wind facilities of $157 million, inclusive of insurance proceeds. The increase in PP&E additions was partially offset by depreciation of $585 million and

•Higher net investment in finance leases related to the Northern Goldfields solar facilities, partially offset by

•Lower risk management assets due to changes in market pricing across multiple markets and contract settlements.

Non-Current Liabilities

Non-current liabilities as at Dec. 31, 2023, were $5,253 million, a decrease of $611 million from $5,864 million as at Dec. 31, 2022, mainly due to:

•Lower long-term debt and lease liabilities related to scheduled debt repayments and the reclassification of the $400 million Term Facility to current liabilities,

•Lower risk management liabilities of $59 million related to contract settlements and pricing and

•Lower defined benefit obligations due to higher interest rates and a voluntary pension payment made to reduce our pension obligations, partially offset by

•Higher deferred tax liabilities.

Total Equity

As at Dec. 31, 2023, the decrease in total equity of $325 million was due to:

•A net decrease of $809 million from the acquisition of TransAlta Renewables,

•Distributions to non-controlling interests of $198 million,

•Share repurchases under the NCIB of $87 million and

•Dividends declared on common and preferred shares of $116 million, partially offset by

•Net earnings of $796 million and

•Net gains on derivatives from cash flow hedges of $99 million.

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 2023, Moody's reaffirmed the Company's long-term rating of Ba1 with a stable outlook. Morningstar DBRS reaffirmed 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 outlook. In addition, S&P Global Ratings reaffirmed the Company's senior unsecured debt rating and issuer

TransAlta Corporation 2023 Integrated Report M37

credit 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

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

	2023		2022		2021
	$	%	$	%	$	%
Net senior unsecured debt
Recourse debt - CAD debentures	251	5	251	5	251	4
Recourse debt - US senior notes	911	17	934	18	888	16
Credit facilities	397	7	428	9	—	—
Other	—	—	1	—	4	—
Less: cash and cash equivalents(1)	(345)	(6)	(1,118)	(21)	(947)	(17)
Less: other cash and liquid assets(2)	(12)	—	(20)	—	(19)	—
Net senior unsecured debt	1,202	23	476	11	177	3
Other debt liabilities
Exchangeable debentures	344	6	339	6	335	6
Non-recourse debt
TAPC Holdings LP bond	85	1	94	2	102	2
Pingston bond	39	1	45	1	45	1
Melancthon Wolfe Wind bond	168	3	202	4	235	4
New Richmond Wind bond	103	2	112	2	120	2
Kent Hills Wind bond	193	3	206	4	221	4
Windrise Wind bond	164	3	170	3	171	3
South Hedland non-recourse debt	691	13	711	14	732	13
OCP Bond	217	4	241	4	263	5
US tax equity financing	104	1	123	2	135	2
Lease liabilities	143	3	135	2	100	2
Total consolidated net debt(3)(4)(5)	3,453	63	2,854	55	2,636	47
Exchangeable preferred securities(5)	400	7	400	7	400	7
Equity attributable to shareholders
Common shares	3,285	60	2,863	54	2,901	51
Preferred shares	942	17	942	18	942	17
Contributed surplus, deficit and accumulated other comprehensive loss	(2,690)	(49)	(2,695)	(51)	(2,261)	(40)
Non-controlling interests	127	2	879	17	1,011	18
Total capital	5,517	100	5,243	100	5,629	100

(1)Cash and cash equivalents is net of bank overdraft.

(2)Includes principal portion of the TransAlta OCP restricted cash related to the TransAlta OCP bonds as this cash is restricted specifically to repay outstanding debt and also includes the fair value of economic and designated hedging instruments on debt, as the carrying value of the related debt is impacted by changes in foreign exchange rates.

(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 for further discussion, including reconciliations to measures calculated in accordance with IFRS.

(4)The tax equity financing for the 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.

M38 TransAlta Corporation 2023 Integrated Report

We have enhanced liquidity and shareholder value through the following:

2023

•Extended the committed syndicated credit facility by one year to June 30, 2027 and the committed bilateral credit facilities by one year to June 30, 2025;

•Refinanced the $45 million Pingston non-recourse bond due in 2023 with a non-recourse bond for approximately $39 million, with a fixed interest rate of 6.145 per cent per annum, payable semi-annually, and maturing on May 8, 2043; and

•Purchased and cancelled 7,537,500 common shares at an average price of $11.49 per share through our NCIB program, for a total cost of $87 million.

2022

•Issued US$400 million Senior Green Bonds, with a fixed coupon rate of 7.75 per cent per annum (effective interest rate of 5.98 per cent), due on Nov. 15, 2029;

•Repaid the US$400 million 4.50 per cent unsecured senior notes due 2022;

•Extended the committed syndicated credit facilities by one year to June 30, 2026 and the committed bilateral credit facilities by one year to June 30, 2024;

•Closed a two-year floating rate Term Facility with our banking syndicate for $400 million with a maturity date of Sept. 7, 2024. The Term Facility has interest rates that vary depending on the option selected (e.g. Canadian prime and bankers' acceptances); and

•Purchased and cancelled 4,342,300 common shares at an average price of $12.48 per share through our NCIB program, for a total cost of $54 million.

2021

•Obtained $173 million in project financing related to our Windrise wind facility.

Credit Facilities

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

As at Dec. 31, 2023		Utilized		Available capacity	Maturity date
Credit facilities	Facility size	Outstanding letters of credit(1)	Cash drawings
Committed
TransAlta syndicated credit facility	1,950	417	—	1,533	Q2 2027
TransAlta bilateral credit facilities	240	178	—	62	Q2 2025
TransAlta Term Facility	400	—	400	—	Q3 2024
Total committed	2,590	595	400	1,595
Non-committed
TransAlta demand facilities	400	187	—	213	N/A
Total non-committed	400	187	—	213

(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. Letters of credit drawn against the non-committed facilities reduce available capacity under the committed syndicated credit facilities.

On Oct. 5, 2023, upon closing the TransAlta Renewables transaction, the syndicated credit facilities were amended to effectively consolidate the TransAlta Renewables syndicated credit facility and non-committed demand facility into the TransAlta credit facilities. The cash drawings on the TransAlta Renewables' syndicated credit facility were repaid and the outstanding letters of credit were transferred to the TransAlta non-committed demand facility. The TransAlta Renewables credit facilities were then terminated.

This resulted in the TransAlta syndicated credit facility increasing by $700 million to approximately $2.0 billion.

See the Significant and Subsequent events section of this MD&A for more details.

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Non-Recourse Debt and Other

The Melancthon Wolfe Wind LP, TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd. and Windrise Wind LP non-recourse bonds, and TransAlta OCP LP 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 fourth quarter of 2023, with the exception of Kent Hills Wind LP and TAPC Holdings LP. Kent Hills Wind LP cannot make any distributions to its partners until the foundation replacement work has been completed and TAPC Holdings LP has been impacted by higher interest rates in 2023. The funds in these entities that have accumulated since the fourth quarter test will remain there until the next debt service coverage ratio is calculated in the first quarter of 2024. At Dec. 31, 2023, $79 million (Dec. 31, 2022 – $50 million) of cash was subject to these financial restrictions.

At Dec. 31, 2023, $3 million (AU$3 million) of funds held by TEC Hedland Pty Ltd. 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 reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit.

Between 2024 and 2026, we have a total of $811 million of debt repayments, including the $400 million maturity of the Term Facility, with the balance of $411 million related to scheduled non-recourse debt repayments. The $750 million of exchangeable securities can be exchanged at the earliest on Jan. 1, 2025.

US Tax Equity Financing and Production Tax Credits

The Company owns equity interests in wind facilities that are eligible for tax incentives available for renewable energy facilities in the US. Current US tax law allows qualified wind energy projects to receive production tax credits ("PTCs") that are earned for each MWh of generation during the first 10 years of the project's operation. In order to monetize tax incentives, the Company has partnered with Tax Equity Investors (“TEI”) who invest in these facilities in exchange for a share of the tax incentives and cash. TransAlta accounts for the TEI interest as long-term debt, where cash distributions and allocations of tax incentives to the TEI primarily reduce the long-term debt balance. Upon the TEI achieving an agreed-upon after-tax investment return, the project Flip Point occurs. Prior to achieving the Flip Point, the TEI are allocated substantially all of the taxable attributes including PTCs produced and a proportion of cash. After the Flip Point has been reached, the Company retains substantially all of the cash and the taxable income (losses) generated by the facility.

In 2023, US tax laws were amended to allow entities to monetize certain clean energy tax credits, including PTCs, by transferring (selling) them to third-party taxpayers, in exchange for cash consideration.

The following table outlines information regarding the Company's tax equity financing arrangements with PTC eligibility:

Facility	Commercial operation date	Expected Flip Point	Initial TEI investment ($)	Expected annual PTC ($)	TEI allocation of cash distributions (pre-Flip Point) Undiscounted(1) ($)	TEI allocation of taxable income and PTCs (pre-Flip Point)
Lakeswind	2014	2029	45	1	11	99	%
Big Level and Antrim	2019	2030	126	10	46	99	%
Skookumchuck(2)	2020	2030	121	10	21	99	%

(1)Cumulative expected cash distributions from Dec. 31, 2023 to the expected Flip Point.

(2)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.

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Returns to Providers of Capital

Interest Income and Interest Expense

Interest income and the components of interest expense are shown below:

Year ended Dec. 31	2023	2022	2021
Interest income	59	24	11
Interest on debt	203	164	163
Interest on exchangeable debentures	29	29	29
Interest on exchangeable preferred shares	28	28	28
Capitalized interest	(57)	(16)	(14)
Interest on lease liabilities	9	7	7
Credit facility fees, bank charges and other interest	21	27	20
Tax shield on tax equity financing	—	(2)	(9)
Accretion of provisions	48	49	32
Interest expense	281	286	256

Interest income was higher due to higher cash balances and favourable interest rates. Interest expense was lower than 2022, primarily due to higher capitalized interest resulting from higher capital expenditures on growth

projects. This was partially offset by higher interest on debt due to higher credit facility borrowings and higher year-over-year interest rates on variable rate debt.

Share Capital

The following tables outline the common and preferred shares issued and outstanding:

	Number of shares (millions)
As at	Feb. 22, 2024	Dec. 31, 2023	Dec. 31, 2022
Common shares issued and outstanding, end of period	307.1	308.6	268.1
Preferred shares
Series A	9.6	9.6	9.6
Series B	2.4	2.4	2.4
Series C	10.0	10.0	10.0
Series D	1.0	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	38.6	38.6	38.6
Series I - Exchangeable Securities(1)	0.4	0.4	0.4
Preferred shares issued and outstanding	39.0	39.0	39.0

(1)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 consolidated financial statements.

Non-Controlling Interests

On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. See the Significant and Subsequent Events section of this MD&A for details.

As at Dec. 31, 2023, the Company owned 50.01 per cent of TransAlta Cogeneration, LP (“TA Cogen”) (Dec. 31, 2022 – 50.01 per cent), which owns, operates or has an interest in three natural-gas-fired cogeneration facilities (Ottawa, Windsor and Fort Saskatchewan) and a natural-gas-fired facility (Sheerness). As at Dec. 31, 2023, the Company

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owned 83 per cent of Kent Hills Wind LP (Dec. 31, 2022 - 83 per cent), which owns and operates three wind facilities. Throughout 2022, on Dec. 31, 2022, and from Jan. 1, 2023 to Oct. 4, 2023, the Company owned 60.1 per cent of TransAlta Renewables.

Since the Company owned a controlling interest in TA Cogen and Kent Hills Wind LP, we consolidated the entire earnings, assets and liabilities in relation to the subsidiaries. Earnings, assets and liabilities of these subsidiaries, and of TransAlta Renewables prior to Oct. 5, 2023, were allocated to the other owners in proportion to their ownership interests.

The reported net earnings attributable to non-controlling interests for the year ended Dec. 31, 2023, decreased by $10 million, compared to 2022, primarily as a result of lower TA Cogen net earnings attributable to non-controlling interests resulting from lower production and lower merchant pricing in the Alberta market. TransAlta Renewables net earnings attributable to non-controlling interests increased by $1 million for the year ended Dec. 31, 2023 compared to 2022.

Cash Flows

The following highlights significant changes in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2023 and Dec. 31, 2022:

Year ended Dec. 31	2023	2022	Increase/ (decrease)
Cash and cash equivalents, beginning of year	1,134	947	187
Provided by (used in):
Operating activities	1,464	877	587
Investing activities	(814)	(741)	(73)
Financing activities	(1,432)	45	(1,477)
Translation of foreign currency cash	(4)	6	(10)
Cash and cash equivalents, end of year	348	1,134	(786)

Cash Flow from Operating Activities

Cash from operating activities for the year ended Dec. 31, 2023, increased compared with the same period in 2022, primarily due to the following:

	Year ended Dec. 31
Cash flow from operating activities for the year ended Dec. 31, 2022	877
Higher gross margin: Lower natural gas costs included in fuel and purchased power, partially offset by lower revenues net of unrealized gains and losses from risk management activities and higher carbon compliance costs.	127
Higher OM&A: Increased spending on strategic and growth initiatives; higher costs associated with the relocation of the Company's head office; and increased costs due to inflationary pressures.	(18)
Lower current income tax expense: Previously restricted non-capital loss carryforwards were utilized to offset taxable income.	15
Higher interest income: Higher cash balances and favourable interest rates	35
Favourable change in non-cash operating working capital balances: Lower accounts receivable and collateral provided as a result of volatility in the market and market prices, partially offset by lower accounts payable and collateral received related to derivative instruments.	440
Other	(12)
Cash flow from operating activities for the year ended Dec. 31, 2023	1,464

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Cash Flow used in Investing Activities

Cash used in investing activities for the year ended Dec. 31, 2023, increased compared with the same period in 2022, primarily due to the following:

	Year ended Dec. 31
Cash flow used in investing activities for the year ended Dec. 31, 2022	(741)
Lower additions to PP&E: Additions in 2022 were mainly for the construction of the White Rock wind projects, Garden Plain wind facility, the Horizon Hill wind project and the Northern Goldfields solar facilities. In 2023, most of these facilities achieved commercial operation.	43
Lower intangible assets: Lower additions of intangibles under development.	18
Lower proceeds on sale of PP&E: In 2022, the Company closed the sale of two hydro facilities and sold equipment related to its Sundance Unit 5 energy transition assets and other equipment.	(37)
Unfavourable change in non-cash investing working capital balances: Lower capital accruals.	(28)
Other(1)	(69)
Cash flow used in investing activities for the year ended Dec. 31, 2023	(814)

(1)Other is mainly comprised of higher spend on project development costs in 2023, higher contributions to investments in 2023, lower insurance proceeds in 2023 and lower settlements in 2023.

Cash Flow from (used in) Financing Activities

Cash used in financing activities for the year ended Dec. 31, 2023, increased compared with the same period in 2022, primarily due to the following:

	Year ended Dec. 31
Cash flow from financing activities for the year ended Dec. 31, 2022	45
Lower repayment of long-term debt: In 2022, the Company repaid the US$400 million senior notes.	457
Higher share capital issuance: Used cash and issued shares to acquire TransAlta Renewables.	(811)
Lower net increase in borrowings under credit facilities: In 2022, the Company fully utilized the $400 million Term Facility, which continues to remain outstanding.	(495)
Lower issuance of long-term debt: In 2022, the Company issued US$400 million senior notes.	(493)
Lower realized gains on financial instruments: The Company recognized a gain on the repayment of US$400 million senior notes in 2022.	(72)
Higher distributions paid to non-controlling interests: Timing of distributions to TA Cogen, partially offset by lower distributions to TransAlta.	(36)
Higher repurchases of common shares under the NCIB.	(35)
Other	8
Cash flow used in financing activities for the year ended Dec. 31, 2023	(1,432)

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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.

Related-Party Transactions

In the normal course of operations, we enter into transactions on market terms with related parties, including consolidated and equity accounted entities, which have been measured at exchange value and are recognized in the consolidated financial statements, including, but not limited to asset management fees, power purchase and derivative contracts. Refer to Note 35, Related-Party Transactions in the consolidated financial statements for further details.

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, 2023, we provided letters of credit totalling $782 million (2022 – $1.2 billion) and cash collateral of $145 million (2022 – $304 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 obligations and other long-term liabilities and decommissioning and other provisions. The decrease in the amount of letters of credit issued during 2023 relates to lower letters of credit on physical and financial derivative transactions in a net liability position.

Commitments

Contractual commitments are as follows:

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Natural gas and transportation contracts(1)	55	49	50	48	57	436	695
Transmission(1)	9	9	6	4	5	93	126
Coal supply and mining agreements(1)	86	71	—	—	—	—	157
Long-term service agreements(1)	60	57	42	44	37	184	424
Operating leases(1,2)	3	3	2	2	2	25	37
Long-term debt(3)	526	142	143	153	162	2,237	3,363
Exchangeable securities(4)	—	—	—	—	—	750	750
Principal payments on lease liabilities(5)	4	4	4	4	4	123	143
Interest on long-term debt and lease liabilities(1,6)	186	167	158	151	143	711	1,516
Interest on exchangeable securities(1,4)	53	53	53	53	53	13	278
Growth(1,7)	47	—	—	—	—	—	47
Total	1,029	555	458	459	463	4,572	7,536

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

(2)Includes leases that have not been recognized as a lease liability and leases that have not yet commenced.

(3)Excludes impact of hedge accounting and derivatives.

(4)Cash payment could occur after Dec. 31, 2028 if exchangeable securities are not exchanged by Brookfield Renewable Partners or its affiliates (collectively "Brookfield"). At Brookfield's option, the exchangeable securities can be exchanged, at the earliest, on Jan. 1, 2025.

(5)Lease liabilities exclude a lease incentive of $12 million expected to be received in 2024, which is recognized in trade and other receivables.

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

(7)For further details on growth commitments, refer to the Strategy and Capability to Deliver Results section of this MD&A.

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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.

The Company conducts internal reviews of its offers and offer behaviour in both the energy and ancillary services markets in Alberta on an ongoing basis and will self-report suspected contraventions or respond to inquiries from regulatory agencies as required. There currently is no certainty that any particular matter will be resolved in the Company’s favour or that such matters may not have a material adverse effect on TransAlta.

Brazeau Facility - Well Licence Applications to Consider Hydraulic Fracturing Activities

The Alberta Energy Regulator ("AER") issued a subsurface order on May 27, 2019, which does not permit any hydraulic fracturing within three kilometres of the Brazeau facility but permits hydraulic fracturing in all formations (except the Duvernay) within three to five kilometres of the Brazeau facility. Subsequently, two oil and gas operators submitted applications to the AER for 10 well licences (which include hydraulic fracturing activities) within three to five kilometres of the Brazeau facility.

The Company's position, based on independent expert analysis commissioned by the Government of Alberta, is that hydraulic fracturing activities within five kilometres of the Brazeau facility pose an unacceptable risk and that the applications should be denied. The regulatory hearing to consider these applications - Proceeding 379 - was adjourned to April 2025. The other parties to the hearing, including the Company, have supported the adjournment.

Brazeau Facility - Claim Against the Government of Alberta

On Sept. 9, 2022, the Company filed a Statement of Claim against the Alberta Government in the Alberta Court of King’s Bench seeking a declaration that: (a) granting mineral leases within five kilometres of the Brazeau facility is a breach of the 1960 agreement between the Company and the Alberta Government; and (b) the Alberta Government is required to indemnify the Company for any costs or damages that result from the risks of hydraulic fracturing near the Brazeau facility. On Sept. 29, 2022, the Alberta Government filed its Statement of Defence, which asserts, among other things, that the Company: (a) is trying

to usurp the jurisdiction of the AER; and (b) is out of time under the Limitations Act (Alberta). The trial was scheduled for two weeks starting Feb. 26, 2024. The parties to the matter, along with Cenovus Energy Inc., sought an adjournment when AER Proceeding 379 was adjourned. The trial is scheduled to resume in February 2025 in the event the parties are unable to resolve the dispute prior to such date.

Garden Plain

Garden Plain I LP, a wholly owned subsidiary of the Company, retained a third-party contractor to construct the Garden Plain wind project near Hanna, Alberta. The contractor experienced scheduling delays, challenges with construction and significant cost overruns, resulting in overdue deadlines, and has asserted a claim for $49 million in damages. The Company disputes this claim in its entirety and asserts a counterclaim. The parties have initiated the dispute resolution procedure, and the arbitration hearing is set down for three weeks starting April 14, 2025.

Hydro Power Purchase Arrangement ("Hydro PPA") Emissions Performance Credits

The Balancing Pool claimed entitlement to 1,750,000 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 EPCs under dispute had no recorded book value as they were internally generated. The Balancing Pool claimed ownership of the EPCs because it believed the change-in-law provisions under the Hydro PPA required the EPCs to be passed through to the Balancing Pool. TransAlta disputed this claim. The parties have reached a confidential settlement and this matter is now resolved.

Sundance A Decommissioning

TransAlta filed an application with the Alberta Utilities Commission 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. The application is being heard in the first quarter of 2024 with a decision expected to be rendered in the third quarter of 2024.

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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 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 (loss), while any ineffective portion is recognized in net earnings (loss).

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 (loss) mark-to-market gains and losses resulting from changes in forward prices compared to the price at which these contracts were transacted. These changes in price alter the timing of earnings recognition, but do not necessarily determine the final settlement amount received. The fair value of future contracts will continue to fluctuate as market prices change. The fair value of derivatives that are not traded on an active exchange, or extend beyond the time period for

which exchange-based quotes are available, are determined using valuation techniques or models.

Cash Flow Hedges

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

Foreign currency forward contracts and cross-currency swaps 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. Interest rate swaps may be used to convert the fixed interest cash flows related to interest expense at debt to floating rates and vice versa.

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

M46 TransAlta Corporation 2023 Integrated Report

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 (loss) in the period in which the change occurs.

Fair Values

The majority of fair values for our foreign exchange, interest rate, commodity hedges and non-hedge derivatives are calculated using adjusted quoted prices from an active market or inputs validated by broker quotes. We may enter into commodity transactions involving non-standard features for which market-observable data is not available. These transactions are defined under IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable from the market and fair

value is therefore determined using valuation techniques. Fair values are validated by using reasonably possible alternative assumptions as inputs to valuation techniques and any material differences are disclosed in the notes to the consolidated financial statements.

At Dec. 31, 2023, Level III instruments had a net liabilities carrying value of $147 million (2022 – net liabilities $782 million). The Level III liabilities decreased in 2023 primarily due to market price changes and contracts settled in the year. Additionally, the long-term fixed price power sale contract in the US for delivery of power was transferred to Level II from Level III as all inputs were observable at Dec. 31, 2023. Our risk management profile has decreased in 2023 as most energy markets have moderated considerably from the extreme price and high volatility environment experienced for much of 2022. Our risk management profile and practices have not changed materially from Dec. 31, 2022.

Refer to the Material Accounting Policies and Critical Accounting Estimates section of this MD&A for further details regarding valuation techniques.

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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, 2023, 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 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, as an alternative to, 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 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

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 operational results. 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.

The following are descriptions of the adjustments made.

Adjustments to Revenue

•Certain assets that we own in Canada and in Australia are fully contracted and recorded as finance leases under IFRS. We believe that 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 are made for gains and losses related to closed positions effectively settled by offsetting positions with exchanges that have been recorded in the period the positions are settled.

Adjustments to Fuel and Purchased Power

•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 Net Other Operating Income

•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.

Adjustments to Earnings (Loss) in Addition to Interest, Taxes, Depreciation and Amortization

•Asset impairment charges and reversals are not included as these are accounting adjustments that impact depreciation and amortization and do not reflect ongoing 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 part of our regular power-generating operations, we have included our proportionate share of the adjusted EBITDA of the Skookumchuck wind facility in our total adjusted EBITDA.

M48 TransAlta Corporation 2023 Integrated Report

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 International, LLC’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 forward-looking non-IFRS financial measure that is 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 Flow from Operations

•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 are reclassified to reflect cash from operations.

•We adjust for items within the Energy Transition segment that may not be reflective of ongoing operations including certain costs related to decisions made to accelerate our transition off-coal in Alberta and our planned transition off-coal for Centralia. These are included in the "Clean energy transition provisions and adjustments" in the reconciliation.

•Cash received/paid on closed positions are reflected in the period that the position is settled.

•Other adjustments include payments/receipts for production tax credits, which are reductions to tax equity debt and include distributions from equity-accounted joint ventures.

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 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 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 are non-IFRS ratios.

Supplementary Financial Measures

The Alberta electricity portfolio metrics disclosed are supplementary financial measures used to present the gross margin by segment for the Alberta market. Refer to the Alberta Electricity Portfolio section of this MD&A for additional information.

TransAlta Corporation 2023 Integrated Report M49

Full Year 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 year ended Dec. 31, 2023:

	Hydro	Wind & Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	533	357	1,514	751	220	1	3,376	(21)	—	3,355
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	(4)	16	(67)	(5)	23	—	(37)	—	37	—
Realized gain (loss) on closed exchange positions	—	—	10	—	(91)	—	(81)	—	81	—
Decrease in finance lease receivable	—	—	55	—	—	—	55	—	(55)	—
Finance lease income	—	—	12	—	—	—	12	—	(12)	—
Unrealized foreign exchange loss on commodity	—	—	1	—	—	—	1	—	(1)	—
Adjusted revenues	529	373	1,525	746	152	1	3,326	(21)	50	3,355
Fuel and purchased power	19	30	453	557	—	1	1,060	—	—	1,060
Reclassifications and adjustments:
Australian interest income	—	—	(4)	—	—	—	(4)	—	4	—
Adjusted fuel and purchased power	19	30	449	557	—	1	1,056	—	4	1,060
Carbon compliance	—	—	112	—	—	—	112	—	—	112
Gross margin	510	343	964	189	152	—	2,158	(21)	46	2,183
OM&A	48	80	192	64	43	115	542	(3)	—	539
Taxes, other than income taxes	3	12	11	3	—	1	30	(1)	—	29
Net other operating income	—	(7)	(40)	—	—	—	(47)	—	—	(47)
Reclassifications and adjustments:
Insurance recovery	—	1	—	—	—	—	1	—	(1)	—
Adjusted net other operating income	—	(6)	(40)	—	—	—	(46)	—	(1)	(47)
Adjusted EBITDA(2)	459	257	801	122	109	(116)	1,632
Equity income										4
Finance lease income										12
Depreciation and amortization										(621)
Asset impairment reversals										48
Interest income										59
Interest expense										(281)
Foreign exchange loss										(7)
Gain on sale of assets and other										4
Earnings before income taxes										880

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)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.

M50 TransAlta Corporation 2023 Integrated Report

The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the year ended Dec. 31, 2022:

	Hydro	Wind & Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	606	303	1,209	714	160	(2)	2,990	(14)	—	2,976
Reclassifications and adjustments:
Unrealized mark-to-market loss	1	104	251	10	12	—	378	—	(378)	—
Realized gain (loss) on closed exchange positions	—	—	(4)	—	47	—	43	—	(43)	—
Decrease in finance lease receivable	—	—	46	—	—	—	46	—	(46)	—
Finance lease income	—	—	19	—	—	—	19	—	(19)	—
Unrealized foreign exchange gain on commodity	—	—	—	—	(1)	—	(1)	—	1	—
Adjusted revenues	607	407	1,521	724	218	(2)	3,475	(14)	(485)	2,976
Fuel and purchased power	22	31	641	566	—	3	1,263	—	—	1,263
Reclassifications and adjustments:
Australian interest income	—	—	(4)	—	—	—	(4)	—	4	—
Adjusted fuel and purchased power	22	31	637	566	—	3	1,259	—	4	1,263
Carbon compliance	—	1	83	(1)	—	(5)	78	—	—	78
Gross margin	585	375	801	159	218	—	2,138	(14)	(489)	1,635
OM&A	55	68	195	69	35	101	523	(2)	—	521
Taxes, other than income taxes	3	12	15	4	—	1	35	(2)	—	33
Net other operating income	—	(23)	(38)	—	—	—	(61)	3	—	(58)
Reclassifications and adjustments:
Insurance recovery	—	7	—	—	—	—	7	—	(7)	—
Adjusted net other operating income	—	(16)	(38)	—	—	—	(54)	3	(7)	(58)
Adjusted EBITDA(2)	527	311	629	86	183	(102)	1,634
Equity income										9
Finance lease income										19
Depreciation and amortization										(599)
Asset impairment charges										(9)
Interest income										24
Interest expense										(286)
Foreign exchange gain										4
Gain on sale of assets and other										52
Earnings before income taxes										353

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)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.

TransAlta Corporation 2023 Integrated Report M51

The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the year ended Dec. 31, 2021:

	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	—
Realized gain (loss) on closed exchange positions	—	—	(6)	—	29	—	23	—	(23)	—
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	1,126	728	202	4	2,791	(18)	(52)	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 writedown	—	—	—	(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	634	236	202	—	1,770	(18)	(263)	1,489
OM&A	42	59	175	117	36	84	513	(2)	—	511
Reclassifications and adjustments:
Parts and materials writedown	—	—	(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 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(2)	322	262	488	133	166	(85)	1,286
Equity income										9
Finance lease income										25
Depreciation and amortization										(529)
Asset impairment charges										(648)
Interest income										11
Interest expense										(256)
Foreign exchange gain										16
Gain on sale of assets and other										54
Loss before income taxes										(380)

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)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.

M52 TransAlta Corporation 2023 Integrated Report

Full Year 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: 

	2023	2022	2021
Cash flow from operating activities(1)	1,464	877	1,001
Change in non-cash operating working capital balances	(124)	316	(174)
Cash flow from operations before changes in working capital	1,340	1,193	827
Adjustments
Share of adjusted FFO from joint venture(1)	8	8	13
Decrease in finance lease receivable	55	46	41
Clean energy transition provisions and adjustments(2)	11	42	79
Realized gain (loss) on closed exchanged positions	(81)	37	23
Other(3)	18	20	11
FFO(4)	1,351	1,346	994
Deduct:
Sustaining capital(1)	(174)	(142)	(199)
Productivity capital	(3)	(4)	(4)
Dividends paid on preferred shares	(51)	(43)	(39)
Distributions paid to subsidiaries’ non-controlling interests	(223)	(187)	(159)
Principal payments on lease liabilities	(10)	(9)	(8)
FCF(4)	890	961	585
Weighted average number of common shares outstanding in the period	276	271	271
FFO per share(4)	4.89	4.97	3.67
FCF per share(4)	3.22	3.55	2.16

(1)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture.

(2)2023 includes amounts related to onerous contracts recognized in 2021 and a voluntary contribution to the US Defined Benefit Pension Plan for the Centralia thermal facility. During 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 to the Highvale mine pension plan. 2022 also includes amounts related to onerous contracts recognized in 2021. 2021 includes a write-down on parts and material inventory and coal inventory for our coal operations and amounts related to onerous contracts and contract termination penalties.

(3)Other consists of production tax credits, which is a reduction to tax equity debt, less distributions from equity-accounted joint venture.

(4)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.

TransAlta Corporation 2023 Integrated Report M53

The table below provides a reconciliation of our adjusted EBITDA to our FFO and FCF:

Year ended Dec. 31	2023	2022	2021
Adjusted EBITDA(1)(4)	1,632	1,634	1,286
Provisions	(1)	25	(43)
Net interest expense(2)	(164)	(200)	(200)
Current income tax expense	(50)	(65)	(56)
Realized foreign exchange loss	(4)	—	(2)
Decommissioning and restoration costs settled	(37)	(35)	(18)
Other non-cash items	(25)	(13)	27
FFO(3)(4)	1,351	1,346	994
Deduct:
Sustaining capital(4)	(174)	(142)	(199)
Productivity capital	(3)	(4)	(4)
Dividends paid on preferred shares	(51)	(43)	(39)
Distributions paid to subsidiaries’ non-controlling interests	(223)	(187)	(159)
Principal payments on lease liabilities	(10)	(9)	(8)
FCF(4)	890	961	585

(1)Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section of this MD&A and reconciled to earnings (loss) before income taxes above.

(2)Net interest expense includes interest expense for the period less interest income.

(3)These items are not defined and have no standardized meaning under IFRS. FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section of this MD&A and reconciled to cash flow from operating activities above.

(4)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture.

M54 TransAlta Corporation 2023 Integrated Report

Fourth Quarter 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 Dec. 31, 2023:

	Hydro	Wind & Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	77	94	246	175	39	—	631	(7)	—	624
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	(2)	20	53	7	(19)	—	59	—	(59)	—
Realized gain on closed exchange positions	—	—	23	—	4	—	27	—	(27)	—
Decrease in finance lease receivable	—	—	15	—	—	—	15	—	(15)	—
Finance lease income	—	—	2	—	—	—	2	—	(2)	—
Unrealized foreign exchange gain on commodity	—	—	1	—	—	—	1	—	(1)	—
Adjusted revenues	75	114	340	182	24	—	735	(7)	(104)	624
Fuel and purchased power	5	8	127	138	—	—	278	—	—	278
Reclassifications and adjustments:
Australian interest income	—	—	(1)	—	—	—	(1)	—	1	—
Adjusted fuel and purchased power	5	8	126	138	—	—	277	—	1	278
Carbon compliance	—	—	27	—	—	—	27	—	—	27
Gross margin	70	106	187	44	24	—	431	(7)	(105)	319
OM&A	13	25	56	18	10	29	151	(1)	—	150
Taxes, other than income taxes	1	1	—	—	—	1	3	—	—	3
Net other operating income	—	(3)	(10)	—	—	—	(13)	—	—	(13)
Reclassifications and adjustments:
Insurance recovery	—	1	—	—	—	—	1	—	(1)	—
Adjusted net other operating income	—	(2)	(10)	—	—	—	(12)	—	(1)	(13)
Adjusted EBITDA(2)	56	82	141	26	14	(30)	289
Equity income										3
Finance lease income										2
Depreciation and amortization										(132)
Asset impairment reversals										(26)
Interest income										12
Interest expense										(66)
Foreign exchange loss										(7)
Loss before income taxes										(35)

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)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.

TransAlta Corporation 2023 Integrated Report M55

The following table reflects adjusted EBITDA by segment and provides reconciliation to loss before income taxes for the three months ended Dec. 31, 2022:

	Hydro	Wind & Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	159	98	276	281	44	—	858	(4)	—	854
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	1	23	238	(7)	12	—	267	—	(267)	—
Realized gain on closed exchange positions	—	—	7	—	20	—	27	—	(27)	—
Decrease in finance lease receivable	—	—	12	—	—	—	12	—	(12)	—
Finance lease income	—	—	4	—	—	—	4	—	(4)	—
Unrealized foreign exchange gain on commodity	—	—	—	—	(1)	—	(1)	—	1	—
Adjusted revenues	160	121	537	274	75	—	1,167	(4)	(309)	854
Fuel and purchased power	5	11	196	234	—	—	446	—	—	446
Reclassifications and adjustments:
Australian interest income	—	—	(1)	—	—	—	(1)	—	1	—
Adjusted fuel and purchased power	5	11	195	234	—	—	445	—	1	446
Carbon compliance	—	—	27	—	—	—	27	—	—	27
Gross margin	155	110	315	40	75	—	695	(4)	(310)	381
OM&A	22	18	57	19	12	30	158	(1)	—	157
Taxes, other than income taxes	—	5	2	2	—	—	9	(1)	—	8
Net other operating income	—	(5)	(8)	—	—	—	(13)	3	—	(10)
Adjusted EBITDA(2)	133	92	264	19	63	(30)	541
Equity income										4
Finance lease income										4
Depreciation and amortization										(188)
Asset impairment charges										(5)
Interest income										10
Interest expense										(77)
Foreign exchange loss										(13)
Gain on sale of assets and other										46
Earnings before income taxes										7

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)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.

M56 TransAlta Corporation 2023 Integrated Report

Fourth Quarter 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:

Three months ended Dec. 31	2023	2022
Cash flow from operating activities(1)	310	351
Change in non-cash operating working capital balances	(135)	64
Cash flow from operations before changes in working capital	175	415
Adjustments
Share of adjusted FFO from joint venture(1)	(2)	1
Decrease in finance lease receivable	15	12
Clean energy transition provisions and adjustments(2)	4	7
Realized gain on closed exchanged positions	27	21
Other(3)	10	3
FFO(3)	229	459
Deduct:
Sustaining capital(1)	(74)	(67)
Productivity capital	(1)	(1)
Dividends paid on preferred shares	(12)	(12)
Distributions paid to subsidiaries’ non-controlling interests	(19)	(61)
Principal payments on lease liabilities	(2)	(3)
FCF(4)	121	315
Weighted average number of common shares outstanding in the period	308	269
FFO per share(4)	0.74	1.71
FCF per share(4)	0.39	1.17

(1)Includes our share of amounts for Skookumchuck, an equity-accounted joint venture.

(2)Includes amounts related to onerous contracts recognized in 2021 and a voluntary contribution to the US Defined Benefit Pension Plan for the Centralia thermal facility.

(3)Other consists of production tax credits, which is a reduction to tax equity debt, less distributions from the equity-accounted joint venture.

(4)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.

TransAlta Corporation 2023 Integrated Report M57

The table below provides a reconciliation of our adjusted EBITDA to our FFO and FCF for the three months ended Dec 31. 2023 and 2022:

Three months ended Dec. 31	2023	2022
Adjusted EBITDA(1)(4)	289	541
Provisions	(1)	20
Net interest expense(2)	(41)	(49)
Current income tax recovery (expense)	5	(29)
Realized foreign exchange gain (loss)	9	(18)
Decommissioning and restoration costs settled	(15)	(12)
Other non-cash items	(17)	6
FFO(3)(4)	229	459
Deduct:
Sustaining capital(4)	(74)	(67)
Productivity capital	(1)	(1)
Dividends paid on preferred shares	(12)	(12)
Distributions paid to subsidiaries’ non-controlling interests	(19)	(61)
Principal payments on lease liabilities	(2)	(3)
FCF(4)	121	315

(1)Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section of this MD&A and reconciled to earnings (loss) before income taxes above.

(2)Net interest expense includes interest expense for the period less interest income.

(3)These items are not defined and have no standardized meaning under IFRS. FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section of this MD&A and reconciled to cash flow from operating activities above.

(4)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture.

M58 TransAlta Corporation 2023 Integrated Report

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

Year ended Dec. 31	2023	2022	2021
Period-end long-term debt(1)	3,466	3,653	3,267
Exchangeable debentures	344	339	335
Less: Cash and cash equivalents(2)	(345)	(1,118)	(947)
Add: 50 per cent of issued preferred shares and exchangeable preferred shares(3)	671	671	671
Other(4)	(12)	(20)	(19)
Adjusted net debt(5)	4,124	3,525	3,307
Adjusted EBITDA(6)	1,632	1,634	1,286
Adjusted net debt to adjusted EBITDA (times)	2.5	2.2	2.6

(1)Consists of current and long-term portion of debt, which includes lease liabilities and tax equity financing.

(2)Cash and cash equivalents, net of bank overdraft.

(3)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 purposes of this ratio, we consider 50 per cent of issued preferred shares, including these, as debt.

(4)Includes principal portion of TransAlta OCP restricted cash ($17 million for 2023, 2022 and 2021) and fair value of hedging instruments on debt (included in risk management assets and/or liabilities on the Consolidated Statements of Financial Position).

(5)The tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in this amount. 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.

(6)Last 12 months.

The Company's capital is managed using a net debt position. We use the adjusted net debt to adjusted EBITDA ratio as a measurement of financial leverage and to assess our ability to service debt. Our target for adjusted net debt to adjusted EBITDA is 3.0 to 4.0 times. Our adjusted net debt

to adjusted EBITDA ratio for Dec. 31, 2023 was higher compared to Dec. 31, 2022, due to higher adjusted net debt resulting from lower cash and cash equivalents due to the acquisition of TransAlta Renewables, partially offset by scheduled debt repayments and a lower amount outstanding on the credit facility at the end of 2023.

2024 Outlook

For 2024, the Company expects adjusted EBITDA to be in the range of $1.15 billion to $1.3 billion and FCF to be in the range of $450 million to $600 million which is based on the following:

•Higher contribution from the wind and solar portfolio due to the full year impact of new asset additions of the Garden Plain wind facility and Northern Goldfields solar facilities, as well as the full return to service of Kent Hills wind facilities in the first quarter of 2024;

•Contributions from the addition of Mount Keith transmission;

•Contributions from the commercial operation of the White Rock and Horizon Hill wind projects which are expected in the first quarter of 2024;

•Contribution from the Heartland Generation acquisition, which is expected to close in 2024;

•Lower contributions from the legacy merchant hydro, wind and gas portfolio in Alberta which are expected to step down due to lower expected average power prices in Alberta given the baseload gas and renewables supply additions expected in 2024;

TransAlta Corporation 2023 Integrated Report M59

•Higher expected current income tax expense in 2024 in the absence of growth that could defer or partially offset the Company's tax horizon; and

•Increased net interest expense in 2024 as a result of lower interest income earned on lower cash deposits and lower capitalized interest on growth projects.

The following table outlines our expectations on key financial targets and related assumptions for 2024 and should be read in conjunction with the narrative discussion that follows and the Governance and Risk Management section of this MD&A:

Measure	2024 Target	Updated Target 2023	2023 Actuals
Adjusted EBITDA(1)(2)	$1,150 million - $1,300 million	$1,700 million - $1,800 million	$1,632 million
FCF(1)(2)	$450 million - $600 million	$850 million - $950 million	$890 million
FCF per share	$1.47 - $1.96	$2.77 - $3.10	$3.22
Dividend	$0.24 per share annualized	$0.22 per share annualized	$0.22 per share annualized

(1)These items are not defined and have no standardized meaning under IFRS. 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)During the second quarter of 2023, the Company revised and increased our 2023 guidance for adjusted EBITDA and FCF based on the strong financial performance attained in the first half of the year and our expectations for the balance of the year.

The Company's outlook for 2024 may be impacted by a number of factors as detailed further below.

Range of key 2024 power and gas price assumptions

Market	2024 Assumptions	Updated Target 2023	2023 Actuals
Alberta spot ($/MWh)	$75 to $95	$150 to $170	$134
Mid-C spot (US$/MWh)	US$85 to US$95	US$90 to US$110	US$76
AECO gas price ($/GJ)	$2.50 to $3.00	$2.50	$2.54

Alberta spot price sensitivity: a +/- $1 per MWh change in spot price is expected to have a +/-$5 million impact on adjusted EBITDA for 2024.

Other assumptions relevant to the 2024 outlook

	2024 Expectations
Energy Marketing gross margin	$110 million to $130 million
Sustaining capital	$130 million to $150 million
Corporate cash taxes	$95 million to $130 million
Cash interest	$240 million to $260 million

Alberta Hedging

Range of hedging assumptions	2024
Hedged production (GWh)	8,152
Hedge price ($/MWh)	$85
Hedged gas volumes (GJ)	62 million
Hedge gas prices ($/GJ)	$2.76

M60 TransAlta Corporation 2023 Integrated Report

Market Pricing

The following graphs include 2024 pricing based on a range of assumptions and is subject to change:

Annual Average Spot Electricity Prices

Annual Average Gas (AECO) Prices

For 2024, spot electricity prices in Alberta are expected to be lower compared to 2023, driven by normalized weather expectations and the anticipated additions of new natural gas, and wind and solar supply. Spot electricity prices in the Pacific Northwest are expected to be higher in 2024, but will depend on the actual hydrology for the region during the year.

AECO natural gas prices are expected to be comparable to 2023.

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 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 assets within the Alberta electricity portfolio are managed as a portfolio to maximize the overall value of generation and capacity from our hydro, wind, energy storage and thermal facilities. Hedging is a key component of cash flow certainty and the hedges are primarily tied to our portfolio of gas assets and opportunistically allocated to our portfolio of hydro facilities rather than a single facility.

Sustaining Capital Expenditures

Our estimate for total sustaining capital is as follows:

	Spent in 2023	Expected spend in 2024
Total sustaining capital (millions)	174	130-150

The Company expects sustaining capital to be in the range of $130 million to $150 million. The midpoint for the range represents a 10 per cent decrease from the midpoint of the 2023 outlook sustaining capital range of $140 million to $170 million, and a 20 per cent decrease from 2023 sustaining capital spend. This is driven by lower sustaining capital expenditures for planned major maintenance related to the gas assets and lower costs associated with the relocation of the Company's head office.

Liquidity and Capital Resources

We expect to maintain adequate available liquidity under our committed credit facilities. As at Dec. 31, 2023, we had access to $1.7 billion in liquidity, including $345 million in cash, net of bank overdraft; which significantly exceeds the funds required for committed growth, sustaining capital and productivity projects. .

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Material Accounting Policies and Critical Accounting Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules and guidance have changed. Accounting rules generally do not involve a selection among alternatives, but involve the 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 the Audit, Finance and Risk Committee ("AFRC") of the Board of Directors 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 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.

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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 other models such as numerical derivative valuation or scenario analysis.

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 are utilized by the Company. 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 14(I) and (II) from our consolidated financial statements for further details on the inputs used for each level.

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, 2023, is an estimated total upside of $92 million (2022 – $193 million) and total downside of $116 million (2022 – $287 million) impact to the carrying value of the financial instruments. Fair values are stressed for unobservable inputs, which can include variable volumes, unobservable prices and wind discounts, among other inputs. The variable volumes are stressed up and down based on 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. Wind discounts represent price to volume relationships and are stressed specific to each location.

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 $25 million (2022 – $25 million) potential impact to the carrying value of nil as at Dec. 31, 2023 (2022 – 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 cash-generating unit (“CGU”) to which the asset belongs. 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 recoverable amount is the higher of an asset’s fair value less costs of disposal or 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 49 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.

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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. 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 2023.

PP&E 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.

Asset Impairments

Hydro

During 2023, internal valuations indicated the fair value less costs of disposal for two hydro facilities exceeded the carrying value due to a contract extension and changes in power price assumptions, which favourably impacted estimated future cash flows and resulted in a full recoverability test. As a result of the recoverability test an impairment reversal of $10 million was recognized.

Wind and Solar

During 2023, the Company recorded a net impairment reversal of $4 million as a result of changes in power price assumptions for two wind facilities, which favourably impacted estimated future cash flows and resulted in a full recoverability test.

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 the purposes of the 2023 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 projections. In 2023, the Company relied on the recoverable amounts determined in 2022 for the Hydro and Energy Marketing segments in performing the 2023 goodwill impairment review. The recoverable amounts are based on the Company’s long-range forecasts for the periods extending to the last planned asset retirement in 2072. The resulting fair value measurement is categorized within Level III of the fair value hierarchy. We have determined there were no goodwill impairments for 2023, 2022 and 2021.

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, including 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.

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 (loss).

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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Change in Estimate - Useful Lives

During 2023, the Company adjusted the useful lives of certain assets in the Gas segment to reflect changes made based on future operating expectations of the assets. This resulted in a decrease of $92 million in depreciation expense that was recognized in the Consolidated Statement of Earnings (Loss) in 2023.

Leases

In determining whether the Company's contracts contain, or are, leases, management must use judgment to assess 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 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 remains with the Company, 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 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.

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. The defined benefit obligation has increased by $5 million to $155 million as at Dec. 31, 2023, from $150 million as at Dec. 31, 2022. A one per cent increase in discount rates would have a $40 million impact on the defined benefit obligation.

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

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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.

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.

During 2023, the decommissioning and restoration provision decreased by $89 million due to revisions in estimated cash flows and timing of cash flows for certain Gas and Energy Transition assets. The timing of cash flows was adjusted to optimize and maximize efficiencies by staging required reclamation work. Operating assets included in PP&E decreased by $34 million and $55 million was recognized as an impairment reversal in net earnings related to retired assets.

During 2023, revisions in discount rates increased the decommissioning and restoration provision by $52 million due to a decrease in discount rates, largely driven by decreases in long-term market benchmark rates. On average, discount rates decreased compared to 2022, with rates ranging from 6.0 to 9.0 per cent as at Dec. 31, 2023. This has resulted in a corresponding increase in PP&E of $31 million on operating assets and the recognition of a $21 million impairment charge in net earnings related to retired assets.

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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Accounting Changes

Current Accounting Changes

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

On May 7, 2021, the International Accounting Standards Board (“IASB”) issued Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction, which amends IAS 12 Income Taxes. 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, and were adopted by the Company on that date. The Company's accounting aligns with the amendment and no financial impact arose upon adoption.

Amendments to IAS 12 International Tax Reform — Pillar Two Model Rules

The Organization for Economic Co-operation and Development (OECD) published Pillar Two model rules in December 2021 to ensure that large multinational companies would be subject to a minimum 15 per cent tax rate. In May 2023, the IASB issued amendments to IAS 12 Income Taxes to provide companies with immediate temporary relief from accounting for deferred taxes arising from the OECD international tax reform. The amendments clarify that IAS 12 applies to income taxes arising from tax law enacted or substantively enacted to implement the Pillar Two model rules published by the OECD. Pillar Two legislation has not been enacted or substantively enacted

in any jurisdiction in which the Company operates and therefore has not been reflected within our tax provisions at Dec. 31, 2023.

Future Accounting Changes

Amendments to IAS 1 Non-current Liabilities with Covenants and Classification of Liabilities as Current or Non-current 

In October 2022, the IASB issued Non-current Liabilities with Covenants, which amends IAS 1 Presentation of Financial Statements, to clarify how conditions with which an entity must comply within 12 months after the reporting period affect the classification of a liability. In January 2020, the IASB issued Classification of Liabilities as Current or Non-current, which amends IAS 1 Presentation of Financial Statements regarding the classification of liabilities as current or non‐current, clarifying that contractual 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.

Additionally, the IASB clarified that the classification of a liability is unaffected by the likelihood that an entity will exercise its deferral right. The amendments are effective for annual periods beginning on or after Jan. 1, 2024, and are to be applied retrospectively. On Jan. 1, 2024, the Company will re-classify the Exchangeable Securities from non-current liabilities to current liabilities as the conversion option can be exercised at any time after Jan. 1, 2025, although there is no obligation to deliver cash equivalent resources and the holder cannot call for repayment. This accounting is consistent with the amendment.

Environmental, Social and Governance

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 equity, diversity and inclusion), we believe the focus will only strengthen our corporate strategy and support value creation into the future. Our pillars include:

•Clean, Reliable and Sustainable Electricity Production

•Safe, Healthy, Diverse and Engaged Workplace

•Positive Indigenous, Stakeholder and Customer Relationships

•Progressive Environmental Stewardship

•Technology and Innovation

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Reporting on Our Material Sustainability Factors

TransAlta has been reporting on sustainability since 1994. The Company's ESG reporting 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. We adopt guidance from the International Sustainability Standards Board by the International Financial Reporting Standards ("IFRS") Foundation, the International Integrated Reporting Framework, the Global Reporting Initiative ("GRI") and the Sustainability Accounting Standards Board ("SASB") requirements for electric utilities and power generators. We continue to monitor the development of sustainability and climate-related disclosure requirements to assess our future reporting, such as the proposed climate-related disclosure rules by the Canadian Securities Administrators, the US Securities and Exchange Commission and the Australian government.

Since 2007, TransAlta's material sustainability data to be disclosed has received limited assurance from independent third-party providers. Climate-related data to be disclosed is informed by the IFRS S2 Climate-related Disclosures Standard launched in 2023, in alignment with the recommendations of the Task Force on Climate-related Financial Disclosures ("TCFD"). In 2024, TransAlta will continue to focus on our alignment with the IFRS S2 requirements. As a result, we no longer expect to respond to climate change questionnaires from CDP (the global disclosure system for environmental impacts known formerly as the Carbon Disclosure Project). We will continue to monitor its future guidance for the purpose of continuous improvement of our voluntary climate-related disclosures.

In 2023, we reviewed and updated our management response to our 2021 climate-related scenario analysis that enhanced our alignment with both international sustainability frameworks. We also reviewed and updated our Climate Transition Plan and climate-related financial metrics. GHG emissions data for scopes 1 and 2 follow the accounting and reporting standards of the GHG Protocol. We continue to make advancements in our scope 3 accounting for future reporting in alignment with the GHG Protocol. For further information on climate change management and the findings of our scenario analysis, refer to the Decarbonizing Our Energy Mix section of this MD&A.

The disclosure of our most relevant sustainability factors remained in 2023 and is guided by our sustainability materiality assessment. In 2022, we refreshed our materiality assessment by evaluating key sector-specific research on material issues, supported by internal and external engagement on key sustainability issues. Our Enterprise Risk Management ("ERM") program is designed to help the Company focus its efforts on key enterprise risks, within the planning horizon, that could significantly impact the success of our strategy, including our sustainability objectives. We consider a sustainability factor as material if it could substantively affect our ability to create value.

In addition, we reviewed key topics identified within SASB, TCFD, IFRS and the Taskforce on Nature-related Financial Disclosures to inform the identification of our material sustainability factors. We also considered sustainability factors from the electricity sector through Electricity Canada’s 2021 Sustainable Electricity Report and conducted a peer review of material sustainability factors. This work was validated by our executive team and resulted in the identification of 21 material sustainability factors presented in the Sustainability Governance section of this MD&A.

For further guidance on our risk factors, refer to the Governance and Risk Management section of this MD&A.

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Accelerating Our Business Transformation with a Target to Become Net-Zero by 2045

At TransAlta, our mission is to provide safe, low-cost and reliable clean electricity to our customers. As a customer-centred clean electricity 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 that we are uniquely positioned as the world continues to electrify and adopt sustainability practices. For further information, refer to the Description of the Business section of this MD&A.

Our President and Chief Executive Officer, John Kousinioris, speaks about our decarbonization journey below.

What role do you see natural gas generation having in a successful energy transition?

“We believe that there are three factors that must be balanced to ensure a successful energy transition: reliability, decarbonization and affordability. We continue to see a role in natural gas-fired generation enabling the energy transition by ensuring the reliability of the electricity grid. Today, our gas fleet, to be strengthened following closing of the Heartland Generation acquisition, includes peaking and baseload generation, which underpin the reliability needs of our grid, as well as cogeneration facilities, which serve customers critical to the industrial sectors of our three core markets. We also work closely with our industrial customers to support their decarbonization goals. For example, we recently achieved commercial operation for the Northern Goldfield solar and battery storage project for BHP Nickel West in Western Australia that is expected to reduce BHP's scope 2 GHG emissions.”

Following closing of the Heartland Generation acquisition, will TransAlta still be able to achieve its 2026 decarbonization target?

“Our commitment to decarbonization remains unchanged. TransAlta’s target of a 75 per cent scope 1 and 2 GHG emissions reduction by 2026 is estimated to align with the Paris Agreement goal to limit global warming to 1.5°C and is based on our 2015 scope 1 and 2 GHG emissions of 32.2 MT CO2e. The acquisition of the Heartland Generation portfolio is aligned with our decarbonization commitment. We will recalculate our 2015 emission baseline to include emissions from Heartland Generation and expect this

transaction will continue to enable us to reduce our emissions in the short term and to be carbon net-zero by 2045.

We remain committed to investing in climate change mitigation solutions to maximize value for our shareholders, customers, local communities and the environment.”

For further information, refer to Climate Change Metrics and Targets in the Decarbonizing Our Energy Mix section of this MD&A.

TransAlta has adopted a 2045 net-zero target. How will the Company achieve this target?

"Our net-zero target is a testament of our growth strategy. We are using the cash flows from our legacy thermal generation assets to fund our transition to a generating fleet focused on renewables and storage by creating electricity solutions for our industrial and commercial customers. In 2023, we revised our Clean Electricity Growth Plan, which targets growing the Company’s generation fleet by an incremental 1.75 GW — with approximately $3.5 billion of capital expenditure — as well as increasing our development pipeline of projects to 10 GW, each to be achieved by 2028. Our investment focus to 2028 will be on renewables and storage assets, responsive and flexible generation to support reliability, and advancing new technological solutions."

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Our 2023 Sustainability Performance

In 2023, TransAlta's strong safety performance was a key accomplishment amongst our social performance metrics. Our Total Safety Report Frequency and Total Recordable Injury Frequency ("TRIF") exceeded our performance targets.

Performance against our 2023 sustainability targets is outlined below. Target year means by Dec. 31 of that year.

ESG Alignment: Environmental

Sustainability goal	Sustainability target	Results	Comments
Reduce GHG emissions	By 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from 2015 base year(1)	On track	Since 2015, we have reduced scope 1 and 2 GHG emissions by 21.3 MT CO2e or 66 per cent
	By 2045, achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions(2)	On track
	By 2024, verify and disclose 80 per cent of TransAlta’s scope 3 emissions(3)	On track	We completed a pre-assessment of 80 per cent of TransAlta’s scope 3 emissions to prepare for limited assurance in 2024
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	Achieved	Our total air emissions in 2023 retained similar performance to 2022 levels. We achieved this target in 2022 through the reduction of our SO2 emissions by 98 per cent and NOx emissions by 83 per cent from 2005 levels
Reclaim land utilized for mining	By 2040, complete full reclamation of our Centralia coal mine in Washington State	On track	Reclamation work at Centralia is underway and 40 per cent of the coal mine land has been reclaimed
	By 2046, complete full reclamation of our Highvale coal mine in Alberta	On track	Our Highvale coal mine in Alberta closed in 2021. Reclamation work is underway and 22 per cent of the coal mine land has been reclaimed
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	Achieved in 2022	Water consumption increased to 30 million m3 in 2023 primarily due to an increase in production compared to last year. We achieved this target in 2022 through the reduction of our fleet-wide water consumption by approximately 20 million m3 or 43 per cent from 2015 levels
Protecting nature and biodiversity	By 2024, assess and disclose nature-related risks and opportunities including TransAlta’s dependencies and impacts on ecosystems, land, water and air	On track	Assessment of nature-related risks and opportunities is underway
	Achieve zero biodiversity-related incidents(4)	Achieved	We recorded zero (0) biodiversity-related incidents

(1)TransAlta does not plan to use carbon credits to achieve its 2026 GHG emissions reduction target.

(2)The Company may choose to neutralize residual emissions from gas-fired generation through fuel switching, new technologies or nature-based solutions to achieve its 2045 net-zero target. For further information, refer to Climate Transition Plan in the Decarbonizing Our Energy Mix section of this MD&A.

(3)To calculate TransAlta's scope 3 GHG emissions, we rely on third-party data that is available only after the first quarter of each year. As a result, this target means reporting on 2023 scope 3 GHG emissions data in 2025 following the verification of data by independent third-party providers in 2024.

(4)This means biodiversity-related incidents that affected habitats and species included on the Red List of the International Union for Conservation of Nature and are classified as near-threatened, vulnerable, endangered and critically endangered.

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ESG Alignment: Social

Sustainability goal	Sustainability target	Results	Comments
Reduce safety incidents	Achieve a Total Recordable Injury Frequency rate below 0.32	Achieved	We achieved a TRIF rate of 0.30 compared to 0.39 in 2022. Our strong safety performance can be attributed to our focus on maturing our safety culture, reducing hazards, assessing and addressing risk tolerance and standardizing safety information and data collection technology
Integrate sustainability into supply chain	By 2024, 80 per cent of our spend will be with suppliers that have a sustainability policy or commitment	On track	On average, 78 per cent of our spend in 2022 and 2023 was with suppliers that have a sustainability policy or commitment
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 represented a total value of $453,000, or 14 per cent of TransAlta’s total community investment
	Provide Indigenous cultural awareness training to all TransAlta employees by the end of 2023	Achieved	We provided Indigenous awareness training to all Canadian, Australian and US employees

ESG Alignment: Governance

Sustainability goal	Sustainability target	Results	Comments
Strengthen gender equality	Achieve 50 per cent female representation on the Board by 2030	On track	As at Dec. 31, 2023, women represented 46 per cent of our Board composition compared to 36 per cent in 2022(1)
	Achieve at least 40 per cent female employment among all employees of the Company by 2030	On track	As at Dec. 31, 2023, women represented 27 per cent of all employees, an increase over 2022 levels (26 per cent)
	Maintain equal pay for women in equivalent roles as men	Achieved	We achieved a 97 per cent female/male pay equity ratio. We strive to maintain this ratio within a deviation of plus or minus three per cent
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	TransAlta's MSCI ESG Rating was upgraded to 'AA' from 'A'. The upgrade reflects the Company's strong renewable energy growth compared to peers. We also received an award for best ESG reporting (mid-cap) by the IR Magazine Canada. In 2023, TransAlta demonstrated some of the most comprehensive disclosures among utilities companies assessed in the inaugural Climate Engagement Canada Net Zero Benchmark, which evaluates corporate issuers’ progress towards aligning with the Paris Agreement’s goals

(1)Board composition includes all independent and non-independent directors.

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ESG Alignment: Environmental and Social

Sustainability goal	Sustainability target	Results	Comments
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	On track	We retired 670 MW of Centralia at Dec. 31, 2020. In 2021, we retired or converted all coal plants in Canada and closed the Highvale coal mine, thus ceasing all coal generation in Canada. Our remaining Centralia plant in the US is set to retire on Dec. 31, 2025
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	On track	Since 2021, we have added over 800 MW of new capacity through renewable projects such as Windrise (206 MW), Garden Plain (130 MW), Northern Goldfields Solar (48 MW), White Rock (300 MW) and Horizon Hill (200 MW). We also acquired TransAlta Renewables (1.2 GW) in 2023 and North Carolina Solar (122 MW) in 2021. In 2023, our Clean Electricity Growth Plan was updated to continue our priorities. By 2028, the plan will see the Company execute on an incremental 1.75 GW of renewables growth and a 10 GW growth pipeline

2024+ Sustainability Targets 

Our 2024 and longer-term sustainability targets support the 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 manage current and emerging material sustainability issues in support of the United Nations Sustainable Development Goals ("UN SDGs") and the Future-Fit Business Benchmark, which also defines sustainable goals for businesses. TransAlta is committed to decarbonizing our energy generation and accelerating clean energy growth. We believe that we can make a greater positive impact on UN SDG 7 “Affordable and Clean Energy” and SDG 13 “Climate Action”, while supporting seven other SDGs.

Our 2024 and long-term sustainability targets reflect on incremental change from the sustainability targets set in 2023. Specifically, TransAlta updated two sustainability targets in the areas of safety and Indigenous cultural awareness, while maintaining our climate-related targets to achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions by 2045 and to reduce 75 per cent of our scope 1 and 2 GHG emissions by 2026 from a 2015 base year. This target covers 100 per cent of TransAlta's operating assets and is estimated to align with the electricity sector decarbonization pathway to limit global warming to 1.5°C, as one of the Paris Agreement goals.

In 2024, we will continue to review setting new environmental targets for GHG emissions, air emissions and water consumption consistent with our commitment to continuously improve our environmental performance.

Targets are outlined below. Target year means by Dec. 31 of that year.

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ESG Alignment: Environmental

Sustainability goal	Sustainability target	Alignment with UN SDG Target or Future-Fit Business Benchmark
Reduce GHG emissions	By 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from 2015 base year(1)	UN SDG Target 13.2: "Integrate climate change measures into national policies, strategies and planning"
	By 2045, achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions(2)
	By 2024, verify and disclose 80 per cent of TransAlta’s scope 3 emissions(3)
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"
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"
Protecting nature and biodiversity	By 2024, assess and disclose nature-related risks and opportunities including TransAlta’s dependencies and impacts on ecosystems, land, water and air	UN SDG Target 15.5: "Take urgent and significant action to reduce the degradation of natural habitats, halt the loss of biodiversity and, by 2020, protect and prevent the extinction of threatened species”
	Achieve zero biodiversity-related incidents(4)

(1)TransAlta does not plan to use carbon credits to achieve its 2026 GHG emissions reduction target.

(2)The Company may choose to neutralize residual emissions from gas-fired generation through fuel switching, new technologies or nature-based solutions to achieve its 2045 net-zero target. For further information, refer to Climate Transition Plan in the Decarbonizing Our Energy Mix section of this MD&A.

(3)To calculate TransAlta's scope 3 GHG emissions, we rely on third-party data that is available only after the first quarter of each year. As a result, this target means reporting on 2023 scope 3 GHG emissions data in 2025 following the verification of data by independent third-party providers in 2024.

(4)This means biodiversity-related incidents that affected habitats and species included on the Red List of the International Union for Conservation of Nature and are classified as near-threatened, vulnerable, endangered and critically endangered.

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ESG Alignment: Social

Sustainability goal	Sustainability target	Alignment with UN SDG Target or Future-Fit Business Benchmark
Reduce safety incidents	Achieve a Total Recordable Injury Frequency rate below 0.32 with a goal of 0.00	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"
Integrate sustainability into supply chain	By 2024, 80 per cent of our spend will be with suppliers that have a sustainability policy or commitment	UN SDG Target 12.7: “Promote public procurement practices that are sustainable, in accordance with national policies and priorities”
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 during the onboarding of all new TransAlta employees	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"

ESG Alignment: Governance

Sustainability goal	Sustainability target	Alignment with UN SDG Target or Future-Fit Business Benchmark
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: Environmental and Social

Sustainability goal	Sustainability target	Alignment with UN SDG Target or Future-Fit Business Benchmark
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"

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Decarbonizing Our Energy Mix

ESG is more than 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 journey began 112 years ago when we built the first hydro assets in Alberta, which still operate today. In 1993, we began operating our first wind facility, which was the first commercial wind facility in Canada; in 2014, acquired our first solar facility; and, in 2020, constructed our first battery storage facility. Today, we operate 57 renewable facilities across Canada, the US and Australia.

Our reporting on climate change management has been guided by the TCFD recommendations since 2018. In 2023, we adopted guidance from IFRS S2, which is based on the TCFD recommendations with industry-specific climate metrics based on the SASB standards. IFRS S2 and TCFD help inform discussion and provide context on how climate change affects our business.

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 scenarios.

TransAlta remains committed to creating a path to resiliency in a decarbonizing world in support of the goals adopted under the Paris Agreement, and the goals adopted during subsequent international climate meetings. Our strategy is focused on the operation of our existing assets (wind, hydro, solar, natural gas, battery storage and transition-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 renewable 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 2023, we grew our nameplate renewables capacity from approximately 900

MW to over 2,900 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 that 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. Furthermore, 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 and evaluate the role of natural gas to provide increased reliability and flexibility.

In 2020, we launched WindCharger, a "first-of-its-kind in Alberta" battery storage project that stores energy produced by our Summerview II wind facility and discharges electricity onto the Alberta grid during system supply shortages, as well as providing critical system support services to the system operator. This project received co-funding from Emissions Reduction Alberta. Further, in 2021, we agreed to provide solar electricity supported with a battery energy storage system to BHP Nickel West through the construction of the Northern Goldfields hybrid solar project in Western Australia. The Northern Goldfields solar and battery storage facilities were commissioned in 2023 and are expected to reduce BHP's scope 2 GHG emissions at its Nickel West operations by 12 per cent. In 2022, TransAlta entered into an agreement for the expansion of the Mount Keith 132kV transmission system. The expansion is underway, with expected completion in the first quarter of 2024. In 2023, TransAlta’s early-stage development pipeline included in excess of 1 GW from four energy storage projects in Canada.

In support of our own path to build resilience to climate change, 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. This target covers 100 per cent of TransAlta's operating assets and is estimated to align with the electricity sector decarbonization pathway to limit global warming to 1.5°C, as one of the Paris Agreement goals. Furthermore, we adopted a long-term climate-related target to achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions by 2045. This ambitious target aligns us with the Canadian Net-Zero Emissions Accountability Act to achieve net-zero emissions by 2050.

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We are also taking strategic steps to decarbonize the power sector and support the energy transition. In 2021, we set out clear targets under the Clean Electricity Growth Plan. Since 2021, the Company added 800 MW of new capacity and acquired TransAlta Renewables (1.2 GW) and North Carolina Solar (122 MW). In 2023, our Clean Electricity Growth Plan was updated to continue our priorities. By 2028, the plan will see the Company execute on an incremental 1.75 GW of renewables growth and a 10 GW growth pipeline. In 2025, we will retire our single remaining coal unit, located in the US, to complete TransAlta's transition away from coal generation.

To date, we have retired 4,664 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to natural gas. Comparatively, our converted natural gas units' CO2 intensity is approximately 57 per cent less than coal generation. 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 contribute to the goals of the Powering Past Coal Alliance, which TransAlta joined in 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 dispatchable 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 Transition Plan

A climate-related transition plan describes how a company aims to minimize climate-related risks and increase opportunities, in alignment with IFRS S2 and TCFD. In 2023, TransAlta reviewed and updated its Climate Transition Plan, which lays out our approach to reducing operational and value chain emissions to deliver net-zero operations by 2045. In addition, our Climate Transition Plan includes sustainable finance and inclusive transition actions reflecting TransAlta's commitment to a successful transition toward a low-carbon economy. For further information, refer to Sustainable Finance in the Decarbonizing Our Energy Mix section of this MD&A and Inclusive Transition in the Engaging with Our Stakeholders to Create Positive Relationships section of this MD&A.

Our Climate Transition Plan defines TransAlta's past, short-term (2024-2025) and medium- to long-term actions (beyond 2026). For each of these actions, we assessed our ability to control ("C") intended outcomes, partner ("P") with stakeholders to drive outcomes or influence ("I") outcomes that will help us achieve our decarbonization targets.

The highest level of climate change oversight, including the actions of our Climate Transition Plan, is at the Board level. For further information, refer to Oversight by the Board of Directors in the Climate Change Governance section of this MD&A. Information on executive compensation linked to climate-related targets is described in ESG-Linked Compensation in the Building a Diverse and Inclusive Workforce section of this MD&A. Metrics and targets supporting our Climate Transition Plan, including climate-related financial metrics, are described in Climate Change Metrics and Targets in the Decarbonizing Our Energy Mix section of this MD&A.

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Delivering Net-Zero Operations by 2045

	Past actions	Short-term actions (2024-2025)	Medium to long-term actions (2026 +)
Hydro	Became the largest producer of hydro power in Alberta (C)	Advance 1500 MW of early-stage wind and solar projects in all jurisdictions (C) Complete development and commence construction on 100 MW wind project in Canada (C)	Deliver an incremental 1.75 GW of clean electricity capacity by 2028 (C) Deploy approximately $3.5 billion of growth capital by 2028 (C) Expand our growth pipeline to 10 GW by 2028 with focus on renewables and storage (C)
Wind and Solar	From 2000 to 2023, we grew our nameplate renewables capacity by approximately 2,000 MW (C)
Battery Storage	First battery storage facility delivered in 2020 (C) In 2023, completed the construction of a 48 MW solar and battery storage system in Australia (C)	Complete development and commence construction on 180 MW battery storage in Canada (C) Evaluate and deploy battery storage alongside renewable facilities where appropriate (C)
Natural Gas	Completed our coal-to-gas conversions in Canada in 2021 (C) Converted 1,659 MW from coal to natural gas since 2018 (C)	Operate simple-cycle, combined-cycle and cogeneration facilities in Canada, the United States and Australia (C) Assess deployment of nature-based or engineered solutions to neutralize unabated gas-fired generation where appropriate (C) Evaluate use of renewable and low-carbon natural gas (C)	Neutralize residual emissions from gas-fired generation through fuel switching, new technologies or nature-based solutions (C)
Emerging Abatement Technologies and Solutions	Started exploring new technologies such as storage, hydrogen and carbon capture (P) In 2023, continued to support the development of low-cost, low-emissions hydrogen production through $2 million investment in a Canadian-based venture (P) In 2023, started partnership with leading global companies to target early-stage revolutionary technologies through a US$25 million investment in a deep decarbonization fund (P) In 2023, started an electric vehicle pilot project in our hydro operations (C)	Identify the next generation of power solutions and technologies and potential for parallel investments in new complementary sectors by the end of 2025 (P) Assess ways to support customers with broader decarbonization technologies beyond electrification (P) Identify opportunities to partner, pilot and deploy novel, net-zero generation technologies (P) Assess and deploy GHG removal technologies where appropriate (C) Evaluate the electrification of our vehicle fleet (C)	Deploy new net-zero generation technologies and solutions where appropriate (C) Choose materials, products and processes that generate fewer GHG emissions, mainly through energy savings (C) Evaluate the electrification of our vehicle fleet (C)
Energy Transition (Coal)	Retired 4,664 MW of coal-fired generation capacity since 2018 including ending coal generation in Canada in 2021 (C)	Continue to execute reclamation work at our coal mines (C) Contribute to a circular economy through mining waste reuse or by-product sales (C)	Cease coal generation by 2026 (C) Complete full reclamation in Washington State by 2040 and in Alberta by 2046 (C)

Legend: (C) Control intended outcomes, (P) partner with stakeholders to drive outcomes, and (I) influence outcomes that will help us achieve our decarbonization targets.

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Delivering Net-Zero Operations by 2045 (Continued)

	Past actions	Short-term actions (2024-2025)	Medium to long-term actions (2026 +)
Supply Chain	Enhanced supplier management functionality within the corporate procurement system (C)	Develop ESG criteria for supply chain engagement (C) Understand direct suppliers, GHG emissions profile and targets (C) Incorporate ESG data reporting capability in corporate procurement system (C)	Engage with suppliers to explore enhancement of their GHG emissions reduction targets (I) Set direction for engaging suppliers with GHG emissions reduction targets (C)
Value Chain	Disclosed range of scope 3 GHG emissions at company level (C)	Update scope 3 GHG emissions reporting methodology (C) Verify and disclose 80 per cent of our total scope 3 emissions (C)	Consider scope 3 GHG emissions targets (C)
Sustainable Finance	In 2021, converted existing $1.3 billion loan into a Sustainability-Linked Loan aligned with GHG emissions reduction and female employment targets at the company level (C) In 2021, secured $173 million green bond financing for eligible wind project in Alberta (C) In 2022, issued US$400 million Senior Green Bonds for eligible renewable energy and energy-efficiency projects (C) Linked ESG performance to employees’ and executive remuneration (C)	Continue to evaluate the use of sustainable or green financing instruments to fund renewable energy and battery storage projects (C) Link ESG performance to employees’ and executive remuneration (C)	Continue to evaluate the use of sustainable or green financing instruments to grow our renewables and storage capacity (C) Link ESG performance to employees’ and executive remuneration (C)
Inclusive Transition	Developed a five-year Equity, Diversity and Inclusion (ED&I) strategy (C) Conducted ED&I census to help drive a greater sense of belonging for all employees (C) Set employee engagement and ED&I targets as part of ESG-linked compensation (C) In 2023, launched two employee resource groups (C) In 2023, provided Indigenous cultural awareness training to all employees (C) In 2015, announced community investment of US$55 million over 10 years to support energy efficiency, economic and community development and education and retraining initiatives in Washington State (P) In 2016, agreed to invest in the communities impacted by the phase-out of coal generation in Alberta (P)	Expand number of employee resource groups available (C) Adapt workplaces to incorporate structural changes for inclusive work environments (C) Deliver year-round ED&I learning and awareness, and celebration campaigns (C) Continue energy transition investment in Washington State communities of up to US$55 million by 2025 (P) Continue to invest in the communities impacted by the phase-out of coal generation in Alberta (P) Strengthen Indigenous relations focused on community engagement and consultation, community investment and partnership opportunities (P) Promote supplier diversity in our operations (C)	Enhance recruitment and retention of female employees to achieve gender-based targets (C) Maintain succession practices to increase female representation at senior management level (C) Increase female representation in Generation by encouraging women to pursue a career in electricity (C) Enhance opportunities for diverse suppliers in our procurement processes (C) Continue to enhance our Indigenous relations focused on partnership opportunities with local communities (P) Ongoing support to local community organizations aligned with our community investment pillars where we operate and grow communities (P)

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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 emissions 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”) of the Board.

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 business. The GSSC then supports the Board in assessing and overseeing Company-wide climate change strategies, policies and practices. The GSSC also reviews environmental protection guidelines, including with respect to 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 considers climate risks and opportunities as it relates to our 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 investment 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.

The Board reviews and updates the Company's strategy annually. In 2023, the Board's strategic planning sessions included climate-related issues considering growth

initiatives and strategies, capital allocation, ESG policy development and other matters. Our Board is composed of individuals with a mix of skills, knowledge and experience critical to our strategy success and business growth. In 2023, three of our 13 Board members identified environment/climate change among their top four relevant competencies. Given the breadth of experience and skills of each director, the skills matrix lists only the top four competencies possessed by each director nominee based on the Board’s assessment and each director’s self-evaluation. The criteria used to assess competence of Board members on climate-related issues includes the knowledge of corporate responsibility practices and the constituents involved in sustainable development practices, including as it pertains to climate change.

For further information regarding Board members competence on climate-related issues, refer to TransAlta's Management Proxy Circular.

Role of Senior Management

TransAlta’s President and CEO maintains the highest level of oversight on climate-related issues at the executive level. Senior management of the Company, including our President and CEO, provide the Board with updates on climate-related risks and opportunities to inform business strategy and ensure alignment with TransAlta’s GHG emissions reduction goals.

Our business units and corporate functions work closely together to support the executive team in understanding climate-related risks and opportunities, including legislative developments. Our executive team reviews such risks and opportunities quarterly and reports to the GSSC and AFRC, as applicable.

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 annual incentive plans (short-term incentive and long-term incentives) to 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, refer to the discussion on ESG-Linked Compensation in Building a Diverse and Inclusive Workforce section of this MD&A.

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Climate Scenarios

In 2021, we conducted climate scenario analysis to understand risks and opportunities and assess our strategy's resiliency under several potential 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 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.

In 2023, we reviewed the findings from the climate scenario analysis and updated the management response accordingly.

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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 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. In Canada, it is expected that major grid decarbonization investments will flow into Alberta as most other provincial markets 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.	Demand for power from natural gas declines as the market shifts towards cleaner power with gas shifting to a reliability backstop role. An additional decline from Canadian oil and 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. 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.	Carbon price increases the cost of natural gas operations. Additional mandated emissions 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 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.

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	Increased competition	Decreased demand of natural gas electricity	Increased operational costs
NZE	By 2040, renewables are expected to comprise over 85 per cent of the total electricity generation in the regions we operate. This surge in renewables will increase competition and drive electricity pricing down depending on availability and the cost of energy storage. 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 in which 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.
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 a 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 in which 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.
Management Response	Navigating the uncertainty around market dynamics (structure, pricing and competition), government policies and planning is critical for TransAlta. We use hedging and PPAs to stabilize pricing and are planning on leading clean energy growth in the regions in which we operate. See more details of our strategy and risk management under the Climate Strategy section and the Managing Climate Change Risks and Opportunities section of this MD&A.	Optimize gas assets to maximize value and cash flows to support renewables and storage growth. Our converted natural gas units' CO2 intensity is approximately 57 per cent less than coal generation. 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 the end of 2025 we will have achieved a 100 per cent portfolio mix of renewables and natural gas.	We have taken significant steps to reduce our carbon footprint. Since 2015, we have reduced scope 1 and 2 GHG emissions by 66 per cent. By 2026, we have a commitment to reduce scope 1 and 2 GHG emissions by 75 per cent from 2015 base year and plan to achieve net-zero emissions by 2045. 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.

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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 types 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 especially anticipated to play an important role in the energy transition. Cost-competitive battery storage enables greater adoption of renewables.
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 in which 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 in which 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 in which 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 in which we operate by 2040. An 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 years ago when we built the first hydro assets in Alberta, which still operate today. We now operate 57 renewable facilities across Canada, the US and Australia. By the end of 2028, 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 responsive and flexible natural gas generation for reliability. Our investments and growth in renewable energy are highlighted by our portfolio of renewable energy-generating assets. From 2000 to 2023, we grew our nameplate renewables capacity from approximately 900 MW to over 2,900 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.	To leverage this opportunity and combat the challenges of renewable energy intermittency, we continue to invest in battery storage. In 2020, we launched WindCharger, a "first of its kind in Alberta" 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 Nickel West through the construction of the Northern Goldfields solar project in Western Australia. This project was completed in November 2023 and will support BHP in meeting its emissions reduction targets and delivering lower-carbon, sustainable nickel to its customers. In 2023, TransAlta’s early-stage development pipeline included four energy storage projects in Canada with a total capacity in excess of 1 GW.

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NZE: The most significant risks include increased competition, decreased demand for natural gas and increased operational costs due to increased carbon pricing and emissions 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, 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. 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's strategy and financial planning, risk management, opportunity assessment and planning for uncertainty.

Managing Climate Change Risks and Opportunities

We actively monitor and manage climate-related risks through our Company-wide ERM 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 Reporting in the Governance and Risk Management section of this MD&A.

We divide our climate change risks into two major categories as per IFRS S2 and TCFD guidance: (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, 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.

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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, subject to the federal government's authority to set national carbon pricing standards. 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. Further, we continue to see strong private sector demand for contracted zero emissions generation to meet corporate sustainability goals.

•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 electricity generation.

Management Response

•TransAlta’s Clean Electricity Growth Plan positions our company to meet the rapidly growing demand for clean electricity generation driven by customers and government policy.

•We are 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 energy tax legislation and programs to maximize, wherever possible, access to project incentives.

•Our clean and contracted growth reduces the proportional Company exposure to potential policy and regulatory decisions that negatively impact natural gas generation.

•Our coal-to-gas facilities fit within government plans to continue providing reliable and competitively priced electricity for consumers and industry.

•Our remaining natural gas facilities (non-coal-to-gas) 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, both directly and through industry associations, to encourage governments to adopt a level playing field within funding and crediting programs so that all new emerging technology projects receive equitable government 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 and energy storage.

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 (refer to Management Response below).

•Significant new federal incentives for clean energy could increase competition in the renewables and energy storage space.

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Opportunities

•Achieving government climate goals and private sector sustainability commitments will require rapid and sustained growth in zero-emissions electricity generation over the coming decades. TransAlta’s Clean Electricity Growth Plan is focused on providing renewable electricity to contracted customers in a manner that aligned with federal, state and private sector goals.

•US tax incentive programs offer significant support for new renewable and energy storage 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 any carbon regulation 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 Australian Government has a 43 per cent national emissions reduction target over 2005 levels by 2030 and a goal to achieve a net-zero national economy by 2050. Decarbonization efforts have been centered on funding for clean technologies, upgrading the electricity grid to support more renewables, regulating and reporting of GHG emissions, and incentivizing zero-emissions vehicle adoption. Large GHG emitters are required to reduce their scope 1 emissions under the Australian Government's National Safeguard Mechanism ("SGM"). While the government has made recent changes to the SGM, these changes are not expected to have a material impact on TransAlta's assets. 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 (refer to Management Response below).

Opportunities

•Our Clean Electricity Growth Plan is focused on building new, clean electricity generation in Australia and other markets. Government policies and funding programs are generally supportive of the types of projects contemplated within TransAlta’s strategy.

•Strong corporate demand for clean electricity solutions in Australia's natural resource sectors present opportunities for TransAlta to leverage its existing expertise to help customers meet regulatory requirements and reach their decarbonization objectives.

Management Response

•Through our Clean Electricity Growth Plan, TransAlta continues to deliver clean electricity solutions to natural resource customers in Western Australia. Our growing suite of technologies, including renewables and energy storage, positions us to provide contracted solutions to customers focused on the need for reliable and sustainable energy.

•TransAlta also continues to assess opportunities to grow our clean energy generation in alignment with Australia's national and state climate goals.

•TransAlta’s assets are predominantly contracted with an ability to pass through carbon compliance costs 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 Energy Innovation team and our ERM process. Examples of technology risks and opportunities include infrastructure changes (such as the shift to distributed energy 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 facilities in Southern Alberta. In 2023, we delivered 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 will continue monitoring new technologies such as storage, hydrogen and CCUS for future deployment.

For further information on technology and innovation, refer to the Enabling Innovation and Technology Adoption section of this MD&A.

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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 30 renewable projects that are either under construction or in the development stage. We are committed to growing our clean energy fleet. Further, we established Canadian, US and Australian clean energy growth teams. In 2023, the Company established a pipeline of potential growth projects in renewables that includes 280 MW of advanced-stage development projects along with 4,285 to 5,015 MW of projects in earlier stages of development. 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 clear transition path away from coal mitigates this reputational risk. As consumer trends move in favour of renewable 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 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. We continue to investigate the physical impacts of climate change on our operating assets.

Acute Physical Risks

We have operating assets in three countries and varied geographic locations, many of which could be impacted by extreme weather events. We continuously evaluate 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. In Canada, since the 2013 floods in Southern Alberta, we have implemented projects that increase the resilience of our hydro facilities to severe climate events. We have also modified operations at several of our facilities as per an agreement with the Government of Alberta. This reduces flood risk in the spring while also recognizing the potential for increased droughts as a result of climate change in the future. TransAlta continues to participate in multi-stakeholder groups developing options for climate resiliency across Southern Alberta.

For further information on weather-related risks, refer to Weather in the Progressive Environmental Stewardship section of this MD&A.

Chronic Physical Risks

We continuously investigate the physical impacts of longer-term shifts in climate patterns 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 established our climate-related goals and targets with reference to the UN SDGs. Over time, we have set ourselves apart with actions that demonstrate climate change leadership.

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Progress towards our climate-related targets are presented below. As a result of our Clean Electricity Growth Plan being updated in November 2023, the below performance is assessed against our prior Clean Electricity Growth Plan announced in 2021.

Clean energy growth
Sustainability Target	Develop new renewable projects that support our customers' sustainability goals to achieve both long-term power price affordability and carbon reductions.(1)	No further coal generation; 100 per cent of our owned net generation capacity from renewables and gas.
Target Year	2025	2025
Progress	Renewables Growth	Net Generation Capacity (renewable and gas)
Notes	Since 2021, we have added over 800 MW of new capacity through renewable projects such as Windrise (206 MW), Garden Plain (130 MW), Northern Goldfields Solar (48 MW), White Rock (300 MW) and Horizon Hill (200 MW). In November 2023, our Clean Electricity Growth Plan was updated to continue our priorities. By 2028, the plan will see the Company execute on an incremental 1.75 GW of renewables growth and a 10 GW growth pipeline.	In 2023, our owned net generation capacity from renewables and gas represented approximately 90 per cent of our total 6,425 MW owned net generation capacity. In 2021, we achieved full phase-out of coal in Canada. In the US, the remaining unit at Centralia is set to retire on Dec. 31, 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”.

(1)This includes the construction of new renewable projects (hydro, wind and solar) as part of the Company's Clean Electricity Growth Plan. This excludes acquisitions.

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Emissions reduction
Sustainability Target	By 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from a 2015 base year.	By 2045, achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions.
Target Year	2026	2045
Progress	GHG Emissions Reduction	GHG Emission (million tonnes CO2e)
Notes	We are well on track to achieve our target of 75 per cent scope 1 and 2 GHG emissions reductions by 2026. Since 2015, we have reduced scope 1 and 2 GHG emissions by 21.3 MT CO2e or 66 per cent.	In 2022, we adopted a more ambitious target to be net-zero by 2045. We believe our Clean Electricity Growth Plan supports achieving our net-zero target.
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".

TransAlta's target to reduce 75 per cent of our scope 1 and 2 GHG emissions by 2026 from a 2015 base year is estimated to align with the electricity sector decarbonization pathway to limit global warming to 1.5°C, as one of the Paris Agreement goals.

In December 2021, the Company committed to setting a science-based emissions reduction target through the Science Based Target initiative ("SBTi"). In 2022, we started the target validation process of our 2026 scope 1 and 2 emissions reduction target. In 2023, TransAlta did not anticipate that setting a near-term scope 3 target would be a condition to our scope 1 and 2 target being validated by the SBTi. This would mean accelerating the validation of our scope 3 emissions ahead of the Company's intended timelines. As a result, given SBTi's requirement that we establish a near-term scope 3 reduction target, we determined to withdraw from our commitment to the SBTi. TransAlta remains confident that our significant scope 1 and 2 emissions reduction trajectory from 2015 to 2026 is in line with the electricity sector pathway to limit global warming to 1.5°C.

GHG Disclosures

Scope 1 and 2 Emissions

Our scope 1 and 2 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 that we operate.

The GHG Protocol classifies a company’s scope 1 emissions as the direct emissions from owned or controlled sources. Scope 2 emissions are indirect emissions from the generation of purchased energy.

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. Applying harmonized global warming potentials across our fleet would result in a minor variance to our overall calculated GHG totals.

Our 2023 GHG data was 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

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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. Methane emissions from our operations are mainly due to incomplete combustion of natural gas from the natural-gas-powered plants and there are no fugitive methane emissions associated with our operations. In 2023, methane emissions were 0.2 per cent of our total emissions.

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	2023	2022	2021
Scope 1	10.9	10.2	12.4
Scope 2	0.0	0.1	0.1
Total scope 1 and 2 GHG emissions	10.9	10.2	12.5

Year ended Dec. 31	2023	2022	2021
Hydro	0.0	0.0	0.0
Wind and Solar	0.0	0.0	0.0
Gas	6.4	6.3	6.5
Energy Transition	4.5	4.0	6.0
Corporate and Energy Marketing	0.0	0.0	0.0
Total scope 1 and 2 GHG emissions	10.9	10.2	12.5

Year ended Dec. 31	2023	2022	2021
Australia	1.0	0.9	1.0
Canada	5.3	5.2	7.9
US	4.6	4.1	3.6
Total scope 1 and 2 GHG emissions	10.9	10.2	12.5

In 2023, our GHG emissions (scopes 1 and 2) were 10.9 million tonnes as a result of normal operating activities. Despite the increase in absolute emissions as a result of increased production, our scope 1 and 2 GHG emissions intensity remains similar to the previous year at 0.41 tCO2e/MWh (2022 - 0.40 tCO2e/MWh). TransAlta will cease generation from our single remaining US coal unit by the end of 2025, which will further reduce the Company’s emissions.

TransAlta sells the environmental attributes generated from our renewable energy facilities and does not subtract this amount from our total GHG emissions (scope 1 and 2). However, it should be noted that TransAlta’s customers are reporting GHG emissions reductions using our renewable energy assets, projects and operations.

GHG emissions are verified to a level of reasonable assurance in locations in which 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 table highlights our scope 1 and 2 GHG emissions reductions since 2015 and our targeted emissions in 2026. 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)	2023	2015
Total scope 1 and 2 GHG emissions (million tonnes CO2e)	8.1	10.9	32.2

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Scope 3 Emissions

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. TransAlta's scope 3 emissions are calculated using methodologies consistent with the GHG Protocol Corporate Value Chain (Scope 3) Accounting and Reporting Standard ("Scope 3 Standard") and with reference to the additional guidance provided in the GHG Protocol Technical Guidance for Calculating Scope 3 Emissions ("Scope 3 Guidance") developed by the World Resources Institute and the World Business Council for Sustainable Development.

Our scope 3 emissions include the indirect GHG emissions resulting from activities in our value chain but outside of our operational control. We estimate our scope 3 emissions in 2023 to be approximately four million tonnes of CO2e, which is primarily attributed to our non-operated joint venture interests as part of Category 15: Investments. Of the 15 categories described in the GHG Protocol Scope 3 Guidance, four are not relevant to our business and, therefore, are not included in the calculation: Category 8: Upstream leased assets, Category 12: End-of-life treatment of sold products, Category 13: Downstream leased assets, and Category 14: Franchises.

Since 2022, we have focused on enhancing our scope 3 emissions accounting. In 2022, we engaged with an independent third-party consulting company to complete a methodology review of our scope 3 inventory based on the GHG Protocol Scope 3 Guidance. In 2023, we engaged with an independent third-party advisory firm to complete a pre-assessment of material scope 3 emissions so that we can meet our target to verify and disclose 80 per cent of TransAlta’s scope 3 emissions by 2024, with the aim of reporting on 2023 scope 3 emissions as part of our 2024 Integrated Report.

Avoided Emissions

In 2023, production from renewable assets resulted in the avoidance of approximately 2.3 million tonnes of CO2e for our customers. TransAlta's avoided emissions are defined as the sum of the displaced emissions by our renewable assets in the jurisdictions where we operate. The value is calculated as the product of the generation of electricity obtained from a renewable source (hydro, wind and solar) and the specific CO2 emissions intensity from the grid of the jurisdiction in which we operate. Avoided emissions decreased in 2023 compared to 2022 primarily due to the reduction of emission intensity of the grid. As the world decarbonizes over time, the emission intensity of the grid will gradually decrease year over year. The following table highlights our avoided emissions in the reporting year.

Year ended Dec. 31	2023	2022	2021
Total GHG emissions avoided (million tonnes CO2e)	2.3	2.7	2.6

Sustainable Finance

Sustainable finance is the process of taking due account of ESG considerations (e.g., climate change, biodiversity, human rights, etc.) when making investment decisions. Sustainable finance is a key pillar of TransAlta’s Climate Transition Plan. This means we will utilize pools of capital available to sustainable economic activities and projects to finance our energy transition towards net-zero operations.

TransAlta deploys green and sustainable financing to build our renewable energy fleet and advance our clean energy transition. This supports our goal to deliver on our customers’ needs for clean electricity. Since 2020, we have issued $684 million in green bonds and converted our four-year $2.0 billion revolving credit facility into a sustainability-linked loan.

In 2022, TransAlta issued US$400 million ($533 million) in Senior Green Bonds, an amount equal to the net proceeds from the bonds has been allocated to finance or refinance

new and/or existing eligible green projects. The bonds were issued under TransAlta's Green Bond Framework, which aligns with the Green Bond Principles published by the International Capital Market Association. For further information, refer to Green Bond Framework in the Shareholder Information section of the Investor Centre on our website. In 2021, the Company's indirect wholly owned subsidiary, Windrise Wind LP, completed a secured green bond offering by way of private placement for approximately $170 million (face value).

In 2021, TransAlta converted an existing $1.3 billion syndicated revolving credit facility into a sustainability-linked loan. The loan aligns the cost of borrowing to the Company's GHG emissions reductions and gender diversity targets. Sustainability-linked loans are any types of loan instruments and/or contingent facilities (such as bonding lines, guarantee lines or letters of credit) that incentivize the borrower’s achievement of ambitious, predetermined sustainability performance objectives.

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The summary below shows the carrying value of the issued green bonds and the total facility size of our ESG financial operations portfolio.

As at Dec. 31 (in millions of Canadian dollars)	2023	2022	2021
Green bonds (1)	684	703	171
Sustainability-linked loans	1,950	1,250	1,250

(1)Green bonds are related to Senior Green Bonds issued in 2022 and the Windrise Wind green bond issued in 2021.

Climate-Related Financial Metrics

The results of TransAlta’s 2021 climate-related scenario analysis, aligning with a 1.5°C warmer world, have shown that opportunities to grow the renewable fleet exist across all scenarios and locations. Our adjusted revenue from renewable energy generation (hydro, wind and solar) in 2023 was $902 million (2022 – 1,014 million) or 27 per cent of our total adjusted revenue in 2023.

We continue to execute the Clean Electricity Growth Plan updated in 2023 to deliver up to 1.75 GW of incremental renewables capacity and a 10 GW growth pipeline by 2028. In 2023, our growth capital expenditures for renewable energy generation was $630 million (2022 – $666 million). In addition, TransAlta continues to invest in emerging abatement technologies and solutions. In 2023, our investments in low-carbon research and development were $4 million (2022 – $12 million).

As part of our Clean Electricity Growth Plan, our goal is to achieve 70 per cent of adjusted EBITDA from renewables and storage by the end of 2028. In 2023, adjusted EBITDA from renewable energy generation was $716 million (2022 – $838 million) or 44 per cent of our total adjusted EBITDA. Our renewable fleet makes our overall portfolio more resilient to climate-related risks, provides increased flexibility in generation and creates incremental environmental value through environmental attributes. Our revenue in 2023 from environmental attribute sales was $36 million (2022 – $53 million).

The disclosure of TransAlta's financial metrics related to our climate-related risks and opportunities align with the IFRS S2 and TCFD recommendations. A summary of our climate-related financial metrics is presented below.

Year ended Dec. 31 (in millions of Canadian dollars)	2023	2022	2021
Growth capital expenditures for renewable energy generation(1)	630	666	326
Renewable energy adjusted EBITDA(2)	716	838	584
Environmental attribute sales revenue(3)	36	53	40
Renewable energy adjusted revenue(4)	902	1,014	731
Investments in low-carbon research and development(5)	4	12	—

(1)Growth capital expenditures include amounts deployed for growth projects and acquisitions related to renewable energy generation. This includes the construction of our Windrise wind facility completed in 2021, the acquisition of North Carolina Solar portfolio in 2021, the construction of the Garden Plain wind project, White Rock wind projects, Horizon Hill wind project and Northern Goldfields solar project as part of our Clean Electricity Growth Plan. This excludes the Mount Keith transmission expansion project.

(2)Adjusted EBITDA from renewable energy generation includes hydro, wind, solar and battery storage facilities. The renewable energy adjusted EBITDA is the total adjusted EBITDA of the Hydro and Wind and Solar segments. These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures and Segmented Financial Performance and Operating Results sections of this MD&A.

(3)Environmental attribute sales revenue indicates the full amount of hydro, wind and solar environmental credits, without any other consolidation impacts.

(4)Adjusted revenue from renewable energy generation includes hydro, wind, solar and battery storage facilities. 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

(5)Investments in low-carbon research and development include our equity investment in Ekona Power Inc.'s ("Ekona") Series A funding round and our four-year investment in EIP’s Deep Decarbonization Frontier Fund 1 (the “Frontier Fund”).

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Alignment with Climate-Related Disclosures Frameworks

The table below shows the alignment of our climate change management disclosure with TCFD, IFRS S2 and CDP (2023) recommendations.

TCFD Recommended Disclosures	Other Alignments	Location
Governance
Describe the board’s oversight of climate-related risks and opportunities	IFRS S2: 6; CDP: C1.1	Oversight by the Board of Directors
Describe management’s role in assessing and managing climate-related risks and opportunities	IFRS S2: 6; CDP: C1.2	Role of Senior Management
Strategy
Describe the climate-related risks and opportunities the organization has identified over the short, medium and long term	IFRS S2: 8-9; CDP: C2.1	Key Scenario Findings
Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy and financial planning	IFRS S2: 8-9; CDP: C2.3, C2.4, C3.3, C3.4	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	IFRS S2: 22-23; CDP: C3.1, C3.2	Climate Scenarios, Key Climate Scenario Findings
Risk management
Describe the organization’s processes for identifying and assessing climate-related risks	IFRS S2: 10; CDP: C2.2	Climate Change Strategy
Describe the organization’s processes for managing climate-related risks	IFRS S2: 24-25; CDP: C2.2	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	IFRS S2: 24-25; CDP: C2.2	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	IFRS S2: 27-28; CDP: C6.1, C6.3, C6.5, C9.1	Climate Change Metrics and Targets
Disclose scope 1, scope 2 and, if appropriate, scope 3 greenhouse gas (GHG) emissions and the related risks	IFRS S2: 29-32; CDP: C6.1, C6.3, C6.5	Climate Change Metrics and Targets
Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets	IFRS S2: 33-36; CDP: C4.1, C4.2	Climate Change Metrics and Targets

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Enabling Innovation and Technology Adoption

Technology and innovation are an existing and increasing focus at TransAlta. We have long been innovators. 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, including the first commercial wind farm in Canada, and are now one of the largest wind generators in the country. In 2015, we made our first investment in solar technology in Massachusetts, in 2020, we installed the first utility-scale battery in Alberta and, in 2023 we completed our first solar microgrid with battery energy storage system in Western Australia. We are now looking to advance a new technology roadmap that aligns with the Clean Electricity Growth Plan. This section covers manufactured and intellectual capital management as per guidance from the International Integrated Reporting Framework.

Our Energy Innovation Team

As part of our Clean Electricity Growth Plan, in 2021, we established an Energy Innovation team to investigate, prioritize and deploy new net-zero electricity generation technologies that address the three main factors of our energy transition: reliability, decarbonization and affordability. As we grow our renewables business, the Energy Innovation team is focused on what we should build next that complements our hydro, wind and solar assets to deliver reliable, affordable and low-carbon electricity to our customers. At the same time, the Energy Innovation team is looking at electrification broadly to investigate where potential new, adjacent business opportunities may exist for TransAlta.

Our Energy Innovation team participates in the Energy Futures Lab, a multi-stakeholder initiative that brings together innovators, influencers, and experts from different sectors and perspectives to address the challenges and opportunities of achieving a net-zero Alberta energy system. In 2023, TransAlta sponsored the Energy Futures Labs Alberta’s Electricity Futures Working Group, which aims to foster collaboration to explore and test new solutions for a reliable, affordable, and low-carbon electricity system in Alberta. We also continue to participate in the energy innovation ecosystem through engagement with various innovation accelerators that 'incubate' and accelerate start-ups by matching new technology solutions with practical problems identified by end-users, like TransAlta.

In 2023, TransAlta launched its Energy Innovation Series. The Series is led by our Energy Innovation Team along with guest speakers from across the Company and aims to empower our workforce through relevant industry knowledge on innovation in the electricity sector. In 2023, we delivered four sessions on a range of relevant topics

including grid reliability during the energy transition, grid energy storage options and decarbonized baseload generation strategies.

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.

Renewable Energy

In 2023, TransAlta's nameplate capacity was 944 MW from hydro energy, 2,046 MW from wind and battery storage, and 181 MW from solar power. We continue to look for opportunities to develop and operate solar energy.

In August 2023, the Garden Plain wind facility in Alberta was commissioned adding 130 MW to our gross installed capacity. The facility is fully contracted with Pembina Pipeline Corporation (100 MW) and PepsiCo Canada (30 MW), with a weighted average contract life of approximately 17 years.

In November 2023, the 48 MW Northern Goldfields solar and battery storage facilities in Western Australia achieved commercial operation. The facilities consist of the 27 MW Mount Keith solar facility, 11 MW Leinster solar farm and 10 MW/5 MWh Leinster battery energy storage system and interconnecting transmission infrastructure, all of which are now integrated into TransAlta’s 169 MW Southern Cross Energy North remote network. The Northern Goldfields solar facilities are expected to reduce BHP Nickel West’s scope 2 electricity GHG emissions from its Leinster and Mount Keith operations by 12 per cent and is long-term contracted with a globally recognized counterparty for 16 years.

In 2023, the Company continued to advance the 300 MW White Rock wind projects, to be located in Oklahoma. The White Rock wind projects are expected to achieve commercial operation in the first quarter of 2024. In 2021, we entered into two long-term PPAs with Amazon for the offtake of 100 per cent of the generation from these projects.

In 2023, TransAlta advanced the construction of its 200 MW Horizon Hill wind project located in Oklahoma, with a target commercial operation date in the first quarter of 2024. In 2022, the Company executed a long-term renewable energy PPA with a subsidiary of Meta for 100 per cent of the generation from the project. Under this agreement, Meta will receive both renewable electricity and environmental attributes from the Horizon Hill wind project.

TransAlta is actively advancing its development pipeline for renewable energy generation. In 2023, the Company

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established a pipeline of potential growth projects in renewables that includes 280 MW of advanced-stage development projects along with 4,285 to 5,015 MW of projects in earlier stages of development.

Scaling Up Energy Solutions

Battery Storage

We continue to invest in battery energy storage systems and see them as an important element for TransAlta to continue to provide reliability through the energy transition – continuing an important role TransAlta has played for over one hundred years with our hydro units.

In November 2023, the Northern Goldfields solar and battery storage facilities in Western Australia achieved commercial operation and are now supplying reliable electricity to BHP’s remote nickel mining operations in Western Australia. The energy storage consists of the 10 MW/5 MWh Leinster Battery Energy Storage System which will be integrated into TransAlta’s remote network. The network and new generation will support BHP Nickel West to meet its emissions reduction targets and deliver lower-carbon nickel to its customers. TransAlta is continuing to work with BHP Nickel West on the development of other projects to further reduce scope 2 GHG emissions at BHP’s Mt Keith and Leinster operations.

In 2023, TransAlta’s development pipeline included four energy storage projects in Canada: WaterCharger (lithium-ion battery storage, 180 MW), Tent Mountain (pumped hydro storage, 160 MW), Brazeau (pumped hydro storage, 300-900 MW) and New Brunswick Power Battery (battery, 10 MW). These strategically-located units could play various roles on electricity grids including providing reliability services and storing surplus generation for discharge at peak periods.

Electric Mobility

Companies can play an important role in driving the transition to electric vehicles by taking the lead in their own operations. Recognizing this role, TransAlta is exploring the potential of electrifying our service fleet with zero-emission vehicles. In 2023, we launched a pilot project called Project Electrify to test four fully-electric vehicles at different facilities in Canada. We will assess their performance, safety and cost-effectiveness under different conditions and operator needs. The project will run from 2024 to 2025, during which time our operators will gain hands-on experience with the technology and provide feedback on its suitability for wider adoption. Based on the learnings from the project, TransAlta will decide whether to pursue further electrification of our fleet.

Future Solutions

Hydrogen

In 2022, we announced a $2 million equity investment in Ekona's Series A funding round. The investment will help support the commercialization of Ekona’s novel methane pyrolysis technology platform, which produces cleaner and lower-cost turquoise hydrogen. If successful, Ekona’s distributed technology allows for onsite production of hydrogen, hence avoiding the need for costly transportation of hydrogen. Furthermore, its solid carbon byproduct allows for low-cost, low-emissions hydrogen production without the need for carbon sequestration. TransAlta is a member of Ekona’s Strategic Committee and continues to work with Ekona as it develops its pyrolysis technology.

Small Modular Reactors ("SMR")

Small modular reactors have a power capacity of up to 300 MW per unit and differ from traditional nuclear in that they are built to be modular, factory-assembled units that are transported to a location for installation. Additionally, they implement passive or walk-away safety features designed to dramatically reduce the risk of nuclear events. While high costs remain a challenge for all forms of nuclear, SMR developers argue that smaller MW plants made from manufactured components will allow the industry to access steep cost declines as the technology matures and more units are deployed. By providing reliable, emissions-free baseload power, nuclear power may play an important role in clean energy transitions. Today, nuclear power makes a significant contribution to low-carbon electricity generation and has significant potential to contribute to power sector decarbonization. TransAlta continues to monitor developments in SMR.

Nature-based Solutions ("NBS")

Nature-based solutions are actions to protect, sustainably manage and restore natural and modified ecosystems that address societal challenges effectively and adaptively, simultaneously benefiting people and nature. TransAlta is actively evaluating NBS as carbon removals to neutralize any residual emissions that we cannot yet eliminate.

Direct Air Capture ("DAC")

Direct air capture technologies extract CO2 directly from the atmosphere. The CO2 can be permanently stored in deep geological formations, thereby achieving permanent CO2 removal. TransAlta continues to explore the benefits of DAC as a carbon dioxide removal option to support the net-zero transition of our operations and customers.

Carbon Capture, Utilization and Storage ("CCUS")

Our teams continuously explore the use of applied or new technologies such as CCUS to reduce GHG emissions. We

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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.

Disruptive Technologies

In 2022, we entered into a commitment to invest US$25 million over the next four years in Energy Impact Partners' ("EIP") Deep Decarbonization Frontier Fund 1 (the “Frontier Fund”) that invests in early-stage, innovative technology companies that will accelerate the transition to net-zero GHG emissions. TransAlta's investment in the Frontier Fund provides TransAlta with the opportunity to pool funds with some of the largest utilities in the United States and Europe to identify, pilot, commercialize and bring to market technologies that will support its decarbonization goals.

Fusion

Fusion technologies attempt to recreate the fusion reactions in the sun by fusing two hydrogen molecules together. If successful, fusion promises low-cost energy, with far shorter-lived nuclear waste. Fusion achieved some significant development milestones in 2022, including most significantly, Lawrence Livermore National Laboratory achieving net energy gain. This, coupled with unprecedented capital flow into fusion companies, has led to newfound excitement that fusion may be able to leapfrog current generation technologies.

Through EIP, TransAlta has invested in ZAP Energy, a leading fusion start-up. ZAP Energy’s technology stabilizes the hydrogen plasma using sheared flow (driving current through the flow creating the magnetic field confining and compressing the plasma) rather than magnetic fields. In 2022, ZAP announced it will conduct a feasibility study of retrofitting the former TransAlta Big Hanaford gas plant located in Centralia to host its first-of-a-kind Z-pinch fusion pilot plant. ZAP received $1 million from the Centralia Coal Transition Grants Energy Technology Board as part of our energy transition investments to move away from coal in Washington State.

For more information on investments in low-carbon research and development, refer to Climate-Related Financial Metrics section of this MD&A.

Analytics and Automation

Asset Performance

TransAlta's Asset Performance team was founded in 2023 to continue the work initiated by our previous Asset Analytics and Optimization team founded in 2008. This team monitors the Company's generation portfolio 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. The Asset Performance team also performs production reporting functions for these assets and is actively engaged in projects to improve this reporting.

The Data and Innovation team worked with partners across the company to advance its Asset Performance Management platform, GenOS, to deliver new features that increase the performance and management of our renewable asset fleet. Key process improvements, such as enhanced performance analytics that leverage machine learning, advanced analytics and data science models, provide our operators with deeper insights to help optimize asset performance across the entire fleet. Built in-house, GenOS provides data-driven insights for our wind, solar, gas and hydro fleets

Asset Performance 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 Asset Performance engineer 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. For 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 Asset Performance engineer are focused on early identification of equipment issues based on longer-term trend analysis and complements day-to-day facility operations.

Automation and Robotics

TransAlta created the Data and Innovation team in 2019 to modernize its data infrastructure and take advantage of new opportunities in analytics and data science. The Data and Innovation team is cross-functional; composed of data architects, data engineers, data analysts, software developers, integration specialists and engineers. The team focuses on the delivery of value using digital innovation, such as the modernization of data management strategy and platforms, the rapid delivery of data-driven applications, the design and implementation of advanced analytics and machine learning models and the execution of robotic process automation to eliminate manual tasks.

The substantial growth of our Advanced Automation Program has increased the number of manual processes we have automated, allowing our subject matter experts to spend more time on higher-value opportunities. With industry leaders in automation, TransAlta is able to leverage high impact technology to quickly develop custom robotic process automations across the company.

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Drones

In 2022, TransAlta formed the Robotics Inspection Council. The Council's purpose is to coordinate and assess the use of drones for robotic inspections to increase value to the business through improved safety, reduced inspection costs and better communication. In alignment with TransAlta’s core value of safety, the Council defined the corporate requirements on the safe use of remotely piloted aircraft in TransAlta's fleet. In 2023, drone technology was

used in TransAlta's gas and hydro fleets to inspect boiler internal components, canals and cooling ponds, and a “drone in a box” solution was trialed and purchased for improved site security. The Council continues to meet with vendors and industry peers to understand areas of opportunity and how these technologies are being deployed. Robotic inspections were performed in TransAlta’s gas and hydro fleets. The Council is investigating additional applications in our fleet for 2024.

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.

Inclusive Transition

In support of our energy transition, since 2015, TransAlta has been investing US$55 million over 10 years to support energy efficiency, economic and community development and education and retraining initiatives in Washington State. The 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 and Community Development Board (US$20 million), and the Energy Technology Board (US$25 million). To date, the Weatherization Board has invested US$9.5 million, the Economic and Community Development Board US$15 million and the Energy Technology Board US$15 million.

Specific projects that the boards funded in 2023 include: the replacement of a diesel bus with a new electric bus by the Skamania School District; the installation of a 100 kW roof mounted solar system at Palouse High School by the Palouse School District; the installation of a 100kW ground mounted solar system at the Wastewater Treatment Plant owned by the City of Medical Lake; and pre-employment training services for youth in Lewis County by Morningside Services.

Additionally, in 2016, TransAlta announced that we had reached an agreement with the Government of Alberta for the cessation of emissions from coal-fired electricity generation facilities in Alberta (Off-Coal Agreement). As part of the Off-Coal Agreement, TransAlta has invested in programs and initiatives to support the communities surrounding the plants negatively impacted by the phase-out of coal generation during the transition.

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:

•Energy 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. Our work has been recognized by our customers through an average retention rate of 89 per cent over the last three years.

Across our business in Canada, the US and Australia, we provide on-site generation for large mining and industrial customers. This requires us to continually engage 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 explore opportunities to provide 24/7 carbon-free energy to help customers meet their decarbonization goals.

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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 emissions reduction targets. Production

from renewable electricity in 2023 resulted in the avoidance of approximately 2.3 million tonnes of CO2e for our customers.

Our experience in developing and operating power facilities is highlighted below:

Power generation type	Operating experience (years)
Hydro	112
Natural Gas	73
Wind	26
Solar	9
Battery Energy Storage Systems	3

For further details on how we support our customers' sustainability objectives, please refer to the Enabling Innovation and Technology Adoption section of this MD&A.

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 all gender identities, 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 have governance practices in place for the protection of human rights.

Our Human Rights and Discrimination Policy outlines our commitment to human rights in our operations and supply chain to ensure that our personnel policies and practices in our global operations 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. Our annual mandatory Code of Conduct training is required for employees prior to signing off the Code of Conduct. In 2023, 100 per cent of employees completed the training and acknowledged and signed the Code of Conduct. 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 providing 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, since 2020, we have reported under federal 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. In 2024, we will report under Canada’s Fighting Against Forced Labour and Child Labour in Supply Chains Act.

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 and for select procurement engagements, 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.

Supply chain is a pillar of our Clean Electricity Growth Plan to deliver net-zero operations. We have enhanced the supplier management functionality within our corporate

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procurement system and are working to incorporate ESG data reporting capability. In the next few years, we will develop ESG criteria for supply chain engagement and work to understand our direct suppliers' GHG emissions profile and targets. Our long-term plan is to engage with suppliers to explore enhancement of their GHG emissions targets and set direction for engaging suppliers with GHG emissions reduction targets.

In 2022, TransAlta approved a new goal to integrate sustainability into supply chain. Our target is "By 2024, 80 per cent of our spend will be with suppliers that have a sustainability policy or commitment". This supports the intent of the UN SDG Target 12.7: “Promote public procurement practices that are sustainable, in accordance with national policies and priorities.” In 2023, we confirmed that on average 78 per cent of our spend in 2022 and 2023 was with suppliers that have a sustainability policy or commitment. TransAlta will continue to consider other targets to help integrate sustainability into supply chain.

Our Supplier Code of Conduct 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 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.

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 peoples. Our core values of safety, innovation, sustainability, respect and integrity represent how we do business and engage with Indigenous peoples. Our commitment to Indigenous relations is led by a centralized corporate team who foster a relationship-based approach, involving employees at our facilities 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 five key areas: community engagement and consultation, business development, community investment, employment, and training and awareness. We ensure that TransAlta’s principles for engagement are upheld and 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.

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, which has minimized potential project delays. We strive to maintain relationships through the life cycle of our facilities, 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 2024, TransAlta will continue to ensure that all new employees complete Indigenous cultural awareness training as part of the Company’s onboarding process.

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 2023, TransAlta provided more than $453,000 to support Indigenous youth, education and employment programs, representing 14 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, Nakoda Sioux and Stoney. MECCS is a tuition-free public school integrating Indigenous

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culture, beliefs and perspectives into elementary school experience. The school specializes in working with children suffering from adversity and provides enhanced learning support. MECCS students have a high success rate for completing high school and winning academic awards. In 2023, TransAlta provided $35,000 to support the school’s operations plus a holiday donation to enable a student celebration.

•The Read On Literacy Program ("Read On") – In 2023, TransAlta partnered with Read On to provide elementary students in communities near our operations with in-person and virtual sessions. Read On is an Indigenous literacy program that seeks to mentor young people in First Nation schools to achieve their maximum academic, personal and social development by promoting the core values of education, literacy, taking pride in ones’ culture and making good decisions in one’s life.

•Diamond Willow Youth Lodge – In partnership with the United Way of Calgary and Area, designated funding was provided to the Diamond Willow Youth Lodge, which is 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.

•Wihnemne School Hot Lunch Program – In 2023, TransAlta partnered with the community school at Paul First Nation in Alberta on a program designed to ensure the Nation’s children receive nutritious meals each day maximizing their scholastic success. This program is cited as a catalyst responsible for strong growth in the school's enrollment.

Indigenous Cultural Awareness Training for TransAlta Employees

In November 2023, TransAlta successfully reached 100 per cent completion of the Indigenous Cultural Awareness Training program across our operating jurisdictions in Canada, the US and Australia. In line with our sustainability target set in 2021, the Company made a deliberate effort to ensure that every employee participated in Indigenous Cultural Awareness training over the past two years. This initiative has been instrumental in providing valuable insights into the rich history, culture and perspectives of Indigenous communities within the jurisdictions where we operate.

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.

Our Stakeholders

To act in the best interests of the Company and optimize the balance between financial, environmental and social values of 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 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.

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TransAlta stakeholders
Non-governmental organizations	Community associations	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 and gas associations/Industry	Railroad owners
Customers	Think tanks	Utility owners
Shareholders	Academics	Employees

Stakeholder Engagement

In order to run our business successfully, we maintain open communication channels with our stakeholders. We are committed 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 externally with each stakeholder to identify and mitigate further issues.

Examples of our methods of engagement are listed in the following table.

Information and communication	Dialogue and 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 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 phase and maintain engaged communication throughout operations to decommissioning phase.

Examples of stakeholder engagement in 2023 include: the Pinnacle project 1 and 2 open houses, SunHills Solar project open house, two Riplinger project open houses and ongoing engagement on the Kent Hills rehabilitation plan.

Community Investments

In 2023, TransAlta contributed approximately $3.2 million in donations and sponsorships (2022 – $2.3 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 $1.5 million for the United Way.

In 2023, TransAlta made a number of other significant investments, including the following highlights:

•Community Shelters – In 2023, TransAlta donated $40,000 to local shelters near our operating assets in Canada, US and Australia. This initiative recognizes the unprecedented need for employment services, families experiencing poverty and escaping violence and abuse.

•New Operation Support – In 2023, TransAlta donated $50,000 to local communities surrounding our new White Rock, Horizon Hill and Garden Plain operations. These initiatives recognize our commitment to supporting the communities in which we operate. Funding was designated to the local school libraries, school repairs and a local fire station.

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•Centralia Coal Facility – Since 2012, TransAlta has maintained its commitment to invest US$55 million in the state of Washington and made the final annual payment in December 2023. Funds from this investment have been managed by the Centralia Coal Transition Board to support local community sponsorships including investments in the arts, colleges, energy technology, weatherization upgrades and supporting displaced workers with education and retraining opportunities. This completes a significant commitment for the transition of the Centralia coal facility.

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 employees.

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 receives executive sponsorship and includes an emergency management policy and standard, which sets an expectation for employees to continuously prepare for emergencies. 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 capable of responding 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 the incident might be.

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.

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, co-ordinate messaging with any applicable external agencies and, if necessary, deploy to an incident site.

Annual training, exercise and drill 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 an effective program across the organization.

Data and Digital Asset Protection

We work diligently to protect our digital assets, including our corporate data and our digital identities that provide access into line of business applications. Cybersecurity threats that compromise these assets include the manipulation of data integrity, system and network hacking, use of social engineering tactics through email phishing and compromise of operations and infrastructure through the use of ransomware, credential breaches and attacks introduced through unknowing third-party vendors and service providers.

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 cybersecurity risks and threats through a comprehensive and multi-faceted program. TransAlta continually assesses our cyber threat level, implementing measures and controls to proactively mitigate internal and external cybersecurity risks and threats posed to the organization.

TransAlta’s Cybersecurity Policy defines how we identify and manage cybersecurity risks and threats, as well as how we detect, respond, and recover from cybersecurity incidents. We comply with the North American Electric Reliability Corporation Critical Infrastructure Protection ("NERC CIP") requirements where applicable. The NERC CIP is a set of standards aimed at regulating, enforcing, monitoring and managing the security of the North American power system. These compliance standards apply specifically to address cybersecurity risks.

In 2023, there were no identified cybersecurity breaches to our technology environment. Refer to Cybersecurity Risk in the Governance and Risk Management section of this MD&A for further details.

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Building a Diverse and Inclusive Workforce

Engaging our workforce, developing our employees, creating an equitable, 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 2023, we enhanced 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 equity, diversity and inclusion ("ED&I") is found in our workplace and among our co-workers who advocate for the values of equity and inclusion at all working levels. This commitment is outlined in our Board and Workforce Diversity Policy and Diversity and Inclusion Pledge. We believe a strong focus on ED&I will create a culture of belonging, allowing our employees to bring their authentic selves to work where they can thrive, innovate, improve service to our customers and positively impact the communities that we live in.

In 2023, TransAlta executed the third year of our five-year ED&I strategy to achieve the goals and aspirations defined in our ED&I Pledge.

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, 2023, women made up 26 per cent of our executive team and 46 per cent of our Board. These percentages are higher than the Canadian corporate averages of board seats held by women (29 per cent) and women on executive teams (21 per cent), according to data from all disclosing Canadian TSX-listed companies in Canada.

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. Currently, women employees represent 27 per cent of all employees. Though the majority of our operational roles are currently held by male employees, we remain committed to achieving the 40 per cent goal in this time period.

In 2023, we continued with the Women in Trades Scholarship that provides eligible students enrolled in post-secondary trade programs with financial support. In 2023, we also continued with a female apprenticeship program in

our Generation business to strategically target the recruitment of female students and train them to gain valuable experiential learning in the trades.

Workforce Health and Safety

The safety of our people, communities and the environment is one of our core values. Our focus on Operational Excellence puts into action TransAlta’s value of enabling a safe environment for our people and our communities. Operational Excellence is about powering and empowering our communities in a safe, environmentally-friendly and sustainable manner by ensuring our assets operate reliably and efficiently.

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.

We made significant progress on our safety culture transformation journey. Training and development initiatives were a top priority in which we completed behaviour-based safety training for all employees.

This training provides the tools and strategies to allow employees to influence their individual behaviours and encourage personal ownership over safety outcomes. It helps create a psychologically safe environment in our workplace as it encourages personal accountability towards safety.

In 2023, our strong safety performance has been supported by our strategic areas of focus: maturing our safety culture, understanding risk tolerance and standardization of safety information and systems. To support our safety cultural growth, new employees and leaders completed training modules designed to gain tools to understand their role in setting, building, and maintaining our safety culture. Through peer board sessions designed to embed an understanding of risk perception, risk tolerance and psychological safety, leaders held over 100 sessions across the fleet.

One of our key safety indicator is the TRIF, which tracks the number of injury incidents that require treatment beyond first aid, relative to total exposure hours worked. Our TRIF result for 2023 was 0.30 compared to 0.39 in 2022.

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The following represents our corporate safety performance and includes employees and contractors:

Year ended Dec. 31	2023	2022	2021
Lost-time injuries	1	0	3
Medical aids	4	6	9
Restricted work injuries	0	0	5
Exposure hours	3,362,000	3,058,000	4,134,000
Total Recordable Injury Frequency (TRIF)	0.30	0.39	0.82

We focus on leading indicators and participation through Total Safety Reports (hazard, near miss, positive observations, and cybersecurity reports). Total Safety Report Frequency demonstrates the proactive activities, per worker per year, we are taking to identify and prevent an injury or loss from occurring. We also report and recognize positive behaviours in the workplace to enhance psychological safety. This allows us to not only respond to incidents if they occur but find opportunities to strengthen barriers and layers of protection to mitigate potential incidents. In 2023, we recorded 12.5 reports per worker, which is above our target of 12. Evidence of the positive impacts associated with strong engagement and a maturing safety culture is apparent in TransAlta's overall safety performance. In 2023, TransAlta was selected by Canada’s Safest Employers to receive a Utilities and Electrical Employer Excellence Award. TransAlta was also recognized as the employer with the Best Wellness Program across all industries, excelling in the promotion and protection of employee overall wellness.

Organizational Culture and Structure

Our employees are central to value creation. Our corporate culture has evolved and adapted throughout our 112-year history. Our values are safety, innovation, sustainability, respect and integrity. These five 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.

Culture Transformation

In 2022, we embarked on our culture transformation journey with the goal of becoming a culture of results, purpose and learning. We developed a three-year culture strategy, Culture Charter and Culture Roadmap that defines milestones. For alignment and transparency, all of these documents are available to our employees. Part of our culture transformation involves improving employee psychological safety in order to increase employees to speak up with a view to increase innovation, creativity and ultimately, results.

We conduct annual Employee Engagement Surveys to gauge the employee experience, and based on survey results, leaders created action plans to drive improvement and increase engagement at the business unit and team level.

Finally, we are focused on improving employee health and well-being. To increase awareness, we have launched education sessions on a variety of topics such as mental health, women’s health, men’s health, nutrition, resiliency, etc.

Organizational Structure

As of Dec. 31, 2023, we had 1,257 (2022 – 1,222) active employees. This number increased by one per cent from 2022 levels. With approximately 30 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 2023. Our business continues to operate four generating segments, with Gas, Wind and Solar, Hydro and Energy Transition, with support from our Corporate and Growth Business Units. Our operations portfolio is run by a single leadership team, which provides operational and financial synergies, thus enhancing our competitiveness.

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Employee Retention and Recognition

ESG-Linked Compensation

At TransAlta, we have linked our ESG performance to our employees’ compensation including that of our executive leadership team. Our annual and long-term incentive pay for performance plans are linked to TransAlta achieving various ESG goals, where the targets and metrics are reviewed and approved annually by our Board of Directors and further outlined in our annual compensation plans.

In 2023, 20 per cent of our annual incentive plan was linked to achieving specific ESG targets: 10 per cent referred to our organizational culture improvements and 10 per cent was linked to safety. Further, 30 per cent of our 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, strong renewables growth, leading in ESG policy development, delivering on our culture plan and our ED&I strategy. Refer to the Management Proxy Circular for additional details on our ESG related compensation.

Employee Performance and Recognition

Coaching, feedback and management are fundamental to our performance philosophy, with leaders and employees being asked to participate in regular meetings to discuss work progress, professional and career development throughout the year.

We strive to be an employer of choice through our HR and total rewards programs, which include pay-for performance incentive plans, as reviewed and approved by the Board of Directors. TransAlta’s annual and long-term incentive plans are designed to measure and recognize employees’ contributions towards metrics and targets. In order to motivate and engage employees in a timely manner, we continue to utilize employee recognition programs, including a quarterly recognition program and a peer-to-peer recognition program.

Talent Development

TransAlta places significant focus on talent development and retention of its employees. Annually, employees complete a combination of optional, mandatory and customized training as part of their roles. All employees have access to learning sessions from speakers who are experts on topics as varied as psychological safety, ED&I, mental and physical health, culture, financial wellness, core skills and leadership development.

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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. This section covers natural capital management as per guidance from the International Integrated Reporting Framework.

Environmental Strategy

All energy sources used to generate electricity have 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.

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 at large place an increasing emphasis on successful environmental management. Our Environmental Policy defines how we are integrating the protection of nature and the environment within TransAlta’s strategy, our Total Safety Management System, as well as the principles of conduct for the management of natural resources.

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 (i.e., pollutants) 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.

Environmental Performance

Our performance on managing environmental aspects, reducing our environmental impact and capitalizing on environmental initiatives includes the following:

Biodiversity

The importance of environmental protection and biodiversity is outlined in our Environmental Policy as a corporate responsibility for TransAlta and a responsibility of each employee and contractor working on TransAlta's behalf. In 2022, the Company adopted the target to "achieve zero biodiversity-related incidents". This means zero biodiversity-related incidents that affected habitats and species included on the Red List of the International Union for Conservation of Nature ("IUCN") from near-threatened to critically endangered.

The following represents our biodiversity incidents in accordance with the IUCN Red List classification:

Year ended Dec. 31	2023	2022	2021
Critically Endangered	0	0	0
Endangered	0	0	0
Vulnerable	0	0	0
Near threatened	0	0	0
Total biodiversity-related incidents	0	0	0

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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, 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 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 assess 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. Typically, our renewable projects are greenfield development projects that require a higher level of evaluation compared to our gas projects, which primarily integrate into existing industrial facilities.

In addition, each greenfield development project has a detailed community engagement 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, resolving and mitigating stakeholder or Indigenous community concerns before filing major permit applications for all of our projects.

Day-to-day Operations

At our Alberta operations, in 2023, 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 its 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, an Operational Environmental Management Plan has been developed for each asset to ensure that our facilities use environmentally-sound and responsible practices that are based on a philosophy of continuous improvement of environmental protection. Examples of environmental initiatives to support our biodiversity focus include our bird and bat protection practices (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), and long-term dataset collections (e.g., wildlife studies pre-construction and post-construction). In addition, we continue to collaborate with industry and the scientific community to address environmental concerns and impacts pertaining to biodiversity.

At our Centralia operations, in 2023, we completed a riparian reforestation plan for under-forested areas along the Skookumchuck River within our Skookumchuck Wildlife Habitat Management Area. We planted 15,620 trees along both sides of the river to maintain the river banks and decrease erosion, and we completed a vigorous weed control program to control the proliferation of invasive species; thus, improving overall habitat health. Additionally, we harvested approximately 97,300 board feet of timber consisting of diseased Red Alder and Douglas Fir to allow for the growth of healthy trees as part of our overall wildlife habit management program.

Energy Use

TransAlta uses energy in a number of different ways. We burn natural gas, diesel and coal (to the end of 2025 at

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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 and diesel in our vehicles and the electricity use and fuel use for heating (such as 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 captures our energy use (million gigajoules). Energy use increased by one (1) per cent in 2023 over 2022. Some values do not sum to the indicated total due to rounding. Zeros (0) indicate truncated values:

Year ended Dec. 31	2023	2022	2021
Hydro	0	0	0
Wind and Solar	0	0	0
Gas	123	130	118
Energy Transition	73	64	86
Corporate and Energy Marketing	0	0	0
Total energy use (million gigajoules)	197	195	204

Air Emissions

Our one remaining coal facility emits 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 NOx, SO2, particulate matter and mercury. We continue reducing air emissions in our existing facilities through our conversion and retirement of coal units in Alberta (completed in 2021) and Washington State (planned completion by the end of 2025).

In 2022, we achieved our 2026 target of 95 per cent SO2 and 80 per cent NOx emissions reductions over 2005 levels. Since 2005, we have reduced SO2 emissions by 98 per cent and NOx by 83 per cent. In 2024, we will continue to review setting new environmental targets for air emissions.

None of our previous Alberta coal facilities are located within 50 kilometres of dense or urban populations and they all have been retired or converted to gas as of 2021. Our Centralia thermal facility in Washington State is located 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"). In 2023, the Centralia thermal facility accounted for 35 per cent of total NOx, 99 per cent of total SO2, 30 per cent of total

particulate matter and 76 per cent of total mercury. The 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 sufficient levels of NOx 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 facilities with air emissions within 49 kilometres of dense or urban environments.

Our total air emissions in 2023 retained similar performance to 2022 levels. This is due to the completion of coal-to-gas conversions in previous years, which resulted in higher operational efficiency and reduction in air emissions. The slight increase of particulate matter is due to increased production of Centralia, which is the only remaining coal plant within our portfolio.

The following represents our material air emissions. Figures have been rounded for SO2 (to the nearest one hundred), NOx (to the nearest one thousand), particulate matter (to the nearest ten, when possible) and mercury (to the nearest whole number):

Year ended Dec. 31	2023	2022	2021
SO2 (tonnes)	1,100	1,200	7,300
NOx (tonnes)	11,000	11,000	15,000
Particulate matter (tonnes)	460	360	2,200
Mercury (kilograms)	18	21	41

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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 therefore 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, which we are unable to recover.

In 2022, we achieved our water consumption reduction target to reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m3 or 40 per cent in 2026 over the 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." In 2024, we will continue to review setting new environmental targets for water consumption.

In 2023, we withdrew approximately 273 million m3 (2022 – 233 million m3) and returned approximately 239 million m3 (2022 – 207 million m3) or 88 per cent. Overall, water consumption was approximately 34 million m3 (2022 – 26 million m3). Water consumption increased primarily due to an increase in production compared to last year. This is particularly observed in Centralia, our last transition-coal plant with the highest water consumption intensity.

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 million m3:

Year ended Dec. 31	2023	2022	2021
Water withdrawal	273	233	241
Water discharge	239	207	209
Total water consumption (million m3)	34	26	32

Water Security

Our largest water withdrawal and discharge occurs at our Sarnia gas cogeneration facility (which produces both electricity and steam for our customers). 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 97 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. With respect to gas and diesel turbine water use, water wash 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 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.

Dam Safety

Our dam safety programs include all hydroelectric developments, constructed ponds and fluid retaining structures such as ash lagoons and canals, as well as associated equipment and structures and the personnel required to operate, maintain and inspect these items. They are governed through our Dam Safety Policy and Dam Safety Management System, which includes requirements on design, modification and decommissioning, operation, maintenance and surveillance, public safety, emergency management and risk management.

TransAlta’s Board and its President and CEO oversee the effectiveness of our dam safety programs and receive regular updates. In 2022, a member of the Board was designated as the Company's Dam Safety Advisor to assist the Board in fulfilling its oversight role in regard to the Company's dam safety practices given the unique and technical aspects of dam safety. In addition, TransAlta engages an external Dam Safety Review Panel to provide external review of the program and its management, including overall assessment and benchmarking against

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other national and international programs. Our monitoring programs include:

•Regular operations and engineering inspections;

•Testing of critical equipment;

•Numerous instruments in the dams monitoring water level, temperature, movement, earthquake detection;

•Use of drones and satellite remote movement monitoring;

•Emergency plans and exercises with internal and external stakeholders; and

•Regular third-party reviews that are shared with the regulators.

We work closely with local stakeholders including conservation authorities and public agencies on watershed management, emergency planning and flood response. For example, in Southern Alberta, our hydroelectric facilities have played an increasingly important water management role following the flood of 2013. In 2021, we renewed our previous agreement with the Government of Alberta for another five years 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 River System (which includes the Interlakes, Pocaterra and Barrier hydroelectric plants) for drought mitigation efforts. In 2022, we started decommissioning the Keephills Ash Lagoon, a facility that is no longer needed for ash storage following the coal-to-gas conversion of Keephills Unit 2. This three-year project will reshape the existing lagoon so that it is stable for the long term and is the first step towards delicensing the structure.

TransAlta is proud of its reputation in dam safety. We participate in the Canadian Dam Association, Dam Safety Interest Group of the Centre for Energy Advancement through Technological Innovation, United States Society on Dams, Canadian Geotechnical Society, Dam Safety Advisory Committee of the Alberta Chamber of Resources and Association of State Dam Safety Officials.

For information on our corporate emergency management program, refer to Public Health and Safety in the Engaging with Our Stakeholders to Create Positive Relationships section of this MD&A.

Waste

The importance of environmental protection and waste management is outlined in our Environmental Policy as a corporate responsibility for TransAlta and its employees, and contractors working on TransAlta's behalf. Our waste data is reported annually to a number of different regulatory bodies.

In 2023, our operations generated approximately 479,000 tonnes equivalent of waste (2022 – 204,000 tonnes). Of the total waste generated, 97 per cent was non-hazardous waste and 0.2 per cent was directed to landfill (2022 – 0.9 per cent). The main reason for the increase in total waste is due to the waste reuse. Since its retirement, we have been selling ash from our Highvale and Centralia Mine, which accounts for 95 per cent of the total waste generated.

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	2023	2022	2021
Total waste generation (tonnes equivalent)	479,000	204,000	514,000
Waste to landfill (tonne eq.)	1,000	1,900	1,000
Waste recycled (tonne eq.)	19,000	22,000	31,000
Waste reuse (tonne eq.)	457,000	151,000	176,000
% of total waste to landfill	0.2	0.9	0.2
% of total waste: hazardous	3	9	5
% hazardous waste to landfill	0.0	0.6	1.0

Our reuse waste or byproduct waste is generally sold to third parties. Our operating teams are diligent at not only minimizing waste, but also maximizing recoverable value from waste. We have invested in equipment to capture byproducts from the combustion of coal, such as fly ash, bottom ash, gypsum and cenospheres, for subsequent sale. These non-hazardous materials add value to products like cement and asphalt, wallboard, paints and plastics.

Coal Ash Management

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. In 2023, Lafarge

Canada and TransAlta entered into an agreement that will advance low-carbon concrete projects in Alberta. The project will repurpose landfilled fly ash, a waste product from TransAlta’s Highvale mine, which ceased operations in 2021. The ash will be used to replace cement in concrete manufacturing. 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.

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Land Use

Our largest land use had been associated with land disturbed by surface mining of coal, which ceased operations in 2021. Of the three mines we 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.

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 of Highvale has been progressively executed as part of our regulatory approvals and our target is to have it fully reclaimed by 2046. In 2022, our reclamation team submitted our final reclamation plans. 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 practices incorporate progressive reclamation where the final end use of the land is considered at all

stages of planning and development. To date, we have reclaimed approximately 4,900 hectares, which is approximately 39 per cent of land disturbed (12,600 hectares).

Environmental Incidents and Spills

Protecting 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 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 2023, no regulatory non-compliance environmental incidents were recorded (2022 – one incident). No fines or environmental enforcement actions occurred.

Regulatory non-compliance environmental incidents follow:

Year ended Dec. 31	2023	2022	2021
Regulatory non-compliance environmental incidents	0	1	2

Regarding spills and releases, 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.

The volume of spills in 2023 was zero (0) m3 (2022 – 246 m3).

Significant environmental incidents follow:

Year ended Dec. 31	2023	2022	2021
Significant environmental incidents	0	0	0

There is a potential that ash ponds associated with our retired coal mines 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 our approach to dam safety and 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 seasonal weather variations. Variations in winter weather affect the demand for electrical heating requirements while 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 facilities. 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.

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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. Refer to the Governance and Risk Management section of this MD&A for further discussion on weather-related risks.

Delivering Reliable and Affordable Energy

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. This section covers manufactured, intellectual and social and relationship capital management as per guidance from the International Integrated Reporting Framework.

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 customers if their sites are operating 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.

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 2023, TransAlta completed the Northern Goldfields solar facilities 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.

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 participates in the AESO’s fast frequency response ancillary services market to support intertie operations. Beyond the fast frequency response, WindCharger introduces a resource with a response time

M112 TransAlta Corporation 2023 Integrated Report

that can be operated with a high level of reliability to support the growing need for primary frequency response and system frequency support 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, refer to the Enabling Innovation and Technology Adoption section of this MD&A. For more information on extreme weather events and natural disasters, refer to Weather in the Progressive Environmental Stewardship section of this MD&A.

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

•Environmental Policy

In 2023, our sustainability memberships included key sustainability organizations and working groups such as the EXCEL Partnership, the Canadian Business for Social Responsibility and the Electricity Canada Sustainable Electricity Steering Committee, which all provide validation and support of our sustainability strategy and practices.

In 2022, we refreshed our material sustainability factors. They are presented below in alphabetical order.

•Air quality and emissions

•Asset integrity and grid resiliency

•Biodiversity and land management

•Climate change and greenhouse gas emissions

•Dam safety

•Energy use and conservation

•Equity, diversity and inclusion

•Ethics and business conduct

•Health, safety and well-being

•Human rights and labour practices

•Indigenous relationships and partnerships

•Information asset protection and cybersecurity

•Renewable energy and innovative technologies

•Security and emergency preparedness and response

•Stakeholder engagement and community investment

•Supply chain and sustainable sourcing

•Sustainability governance

•Sustainable finance

•Talent attraction, retention and development

•Waste management

•Water management

For additional details on governance, refer to the Governance and Risk Management section of this MD&A.

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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 interact.

Governance

The key elements of our governance practices are:

•Employees, management and the Board are committed to ethical business conduct, integrity and honesty;

•We have established key policies and standards to provide a framework for how we conduct our business;

•The Chair of our Board and all directors, other than our President and 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 the 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 Corporate Code of Conduct outlines 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 delegated certain responsibilities to the AFRC, GSSC, the Human Resources Committee (the “HRC”) and the Investment Performance Committee ("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 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

M114 TransAlta Corporation 2023 Integrated Report

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, refer to the Climate Change Governance in the 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; (vii) considering and recommending our sustainability targets to the Board and evaluating our performance against such targets; and (viii) 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 and Chief Financial Officer.

The Investment Committee is a management committee chaired by our Senior Vice-President, M&A, Strategy and Treasurer and comprises the President and Chief Executive Officer; Executive Vice-President, Finance and Chief Financial Officer; Executive Vice-President, Generation; Executive Vice-President, Commercial and Customer Relations; and Vice-President, Strategic Finance and Investor Relations. 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 and Chief Financial Officer and comprises 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 Toronto Stock Exchange 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 and guidelines of the TSX and Canadian Securities Administrators: (i) Multilateral Instrument 52-109 —

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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.

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 Corporate 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 Corporate 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 scenario analysis approaches. We estimate VaR using the historical variance/covariance approach. An inherent limitation of historical variance/covariance VaR is that historical information used in the estimate may not be indicative of future market risk. Stress tests are performed periodically to measure the financial impact to the trading portfolio resulting from potential market events, including fluctuations in market prices, volatilities of those prices and the relationships between those prices. We also employ additional risk mitigation measures. VaR at Dec. 31, 2023, associated with our proprietary commodity risk management activities was $4 million (2022 – $4 million). 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.sedarplus.ca 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 (loss) of changes in certain key variables. The analysis is based on business conditions and production volumes in 2023. Each item in the sensitivity analysis assumes all other potential variables are held constant. While these sensitivities are applicable to the period and the magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or for a greater magnitude of changes. The changes in rates should also not be assumed to be proportionate to earnings in all instances.

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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 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 (per cent)	Approximate impact on net earnings (millions)
Availability/production	1	$20

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;

•Monitoring the condition of our assets and performing predictive analytics, and adjusting our maintenance programs to maintain availability;

•Entering into long-term arrangements with our strategic supply partners to ensure availability of critical spare parts; and

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•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.

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 2023, we had approximately 84 per cent (2022 – 83 per cent) of total 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 2023, 86 per cent (2022 – 82 per cent) of our gas consumption used in generating electricity was contractually fixed or passed through to our customers and 100 per cent (2022 – 100 per cent) of our purchased coal was contractually fixed.

Actual variations in net earnings (loss) can vary from calculated sensitivities and may not be linear due to optimization opportunities, co-dependencies and cost mitigations, production, availability and other factors.

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 caused 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;

•Conducting 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;

M118 TransAlta Corporation 2023 Integrated Report

•Developing compliance plans that address how to meet or surpass emission standards for GHG, mercury, SO2 and NOx, 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.

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 fulfil its financial or performance obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect cash due to us or to receive products or services may have an adverse impact upon our net earnings (loss) 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, 2022. We had no material counterparty losses in 2023. 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, 2023:

	Investment grade  (per cent)	Non-investment grade  (per cent)	Total  (per cent)	Total amount ($)
Trade and other receivables(1,2)	95	5	100	807
Long-term finance lease receivables	100	—	100	171
Risk management assets(1)	75	25	100	203
Loan receivable(2)	—	100	100	26
Total				1,207

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

(2)Includes $26 million loan receivable included within other assets with a counterparty that has no external credit rating.

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 $23 million (2022 – $64 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

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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 and Australian dollar-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, is 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 (millions)
Exchange rate	$0.03	$14

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, or establishing normal course derivative or hedging transactions, including those undertaken by our Energy Marketing segment. 

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, 2023, we had liquidity of $1.7 billion comprising undrawn amounts under our committed credit facilities and cash on hand net of bank overdraft.

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 and 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.

M120 TransAlta Corporation 2023 Integrated Report

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 probable debt issuances and outstanding variable rate borrowings using interest rate swaps.

At Dec. 31, 2023, approximately 14 per cent (2022 – nine per cent) of our total long-term debt 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 (per cent)	Approximate impact on net earnings (millions)
Interest rate	50 bps	$2

London Interbank Offered Rate reform could impact interest rate risk with respect to the Company's Canadian dollar credit facilities and the Poplar Creek non-recourse bond held by a TransAlta subsidiary. The facilities reference the Canadian Dollar Offer Rate ("CDOR") for Canadian-dollar drawings, but include appropriate fallback language to replace this benchmark rate in the event of a benchmark transition. In addition, the non-recourse bond references the three-month CDOR. Cessation of the three-month CDOR will occur on June 28, 2024, which will impact the facilities and the non-recourse bond.

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.

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.

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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:

•Possessing a labour relations strategy;

•Applying a human-centric approach that emphasizes the employee experience, including actively improving our workplace culture, focusing on ED&I strategies and offering health and wellness programming and initiatives;

•Focusing on employee learning and development;

•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 employees have the appropriate training and qualifications to perform their jobs.

In 2023, approximately 30 per cent (2022 – 31 per cent) of our labour force was covered by 11 collective bargaining agreements (2022 – 11). In 2023, we successfully renegotiated three (2022 – six) collective bargaining agreements. Of these three agreements, one agreement is for a three-year duration, one agreement is for a two-year duration and one agreement is a one-year duration. We expect to renegotiate five collective bargaining agreements in 2024. Any problems in negotiating these collective bargaining agreements could lead to higher employee costs and a work stoppage or strike, which could have a material adverse effect on us.

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 transmission infrastructure in the markets where we operate are increasing 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, financiers and other entities.

We manage reputation risk by:

•Striving as a neighbour and business partner, in the regions where we operate, to build viable relationships based on mutual understanding leading to workable solutions with our neighbours and other community stakeholders;

•Clearly communicating our business objectives and priorities to a variety of stakeholders on a routine and transparent basis;

•Applying innovative technologies to improve our operations, work environment and environmental footprint;

•Maintaining positive relationships with various levels of government;

M122 TransAlta Corporation 2023 Integrated Report

•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. Over the past few years, geopolitical tensions and the pandemic have significantly impacted the cybersecurity ecosystem, increasing the frequency and diversity of cyberattacks, including threats of war driven cyberattacks (i.e., terrorism) against critical infrastructure and threat actors taking advantage of the pandemic (e.g., charity scams) and hybrid working environments. We anticipate that the cyber threat landscape will continue to evolve, with increasing threats of ransomware, compromised insider threats, supply chain attacks, advanced targeted phishing and artificial intelligence.

Cyber threats originate from various sources and vectors, from nation states, organized hacking groups or malware/ransomware. The cyber threat landscape continues to evolve, as we see cyber threats shift their focus from traditional attacks against perimeter information technology systems, to more effective attacks, such as phishing and ransomware.

TransAlta has established a comprehensive cybersecurity program to manage cybersecurity risks through effective security practices and structured and tailored plans. As information technology /operation technology systems are integral to TransAlta’s business operations, the risk of a cybersecurity incident threatens the safety of the public, TransAlta personnel and/or business functions, service delivery, reputation and profitability.

TransAlta maintains compliance to regulatory, legislative, and business requirements (e.g., NERC CIP, SOX, Privacy) by adopting industry endorsed standards and frameworks

(e.g., National Institute of Standards and Technology (“NIST”), CIP/Reliability Standards) to implement a pragmatic fit-for-purpose cybersecurity program, implementing cybersecurity controls and processes under the following domains:

•Identify: TransAlta conducts comprehensive risk assessments to identify and document the organization's assets, systems and data, as well as potential risks and vulnerabilities.

•Protect: TransAlta implements security controls, policies and procedures to safeguard the organization's assets, systems and data from unauthorized access, use, disclosure, disruption, modification or destruction. This includes implementing access controls, encryption, firewalls and intrusion detection/prevention systems to protect the organization's networks and systems.

•Detect: TransAlta implements incident detection and response capabilities to detect and respond to cyber incidents. This includes monitoring systems, networks and data for suspicious activity.

•Respond: TransAlta has developed incident response plans, procedures and teams, as well as provided training and conducted exercises to ensure that these plans and procedures are operating effectively.

•Recover: TransAlta has developed disaster recovery and business continuity plans, and it conducts test exercises of these plans to ensure their effectiveness. This includes identifying critical systems, data and process to ensure the continuity of business operations, as well as implementing backup and recovery solutions to ensure that the organization's data can be restored in the event of a disaster.

Although complete cyber risk elimination is not achievable given the evolving cyber threat landscape, the security controls implemented to detect, prevent and respond to a cyber incident significantly reduce TransAlta’s cyber risk and potential incident impact to acceptable levels. In addition, cyber insurance is utilized to further manage and transfer residual cyber risk to TransAlta’s business. We continue to improve our overall security maturity and defense capabilities against cyber threats and align cybersecurity practices to industry standards, business objectives and regulatory compliance requirements.

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.

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Growth Risk

Our business plan includes targets for the growth of our fleet of generating assets through suitable acquisitions or contracting 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 and its subsidiaries are subject to changing laws, treaties and regulations in and between countries.

Various tax proposals in the countries we operate in could result in changes to the basis on which deferred taxes are calculated or could result in changes to income or non-income tax expense. There has recently been an increased focus on issues related to the taxation of multinational corporations. A change in tax laws, treaties or regulations, or in the interpretation thereof, could result in a materially higher income or non-income tax expense 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 (per cent)	Approximate impact on net earnings (millions)
Tax rate	1	$9

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 the remedy 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. Refer to the Other Consolidated Analysis section of this MD&A for further details.

Other Contingencies

We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our insurance coverage during renewal of the insurance policies on Dec. 31, 2023. 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.

M124 TransAlta Corporation 2023 Integrated Report

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 year ended Dec. 31, 2023, the majority of our workforce supporting and executing our ICFR and DC&P continue to work 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.

ICFR is a framework designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the 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.

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, 2023, the end of the period covered by this MD&A, our ICFR and DC&P were effective.

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EX-13.3

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 Corporate 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.

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

February 22, 2024

F1 TransAlta Corporation 2023 Integrated Report

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” or the "Company") 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 controls over financial reporting are processes that involve human diligence and compliance and are subject to lapses in judgment and breakdowns resulting from human failures.

Internal control over financial reporting can also be circumvented by collusion or improper overrides. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process and it is possible to design safeguards into the process to reduce, though not eliminate, this risk.

TransAlta 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 2023 Consolidated Financial Statements of TransAlta for joint operations and equity accounted investments are three per cent and 12 per cent of the Company's total and net assets, respectively, as of Dec. 31, 2023, and seven per cent and 16 per cent of the Company's revenues and net earnings, respectively.

TransAlta Corporation 2023 Integrated Report F2

Changes in Internal Control over Financial Reporting

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 is 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, 2023 and has concluded that such internal control over financial reporting was effective.

Ernst & Young LLP, who has audited the Consolidated Financial Statements of TransAlta for the year ended Dec. 31, 2023, 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.

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

February 22, 2024

F3 TransAlta Corporation 2023 Integrated Report

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, 2023, 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, 2023, 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 2023 consolidated financial statements of the Company and constituted 3% and 12% of total and net assets, respectively, as of December 31, 2023, and 7% and 16% of revenues and net earnings, respectively, 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.

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, 2023 and 2022, the related consolidated statements of earnings (loss), comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and our report dated February 22, 2024 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.

TransAlta Corporation 2023 Integrated Report F4

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 22, 2024

F5 TransAlta Corporation 2023 Integrated Report

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, 2023 and 2022, the related consolidated statements of earnings (loss), comprehensive income (loss), changes in equity and cash flows, for each of the three years in the period ended December 31, 2023, 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, 2023 and 2022, and the financial performance and its cash flows for each of the three years in the period ended December 31, 2023, 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, 2023, 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 22, 2024 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.

TransAlta Corporation 2023 Integrated Report F6

Valuation of Long-Lived Assets related to certain cash generating units (“CGU”s) and Goodwill related to the Wind & Solar segment
Description of the Matter	As disclosed in notes 2(G), 2(H), 2(P)(I), 7 and 21 of the consolidated financial statements, the Company owns significant Wind & Solar generation assets and has recognized goodwill from historical acquisitions which must be tested for impairment at least annually or when indicators of impairment are present. The carrying value of Goodwill related to the Wind & Solar segment as at December 31, 2023 was $176 million and the recoverable amount of long-lived assets in the Wind & Solar segment that had indicators of impairment or impairment reversal during the year was $670 million. Determining the recoverable amounts for the Wind & Solar segment for the purposes of the goodwill impairment test and of certain CGUs in the Wind & Solar segment with indicators of impairment or impairment reversal (“Wind & 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 electricity production, sales prices, cost inputs, 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 & Solar segment and the Wind & 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 & Solar segment and the Wind & Solar CGUs with indicators of impairment or impairment reversal included, among others, comparing the significant assumptions used to estimate cash flows to current contracts with external parties and historical trends and obtaining historical electricity generation data to evaluate future electricity production 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 sales prices by comparing them to externally available third-party future electricity 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), 14 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, 2023 the fair value of the Company’s derivative financial instruments classified as level III was a $147 million net risk management liability. 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 prices, discount rates, credit value adjustments, liquidity and delivery volumes, and can fluctuate significantly depending on market conditions. Therefore, such determination of fair value was identified as a critical audit matter.
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 value adjustments, and liquidity assumptions to third-party data as well as comparing terms such as delivery volumes and timing to executed commodity contracts. We compared the delivery volume assumptions to historical information. We performed a sensitivity analysis to evaluate assumptions including future commodity prices, delivery volumes and discount rates. For a sample of level III derivative instruments, we involved our internal valuation specialist to assist in our evaluation of the appropriateness of the fair value 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 22, 2024

F7 TransAlta Corporation 2023 Integrated Report

Consolidated Statements of Earnings (Loss)

(in millions of Canadian dollars except where noted)

Year ended Dec. 31	2023	2022	2021
Revenues (Note 5)	3,355	2,976	2,721
Fuel and purchased power (Note 6)	1,060	1,263	1,054
Carbon compliance (Note 16)	112	78	178
Gross margin	2,183	1,635	1,489
Operations, maintenance and administration (Note 6)	539	521	511
Depreciation and amortization	621	599	529
Asset impairment charges (reversals) (Note 7)	(48)	9	648
Taxes, other than income taxes	29	33	32
Net other operating (income) loss (Note 8)	(47)	(58)	8
Operating income (loss)	1,089	531	(239)
Equity income (Note 9)	4	9	9
Finance lease income	12	19	25
Interest income	59	24	11
Interest expense (Note 10)	(281)	(286)	(256)
Foreign exchange gain (loss)	(7)	4	16
Gain on sale of assets and other	4	52	54
Earnings (loss) before income taxes	880	353	(380)
Income tax expense (Note 11)	84	192	45
Net earnings (loss)	796	161	(425)
Net earnings (loss) attributable to:
TransAlta shareholders	695	50	(537)
Non-controlling interests (Note 12)	101	111	112
	796	161	(425)
Net earnings (loss) attributable to TransAlta shareholders	695	50	(537)
Preferred share dividends (Note 28)	51	46	39
Net earnings (loss) attributable to common shareholders	644	4	(576)
Weighted average number of common shares outstanding in the year (millions)	276	271	271
Net earnings (loss) per share attributable to common shareholders, basic and diluted (Note 27)	2.33	0.01	(2.13)

See accompanying notes.

TransAlta Corporation 2023 Integrated Report F8

Consolidated Statements of Comprehensive Income (Loss)

(in millions of Canadian dollars)

Year ended Dec. 31	2023	2022	2021
Net earnings (loss)	796	161	(425)
Other comprehensive income (loss)
Net actuarial gains (losses) on defined benefit plans, net of tax(1)	(5)	37	37
Fair value loss on third-party investments, net of tax (Note 9)	—	(1)	—
Total items that will not be reclassified subsequently to net earnings (loss)	(5)	36	37
Gains (losses) on translating net assets of foreign operations, net of tax	(6)	21	(14)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax(2)	9	(25)	—
Gains (losses) on derivatives designated as cash flow hedges, net of tax(3)	41	(556)	(200)
Reclassification of (gains) losses on derivatives designated as cash flow hedges to net earnings (loss), net of tax(4)	58	100	(8)
Total items that will be reclassified subsequently to net earnings (loss)	102	(460)	(222)
Other comprehensive income (loss)	97	(424)	(185)
Total comprehensive income (loss)	893	(263)	(610)
Total comprehensive income (loss) attributable to:
TransAlta shareholders	817	(318)	(693)
Non-controlling interests (Note 12)	76	55	83
	893	(263)	(610)

(1)Net of income tax recovery of $1 million for the year ended Dec. 31, 2023 (2022 – $12 million expense, 2021 – $11 million expense).

(2)Net of income tax expense of $1 million for the year ended Dec. 31, 2023 (2022 – $3 million recovery, 2021 – nil).

(3)Net of income tax expense of $10 million for the year ended Dec. 31, 2023 (2022 – $138 million recovery, 2021 – $55 million recovery).

(4)Net of reclassification of income tax expense of $17 million for the year ended Dec. 31, 2023 (2022 – $26 million expense, 2021 – $2 million recovery).

See accompanying notes.

F9 TransAlta Corporation 2023 Integrated Report

Consolidated Statements of Financial Position

(in millions of Canadian dollars)

As at Dec. 31	2023	2022
Current assets
Cash and cash equivalents	348	1,134
Restricted cash (Note 24)	69	70
Trade and other receivables (Note 13)	807	1,589
Prepaid expenses and other	48	55
Risk management assets (Note 14 and 15)	151	709
Inventory (Note 16)	157	157
	1,580	3,714
Non-current assets
Investments (Note 9)	138	129
Long-term portion of finance lease receivables (Note 17)	171	129
Risk management assets (Note 14 and 15)	52	161
Property, plant and equipment (Note 18)	5,714	5,556
Right-of-use assets (Note 19)	117	126
Intangible assets (Note 20)	223	252
Goodwill (Note 21)	464	464
Deferred income tax assets (Note 11)	21	50
Other assets (Note 22)	179	160
Total assets	8,659	10,741
Current liabilities
Bank overdraft (Note 14)	3	16
Accounts payable and accrued liabilities (Note 13)	797	1,346
Current portion of decommissioning and other provisions (Note 23)	35	70
Risk management liabilities (Note 14 and 15)	314	1,129
Current portion of contract liabilities	3	8
Income taxes payable	9	73
Dividends payable (Note 27 and 28)	49	68
Current portion of long-term debt and lease liabilities (Note 24)	532	178
	1,742	2,888
Non-current liabilities
Credit facilities, long-term debt and lease liabilities (Note 24)	2,934	3,475
Exchangeable securities (Note 25)	744	739
Decommissioning and other provisions (Note 23)	654	659
Deferred income tax liabilities (Note 11)	386	352
Risk management liabilities (Note 14 and 15)	274	333
Contract liabilities	10	12
Defined benefit obligation and other long-term liabilities (Note 26)	251	294
Equity
Common shares (Note 27)	3,285	2,863
Preferred shares (Note 28)	942	942
Contributed surplus	41	41
Deficit	(2,567)	(2,514)
Accumulated other comprehensive loss (Note 29)	(164)	(222)
Equity attributable to shareholders	1,537	1,110
Non-controlling interests (Note 12)	127	879
Total equity	1,664	1,989
Total liabilities and equity	8,659	10,741

Commitments and contingencies (Note 36)

See accompanying notes.

On behalf of the Board:	John P. Dielwart Director	Bryan D. Pinney Chair of Audit, Finance and Risk Committee

TransAlta Corporation 2023 Integrated Report F10

Consolidated Statements of Changes in Equity

(in millions of Canadian dollars)

	Common shares	Preferred shares	Contributed surplus	Deficit	Accumulated other comprehensive income (loss)(1)	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	—	—	—	50	—	50	111	161
Other comprehensive income (loss):
Net losses on translating net assets of foreign operations, net of hedges and of tax	—	—	—	—	(4)	(4)	—	(4)
Net losses on derivatives designated as cash flow hedges, net of tax	—	—	—	—	(456)	(456)	—	(456)
Net actuarial gains on defined benefits plans, net of tax	—	—	—	—	37	37	—	37
Intercompany and third-party FVTOCI investments	—	—	—	—	55	55	(56)	(1)
Total comprehensive income (loss)	—	—	—	50	(368)	(318)	55	(263)
Common share dividends (Note 27)	—	—	—	(57)	—	(57)	—	(57)
Preferred share dividends (Note 28)	—	—	—	(46)	—	(46)	—	(46)
Shares purchased under NCIB program (Note 27)	(46)	—	—	(8)	—	(54)	—	(54)
Share-based payment plans and stock options exercised (Note 30)	8	—	(5)	—	—	3	—	3
Distributions declared to non-controlling interests (Note 12)	—	—	—	—	—	—	(187)	(187)
Balance, Dec. 31, 2022	2,863	942	41	(2,514)	(222)	1,110	879	1,989
Net earnings	—	—	—	695	—	695	101	796
Other comprehensive income (loss):
Net losses on translating net assets of foreign operations, net of hedges and tax	—	—	—	—	3	3	—	3
Net gains on derivatives designated as cash flow hedges, net of tax	—	—	—	—	99	99	—	99
Net actuarial gains on defined benefits plans, net of tax	—	—	—	—	(5)	(5)	—	(5)
Intercompany FVTOCI investments	—	—	—	—	25	25	(25)	—
Total comprehensive income	—	—	—	695	122	817	76	893
Common share dividends (Note 27)	—	—	—	(65)	—	(65)	—	(65)
Preferred share dividends (Note 28)	—	—	—	(51)	—	(51)	—	(51)
Shares purchased under normal course issuer bid ("NCIB") (Note 27)	(80)	—	—	(7)	—	(87)	—	(87)
Changes in non-controlling interests in TransAlta Renewables (Note 4)	510	—	—	(625)	(64)	(179)	(630)	(809)
Provision for repurchase of shares under the automatic share purchase plan (Note 27)	(19)	—	—	—	—	(19)	—	(19)
Share-based payment plans and stock options exercised (Note 30)	11	—	—	—	—	11	—	11
Distributions declared to non-controlling interests (Note 12)	—	—	—	—	—	—	(198)	(198)
Balance, Dec. 31, 2023	3,285	942	41	(2,567)	(164)	1,537	127	1,664

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

See accompanying notes.

F11 TransAlta Corporation 2023 Integrated Report

Consolidated Statements of Cash Flows

(in millions of Canadian dollars)

Year ended Dec. 31	2023	2022	2021
Operating activities
Net earnings (loss)	796	161	(425)
Depreciation and amortization (Note 37)	621	599	719
Gain on sale of assets and other	(3)	(32)	(54)
Accretion of provisions (Note 10 and 23)	48	49	32
Decommissioning and restoration costs settled (Note 23)	(37)	(35)	(18)
Deferred income tax expense (recovery) (Note 11)	34	127	(11)
Unrealized loss (gain) from risk management activities	(36)	385	(34)
Unrealized foreign exchange gain	(9)	(82)	(24)
Provisions and contract liabilities	(1)	19	(41)
Asset impairment charges (reversals) (Note 7)	(48)	9	648
Equity (income) loss, net of distributions from investments (Note 9)	2	(4)	(5)
Other non-cash items	(27)	(3)	40
Cash flow from operations before changes in working capital	1,340	1,193	827
Change in non-cash operating working capital balances (Note 33)	124	(316)	174
Cash flow from operating activities	1,464	877	1,001
Investing activities
Additions to property, plant and equipment (Note 18 and 37)	(875)	(918)	(480)
Additions to intangible assets (Note 20 and 37)	(13)	(31)	(9)
Restricted cash (Note 24)	1	—	(1)
Repayment (advances) from loan receivable (Note 22)	11	18	(3)
Acquisitions, net of cash acquired	—	(10)	(120)
Investments (Note 9)	(13)	(10)	—
Proceeds on sale of Pioneer Pipeline	—	—	128
Proceeds on sale of property, plant and equipment	29	66	39
Realized gain (loss) on financial instruments	18	27	(6)
Decrease in finance lease receivable	55	46	41
Other	(25)	45	(16)
Change in non-cash investing working capital balances	(2)	26	(45)
Cash flow used in investing activities	(814)	(741)	(472)
Financing activities
Net increase (decrease) in borrowings under credit facilities (Note 24 and 33)	(46)	449	(114)
Repayment of long-term debt (Note 24 and 33)	(164)	(621)	(92)
Issuance of long-term debt (Note 24 and 33)	39	532	173
Dividends paid on common shares (Note 27)	(58)	(54)	(48)
Dividends paid on preferred shares (Note 28)	(51)	(43)	(39)
Repurchase of common shares under NCIB (Note 27)	(87)	(52)	(4)
Proceeds on issuance of common shares	5	3	8
Realized gain (loss) on financial instruments	(30)	42	3
Acquisition of TransAlta Renewables (Note 4)	(811)	—	—
Distributions paid to subsidiaries' non-controlling interests (Note 12)	(223)	(187)	(156)
Decrease in lease liabilities (Note 24 and 33)	(10)	(9)	(8)
Financing fees and other	1	(13)	(4)
Change in non-cash financing working capital balances	3	(2)	(1)
Cash flow from (used in) financing activities	(1,432)	45	(282)
Cash flow from (used in) operating, investing and financing activities	(782)	181	247
Effect of translation on foreign currency cash	(4)	6	(3)
Increase (decrease) in cash and cash equivalents	(786)	187	244
Cash and cash equivalents, beginning of year	1,134	947	703
Cash and cash equivalents, end of year	348	1,134	947
Cash taxes paid	94	67	57
Cash interest paid	277	229	220
Cash interest received	54	20	7

See accompanying notes.

TransAlta Corporation 2023 Integrated Report F12

Notes to the 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. The Company's head office is located in Calgary, Alberta.

Operating Segments

Generation Segments

The four generation segments of the Company are as follows: Hydro, Wind and Solar, Gas, and Energy Transition. The Company directly or indirectly owns and operates hydro, wind and solar, natural gas-fired facilities, a coal-fired facility and natural gas pipeline operations in Canada, the United States (“US”) and Australia. Transmission in Canada is included within the Hydro segment while transmission in Australia is included in the Gas segment. The Wind and Solar segment includes the financial results, on a proportionate basis, of our investment in SP Skookumchuck Investment, LLC ("Skookumchuck"). Segment revenues are derived from the availability and production of electricity and steam as well as ancillary services.

Energy Marketing Segment

The Energy Marketing segment derives revenue and earnings from the trading of electricity, natural gas and environmental products across a variety of North American markets, excluding Alberta.

The Energy Marketing segment also performs services on behalf of certain assets outside of Alberta for the power marketing of available generating capacity as well as the procurement of the fuel and transmission needs for the fleet. Contracts of various durations for the forward sales of electricity and for the purchase of natural gas and transmission   capacity   are   utilized.   The   results   of   these

activities are included in the gross margin of the related generation segment. The Energy Marketing segment allocates charges to recognize the performance of these activities to the applicable generation segments.

Corporate Segment

The Corporate 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.

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. 22, 2024.

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.

F13 TransAlta Corporation 2023 Integrated Report

2. Material Accounting Policies

The Company has reviewed its material 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. Contract modifications are accounted for as separate contracts when the consideration for the additional promised goods reflects a stand-alone selling price. Otherwise, contract modifications are accounted for as part of the existing contract. If the additional goods are not considered distinct the transaction price can be affected and adjustments to previously recognized revenue can occur. If the additional goods are distinct, the existing and modified contracts are treated together as a new contract, with impacts reflected prospectively from the modification date, which can include the blending of contract prices. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the goods or services are 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 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 that has previously been constrained 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, the 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.

TransAlta Corporation 2023 Integrated Report F14

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 (e.g., 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 (e.g., 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 (e.g., 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.
Generation byproducts	Generation byproducts refers to the sale of byproducts from the use of coal in the Company’s current US and previous Canadian coal operations. 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) include 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.

F15 TransAlta Corporation 2023 Integrated Report

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 ("VPPA"). Contracts for differences are financial contracts whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh. A VPPA is whereby the Company receives the difference between the fixed contract price per MWh and the settled market price. These arrangements meet the definition of a derivative 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.

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 (loss) (“FVTOCI”).

Financial assets with contractual cash flows arising on specified dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows, are subsequently measured at amortized cost. Financial assets measured at FVTOCI are those that have contractual cash flows, arising on specific dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows and to sell the

financial asset and investments in equity instruments. 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 investor's investment is subsequently considered residual equity ownership with distributions classified as 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.

TransAlta Corporation 2023 Integrated Report F16

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.

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 income (loss) ("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.

F17 TransAlta Corporation 2023 Integrated Report

If cash flow hedge accounting is discontinued, the amounts previously recognized in accumulated other comprehensive income (loss) ("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 of 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 comprises cash and highly liquid investments with original maturities of three months or less.

D. Inventory

I. Fuel

The Company’s inventory balance is composed 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 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 and 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 at the estimated compliance cost required by the Company to settle its obligation in excess of government-established caps and targets. Compliance costs that are recoverable under the terms of the contracts with third parties are recognized as Revenue from Contracts with Customers.

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 if it is probable that future economic benefits will be realized and the cost of the item can be measured reliably. The cost of major spare parts is capitalized and classified as PP&E, as these items can only be used in connection with an item of PP&E.

Planned maintenance is performed at regular intervals. Planned major maintenance includes inspection, repair and maintenance of existing components and the replacement of existing components. Costs incurred for planned major maintenance activities are capitalized in the period maintenance activities occur and are amortized on a straight-line basis 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.

TransAlta Corporation 2023 Integrated Report F18

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. Insurance 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. 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	1-49 years
Wind and Solar generation	1-30 years
Gas generation	1-34 years
Energy Transition	1-9 years
Capital spares and other	1-49 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 composed of all directly attributable costs necessary to create, produce and prepare the intangible asset to be capable of operating in the manner intended by management.

Subsequent to initial recognition, intangible assets continue to be measured using the cost model and are reported at cost less accumulated amortization and impairment losses, if any. Amortization is included in depreciation and amortization 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	1-7 years
Power sale contracts	1-18 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

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taken into account. If no such transactions can be identified, an appropriate valuation model such as discounted cash flow 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. 

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 reassessed at each reporting date and are recognized 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 prorated based on service. The net interest cost is determined by applying the discount rate to the net defined benefit liability. The discount rate used to determine the present value of the defined benefit obligation and the net interest cost, is determined by reference to market yields at the end of the reporting period on high-quality corporate bonds with terms and currencies that match the estimated terms and currencies of the benefit obligations. Remeasurements, which include actuarial gains and losses and the return on plan assets (excluding net interest), are recognized through OCI in the period in which they occur. Actuarial gains and losses arise

TransAlta Corporation 2023 Integrated Report F20

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. 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.

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 for both the decommissioning and restoration provision and other provisions are charged to net earnings each period and is included in net interest expense.

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.

I. 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

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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.

II. Lessor

Power Purchase Agreements ("PPAs") and other long-term contracts may contain, or may be considered, leases where the fulfilment of the arrangement is dependent on the use of a specific asset (e.g., a generating unit) and the arrangement conveys to the customer the right to 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.

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 income (loss) is attributed to the non-controlling interests even if this results in the non-controlling interests having a negative balance.

When the proportion of the equity held by non-controlling interests changes, the carrying amounts of the controlling and non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiary. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received, is recognized directly in equity and attributed to shareholders.

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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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 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. 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.

F23 TransAlta Corporation 2023 Integrated Report

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 regard 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 2021 to 2023 is disclosed 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.

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. In 2023, a finance lease receivable was recognized as it was determined that the significant risks and rewards of ownership of the facilities were transferred to the customer. See Note 17.

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. Information regarding the impacts of the Company’s tax policies is disclosed in Note 11.

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. Transfers between levels of the fair value hierarchy are deemed to have occurred at             

TransAlta Corporation 2023 Integrated Report F24

the end of the reporting period in which the event or change in circumstances that caused the transfer occurred. These fair value levels are outlined and discussed in more detail in Note 14. 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 fulfilled.

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 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 when determining the amount to be capitalized. Information regarding project development costs is disclosed in Note 22 and 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). 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 to 2023 in respect of decommissioning and restoration provisions is disclosed in Notes 7, 18 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;

•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.

F25 TransAlta Corporation 2023 Integrated Report

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. Disclosures on employee future benefits are disclosed in Note 31.

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 8 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, to determine when this transfer occurs.

When contracts are modified, management must exercise judgment to determine, depending upon the facts and circumstances of the changes to the contract, whether the modification is accounted for as a new contract or as part of the existing contract. If it is required to be accounted for as part of the existing contract the transaction price can be affected and adjustments to previously recognized revenue can occur, or the impacts can be reflected prospectively from the modification date.

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, and this 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.

XII. Significant Influence

Upon entering into an investment, the Company must classify it as either an investment in 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, 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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XIII. Change in Estimates

During the year ended Dec. 31, 2023, there were changes in estimates relating to asset impairment charges (reversals) (Note 7), useful lives (Note 18), decommissioning and other provisions (Note 23) and defined benefit obligation (Note 26). During the year ended

Dec. 31, 2022, there were changes in estimates relating to asset impairment charges (reversals) (Note 7), asset useful lives and depreciation (Note 18), decommissioning and other provisions (Note 23) and defined benefit obligation (Note 26).

3. Accounting Changes

A. Current Accounting Changes

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

On May 7, 2021, the International Accounting Standards Board (“IASB”) issued Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction, which amends IAS 12 Income Taxes. 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, and were adopted by the Company on that date. The Company's accounting aligns with the amendment and no financial impact arose upon adoption.

Amendments to IAS 12 International Tax Reform — Pillar Two Model Rules

The Organization for Economic Co-operation and Development (OECD) published Pillar Two model rules in December 2021 to ensure that large multinational companies would be subject to a minimum 15 per cent tax rate. In May 2023, the IASB issued amendments to IAS 12 Income Taxes to provide companies with immediate temporary relief from accounting for deferred taxes arising from the OECD international tax reform. The amendments clarify that IAS 12 applies to income taxes arising from tax law enacted or substantively enacted to implement the Pillar Two model rules published by the OECD. Pillar Two legislation has not been enacted or substantively enacted in any jurisdiction in which the Company operates and therefore has not been reflected within our tax provisions at Dec. 31, 2023.

B. Future Accounting Changes

The Company closely monitors both new accounting standards and amendments to existing accounting standards issued by the IASB. The following standards have been issued but are not yet in effect.

Amendments to IAS 1 Non-current Liabilities with Covenants and Classification of Liabilities as Current or Non-current 

In October 2022, the IASB issued Non-current Liabilities with Covenants, which amends IAS 1 Presentation of Financial Statements, to clarify how conditions with which an entity must comply within 12 months after the reporting period affect the classification of a liability. In January 2020, the IASB issued Classification of Liabilities as Current or Non-current, which amends IAS 1 Presentation of Financial Statements regarding the classification of liabilities as current or non‐current, clarifying that contractual 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.

Additionally, the IASB clarified that the classification of a liability is unaffected by the likelihood that an entity will exercise its deferral right. The amendments are effective for annual periods beginning on or after Jan. 1, 2024, and are to be applied retrospectively. On Jan. 1, 2024, the Company will re-classify the Exchangeable Securities from non-current liabilities to current liabilities as the conversion option can be exercised at any time after Jan. 1, 2025, although there is no obligation to deliver cash equivalent resources and the holder cannot call for repayment. This accounting is consistent with the amendment.

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.

F27 TransAlta Corporation 2023 Integrated Report

4. Business Acquisitions

TransAlta to Acquire Heartland Generation

On Nov. 2, 2023, the Company announced that it had entered into a definitive share purchase agreement (the "Agreement") with an affiliate of Energy Capital Partners, the parent of Heartland Generation Ltd. and Alberta Power (2000) Ltd. (collectively, "Heartland"), pursuant to which TransAlta will acquire Heartland and its entire business operations in Alberta and British Columbia. The purchase price for the acquisition is $390 million, subject to working capital and other adjustments, as well as the assumption of $268 million of debt, for a total cost of $658 million. The Company will finance the transaction using cash on hand and draws on its credit facilities. Closing of the transaction remains subject to regulatory approval.

Acquisition of TransAlta Renewables

On Oct. 5, 2023, the Company completed the acquisition of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by the Company. The consideration paid totalled $1.3 billion, comprising $800 million of cash and 46 million common shares of the Company valued at $514 million, based on an $11.06 closing price of the Company’s shares on the Toronto Stock Exchange on Oct. 4, 2023.

Transaction costs of $11 million incurred to effect the acquisition, have been charged, net of income tax, against Common Shares ($4 million) and Deficit ($7 million) on closing of the acquisition.

Since the Company retained control of TransAlta Renewables, the acquisition was accounted for as an equity transaction. On closing of the transaction, Non-controlling Interests was reduced by $630 million and Accumulated Other Comprehensive Loss increased by $64 million to eliminate the balances previously attributed to non-controlling interest holders of TransAlta Renewables. The difference between consideration paid and these amounts was recognized in Deficit.

The Company's syndicated credit facilities were amended to effectively consolidate the TransAlta Renewables syndicated credit facility and non-committed demand facility into the TransAlta credit facilities. The cash drawings on the TransAlta Renewables' syndicated credit facility were repaid and the outstanding letters of credit were transferred to the TransAlta non-committed demand facility. The TransAlta Renewables' credit facilities were then terminated. This resulted in the TransAlta syndicated credit facility increasing by $700 million to approximately $2.0 billion. Refer to Note 24.

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5. Revenue

A. Disaggregation of Revenue

The majority of the Company's revenues are derived from the sale of 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, 2023	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Revenues from contracts with customers
Power and other	30	190	400	12	—	—	632
Environmental attributes(1)	14	26	—	—	—	—	40
Revenue from contracts with customers	44	216	400	12	—	—	672
Revenue from leases(2)	—	—	32	—	—	—	32
Revenue from derivatives and other trading activities(3)	44	(2)	(172)	251	220	—	341
Revenue from merchant sales	434	104	1,247	488	—	—	2,273
Other(4)	11	18	7	—	—	1	37
Total revenue	533	336	1,514	751	220	1	3,355
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	14	26	—	12	—	—	52
Over time	30	190	400	—	—	—	620
Total revenue from contracts with customers	44	216	400	12	—	—	672

(1)The environmental attributes represent environmental attribute sales not bundled with power and other sales.

(2)Total lease income from long-term contracts that meet the criteria of operating leases.

(3)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions.

(4) Other revenue includes production tax credits related to US wind facilities and other miscellaneous revenues.

F29 TransAlta Corporation 2023 Integrated Report

Year ended Dec. 31, 2022	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Revenues from contracts with customers
Power and other	33	220	462	10	—	—	725
Environmental attributes(1)	1	50	—	—	—	—	51
Revenue from contracts with customers	34	270	462	10	—	—	776
Revenue from leases(2)	—	—	32	—	—	—	32
Revenue from derivatives and other trading activities(3)	—	(121)	(821)	243	160	(2)	(541)
Revenue from merchant sales	564	119	1,529	461	—	—	2,673
Other(4)	8	21	7	—	—	—	36
Total revenue	606	289	1,209	714	160	(2)	2,976
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	1	50	—	12	—	—	63
Over time	33	220	462	(2)	—	—	713
Total revenue from contracts with customers	34	270	462	10	—	—	776

(1)The environmental attributes represent environmental attribute sales not bundled with power and other sales.

(2)Total lease income from long-term contracts that meet the criteria of operating leases.

(3)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions.

(4)Other revenue includes production tax credits related to US wind facilities and other miscellaneous revenues.

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Year ended Dec. 31, 2021	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Revenues from contracts with customers
Power and other	28	207	395	24	—	—	654
Environmental attributes(1)	—	28	—	—	—	—	28
Revenue from contracts with customers	28	235	395	24	—	—	682
Revenue from leases(2)	—	—	19	—	—	—	19
Revenue from derivatives and other trading activities(3)	—	(22)	(118)	138	211	4	213
Revenue from merchant sales	345	35	808	546	—	—	1,734
Other(4)	10	57	5	1	—	—	73
Total revenue	383	305	1,109	709	211	4	2,721
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)The environmental attributes represent environmental attribute sales not bundled with power and other sales.

(2)Total lease income from long-term contracts that meet the criteria of operating leases.

(3)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions.

(4)Other revenue includes production tax credits related to US wind facilities and other miscellaneous revenues.

B. Performance Obligations

The performance obligations in the Company's contracts with its customers include the provision of electricity and steam capacity; the delivery of electricity, thermal energy and environmental attributes; the provision of operation and maintenance services and water management services; and the supply of byproducts from coal generation.

The aggregate amount of transaction prices allocated to remaining performance obligations (contract revenues that have not yet been recognized) as at Dec. 31, 2023, is approximately $2,700 million, with approximately $510 million expected to be recognized during the period 2024-2026; $505 million for the period of 2027-2029; $725 million for the period of 2030-2034; and $960 million for 2035 and thereafter.

These amounts exclude revenues related to contracts that qualify for the invoice practical expedient and future revenues that are related to constrained variable consideration. 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. As a result, the amounts of future revenues disclosed above represent only a portion of future revenues that are expected to be realized by the Company from its contractual portfolio.

F31 TransAlta Corporation 2023 Integrated Report

6. Expenses by Nature

Fuel, Purchased Power and Operations, Maintenance and Administration ("OM&A")

Fuel and purchased power and OM&A expenses classified by nature are as follows:

Year ended Dec. 31	2023		2022		2021
	Fuel and purchased power	OM&A	Fuel and purchased power	OM&A	Fuel and purchased power	OM&A
Gas fuel costs	384	—	578	—	306	—
Coal fuel costs(1)	177	—	146	—	164	—
Royalty, land lease, other direct costs	25	—	25	—	19	—
Purchased power	474	—	514	—	339	—
Mine depreciation(2)	—	—	—	—	190	—
Salaries and benefits	—	254	—	263	36	234
Other operating expenses(3)	—	285	—	258	—	277
Total	1,060	539	1,263	521	1,054	511

(1)Included in coal fuel costs for 2021 was $17 million related to the impairment of coal inventory.

(2)Included in mine depreciation for 2021 was $48 million related to mine depreciation that was initially recorded in the standard cost of coal inventory and then subsequently written down during 2021.

(3)Included in OM&A costs for 2023 was $14 million related to the write-down of parts and material inventory related to our natural-gas-fired facilities. 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.

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7. Asset Impairment Charges (Reversals)

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 or fair value less costs of disposal) for the affected CGUs using discounted cash flow projections. The valuations are subject to measurement uncertainty from assumptions and inputs to the discount rates, power price forecasts, useful lives of the assets (extending to the last planned asset retirement in 2072) and long-range forecasts, which includes changes to production, fuel costs, operating costs and capital expenditures.

The Company recognized the following asset impairment charges (reversals):

Year ended Dec. 31	2023	2022	2021
Segments:
Hydro	(10)	21	5
Wind and Solar	(4)	43	12
Gas		—	5
Energy Transition	—	—	540
Corporate	—	(2)	27
Changes in decommissioning and restoration provisions on retired assets(1)	(34)	(53)	32
Intangible asset impairment charges - coal rights	—	—	17
Project development costs	—	—	10
Asset impairment charges (reversals)	(48)	9	648

(1)Changes relate to changes in discount rates and cash flow revisions on retired assets in 2023 and 2022 and cash flow revisions on retired assets in 2021. Refer to Note 23 for further details.

Hydro

During 2023, internal valuations indicated the fair value less costs of disposal for two hydro facilities exceeded the carrying value due to a contract extension and changes in power price assumptions, which favourably impacted estimated future cash flows and resulted in a recoverability test. As a result of the recoverability test an impairment reversal of $10 million was recognized. The recoverable amounts of $70 million in total were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement.

During 2022, the Company recorded net impairment charges of $21 million on four hydro facilities as a result of changes in key assumptions, that included significant increases in discount rates, changes in pricing and changes in estimated future cash flows. The recoverable amounts of $89 million in total for these four assets were estimated based on fair value less costs of disposal using a discounted cash flow approach and are categorized as a Level III fair value measurement.

Wind and Solar

During 2023, the Company recorded net impairment reversals of $4 million.

During the year, internal valuations indicated the fair value less costs of disposal of the assets exceeded the carrying value due to changes in power price assumptions for three wind facilities, which favourably impacted estimated future cash flows and resulted in impairment reversals of $17 million. The recoverable amounts of $540 million in total were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement.

Also in 2023, two wind facilities were impaired primarily due to unfavourable power price assumptions and changes in estimated future cash flows, resulting in a $13 million impairment charge. The recoverable amounts of $130 million for these two assets were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement.

F33 TransAlta Corporation 2023 Integrated Report

During 2022, the Company recorded net impairment charges of $43 million on five wind facilities and one solar facility as a result of changes in key assumptions, that included significant increases in discount rates, changes in pricing and changes in estimated future cash flows. The recoverable amounts of $754 million for these six assets were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and categorized as a Level III fair value measurement.

During 2021, the Company recorded impairment charges of $10 million for a wind asset as a result of an increase in estimated decommissioning costs after the review of an engineering study commissioned for the wind sites. The recoverable amount of $65 million was estimated based on

fair value less costs of disposal utilizing a discounted cash flow approach, using a discount rate of 5.0 per cent, and was categorized as a Level III fair value measurement.

Additionally, during 2021, the Company recognized impairment charges 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.

The calculation of fair value less costs of disposal for all of the above facilities is most sensitive to the following assumptions:

	Location of assets	Current year contract and merchant discount rates	Prior year contract and merchant discount rates
Wind and Solar	Canada	6.4 and 7.0 per cent	6.4 and 7.1 per cent
	US	6.9 and 7.5 per cent	6.5 and 7.7 per cent
Hydro	Canada	6.1 and 6.4 per cent	5.9 and 6.4 per cent

Energy Transition

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), and 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 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. Discounting did not have a material impact on 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 2021, with the expected closure of the Highvale mine at the end of 2021, it was determined that the estimated salvage value of the Highvale mine exceeded its 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 $195 million in the Energy Transition segment, with the asset being written down to salvage value.

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 impairment charges 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. During the fourth quarter of 2022, the dispute was settled. The Company reversed $2 million of the impairment loss previously recognized.

TransAlta Corporation 2023 Integrated Report F34

8. Net Other Operating (Income) Loss

Net other operating (income) loss includes the following:

Year ended Dec. 31	2023	2022	2021
Alberta Off-Coal Agreement	(40)	(40)	(40)
Liquidated damages recoverable	(6)	(12)	—
Insurance recoveries	(1)	(7)	—
Supplier, other contract settlements and other	—	1	34
Onerous contract provisions	—	—	14
Net other operating (income) loss	(47)	(58)	8

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.

Liquidated Damages Recoverable

During 2023, the Company recognized $3 million of recoverable liquidated damages related to requirements to be met by the contractor on turbine availability at the Windrise wind facility (2022 - $12 million) and $3 million for availability guarantees at other facilities (2022 - nil).

Insurance Recoveries

During 2023, the Company received insurance proceeds of $1 million related to the replacement costs for the single tower failure at the Kent Hills wind facilities (2022 - $7 million).

Supplier, Other Contract Settlements and Other

During 2021, $34 million was expensed related to decisions to suspend 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.

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.

F35 TransAlta Corporation 2023 Integrated Report

9. Investments

The change in investments is as follows:

	EMG	Skookumchuck	Tent Mountain	EIP	Ekona	Total
Classification	Equity-accounted	Equity-accounted	Equity-accounted	FVTPL	FVTOCI
Balance, Dec. 31, 2021	12	93	—	—	—	105
Investment	—	—	—	10	2	12
Equity income (loss)	(1)	10	—	—	—	9
Distributions received	—	(5)	—	—	—	(5)
Changes in foreign exchange rates	1	7	—	1	—	9
Net change in fair value recognized in OCI	—	—	—	—	(1)	(1)
Balance, Dec. 31, 2022	12	105	—	11	1	129
Investment	—	—	10	4	—	14
Equity income (loss)	(4)	8	—	—	—	4
Distributions received	—	(6)	—	—	—	(6)
Changes in foreign exchange rates	—	(3)	—	—	—	(3)
Balance, Dec. 31, 2023	8	104	10	15	1	138

Equity-accounted Investments

The Company’s investments in joint ventures and associates that are accounted for using the equity method consist of its investments in Skookumchuck, EMG and Tent Mountain Renewable Energy Complex (“Tent Mountain”).

EMG International, LLC ("EMG")

TransAlta holds a 30 per cent interest in EMG, a wastewater treatment processing company. Earnings are derived from the design and construction of wastewater treatment facilities. During 2022, the contingent purchase price consideration of US$3.5 million was paid, which was calculated based on actual earnings metrics achieved in 2021 and did not differ from the estimated amount included in the initial purchase price.

Skookumchuck Wind Project

TransAlta holds a 49 per cent membership interest in SP Skookumchuck Investment, LLC. Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state. The project has a 20-year PPA with Puget Sound Energy.

Tent Mountain Pumped Hydro Development Project

On April 24, 2023, the Company acquired a 50 per cent interest in Tent Mountain, an early-stage 320 MW pumped hydro energy storage development project, located in southwest Alberta, from Evolve Power Ltd. ("Evolve"), formerly known as Montem Resources Limited. The acquisition included land rights, fixed assets and intellectual property associated with the pumped hydro development project. The Company paid Evolve approximately $8 million on closing and made additional investments of $2 million during the balance of 2023. Additional contingent payments of up to $17 million may become payable to Evolve based on the achievement of specific development and commercial milestones. The Company and Evolve jointly control Tent Mountain, with the result that the Company accounts for its interest in the joint venture as an investment using the equity method.

TransAlta Corporation 2023 Integrated Report F36

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

Year ended Dec. 31	2023	2022	2021
Results of operations
Revenues and other operating income	22	24	19
Expenses	(18)	(15)	(10)
Proportionate share of net earnings	4	9	9

Other Investments

Energy Impact Partners

On May 6, 2022, the Company entered into a commitment to invest US$25 million over the next four years in Energy Impact Partners ("EIP") 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. The investment is accounted for at FVTPL.

Ekona Power Inc.

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 is being developed to produce cleaner and lower-cost turquoise hydrogen. The Company has irrevocably elected to measure its investment in Ekona at FVTOCI.

10. Interest Expense

The components of interest expense are as follows:

	2023	2022	2021
Interest on debt	203	164	163
Interest on exchangeable debentures (Note 25)	29	29	29
Interest on exchangeable preferred shares (Note 25)	28	28	28
Capitalized interest (Note 18)	(57)	(16)	(14)
Interest on lease liabilities	9	7	7
Credit facility fees, bank charges and other interest	21	27	20
Tax shield on tax equity financing (Note 24)	—	(2)	(9)
Accretion of provisions (Note 23)	48	49	32
Interest expense	281	286	256

F37 TransAlta Corporation 2023 Integrated Report

11. Income Taxes

Consolidated Statements of Earnings

I. Rate Reconciliation

Year ended Dec. 31	2023		2022		2021
Earnings (loss) before income taxes	880		353		(380)
Net earnings attributable to non-controlling interests not subject to tax	(80)		(94)		(33)
Adjusted earnings (loss) before income taxes	800		259		(413)
Statutory Canadian federal and provincial income tax rate (%)	23.4	%	23.4	%	23.6	%
Expected income tax expense (recovery)	187		61		(98)
Increase (decrease) in income taxes resulting from:
Differences in effective foreign tax rates	9		(1)		4
Non-deductible expense(1)	58		130		—
Taxable capital (gain) loss	(2)		18		—
Deferred income tax recovery related to temporary difference on investment in subsidiaries	(3)		(2)		—
Write-down (reversal of write-down) of unrecognized deferred income tax assets	(178)		(24)		134
Statutory and other rate differences	1		(3)		4
Adjustments in respect of deferred income tax of previous years	1		6		(4)
Other	11		7		5
Income tax expense	84		192		45
Effective tax rate (%)	11	%	74	%	(11	%)

(1)This amount is related to current and prior period tax adjustments in the US to mitigate cash tax relating to the Base Erosion and Anti-Abuse Tax.

TransAlta Corporation 2023 Integrated Report F38

II. Components of Income Tax Expense

The components of income tax expense are as follows:

Year ended Dec. 31	2023	2022	2021
Current income tax expense	50	65	56
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences	215	153	(145)
Deferred income tax recovery related to temporary difference on investment in subsidiaries	(3)	(2)	—
Write-down (reversal of write-down) of unrecognized deferred income tax assets(1)	(178)	(24)	134
Income tax expense	84	192	45
Current income tax expense	50	65	56
Deferred income tax expense (recovery)	34	127	(11)
Income tax expense	84	192	45

(1)During the year ended Dec. 31, 2023, the Company recognized deferred tax assets of $178 million (2022 - $24 million, 2021 - $134 million write-down). The deferred income tax assets mainly relate to the tax benefits associated with tax losses related to the Company's directly owned US operations and other deductible differences. The Company has not recognized an additional $157 million of deferred tax assets on the basis that it is not probable that sufficient future taxable income would be available to utilize these tax assets.

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	2023	2022	2021
Income tax expense (recovery) related to:
Net impact related to cash flow hedges	27	(112)	(57)
Net impact related to hedges of foreign operations	1	(3)	—
Net impact related to net actuarial gains (losses)	(1)	12	11
Transaction costs for the acquisition of TransAlta Renewables	(2)	—	—
Income tax expense (recovery) reported in equity	25	(103)	(46)

F39 TransAlta Corporation 2023 Integrated Report

Consolidated Statements of Financial Position

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

As at Dec. 31	2023	2022
Non-capital losses(1)	88	244
Future decommissioning and restoration costs	111	119
Property, plant and equipment	(605)	(553)
Risk management assets and liabilities, net	144	193
Employee future benefits and compensation plans	50	48
Foreign exchange differences on US-denominated debt	12	13
Other taxable temporary differences	(8)	(5)
Net deferred income tax asset (liability), before write-down of deferred income tax assets	(208)	59
Unrecognized deferred income tax assets	(157)	(361)
Net deferred income tax liability, after write-down of deferred income tax assets	(365)	(302)

(1)Non-capital losses expire between 2033 and 2043. Net operating losses from US operations have no expiration.

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

As at Dec. 31	2023	2022
Deferred income tax assets(1)	21	50
Deferred income tax liabilities	(386)	(352)
Net deferred income tax liability	(365)	(302)

(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.

Contingencies

As of Dec. 31, 2023, the Company had recognized a net liability of nil (2022 – nil) related to uncertain tax positions.

TransAlta Corporation 2023 Integrated Report F40

12. Non-Controlling Interests

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

Subsidiary / Operation	Non-controlling interest owner	Non-controlling interest as at Dec. 31, 2023	Non-controlling interest as at Dec. 31, 2022
TransAlta Cogeneration LP	Canadian Power Holdings Inc.	49.99%	49.99%
Kent Hills Wind LP	Natural Forces Technologies Inc.	17%	17%
TransAlta Renewables Inc.	Public shareholders	nil(1)	39.9%

(1)Non-controlling interest from Jan. 1, 2023 to Oct. 4, 2023 was 39.9%.

TransAlta Cogeneration, LP (“TA Cogen”) operates a portfolio of cogeneration facilities in Canada and owns 50 per cent of a dual-fuel generating facility.

Kent Hills Wind LP owns and operates the 167 MW Kent Hills (1, 2 and 3) wind facilities located in New Brunswick. Kent Hills Wind LP is a subsidiary of TransAlta Renewables Inc. ("TransAlta Renewables").

TransAlta Renewables owns 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. On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. TransAlta Renewables at Dec. 31, 2023, is a wholly owned subsidiary of the Company. Refer to Note 4 for more details.

Summarized financial information relating to subsidiaries with significant non-controlling interests is as follows:

TA Cogen

Year ended Dec. 31	2023	2022	2021
Revenues	290	347	265
Net earnings and total comprehensive income	121	143	103
Amounts attributable to the non-controlling interest:
Net earnings	80	91	62
Total comprehensive income	80	91	62
Distributions paid to Canadian Power Holdings Inc.	148	87	56

As at Dec. 31	2023	2022
Current assets	43	127
Long-term assets	193	253
Current liabilities	(41)	(62)
Long-term liabilities	(34)	(27)
Total equity	(161)	(291)
Equity attributable to Canadian Power Holdings Inc.	(79)	(147)
Non-controlling interest share (per cent)	49.99	49.99

F41 TransAlta Corporation 2023 Integrated Report

Kent Hills Wind LP

Prior to Oct 5, 2023, financial information related to the 17 per cent non-controlling interest in Kent Hills Wind LP was included in the financial information disclosed in TransAlta Renewables in this note.

Year ended Dec. 31	2023(1)
Revenues	7
Net earnings and total comprehensive income	2
Amounts attributable to the non-controlling interest:
Net earnings and total comprehensive income	—

(1)This represents financial information from Oct. 5, 2023 to Dec. 31, 2023. The net earnings attributable to non-controlling interest in Kent Hills Wind LP prior to Oct. 5, 2023, is included in the disclosures for TransAlta Renewables.

As at Dec. 31	2023
Current assets	35
Long-term assets	481
Current liabilities	(42)
Long-term liabilities	(188)
Total equity	(285)
Equity attributable to non-controlling interests	(48)
Non-controlling interest share (per cent)	17

TransAlta Renewables

The financial information disclosed below includes the 17 per cent non-controlling interest in Kent Hills Wind LP until Oct. 5, 2023.

Year ended Dec. 31	2023(1)	2022	2021
Revenues	303	560	470
Net earnings	56	74	139
Total comprehensive income (loss)	(7)	(67)	66
Amounts attributable to the non-controlling interests:
Net earnings	21	20	50
Total comprehensive income (loss)	(4)	(36)	21
Distributions paid to non-controlling interests	75	100	100

(1)Non-controlling interest share prior the close of the transaction on Oct. 5, 2023. This represents financial information from Jan. 1, 2023 to Oct. 4, 2023.

TransAlta Corporation 2023 Integrated Report F42

As at Dec. 31	2022
Current assets	240
Long-term assets	2,989
Current liabilities	(306)
Long-term liabilities	(1,118)
Total equity	(1,805)
Equity attributable to non-controlling interests	(732)
Non-controlling interests’ share (per cent)	39.9

13. Trade and Other Receivables and Accounts Payable

As at Dec. 31	2023	2022
Trade accounts receivable	600	1,165
Collateral provided (Note 15)	145	304
Current portion of finance lease receivables (Note 17)	19	52
Loan receivable (Note 22)	1	4
Income taxes receivable	42	64
Trade and other receivables	807	1,589

As at Dec. 31	2023	2022
Accounts payable and accrued liabilities	772	1,069
Interest payable	16	17
Collateral held (Note 15)	9	260
Accounts payable and accrued liabilities	797	1,346

F43 TransAlta Corporation 2023 Integrated Report

14. Financial Instruments

A. Financial Assets and Liabilities — Classification and Measurement

Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost.

Carrying value as at Dec. 31, 2023	Derivatives used for hedging	Derivatives held for trading (FVTPL)	Amortized cost	Other financial assets (FVTPL)	Other financial assets (FVOCI)	Total
Financial assets
Cash and cash equivalents(1)	—	—	348	—	—	348
Restricted cash	—	—	69	—	—	69
Trade and other receivables	—	—	807	—	—	807
Long-term portion of finance lease receivables	—	—	171	—	—	171
Long-term portion of loan receivable(2)	—	—	25	—	—	25
Other investments(3)	—	—	—	15	1	16
Risk management assets
Current	—	151	—	—	—	151
Long-term	—	52	—	—	—	52
Financial liabilities
Bank overdraft	—	—	3	—	—	3
Accounts payable and accrued liabilities	—	—	797	—	—	797
Dividends payable	—	—	49	—	—	49
Risk management liabilities
Current	125	189	—	—	—	314
Long-term	80	194	—	—	—	274
Credit facilities, long-term debt and lease liabilities(4)	—	—	3,466	—	—	3,466
Exchangeable securities	—	—	744	—	—	744

(1)Includes cash equivalents of nil.

(2)Included in other assets. Refer to Note 22.

(3)Included in investments. Refer to Note 9.

(4)Includes current portion.

TransAlta Corporation 2023 Integrated Report F44

Carrying value as at Dec. 31, 2022	Derivatives used for hedging	Derivatives held for trading (FVTPL)	Amortized cost	Other financial assets (FVTPL)	Other financial assets (FVTOCI)	Total
Financial assets
Cash and cash equivalents(1)	—	—	1,134	—	—	1,134
Restricted cash	—	—	70	—	—	70
Trade and other receivables	—	—	1,589	—	—	1,589
Long-term portion of finance lease receivables	—	—	129	—	—	129
Long-term portion of loan receivable(2)	—	—	33	—	—	33
Other investments(3)	—	—	—	11	1	12
Risk management assets
Current	—	709	—	—	—	709
Long-term	—	161	—	—	—	161
Financial liabilities
Bank overdraft	—	—	16	—	—	16
Accounts payable and accrued liabilities	—	—	1,346	—	—	1,346
Dividends payable	—	—	68	—	—	68
Risk management liabilities
Current	271	858	—	—	—	1,129
Long-term	76	257	—	—	—	333
Credit facilities, long-term debt and lease liabilities(4)	—	—	3,653	—	—	3,653
Exchangeable securities	—	—	739	—	—	739

(1)Includes cash equivalents of nil.

(2)Included in other assets. Refer to Note 22.

(3)Included in investments. Refer to Note 9.

(4)Includes current portion.

B. Fair Value of Financial Instruments

The fair value of a financial instrument is the price that would be received when selling the asset or paid to transfer the associated liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by observing quoted prices for the 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.

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. The Level III classification is the lowest level classification in the fair value hierarchy.

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.

F45 TransAlta Corporation 2023 Integrated Report

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 scenario analysis simulation 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. 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.

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.

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 segments 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, 2023, are as follows: Level I – $13 million net liability (Dec. 31, 2022 – $23 million net asset), Level II – $244 million net liability (Dec. 31, 2022 – $173 million net asset) and Level III – $147 million net liability (Dec. 31, 2022 – $782 million net liability).

Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2023, are primarily attributable to contract settlements and volatility in market prices across multiple markets on both existing contracts and new contracts.

TransAlta Corporation 2023 Integrated Report F46

The following table summarizes 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, 2023 and 2022, respectively:

	Year ended Dec. 31, 2023			Year ended Dec. 31, 2022
	Hedge	Non-hedge	Total	Hedge	Non-hedge	Total
Opening balance	(347)	(435)	(782)	285	(126)	159
Changes attributable to:
Market price changes on existing contracts	(123)	(6)	(129)	(611)	(298)	(909)
Market price changes on new contracts	—	18	18	—	(124)	(124)
Contracts settled	256	269	525	(38)	118	80
Change in foreign exchange rates	9	7	16	17	(5)	12
Transfers out of Level III(1)	205	—	205	—	—	—
Net risk management assets (liabilities) at end of year	—	(147)	(147)	(347)	(435)	(782)
Additional Level III information:
Losses recognized in other comprehensive loss	(114)	—	(114)	(594)	—	(594)
Total gains (losses) included in earnings before income taxes	(256)	19	(237)	38	(427)	(389)
Unrealized gains (losses) included in earnings before income taxes relating to net assets (liabilities) held at year end	—	288	288	—	(309)	(309)

(1)The Company has a long-term fixed price power sale contract in the US for delivery of power. The fair value of this instrument was transferred out of Level III to Level II as at Dec. 31, 2023 as the forward price curve is now based on observable market prices for the remaining duration of the contract.

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 processes. 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, the 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.

As at Dec. 31, 2023, the total Level III risk management asset balance was $56 million (Dec. 31, 2022 – $31 million) and Level III risk management liability balance was $203 million (Dec. 31, 2022 – $813 million). The net risk management liabilities decreased mainly due to market price changes and settled contracts. 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 are outlined in the following table. 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.

F47 TransAlta Corporation 2023 Integrated Report

As at	Dec. 31, 2023
Description	Valuation technique	Unobservable input	Reasonably possible change	Sensitivity(1)
Coal transportation – US	Numerical derivative valuation	Volatility	80% to 120%	+6
		Rail rate escalation	zero to 10%	-4
Full requirements – Eastern US	Scenario analysis	Volume	96% to 104%	+3
		Cost of supply	Decrease of $2.30 per MWh or increase of $2.40 per MWh	-3
Long-term wind energy sale – Eastern US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease or increase of US$6	+24
		Illiquid future REC prices (per unit)	Price decrease of US$12 or increase of US$8
		Wind discounts	0% decrease or 9% increase	-28
Long-term wind energy sale – Canada	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of C$81 or increase of C$5	+65
		Wind discounts	16% decrease or 5% increase	-23
Long-term wind energy sale - Central US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$1 or increase of US$2	+81
		Wind discounts	5% decrease or 2% increase	-36

(1)Sensitivity represents the total increase or decrease in recognized fair value that could arise from the use of the reasonably possible changes of all unobservable inputs.

TransAlta Corporation 2023 Integrated Report F48

As at	Dec. 31, 2022
Description	Valuation technique	Unobservable input	Reasonably possible change	Sensitivity(1)
Coal transportation – US	Numerical derivative valuation	Illiquid future power prices (per MWh)	Price decrease of US$5 or increase of US$55	+14
		Volatility	80% to 120%
		Rail rate escalation	zero to 10%	-13
Full requirements - Eastern US	Scenario analysis	Volume	96% to 104%	+3
		Cost of supply	Decrease of US$0.50 per MWh or increase of US$3.30 per MWh	-21
Long-term wind energy sale – Eastern US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease or increase of US$6	+22
		Illiquid future REC prices (per unit)	Price decrease or increase of US$2
		Wind discounts	0% decrease or 5% increase	-18
Long-term wind energy sale – Canada	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of C$85 or increase of C$5	+47
		Wind discounts	28% decrease or 5% increase	-25
Long-term wind energy sale – Central US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease or increase of US$2	+74
		Wind discounts	2% decrease or 5% increase	-28
Long-term power sale – US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$5 or increase of US$55	+15
				-163

(1)Sensitivity represents the total increase or decrease in recognized fair value that would arise from the use of the reasonably possible changes of all unobservable inputs.

a. 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.

The key unobservable inputs used in the valuation include option volatility and rail rate escalation. Option volatility and rail rate escalation ranges have been determined based on historical data and professional judgment.

In the first three quarters of 2023, non-liquid power prices were also used as a key unobservable input. At Dec. 31, 2023, the relevant forward power prices were observable in the market.

b. 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.

c. Long-Term Wind Energy Sale – Eastern US

The Company is party to a long-term contract for differences ("CFD") for the offtake of 100 per cent of the generation from its 90 MW Big Level wind facility. The CFD, together with the sale of electricity generated into the PJM Interconnection at the prevailing real-time energy market price, achieve the fixed contract price per MWh on proxy generation. Under the CFD, if the market price is lower than the fixed contract price the customer pays the Company the difference and if the market price is higher than the fixed contract price the Company refunds the difference to the customer. The customer is also entitled to the physical delivery of environmental attributes. The contract matures in December 2034. The contract is accounted for as a derivative. Changes in fair value are presented in revenue.

F49 TransAlta Corporation 2023 Integrated Report

The key unobservable inputs used in the valuation of the contract are expected proxy generation volumes and non-liquid forward prices for power, RECs and wind discounts.

d. Long-Term Wind Energy Sale – Canada

The Company is party to two Virtual Power Purchase Agreements ("VPPAs") for the offtake of 100 per cent of the generation from its 130 MW Garden Plain wind facility. The VPPAs, together with the sale of electricity generated into the Alberta power market at the pool price, achieve the fixed contract prices per MWh. Under the VPPAs, if the pool price is lower than the fixed contract price the customer pays the Company the difference and if the pool price is higher than the fixed contract price the Company refunds the difference to the customer. The customers are also entitled to the physical delivery of environmental attributes. Both VPPAs commenced on commercial operation of the facility which was achieved in August 2023, and extend for a weighted average of approximately 17 years.

The energy components of these contracts are accounted for as derivatives. Changes in fair value are presented in revenue.

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

e. Long-Term Wind Energy Sale – Central US

The Company is party to two long-term VPPAs for the offtake of 100 per cent of the generation from its 300 MW White Rock East and White Rock West wind power projects. The VPPAs, together with the sale of electricity generated into the US Southwest Power Pool ("SPP") market at the relevant price nodes, achieve the fixed contract prices per MWh. Under the VPPAs, if the SPP pricing is lower than the fixed contract price the customers pay the Company the difference, and if the SPP pricing is higher than the fixed contract price, the Company refunds the difference to the customers. The customer is also entitled to the physical delivery of environmental attributes. During the fourth quarter of 2023, the Company and the customer for the White Rock wind projects amended the associated VPPAs. The VPPAs commence on commercial operation of the facilities.

The Company is also party to a VPPA for the offtake of 100 per cent of the generation from its 200 MW Horizon Hill wind power project. The VPPA, together with the sale of electricity generated into the SPP market at the relevant price node, achieve the fixed contract price per MWh. Under the VPPA, if the SPP pricing is lower than the fixed contract price the customer pays the Company the difference and if the SPP pricing is higher than the fixed contract price the Company refunds the difference to the customer. The customer remains entitled to the physical delivery of environmental attributes. During the second quarter of 2023, the Company and the customer for the

Horizon Hill wind project amended the associated VPPA. The VPPA commences on commercial operation of the facility. Commissioning of the Horizon Hill wind project is expected during the first quarter of 2024.

The energy components of these contracts are accounted for as derivatives. Changes in fair value are presented in revenue. The amendments to the Horizon Hill and White Rock VPPAs did not change the nature of the contracts and the energy components continue to be accounted for as derivatives.

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

f. 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.

At Dec. 31, 2023, the contract was transferred to Level II as all significant inputs were observable. In the first three quarters of 2023, the term of the transaction extended beyond where the relevant forward power prices were observable in the market.

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 $19 million as at Dec. 31, 2023 (Dec. 31, 2022 – $6 million net liability) are classified as Level II fair value measurements. The changes in other net risk management assets and liabilities during the year ended Dec. 31, 2023, are attributable to favourable market price changes on existing contracts, favourable foreign exchange rates on new contracts entered into during 2023, and contracts settled during 2023.

TransAlta Corporation 2023 Integrated Report F50

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, 2023	—	718	—	718	744
Long-term debt — Dec. 31, 2023	—	3,104	—	3,104	3,323
Loan receivable — Dec. 31, 2023	—	26	—	26	26
Exchangeable securities — Dec. 31, 2022	—	685	—	685	739
Long-term debt — Dec. 31, 2022	—	3,200	—	3,200	3,518
Loan receivable — Dec. 31, 2022	—	37	—	37	37

(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 provided, bank overdraft, accounts payable and accrued liabilities, collateral held and dividends payable) approximates fair value due to the liquid nature of the asset or liability. The fair values of the finance lease receivables approximate the carrying amounts as 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 14 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 (loss) and a reconciliation of changes is as follows:

As at Dec. 31	2023	2022	2021
Unamortized net loss at beginning of year	(213)	(131)	(33)
New inception gains (losses)(1)	47	(37)	(79)
Change resulting from amended contract(2)	190	—	—
Change in foreign exchange rates	6	(10)	—
Amortization recorded in net earnings during the year	(27)	(35)	(19)
Unamortized net gain (loss) at end of year	3	(213)	(131)

(1)During 2023, the Company entered into long-term fixed price power sale contracts with certain of its US customers and as a result recognized day one inception gains that are based on the forward price curve at the inception of the contract. During 2022, the Company entered into a PPA for the Horizon Hill wind project (2021 – PPAs for the White Rock wind projects) that resulted in new inception losses 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 PPA.

(2)During 2023, the Company entered into certain contract amendments related to the Horizon Hill and White Rock wind projects. These amendments were mainly specific to obtaining price increases over the contract term. Accordingly, certain inception loss calibration adjustments were recognized within the risk management liability.

F51 TransAlta Corporation 2023 Integrated Report

15. 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.

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.

TransAlta Corporation 2023 Integrated Report F52

B. Net Risk Management Assets and Liabilities

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

As at Dec. 31, 2023
	Cash flow hedges	Not designated as a hedge	Total
Commodity risk management
Current	(125)	(53)	(178)
Long-term	(80)	(146)	(226)
Net commodity risk management liabilities	(205)	(199)	(404)
Other
Current	—	15	15
Long-term	—	4	4
Net other risk management assets	—	19	19
Total net risk management liabilities	(205)	(180)	(385)

As at Dec. 31, 2022
	Cash flow hedges	Not designated as a hedge	Total
Commodity risk management
Current	(271)	(143)	(414)
Long-term	(76)	(96)	(172)
Net commodity risk management liabilities	(347)	(239)	(586)
Other
Current	—	(6)	(6)
Long-term	—	—	—
Net other risk management liabilities	—	(6)	(6)
Total net risk management liabilities	(347)	(245)	(592)

F53 TransAlta Corporation 2023 Integrated Report

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, 2023	Gross amounts of recognized financial assets (liabilities)	Amounts set off	Net amounts included on the statement of financial position	Master netting arrangements(1)	Net amount
Current risk management assets	528	(355)	173	(7)	166
Long-term risk management assets	161	(91)	70	(2)	68
Current risk management liabilities	(504)	355	(149)	7	(142)
Long-term risk management liabilities	(145)	91	(54)	2	(52)
Trade and other receivables(2)	789	(646)	143	(11)	132
Accounts payable and accrued  liabilities(2)	(760)	646	(114)	11	(103)

As at Dec. 31, 2022	Gross amounts of recognized financial assets (liabilities)	Amounts set off	Net amounts included on the statement of financial position	Master netting arrangements(1)	Net amount
Current risk management assets	1,602	(883)	719	(62)	657
Long-term risk management assets	204	(43)	161	(7)	154
Current risk management liabilities	(1,953)	883	(1,070)	62	(1,008)
Long-term risk management liabilities	(449)	43	(406)	7	(399)
Trade and other receivables(2)	1,330	(934)	396	(176)	220
Accounts payable and accrued liabilities(2)	(1,344)	934	(410)	176	(234)

(1)Amounts not set off in the Consolidated Statements of Financial Position.

(2)The trade and other receivables and accounts payable and accrued liabilities include amounts related to collateral provided and held. Refer to Note 15(F) below for further details.

TransAlta Corporation 2023 Integrated Report F54

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, the VPPAs and other long-term contracts that are derivatives 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 predefined 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, including a long-term physical power sale contract, and may, at times, execute hedges for its electricity price exposure in Alberta using fixed price financial swaps or other similar instruments. Both hedging strategies fall under the Company’s risk management strategy used to hedge commodity price risk.

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. Position sizes and trade strategies were adjusted to remain within the Company's risk framework.

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.

Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes occur. VaR at Dec. 31, 2023, associated with the Company’s proprietary trading activities was $4 million (2022 – $4 million, 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 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.

F55 TransAlta Corporation 2023 Integrated Report

VaR at Dec. 31, 2023, associated with the Company’s commodity derivative instruments used in generation hedging activities was $23 million (2022 – $97 million, 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 in the period in which the price change occurs. VaR at Dec. 31, 2023, associated with these transactions was $16 million (2022 – $45 million, 2021 – $34 million). For the market risk related to long-term power sale and long-term

wind energy sales contracts, refer to the Level III measurements table and the related unobservable inputs and sensitivities in Note 14(B)(II).

iii. Commodity Price Risk Management – Hedges

At Dec. 31, 2023, the Company had no outstanding commodity derivative instruments designated as hedging instruments, except for the long-term power sale - US contract. For further details on this contract, refer to Note 14(B)(II)(i).

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	2023		2022
Type (thousands)	Notional amount sold	Notional amount purchased	Notional amount sold	Notional amount purchased
Electricity (MWh)	54,043	12,628	55,821	13,934
Natural gas (GJ)	50,949	209,348	23,464	162,384
Transmission (MWh)	—	856	—	1,643
Emissions (MWh)	212	804	274	2,297
Emissions (tonnes)	4,450	5,125	300	300
Coal (tonnes)	—	5,172	—	7,746

TransAlta Corporation 2023 Integrated Report F56

b. Interest Rate Risk Management

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

The Company's syndicated 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 14 per cent of the Company’s total long-term debt as at Dec. 31, 2023 (2022 – 15 per cent). Interest rate risk is managed with the use of derivatives.

Interbank Offered Rate 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 term and credit facilities with $400 million outstanding (2022 – $433 million) reference the Canadian Dollar Offered Rate ("CDOR") for Canadian-dollar drawings, but include appropriate fallback language to replace this benchmark rate in the event of a benchmark transition. The Poplar Creek non-recourse bond with a face value as at Dec. 31, 2023 of $86 million (2022 – $95 million) pays interest based upon the three-month CDOR. Cessation of the three-month CDOR is anticipated to occur mid-2024.

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

•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. 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 (2022 – US$370 million).

ii. Non-Hedges

The Company also uses foreign currency contracts to manage its expected foreign operating cash flows and foreign exchange forward contracts to manage foreign exchange exposure on foreign-denominated debt not designated as a net investment hedge. Hedge accounting is not applied to these foreign currency contracts.

As at Dec. 31	2023			2022
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
AUD125	CAD113	(1)	2024-2027	AUD183	CAD168	(1)	2023-2026
USD828	CAD1,113	19	2024-2027	USD573	CAD761	(12)	2023-2025
USD100	AUD152	5	2024	USD66	AUD102	4	2023
Foreign exchange forward contracts – foreign-denominated debt
CAD190	USD140	(4)	2024	CAD159	USD120	3	2023

F57 TransAlta Corporation 2023 Integrated Report

iii. 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 cents (2022 – three cents, 2021 – three cents) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter.

Year ended Dec. 31	2023		2022		2021
Currency	Net earnings decrease(1)	OCI gain(1)(2)	Net earnings increase (decrease)(1)	OCI gain(1)(2)	Net earnings decrease(1)	OCI gain(1)(2)
USD	(11)	—	(12)	—	(13)	1
AUD	(3)	—	(2)	—	1	—
Total	(14)	—	(14)	—	(12)	1

(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, 2023:

	Investment grade  (per cent)	Non-investment grade  (per cent)	Total  (per cent)	Total amount
Trade and other receivables(1)	95	5	100	807
Long-term finance lease receivable	100	—	100	171
Risk management assets(1)	75	25	100	203
Loans receivable(2)	—	100	100	26
Total				1,207

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

(2)Includes $26 million loans receivable included within other assets with counterparties that have no external credit rating.

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.

TransAlta Corporation 2023 Integrated Report F58

The Company did not have material expected credit losses as at Dec. 31, 2023.

The Company’s maximum exposure to credit risk at Dec. 31, 2023, 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, 2023, was $23 million (Dec. 31, 2022 – $64 million).

III. Liquidity Risk

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. As at Dec. 31, 2023, TransAlta maintains an investment grade rating from one credit rating agency and one notch below investment grade ratings from two credit rating agencies. Between 2024 and 2026, the Company has $400 million of debt maturing, and an

additional $411 million of scheduled non-recourse debt principal payments.

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.

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 Audit, Finance and Risk Committee (on behalf of 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:

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Bank overdraft	3	—	—	—	—	—	3
Accounts payable and accrued liabilities	797	—	—	—	—	—	797
Long-term debt(1)
Credit facilities(1)	400	—	—	—	—	—	400
Debentures	—	—	—	—	—	251	251
Senior notes	—	—	—	—	—	924	924
Non-recourse – Hydro	—	—	—	—	—	39	39
Non-recourse – Wind & Solar	66	69	67	70	75	289	636
Non-recourse and other – Gas	46	58	61	65	66	707	1,003
Tax equity financing	14	15	15	18	21	27	110
Exchangeable securities(2)	—	—	—	—	—	750	750
Commodity risk management liabilities	169	123	15	12	12	73	404
Other risk management assets	(16)	(3)	—	—	—	—	(19)
Lease liabilities(3)	4	4	4	4	4	123	143
Interest on long-term debt and lease liabilities(4)	186	167	158	151	143	711	1,516
Interest on exchangeable securities(2)(4)	53	53	53	53	53	13	278
Dividends payable	49	—	—	—	—	—	49
Total	1,771	486	373	373	374	3,907	7,284

(1)Excludes impact of hedge accounting and derivatives.

(2)Cash payment could occur after Dec. 31, 2028 if exchangeable securities are not exchanged by Brookfield Renewable Partners or its affiliates (collectively "Brookfield"). At Brookfield's option, the exchangeable securities can be exchanged, at the earliest, on Jan. 1, 2025 (Note 25).

(3)Lease liabilities exclude a lease incentive of $12 million expected to be received in 2024, which is recognized in trade and other receivables.

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

F59 TransAlta Corporation 2023 Integrated Report

IV. Equity Price Risk

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.

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
	2024	2025	2026	2027	2028	2029
Cash flow hedges
Commodity derivative instruments
Electricity
Notional amount (thousands of MWh)	3,338	2,628	—	—	—	—
Average price ($ per MWh)	78.18	80.13	—	—	—	—

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, 2023	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(1)	5,966	(205)	Risk management liabilities	(114)
Foreign currency risk
Net investment hedges
Foreign-denominated debt	USD370	CAD489	Credit facilities, long-term debt and lease liabilities	—

(1)In thousands of MWh.

TransAlta Corporation 2023 Integrated Report F60

As at Dec. 31, 2022	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(1)	9,295	(347)	Risk management liabilities	(594)
Foreign currency risk
Net investment hedges
Foreign-denominated debt	USD370	CAD502	Credit facilities, long-term debt and lease liabilities	—

(1)In thousands of MWh.

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

As at Dec. 31	2023		2022
	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	(114)	(129)	(594)	(279)
	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	—	(36)	—	(39)

(1)Net of tax. Included in AOCI.

The hedging gain or 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.

The impact of designated cash flow hedges on OCI and net earnings is:

Year ended Dec. 31, 2023
		Effective portion		Ineffective portion
Derivatives in cash flow  hedging relationships	Pre-tax gain recognized in OCI	Location of gain 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	51	Revenue	83	Revenue	—
Forward starting interest rate swaps	—	Interest expense	(8)	Interest expense	—
OCI impact	51	OCI impact	75	Net earnings impact	—

F61 TransAlta Corporation 2023 Integrated Report

Over the next 12 months, the Company estimates that approximately $89 million of after-tax losses 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, 2022
		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	(747)	Revenue	124	Revenue	—
Forward starting interest rate swaps	53	Interest expense	2	Interest expense	—
OCI impact	(694)	OCI impact	126	Net earnings impact	—

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 reclassified from 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	—

II. Effect of Non-Hedges

For the year ended Dec. 31, 2023, the Company recognized a net unrealized loss of $44 million (2022 – loss of $384 million, 2021 – gain of $97 million) related to commodity derivatives.

For the year ended Dec. 31, 2023, a gain of $11 million (2022 – gain of $20 million, 2021 – gain of $6 million) related to foreign exchange and other derivatives was recognized, which consists of net unrealized gains of $27 million (2022 – loss of $11 million, 2021 – gain of $4 million) and net realized losses of $16 million (2022 – gains of $31 million, 2021 – gains of $2 million), respectively.

F. Collateral

I. Financial Assets Provided as Collateral

At Dec. 31, 2023, the Company provided $145 million (Dec. 31, 2022 – $304 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 within trade and other receivables in the Consolidated Statements of Financial Position. At Dec. 31, 2023, the Company provided $19 million (Dec. 31, 2022 - $6 million) in surety bonds as security for commodity trading activities.

TransAlta Corporation 2023 Integrated Report F62

II. Financial Assets Held as Collateral 

At Dec. 31, 2023, the Company held $9 million (Dec. 31, 2022 – $260 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 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.

At Dec. 31, 2023, the Company had posted collateral of $392 million (Dec. 31, 2022 – $820 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 could result in the Company having to post an additional $154 million (Dec. 31, 2022 – $594 million) of collateral to its counterparties.

16. Inventory

The components of inventory are as follows:

As at Dec. 31	2023	2022
Parts, materials and supplies	72	83
Coal	38	43
Emission credits	45	27
Natural gas	2	4
Total	157	157

No inventory was pledged as security for liabilities.

As at Dec. 31, 2023, the Company holds 962,548 emission credits in inventory that were purchased externally with a recorded book value of $45 million (Dec. 31, 2022 – 963,068 emission credits with a recorded book value of $27 million). The Company also has 3,121,837 (Dec. 31, 2022 – 3,619,450) of internally generated eligible emission credits from the Company's Wind and Solar and Hydro segments which have no recorded book value. This includes the eligible emission performance credits earned by the Alberta Hydro facilities formerly under dispute that has now been resolved. Refer to Note 36 for details.

Emission credits can be sold externally or can be used to offset future emission obligations from our gas facilities located in Alberta, where the compliance price of carbon is expected to increase, resulting in a reduced cash cost for carbon compliance in the year of settlement.

In June 2023, the Company settled the 2022 carbon compliance obligation in cash. The compliance price of carbon for the 2022 obligation settled was $50 per tonne. It increased to $65 per tonne in 2023.

During 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 was recognized as a reduction in the Company's carbon compliance costs in 2022.

F63 TransAlta Corporation 2023 Integrated Report

17. Finance Lease Receivables

Amounts receivable under the Company’s finance leases include the Northern Goldfields solar facilities (2023), the Poplar Creek cogeneration facility (2023 and 2022) and the Southern Cross Energy facilities (2022), and are as follows:

As at Dec. 31	2023		2022
	Minimum lease receipts	Present value of minimum lease receipts	Minimum lease receipts	Present value of minimum lease receipts
Within one year	28	28	62	55
Second to fifth years inclusive	112	98	81	75
More than five years	117	64	60	51
	257	190	203	181
Less: unearned finance lease income	67	—	22	—
Total finance lease receivables	190	190	181	181
Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease receivables (Note 13)	19		52
Long-term portion of finance lease receivables	171		129
Total finance lease receivables	190		181

On Nov. 22, 2023, the Northern Goldfields solar facilities achieved commercial operation. As a result, the Company derecognized assets under construction and recognized a finance lease receivable of $61 million.

TransAlta Corporation 2023 Integrated Report F64

18. Property, Plant and Equipment

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

	Assets under construction	Land	Hydro	Wind and Solar	Gas generation	Energy Transition	Capital spares and other(1)	Total
Cost
As at Dec. 31, 2021	184	96	867	3,276	4,087	4,513	366	13,389
Additions(2)	891	—	—	—	—	—	6	897
Additions from development projects	17	—	—	—	—	—	12	29
Disposals	—	(3)	—	—	(1)	(216)	—	(220)
Impairment (charges) reversals (Note 7)	2	—	(21)	(43)	—	—	—	(62)
Changes to decommissioning and restoration costs (Note 23)	—	—	(15)	(59)	(12)	10	2	(74)
Retirement of assets	—	—	(9)	(9)	(12)	(7)	(2)	(39)
Change in foreign exchange rates	13	—	—	45	(4)	97	2	153
Transfers of assets(3)	(144)	—	18	23	472	(423)	(7)	(61)
As at Dec. 31, 2022	963	93	840	3,233	4,530	3,974	379	14,012
Additions(2)	869	—	—	—	—	—	6	875
Disposals	—	(3)	—	—	—	(30)	—	(33)
Impairment reversals (Note 7)	—	—	10	4	—	—	—	14
Changes to decommissioning and restoration costs (Note 23)	—	—	3	14	(22)	3	(1)	(3)
Retirement of assets	—	—	(7)	(18)	(124)	(7)	(108)	(264)
Change in foreign exchange rates	(26)	—	—	(18)	(7)	(42)	(1)	(94)
Transfers of assets(3)	(572)	—	38	439	50	16	31	2
Transfers to finance lease receivable (Note 17)	—	—	—	(61)	(4)	—	—	(65)
As at Dec. 31, 2023	1,234	90	884	3,593	4,423	3,914	306	14,444
Accumulated depreciation
As at Dec. 31, 2021	—	—	468	1,093	2,178	4,150	180	8,069
Depreciation	—	—	21	130	308	63	16	538
Retirement of assets	—	—	(8)	(6)	(10)	(7)	(2)	(33)
Disposals	—	—	—	—	(1)	(211)	—	(212)
Change in foreign exchange rates	—	—	—	11	2	89	—	102
Transfers of assets(3)	—	—	(3)	—	335	(340)	—	(8)
As at Dec. 31, 2022	—	—	478	1,228	2,812	3,744	194	8,456
Depreciation	—	—	25	129	342	73	16	585
Retirement of assets	—	—	(4)	(15)	(101)	(7)	(108)	(235)
Disposals	—	—	—	—	—	(30)	—	(30)
Change in foreign exchange rates	—	—	—	(5)	(3)	(39)	—	(47)
Transfers in (out) of PP&E(3)	—	—	—	—	(1)	2	—	1
As at Dec. 31, 2023	—	—	499	1,337	3,049	3,743	102	8,730
Carrying amount
As at Dec. 31, 2021	184	96	399	2,183	1,909	363	186	5,320
As at Dec. 31, 2022	963	93	362	2,005	1,718	230	185	5,556
As at Dec. 31, 2023	1,234	90	385	2,256	1,374	171	204	5,714

(1)Includes major spare parts and standby equipment available, but not in service.

(2)In 2023, the Company capitalized $57 million (2022 – $16 million) of interest to PP&E in at a weighted average rate of 6.3 per cent (2022 – 6.0 per cent).

(3)Includes transfers of assets upon commissioning to assets in service and other movements.

F65 TransAlta Corporation 2023 Integrated Report

Assets under Construction

During the year, the Company achieved commercial operations on the Garden Plain wind facility and the Northern Goldfields solar and battery storage facilities. Costs were transferred from assets under construction to the Wind and Solar segment. In addition, the Kent Hills Foundation Rehabilitation project was substantially completed and the costs were transferred to the Wind and Solar segment.

Change in Estimate - Useful Lives

During 2023, the Company adjusted the useful lives of certain assets in the Gas segment to reflect changes to the

future operating expectations of the assets. This resulted in a decrease of $92 million in depreciation expense that was recognized in the Consolidated Statement of Earnings (Loss) in 2023.

During 2022, the Company adjusted the useful lives of certain assets included in the Gas segment to reflect changes to the future operating expectations of the assets. This resulted in an increase of $132 million in depreciation expense that was recognized in the Consolidated Statement of Earnings (Loss) in 2022.

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	Total
As at Dec. 31, 2021	68	20	1	6	95
Additions	36	—	1	3	40
Depreciation	(4)	(5)	—	(2)	(11)
Change in foreign exchange rates	2	—	—	—	2
As at Dec. 31, 2022	102	15	2	7	126
Additions	2	2	1	—	5
Depreciation	(5)	(5)	—	(2)	(12)
Change in foreign exchange rates	(2)	—	—	—	(2)
As at Dec. 31, 2023	97	12	3	5	117

For the year ended Dec. 31, 2023, TransAlta paid $19 million (2022 – $16 million) related to recognized lease liabilities, consisting of $10 million (2022 – $9 million) of principal repayments and $9 million (2022 – $7 million) of interest expense.

Short-term leases (term of less than 12 months) and leases with total lease payments below the Company's capitalization threshold (low value leases) do not require recognition as lease liabilities and right-of-use assets. For the year ended Dec. 31, 2023, the Company expensed $1 million (2022 – $2 million and 2021 – nil) related to short-term and low value leases.

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, 2023, the Company expensed $8 million (2022 – $8 million and 2021 – $6 million) in variable land lease payments for these leases.

TransAlta Corporation 2023 Integrated Report F66

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, 2021	269	422	4	132	827
Additions	—	—	31	—	31
Change in foreign exchange rates	3	3	1	—	7
Transfers	—	12	(9)	—	3
As at Dec. 31, 2022	272	437	27	132	868
Additions	—	—	13	—	13
Asset impairment charges	—	(1)	—	—	(1)
Change in foreign exchange rates	(2)	(2)	(1)	—	(5)
Transfers	—	12	(12)	—	—
As at Dec. 31, 2023	270	446	27	132	875
Accumulated amortization
As at Dec. 31, 2021	140	299	—	132	571
Amortization	17	26	—	—	43
Change in foreign exchange rates	1	1	—	—	2
As at Dec. 31, 2022	158	326	—	132	616
Amortization	17	21	—	—	38
Change in foreign exchange rates	(1)	(1)	—	—	(2)
As at Dec. 31, 2023	174	346	—	132	652
Carrying amount
As at Dec. 31, 2021	129	123	4	—	256
As at Dec. 31, 2022	114	111	27	—	252
As at Dec. 31, 2023	96	100	27	—	223

F67 TransAlta Corporation 2023 Integrated Report

21. Goodwill

Goodwill acquired through business combinations has been allocated to groups of CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments is as follows:

As at Dec. 31	2023	2022
Hydro	258	258
Wind and Solar	176	176
Energy Marketing	30	30
Total goodwill	464	464

For the purposes of the 2023 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 projections. In 2023, the Company relied on the recoverable amounts determined in 2022 for the Hydro and Energy Marketing segments in performing the 2023 goodwill impairment review. The recoverable amounts are based on the Company's long-range forecasts for the periods extending to the last planned asset retirement in 2072. The resulting fair value measurements are categorized within Level III of the fair value hierarchy. No impairment of goodwill arose for any segment.

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

•Discount rates used ranged from 5.9 per cent to 8.2 per cent (2022 – 5.9 per cent to 8.2 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.

•Forecasts of 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. Merchant electricity prices used in the Hydro and Wind and Solar models ranged between $20 to $238 per MWh during the forecast period (2022 – $28 to $233 per MWh).

TransAlta Corporation 2023 Integrated Report F68

22. Other Assets

The components of other assets are as follows:

As at Dec. 31	2023	2022
South Hedland prepaid transmission access and distribution costs	60	61
Long-term prepaids and other assets	41	40
Project development costs	35	10
Loans receivable	26	37
Transmission infrastructure	18	16
Total Other assets	180	164
Included in the Consolidated Statements of Financial Position as:
Total current other assets (Note 13)	1	4
Total long-term other assets	179	160
Total Other assets	180	164

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.

Long-term prepaids and other assets include the TransAlta Energy Transition Bill commitment and other contractually required prepayments and deposits. 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 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 termination and in certain circumstances, this funding or portion thereof would no longer be required. As of Dec. 31, 2023, the Company has fully funded the commitment.

Project development costs primarily include the pre-construction project costs for projects.

At Dec. 31, 2023, $25 million of the loans receivable (2022 – $37 million) is an unsecured loan related to an advancement by the Company's subsidiary, Kent Hills Wind LP, of the net financing proceeds of the Kent Hills Wind Bond ("KH Bonds"), to its 17 per cent partner. The loan bears interest at 4.55 per cent, with interest payable quarterly. No scheduled principal repayments are required until the maturity date of October 2027. However, repayments may be required for amounts associated with foundation replacement capital expenditures and for operating account funding, as outlined in the amendment made to the KH Bonds. During 2023, the Company received repayments of $12 million that were required as part of the waiver and amendment made to the KH Bonds (2022 - $18 million).

Transmission infrastructure was constructed by the Company and then transferred to a transmission provider upon completion. The balance relates to the Garden Plain and Windrise wind facilities and will be amortized to net earnings (loss) over the useful life of the facilities.

F69 TransAlta Corporation 2023 Integrated Report

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, 2021	793	34	827
Liabilities incurred	1	23	24
Liabilities settled	(35)	(12)	(47)
Accretion	49	—	49
Disposals	(5)	—	(5)
Revisions in estimated cash flows	95	5	100
Revisions in discount rates	(225)	—	(225)
Reversals	—	(9)	(9)
Change in foreign exchange rates	15	—	15
Balance, Dec. 31, 2022	688	41	729
Liabilities incurred	1	4	5
Liabilities settled	(37)	(13)	(50)
Accretion (Note 10)	47	1	48
Revisions in estimated cash flows	(89)	—	(89)
Revisions in discount rates	52	—	52
Change in foreign exchange rates	(6)	—	(6)
Balance, Dec. 31, 2023	656	33	689

Included in the Consolidated Statements of Financial Position as:
As at	Dec. 31, 2023	Dec. 31, 2022
Current portion	35	70
Non-current portion	654	659
Total Decommissioning and other provisions	689	729

TransAlta Corporation 2023 Integrated Report F70

A. Decommissioning and Restoration

A provision has been recognized for all generating facilities and mines for which TransAlta is legally, or constructively, required to remove the facilities at the end of their useful lives and restore the sites to their original condition. TransAlta estimates that the undiscounted amount of cash flow required to settle these obligations is approximately $1.7 billion, which will be incurred between 2024 and 2072. The majority of the costs will be incurred between 2024 and 2050.

During 2023, the decommissioning and restoration provision decreased by $89 million due to revisions in estimated cash flows and timing of cash flows for certain Gas and Energy Transition assets. The timing of cash flows was adjusted to optimize and maximize efficiencies by staging required reclamation work. Operating assets included in PP&E decreased by $34 million and $55 million was recognized as an impairment reversal in net earnings related to retired assets.

During 2023, revisions in discount rates increased the decommissioning and restoration provision by $52 million due to a decrease in discount rates, largely driven by decreases in long-term market benchmark rates. On average, discount rates decreased compared to 2022, with rates ranging from 6.0 to 9.0 per cent as at Dec. 31, 2023. This has resulted in a corresponding increase in PP&E of $31 million on operating assets and the recognition of a $21 million impairment charge in net earnings related to retired assets.

During 2022, the Company accelerated the expected timing on decommissioning and restoration for certain facilities. This increased the decommissioning and restoration provision by $95 million, of which $46 million increased operating assets in PP&E and $49 million was recognized as an impairment charge in net earnings related to retired assets.

During 2022, the decommissioning and restoration provision decreased by $225 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 7.0 to 9.7 per cent as at Dec. 31, 2022. This has resulted in a corresponding decrease in PP&E of $123 million on operating assets and the recognition of a $102 million impairment reversal in net earnings related to retired assets.

At Dec. 31, 2023, the Company has provided a surety bond in the amount of US$147 million (2022 – US$147 million) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2023, the Company had provided a surety bond and letters of credit in the amount of $188 million (2022 – $187 million) in support of future decommissioning obligations at the Highvale mine.

B. Other Provisions

Other provisions include provisions arising from ongoing business activities, amounts related to commercial disputes between the Company and customers or suppliers and onerous contract provisions. 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.

F71 TransAlta Corporation 2023 Integrated Report

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

A. Amounts Outstanding

The amounts outstanding are as follows:

As at Dec. 31				2023				2022
	Segment	Maturity	Currency	Carrying value	Face value	Interest(1)		Carrying value	Face value	Interest
Credit facilities
Committed syndicated bank facility(2)	Corporate	2027	CAD	—	—	—		32	33	4.7	%
Term Facility	Corporate	2024	CAD	397	400	7.4	%	396	400	6.5	%
Debentures
7.3% Medium term notes	Corporate	2029	CAD	110	110	7.3	%	110	110	7.3	%
6.9% Medium term notes	Corporate	2030	CAD	141	141	6.9	%	141	141	6.9	%
Senior notes(3)
7.8% Senior notes(4)	Corporate	2029	USD	520	528	7.8	%	533	542	7.8	%
6.5% Senior notes	Corporate	2040	USD	391	396	6.5	%	401	407	6.5	%
Non-recourse
Melancthon Wolfe Wind LP bond	Wind & Solar	2028	CAD	168	169	3.8	%	202	203	3.8	%
New Richmond Wind LP bond	Wind & Solar	2032	CAD	103	104	4.0	%	112	113	4.0	%
Kent Hills Wind LP bond	Wind & Solar	2033	CAD	193	196	4.5	%	206	209	4.5	%
Windrise Wind LP bond	Wind & Solar	2041	CAD	164	167	3.4	%	170	173	3.4	%
Pingston bond	Hydro	2043	CAD	39	39	6.2	%	45	45	3.0	%
TAPC Holdings LP bond (Poplar Creek)	Gas	2030	CAD	85	86	9.4	%	94	95	8.9	%
TEC Hedland PTY Ltd bond(5)	Gas	2042	AUD	691	699	4.1	%	711	720	4.1	%
TransAlta OCP LP bond	Gas	2030	CAD	217	218	4.5	%	241	242	4.5	%
Tax equity financing
Big Level & Antrim(6)	Wind & Solar	2029	USD	91	97	6.6	%	102	108	6.6	%
Lakeswind(7)	Wind & Solar	2029	USD	10	10	10.5	%	15	15	10.5	%
North Carolina Solar(8)	Wind & Solar	2028	USD	3	3	7.3	%	6	6	7.3	%
Other(9)	Corporate		CAD	—	—	—		1	1	5.9	%
Total long-term debt				3,323	3,363			3,518	3,563
Lease liabilities(10)				143				135
Total long-term debt and lease liabilities				3,466				3,653
Less: current portion of long-term debt				(526)				(170)
Less: current portion of lease liabilities				(6)				(8)
Total current long-term debt and lease liabilities				(532)				(178)
Total non-current credit facilities, long-term debt and lease liabilities				2,934				3,475

(1)Interest rate reflects the stipulated rate or the average rate weighted by principal amounts outstanding and 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, 2023 – US$700 million (2022 – US$700 million).

(4)The effective interest rate for the senior notes is 5.98 per cent after the effects of gains realized on settled interest rate hedging instruments.

(5)AU face value at Dec. 31, 2023 – AU$773 million (2022 – AU$786 million).

(6)US face value at Dec. 31, 2023 – US$73 million (2022 – US$79 million).

(7)US face value at Dec. 31, 2023 – US$8 million (2022 – US$11 million).

(8)US face value at Dec. 31, 2023 – US$2 million (2022 – US$5 million).

(9)Other debt consisted of an unsecured commercial loan obligation that matured and was repaid in 2023.

(10)At Dec. 31, 2023, lease liabilities exclude a lease incentive of $12 million expected to be received in 2024, which is recognized in trade and other receivables.

TransAlta Corporation 2023 Integrated Report F72

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

As at Dec. 31, 2023		Utilized
Credit Facilities	Facility size	Outstanding letters of credit(1)	Cash drawings	Available capacity	Maturity date
Committed
TransAlta syndicated credit facility	1,950	417	—	1,533	Q2 2027
TransAlta bilateral credit facilities	240	178	—	62	Q2 2025
TransAlta Term Facility	400	—	400	—	Q3 2024
Total Committed	2,590	595	400	1,595
Non-Committed
TransAlta demand facilities	400	187	—	213	N/A
Total Non-Committed	400	187	—	213

(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. Letters of credit drawn against the non-committed facilities reduce the available capacity under the committed syndicated credit facilities. At Dec. 31, 2023, TransAlta provided cash collateral of $145 million.

These facilities are the primary source of short-term liquidity after the cash flow generated from the Company's business.

The acquisition of TransAlta Renewables resulted in the TransAlta syndicated credit facility increasing by $700 million to approximately $2.0 billion, effectively consolidating the TransAlta Renewables syndicated credit facility into the TransAlta syndicated credit facility. Refer to Note 4 for more details.

The Company is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. The $187 million letters of credit are issued from non-committed demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities. In addition to the $1.4 billion of committed capacity available under the credit facilities, the Company also had $345 million of available cash and cash equivalents, net of bank overdraft.

Senior Notes

On Nov. 15, 2022, the Company repaid the US$400 million 4.5 per cent unsecured senior notes on maturity in addition to related fees and expenses.

On Nov. 17, 2022, the Company issued US$400 million senior notes, which have a fixed coupon rate of 7.75 per cent per annum and mature on Nov. 15, 2029. Including the effects of settled interest rate swaps, the notes have an effective yield of approximately 5.982 per cent. The notes are unsecured and 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 interest payments on the bonds are made semi-annually, on November 15 and May 15 with the first payment commencing May 15, 2023. TransAlta is

required to allocate an amount equal to the net proceeds from this offering to finance or, refinance new and/or existing eligible green projects in accordance with its Green Bond Framework.

A total of US$370 million (2022 – US$370 million) of the senior notes have been designated as a hedge of the Company’s net investment in US operations.

Non-Recourse Debt

On May 8, 2023, the Pingston Power Inc. non-recourse bond matured with a total aggregate repayment of $46 million, consisting of accrued interest and principal.

On Sept. 14, 2023, the Company closed a non-recourse bond financing for approximately $39 million ("Pingston bond") as a replacement for the non-recourse bond that matured on May 8, 2023. The Pingston bond is secured by a first ranking charge over all the respective assets of the Company's subsidiaries that issued the bonds, amortizes and bears interest at a rate of 6.145 per cent per annum, payable semi-annually, and matures on May 8, 2043. The Pingston bond is subject to customary financing conditions and covenants that may restrict the Company's ability to access funds generated by the facility's operations.

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 financings, 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

F73 TransAlta Corporation 2023 Integrated Report

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 are 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 in December 2029; Lakeswind in March 2029 and North Carolina Solar in December 2028.

Other

TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2023, the Company was in compliance with all debt covenants.

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

The Melancthon Wolfe Wind LP, Pingston Power Inc., TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd and Windrise Wind LP non-recourse bonds and the TransAlta OCP LP bond, with a total carrying value of $1.7 billion as at Dec. 31, 2023 (2022 – $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 2023, with the exception of Kent Hills Wind LP and TAPC Holdings LP. Kent Hills Wind cannot make any distributions to its partners until the foundation work is completed. TAPC Holdings LP has been impacted by higher interest rates in 2023. The 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 2024. At Dec. 31, 2023, $79 million (2022 – $50 million) of cash was subject to these financial restrictions.

At Dec. 31, 2023, $3 million (AU$3 million) of funds held by TEC Hedland Pty Ltd 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.

C. Security

Non-recourse debts totalling $1.4 billion as at Dec. 31, 2023 (2022 – $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, 2023 (2022 – $1.5 billion) and intangible assets with total carrying amounts of $61 million (2022 – $70 million). At Dec. 31, 2023, a non-recourse bond of approximately $85 million (2022 – $94 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 $217 million (2022 – $241 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.

TransAlta Corporation 2023 Integrated Report F74

D. Principal Repayments

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Principal repayments(1)	526	142	143	153	162	2,237	3,363
Lease liabilities(2)	4	4	4	4	4	123	143

(1)Excludes impact of hedge accounting and derivatives.

(2)Lease liabilities exclude a lease incentive of $12 million, expected to be received in 2024, which is recognized in trade and other receivables.

E. Restricted Cash

As at Dec. 31, 2023, the Company had $17 million (2022 – $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 scheduled future debt repayments. The Company also had $52 million (2022 – $53 million) of restricted cash related to the TEC Hedland Pty Ltd bond. These cash reserves are required to be held under commercial arrangements and for debt service, which may be replaced by letters of credit in the future.

F. Letters of Credit

Letters of credit issued by TransAlta are drawn on its $2.0 billion committed syndicated credit facility, its $240 million bilateral committed credit facilities and its $400 million uncommitted demand facilities. TransAlta has drawn $417 million on its committed syndicated credit facility, $178 million on its bilateral committed credit facilities and $187 million on its uncommitted demand facilities.

Letters of credit are issued to counterparties as required by 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. 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, 2023, was $782 million (2022 – $1,175 million) with nil (2022 – nil) amounts exercised by third parties under these arrangements.

G. Currency Impacts

The weakening of the US dollar has decreased the US-denominated long-term debt balances, mainly the senior notes and tax equity financing, by $27 million as at Dec. 31, 2023 (2022 – increased $41 million due to the strengthening 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 balance by approximately $9 million as at Dec. 31, 2023 (2022 – $9 million). As this debt is issued by an Australian subsidiary, the foreign currency translation impacts are recognized within other comprehensive income (loss).

F75 TransAlta Corporation 2023 Integrated Report

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").

A. $750 Million Exchangeable Securities

As at	Dec. 31, 2023				Dec. 31, 2022
	Carrying value	Face value	Interest		Carrying value	Face value	Interest
Exchangeable debentures – due May 1, 2039(1)	344	350	7	%	339	350	7	%
Exchangeable preferred shares(2)	400	400	7	%	400	400	7	%
Total exchangeable securities	744	750			739	750

(1)Seven per cent unsecured subordinated debentures due May 1, 2039.

(2)Redeemable, retractable first preferred shares (Series I). Exchangeable preferred share dividends are reported as interest expense.

On Dec. 11, 2023, the Company declared a dividend of $7 million, in aggregate, for the Exchangeable Preferred Shares at the fixed rate of 1.764 per cent, per share, payable on Feb. 28, 2024. The Exchangeable Preferred

Shares are considered debt for accounting purposes and, as such, dividends are reported as interest expense (Note 10).

B. Option to Exchange

As at	Dec. 31, 2023		Dec. 31, 2022
Description	Base fair value	Sensitivity	Base fair value	Sensitivity
Option to exchange – embedded derivative	—	+nil -25	—	+nil -25

The Investment Agreement allows Brookfield the option to exchange all of the outstanding exchangeable securities after Dec. 31, 2024, 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 one 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, 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 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.

In connection with the Investment Agreement, Brookfield is entitled to nominate two directors for election to the Board.

TransAlta Corporation 2023 Integrated Report F76

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	2023	2022
Defined benefit obligation (Note 31)	155	150
Retail power contract liability	83	126
Other	13	18
Total	251	294

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. The defined benefit obligation has increased by $5 million to $155 million as at Dec. 31, 2023, from $150 million as at Dec. 31, 2022.

During 2023, the Company made a voluntary contribution of $4 million (US$3 million) to improve the funded status of the US Defined Benefit Pension Plan for the Centralia thermal facility.

During 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 and to support the employees affected by the closure of the Highvale mine in 2021 and our transition off-coal to cleaner sources. The contribution reduces the amount of the Company's future funding obligations, including amounts secured by the letters of credit.

A one per cent increase in discount rates would result in a $40 million decrease in the defined benefit obligation. Refer to Note 31 for additional sensitivities impacting the defined benefit obligation.

On Dec. 1, 2022, the Company closed a purchase and sale agreement for customer retail contracts to deliver power and gas, along with power and gas financial swaps. The Company accounted for the purchase as an asset acquisition and allocated values to risk management assets of $139 million (Level II valuation) and retail power contract liabilities of $129 million within the Gas segment. The retail power contract liabilities acquired represent certain off-market retail power customer contracts for which fair value was determined as the present value of the amount by which contract terms deviated from the terms that a market participant could have achieved at the closing date. The retail contract liability is amortized to depreciation over the remaining term of the contracts based on volumes that will be delivered each month.

F77 TransAlta Corporation 2023 Integrated Report

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	2023		2022
	Common shares  (millions)	Amount	Common shares (millions)	Amount
Issued and outstanding, beginning of period	268.1	2,863	271.0	2,901
Purchased and cancelled under the NCIB	(7.5)	(80)	(4.3)	(46)
Share-based payment plans	0.8	6	0.9	5
Stock options exercised	0.7	5	0.5	3
Issued for acquisition of TransAlta Renewables(1) (Note 4)	46.5	510	—	—
Issued and outstanding, end of year, prior to ASPP	308.6	3,304	268.1	2,863
Provision for repurchase of common shares under ASPP	(1.7)	(19)	—	—
Issued and outstanding, end of year	306.9	3,285	268.1	2,863

(1)Net of $4 million of transaction costs.

B. Normal Course Issuer Bid ("NCIB") Program

The effects of the Company's purchase and cancellation of common shares during the period are as follows:

For the year ended Dec. 31	2023	2022
Total shares purchased(1)	7,537,500	4,342,300
Average purchase price per share	11.49	12.48
Total cost (millions)	87	54
Book value of shares cancelled	80	46
Amount recorded in deficit	(7)	(8)

(1)At Dec. 31, 2023, includes 181,800 (2022 - 164,300) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. As a result, $2 million (2022 - $2 million) was paid subsequent to the year end.

2023

On May 26, 2023, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.29 per cent of its public float of common shares as at May 17, 2023. 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, 2023, and ends on May 30, 2024.

On Dec. 19, 2023, the Company entered into an Automatic Share Purchase Plan ("ASPP") which permits an independent broker to repurchase shares under the NCIB during the first quarter blackout period through to the end

of the ASPP. The Company has recognized a provision of $19 million for the repurchase of common shares under the ASPP within accounts payables and accrued liabilities as at Dec. 31, 2023, as a estimate of the maximum number of shares that could be repurchased during the blackout period.

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.

TransAlta Corporation 2023 Integrated Report F78

2022

On May 24, 2022, the TSX accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 17, 2022.

C. Shareholder Rights Plan 

The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 28, 2022. 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 28, 2022, and will need to be approved at the annual meeting of shareholders

in 2025. 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.

D. Earnings per Share

Year ended Dec. 31	2023	2022	2021
Net earnings (loss) attributable to common shareholders	644	4	(576)
Basic and diluted weighted average number of common shares outstanding (millions)	276	271	271
Net earnings (loss) per share attributable to common shareholders, basic and diluted	2.33	0.01	(2.13)

E. Dividends

On Nov. 21, 2023, the Company declared a quarterly dividend of $0.06 per common share, payable on April 1, 2024.

There have been no transactions involving common shares between the reporting date and the date of completion of these Consolidated Financial Statements.

F79 TransAlta Corporation 2023 Integrated Report

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	2023		2022
Series(1)	Number of shares  (millions)	Amount	Number of shares (millions)	Amount
Series A	9.6	235	9.6	235
Series B	2.4	58	2.4	58
Series C	10.0	243	10.0	243
Series D	1.0	26	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)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

I. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion

On June 30, 2022, the Company converted 1,044,299 of its 11.0 million Cumulative Redeemable Rate Reset First Preferred Shares, Series C (“Series C Shares”), on a one-for-one basis, into Cumulative Redeemable Floating Rate First Preferred Shares, Series D (“Series D Shares”).

The Series C Shares pay fixed cumulative preferential cash dividends on a quarterly basis, for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The annual fixed dividend rate is 5.854 per cent, being equal to the five-year Government of Canada bond yield of 2.754 per cent determined as of May 31, 2022, plus 3.10 per cent, in accordance with the terms of the Series C Shares.

The Series D Shares pay quarterly floating rate cumulative preferential cash dividends for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The quarterly dividend rate for the Series D Shares is established each quarter, and is equal to the annual rate for the auction of 90-day Government of Canada Treasury Bills, plus 3.10 per cent, in accordance with the terms of the Series D Shares.

II. Series E Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion

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 per cent, 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.

TransAlta Corporation 2023 Integrated Report F80

Preferred Share Series Information 

The holders are entitled to receive cumulative fixed quarterly cash dividends at specified rates, as approved by the Board. After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed rate resets to the sum of the then five-year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified spread. Upon each Rate Reset Date, 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, 2023, are as follows:

Series(1)	Rate during term	Annual dividend rate per share ($)(2)	Next conversion date	Rate spread over benchmark  (per cent)	Convertible to Series
A	Fixed	0.71924	March 31, 2026	2.03	B
B	Floating	1.718910	March 31, 2026	2.03	A
C	Fixed	1.46352	June 30, 2027	3.10	D
D	Floating	1.98695	June 30, 2027	3.10	C
E	Fixed	1.72352	Sept. 30, 2027	3.65	F
G	Fixed	1.24700	Sept. 30, 2024	3.80	H

(1)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

(2)The annual dividend rate per share represents dividends declared in 2023.

B. Dividends

The following table summarizes the preferred share dividends declared in 2023 and 2022:

	Total dividends declared
Series	2023(1)	2022(1)
A	7	7
B(2)	4	3
C	15	14
D(3)	2	1
E	15	13
G	8	8
Total for the year	51	46

(1)No dividends were declared in the first quarter of the year as the quarterly dividend related to the period covering the first quarter was declared in December of the prior year.

(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.

(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 Dec. 11, 2023, the Company declared a quarterly dividend of $0.17981 per share on the Series A preferred shares, $0.43958 per share on the Series B preferred shares, $0.36588 per share on the Series C preferred

shares, $0.50609 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 March 31, 2024.

F81 TransAlta Corporation 2023 Integrated Report

29. Accumulated Other Comprehensive Loss

The components of and changes in, accumulated other comprehensive loss are as follows:

	2023	2022
Currency translation adjustment
Opening balance, Jan. 1	(39)	(35)
(Losses) gains on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax	(6)	21
Gains (losses) on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax(1)	9	(25)
Balance, Dec. 31	(36)	(39)
Cash flow hedges
Opening balance, Jan. 1	(228)	228
Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax(2)	99	(456)
Balance, Dec. 31	(129)	(228)
Employee future benefits
Opening balance, Jan. 1	8	(29)
Net actuarial gains on defined benefit plans, net of tax(3)	(5)	37
Balance, Dec. 31	3	8
Other
Opening balance, Jan. 1	37	(18)
Change in ownership of TransAlta Renewables	(64)	—
Intercompany and third-party investments at FVTOCI	25	55
Balance, Dec. 31	(2)	37
Accumulated other comprehensive loss	(164)	(222)

(1)Net of income tax expense of $1 million for the year ended Dec. 31, 2023 (Dec. 31, 2022 – $3 million recovery).

(2)Net of income tax expense of $27 million for the year ended Dec. 31, 2023 (Dec. 31, 2022 – $112 million recovery).

(3)Net of income tax recovery of $1 million for the year ended Dec. 31, 2023 (Dec. 31, 2022 – $12 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 Share Unit Plan, grants of PSUs and RSUs 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 specific 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 2023 was $21 million (2022 – $20 million, 2021 - $14 million), which is included in OM&A in the Consolidated Statements of Earnings (Loss).

TransAlta Corporation 2023 Integrated Report F82

B. Deferred Share Unit (“DSU”) Plan 

Under the Share Unit 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 $1 million in 2023 (2022 - nil, 2021 – $3 million expense).

C. Stock Option Plan 

In 2023, the Company granted executive officers of the Company a total of 0.4 million stock options with a weighted average exercise price of $12.02 that vest over a three-year period and expire seven years after issuance (2022 – 0.3 million stock options at $12.66; 2021 - 0.7 million stock options at $9.86). The expense recognized relating to these grants during 2023 was approximately $1 million (2022 – approximately $1 million, 2021 – approximately $2 million).

The total options outstanding and exercisable under the Stock Option Plan at Dec. 31, 2023, 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)
5.00-12.00	2.5	3.60	9.17

(1)Options currently exercisable as at Dec. 31, 2023.

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. 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, 2022. The latest actuarial valuation for accounting purposes of the Highvale and Canadian pension plans was at Dec. 31, 2021. 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, 2023.

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 2023 in the amount of $88 million, and provided $70 million in surety bonds, to secure the obligations under the supplemental plan and the Canadian defined benefit plan, respectively.

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, 2021 and Jan. 1, 2022, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2023.

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 five per cent to eleven per cent, depending on the plan. Optional employee contributions are allowed for all the defined contribution plans.

F83 TransAlta Corporation 2023 Integrated Report

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, 2023	Registered	Supplemental	Other	Total
Current service cost	1	1	—	2
Administration expenses	1	—	—	1
Interest cost on defined benefit obligation	16	4	1	21
Interest on plan assets	(13)	(1)	—	(14)
Defined benefit expense	5	4	1	10
Defined contribution expense	11	—	—	11
Net expense	16	4	1	21
Year ended Dec. 31, 2022	Registered	Supplemental	Other	Total
Current service cost	1	1	—	2
Administration expenses	1	—	—	1
Interest cost on defined benefit obligation	13	3	—	16
Interest on plan assets	(9)	—	—	(9)
Defined benefit expense	6	4	—	10
Defined contribution expense	11	—	—	11
Net expense	17	4	—	21

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

TransAlta Corporation 2023 Integrated Report F84

C. Status of Plans

The status of the defined benefit pension and other post-employment benefit plans is as follows:

Year ended Dec. 31, 2023	Registered	Supplemental	Other	Total
Fair value of plan assets	269	15	—	284
Present value of defined benefit obligation	(340)	(89)	(17)	(446)
Funded status – plan deficit	(71)	(74)	(17)	(162)
Amount recognized in the Consolidated Financial Statements:
Accrued current liabilities	(1)	(5)	(1)	(7)
Other long-term liabilities	(70)	(69)	(16)	(155)
Total amount recognized	(71)	(74)	(17)	(162)

Year ended Dec. 31, 2022	Registered	Supplemental	Other	Total
Fair value of plan assets	274	15	—	289
Present value of defined benefit obligation	(345)	(85)	(17)	(447)
Funded status – plan deficit	(71)	(70)	(17)	(158)
Amount recognized in the Consolidated Financial Statements:
Accrued current liabilities	(1)	(6)	(1)	(8)
Other long-term liabilities	(70)	(64)	(16)	(150)
Total amount recognized	(71)	(70)	(17)	(158)

F85 TransAlta Corporation 2023 Integrated Report

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, 2021	339	14	—	353
Interest on plan assets	9	—	—	9
Net loss on plan assets	(55)	—	—	(55)
Contributions(1)	38	6	—	44
Benefits paid	(57)	(5)	—	(62)
Administration expenses	(1)	—	—	(1)
Change in foreign exchange rates	1	—	—	1
As at Dec. 31, 2022	274	15	—	289
Interest on plan assets	13	1	—	14
Net return on plan assets	15	(1)	—	14
Contributions(2)	5	6	2	13
Benefits paid	(36)	(6)	(2)	(44)
Administration expenses	(1)	—	—	(1)
Change in foreign exchange rates	(1)	—	—	(1)
As at Dec. 31, 2023	269	15	—	284

(1)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.

(2)The Company made a voluntary contribution of $4 million to further improve the funded status of the US Defined Benefit Pension Plan for the Centralia thermal facility.

TransAlta Corporation 2023 Integrated Report F86

The fair value of the Company’s defined benefit plan assets by major category is as follows:

As at Dec. 31, 2023	Level I	Level II	Level III	Total
Equity securities
Canadian	—	12	—	12
US	—	6	—	6
International	—	86	—	86
Private	—	—	1	1
Bonds
A - AAA	—	30	62	92
BBB	1	5	10	16
Below BBB	—	—	4	4
Loans(1)	—	2	—	2
Alternative funds(2)	—	—	44	44
Money market and cash and cash equivalents	2	19	—	21
Total	3	160	121	284

(1)Includes A credit rating loans of $1 million.

(2)Alternative funds include investments in infrastructure and real estate funds.

Dec. 31, 2022(1)	Level I	Level II	Level III	Total
Equity securities
Canadian	—	18	—	18
US	—	17	—	17
International	—	79	—	79
Private	—	—	1	1
Bonds
A - AAA	—	27	61	88
BBB	1	6	12	19
Below BBB	—	—	6	6
Loans(2)	—	2	—	2
Alternative funds(3)	—	—	39	39
Money market and cash and cash equivalents	—	20	—	20
Total	1	169	119	289

(1)The fair value level classifications of certain mutual fund investments has been revised for consistency with 2023 classifications.

(2)Includes A credit rating loans of $1 million and BBB credit rating loans of $1 million.

(3)Alternative funds include investments in infrastructure and real estate funds.

Plan assets do not include any common shares of the Company at Dec. 31, 2023 and Dec. 31, 2022.

F87 TransAlta Corporation 2023 Integrated Report

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, 2021	469	101	23	593
Current service cost	1	1	—	2
Interest cost	13	3	—	16
Benefits paid	(57)	(5)	1	(61)
Actuarial gain arising from financial assumptions	(83)	(22)	(5)	(110)
Actuarial gain arising from experience adjustments	1	7	(2)	6
Change in foreign exchange rates	1	—	—	1
Present value of defined benefit obligation as at Dec. 31, 2022	345	85	17	447
Current service cost	1	1	—	2
Interest cost	16	4	1	21
Benefits paid	(36)	(6)	(2)	(44)
Actuarial loss arising from demographic assumptions	1	—	—	1
Actuarial loss arising from financial assumptions	12	4	1	17
Actuarial loss arising from experience adjustments	2	1	—	3
Change in foreign exchange rates	(1)	—	—	(1)
Present value of defined benefit obligation as at Dec. 31, 2023	340	89	17	446

(1)The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2023, is 10.4 years.

F. Contributions

The expected employer contributions for 2024 for the defined benefit pension and other post-employment benefit plans are as follows:

	Registered	Supplemental	Other	Total
Expected employer contributions	3	5	1	9

TransAlta Corporation 2023 Integrated Report F88

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:

	2023			2022
As at Dec. 31 (per cent)	Registered	Supplemental	Other	Registered	Supplemental	Other
Accrued benefit obligation
Discount rate	4.6	4.6	4.7	4.7	5.0	5.0
Rate of compensation increase	2.9	3.0	—	2.6	3.0	—
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	—	—	6.8	—	—	7.1
Dental-care cost escalation	—	—	4.2	—	—	4.2
Benefit cost for the year
Discount rate	5.0	5.0	5.0	2.8	2.8	2.7
Rate of compensation increase	2.7	3.0	—	2.9	3.0	—
Assumed health-care cost trend rate
Health-care cost escalation(2)(4)	—	—	7.1	—	—	6.8
Dental-care cost escalation	—	—	4.7	—	—	4.7

(1)2023 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2033 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

(2)2023 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2032 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

(3)2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2032 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

(4)2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2031 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent 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
As at Dec. 31, 2023	Registered	Supplemental	Other	Pension
1% decrease in the discount rate	30	10	1	2
1% increase in the salary scale	1	—	—	—
1% increase in the health-care cost trend rate	—	—	1	—
10% improvement in mortality rates	13	3	—	1

F89 TransAlta Corporation 2023 Integrated Report

32. Joint Arrangements

Joint arrangements at Dec. 31, 2023, 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
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
Tent Mountain	Hydro	50	Pumped hydro energy storage development project in Alberta

33. Cash Flow Information

A. Change in Non-Cash Operating Working Capital

Year ended Dec. 31	2023	2022	2021
(Use) source:
Accounts receivable	715	(869)	(28)
Prepaid expenses	—	—	9
Income taxes receivable	27	(61)	—
Inventory	(2)	6	42
Accounts payable, accrued liabilities and provisions	(550)	548	153
Income taxes payable	(66)	60	(2)
Change in non-cash operating working capital	124	(316)	174

TransAlta Corporation 2023 Integrated Report F90

B. Changes in Liabilities from Financing Activities

	Balance Dec. 31, 2022	Cash issuances	Repayments and dividends paid(1)	New leases	Dividends declared	Foreign exchange impact	Other	Balance Dec. 31, 2023
Long-term debt and lease liabilities(2)	3,669	39	(220)	5	—	(36)	12	3,469
Exchangeable securities	739	—	—	—	—	—	5	744
Dividends payable (common and preferred)(3)	68	—	(109)	—	116	—	(26)	49
Total liabilities from financing activities	4,476	39	(329)	5	116	(36)	(9)	4,262

(1)Includes a decrease of $164 million related to the repayment of long-term debt, a $46 million net decrease in borrowings under credit facilities and a decrease in finance lease obligations of $10 million.

(2)Includes bank overdraft of $3 million.

(3)Other dividends payable related to payment of TransAlta Renewables' non-controlling interest dividend reflected within distributions paid to subsidiaries of non-controlling interests in the Consolidated Statements of Cash Flows.

	Balance Dec. 31, 2021	Cash issuances(1)	Repayments and dividends paid(2)	New leases	Dividends declared	Foreign exchange impact	Other	Balance Dec. 31, 2022
Long-term debt and lease liabilities(3)	3,267	981	(630)	40	—	39	(28)	3,669
Exchangeable securities	735	—	—	—	—	—	4	739
Dividends payable (common and preferred)	62	—	(97)	—	103	—	—	68
Total liabilities from financing activities	4,064	981	(727)	40	103	39	(24)	4,476

(1)Includes $449 million net increase in borrowings under credit facilities and an increase in issuance of long-term debt of $532 million.

(2)Includes a decrease of $621 million related to the repayment of long-term debt and a decrease in finance lease obligations of $9 million.

(3)Includes bank overdraft of $16 million.

F91 TransAlta Corporation 2023 Integrated Report

34. Capital

TransAlta’s capital is comprised of the following:

As at Dec. 31	2023	2022	Increase/ (decrease)
Long-term debt(1)	3,466	3,653	(187)
Exchangeable securities	744	739	5
Bank overdraft	3	16	(13)
Equity
Common shares	3,285	2,863	422
Preferred shares	942	942	—
Contributed surplus	41	41	—
Deficit	(2,567)	(2,514)	(53)
Accumulated other comprehensive income (loss)	(164)	(222)	58
Non-controlling interests	127	879	(752)
Less: available cash and cash equivalents(2)	(348)	(1,134)	786
Less: principal portion of restricted cash on TransAlta OCP bonds(3)	(17)	(17)	—
Less: fair value liability (asset) of hedging instruments on long-term debt(4)	5	(3)	8
Total capital	5,517	5,243	274

(1)Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt.

(2)The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed using a net debt position. 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 as 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 our 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 Morningstar DBRS (stable outlook). In 2023, Moody's reaffirmed the Company's long term rating of Ba1 with a stable outlook. Morningstar DBRS reaffirmed 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 outlook, and S&P Global Ratings

reaffirmed the Company's senior unsecured debt rating and issuer credit 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.

TransAlta Corporation 2023 Integrated Report F92

B. Liquidity

For the years ended Dec. 31, 2023 and 2022, 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 are available to fund operations, pay dividends, distribute payments to subsidiaries' non-controlling interests and invest in PP&E.

Year ended Dec. 31	2023	2022	Increase (decrease)
Cash flow from operating activities	1,464	877	587
Change in non-cash working capital	(124)	316	(440)
Cash flow from operations before changes in working capital	1,340	1,193	147
Dividends paid on common shares	(58)	(54)	(4)
Dividends paid on preferred shares	(51)	(43)	(8)
Distributions paid to subsidiaries’ non-controlling interests	(223)	(187)	(36)
Property, plant and equipment expenditures	(875)	(918)	43
Inflow (outflow)	133	(9)	142

TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2023, $1.4 billion (2022 – $1.0 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 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, 2023, 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	100(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

(1)On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. TransAlta Renewables at Dec. 31, 2023, is a wholly owned subsidiary of the Company (2022 – 60.1 per cent). Refer to Note 4 for more details.

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.

F93 TransAlta Corporation 2023 Integrated Report

A. Transactions with Key Management Personnel 

TransAlta’s key management personnel include the President and Chief Executive Officer ("CEO"), 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	2023	2022	2021
Total compensation	21	23	30
Comprised of:
Short-term employee benefits	11	11	14
Post-employment benefits	1	1	1
Termination benefits	1	—	—
Share-based payments	8	11	15

B. Transactions with Associates

In connection with the exchangeable securities issued to Brookfield, the Investment Agreement entitles Brookfield to nominate two directors to the TransAlta Board. This allows Brookfield to participate in the financial and operating policy decisions of the Company, and as such, they are considered associates of the Company.

In addition to the exchangeable securities disclosed in Note 25, the Company may, in the normal course of

operations, enter into transactions on market terms with associates that have been measured at exchange value and recognized in the Consolidated Financial Statements, including power purchase and sale agreements, derivative contracts and asset management fees. Transactions and balances between the Company and associates do not eliminate.

Transactions with Brookfield include the following:

Year ended Dec. 31	2023	2022	2021
Power sales	135	127	27
Purchased power	2	12	3
Asset management fees paid	1	2	2

TransAlta Corporation 2023 Integrated Report F94

36. Commitments and Contingencies

In addition to the commitments disclosed elsewhere in the financial statements, the Company has incurred the following contractual commitments, either directly or through its interests in joint operations and joint ventures.

Approximate future payments under these agreements are as follows:

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Natural gas, transportation and other contracts	55	49	50	48	57	436	695
Transmission	9	9	6	4	5	93	126
Coal supply agreements	86	71	—	—	—	—	157
Long-term service agreements	60	57	42	44	37	184	424
Operating leases	3	3	2	2	2	25	37
Growth	47	—	—	—	—	—	47
Total	260	189	100	98	101	738	1,486

Commitments

Natural Gas, Transportation and Other Contracts 

The Company has fixed price or volume natural gas purchase and transportation contracts. Included in these contracts are 15-year natural gas transportation agreements for a total of up to 400 terajoules ("TJ") per day on a firm basis, ending in 2036 to 2038 and eight-year natural gas transportation agreements for 75 TJ per day related to the Sheerness facility ending in 2030 to 2031.

Transmission

The Company has several agreements to purchase transmission network capacity in 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.

Coal Supply 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.

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, equipment for gas and turbines at various wind facilities.

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.

Growth

Commitments for growth include the following projects: Horizon Hill wind project, White Rock wind projects, the Australian capacity and transmission expansions, the Mount Keith 132kV expansion and various other growth projects.

F95 TransAlta Corporation 2023 Integrated Report

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.

The Company conducts internal reviews of its offers and offer behaviour in both the energy and ancillary services markets in Alberta on an ongoing basis and will self-report suspected contraventions or respond to inquiries from regulatory agencies as required. There currently is no certainty that any particular matter will be resolved in the Company’s favour or that such matters may not have a material adverse effect on TransAlta.

Brazeau Facility - Well License Applications to Consider Hydraulic Fracturing Activities

The Alberta Energy Regulator ("AER") issued a subsurface order on May 27, 2019, which does not permit any hydraulic fracturing within three kilometres of the Brazeau facility but permits hydraulic fracturing in all formations (except the Duvernay) within three to five kilometres of the Brazeau facility. Subsequently, two oil and gas operators submitted applications to the AER for 10 well licences (which include hydraulic fracturing activities) within three to five kilometres of the Brazeau facility.

The Company's position, based on independent expert analysis commissioned by the Government of Alberta, is that hydraulic fracturing activities within five kilometres of the Brazeau facility pose an unacceptable risk and that the applications should be denied. The regulatory hearing to consider these applications - Proceeding 379 - was adjourned to April 2025. The other parties to the hearing, including the Company, have supported the adjournment.

Brazeau Facility - Claim against the
Government of Alberta

On Sept. 9, 2022, the Company filed a Statement of Claim against the Alberta Government in the Alberta Court of King’s Bench seeking a declaration that: (a) granting mineral leases within five kilometres of the Brazeau facility is a breach of the 1960 agreement between the Company and the Alberta Government; and (b) the Alberta Government is required to indemnify the Company for any costs or damages that result from the risks of hydraulic fracturing near the Brazeau facility. On Sept. 29, 2022, the Alberta Government filed its Statement of Defence, which asserts, among other things, that the Company: (a) is trying

to usurp the jurisdiction of the AER; and (b) is out of time under the Limitations Act (Alberta). The trial was scheduled for two weeks starting Feb. 26, 2024. The parties to the matter, along with Cenovus Energy Inc., sought an adjournment when AER Proceeding 379 was adjourned. The trial is scheduled to resume in February 2025 in the event the parties are unable to resolve the dispute prior to such date.

Garden Plain

Garden Plain I LP, a wholly owned subsidiary of the Company, retained a third-party contractor to construct the Garden Plain wind project near Hanna, Alberta. The contractor experienced scheduling delays, challenges with construction and significant cost overruns, resulting in overdue deadlines, and has asserted a claim for $49 million in damages. The Company disputes this claim in its entirety and asserts a counterclaim. The parties have initiated the dispute resolution procedure, and the arbitration hearing is set down for three weeks starting April 14, 2025.

Hydro Power Purchase Arrangement ("Hydro PPA") Emissions Performance Credits

The Balancing Pool claimed entitlement to 1,750,000 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 EPCs under dispute had no recorded book value as they were internally generated. The Balancing Pool claimed ownership of the EPCs because it believed the change-in-law provisions under the Hydro PPA required the EPCs to be passed through to the Balancing Pool. TransAlta disputed this claim. The parties have reached a confidential settlement and this matter is now resolved.

Sundance A Decommissioning

TransAlta filed an application with the Alberta Utilities Commission 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. The application is being heard in the first quarter of 2024 with a decision expected to be rendered in the third quarter of 2024.

TransAlta Corporation 2023 Integrated Report F96

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 TransAlta’s President and Chief Executive Officer (the chief operating decision maker) ("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, gains and losses related to closed positions effectively settled by offsetting positions with exchanges recorded in the year the positions are settled, 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, items within the Energy Transition segment that may not be reflective of on-going operations including certain costs related to decisions made to accelerate our transition off-coal in Alberta and our planned transition off-coal for Centralia, 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.

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.

F97 TransAlta Corporation 2023 Integrated Report

B. Reported Adjusted Segment Earnings and Segment Assets

I. Reconciliation of Adjusted EBITDA to Earnings (Loss) before Income Tax

Year ended Dec. 31, 2023	Hydro	Wind &  Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass  adjustments	IFRS financials
Revenues	533	357	1,514	751	220	1	3,376	(21)	—	3,355
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	(4)	16	(67)	(5)	23	—	(37)	—	37	—
Realized gain (loss) on closed exchange positions	—	—	10	—	(91)	—	(81)	—	81	—
Decrease in finance lease receivable	—	—	55	—	—	—	55	—	(55)	—
Finance lease income	—	—	12	—	—	—	12	—	(12)	—
Unrealized foreign exchange loss on commodity	—	—	1	—	—	—	1	—	(1)	—
Adjusted revenues	529	373	1,525	746	152	1	3,326	(21)	50	3,355
Fuel and purchased power	19	30	453	557	—	1	1,060	—	—	1,060
Reclassifications and adjustments:
Australian interest income	—	—	(4)	—	—	—	(4)	—	4	—
Adjusted fuel and purchased power	19	30	449	557	—	1	1,056	—	4	1,060
Carbon compliance	—	—	112	—	—	—	112	—	—	112
Gross margin	510	343	964	189	152	—	2,158	(21)	46	2,183
OM&A	48	80	192	64	43	115	542	(3)	—	539
Taxes, other than income taxes	3	12	11	3	—	1	30	(1)	—	29
Net other operating income	—	(7)	(40)	—	—	—	(47)	—	—	(47)
Reclassifications and adjustments:
Insurance recovery	—	1	—	—	—	—	1	—	(1)	—
Adjusted net other operating income	—	(6)	(40)	—	—	—	(46)	—	(1)	(47)
Adjusted EBITDA(2)	459	257	801	122	109	(116)	1,632
Equity income										4
Finance lease income										12
Depreciation and amortization										(621)
Asset impairment reversals										48
Interest income										59
Interest expense										(281)
Foreign exchange loss										(7)
Gain on sale of assets and other										4
Earnings before income taxes										880

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

TransAlta Corporation 2023 Integrated Report F98

Year ended Dec. 31, 2022	Hydro	Wind &  Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	606	303	1,209	714	160	(2)	2,990	(14)	—	2,976
Reclassifications and adjustments:
Unrealized mark-to-market loss	1	104	251	10	12	—	378	—	(378)	—
Realized gain (loss) on closed exchange positions	—	—	(4)	—	47	—	43	—	(43)	—
Decrease in finance lease receivable	—	—	46	—	—	—	46	—	(46)	—
Finance lease income	—	—	19	—	—	—	19	—	(19)	—
Unrealized foreign exchange gain on commodity	—	—	—	—	(1)	—	(1)	—	1	—
Adjusted revenues	607	407	1,521	724	218	(2)	3,475	(14)	(485)	2,976
Fuel and purchased power	22	31	641	566	—	3	1,263	—	—	1,263
Reclassifications and adjustments:
Australian interest income	—	—	(4)	—	—	—	(4)	—	4	—
Adjusted fuel and purchased power	22	31	637	566	—	3	1,259	—	4	1,263
Carbon compliance	—	1	83	(1)	—	(5)	78	—	—	78
Gross margin	585	375	801	159	218	—	2,138	(14)	(489)	1,635
OM&A	55	68	195	69	35	101	523	(2)	—	521
Taxes, other than income taxes	3	12	15	4	—	1	35	(2)	—	33
Net other operating income	—	(23)	(38)	—	—	—	(61)	3	—	(58)
Reclassifications and adjustments:
Insurance recovery	—	7	—	—	—	—	7	—	(7)	—
Adjusted net other operating   income	—	(16)	(38)	—	—	—	(54)	3	(7)	(58)
Adjusted EBITDA(2)	527	311	629	86	183	(102)	1,634
Equity income										9
Finance lease income										19
Depreciation and amortization										(599)
Asset impairment charges										(9)
Interest income										24
Interest expense										(286)
Foreign exchange gain										4
Gain on sale of assets and other										52
Earnings before income taxes										353

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

F99 TransAlta Corporation 2023 Integrated Report

Year ended Dec. 31, 2021	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	—
Realized gain (loss) on closed exchange positions	—	—	(6)	—	29	—	23	—	(23)	—
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	1,126	728	202	4	2,791	(18)	(52)	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 writedown	—	—	—	(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	634	236	202	—	1,770	(18)	(263)	1,489
OM&A	42	59	175	117	36	84	513	(2)	—	511
Reclassifications and adjustments:
Parts and materials writedown	—	—	(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 loss (income)	—	—	(40)	48	—	—	8	—	—	8
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties	—	—	—	(48)	—	—	(48)	—	48	—
Adjusted net other operating loss (income)	—	—	(40)	—	—	—	(40)	—	48	8
Adjusted EBITDA(2)	322	262	488	133	166	(85)	1,286
Equity income										9
Finance lease income										25
Depreciation and amortization										(529)
Asset impairment charges										(648)
Interest income										11
Interest expense										(256)
Foreign exchange gain										16
Gain on sale of assets and other										54
Loss before income taxes										(380)

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

TransAlta Corporation 2023 Integrated Report F100

II. Selected Consolidated Statements of Financial Position Information

As at As at Dec. 31, 2023	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
PP&E	462	3,360	1,543	251	—	98	5,714
Right-of-use assets	7	94	5	—	—	11	117
Intangible assets	2	141	40	4	5	31	223
Goodwill	258	176	—	—	30	—	464
As at As at Dec. 31, 2022	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
PP&E	437	2,837	1,858	313	—	111	5,556
Right-of-use assets	6	98	6	2	—	14	126
Intangible assets	2	157	49	5	8	31	252
Goodwill	258	176	—	—	30	—	464

III. Selected Consolidated Statements of Cash Flows Information

Additions to non-current assets are as follows:

Year ended Dec. 31, 2023	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	42	674	89	16	—	54	875
Intangible assets	—	—	—	—	—	13	13
Year ended Dec. 31, 2022	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	36	745	43	19	—	75	918
Intangible assets	—	19	—	—	3	9	31
Year ended Dec. 31, 2021	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	29	166	167	90	—	28	480
Intangible assets	—	—	—	1	—	8	9

F101 TransAlta Corporation 2023 Integrated Report

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	2023	2022	2021
Depreciation and amortization expense on the Consolidated Statements of Earnings (Loss)	621	599	529
Depreciation included in fuel and purchased power (Note 6)	—	—	190
Depreciation and amortization on the Consolidated Statements of Cash Flows	621	599	719

C. Geographic Information

I. Revenues

Year ended Dec. 31	2023	2022	2021
Canada	2,218	1,905	1,854
US	987	940	731
Australia	150	131	136
Total revenue	3,355	2,976	2,721

II. Non-Current Assets

	Property, plant and equipment		Right-of-use assets		Intangible assets		Other assets
As at Dec. 31	2023	2022	2023	2022	2023	2022	2023	2022
Canada	3,578	3,817	43	49	108	123	68	62
US	1,749	1,307	71	74	88	101	42	34
Australia	387	432	3	3	27	28	69	64
Total	5,714	5,556	117	126	223	252	179	160

D. Significant Customer 

For the year ended Dec. 31, 2023, sales to the AESO represented 46 per cent of the Company’s total revenue (2022 – sales to the AESO represented 60 per cent of the Company’s total revenue). There were no other companies that accounted for more than 10 per cent of the Company's total revenue.

TransAlta Corporation 2023 Integrated Report F102

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the reference of our Firm under the caption “Experts”, and to the incorporation by reference in the following Registration Statements:

a.Form S-8 Nos. 333-260935, 333-236894 pertaining to TransAlta Corporation’s Share Unit Plan, and Form S-8 Nos. 333-72454 and 333-101470 pertaining to TransAlta Corporation’s Share Option Plan

b.Form F-10 No. 333-271953 pertaining to the registration of Debt and Equity Securities

of TransAlta Corporation and the use herein of our reports dated February 22, 2024, with respect to the consolidated statements of financial position as at December 31, 2023 and 2022 and the consolidated statements of earnings (loss), comprehensive income (loss), changes in equity and cash flows for each of the years in the three year period ended December 31, 2023, and the effectiveness of internal control over financial reporting of TransAlta Corporation as of December 31, 2023, included in this Annual Report on Form 40-F.

	/s/Ernst & Young LLP
Calgary, Alberta February 22, 2024	Chartered Professional Accountants

A member firm of Ernst & Young Global Limited

EX-31.1

Exhibit 31.1

Certifications

I, John H. Kousinioris, certify that:

1.I have reviewed this annual report on Form 40-F of TransAlta Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

February 22, 2024
	/s/ John H. Kousinioris
	John H. Kousinioris
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

Certifications

I, Todd J. Stack, certify that:

1.I have reviewed this annual report on Form 40-F of TransAlta Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

February 22, 2024
	/s/ Todd J. Stack
	Todd J. Stack
	Executive Vice President, Finance and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of TransAlta Corporation (the “Company”) on Form 40-F for the year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John H. Kousinioris, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

2.The information contained in the Report fairly presents, in all materials respects, the financial condition and result of operations of the Company.

/s/ John H. Kousinioris

John H. Kousinioris

President and Chief Executive Officer

Dated: February 22, 2024

The foregoing certification is being furnished solely to accompany the Report pursuant to 18 U.S.C § 1350, and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of TransAlta Corporation (the “Company”) on Form 40-F for the year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Todd J. Stack, Executive Vice President, Finance and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

2.The information contained in the Report fairly presents, in all materials respects, the financial condition and result of operations of the Company.

/s/ Todd J. Stack

Todd J. Stack

Executive Vice President, Finance and Chief Financial Officer

Dated: February 22, 2024

The foregoing certification is being furnished solely to accompany the Report pursuant to 18 U.S.C § 1350, and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

EX-97

Exhibit 97

TRANSALTA CORPORATION

EXECUTIVE COMPENSATION CLAWBACK POLICY

Introduction

In accordance with the applicable rules of The New York Stock Exchange Listed Company Manual (the “Listing Standards”), Section 10D and Rule 10D-1 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Board of Directors (the “Board”) of TransAlta Corporation (the “Company”) has adopted this Policy (the “Policy”) to provide for the recoupment of erroneously awarded incentive-based compensation from Covered Executives (as defined below) in the event of an accounting restatement resulting from material noncompliance with financial reporting requirements under applicable securities laws. This Policy does not supercede, limit or replace Policy 501: Compensation Clawback, which pertains to the clawback of variable compensation in circumstances of gross negligence, intentional misconduct, fraud or other serious misconduct and is appended hereto as Schedule A, as may be amended or restated from time to time.

Administration

The Board has delegated administration of this Policy to the Human Resources Committee of the Board (the “Committee”). Any determinations made by the Committee shall be final and binding on all affected individuals. If the Committee is not composed entirely of independent directors, a majority of independent directors serving on the Board may be delegated authority to administer this Policy, including any determination as to the amount of any excess Incentive Compensation paid to the Covered Executives (as such terms are defined below).

Covered Executives

This Policy applies to the Company's current and former executive officers, as determined by the Committee in accordance with Section 10D of the Exchange Act and the Listing Standards, and such other senior executives or employees who may from time to time be deemed subject to the Policy by the Committee (“Covered Executives”). The following are examples of persons who may be deemed executive officers:

•President and Chief Executive Officer;

•Chief Financial Officer or principal financial officer;

•Principal accounting officer or controller;

•Any vice president in charge of a principal business unit, division or function, such as sales administration or finance;

•Any other officer who performs a policy-making function; and

•Any other person (such as an executive officer of a subsidiary or parent entity) who performs similar policy-making functions for the company.

1

Recoupment; Accounting Restatement

For purposes of this Policy, Accounting Restatement means an accounting restatement due to the material noncompliance of the Company with any financial reporting requirement under applicable securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements, or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period.

In the event of an Accounting Restatement, the Committee will require reimbursement or forfeiture of any excess Incentive Compensation received by any Covered Executive during the three completed fiscal years immediately preceding the date on which the Company is required to prepare an accounting restatement. However, no reimbursement or forfeiture will apply to Incentive Compensation received by a Covered Executive before such Covered Executive began providing services as a Covered Executive.

Incentive Compensation

For purposes of this Policy, Incentive Compensation means any compensation that is granted, earned or vested based wholly or in part upon the attainment of a Financial Reporting Measure. Incentive Compensation is “received” for purposes of this Policy in the Company’s fiscal period during which the Financial Reporting Measure specified in the Incentive Compensation award is attained, even if the payment or grant of such Incentive Compensation occurs after the end of that period. The following are examples of Incentive Compensation that may be based on a Financial Reporting Measure:

•annual bonuses and other short- and long-term incentives;

•stock options;

•restricted share units;

•performance share units; or

•share appreciation rights.

A “Financial Reporting Measure” is any measure that is determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, and any measure that is derived wholly or in part from such measure. A Financial Reporting Measure need not be presented within the Company’s financial statements or included in a filing with the Securities Exchange Commission. Examples of Financial Reporting Measures may include:

•Company share price;

•total shareholder return;

•revenues;

•net income;

•earnings before interest, taxes, depreciation, and amortization (EBITDA);

•funds from operations;

•liquidity measures such as working capital or operating cash flow;

•return measures such as return on invested capital or return on assets; or

•earnings measures such as earnings per share.

Excess Incentive Compensation: Amount Subject to Recovery

The amount to be recovered will be the excess of the Incentive Compensation paid to the Covered Executive based on the erroneous data over the Incentive Compensation that would have been paid to the Covered

2

Executive had it been based on the restated results, as determined by the Committee. If the Committee cannot determine the amount of excess Incentive Compensation received by the Covered Executive directly from the information in the accounting restatement, then it will make its determination based on a reasonable estimate of the effect of the accounting restatement. The Company shall maintain documentation of the determination of such reasonable estimate and provide the relevant documentation as required to the NYSE.

Method of Recoupment

Upon determining the excess of the Incentive Compensation paid to the Covered Executive, the Committee shall promptly notify the Covered Executive by providing written notice containing the amount of the excess of the Incentive Compensation and a demand for repayment or return of such compensation. The Committee will determine, in its sole discretion, the method for recouping Incentive Compensation hereunder which may include, without limitation:

•requiring reimbursement of cash Incentive Compensation previously paid;

•seeking recovery of any gain realized on the vesting, exercise, settlement, sale, transfer, or other disposition of any equity-based awards;

•offsetting the recouped amount from any compensation otherwise owed by the Company to the Covered Executive;

•cancelling outstanding vested or unvested equity awards; and

•taking any other remedial and recovery action permitted by law, as determined by the Committee.

No Indemnification

The Company shall not be permitted to insure or indemnify any Covered Executives against (i) the loss of any incorrectly awarded Incentive Compensation that is repaid, returned or recovered pursuant to the terms of this Policy, or (ii) any claims relating to the Company’s enforcement of its rights under this Policy.

Interpretation

The Committee is authorized to interpret and construe this Policy and to make all determinations necessary, appropriate, or advisable for the administration of this Policy. It is intended that this Policy be interpreted in a manner that is consistent with the requirements of Section 10D of the Exchange Act and any applicable rules or standards adopted by the Securities and Exchange Commission or any national securities exchange on which the Company's securities are listed.

Effective Date

This Policy has been adopted by the Committee effective as of December 1, 2023 (the “Effective Date”) and shall apply to Incentive Compensation that is approved, awarded or granted to Covered Executives on or after that date.

Amendment; Termination

The Committee may amend this Policy from time to time in its discretion and shall amend this Policy as it deems necessary to reflect further regulations adopted by the Securities and Exchange Commission under Section 10D of the Exchange Act or rules or interpretations promulgated thereunder and to comply with any Listing Standards. The Committee may terminate this Policy at any time.

3

Other Recoupment Rights

The Committee intends that this Policy will be applied to the fullest extent of the law. The Committee may require that any employment agreement, equity award agreement, or similar agreement entered into on or after the Effective Date shall, as a condition to the grant of any benefit thereunder, require a Covered Executive to agree to abide by the terms of this Policy. Any right of recoupment under this Policy is in addition to, and not in lieu of, any other remedies or rights of recoupment that may be available to the Company pursuant to the terms of any similar policy in any employment agreement, equity award agreement, or similar agreement and any other legal remedies available to the Company. This Policy does not supercede, limit or replace Policy 501: Compensation Clawback, which pertains to the clawback of variable compensation in circumstances of gross negligence, intentional misconduct, fraud or other serious misconduct and is appended hereto as Schedule A, as may be amended or restated from time to time.

Impracticability

The Committee shall recover any excess Incentive Compensation in accordance with this Policy unless such recovery would be impracticable, as determined by the Committee in accordance with Rule 10D-1 of the Exchange Act and the Listing Standards, and any of the following conditions are met:

•the Committee has determined that the direct expenses paid to a third party to assist in enforcing the Policy would exceed the amount to be recovered. Before making this determination, the Company must make a reasonable attempt to recover the excess Incentive Compensation, documented such attempt(s) and provided such documentation to the NYSE;

•recovery would violate home country law where that law was adopted prior to November 28, 2022, provided that, before determining that it would be impracticable to recover any amount of excess Incentive Compensation based on violation of home country law, the Company has obtained an opinion of home country counsel, acceptable to the NYSE, that recovery would result in such a violation and a copy of the opinion is provided to NYSE; or

•recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Company, to fail to meet the requirements of Section 401(a)(13) or Section 411(a) of the Internal Revenue Code of 1986, as amended, and regulations thereunder.

Successors

This Policy shall be binding and enforceable against all Covered Executives and their beneficiaries, heirs, executors, administrators or other legal representatives.

Exhibit Filing Requirement

A copy of this Policy and any amendments thereto shall be posted on the Company’s website and filed as an exhibit to the Company’s annual report and the Company shall file all disclosures with respect to this Policy required by applicable U.S. Securities and Exchange Commission (“SEC”) filings and rules.

4

Schedule A

Policy 501: Compensation Clawback

Policy Applies to TransAlta Corporation and all its Subsidiaries

INTRODUCTION

This policy outlines the clawback policy to provide substantially for the reimbursement of compensation in cases where an executive has engaged in wrongdoing or in the case of restatement of financial statements.

APPLICATION

Applies to all variable compensation.

POLICY

The Board has the discretion to seek reimbursement for compensation awarded, and/or cancel unvested incentive awards, and/or claw back vested, and/or paid incentive awards, as applicable, in situations where the board determines the executive engaged in gross negligence, intentional misconduct, fraud or other serious misconduct (which includes, but is not limited to, dishonesty or a breach of company policy to the material detriment of the Company's business or reputation and any conduct that would qualify as cause for termination of employment at common law) irrespective of whether there was a financial restatement.

XML

Cover	12 Months Ended
	Dec. 31, 2023 shares
Entity Addresses [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Entity File Number	001-15214
Entity Registrant Name	TRANSALTA CORPORATION
Entity Incorporation, State or Country Code	Z4
Entity Address, Address Line One	1400, 1100 - 1st Street S.E.
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Postal Zip Code	T2G 1B1
City Area Code	403
Local Phone Number	267-7110
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	306,933,951
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0001144800
Document Financial Statement Error Correction [Flag]	false
Business Contact
Entity Addresses [Line Items]
Contact Personnel Name	TransAlta Centralia Generation LLC
Entity Address, Address Line One	913 Big Hanaford Road
Entity Address, City or Town	Centralia
Entity Address, State or Province	WA
Entity Address, Postal Zip Code	98531
City Area Code	360
Local Phone Number	736-9901

XML

Audit Information	12 Months Ended
	Dec. 31, 2023
Audit Information [Abstract]
Auditor Name	Chartered Professional Accountants
Auditor Location	Calgary, Canada
Auditor Firm ID	1263

XML

Consolidated Statements of Earnings (Loss) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Profit or loss [abstract]
Revenue	$ 3,355	$ 2,976	$ 2,721
Fuel and purchased power	1,060	1,263	1,054
Carbon compliance	112	78	178
Gross margin	2,183	1,635	1,489
Operations, maintenance, and administration	539	521	511
Depreciation and amortization	621	599	529
Asset impairment charges (reversals)	(48)	9	648
Taxes, other than income taxes	29	33	32
Net other operating (income) loss	(47)	(58)	8
Operating income (loss)	1,089	531	(239)
Equity income (loss)	4	9	9
Finance lease income	12	19	25
Interest income	59	24	11
Net interest expense	(281)	(286)	(256)
Foreign exchange gain (loss)	(7)	4	16
Gain on sale of assets and other	4	52	54
Earnings (loss) before income taxes	880	353	(380)
Income tax expense (recovery)	84	192	45
Net earnings (loss)	796	161	(425)
Net earnings (loss) attributable to:
TransAlta shareholders	695	50	(537)
Non-controlling interests	101	111	112
Net earnings (loss)	796	161	(425)
Preferred share dividends	51	46	39
Net earnings (loss) attributable to common shareholders	$ 644	$ 4	$ (576)
Weighted average number of common shares outstanding in the year (in shares)	276	271	271
Net earnings (loss) per share attributable to common shareholders, basic (in CAD per share)	$ 2.33	$ 0.01	$ (2.13)
Net earnings (loss) per share attributable to common shareholders, diluted (in CAD per share)	$ 2.33	$ 0.01	$ (2.13)

XML

Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of comprehensive income [abstract]
Net earnings (loss)		$ 796	$ 161	$ (425)
Other comprehensive income (loss)
Net actuarial gains (losses) on defined benefit plans, net of tax	[1]	(5)	37	37
Fair value losses on third-party investments, net of tax		0	(1)	0
Total items that will not be reclassified subsequently to net earnings (loss)		(5)	36	37
Gains (losses) on translating net assets of foreign operations, net of tax		(6)	21	(14)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax	[2]	9	(25)	0
Gains (losses) on derivatives designated as cash flow hedges, net of tax	[3]	41	(556)	(200)
Reclassification of losses (gains) on derivatives designated as cash flow hedges to net earnings (loss), net of tax	[4]	58	100	(8)
Total items that will be reclassified subsequently to net earnings (loss)		102	(460)	(222)
Other comprehensive income (loss)		97	(424)	(185)
Total comprehensive income (loss)		893	(263)	(610)
Total comprehensive income (loss) attributable to:
TransAlta shareholders		817	(318)	(693)
Non-controlling interests		$ 76	$ 55	$ 83

[1] Net of income tax recovery of $1 million for the year ended Dec. 31, 2023 (2022 – $12 million expense, 2021 – $11 million expense).

[2] Net of income tax expense of $1 million for the year ended Dec. 31, 2023 (2022 – $3 million recovery, 2021 – nil).

[3] Net of income tax expense of $10 million for the year ended Dec. 31, 2023 (2022 – $138 million recovery, 2021 – $55 million recovery).

[4] Net of reclassification of income tax expense of $17 million for the year ended Dec. 31, 2023 (2022 – $26 million expense, 2021 – $2 million recovery).

XML

Consolidated Statements of Comprehensive Loss (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of comprehensive income [abstract]
Net impact related to net actuarial gains (losses)	$ (1)	$ 12	$ 11
Net income tax expense (recovery) relating to gains (losses) on financial instruments	1	(3)	0
Net of income tax (recovery) expense	10	(138)	55
Net of reclassification of income tax expense (recovery)	$ 17	$ 26	$ 2

XML

Consolidated Statements of Financial Position - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 348	$ 1,134
Restricted cash	69	70
Trade and other receivables	807	1,589
Prepaid expenses and other	48	55
Risk management assets	151	709
Inventory	157	157
Current assets	1,580	3,714
Non-current assets
Investments	138	129
Long-term portion of finance lease receivables	171	129
Risk management assets	52	161
PP&E	5,714	5,556
Right-of-use assets	117	126
Intangible assets	223	252
Goodwill	464	464
Deferred income tax assets	21	50
Other assets	179	160
Total assets	8,659	10,741
Current liabilities
Bank overdraft	3	16
Accounts payable and accrued liabilities	797	1,346
Current portion of decommissioning and other provisions	35	70
Risk management liabilities	314	1,129
Current portion of contract liabilities	3	8
Income taxes payable	9	73
Dividends payable	49	68
Current portion of long-term debt and lease liabilities	532	178
Current liabilities	1,742	2,888
Non-current liabilities
Credit facilities, long-term debt and lease liabilities	2,934	3,475
Exchangeable securities	744	739
Decommissioning and other provisions	654	659
Deferred income tax liabilities	386	352
Risk management liabilities	274	333
Contract liabilities	10	12
Defined benefit obligation and other long-term liabilities	251	294
Equity
Common shares	3,285	2,863
Preferred shares	942	942
Contributed surplus	41	41
Deficit	(2,567)	(2,514)
Accumulated other comprehensive income (loss)	(164)	(222)
Equity attributable to shareholders	1,537	1,110
Equity attributable to non-controlling interests	127	879
Total equity	1,664	1,989
Total liabilities and equity	$ 8,659	$ 10,741

XML

Consolidated Statements of Changes in Equity - CAD ($) $ in Millions	Total	Common shares	Preferred shares	Issued capital Common shares	Issued capital Preferred shares	Contributed surplus	Deficit	Deficit Common shares	Deficit Preferred shares	Accumulated other comprehensive income (loss)	[1]	Attributable to shareholders	Attributable to shareholders Common shares	Attributable to shareholders Preferred shares	Attributable to non-controlling interests
Balance, beginning of year at Dec. 31, 2021	$ 2,593			$ 2,901	$ 942	$ 46	$ (2,453)			$ 146		$ 1,582			$ 1,011
Changes in equity [abstract]
Net earnings (loss)	161						50					50			111
Other comprehensive income (loss)
Net losses on translating net assets of foreign operations, net of hedges and tax	(4)									(4)		(4)
Net gains (losses) on derivatives designated as cash flow hedges, net of tax	(456)									(456)		(456)			0
Net actuarial gains on defined benefits plans, net of tax	37									37		37
Intercompany FVTOCI investments	(1)									55		55			(56)
Total comprehensive income (loss)	(263)						50			(368)		(318)			55
Dividends	(46)	$ (57)	$ (46)					$ (57)	$ (46)				$ (57)	$ (46)
Shares purchased under NCIB	(54)			(46)			(8)					(54)
Effect of share-based payment plans	3			8		(5)						3
Dividends recognised as distributions to non-controlling interests	(187)														(187)
Balance, end of year at Dec. 31, 2022	1,989			2,863	942	41	(2,514)			(222)		1,110			879
Changes in equity [abstract]
Net earnings (loss)	796						695					695			101
Other comprehensive income (loss)
Net losses on translating net assets of foreign operations, net of hedges and tax	3									3		3
Net gains (losses) on derivatives designated as cash flow hedges, net of tax	99									99		99			0
Net actuarial gains on defined benefits plans, net of tax	(5)									(5)		(5)
Intercompany FVTOCI investments	0									25		25			(25)
Total comprehensive income (loss)	893						695			122		817			76
Dividends	(51)	$ (65)	$ (51)					$ (65)	$ (51)				$ (65)	$ (51)
Shares purchased under NCIB	(87)			(80)			(7)					(87)
Changes in non-controlling interests in TransAlta Renewables (Note 4)	(809)			510			(625)			(64)		(179)			(630)
Provision for repurchase of shares under the automatic share purchase plan	(19)			(19)								(19)
Effect of share-based payment plans	11			11		0						11
Dividends recognised as distributions to non-controlling interests	(198)														(198)
Balance, end of year at Dec. 31, 2023	$ 1,664			$ 3,285	$ 942	$ 41	$ (2,567)			$ (164)		$ 1,537			$ 127

[1] (1)Refer to Note 29 for details on components of and changes in, accumulated other comprehensive income (loss).

XML

Consolidated Statement of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating activities
Net earnings (loss)	$ 796	$ 161	$ (425)
Depreciation and amortization	621	599	719
Gain on sale of assets and other	(3)	(32)	(54)
Accretion of provisions	48	49	32
Decommissioning and restoration costs settled	(37)	(35)	(18)
Deferred income tax expense (recovery)	34	127	(11)
Unrealized loss (gain) from risk management activities	(36)	385	(34)
Unrealized foreign exchange gain	(9)	(82)	(24)
Provisions and contract liabilities	(1)	19	(41)
Asset impairment charges	(48)	9	648
Equity income, net of distributions from investments	2	(4)	(5)
Other non-cash items	(27)	(3)	40
Cash flow from operations before changes in working capital	1,340	1,193	827
Change in non-cash operating working capital	124	(316)	174
Cash flow from operating activities	1,464	877	1,001
Investing activities
Additions to property, plant and equipment	(875)	(918)	(480)
Additions to intangibles assets	(13)	(31)	(9)
Restricted cash	1	0	(1)
Repayments (advances) in loan receivable	11	18
Repayments (advances) in Loan receivable			(3)
Acquisitions, net of cash acquired	0	(10)	(120)
Investments	(13)	(10)	0
Proceeds on sale of Pioneer Pipeline	0	0	128
Proceeds on sale of property, plant and equipment	29	66	39
Realized gain (loss) on financial instruments	18	27	(6)
Decrease in finance lease receivable	55	46	41
Other	(25)	45	(16)
Change in non-cash investing working capital balances	(2)	26	(45)
Cash flow used in investing activities	(814)	(741)	(472)
Financing activities
Net increase (decrease) in borrowings under credit facilities	(46)	449	(114)
Repayment of long-term debt	(164)	(621)	(92)
Issuance of long-term debt	39	532	173
Repurchase of common shares under NCIB	(87)	(52)	(4)
Proceeds on issuance of common shares	5	3	8
Realized gain (loss) on financial instruments	(30)	42	3
Acquisition of TransAlta Renewables	(811)	0	0
Distributions paid to subsidiaries' non-controlling interests	(223)	(187)	(156)
Decrease in lease liabilities	(10)	(9)	(8)
Financing fees and other	1	(13)	(4)
Change in non-cash financing working capital balances	3	(2)	(1)
Cash flow from (used in) financing activities	(1,432)	45	(282)
Cash flow from (used in) operating, investing and financing activities	(782)	181	247
Effect of translation on foreign currency cash	(4)	6	(3)
Increase (decrease) in cash and cash equivalents	(786)	187	244
Cash and cash equivalents, beginning of year	348	1,134	947
Cash and cash equivalents, end of year	348	1,134	947
Supplemental cash flow information
Cash taxes paid	94	67	57
Cash interest paid	277	229	220
Cash interest received	54	20	7
Common shares
Financing activities
Dividends paid	(58)	(54)	(48)
Preferred shares
Financing activities
Dividends paid	$ (51)	$ (43)	$ (39)

XML

Corporate Information

12 Months Ended

Dec. 31, 2023

Corporate information and statement of IFRS compliance [abstract]

Corporate Information

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. The Company's head office is located in Calgary, Alberta.

Operating Segments

Generation Segments

The four generation segments of the Company are as follows: Hydro, Wind and Solar, Gas, and Energy Transition. The Company directly or indirectly owns and operates hydro, wind and solar, natural gas-fired facilities, a coal-fired facility and natural gas pipeline operations in Canada, the United States (“US”) and Australia. Transmission in Canada is included within the Hydro segment while transmission in Australia is included in the Gas segment. The Wind and Solar segment includes the financial results, on a proportionate basis, of our investment in SP Skookumchuck Investment, LLC ("Skookumchuck"). Segment revenues are derived from the availability and production of electricity and steam as well as ancillary services.

Energy Marketing Segment

The Energy Marketing segment derives revenue and earnings from the trading of electricity, natural gas and environmental products across a variety of North American markets, excluding Alberta.

The Energy Marketing segment also performs services on behalf of certain assets outside of Alberta for the power marketing of available generating capacity as well as the procurement of the fuel and transmission needs for the fleet. Contracts of various durations for the forward sales of electricity and for the purchase of natural gas and transmission   capacity   are   utilized.   The   results   of   these

activities are included in the gross margin of the related generation segment. The Energy Marketing segment allocates charges to recognize the performance of these activities to the applicable generation segments.

Corporate Segment

The Corporate 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.

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. 22, 2024.

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.

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Material Accounting Policies

12 Months Ended

Dec. 31, 2023

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

Material Accounting Policies

Material Accounting Policies

The Company has reviewed its material 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. Contract modifications are accounted for as separate contracts when the consideration for the additional promised goods reflects a stand-alone selling price. Otherwise, contract modifications are accounted for as part of the existing contract. If the additional goods are not considered distinct the transaction price can be affected and adjustments to previously recognized revenue can occur. If the additional goods are distinct, the existing and modified contracts are treated together as a new contract, with impacts reflected prospectively from the modification date, which can include the blending of contract prices. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the goods or services are 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 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 that has previously been constrained 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, the 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 (e.g., 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 (e.g., 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 (e.g., 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.
Generation byproducts	Generation byproducts refers to the sale of byproducts from the use of coal in the Company’s current US and previous Canadian coal operations. 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) include 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 ("VPPA"). Contracts for differences are financial contracts whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh. A VPPA is whereby the Company receives the difference between the fixed contract price per MWh and the settled market price. These arrangements meet the definition of a derivative 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.

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 (loss) (“FVTOCI”).

Financial assets with contractual cash flows arising on specified dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows, are subsequently measured at amortized cost. Financial assets measured at FVTOCI are those that have contractual cash flows, arising on specific dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows and to sell the

financial asset and investments in equity instruments. 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 investor's investment is subsequently considered residual equity ownership with distributions classified as 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.

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.

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 income (loss) ("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 income (loss) ("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 of 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 comprises cash and highly liquid investments with original maturities of three months or less.

D. Inventory

I. Fuel

The Company’s inventory balance is composed 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 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 and 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 at the estimated compliance cost required by the Company to settle its obligation in excess of government-established caps and targets. Compliance costs that are recoverable under the terms of the contracts with third parties are recognized as Revenue from Contracts with Customers.

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 if it is probable that future economic benefits will be realized and the cost of the item can be measured reliably. The cost of major spare parts is capitalized and classified as PP&E, as these items can only be used in connection with an item of PP&E.

Planned maintenance is performed at regular intervals. Planned major maintenance includes inspection, repair and maintenance of existing components and the replacement of existing components. Costs incurred for planned major maintenance activities are capitalized in the period maintenance activities occur and are amortized on a straight-line basis 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. Insurance 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. 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	1-49 years
Wind and Solar generation	1-30 years
Gas generation	1-34 years
Energy Transition	1-9 years
Capital spares and other	1-49 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 composed of all directly attributable costs necessary to create, produce and prepare the intangible asset to be capable of operating in the manner intended by management.

Subsequent to initial recognition, intangible assets continue to be measured using the cost model and are reported at cost less accumulated amortization and impairment losses, if any. Amortization is included in depreciation and amortization 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	1-7 years
Power sale contracts	1-18 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 flow 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. 

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 reassessed at each reporting date and are recognized 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 prorated based on service. The net interest cost is determined by applying the discount rate to the net defined benefit liability. The discount rate used to determine the present value of the defined benefit obligation and the net interest cost, is determined by reference to market yields at the end of the reporting period on high-quality corporate bonds with terms and currencies that match the estimated terms and currencies of the benefit obligations. Remeasurements, which include actuarial gains and losses and the return on plan assets (excluding net interest), are recognized through OCI in the period in which they occur. Actuarial gains and losses arise

from experience adjustments and changes in actuarial assumptions. Remeasurements are not reclassified to profit or loss, from OCI, in subsequent periods.

Gains or losses arising from either a curtailment or settlement of a defined benefit plan are recognized when the curtailment or settlement occurs. When the restructuring of a benefit plan gives rise to a curtailment and a settlement of obligations, the curtailment is accounted for prior to the settlement.

In determining whether statutory minimum funding requirements of the 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. 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.

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 for both the decommissioning and restoration provision and other provisions are charged to net earnings each period and is included in net interest expense.

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.

I. 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.

II. Lessor

Power Purchase Agreements ("PPAs") and other long-term contracts may contain, or may be considered, leases where the fulfilment of the arrangement is dependent on the use of a specific asset (e.g., a generating unit) and the arrangement conveys to the customer the right to 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.

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 income (loss) is attributed to the non-controlling interests even if this results in the non-controlling interests having a negative balance.

When the proportion of the equity held by non-controlling interests changes, the carrying amounts of the controlling and non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiary. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received, is recognized directly in equity and attributed to shareholders.

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.

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 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. 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 regard 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 2021 to 2023 is disclosed 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.

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. In 2023, a finance lease receivable was recognized as it was determined that the significant risks and rewards of ownership of the facilities were transferred to the customer. See Note 17.

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. Information regarding the impacts of the Company’s tax policies is disclosed in Note 11.

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. Transfers between levels of the fair value hierarchy are deemed to have occurred at             

the end of the reporting period in which the event or change in circumstances that caused the transfer occurred. These fair value levels are outlined and discussed in more detail in Note 14. 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 fulfilled.

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 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 when determining the amount to be capitalized. Information regarding project development costs is disclosed in Note 22 and 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). 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 to 2023 in respect of decommissioning and restoration provisions is disclosed in Notes 7, 18 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;

•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. Disclosures on employee future benefits are disclosed in Note 31.

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 8 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, to determine when this transfer occurs.

When contracts are modified, management must exercise judgment to determine, depending upon the facts and circumstances of the changes to the contract, whether the modification is accounted for as a new contract or as part of the existing contract. If it is required to be accounted for as part of the existing contract the transaction price can be affected and adjustments to previously recognized revenue can occur, or the impacts can be reflected prospectively from the modification date.

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, and this 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.

XII. Significant Influence

Upon entering into an investment, the Company must classify it as either an investment in 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, 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, 2023, there were changes in estimates relating to asset impairment charges (reversals) (Note 7), useful lives (Note 18), decommissioning and other provisions (Note 23) and defined benefit obligation (Note 26). During the year ended

Dec. 31, 2022, there were changes in estimates relating to asset impairment charges (reversals) (Note 7), asset useful lives and depreciation (Note 18), decommissioning and other provisions (Note 23) and defined benefit obligation (Note 26).

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Accounting Changes

12 Months Ended

Dec. 31, 2023

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

Accounting Changes

Accounting Changes

A. Current Accounting Changes

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

On May 7, 2021, the International Accounting Standards Board (“IASB”) issued Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction, which amends IAS 12 Income Taxes. 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, and were adopted by the Company on that date. The Company's accounting aligns with the amendment and no financial impact arose upon adoption.

Amendments to IAS 12 International Tax Reform — Pillar Two Model Rules

The Organization for Economic Co-operation and Development (OECD) published Pillar Two model rules in December 2021 to ensure that large multinational companies would be subject to a minimum 15 per cent tax rate. In May 2023, the IASB issued amendments to IAS 12 Income Taxes to provide companies with immediate temporary relief from accounting for deferred taxes arising from the OECD international tax reform. The amendments clarify that IAS 12 applies to income taxes arising from tax law enacted or substantively enacted to implement the Pillar Two model rules published by the OECD. Pillar Two legislation has not been enacted or substantively enacted in any jurisdiction in which the Company operates and therefore has not been reflected within our tax provisions at Dec. 31, 2023.

B. Future Accounting Changes

The Company closely monitors both new accounting standards and amendments to existing accounting standards issued by the IASB. The following standards have been issued but are not yet in effect.

Amendments to IAS 1 Non-current Liabilities with Covenants and Classification of Liabilities as Current or Non-current 

In October 2022, the IASB issued Non-current Liabilities with Covenants, which amends IAS 1 Presentation of Financial Statements, to clarify how conditions with which an entity must comply within 12 months after the reporting period affect the classification of a liability. In January 2020, the IASB issued Classification of Liabilities as Current or Non-current, which amends IAS 1 Presentation of Financial Statements regarding the classification of liabilities as current or non‐current, clarifying that contractual 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.

Additionally, the IASB clarified that the classification of a liability is unaffected by the likelihood that an entity will exercise its deferral right. The amendments are effective for annual periods beginning on or after Jan. 1, 2024, and are to be applied retrospectively. On Jan. 1, 2024, the Company will re-classify the Exchangeable Securities from non-current liabilities to current liabilities as the conversion option can be exercised at any time after Jan. 1, 2025, although there is no obligation to deliver cash equivalent resources and the holder cannot call for repayment. This accounting is consistent with the amendment.

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.

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Business Acquisitions

12 Months Ended

Dec. 31, 2023

Business Combinations 1 [Abstract]

Business Acquisitions

Business Acquisitions

TransAlta to Acquire Heartland Generation

On Nov. 2, 2023, the Company announced that it had entered into a definitive share purchase agreement (the "Agreement") with an affiliate of Energy Capital Partners, the parent of Heartland Generation Ltd. and Alberta Power (2000) Ltd. (collectively, "Heartland"), pursuant to which TransAlta will acquire Heartland and its entire business operations in Alberta and British Columbia. The purchase price for the acquisition is $390 million, subject to working capital and other adjustments, as well as the assumption of $268 million of debt, for a total cost of $658 million. The Company will finance the transaction using cash on hand and draws on its credit facilities. Closing of the transaction remains subject to regulatory approval.

Acquisition of TransAlta Renewables

On Oct. 5, 2023, the Company completed the acquisition of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by the Company. The consideration paid totalled $1.3 billion, comprising $800 million of cash and 46 million common shares of the Company valued at $514 million, based on an $11.06 closing price of the Company’s shares on the Toronto Stock Exchange on Oct. 4, 2023.

Transaction costs of $11 million incurred to effect the acquisition, have been charged, net of income tax, against Common Shares ($4 million) and Deficit ($7 million) on closing of the acquisition.

Since the Company retained control of TransAlta Renewables, the acquisition was accounted for as an equity transaction. On closing of the transaction, Non-controlling Interests was reduced by $630 million and Accumulated Other Comprehensive Loss increased by $64 million to eliminate the balances previously attributed to non-controlling interest holders of TransAlta Renewables. The difference between consideration paid and these amounts was recognized in Deficit.

The Company's syndicated credit facilities were amended to effectively consolidate the TransAlta Renewables syndicated credit facility and non-committed demand facility into the TransAlta credit facilities. The cash drawings on the TransAlta Renewables' syndicated credit facility were repaid and the outstanding letters of credit were transferred to the TransAlta non-committed demand facility. The TransAlta Renewables' credit facilities were then terminated. This resulted in the TransAlta syndicated credit facility increasing by $700 million to approximately $2.0 billion. Refer to Note 24.

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Revenue

12 Months Ended

Dec. 31, 2023

Disclosure of revenue from contracts with customers [Abstract]

Revenue

Revenue

A. Disaggregation of Revenue

The majority of the Company's revenues are derived from the sale of 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, 2023	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Revenues from contracts with customers
Power and other	30	190	400	12	—	—	632
Environmental attributes(1)	14	26	—	—	—	—	40
Revenue from contracts with customers	44	216	400	12	—	—	672
Revenue from leases(2)	—	—	32	—	—	—	32
Revenue from derivatives and other trading activities(3)	44	(2)	(172)	251	220	—	341
Revenue from merchant sales	434	104	1,247	488	—	—	2,273
Other(4)	11	18	7	—	—	1	37
Total revenue	533	336	1,514	751	220	1	3,355
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	14	26	—	12	—	—	52
Over time	30	190	400	—	—	—	620
Total revenue from contracts with customers	44	216	400	12	—	—	672

(1)The environmental attributes represent environmental attribute sales not bundled with power and other sales.

(2)Total lease income from long-term contracts that meet the criteria of operating leases.

(3)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions.

(4) Other revenue includes production tax credits related to US wind facilities and other miscellaneous revenues.

Year ended Dec. 31, 2022	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Revenues from contracts with customers
Power and other	33	220	462	10	—	—	725
Environmental attributes(1)	1	50	—	—	—	—	51
Revenue from contracts with customers	34	270	462	10	—	—	776
Revenue from leases(2)	—	—	32	—	—	—	32
Revenue from derivatives and other trading activities(3)	—	(121)	(821)	243	160	(2)	(541)
Revenue from merchant sales	564	119	1,529	461	—	—	2,673
Other(4)	8	21	7	—	—	—	36
Total revenue	606	289	1,209	714	160	(2)	2,976
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	1	50	—	12	—	—	63
Over time	33	220	462	(2)	—	—	713
Total revenue from contracts with customers	34	270	462	10	—	—	776

(1)The environmental attributes represent environmental attribute sales not bundled with power and other sales.

(2)Total lease income from long-term contracts that meet the criteria of operating leases.

(3)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions.

(4)Other revenue includes production tax credits related to US wind facilities and other miscellaneous revenues.

Year ended Dec. 31, 2021	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Revenues from contracts with customers
Power and other	28	207	395	24	—	—	654
Environmental attributes(1)	—	28	—	—	—	—	28
Revenue from contracts with customers	28	235	395	24	—	—	682
Revenue from leases(2)	—	—	19	—	—	—	19
Revenue from derivatives and other trading activities(3)	—	(22)	(118)	138	211	4	213
Revenue from merchant sales	345	35	808	546	—	—	1,734
Other(4)	10	57	5	1	—	—	73
Total revenue	383	305	1,109	709	211	4	2,721
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)The environmental attributes represent environmental attribute sales not bundled with power and other sales.

(2)Total lease income from long-term contracts that meet the criteria of operating leases.

(3)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions.

(4)Other revenue includes production tax credits related to US wind facilities and other miscellaneous revenues.

B. Performance Obligations

The performance obligations in the Company's contracts with its customers include the provision of electricity and steam capacity; the delivery of electricity, thermal energy and environmental attributes; the provision of operation and maintenance services and water management services; and the supply of byproducts from coal generation.

The aggregate amount of transaction prices allocated to remaining performance obligations (contract revenues that have not yet been recognized) as at Dec. 31, 2023, is approximately $2,700 million, with approximately $510 million expected to be recognized during the period 2024-2026; $505 million for the period of 2027-2029; $725 million for the period of 2030-2034; and $960 million for 2035 and thereafter.

These amounts exclude revenues related to contracts that qualify for the invoice practical expedient and future revenues that are related to constrained variable consideration. 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. As a result, the amounts of future revenues disclosed above represent only a portion of future revenues that are expected to be realized by the Company from its contractual portfolio.

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Expenses by Nature

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Expenses by Nature

Expenses by Nature

Fuel, Purchased Power and Operations, Maintenance and Administration ("OM&A")

Fuel and purchased power and OM&A expenses classified by nature are as follows:

Year ended Dec. 31	2023		2022		2021
	Fuel and purchased power	OM&A	Fuel and purchased power	OM&A	Fuel and purchased power	OM&A
Gas fuel costs	384	—	578	—	306	—
Coal fuel costs(1)	177	—	146	—	164	—
Royalty, land lease, other direct costs	25	—	25	—	19	—
Purchased power	474	—	514	—	339	—
Mine depreciation(2)	—	—	—	—	190	—
Salaries and benefits	—	254	—	263	36	234
Other operating expenses(3)	—	285	—	258	—	277
Total	1,060	539	1,263	521	1,054	511

(1)Included in coal fuel costs for 2021 was $17 million related to the impairment of coal inventory.

(2)Included in mine depreciation for 2021 was $48 million related to mine depreciation that was initially recorded in the standard cost of coal inventory and then subsequently written down during 2021.

(3)Included in OM&A costs for 2023 was $14 million related to the write-down of parts and material inventory related to our natural-gas-fired facilities. 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.

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Asset Impairment Charges (Reversals)

12 Months Ended

Dec. 31, 2023

Disclosure of impairment of assets [Abstract]

Asset Impairment Charges (Reversals)

Asset Impairment Charges (Reversals)

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 or fair value less costs of disposal) for the affected CGUs using discounted cash flow projections. The valuations are subject to measurement uncertainty from assumptions and inputs to the discount rates, power price forecasts, useful lives of the assets (extending to the last planned asset retirement in 2072) and long-range forecasts, which includes changes to production, fuel costs, operating costs and capital expenditures.

The Company recognized the following asset impairment charges (reversals):

Year ended Dec. 31	2023	2022	2021
Segments:
Hydro	(10)	21	5
Wind and Solar	(4)	43	12
Gas		—	5
Energy Transition	—	—	540
Corporate	—	(2)	27
Changes in decommissioning and restoration provisions on retired assets(1)	(34)	(53)	32
Intangible asset impairment charges - coal rights	—	—	17
Project development costs	—	—	10
Asset impairment charges (reversals)	(48)	9	648

(1)Changes relate to changes in discount rates and cash flow revisions on retired assets in 2023 and 2022 and cash flow revisions on retired assets in 2021. Refer to Note 23 for further details.

Hydro

During 2023, internal valuations indicated the fair value less costs of disposal for two hydro facilities exceeded the carrying value due to a contract extension and changes in power price assumptions, which favourably impacted estimated future cash flows and resulted in a recoverability test. As a result of the recoverability test an impairment reversal of $10 million was recognized. The recoverable amounts of $70 million in total were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement.

During 2022, the Company recorded net impairment charges of $21 million on four hydro facilities as a result of changes in key assumptions, that included significant increases in discount rates, changes in pricing and changes in estimated future cash flows. The recoverable amounts of $89 million in total for these four assets were estimated based on fair value less costs of disposal using a discounted cash flow approach and are categorized as a Level III fair value measurement.

Wind and Solar

During 2023, the Company recorded net impairment reversals of $4 million.

During the year, internal valuations indicated the fair value less costs of disposal of the assets exceeded the carrying value due to changes in power price assumptions for three wind facilities, which favourably impacted estimated future cash flows and resulted in impairment reversals of $17 million. The recoverable amounts of $540 million in total were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement.

Also in 2023, two wind facilities were impaired primarily due to unfavourable power price assumptions and changes in estimated future cash flows, resulting in a $13 million impairment charge. The recoverable amounts of $130 million for these two assets were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement.

During 2022, the Company recorded net impairment charges of $43 million on five wind facilities and one solar facility as a result of changes in key assumptions, that included significant increases in discount rates, changes in pricing and changes in estimated future cash flows. The recoverable amounts of $754 million for these six assets were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and categorized as a Level III fair value measurement.

During 2021, the Company recorded impairment charges of $10 million for a wind asset as a result of an increase in estimated decommissioning costs after the review of an engineering study commissioned for the wind sites. The recoverable amount of $65 million was estimated based on

fair value less costs of disposal utilizing a discounted cash flow approach, using a discount rate of 5.0 per cent, and was categorized as a Level III fair value measurement.

Additionally, during 2021, the Company recognized impairment charges 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.

The calculation of fair value less costs of disposal for all of the above facilities is most sensitive to the following assumptions:

	Location of assets	Current year contract and merchant discount rates	Prior year contract and merchant discount rates
Wind and Solar	Canada	6.4 and 7.0 per cent	6.4 and 7.1 per cent
	US	6.9 and 7.5 per cent	6.5 and 7.7 per cent
Hydro	Canada	6.1 and 6.4 per cent	5.9 and 6.4 per cent

Energy Transition

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), and 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 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. Discounting did not have a material impact on 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 2021, with the expected closure of the Highvale mine at the end of 2021, it was determined that the estimated salvage value of the Highvale mine exceeded its 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 $195 million in the Energy Transition segment, with the asset being written down to salvage value.

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 impairment charges 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. During the fourth quarter of 2022, the dispute was settled. The Company reversed $2 million of the impairment loss previously recognized.

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Net Other Operating (Income) Loss

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Net Other Operating (Income) Loss

Net Other Operating (Income) Loss

Net other operating (income) loss includes the following:

Year ended Dec. 31	2023	2022	2021
Alberta Off-Coal Agreement	(40)	(40)	(40)
Liquidated damages recoverable	(6)	(12)	—
Insurance recoveries	(1)	(7)	—
Supplier, other contract settlements and other	—	1	34
Onerous contract provisions	—	—	14
Net other operating (income) loss	(47)	(58)	8

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.

Liquidated Damages Recoverable

During 2023, the Company recognized $3 million of recoverable liquidated damages related to requirements to be met by the contractor on turbine availability at the Windrise wind facility (2022 - $12 million) and $3 million for availability guarantees at other facilities (2022 - nil).

Insurance Recoveries

During 2023, the Company received insurance proceeds of $1 million related to the replacement costs for the single tower failure at the Kent Hills wind facilities (2022 - $7 million).

Supplier, Other Contract Settlements and Other

During 2021, $34 million was expensed related to decisions to suspend 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.

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.

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Investments

12 Months Ended

Dec. 31, 2023

Interests In Other Entities [Abstract]

Investments

Investments

The change in investments is as follows:

	EMG	Skookumchuck	Tent Mountain	EIP	Ekona	Total
Classification	Equity-accounted	Equity-accounted	Equity-accounted	FVTPL	FVTOCI
Balance, Dec. 31, 2021	12	93	—	—	—	105
Investment	—	—	—	10	2	12
Equity income (loss)	(1)	10	—	—	—	9
Distributions received	—	(5)	—	—	—	(5)
Changes in foreign exchange rates	1	7	—	1	—	9
Net change in fair value recognized in OCI	—	—	—	—	(1)	(1)
Balance, Dec. 31, 2022	12	105	—	11	1	129
Investment	—	—	10	4	—	14
Equity income (loss)	(4)	8	—	—	—	4
Distributions received	—	(6)	—	—	—	(6)
Changes in foreign exchange rates	—	(3)	—	—	—	(3)
Balance, Dec. 31, 2023	8	104	10	15	1	138

Equity-accounted Investments

The Company’s investments in joint ventures and associates that are accounted for using the equity method consist of its investments in Skookumchuck, EMG and Tent Mountain Renewable Energy Complex (“Tent Mountain”).

EMG International, LLC ("EMG")

TransAlta holds a 30 per cent interest in EMG, a wastewater treatment processing company. Earnings are derived from the design and construction of wastewater treatment facilities. During 2022, the contingent purchase price consideration of US$3.5 million was paid, which was calculated based on actual earnings metrics achieved in 2021 and did not differ from the estimated amount included in the initial purchase price.

Skookumchuck Wind Project

TransAlta holds a 49 per cent membership interest in SP Skookumchuck Investment, LLC. Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state. The project has a 20-year PPA with Puget Sound Energy.

Tent Mountain Pumped Hydro Development Project

On April 24, 2023, the Company acquired a 50 per cent interest in Tent Mountain, an early-stage 320 MW pumped hydro energy storage development project, located in southwest Alberta, from Evolve Power Ltd. ("Evolve"), formerly known as Montem Resources Limited. The acquisition included land rights, fixed assets and intellectual property associated with the pumped hydro development project. The Company paid Evolve approximately $8 million on closing and made additional investments of $2 million during the balance of 2023. Additional contingent payments of up to $17 million may become payable to Evolve based on the achievement of specific development and commercial milestones. The Company and Evolve jointly control Tent Mountain, with the result that the Company accounts for its interest in the joint venture as an investment using the equity method.

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

Year ended Dec. 31	2023	2022	2021
Results of operations
Revenues and other operating income	22	24	19
Expenses	(18)	(15)	(10)
Proportionate share of net earnings	4	9	9

Other Investments

Energy Impact Partners

On May 6, 2022, the Company entered into a commitment to invest US$25 million over the next four years in Energy Impact Partners ("EIP") 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. The investment is accounted for at FVTPL.

Ekona Power Inc.

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 is being developed to produce cleaner and lower-cost turquoise hydrogen. The Company has irrevocably elected to measure its investment in Ekona at FVTOCI.

Joint Arrangements

Joint arrangements at Dec. 31, 2023, 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
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
Tent Mountain	Hydro	50	Pumped hydro energy storage development project in Alberta

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Interest Expense

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Interest Expense

Interest Expense

The components of interest expense are as follows:

	2023	2022	2021
Interest on debt	203	164	163
Interest on exchangeable debentures (Note 25)	29	29	29
Interest on exchangeable preferred shares (Note 25)	28	28	28
Capitalized interest (Note 18)	(57)	(16)	(14)
Interest on lease liabilities	9	7	7
Credit facility fees, bank charges and other interest	21	27	20
Tax shield on tax equity financing (Note 24)	—	(2)	(9)
Accretion of provisions (Note 23)	48	49	32
Interest expense	281	286	256

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Income Taxes

12 Months Ended

Dec. 31, 2023

Income Taxes [Abstract]

Income Taxes

Income Taxes

Consolidated Statements of Earnings

I. Rate Reconciliation

Year ended Dec. 31	2023		2022		2021
Earnings (loss) before income taxes	880		353		(380)
Net earnings attributable to non-controlling interests not subject to tax	(80)		(94)		(33)
Adjusted earnings (loss) before income taxes	800		259		(413)
Statutory Canadian federal and provincial income tax rate (%)	23.4	%	23.4	%	23.6	%
Expected income tax expense (recovery)	187		61		(98)
Increase (decrease) in income taxes resulting from:
Differences in effective foreign tax rates	9		(1)		4
Non-deductible expense(1)	58		130		—
Taxable capital (gain) loss	(2)		18		—
Deferred income tax recovery related to temporary difference on investment in subsidiaries	(3)		(2)		—
Write-down (reversal of write-down) of unrecognized deferred income tax assets	(178)		(24)		134
Statutory and other rate differences	1		(3)		4
Adjustments in respect of deferred income tax of previous years	1		6		(4)
Other	11		7		5
Income tax expense	84		192		45
Effective tax rate (%)	11	%	74	%	(11	%)

(1)This amount is related to current and prior period tax adjustments in the US to mitigate cash tax relating to the Base Erosion and Anti-Abuse Tax.

II. Components of Income Tax Expense

The components of income tax expense are as follows:

Year ended Dec. 31	2023	2022	2021
Current income tax expense	50	65	56
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences	215	153	(145)
Deferred income tax recovery related to temporary difference on investment in subsidiaries	(3)	(2)	—
Write-down (reversal of write-down) of unrecognized deferred income tax assets(1)	(178)	(24)	134
Income tax expense	84	192	45
Current income tax expense	50	65	56
Deferred income tax expense (recovery)	34	127	(11)
Income tax expense	84	192	45

(1)During the year ended Dec. 31, 2023, the Company recognized deferred tax assets of $178 million (2022 - $24 million, 2021 - $134 million write-down). The deferred income tax assets mainly relate to the tax benefits associated with tax losses related to the Company's directly owned US operations and other deductible differences. The Company has not recognized an additional $157 million of deferred tax assets on the basis that it is not probable that sufficient future taxable income would be available to utilize these tax assets.

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	2023	2022	2021
Income tax expense (recovery) related to:
Net impact related to cash flow hedges	27	(112)	(57)
Net impact related to hedges of foreign operations	1	(3)	—
Net impact related to net actuarial gains (losses)	(1)	12	11
Transaction costs for the acquisition of TransAlta Renewables	(2)	—	—
Income tax expense (recovery) reported in equity	25	(103)	(46)

Consolidated Statements of Financial Position

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

As at Dec. 31	2023	2022
Non-capital losses(1)	88	244
Future decommissioning and restoration costs	111	119
Property, plant and equipment	(605)	(553)
Risk management assets and liabilities, net	144	193
Employee future benefits and compensation plans	50	48
Foreign exchange differences on US-denominated debt	12	13
Other taxable temporary differences	(8)	(5)
Net deferred income tax asset (liability), before write-down of deferred income tax assets	(208)	59
Unrecognized deferred income tax assets	(157)	(361)
Net deferred income tax liability, after write-down of deferred income tax assets	(365)	(302)

(1)Non-capital losses expire between 2033 and 2043. Net operating losses from US operations have no expiration.

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

As at Dec. 31	2023	2022
Deferred income tax assets(1)	21	50
Deferred income tax liabilities	(386)	(352)
Net deferred income tax liability	(365)	(302)

(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.

Contingencies

As of Dec. 31, 2023, the Company had recognized a net liability of nil (2022 – nil) related to uncertain tax positions.

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Non-Controlling Interests

12 Months Ended

Dec. 31, 2023

Interests In Other Entities [Abstract]

Non-Controlling Interests

Non-Controlling Interests

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

Subsidiary / Operation	Non-controlling interest owner	Non-controlling interest as at Dec. 31, 2023	Non-controlling interest as at Dec. 31, 2022
TransAlta Cogeneration LP	Canadian Power Holdings Inc.	49.99%	49.99%
Kent Hills Wind LP	Natural Forces Technologies Inc.	17%	17%
TransAlta Renewables Inc.	Public shareholders	nil(1)	39.9%

(1)Non-controlling interest from Jan. 1, 2023 to Oct. 4, 2023 was 39.9%.

TransAlta Cogeneration, LP (“TA Cogen”) operates a portfolio of cogeneration facilities in Canada and owns 50 per cent of a dual-fuel generating facility.

Kent Hills Wind LP owns and operates the 167 MW Kent Hills (1, 2 and 3) wind facilities located in New Brunswick. Kent Hills Wind LP is a subsidiary of TransAlta Renewables Inc. ("TransAlta Renewables").

TransAlta Renewables owns 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. On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. TransAlta Renewables at Dec. 31, 2023, is a wholly owned subsidiary of the Company. Refer to Note 4 for more details.

Summarized financial information relating to subsidiaries with significant non-controlling interests is as follows:

TA Cogen

Year ended Dec. 31	2023	2022	2021
Revenues	290	347	265
Net earnings and total comprehensive income	121	143	103
Amounts attributable to the non-controlling interest:
Net earnings	80	91	62
Total comprehensive income	80	91	62
Distributions paid to Canadian Power Holdings Inc.	148	87	56

As at Dec. 31	2023	2022
Current assets	43	127
Long-term assets	193	253
Current liabilities	(41)	(62)
Long-term liabilities	(34)	(27)
Total equity	(161)	(291)
Equity attributable to Canadian Power Holdings Inc.	(79)	(147)
Non-controlling interest share (per cent)	49.99	49.99

Kent Hills Wind LP

Prior to Oct 5, 2023, financial information related to the 17 per cent non-controlling interest in Kent Hills Wind LP was included in the financial information disclosed in TransAlta Renewables in this note.

Year ended Dec. 31	2023(1)
Revenues	7
Net earnings and total comprehensive income	2
Amounts attributable to the non-controlling interest:
Net earnings and total comprehensive income	—

(1)This represents financial information from Oct. 5, 2023 to Dec. 31, 2023. The net earnings attributable to non-controlling interest in Kent Hills Wind LP prior to Oct. 5, 2023, is included in the disclosures for TransAlta Renewables.

As at Dec. 31	2023
Current assets	35
Long-term assets	481
Current liabilities	(42)
Long-term liabilities	(188)
Total equity	(285)
Equity attributable to non-controlling interests	(48)
Non-controlling interest share (per cent)	17

TransAlta Renewables

The financial information disclosed below includes the 17 per cent non-controlling interest in Kent Hills Wind LP until Oct. 5, 2023.

Year ended Dec. 31	2023(1)	2022	2021
Revenues	303	560	470
Net earnings	56	74	139
Total comprehensive income (loss)	(7)	(67)	66
Amounts attributable to the non-controlling interests:
Net earnings	21	20	50
Total comprehensive income (loss)	(4)	(36)	21
Distributions paid to non-controlling interests	75	100	100

(1)Non-controlling interest share prior the close of the transaction on Oct. 5, 2023. This represents financial information from Jan. 1, 2023 to Oct. 4, 2023.

As at Dec. 31	2022
Current assets	240
Long-term assets	2,989
Current liabilities	(306)
Long-term liabilities	(1,118)
Total equity	(1,805)
Equity attributable to non-controlling interests	(732)
Non-controlling interests’ share (per cent)	39.9

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Trade and Other Receivables and Accounts Payable

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Trade and Other Receivables and Accounts Payable

Trade and Other Receivables and Accounts Payable

As at Dec. 31	2023	2022
Trade accounts receivable	600	1,165
Collateral provided (Note 15)	145	304
Current portion of finance lease receivables (Note 17)	19	52
Loan receivable (Note 22)	1	4
Income taxes receivable	42	64
Trade and other receivables	807	1,589

As at Dec. 31	2023	2022
Accounts payable and accrued liabilities	772	1,069
Interest payable	16	17
Collateral held (Note 15)	9	260
Accounts payable and accrued liabilities	797	1,346

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Financial Instruments

12 Months Ended

Dec. 31, 2023

Disclosure of detailed information about financial instruments [abstract]

Financial Instruments

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.

Carrying value as at Dec. 31, 2023	Derivatives used for hedging	Derivatives held for trading (FVTPL)	Amortized cost	Other financial assets (FVTPL)	Other financial assets (FVOCI)	Total
Financial assets
Cash and cash equivalents(1)	—	—	348	—	—	348
Restricted cash	—	—	69	—	—	69
Trade and other receivables	—	—	807	—	—	807
Long-term portion of finance lease receivables	—	—	171	—	—	171
Long-term portion of loan receivable(2)	—	—	25	—	—	25
Other investments(3)	—	—	—	15	1	16
Risk management assets
Current	—	151	—	—	—	151
Long-term	—	52	—	—	—	52
Financial liabilities
Bank overdraft	—	—	3	—	—	3
Accounts payable and accrued liabilities	—	—	797	—	—	797
Dividends payable	—	—	49	—	—	49
Risk management liabilities
Current	125	189	—	—	—	314
Long-term	80	194	—	—	—	274
Credit facilities, long-term debt and lease liabilities(4)	—	—	3,466	—	—	3,466
Exchangeable securities	—	—	744	—	—	744

(1)Includes cash equivalents of nil.

(2)Included in other assets. Refer to Note 22.

(3)Included in investments. Refer to Note 9.

(4)Includes current portion.

Carrying value as at Dec. 31, 2022	Derivatives used for hedging	Derivatives held for trading (FVTPL)	Amortized cost	Other financial assets (FVTPL)	Other financial assets (FVTOCI)	Total
Financial assets
Cash and cash equivalents(1)	—	—	1,134	—	—	1,134
Restricted cash	—	—	70	—	—	70
Trade and other receivables	—	—	1,589	—	—	1,589
Long-term portion of finance lease receivables	—	—	129	—	—	129
Long-term portion of loan receivable(2)	—	—	33	—	—	33
Other investments(3)	—	—	—	11	1	12
Risk management assets
Current	—	709	—	—	—	709
Long-term	—	161	—	—	—	161
Financial liabilities
Bank overdraft	—	—	16	—	—	16
Accounts payable and accrued liabilities	—	—	1,346	—	—	1,346
Dividends payable	—	—	68	—	—	68
Risk management liabilities
Current	271	858	—	—	—	1,129
Long-term	76	257	—	—	—	333
Credit facilities, long-term debt and lease liabilities(4)	—	—	3,653	—	—	3,653
Exchangeable securities	—	—	739	—	—	739

(1)Includes cash equivalents of nil.

(2)Included in other assets. Refer to Note 22.

(3)Included in investments. Refer to Note 9.

(4)Includes current portion.

B. Fair Value of Financial Instruments

The fair value of a financial instrument is the price that would be received when selling the asset or paid to transfer the associated liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by observing quoted prices for the 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.

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. The Level III classification is the lowest level classification in the fair value hierarchy.

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 scenario analysis simulation 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. 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.

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.

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 segments 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, 2023, are as follows: Level I – $13 million net liability (Dec. 31, 2022 – $23 million net asset), Level II – $244 million net liability (Dec. 31, 2022 – $173 million net asset) and Level III – $147 million net liability (Dec. 31, 2022 – $782 million net liability).

Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2023, are primarily attributable to contract settlements and volatility in market prices across multiple markets on both existing contracts and new contracts.

The following table summarizes 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, 2023 and 2022, respectively:

	Year ended Dec. 31, 2023			Year ended Dec. 31, 2022
	Hedge	Non-hedge	Total	Hedge	Non-hedge	Total
Opening balance	(347)	(435)	(782)	285	(126)	159
Changes attributable to:
Market price changes on existing contracts	(123)	(6)	(129)	(611)	(298)	(909)
Market price changes on new contracts	—	18	18	—	(124)	(124)
Contracts settled	256	269	525	(38)	118	80
Change in foreign exchange rates	9	7	16	17	(5)	12
Transfers out of Level III(1)	205	—	205	—	—	—
Net risk management assets (liabilities) at end of year	—	(147)	(147)	(347)	(435)	(782)
Additional Level III information:
Losses recognized in other comprehensive loss	(114)	—	(114)	(594)	—	(594)
Total gains (losses) included in earnings before income taxes	(256)	19	(237)	38	(427)	(389)
Unrealized gains (losses) included in earnings before income taxes relating to net assets (liabilities) held at year end	—	288	288	—	(309)	(309)

(1)The Company has a long-term fixed price power sale contract in the US for delivery of power. The fair value of this instrument was transferred out of Level III to Level II as at Dec. 31, 2023 as the forward price curve is now based on observable market prices for the remaining duration of the contract.

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 processes. 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, the 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.

As at Dec. 31, 2023, the total Level III risk management asset balance was $56 million (Dec. 31, 2022 – $31 million) and Level III risk management liability balance was $203 million (Dec. 31, 2022 – $813 million). The net risk management liabilities decreased mainly due to market price changes and settled contracts. 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 are outlined in the following table. 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.

As at	Dec. 31, 2023
Description	Valuation technique	Unobservable input	Reasonably possible change	Sensitivity(1)
Coal transportation – US	Numerical derivative valuation	Volatility	80% to 120%	+6
		Rail rate escalation	zero to 10%	-4
Full requirements – Eastern US	Scenario analysis	Volume	96% to 104%	+3
		Cost of supply	Decrease of $2.30 per MWh or increase of $2.40 per MWh	-3
Long-term wind energy sale – Eastern US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease or increase of US$6	+24
		Illiquid future REC prices (per unit)	Price decrease of US$12 or increase of US$8
		Wind discounts	0% decrease or 9% increase	-28
Long-term wind energy sale – Canada	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of C$81 or increase of C$5	+65
		Wind discounts	16% decrease or 5% increase	-23
Long-term wind energy sale - Central US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$1 or increase of US$2	+81
		Wind discounts	5% decrease or 2% increase	-36

(1)Sensitivity represents the total increase or decrease in recognized fair value that could arise from the use of the reasonably possible changes of all unobservable inputs.

As at	Dec. 31, 2022
Description	Valuation technique	Unobservable input	Reasonably possible change	Sensitivity(1)
Coal transportation – US	Numerical derivative valuation	Illiquid future power prices (per MWh)	Price decrease of US$5 or increase of US$55	+14
		Volatility	80% to 120%
		Rail rate escalation	zero to 10%	-13
Full requirements - Eastern US	Scenario analysis	Volume	96% to 104%	+3
		Cost of supply	Decrease of US$0.50 per MWh or increase of US$3.30 per MWh	-21
Long-term wind energy sale – Eastern US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease or increase of US$6	+22
		Illiquid future REC prices (per unit)	Price decrease or increase of US$2
		Wind discounts	0% decrease or 5% increase	-18
Long-term wind energy sale – Canada	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of C$85 or increase of C$5	+47
		Wind discounts	28% decrease or 5% increase	-25
Long-term wind energy sale – Central US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease or increase of US$2	+74
		Wind discounts	2% decrease or 5% increase	-28
Long-term power sale – US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$5 or increase of US$55	+15
				-163

(1)Sensitivity represents the total increase or decrease in recognized fair value that would arise from the use of the reasonably possible changes of all unobservable inputs.

a. 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.

The key unobservable inputs used in the valuation include option volatility and rail rate escalation. Option volatility and rail rate escalation ranges have been determined based on historical data and professional judgment.

In the first three quarters of 2023, non-liquid power prices were also used as a key unobservable input. At Dec. 31, 2023, the relevant forward power prices were observable in the market.

b. 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.

c. Long-Term Wind Energy Sale – Eastern US

The Company is party to a long-term contract for differences ("CFD") for the offtake of 100 per cent of the generation from its 90 MW Big Level wind facility. The CFD, together with the sale of electricity generated into the PJM Interconnection at the prevailing real-time energy market price, achieve the fixed contract price per MWh on proxy generation. Under the CFD, if the market price is lower than the fixed contract price the customer pays the Company the difference and if the market price is higher than the fixed contract price the Company refunds the difference to the customer. The customer is also entitled to the physical delivery of environmental attributes. The contract matures in December 2034. The contract is accounted for as a derivative. Changes in fair value are presented in revenue.

The key unobservable inputs used in the valuation of the contract are expected proxy generation volumes and non-liquid forward prices for power, RECs and wind discounts.

d. Long-Term Wind Energy Sale – Canada

The Company is party to two Virtual Power Purchase Agreements ("VPPAs") for the offtake of 100 per cent of the generation from its 130 MW Garden Plain wind facility. The VPPAs, together with the sale of electricity generated into the Alberta power market at the pool price, achieve the fixed contract prices per MWh. Under the VPPAs, if the pool price is lower than the fixed contract price the customer pays the Company the difference and if the pool price is higher than the fixed contract price the Company refunds the difference to the customer. The customers are also entitled to the physical delivery of environmental attributes. Both VPPAs commenced on commercial operation of the facility which was achieved in August 2023, and extend for a weighted average of approximately 17 years.

The energy components of these contracts are accounted for as derivatives. Changes in fair value are presented in revenue.

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

e. Long-Term Wind Energy Sale – Central US

The Company is party to two long-term VPPAs for the offtake of 100 per cent of the generation from its 300 MW White Rock East and White Rock West wind power projects. The VPPAs, together with the sale of electricity generated into the US Southwest Power Pool ("SPP") market at the relevant price nodes, achieve the fixed contract prices per MWh. Under the VPPAs, if the SPP pricing is lower than the fixed contract price the customers pay the Company the difference, and if the SPP pricing is higher than the fixed contract price, the Company refunds the difference to the customers. The customer is also entitled to the physical delivery of environmental attributes. During the fourth quarter of 2023, the Company and the customer for the White Rock wind projects amended the associated VPPAs. The VPPAs commence on commercial operation of the facilities.

The Company is also party to a VPPA for the offtake of 100 per cent of the generation from its 200 MW Horizon Hill wind power project. The VPPA, together with the sale of electricity generated into the SPP market at the relevant price node, achieve the fixed contract price per MWh. Under the VPPA, if the SPP pricing is lower than the fixed contract price the customer pays the Company the difference and if the SPP pricing is higher than the fixed contract price the Company refunds the difference to the customer. The customer remains entitled to the physical delivery of environmental attributes. During the second quarter of 2023, the Company and the customer for the

Horizon Hill wind project amended the associated VPPA. The VPPA commences on commercial operation of the facility. Commissioning of the Horizon Hill wind project is expected during the first quarter of 2024.

The energy components of these contracts are accounted for as derivatives. Changes in fair value are presented in revenue. The amendments to the Horizon Hill and White Rock VPPAs did not change the nature of the contracts and the energy components continue to be accounted for as derivatives.

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

f. 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.

At Dec. 31, 2023, the contract was transferred to Level II as all significant inputs were observable. In the first three quarters of 2023, the term of the transaction extended beyond where the relevant forward power prices were observable in the market.

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 $19 million as at Dec. 31, 2023 (Dec. 31, 2022 – $6 million net liability) are classified as Level II fair value measurements. The changes in other net risk management assets and liabilities during the year ended Dec. 31, 2023, are attributable to favourable market price changes on existing contracts, favourable foreign exchange rates on new contracts entered into during 2023, and contracts settled during 2023.

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, 2023	—	718	—	718	744
Long-term debt — Dec. 31, 2023	—	3,104	—	3,104	3,323
Loan receivable — Dec. 31, 2023	—	26	—	26	26
Exchangeable securities — Dec. 31, 2022	—	685	—	685	739
Long-term debt — Dec. 31, 2022	—	3,200	—	3,200	3,518
Loan receivable — Dec. 31, 2022	—	37	—	37	37

(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 provided, bank overdraft, accounts payable and accrued liabilities, collateral held and dividends payable) approximates fair value due to the liquid nature of the asset or liability. The fair values of the finance lease receivables approximate the carrying amounts as 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 14 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 (loss) and a reconciliation of changes is as follows:

As at Dec. 31	2023	2022	2021
Unamortized net loss at beginning of year	(213)	(131)	(33)
New inception gains (losses)(1)	47	(37)	(79)
Change resulting from amended contract(2)	190	—	—
Change in foreign exchange rates	6	(10)	—
Amortization recorded in net earnings during the year	(27)	(35)	(19)
Unamortized net gain (loss) at end of year	3	(213)	(131)

(1)During 2023, the Company entered into long-term fixed price power sale contracts with certain of its US customers and as a result recognized day one inception gains that are based on the forward price curve at the inception of the contract. During 2022, the Company entered into a PPA for the Horizon Hill wind project (2021 – PPAs for the White Rock wind projects) that resulted in new inception losses 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 PPA.

(2)During 2023, the Company entered into certain contract amendments related to the Horizon Hill and White Rock wind projects. These amendments were mainly specific to obtaining price increases over the contract term. Accordingly, certain inception loss calibration adjustments were recognized within the risk management liability.

XML

Risk Management Activities

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Risk Management Activities

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.

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.

B. Net Risk Management Assets and Liabilities

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

As at Dec. 31, 2023
	Cash flow hedges	Not designated as a hedge	Total
Commodity risk management
Current	(125)	(53)	(178)
Long-term	(80)	(146)	(226)
Net commodity risk management liabilities	(205)	(199)	(404)
Other
Current	—	15	15
Long-term	—	4	4
Net other risk management assets	—	19	19
Total net risk management liabilities	(205)	(180)	(385)

As at Dec. 31, 2022
	Cash flow hedges	Not designated as a hedge	Total
Commodity risk management
Current	(271)	(143)	(414)
Long-term	(76)	(96)	(172)
Net commodity risk management liabilities	(347)	(239)	(586)
Other
Current	—	(6)	(6)
Long-term	—	—	—
Net other risk management liabilities	—	(6)	(6)
Total net risk management liabilities	(347)	(245)	(592)

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, 2023	Gross amounts of recognized financial assets (liabilities)	Amounts set off	Net amounts included on the statement of financial position	Master netting arrangements(1)	Net amount
Current risk management assets	528	(355)	173	(7)	166
Long-term risk management assets	161	(91)	70	(2)	68
Current risk management liabilities	(504)	355	(149)	7	(142)
Long-term risk management liabilities	(145)	91	(54)	2	(52)
Trade and other receivables(2)	789	(646)	143	(11)	132
Accounts payable and accrued  liabilities(2)	(760)	646	(114)	11	(103)

As at Dec. 31, 2022	Gross amounts of recognized financial assets (liabilities)	Amounts set off	Net amounts included on the statement of financial position	Master netting arrangements(1)	Net amount
Current risk management assets	1,602	(883)	719	(62)	657
Long-term risk management assets	204	(43)	161	(7)	154
Current risk management liabilities	(1,953)	883	(1,070)	62	(1,008)
Long-term risk management liabilities	(449)	43	(406)	7	(399)
Trade and other receivables(2)	1,330	(934)	396	(176)	220
Accounts payable and accrued liabilities(2)	(1,344)	934	(410)	176	(234)

(1)Amounts not set off in the Consolidated Statements of Financial Position.

(2)The trade and other receivables and accounts payable and accrued liabilities include amounts related to collateral provided and held. Refer to Note 15(F) below for further details.

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, the VPPAs and other long-term contracts that are derivatives 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 predefined 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, including a long-term physical power sale contract, and may, at times, execute hedges for its electricity price exposure in Alberta using fixed price financial swaps or other similar instruments. Both hedging strategies fall under the Company’s risk management strategy used to hedge commodity price risk.

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. Position sizes and trade strategies were adjusted to remain within the Company's risk framework.

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.

Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes occur. VaR at Dec. 31, 2023, associated with the Company’s proprietary trading activities was $4 million (2022 – $4 million, 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 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, 2023, associated with the Company’s commodity derivative instruments used in generation hedging activities was $23 million (2022 – $97 million, 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 in the period in which the price change occurs. VaR at Dec. 31, 2023, associated with these transactions was $16 million (2022 – $45 million, 2021 – $34 million). For the market risk related to long-term power sale and long-term

wind energy sales contracts, refer to the Level III measurements table and the related unobservable inputs and sensitivities in Note 14(B)(II).

iii. Commodity Price Risk Management – Hedges

At Dec. 31, 2023, the Company had no outstanding commodity derivative instruments designated as hedging instruments, except for the long-term power sale - US contract. For further details on this contract, refer to Note 14(B)(II)(i).

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	2023		2022
Type (thousands)	Notional amount sold	Notional amount purchased	Notional amount sold	Notional amount purchased
Electricity (MWh)	54,043	12,628	55,821	13,934
Natural gas (GJ)	50,949	209,348	23,464	162,384
Transmission (MWh)	—	856	—	1,643
Emissions (MWh)	212	804	274	2,297
Emissions (tonnes)	4,450	5,125	300	300
Coal (tonnes)	—	5,172	—	7,746

b. Interest Rate Risk Management

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

The Company's syndicated 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 14 per cent of the Company’s total long-term debt as at Dec. 31, 2023 (2022 – 15 per cent). Interest rate risk is managed with the use of derivatives.

Interbank Offered Rate 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 term and credit facilities with $400 million outstanding (2022 – $433 million) reference the Canadian Dollar Offered Rate ("CDOR") for Canadian-dollar drawings, but include appropriate fallback language to replace this benchmark rate in the event of a benchmark transition. The Poplar Creek non-recourse bond with a face value as at Dec. 31, 2023 of $86 million (2022 – $95 million) pays interest based upon the three-month CDOR. Cessation of the three-month CDOR is anticipated to occur mid-2024.

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

•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. 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 (2022 – US$370 million).

ii. Non-Hedges

The Company also uses foreign currency contracts to manage its expected foreign operating cash flows and foreign exchange forward contracts to manage foreign exchange exposure on foreign-denominated debt not designated as a net investment hedge. Hedge accounting is not applied to these foreign currency contracts.

As at Dec. 31	2023			2022
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
AUD125	CAD113	(1)	2024-2027	AUD183	CAD168	(1)	2023-2026
USD828	CAD1,113	19	2024-2027	USD573	CAD761	(12)	2023-2025
USD100	AUD152	5	2024	USD66	AUD102	4	2023
Foreign exchange forward contracts – foreign-denominated debt
CAD190	USD140	(4)	2024	CAD159	USD120	3	2023

iii. 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 cents (2022 – three cents, 2021 – three cents) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter.

Year ended Dec. 31	2023		2022		2021
Currency	Net earnings decrease(1)	OCI gain(1)(2)	Net earnings increase (decrease)(1)	OCI gain(1)(2)	Net earnings decrease(1)	OCI gain(1)(2)
USD	(11)	—	(12)	—	(13)	1
AUD	(3)	—	(2)	—	1	—
Total	(14)	—	(14)	—	(12)	1

(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, 2023:

	Investment grade  (per cent)	Non-investment grade  (per cent)	Total  (per cent)	Total amount
Trade and other receivables(1)	95	5	100	807
Long-term finance lease receivable	100	—	100	171
Risk management assets(1)	75	25	100	203
Loans receivable(2)	—	100	100	26
Total				1,207

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

(2)Includes $26 million loans receivable included within other assets with counterparties that have no external credit rating.

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 material expected credit losses as at Dec. 31, 2023.

The Company’s maximum exposure to credit risk at Dec. 31, 2023, 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, 2023, was $23 million (Dec. 31, 2022 – $64 million).

III. Liquidity Risk

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. As at Dec. 31, 2023, TransAlta maintains an investment grade rating from one credit rating agency and one notch below investment grade ratings from two credit rating agencies. Between 2024 and 2026, the Company has $400 million of debt maturing, and an

additional $411 million of scheduled non-recourse debt principal payments.

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.

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 Audit, Finance and Risk Committee (on behalf of 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:

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Bank overdraft	3	—	—	—	—	—	3
Accounts payable and accrued liabilities	797	—	—	—	—	—	797
Long-term debt(1)
Credit facilities(1)	400	—	—	—	—	—	400
Debentures	—	—	—	—	—	251	251
Senior notes	—	—	—	—	—	924	924
Non-recourse – Hydro	—	—	—	—	—	39	39
Non-recourse – Wind & Solar	66	69	67	70	75	289	636
Non-recourse and other – Gas	46	58	61	65	66	707	1,003
Tax equity financing	14	15	15	18	21	27	110
Exchangeable securities(2)	—	—	—	—	—	750	750
Commodity risk management liabilities	169	123	15	12	12	73	404
Other risk management assets	(16)	(3)	—	—	—	—	(19)
Lease liabilities(3)	4	4	4	4	4	123	143
Interest on long-term debt and lease liabilities(4)	186	167	158	151	143	711	1,516
Interest on exchangeable securities(2)(4)	53	53	53	53	53	13	278
Dividends payable	49	—	—	—	—	—	49
Total	1,771	486	373	373	374	3,907	7,284

(1)Excludes impact of hedge accounting and derivatives.

(2)Cash payment could occur after Dec. 31, 2028 if exchangeable securities are not exchanged by Brookfield Renewable Partners or its affiliates (collectively "Brookfield"). At Brookfield's option, the exchangeable securities can be exchanged, at the earliest, on Jan. 1, 2025 (Note 25).

(3)Lease liabilities exclude a lease incentive of $12 million expected to be received in 2024, which is recognized in trade and other receivables.

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

IV. Equity Price Risk

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.

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
	2024	2025	2026	2027	2028	2029
Cash flow hedges
Commodity derivative instruments
Electricity
Notional amount (thousands of MWh)	3,338	2,628	—	—	—	—
Average price ($ per MWh)	78.18	80.13	—	—	—	—

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, 2023	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(1)	5,966	(205)	Risk management liabilities	(114)
Foreign currency risk
Net investment hedges
Foreign-denominated debt	USD370	CAD489	Credit facilities, long-term debt and lease liabilities	—

(1)In thousands of MWh.

As at Dec. 31, 2022	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(1)	9,295	(347)	Risk management liabilities	(594)
Foreign currency risk
Net investment hedges
Foreign-denominated debt	USD370	CAD502	Credit facilities, long-term debt and lease liabilities	—

(1)In thousands of MWh.

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

As at Dec. 31	2023		2022
	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	(114)	(129)	(594)	(279)
	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	—	(36)	—	(39)

(1)Net of tax. Included in AOCI.

The hedging gain or 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.

The impact of designated cash flow hedges on OCI and net earnings is:

Year ended Dec. 31, 2023
		Effective portion		Ineffective portion
Derivatives in cash flow  hedging relationships	Pre-tax gain recognized in OCI	Location of gain 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	51	Revenue	83	Revenue	—
Forward starting interest rate swaps	—	Interest expense	(8)	Interest expense	—
OCI impact	51	OCI impact	75	Net earnings impact	—

Over the next 12 months, the Company estimates that approximately $89 million of after-tax losses 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, 2022
		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	(747)	Revenue	124	Revenue	—
Forward starting interest rate swaps	53	Interest expense	2	Interest expense	—
OCI impact	(694)	OCI impact	126	Net earnings impact	—

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 reclassified from 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	—

II. Effect of Non-Hedges

For the year ended Dec. 31, 2023, the Company recognized a net unrealized loss of $44 million (2022 – loss of $384 million, 2021 – gain of $97 million) related to commodity derivatives.

For the year ended Dec. 31, 2023, a gain of $11 million (2022 – gain of $20 million, 2021 – gain of $6 million) related to foreign exchange and other derivatives was recognized, which consists of net unrealized gains of $27 million (2022 – loss of $11 million, 2021 – gain of $4 million) and net realized losses of $16 million (2022 – gains of $31 million, 2021 – gains of $2 million), respectively.

F. Collateral

I. Financial Assets Provided as Collateral

At Dec. 31, 2023, the Company provided $145 million (Dec. 31, 2022 – $304 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 within trade and other receivables in the Consolidated Statements of Financial Position. At Dec. 31, 2023, the Company provided $19 million (Dec. 31, 2022 - $6 million) in surety bonds as security for commodity trading activities.

II. Financial Assets Held as Collateral 

At Dec. 31, 2023, the Company held $9 million (Dec. 31, 2022 – $260 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 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.

At Dec. 31, 2023, the Company had posted collateral of $392 million (Dec. 31, 2022 – $820 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 could result in the Company having to post an additional $154 million (Dec. 31, 2022 – $594 million) of collateral to its counterparties.

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Inventory

12 Months Ended

Dec. 31, 2023

Disclosure of inventories [Abstract]

Inventory

Inventory

The components of inventory are as follows:

As at Dec. 31	2023	2022
Parts, materials and supplies	72	83
Coal	38	43
Emission credits	45	27
Natural gas	2	4
Total	157	157

No inventory was pledged as security for liabilities.

As at Dec. 31, 2023, the Company holds 962,548 emission credits in inventory that were purchased externally with a recorded book value of $45 million (Dec. 31, 2022 – 963,068 emission credits with a recorded book value of $27 million). The Company also has 3,121,837 (Dec. 31, 2022 – 3,619,450) of internally generated eligible emission credits from the Company's Wind and Solar and Hydro segments which have no recorded book value. This includes the eligible emission performance credits earned by the Alberta Hydro facilities formerly under dispute that has now been resolved. Refer to Note 36 for details.

Emission credits can be sold externally or can be used to offset future emission obligations from our gas facilities located in Alberta, where the compliance price of carbon is expected to increase, resulting in a reduced cash cost for carbon compliance in the year of settlement.

In June 2023, the Company settled the 2022 carbon compliance obligation in cash. The compliance price of carbon for the 2022 obligation settled was $50 per tonne. It increased to $65 per tonne in 2023.

During 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 was recognized as a reduction in the Company's carbon compliance costs in 2022.

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Finance Lease Receivables

12 Months Ended

Dec. 31, 2023

Disclosure of maturity analysis of finance lease payments receivable [abstract]

Finance Lease Receivables

Finance Lease Receivables

Amounts receivable under the Company’s finance leases include the Northern Goldfields solar facilities (2023), the Poplar Creek cogeneration facility (2023 and 2022) and the Southern Cross Energy facilities (2022), and are as follows:

As at Dec. 31	2023		2022
	Minimum lease receipts	Present value of minimum lease receipts	Minimum lease receipts	Present value of minimum lease receipts
Within one year	28	28	62	55
Second to fifth years inclusive	112	98	81	75
More than five years	117	64	60	51
	257	190	203	181
Less: unearned finance lease income	67	—	22	—
Total finance lease receivables	190	190	181	181
Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease receivables (Note 13)	19		52
Long-term portion of finance lease receivables	171		129
Total finance lease receivables	190		181

On Nov. 22, 2023, the Northern Goldfields solar facilities achieved commercial operation. As a result, the Company derecognized assets under construction and recognized a finance lease receivable of $61 million.

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Property, Plant, and Equipment

12 Months Ended

Dec. 31, 2023

Disclosure of detailed information about property, plant and equipment [abstract]

Property, Plant, and Equipment

Property, Plant and Equipment

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

	Assets under construction	Land	Hydro	Wind and Solar	Gas generation	Energy Transition	Capital spares and other(1)	Total
Cost
As at Dec. 31, 2021	184	96	867	3,276	4,087	4,513	366	13,389
Additions(2)	891	—	—	—	—	—	6	897
Additions from development projects	17	—	—	—	—	—	12	29
Disposals	—	(3)	—	—	(1)	(216)	—	(220)
Impairment (charges) reversals (Note 7)	2	—	(21)	(43)	—	—	—	(62)
Changes to decommissioning and restoration costs (Note 23)	—	—	(15)	(59)	(12)	10	2	(74)
Retirement of assets	—	—	(9)	(9)	(12)	(7)	(2)	(39)
Change in foreign exchange rates	13	—	—	45	(4)	97	2	153
Transfers of assets(3)	(144)	—	18	23	472	(423)	(7)	(61)
As at Dec. 31, 2022	963	93	840	3,233	4,530	3,974	379	14,012
Additions(2)	869	—	—	—	—	—	6	875
Disposals	—	(3)	—	—	—	(30)	—	(33)
Impairment reversals (Note 7)	—	—	10	4	—	—	—	14
Changes to decommissioning and restoration costs (Note 23)	—	—	3	14	(22)	3	(1)	(3)
Retirement of assets	—	—	(7)	(18)	(124)	(7)	(108)	(264)
Change in foreign exchange rates	(26)	—	—	(18)	(7)	(42)	(1)	(94)
Transfers of assets(3)	(572)	—	38	439	50	16	31	2
Transfers to finance lease receivable (Note 17)	—	—	—	(61)	(4)	—	—	(65)
As at Dec. 31, 2023	1,234	90	884	3,593	4,423	3,914	306	14,444
Accumulated depreciation
As at Dec. 31, 2021	—	—	468	1,093	2,178	4,150	180	8,069
Depreciation	—	—	21	130	308	63	16	538
Retirement of assets	—	—	(8)	(6)	(10)	(7)	(2)	(33)
Disposals	—	—	—	—	(1)	(211)	—	(212)
Change in foreign exchange rates	—	—	—	11	2	89	—	102
Transfers of assets(3)	—	—	(3)	—	335	(340)	—	(8)
As at Dec. 31, 2022	—	—	478	1,228	2,812	3,744	194	8,456
Depreciation	—	—	25	129	342	73	16	585
Retirement of assets	—	—	(4)	(15)	(101)	(7)	(108)	(235)
Disposals	—	—	—	—	—	(30)	—	(30)
Change in foreign exchange rates	—	—	—	(5)	(3)	(39)	—	(47)
Transfers in (out) of PP&E(3)	—	—	—	—	(1)	2	—	1
As at Dec. 31, 2023	—	—	499	1,337	3,049	3,743	102	8,730
Carrying amount
As at Dec. 31, 2021	184	96	399	2,183	1,909	363	186	5,320
As at Dec. 31, 2022	963	93	362	2,005	1,718	230	185	5,556
As at Dec. 31, 2023	1,234	90	385	2,256	1,374	171	204	5,714

(1)Includes major spare parts and standby equipment available, but not in service.

(2)In 2023, the Company capitalized $57 million (2022 – $16 million) of interest to PP&E in at a weighted average rate of 6.3 per cent (2022 – 6.0 per cent).

(3)Includes transfers of assets upon commissioning to assets in service and other movements.

Assets under Construction

During the year, the Company achieved commercial operations on the Garden Plain wind facility and the Northern Goldfields solar and battery storage facilities. Costs were transferred from assets under construction to the Wind and Solar segment. In addition, the Kent Hills Foundation Rehabilitation project was substantially completed and the costs were transferred to the Wind and Solar segment.

Change in Estimate - Useful Lives

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Right of Use Asset

12 Months Ended

Dec. 31, 2023

Disclosure of leases [Abstract]

Right of Use Assets

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	Total
As at Dec. 31, 2021	68	20	1	6	95
Additions	36	—	1	3	40
Depreciation	(4)	(5)	—	(2)	(11)
Change in foreign exchange rates	2	—	—	—	2
As at Dec. 31, 2022	102	15	2	7	126
Additions	2	2	1	—	5
Depreciation	(5)	(5)	—	(2)	(12)
Change in foreign exchange rates	(2)	—	—	—	(2)
As at Dec. 31, 2023	97	12	3	5	117

For the year ended Dec. 31, 2023, TransAlta paid $19 million (2022 – $16 million) related to recognized lease liabilities, consisting of $10 million (2022 – $9 million) of principal repayments and $9 million (2022 – $7 million) of interest expense.

Short-term leases (term of less than 12 months) and leases with total lease payments below the Company's capitalization threshold (low value leases) do not require recognition as lease liabilities and right-of-use assets. For the year ended Dec. 31, 2023, the Company expensed $1 million (2022 – $2 million and 2021 – nil) related to short-term and low value leases.

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, 2023, the Company expensed $8 million (2022 – $8 million and 2021 – $6 million) in variable land lease payments for these leases.

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Intangible Assets

12 Months Ended

Dec. 31, 2023

Disclosure of detailed information about intangible assets [abstract]

Intangible Assets

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, 2021	269	422	4	132	827
Additions	—	—	31	—	31
Change in foreign exchange rates	3	3	1	—	7
Transfers	—	12	(9)	—	3
As at Dec. 31, 2022	272	437	27	132	868
Additions	—	—	13	—	13
Asset impairment charges	—	(1)	—	—	(1)
Change in foreign exchange rates	(2)	(2)	(1)	—	(5)
Transfers	—	12	(12)	—	—
As at Dec. 31, 2023	270	446	27	132	875
Accumulated amortization
As at Dec. 31, 2021	140	299	—	132	571
Amortization	17	26	—	—	43
Change in foreign exchange rates	1	1	—	—	2
As at Dec. 31, 2022	158	326	—	132	616
Amortization	17	21	—	—	38
Change in foreign exchange rates	(1)	(1)	—	—	(2)
As at Dec. 31, 2023	174	346	—	132	652
Carrying amount
As at Dec. 31, 2021	129	123	4	—	256
As at Dec. 31, 2022	114	111	27	—	252
As at Dec. 31, 2023	96	100	27	—	223

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Goodwill

12 Months Ended

Dec. 31, 2023

Disclosure of detailed information about goodwill [Abstract]

Goodwill

Goodwill

Goodwill acquired through business combinations has been allocated to groups of CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments is as follows:

As at Dec. 31	2023	2022
Hydro	258	258
Wind and Solar	176	176
Energy Marketing	30	30
Total goodwill	464	464

For the purposes of the 2023 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 projections. In 2023, the Company relied on the recoverable amounts determined in 2022 for the Hydro and Energy Marketing segments in performing the 2023 goodwill impairment review. The recoverable amounts are based on the Company's long-range forecasts for the periods extending to the last planned asset retirement in 2072. The resulting fair value measurements are categorized within Level III of the fair value hierarchy. No impairment of goodwill arose for any segment.

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

•Discount rates used ranged from 5.9 per cent to 8.2 per cent (2022 – 5.9 per cent to 8.2 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.

•Forecasts of 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. Merchant electricity prices used in the Hydro and Wind and Solar models ranged between $20 to $238 per MWh during the forecast period (2022 – $28 to $233 per MWh).

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Other Assets

12 Months Ended

Dec. 31, 2023

Disclosure of financial assets [abstract]

Other Assets

Other Assets

The components of other assets are as follows:

As at Dec. 31	2023	2022
South Hedland prepaid transmission access and distribution costs	60	61
Long-term prepaids and other assets	41	40
Project development costs	35	10
Loans receivable	26	37
Transmission infrastructure	18	16
Total Other assets	180	164
Included in the Consolidated Statements of Financial Position as:
Total current other assets (Note 13)	1	4
Total long-term other assets	179	160
Total Other assets	180	164

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.

Long-term prepaids and other assets include the TransAlta Energy Transition Bill commitment and other contractually required prepayments and deposits. 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 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 termination and in certain circumstances, this funding or portion thereof would no longer be required. As of Dec. 31, 2023, the Company has fully funded the commitment.

Project development costs primarily include the pre-construction project costs for projects.

At Dec. 31, 2023, $25 million of the loans receivable (2022 – $37 million) is an unsecured loan related to an advancement by the Company's subsidiary, Kent Hills Wind LP, of the net financing proceeds of the Kent Hills Wind Bond ("KH Bonds"), to its 17 per cent partner. The loan bears interest at 4.55 per cent, with interest payable quarterly. No scheduled principal repayments are required until the maturity date of October 2027. However, repayments may be required for amounts associated with foundation replacement capital expenditures and for operating account funding, as outlined in the amendment made to the KH Bonds. During 2023, the Company received repayments of $12 million that were required as part of the waiver and amendment made to the KH Bonds (2022 - $18 million).

Transmission infrastructure was constructed by the Company and then transferred to a transmission provider upon completion. The balance relates to the Garden Plain and Windrise wind facilities and will be amortized to net earnings (loss) over the useful life of the facilities.

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Decommissioning and Other Provisions

12 Months Ended

Dec. 31, 2023

Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]

Decommissioning and Other Provisions

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 incurred	1	23	24
Liabilities settled	(35)	(12)	(47)
Accretion	49	—	49
Disposals	(5)	—	(5)
Revisions in estimated cash flows	95	5	100
Revisions in discount rates	(225)	—	(225)
Reversals	—	(9)	(9)
Change in foreign exchange rates	15	—	15
Balance, Dec. 31, 2022	688	41	729
Liabilities incurred	1	4	5
Liabilities settled	(37)	(13)	(50)
Accretion (Note 10)	47	1	48
Revisions in estimated cash flows	(89)	—	(89)
Revisions in discount rates	52	—	52
Change in foreign exchange rates	(6)	—	(6)
Balance, Dec. 31, 2023	656	33	689

Included in the Consolidated Statements of Financial Position as:
As at	Dec. 31, 2023	Dec. 31, 2022
Current portion	35	70
Non-current portion	654	659
Total Decommissioning and other provisions	689	729

A. Decommissioning and Restoration

A provision has been recognized for all generating facilities and mines for which TransAlta is legally, or constructively, required to remove the facilities at the end of their useful lives and restore the sites to their original condition. TransAlta estimates that the undiscounted amount of cash flow required to settle these obligations is approximately $1.7 billion, which will be incurred between 2024 and 2072. The majority of the costs will be incurred between 2024 and 2050.

During 2023, the decommissioning and restoration provision decreased by $89 million due to revisions in estimated cash flows and timing of cash flows for certain Gas and Energy Transition assets. The timing of cash flows was adjusted to optimize and maximize efficiencies by staging required reclamation work. Operating assets included in PP&E decreased by $34 million and $55 million was recognized as an impairment reversal in net earnings related to retired assets.

During 2023, revisions in discount rates increased the decommissioning and restoration provision by $52 million due to a decrease in discount rates, largely driven by decreases in long-term market benchmark rates. On average, discount rates decreased compared to 2022, with rates ranging from 6.0 to 9.0 per cent as at Dec. 31, 2023. This has resulted in a corresponding increase in PP&E of $31 million on operating assets and the recognition of a $21 million impairment charge in net earnings related to retired assets.

During 2022, the Company accelerated the expected timing on decommissioning and restoration for certain facilities. This increased the decommissioning and restoration provision by $95 million, of which $46 million increased operating assets in PP&E and $49 million was recognized as an impairment charge in net earnings related to retired assets.

During 2022, the decommissioning and restoration provision decreased by $225 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 7.0 to 9.7 per cent as at Dec. 31, 2022. This has resulted in a corresponding decrease in PP&E of $123 million on operating assets and the recognition of a $102 million impairment reversal in net earnings related to retired assets.

At Dec. 31, 2023, the Company has provided a surety bond in the amount of US$147 million (2022 – US$147 million) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2023, the Company had provided a surety bond and letters of credit in the amount of $188 million (2022 – $187 million) in support of future decommissioning obligations at the Highvale mine.

B. Other Provisions

Other provisions include provisions arising from ongoing business activities, amounts related to commercial disputes between the Company and customers or suppliers and onerous contract provisions. 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.

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Credit Facilities, Long-Term Debt and Lease Liabilities

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Credit Facilities, Long-Term Debt and Lease Liabilities

Credit Facilities, Long-Term Debt and Lease Liabilities

A. Amounts Outstanding

The amounts outstanding are as follows:

As at Dec. 31				2023				2022
	Segment	Maturity	Currency	Carrying value	Face value	Interest(1)		Carrying value	Face value	Interest
Credit facilities
Committed syndicated bank facility(2)	Corporate	2027	CAD	—	—	—		32	33	4.7	%
Term Facility	Corporate	2024	CAD	397	400	7.4	%	396	400	6.5	%
Debentures
7.3% Medium term notes	Corporate	2029	CAD	110	110	7.3	%	110	110	7.3	%
6.9% Medium term notes	Corporate	2030	CAD	141	141	6.9	%	141	141	6.9	%
Senior notes(3)
7.8% Senior notes(4)	Corporate	2029	USD	520	528	7.8	%	533	542	7.8	%
6.5% Senior notes	Corporate	2040	USD	391	396	6.5	%	401	407	6.5	%
Non-recourse
Melancthon Wolfe Wind LP bond	Wind & Solar	2028	CAD	168	169	3.8	%	202	203	3.8	%
New Richmond Wind LP bond	Wind & Solar	2032	CAD	103	104	4.0	%	112	113	4.0	%
Kent Hills Wind LP bond	Wind & Solar	2033	CAD	193	196	4.5	%	206	209	4.5	%
Windrise Wind LP bond	Wind & Solar	2041	CAD	164	167	3.4	%	170	173	3.4	%
Pingston bond	Hydro	2043	CAD	39	39	6.2	%	45	45	3.0	%
TAPC Holdings LP bond (Poplar Creek)	Gas	2030	CAD	85	86	9.4	%	94	95	8.9	%
TEC Hedland PTY Ltd bond(5)	Gas	2042	AUD	691	699	4.1	%	711	720	4.1	%
TransAlta OCP LP bond	Gas	2030	CAD	217	218	4.5	%	241	242	4.5	%
Tax equity financing
Big Level & Antrim(6)	Wind & Solar	2029	USD	91	97	6.6	%	102	108	6.6	%
Lakeswind(7)	Wind & Solar	2029	USD	10	10	10.5	%	15	15	10.5	%
North Carolina Solar(8)	Wind & Solar	2028	USD	3	3	7.3	%	6	6	7.3	%
Other(9)	Corporate		CAD	—	—	—		1	1	5.9	%
Total long-term debt				3,323	3,363			3,518	3,563
Lease liabilities(10)				143				135
Total long-term debt and lease liabilities				3,466				3,653
Less: current portion of long-term debt				(526)				(170)
Less: current portion of lease liabilities				(6)				(8)
Total current long-term debt and lease liabilities				(532)				(178)
Total non-current credit facilities, long-term debt and lease liabilities				2,934				3,475

(1)Interest rate reflects the stipulated rate or the average rate weighted by principal amounts outstanding and 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, 2023 – US$700 million (2022 – US$700 million).

(4)The effective interest rate for the senior notes is 5.98 per cent after the effects of gains realized on settled interest rate hedging instruments.

(5)AU face value at Dec. 31, 2023 – AU$773 million (2022 – AU$786 million).

(6)US face value at Dec. 31, 2023 – US$73 million (2022 – US$79 million).

(7)US face value at Dec. 31, 2023 – US$8 million (2022 – US$11 million).

(8)US face value at Dec. 31, 2023 – US$2 million (2022 – US$5 million).

(9)Other debt consisted of an unsecured commercial loan obligation that matured and was repaid in 2023.

(10)At Dec. 31, 2023, lease liabilities exclude a lease incentive of $12 million expected to be received in 2024, which is recognized in trade and other receivables.

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

As at Dec. 31, 2023		Utilized
Credit Facilities	Facility size	Outstanding letters of credit(1)	Cash drawings	Available capacity	Maturity date
Committed
TransAlta syndicated credit facility	1,950	417	—	1,533	Q2 2027
TransAlta bilateral credit facilities	240	178	—	62	Q2 2025
TransAlta Term Facility	400	—	400	—	Q3 2024
Total Committed	2,590	595	400	1,595
Non-Committed
TransAlta demand facilities	400	187	—	213	N/A
Total Non-Committed	400	187	—	213

(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. Letters of credit drawn against the non-committed facilities reduce the available capacity under the committed syndicated credit facilities. At Dec. 31, 2023, TransAlta provided cash collateral of $145 million.

These facilities are the primary source of short-term liquidity after the cash flow generated from the Company's business.

The acquisition of TransAlta Renewables resulted in the TransAlta syndicated credit facility increasing by $700 million to approximately $2.0 billion, effectively consolidating the TransAlta Renewables syndicated credit facility into the TransAlta syndicated credit facility. Refer to Note 4 for more details.

The Company is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. The $187 million letters of credit are issued from non-committed demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities. In addition to the $1.4 billion of committed capacity available under the credit facilities, the Company also had $345 million of available cash and cash equivalents, net of bank overdraft.

Senior Notes

On Nov. 15, 2022, the Company repaid the US$400 million 4.5 per cent unsecured senior notes on maturity in addition to related fees and expenses.

On Nov. 17, 2022, the Company issued US$400 million senior notes, which have a fixed coupon rate of 7.75 per cent per annum and mature on Nov. 15, 2029. Including the effects of settled interest rate swaps, the notes have an effective yield of approximately 5.982 per cent. The notes are unsecured and 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 interest payments on the bonds are made semi-annually, on November 15 and May 15 with the first payment commencing May 15, 2023. TransAlta is

required to allocate an amount equal to the net proceeds from this offering to finance or, refinance new and/or existing eligible green projects in accordance with its Green Bond Framework.

A total of US$370 million (2022 – US$370 million) of the senior notes have been designated as a hedge of the Company’s net investment in US operations.

Non-Recourse Debt

On May 8, 2023, the Pingston Power Inc. non-recourse bond matured with a total aggregate repayment of $46 million, consisting of accrued interest and principal.

On Sept. 14, 2023, the Company closed a non-recourse bond financing for approximately $39 million ("Pingston bond") as a replacement for the non-recourse bond that matured on May 8, 2023. The Pingston bond is secured by a first ranking charge over all the respective assets of the Company's subsidiaries that issued the bonds, amortizes and bears interest at a rate of 6.145 per cent per annum, payable semi-annually, and matures on May 8, 2043. The Pingston bond is subject to customary financing conditions and covenants that may restrict the Company's ability to access funds generated by the facility's operations.

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 financings, 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 are 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 in December 2029; Lakeswind in March 2029 and North Carolina Solar in December 2028.

Other

TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2023, the Company was in compliance with all debt covenants.

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

The Melancthon Wolfe Wind LP, Pingston Power Inc., TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd and Windrise Wind LP non-recourse bonds and the TransAlta OCP LP bond, with a total carrying value of $1.7 billion as at Dec. 31, 2023 (2022 – $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 2023, with the exception of Kent Hills Wind LP and TAPC Holdings LP. Kent Hills Wind cannot make any distributions to its partners until the foundation work is completed. TAPC Holdings LP has been impacted by higher interest rates in 2023. The 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 2024. At Dec. 31, 2023, $79 million (2022 – $50 million) of cash was subject to these financial restrictions.

At Dec. 31, 2023, $3 million (AU$3 million) of funds held by TEC Hedland Pty Ltd 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.

C. Security

Non-recourse debts totalling $1.4 billion as at Dec. 31, 2023 (2022 – $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, 2023 (2022 – $1.5 billion) and intangible assets with total carrying amounts of $61 million (2022 – $70 million). At Dec. 31, 2023, a non-recourse bond of approximately $85 million (2022 – $94 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 $217 million (2022 – $241 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.

D. Principal Repayments

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Principal repayments(1)	526	142	143	153	162	2,237	3,363
Lease liabilities(2)	4	4	4	4	4	123	143

(1)Excludes impact of hedge accounting and derivatives.

(2)Lease liabilities exclude a lease incentive of $12 million, expected to be received in 2024, which is recognized in trade and other receivables.

E. Restricted Cash

As at Dec. 31, 2023, the Company had $17 million (2022 – $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 scheduled future debt repayments. The Company also had $52 million (2022 – $53 million) of restricted cash related to the TEC Hedland Pty Ltd bond. These cash reserves are required to be held under commercial arrangements and for debt service, which may be replaced by letters of credit in the future.

F. Letters of Credit

Letters of credit issued by TransAlta are drawn on its $2.0 billion committed syndicated credit facility, its $240 million bilateral committed credit facilities and its $400 million uncommitted demand facilities. TransAlta has drawn $417 million on its committed syndicated credit facility, $178 million on its bilateral committed credit facilities and $187 million on its uncommitted demand facilities.

Letters of credit are issued to counterparties as required by 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. 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, 2023, was $782 million (2022 – $1,175 million) with nil (2022 – nil) amounts exercised by third parties under these arrangements.

G. Currency Impacts

The weakening of the US dollar has decreased the US-denominated long-term debt balances, mainly the senior notes and tax equity financing, by $27 million as at Dec. 31, 2023 (2022 – increased $41 million due to the strengthening 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 balance by approximately $9 million as at Dec. 31, 2023 (2022 – $9 million). As this debt is issued by an Australian subsidiary, the foreign currency translation impacts are recognized within other comprehensive income (loss).

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Exchangeable Securities

12 Months Ended

Dec. 31, 2023

Exchangeable Securities [Abstract]

Exchangeable Securities

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").

A. $750 Million Exchangeable Securities

As at	Dec. 31, 2023				Dec. 31, 2022
	Carrying value	Face value	Interest		Carrying value	Face value	Interest
Exchangeable debentures – due May 1, 2039(1)	344	350	7	%	339	350	7	%
Exchangeable preferred shares(2)	400	400	7	%	400	400	7	%
Total exchangeable securities	744	750			739	750

(1)Seven per cent unsecured subordinated debentures due May 1, 2039.

(2)Redeemable, retractable first preferred shares (Series I). Exchangeable preferred share dividends are reported as interest expense.

On Dec. 11, 2023, the Company declared a dividend of $7 million, in aggregate, for the Exchangeable Preferred Shares at the fixed rate of 1.764 per cent, per share, payable on Feb. 28, 2024. The Exchangeable Preferred

Shares are considered debt for accounting purposes and, as such, dividends are reported as interest expense (Note 10).

B. Option to Exchange

As at	Dec. 31, 2023		Dec. 31, 2022
Description	Base fair value	Sensitivity	Base fair value	Sensitivity
Option to exchange – embedded derivative	—	+nil -25	—	+nil -25

The Investment Agreement allows Brookfield the option to exchange all of the outstanding exchangeable securities after Dec. 31, 2024, 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 one 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, 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 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.

In connection with the Investment Agreement, Brookfield is entitled to nominate two directors for election to the Board.

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Defined Benefit Obligation and Other Long-Term Liabilities

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Defined Benefit Obligation and Other Long-Term Liabilities

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	2023	2022
Defined benefit obligation (Note 31)	155	150
Retail power contract liability	83	126
Other	13	18
Total	251	294

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. The defined benefit obligation has increased by $5 million to $155 million as at Dec. 31, 2023, from $150 million as at Dec. 31, 2022.

During 2023, the Company made a voluntary contribution of $4 million (US$3 million) to improve the funded status of the US Defined Benefit Pension Plan for the Centralia thermal facility.

During 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 and to support the employees affected by the closure of the Highvale mine in 2021 and our transition off-coal to cleaner sources. The contribution reduces the amount of the Company's future funding obligations, including amounts secured by the letters of credit.

A one per cent increase in discount rates would result in a $40 million decrease in the defined benefit obligation. Refer to Note 31 for additional sensitivities impacting the defined benefit obligation.

On Dec. 1, 2022, the Company closed a purchase and sale agreement for customer retail contracts to deliver power and gas, along with power and gas financial swaps. The Company accounted for the purchase as an asset acquisition and allocated values to risk management assets of $139 million (Level II valuation) and retail power contract liabilities of $129 million within the Gas segment. The retail power contract liabilities acquired represent certain off-market retail power customer contracts for which fair value was determined as the present value of the amount by which contract terms deviated from the terms that a market participant could have achieved at the closing date. The retail contract liability is amortized to depreciation over the remaining term of the contracts based on volumes that will be delivered each month.

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Common Shares

12 Months Ended

Dec. 31, 2023

Share Capital, Reserves And Other Equity Interest [Abstract]

Common Shares

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	2023		2022
	Common shares  (millions)	Amount	Common shares (millions)	Amount
Issued and outstanding, beginning of period	268.1	2,863	271.0	2,901
Purchased and cancelled under the NCIB	(7.5)	(80)	(4.3)	(46)
Share-based payment plans	0.8	6	0.9	5
Stock options exercised	0.7	5	0.5	3
Issued for acquisition of TransAlta Renewables(1) (Note 4)	46.5	510	—	—
Issued and outstanding, end of year, prior to ASPP	308.6	3,304	268.1	2,863
Provision for repurchase of common shares under ASPP	(1.7)	(19)	—	—
Issued and outstanding, end of year	306.9	3,285	268.1	2,863

(1)Net of $4 million of transaction costs.

B. Normal Course Issuer Bid ("NCIB") Program

The effects of the Company's purchase and cancellation of common shares during the period are as follows:

For the year ended Dec. 31	2023	2022
Total shares purchased(1)	7,537,500	4,342,300
Average purchase price per share	11.49	12.48
Total cost (millions)	87	54
Book value of shares cancelled	80	46
Amount recorded in deficit	(7)	(8)

(1)At Dec. 31, 2023, includes 181,800 (2022 - 164,300) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. As a result, $2 million (2022 - $2 million) was paid subsequent to the year end.

2023

On May 26, 2023, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.29 per cent of its public float of common shares as at May 17, 2023. 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, 2023, and ends on May 30, 2024.

On Dec. 19, 2023, the Company entered into an Automatic Share Purchase Plan ("ASPP") which permits an independent broker to repurchase shares under the NCIB during the first quarter blackout period through to the end

of the ASPP. The Company has recognized a provision of $19 million for the repurchase of common shares under the ASPP within accounts payables and accrued liabilities as at Dec. 31, 2023, as a estimate of the maximum number of shares that could be repurchased during the blackout period.

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.

2022

On May 24, 2022, the TSX accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 17, 2022.

C. Shareholder Rights Plan 

The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 28, 2022. 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 28, 2022, and will need to be approved at the annual meeting of shareholders

in 2025. 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.

D. Earnings per Share

Year ended Dec. 31	2023	2022	2021
Net earnings (loss) attributable to common shareholders	644	4	(576)
Basic and diluted weighted average number of common shares outstanding (millions)	276	271	271
Net earnings (loss) per share attributable to common shareholders, basic and diluted	2.33	0.01	(2.13)

E. Dividends

On Nov. 21, 2023, the Company declared a quarterly dividend of $0.06 per common share, payable on April 1, 2024.

There have been no transactions involving common shares between the reporting date and the date of completion of these Consolidated Financial Statements.

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	2023		2022
Series(1)	Number of shares  (millions)	Amount	Number of shares (millions)	Amount
Series A	9.6	235	9.6	235
Series B	2.4	58	2.4	58
Series C	10.0	243	10.0	243
Series D	1.0	26	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)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

I. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion

On June 30, 2022, the Company converted 1,044,299 of its 11.0 million Cumulative Redeemable Rate Reset First Preferred Shares, Series C (“Series C Shares”), on a one-for-one basis, into Cumulative Redeemable Floating Rate First Preferred Shares, Series D (“Series D Shares”).

The Series C Shares pay fixed cumulative preferential cash dividends on a quarterly basis, for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The annual fixed dividend rate is 5.854 per cent, being equal to the five-year Government of Canada bond yield of 2.754 per cent determined as of May 31, 2022, plus 3.10 per cent, in accordance with the terms of the Series C Shares.

The Series D Shares pay quarterly floating rate cumulative preferential cash dividends for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The quarterly dividend rate for the Series D Shares is established each quarter, and is equal to the annual rate for the auction of 90-day Government of Canada Treasury Bills, plus 3.10 per cent, in accordance with the terms of the Series D Shares.

II. Series E Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion

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 per cent, 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.

Preferred Share Series Information 

The holders are entitled to receive cumulative fixed quarterly cash dividends at specified rates, as approved by the Board. After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed rate resets to the sum of the then five-year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified spread. Upon each Rate Reset Date, 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, 2023, are as follows:

Series(1)	Rate during term	Annual dividend rate per share ($)(2)	Next conversion date	Rate spread over benchmark  (per cent)	Convertible to Series
A	Fixed	0.71924	March 31, 2026	2.03	B
B	Floating	1.718910	March 31, 2026	2.03	A
C	Fixed	1.46352	June 30, 2027	3.10	D
D	Floating	1.98695	June 30, 2027	3.10	C
E	Fixed	1.72352	Sept. 30, 2027	3.65	F
G	Fixed	1.24700	Sept. 30, 2024	3.80	H

(1)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

(2)The annual dividend rate per share represents dividends declared in 2023.

B. Dividends

The following table summarizes the preferred share dividends declared in 2023 and 2022:

	Total dividends declared
Series	2023(1)	2022(1)
A	7	7
B(2)	4	3
C	15	14
D(3)	2	1
E	15	13
G	8	8
Total for the year	51	46

(1)No dividends were declared in the first quarter of the year as the quarterly dividend related to the period covering the first quarter was declared in December of the prior year.

(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.

(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 Dec. 11, 2023, the Company declared a quarterly dividend of $0.17981 per share on the Series A preferred shares, $0.43958 per share on the Series B preferred shares, $0.36588 per share on the Series C preferred

shares, $0.50609 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 March 31, 2024.

TransAlta’s capital is comprised of the following:

As at Dec. 31	2023	2022	Increase/ (decrease)
Long-term debt(1)	3,466	3,653	(187)
Exchangeable securities	744	739	5
Bank overdraft	3	16	(13)
Equity
Common shares	3,285	2,863	422
Preferred shares	942	942	—
Contributed surplus	41	41	—
Deficit	(2,567)	(2,514)	(53)
Accumulated other comprehensive income (loss)	(164)	(222)	58
Non-controlling interests	127	879	(752)
Less: available cash and cash equivalents(2)	(348)	(1,134)	786
Less: principal portion of restricted cash on TransAlta OCP bonds(3)	(17)	(17)	—
Less: fair value liability (asset) of hedging instruments on long-term debt(4)	5	(3)	8
Total capital	5,517	5,243	274

(1)Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt.

(2)The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed using a net debt position. 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 as 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.

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Preferred Shares

12 Months Ended

Dec. 31, 2023

Share Capital, Reserves And Other Equity Interest [Abstract]

Preferred Shares

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	2023		2022
	Common shares  (millions)	Amount	Common shares (millions)	Amount
Issued and outstanding, beginning of period	268.1	2,863	271.0	2,901
Purchased and cancelled under the NCIB	(7.5)	(80)	(4.3)	(46)
Share-based payment plans	0.8	6	0.9	5
Stock options exercised	0.7	5	0.5	3
Issued for acquisition of TransAlta Renewables(1) (Note 4)	46.5	510	—	—
Issued and outstanding, end of year, prior to ASPP	308.6	3,304	268.1	2,863
Provision for repurchase of common shares under ASPP	(1.7)	(19)	—	—
Issued and outstanding, end of year	306.9	3,285	268.1	2,863

(1)Net of $4 million of transaction costs.

B. Normal Course Issuer Bid ("NCIB") Program

The effects of the Company's purchase and cancellation of common shares during the period are as follows:

For the year ended Dec. 31	2023	2022
Total shares purchased(1)	7,537,500	4,342,300
Average purchase price per share	11.49	12.48
Total cost (millions)	87	54
Book value of shares cancelled	80	46
Amount recorded in deficit	(7)	(8)

(1)At Dec. 31, 2023, includes 181,800 (2022 - 164,300) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. As a result, $2 million (2022 - $2 million) was paid subsequent to the year end.

2023

On May 26, 2023, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.29 per cent of its public float of common shares as at May 17, 2023. 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, 2023, and ends on May 30, 2024.

On Dec. 19, 2023, the Company entered into an Automatic Share Purchase Plan ("ASPP") which permits an independent broker to repurchase shares under the NCIB during the first quarter blackout period through to the end

of the ASPP. The Company has recognized a provision of $19 million for the repurchase of common shares under the ASPP within accounts payables and accrued liabilities as at Dec. 31, 2023, as a estimate of the maximum number of shares that could be repurchased during the blackout period.

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.

2022

On May 24, 2022, the TSX accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 17, 2022.

C. Shareholder Rights Plan 

The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 28, 2022. 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 28, 2022, and will need to be approved at the annual meeting of shareholders

in 2025. 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.

D. Earnings per Share

Year ended Dec. 31	2023	2022	2021
Net earnings (loss) attributable to common shareholders	644	4	(576)
Basic and diluted weighted average number of common shares outstanding (millions)	276	271	271
Net earnings (loss) per share attributable to common shareholders, basic and diluted	2.33	0.01	(2.13)

E. Dividends

On Nov. 21, 2023, the Company declared a quarterly dividend of $0.06 per common share, payable on April 1, 2024.

There have been no transactions involving common shares between the reporting date and the date of completion of these Consolidated Financial Statements.

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	2023		2022
Series(1)	Number of shares  (millions)	Amount	Number of shares (millions)	Amount
Series A	9.6	235	9.6	235
Series B	2.4	58	2.4	58
Series C	10.0	243	10.0	243
Series D	1.0	26	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)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

I. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion

On June 30, 2022, the Company converted 1,044,299 of its 11.0 million Cumulative Redeemable Rate Reset First Preferred Shares, Series C (“Series C Shares”), on a one-for-one basis, into Cumulative Redeemable Floating Rate First Preferred Shares, Series D (“Series D Shares”).

The Series C Shares pay fixed cumulative preferential cash dividends on a quarterly basis, for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The annual fixed dividend rate is 5.854 per cent, being equal to the five-year Government of Canada bond yield of 2.754 per cent determined as of May 31, 2022, plus 3.10 per cent, in accordance with the terms of the Series C Shares.

The Series D Shares pay quarterly floating rate cumulative preferential cash dividends for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The quarterly dividend rate for the Series D Shares is established each quarter, and is equal to the annual rate for the auction of 90-day Government of Canada Treasury Bills, plus 3.10 per cent, in accordance with the terms of the Series D Shares.

II. Series E Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion

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 per cent, 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.

Preferred Share Series Information 

The holders are entitled to receive cumulative fixed quarterly cash dividends at specified rates, as approved by the Board. After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed rate resets to the sum of the then five-year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified spread. Upon each Rate Reset Date, 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, 2023, are as follows:

Series(1)	Rate during term	Annual dividend rate per share ($)(2)	Next conversion date	Rate spread over benchmark  (per cent)	Convertible to Series
A	Fixed	0.71924	March 31, 2026	2.03	B
B	Floating	1.718910	March 31, 2026	2.03	A
C	Fixed	1.46352	June 30, 2027	3.10	D
D	Floating	1.98695	June 30, 2027	3.10	C
E	Fixed	1.72352	Sept. 30, 2027	3.65	F
G	Fixed	1.24700	Sept. 30, 2024	3.80	H

(1)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

(2)The annual dividend rate per share represents dividends declared in 2023.

B. Dividends

The following table summarizes the preferred share dividends declared in 2023 and 2022:

	Total dividends declared
Series	2023(1)	2022(1)
A	7	7
B(2)	4	3
C	15	14
D(3)	2	1
E	15	13
G	8	8
Total for the year	51	46

(1)No dividends were declared in the first quarter of the year as the quarterly dividend related to the period covering the first quarter was declared in December of the prior year.

(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.

(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 Dec. 11, 2023, the Company declared a quarterly dividend of $0.17981 per share on the Series A preferred shares, $0.43958 per share on the Series B preferred shares, $0.36588 per share on the Series C preferred

shares, $0.50609 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 March 31, 2024.

TransAlta’s capital is comprised of the following:

As at Dec. 31	2023	2022	Increase/ (decrease)
Long-term debt(1)	3,466	3,653	(187)
Exchangeable securities	744	739	5
Bank overdraft	3	16	(13)
Equity
Common shares	3,285	2,863	422
Preferred shares	942	942	—
Contributed surplus	41	41	—
Deficit	(2,567)	(2,514)	(53)
Accumulated other comprehensive income (loss)	(164)	(222)	58
Non-controlling interests	127	879	(752)
Less: available cash and cash equivalents(2)	(348)	(1,134)	786
Less: principal portion of restricted cash on TransAlta OCP bonds(3)	(17)	(17)	—
Less: fair value liability (asset) of hedging instruments on long-term debt(4)	5	(3)	8
Total capital	5,517	5,243	274

(1)Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt.

(2)The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed using a net debt position. 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 as 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.

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Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2023

Disclosure of analysis of other comprehensive income by item [abstract]

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss

The components of and changes in, accumulated other comprehensive loss are as follows:

	2023	2022
Currency translation adjustment
Opening balance, Jan. 1	(39)	(35)
(Losses) gains on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax	(6)	21
Gains (losses) on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax(1)	9	(25)
Balance, Dec. 31	(36)	(39)
Cash flow hedges
Opening balance, Jan. 1	(228)	228
Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax(2)	99	(456)
Balance, Dec. 31	(129)	(228)
Employee future benefits
Opening balance, Jan. 1	8	(29)
Net actuarial gains on defined benefit plans, net of tax(3)	(5)	37
Balance, Dec. 31	3	8
Other
Opening balance, Jan. 1	37	(18)
Change in ownership of TransAlta Renewables	(64)	—
Intercompany and third-party investments at FVTOCI	25	55
Balance, Dec. 31	(2)	37
Accumulated other comprehensive loss	(164)	(222)

(1)Net of income tax expense of $1 million for the year ended Dec. 31, 2023 (Dec. 31, 2022 – $3 million recovery).

(2)Net of income tax expense of $27 million for the year ended Dec. 31, 2023 (Dec. 31, 2022 – $112 million recovery).

(3)Net of income tax recovery of $1 million for the year ended Dec. 31, 2023 (Dec. 31, 2022 – $12 million).

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Share-Based Payment Plans

12 Months Ended

Dec. 31, 2023

Share-based payment arrangements [Abstract]

Share-Based Payment Plans

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 Share Unit Plan, grants of PSUs and RSUs 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 specific 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 2023 was $21 million (2022 – $20 million, 2021 - $14 million), which is included in OM&A in the Consolidated Statements of Earnings (Loss).

B. Deferred Share Unit (“DSU”) Plan 

Under the Share Unit 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 $1 million in 2023 (2022 - nil, 2021 – $3 million expense).

C. Stock Option Plan 

In 2023, the Company granted executive officers of the Company a total of 0.4 million stock options with a weighted average exercise price of $12.02 that vest over a three-year period and expire seven years after issuance (2022 – 0.3 million stock options at $12.66; 2021 - 0.7 million stock options at $9.86). The expense recognized relating to these grants during 2023 was approximately $1 million (2022 – approximately $1 million, 2021 – approximately $2 million).

The total options outstanding and exercisable under the Stock Option Plan at Dec. 31, 2023, 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)
5.00-12.00	2.5	3.60	9.17

(1)Options currently exercisable as at Dec. 31, 2023.

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Employee Future Benefits

12 Months Ended

Dec. 31, 2023

Employee Benefits [Abstract]

Employee Future Benefits

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. 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, 2022. The latest actuarial valuation for accounting purposes of the Highvale and Canadian pension plans was at Dec. 31, 2021. 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, 2023.

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 2023 in the amount of $88 million, and provided $70 million in surety bonds, to secure the obligations under the supplemental plan and the Canadian defined benefit plan, respectively.

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, 2021 and Jan. 1, 2022, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2023.

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 five per cent to eleven per cent, depending on the plan. Optional employee contributions are allowed for all the defined contribution plans.

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, 2023	Registered	Supplemental	Other	Total
Current service cost	1	1	—	2
Administration expenses	1	—	—	1
Interest cost on defined benefit obligation	16	4	1	21
Interest on plan assets	(13)	(1)	—	(14)
Defined benefit expense	5	4	1	10
Defined contribution expense	11	—	—	11
Net expense	16	4	1	21
Year ended Dec. 31, 2022	Registered	Supplemental	Other	Total
Current service cost	1	1	—	2
Administration expenses	1	—	—	1
Interest cost on defined benefit obligation	13	3	—	16
Interest on plan assets	(9)	—	—	(9)
Defined benefit expense	6	4	—	10
Defined contribution expense	11	—	—	11
Net expense	17	4	—	21

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

C. Status of Plans

The status of the defined benefit pension and other post-employment benefit plans is as follows:

Year ended Dec. 31, 2023	Registered	Supplemental	Other	Total
Fair value of plan assets	269	15	—	284
Present value of defined benefit obligation	(340)	(89)	(17)	(446)
Funded status – plan deficit	(71)	(74)	(17)	(162)
Amount recognized in the Consolidated Financial Statements:
Accrued current liabilities	(1)	(5)	(1)	(7)
Other long-term liabilities	(70)	(69)	(16)	(155)
Total amount recognized	(71)	(74)	(17)	(162)

Year ended Dec. 31, 2022	Registered	Supplemental	Other	Total
Fair value of plan assets	274	15	—	289
Present value of defined benefit obligation	(345)	(85)	(17)	(447)
Funded status – plan deficit	(71)	(70)	(17)	(158)
Amount recognized in the Consolidated Financial Statements:
Accrued current liabilities	(1)	(6)	(1)	(8)
Other long-term liabilities	(70)	(64)	(16)	(150)
Total amount recognized	(71)	(70)	(17)	(158)

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, 2021	339	14	—	353
Interest on plan assets	9	—	—	9
Net loss on plan assets	(55)	—	—	(55)
Contributions(1)	38	6	—	44
Benefits paid	(57)	(5)	—	(62)
Administration expenses	(1)	—	—	(1)
Change in foreign exchange rates	1	—	—	1
As at Dec. 31, 2022	274	15	—	289
Interest on plan assets	13	1	—	14
Net return on plan assets	15	(1)	—	14
Contributions(2)	5	6	2	13
Benefits paid	(36)	(6)	(2)	(44)
Administration expenses	(1)	—	—	(1)
Change in foreign exchange rates	(1)	—	—	(1)
As at Dec. 31, 2023	269	15	—	284

(1)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.

(2)The Company made a voluntary contribution of $4 million to further improve the funded status of the US Defined Benefit Pension Plan for the Centralia thermal facility.

The fair value of the Company’s defined benefit plan assets by major category is as follows:

As at Dec. 31, 2023	Level I	Level II	Level III	Total
Equity securities
Canadian	—	12	—	12
US	—	6	—	6
International	—	86	—	86
Private	—	—	1	1
Bonds
A - AAA	—	30	62	92
BBB	1	5	10	16
Below BBB	—	—	4	4
Loans(1)	—	2	—	2
Alternative funds(2)	—	—	44	44
Money market and cash and cash equivalents	2	19	—	21
Total	3	160	121	284

(1)Includes A credit rating loans of $1 million.

(2)Alternative funds include investments in infrastructure and real estate funds.

Dec. 31, 2022(1)	Level I	Level II	Level III	Total
Equity securities
Canadian	—	18	—	18
US	—	17	—	17
International	—	79	—	79
Private	—	—	1	1
Bonds
A - AAA	—	27	61	88
BBB	1	6	12	19
Below BBB	—	—	6	6
Loans(2)	—	2	—	2
Alternative funds(3)	—	—	39	39
Money market and cash and cash equivalents	—	20	—	20
Total	1	169	119	289

(1)The fair value level classifications of certain mutual fund investments has been revised for consistency with 2023 classifications.

(2)Includes A credit rating loans of $1 million and BBB credit rating loans of $1 million.

(3)Alternative funds include investments in infrastructure and real estate funds.

Plan assets do not include any common shares of the Company at Dec. 31, 2023 and Dec. 31, 2022.

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, 2021	469	101	23	593
Current service cost	1	1	—	2
Interest cost	13	3	—	16
Benefits paid	(57)	(5)	1	(61)
Actuarial gain arising from financial assumptions	(83)	(22)	(5)	(110)
Actuarial gain arising from experience adjustments	1	7	(2)	6
Change in foreign exchange rates	1	—	—	1
Present value of defined benefit obligation as at Dec. 31, 2022	345	85	17	447
Current service cost	1	1	—	2
Interest cost	16	4	1	21
Benefits paid	(36)	(6)	(2)	(44)
Actuarial loss arising from demographic assumptions	1	—	—	1
Actuarial loss arising from financial assumptions	12	4	1	17
Actuarial loss arising from experience adjustments	2	1	—	3
Change in foreign exchange rates	(1)	—	—	(1)
Present value of defined benefit obligation as at Dec. 31, 2023	340	89	17	446

(1)The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2023, is 10.4 years.

F. Contributions

The expected employer contributions for 2024 for the defined benefit pension and other post-employment benefit plans are as follows:

	Registered	Supplemental	Other	Total
Expected employer contributions	3	5	1	9

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:

	2023			2022
As at Dec. 31 (per cent)	Registered	Supplemental	Other	Registered	Supplemental	Other
Accrued benefit obligation
Discount rate	4.6	4.6	4.7	4.7	5.0	5.0
Rate of compensation increase	2.9	3.0	—	2.6	3.0	—
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	—	—	6.8	—	—	7.1
Dental-care cost escalation	—	—	4.2	—	—	4.2
Benefit cost for the year
Discount rate	5.0	5.0	5.0	2.8	2.8	2.7
Rate of compensation increase	2.7	3.0	—	2.9	3.0	—
Assumed health-care cost trend rate
Health-care cost escalation(2)(4)	—	—	7.1	—	—	6.8
Dental-care cost escalation	—	—	4.7	—	—	4.7

(1)2023 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2033 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

(2)2023 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2032 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

(3)2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2032 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

(4)2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2031 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent 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
As at Dec. 31, 2023	Registered	Supplemental	Other	Pension
1% decrease in the discount rate	30	10	1	2
1% increase in the salary scale	1	—	—	—
1% increase in the health-care cost trend rate	—	—	1	—
10% improvement in mortality rates	13	3	—	1

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Joint Arrangements

12 Months Ended

Dec. 31, 2023

Disclosure of interests in other entities [Abstract]

Joint arrangements

Investments

The change in investments is as follows:

	EMG	Skookumchuck	Tent Mountain	EIP	Ekona	Total
Classification	Equity-accounted	Equity-accounted	Equity-accounted	FVTPL	FVTOCI
Balance, Dec. 31, 2021	12	93	—	—	—	105
Investment	—	—	—	10	2	12
Equity income (loss)	(1)	10	—	—	—	9
Distributions received	—	(5)	—	—	—	(5)
Changes in foreign exchange rates	1	7	—	1	—	9
Net change in fair value recognized in OCI	—	—	—	—	(1)	(1)
Balance, Dec. 31, 2022	12	105	—	11	1	129
Investment	—	—	10	4	—	14
Equity income (loss)	(4)	8	—	—	—	4
Distributions received	—	(6)	—	—	—	(6)
Changes in foreign exchange rates	—	(3)	—	—	—	(3)
Balance, Dec. 31, 2023	8	104	10	15	1	138

Equity-accounted Investments

The Company’s investments in joint ventures and associates that are accounted for using the equity method consist of its investments in Skookumchuck, EMG and Tent Mountain Renewable Energy Complex (“Tent Mountain”).

EMG International, LLC ("EMG")

TransAlta holds a 30 per cent interest in EMG, a wastewater treatment processing company. Earnings are derived from the design and construction of wastewater treatment facilities. During 2022, the contingent purchase price consideration of US$3.5 million was paid, which was calculated based on actual earnings metrics achieved in 2021 and did not differ from the estimated amount included in the initial purchase price.

Skookumchuck Wind Project

TransAlta holds a 49 per cent membership interest in SP Skookumchuck Investment, LLC. Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state. The project has a 20-year PPA with Puget Sound Energy.

Tent Mountain Pumped Hydro Development Project

On April 24, 2023, the Company acquired a 50 per cent interest in Tent Mountain, an early-stage 320 MW pumped hydro energy storage development project, located in southwest Alberta, from Evolve Power Ltd. ("Evolve"), formerly known as Montem Resources Limited. The acquisition included land rights, fixed assets and intellectual property associated with the pumped hydro development project. The Company paid Evolve approximately $8 million on closing and made additional investments of $2 million during the balance of 2023. Additional contingent payments of up to $17 million may become payable to Evolve based on the achievement of specific development and commercial milestones. The Company and Evolve jointly control Tent Mountain, with the result that the Company accounts for its interest in the joint venture as an investment using the equity method.

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

Year ended Dec. 31	2023	2022	2021
Results of operations
Revenues and other operating income	22	24	19
Expenses	(18)	(15)	(10)
Proportionate share of net earnings	4	9	9

Other Investments

Energy Impact Partners

On May 6, 2022, the Company entered into a commitment to invest US$25 million over the next four years in Energy Impact Partners ("EIP") 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. The investment is accounted for at FVTPL.

Ekona Power Inc.

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 is being developed to produce cleaner and lower-cost turquoise hydrogen. The Company has irrevocably elected to measure its investment in Ekona at FVTOCI.

Joint Arrangements

Joint arrangements at Dec. 31, 2023, 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
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
Tent Mountain	Hydro	50	Pumped hydro energy storage development project in Alberta

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Cash Flow Information

12 Months Ended

Dec. 31, 2023

Disclosure of cash flow statement [Abstract]

Cash Flow Information

Cash Flow Information

A. Change in Non-Cash Operating Working Capital

Year ended Dec. 31	2023	2022	2021
(Use) source:
Accounts receivable	715	(869)	(28)
Prepaid expenses	—	—	9
Income taxes receivable	27	(61)	—
Inventory	(2)	6	42
Accounts payable, accrued liabilities and provisions	(550)	548	153
Income taxes payable	(66)	60	(2)
Change in non-cash operating working capital	124	(316)	174

B. Changes in Liabilities from Financing Activities

	Balance Dec. 31, 2022	Cash issuances	Repayments and dividends paid(1)	New leases	Dividends declared	Foreign exchange impact	Other	Balance Dec. 31, 2023
Long-term debt and lease liabilities(2)	3,669	39	(220)	5	—	(36)	12	3,469
Exchangeable securities	739	—	—	—	—	—	5	744
Dividends payable (common and preferred)(3)	68	—	(109)	—	116	—	(26)	49
Total liabilities from financing activities	4,476	39	(329)	5	116	(36)	(9)	4,262

(1)Includes a decrease of $164 million related to the repayment of long-term debt, a $46 million net decrease in borrowings under credit facilities and a decrease in finance lease obligations of $10 million.

(2)Includes bank overdraft of $3 million.

(3)Other dividends payable related to payment of TransAlta Renewables' non-controlling interest dividend reflected within distributions paid to subsidiaries of non-controlling interests in the Consolidated Statements of Cash Flows.

	Balance Dec. 31, 2021	Cash issuances(1)	Repayments and dividends paid(2)	New leases	Dividends declared	Foreign exchange impact	Other	Balance Dec. 31, 2022
Long-term debt and lease liabilities(3)	3,267	981	(630)	40	—	39	(28)	3,669
Exchangeable securities	735	—	—	—	—	—	4	739
Dividends payable (common and preferred)	62	—	(97)	—	103	—	—	68
Total liabilities from financing activities	4,064	981	(727)	40	103	39	(24)	4,476

(1)Includes $449 million net increase in borrowings under credit facilities and an increase in issuance of long-term debt of $532 million.

(2)Includes a decrease of $621 million related to the repayment of long-term debt and a decrease in finance lease obligations of $9 million.

(3)Includes bank overdraft of $16 million.

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Capital

12 Months Ended

Dec. 31, 2023

Disclosure of notes and other explanatory information [Abstract]

Capital

Capital

TransAlta’s capital is comprised of the following:

As at Dec. 31	2023	2022	Increase/ (decrease)
Long-term debt(1)	3,466	3,653	(187)
Exchangeable securities	744	739	5
Bank overdraft	3	16	(13)
Equity
Common shares	3,285	2,863	422
Preferred shares	942	942	—
Contributed surplus	41	41	—
Deficit	(2,567)	(2,514)	(53)
Accumulated other comprehensive income (loss)	(164)	(222)	58
Non-controlling interests	127	879	(752)
Less: available cash and cash equivalents(2)	(348)	(1,134)	786
Less: principal portion of restricted cash on TransAlta OCP bonds(3)	(17)	(17)	—
Less: fair value liability (asset) of hedging instruments on long-term debt(4)	5	(3)	8
Total capital	5,517	5,243	274

(1)Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt.

(2)The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed using a net debt position. 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 as 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 our 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 Morningstar DBRS (stable outlook). In 2023, Moody's reaffirmed the Company's long term rating of Ba1 with a stable outlook. Morningstar DBRS reaffirmed 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 outlook, and S&P Global Ratings

reaffirmed the Company's senior unsecured debt rating and issuer credit 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, 2023 and 2022, 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 are available to fund operations, pay dividends, distribute payments to subsidiaries' non-controlling interests and invest in PP&E.

Year ended Dec. 31	2023	2022	Increase (decrease)
Cash flow from operating activities	1,464	877	587
Change in non-cash working capital	(124)	316	(440)
Cash flow from operations before changes in working capital	1,340	1,193	147
Dividends paid on common shares	(58)	(54)	(4)
Dividends paid on preferred shares	(51)	(43)	(8)
Distributions paid to subsidiaries’ non-controlling interests	(223)	(187)	(36)
Property, plant and equipment expenditures	(875)	(918)	43
Inflow (outflow)	133	(9)	142

TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2023, $1.4 billion (2022 – $1.0 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 maintain its capital structure and credit metrics within targeted ranges.

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Related Party Transactions

12 Months Ended

Dec. 31, 2023

Related Party [Abstract]

Related Party Transactions

Related-Party Transactions

Details of the Company’s principal operating subsidiaries at Dec. 31, 2023, 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	100(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

(1)On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. TransAlta Renewables at Dec. 31, 2023, is a wholly owned subsidiary of the Company (2022 – 60.1 per cent). Refer to Note 4 for more details.

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"), 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	2023	2022	2021
Total compensation	21	23	30
Comprised of:
Short-term employee benefits	11	11	14
Post-employment benefits	1	1	1
Termination benefits	1	—	—
Share-based payments	8	11	15

B. Transactions with Associates

In connection with the exchangeable securities issued to Brookfield, the Investment Agreement entitles Brookfield to nominate two directors to the TransAlta Board. This allows Brookfield to participate in the financial and operating policy decisions of the Company, and as such, they are considered associates of the Company.

In addition to the exchangeable securities disclosed in Note 25, the Company may, in the normal course of

operations, enter into transactions on market terms with associates that have been measured at exchange value and recognized in the Consolidated Financial Statements, including power purchase and sale agreements, derivative contracts and asset management fees. Transactions and balances between the Company and associates do not eliminate.

Transactions with Brookfield include the following:

Year ended Dec. 31	2023	2022	2021
Power sales	135	127	27
Purchased power	2	12	3
Asset management fees paid	1	2	2

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Disclosure of other provisions, contingent liabilities and contingent assets [Abstract]

Commitments and Contingencies

Commitments and Contingencies

In addition to the commitments disclosed elsewhere in the financial statements, the Company has incurred the following contractual commitments, either directly or through its interests in joint operations and joint ventures.

Approximate future payments under these agreements are as follows:

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Natural gas, transportation and other contracts	55	49	50	48	57	436	695
Transmission	9	9	6	4	5	93	126
Coal supply agreements	86	71	—	—	—	—	157
Long-term service agreements	60	57	42	44	37	184	424
Operating leases	3	3	2	2	2	25	37
Growth	47	—	—	—	—	—	47
Total	260	189	100	98	101	738	1,486

Commitments

Natural Gas, Transportation and Other Contracts 

The Company has fixed price or volume natural gas purchase and transportation contracts. Included in these contracts are 15-year natural gas transportation agreements for a total of up to 400 terajoules ("TJ") per day on a firm basis, ending in 2036 to 2038 and eight-year natural gas transportation agreements for 75 TJ per day related to the Sheerness facility ending in 2030 to 2031.

Transmission

The Company has several agreements to purchase transmission network capacity in 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.

Coal Supply 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.

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, equipment for gas and turbines at various wind facilities.

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.

Growth

Commitments for growth include the following projects: Horizon Hill wind project, White Rock wind projects, the Australian capacity and transmission expansions, the Mount Keith 132kV expansion and various other growth projects.

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.

The Company conducts internal reviews of its offers and offer behaviour in both the energy and ancillary services markets in Alberta on an ongoing basis and will self-report suspected contraventions or respond to inquiries from regulatory agencies as required. There currently is no certainty that any particular matter will be resolved in the Company’s favour or that such matters may not have a material adverse effect on TransAlta.

Brazeau Facility - Well License Applications to Consider Hydraulic Fracturing Activities

The Alberta Energy Regulator ("AER") issued a subsurface order on May 27, 2019, which does not permit any hydraulic fracturing within three kilometres of the Brazeau facility but permits hydraulic fracturing in all formations (except the Duvernay) within three to five kilometres of the Brazeau facility. Subsequently, two oil and gas operators submitted applications to the AER for 10 well licences (which include hydraulic fracturing activities) within three to five kilometres of the Brazeau facility.

The Company's position, based on independent expert analysis commissioned by the Government of Alberta, is that hydraulic fracturing activities within five kilometres of the Brazeau facility pose an unacceptable risk and that the applications should be denied. The regulatory hearing to consider these applications - Proceeding 379 - was adjourned to April 2025. The other parties to the hearing, including the Company, have supported the adjournment.

Brazeau Facility - Claim against the
Government of Alberta

On Sept. 9, 2022, the Company filed a Statement of Claim against the Alberta Government in the Alberta Court of King’s Bench seeking a declaration that: (a) granting mineral leases within five kilometres of the Brazeau facility is a breach of the 1960 agreement between the Company and the Alberta Government; and (b) the Alberta Government is required to indemnify the Company for any costs or damages that result from the risks of hydraulic fracturing near the Brazeau facility. On Sept. 29, 2022, the Alberta Government filed its Statement of Defence, which asserts, among other things, that the Company: (a) is trying

to usurp the jurisdiction of the AER; and (b) is out of time under the Limitations Act (Alberta). The trial was scheduled for two weeks starting Feb. 26, 2024. The parties to the matter, along with Cenovus Energy Inc., sought an adjournment when AER Proceeding 379 was adjourned. The trial is scheduled to resume in February 2025 in the event the parties are unable to resolve the dispute prior to such date.

Garden Plain

Garden Plain I LP, a wholly owned subsidiary of the Company, retained a third-party contractor to construct the Garden Plain wind project near Hanna, Alberta. The contractor experienced scheduling delays, challenges with construction and significant cost overruns, resulting in overdue deadlines, and has asserted a claim for $49 million in damages. The Company disputes this claim in its entirety and asserts a counterclaim. The parties have initiated the dispute resolution procedure, and the arbitration hearing is set down for three weeks starting April 14, 2025.

Hydro Power Purchase Arrangement ("Hydro PPA") Emissions Performance Credits

The Balancing Pool claimed entitlement to 1,750,000 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 EPCs under dispute had no recorded book value as they were internally generated. The Balancing Pool claimed ownership of the EPCs because it believed the change-in-law provisions under the Hydro PPA required the EPCs to be passed through to the Balancing Pool. TransAlta disputed this claim. The parties have reached a confidential settlement and this matter is now resolved.

Sundance A Decommissioning

TransAlta filed an application with the Alberta Utilities Commission 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. The application is being heard in the first quarter of 2024 with a decision expected to be rendered in the third quarter of 2024.

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Segments Disclosures

12 Months Ended

Dec. 31, 2023

Disclosure of operating segments [abstract]

Segments Disclosures

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 TransAlta’s President and Chief Executive Officer (the chief operating decision maker) ("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, gains and losses related to closed positions effectively settled by offsetting positions with exchanges recorded in the year the positions are settled, 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, items within the Energy Transition segment that may not be reflective of on-going operations including certain costs related to decisions made to accelerate our transition off-coal in Alberta and our planned transition off-coal for Centralia, 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.

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 and Segment Assets

I. Reconciliation of Adjusted EBITDA to Earnings (Loss) before Income Tax

Year ended Dec. 31, 2023	Hydro	Wind &  Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass  adjustments	IFRS financials
Revenues	533	357	1,514	751	220	1	3,376	(21)	—	3,355
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	(4)	16	(67)	(5)	23	—	(37)	—	37	—
Realized gain (loss) on closed exchange positions	—	—	10	—	(91)	—	(81)	—	81	—
Decrease in finance lease receivable	—	—	55	—	—	—	55	—	(55)	—
Finance lease income	—	—	12	—	—	—	12	—	(12)	—
Unrealized foreign exchange loss on commodity	—	—	1	—	—	—	1	—	(1)	—
Adjusted revenues	529	373	1,525	746	152	1	3,326	(21)	50	3,355
Fuel and purchased power	19	30	453	557	—	1	1,060	—	—	1,060
Reclassifications and adjustments:
Australian interest income	—	—	(4)	—	—	—	(4)	—	4	—
Adjusted fuel and purchased power	19	30	449	557	—	1	1,056	—	4	1,060
Carbon compliance	—	—	112	—	—	—	112	—	—	112
Gross margin	510	343	964	189	152	—	2,158	(21)	46	2,183
OM&A	48	80	192	64	43	115	542	(3)	—	539
Taxes, other than income taxes	3	12	11	3	—	1	30	(1)	—	29
Net other operating income	—	(7)	(40)	—	—	—	(47)	—	—	(47)
Reclassifications and adjustments:
Insurance recovery	—	1	—	—	—	—	1	—	(1)	—
Adjusted net other operating income	—	(6)	(40)	—	—	—	(46)	—	(1)	(47)
Adjusted EBITDA(2)	459	257	801	122	109	(116)	1,632
Equity income										4
Finance lease income										12
Depreciation and amortization										(621)
Asset impairment reversals										48
Interest income										59
Interest expense										(281)
Foreign exchange loss										(7)
Gain on sale of assets and other										4
Earnings before income taxes										880

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

Year ended Dec. 31, 2022	Hydro	Wind &  Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	606	303	1,209	714	160	(2)	2,990	(14)	—	2,976
Reclassifications and adjustments:
Unrealized mark-to-market loss	1	104	251	10	12	—	378	—	(378)	—
Realized gain (loss) on closed exchange positions	—	—	(4)	—	47	—	43	—	(43)	—
Decrease in finance lease receivable	—	—	46	—	—	—	46	—	(46)	—
Finance lease income	—	—	19	—	—	—	19	—	(19)	—
Unrealized foreign exchange gain on commodity	—	—	—	—	(1)	—	(1)	—	1	—
Adjusted revenues	607	407	1,521	724	218	(2)	3,475	(14)	(485)	2,976
Fuel and purchased power	22	31	641	566	—	3	1,263	—	—	1,263
Reclassifications and adjustments:
Australian interest income	—	—	(4)	—	—	—	(4)	—	4	—
Adjusted fuel and purchased power	22	31	637	566	—	3	1,259	—	4	1,263
Carbon compliance	—	1	83	(1)	—	(5)	78	—	—	78
Gross margin	585	375	801	159	218	—	2,138	(14)	(489)	1,635
OM&A	55	68	195	69	35	101	523	(2)	—	521
Taxes, other than income taxes	3	12	15	4	—	1	35	(2)	—	33
Net other operating income	—	(23)	(38)	—	—	—	(61)	3	—	(58)
Reclassifications and adjustments:
Insurance recovery	—	7	—	—	—	—	7	—	(7)	—
Adjusted net other operating   income	—	(16)	(38)	—	—	—	(54)	3	(7)	(58)
Adjusted EBITDA(2)	527	311	629	86	183	(102)	1,634
Equity income										9
Finance lease income										19
Depreciation and amortization										(599)
Asset impairment charges										(9)
Interest income										24
Interest expense										(286)
Foreign exchange gain										4
Gain on sale of assets and other										52
Earnings before income taxes										353

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

Year ended Dec. 31, 2021	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	—
Realized gain (loss) on closed exchange positions	—	—	(6)	—	29	—	23	—	(23)	—
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	1,126	728	202	4	2,791	(18)	(52)	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 writedown	—	—	—	(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	634	236	202	—	1,770	(18)	(263)	1,489
OM&A	42	59	175	117	36	84	513	(2)	—	511
Reclassifications and adjustments:
Parts and materials writedown	—	—	(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 loss (income)	—	—	(40)	48	—	—	8	—	—	8
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties	—	—	—	(48)	—	—	(48)	—	48	—
Adjusted net other operating loss (income)	—	—	(40)	—	—	—	(40)	—	48	8
Adjusted EBITDA(2)	322	262	488	133	166	(85)	1,286
Equity income										9
Finance lease income										25
Depreciation and amortization										(529)
Asset impairment charges										(648)
Interest income										11
Interest expense										(256)
Foreign exchange gain										16
Gain on sale of assets and other										54
Loss before income taxes										(380)

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

II. Selected Consolidated Statements of Financial Position Information

As at As at Dec. 31, 2023	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
PP&E	462	3,360	1,543	251	—	98	5,714
Right-of-use assets	7	94	5	—	—	11	117
Intangible assets	2	141	40	4	5	31	223
Goodwill	258	176	—	—	30	—	464
As at As at Dec. 31, 2022	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
PP&E	437	2,837	1,858	313	—	111	5,556
Right-of-use assets	6	98	6	2	—	14	126
Intangible assets	2	157	49	5	8	31	252
Goodwill	258	176	—	—	30	—	464

III. Selected Consolidated Statements of Cash Flows Information

Additions to non-current assets are as follows:

Year ended Dec. 31, 2023	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	42	674	89	16	—	54	875
Intangible assets	—	—	—	—	—	13	13
Year ended Dec. 31, 2022	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	36	745	43	19	—	75	918
Intangible assets	—	19	—	—	3	9	31
Year ended Dec. 31, 2021	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	29	166	167	90	—	28	480
Intangible assets	—	—	—	1	—	8	9

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	2023	2022	2021
Depreciation and amortization expense on the Consolidated Statements of Earnings (Loss)	621	599	529
Depreciation included in fuel and purchased power (Note 6)	—	—	190
Depreciation and amortization on the Consolidated Statements of Cash Flows	621	599	719

C. Geographic Information

I. Revenues

Year ended Dec. 31	2023	2022	2021
Canada	2,218	1,905	1,854
US	987	940	731
Australia	150	131	136
Total revenue	3,355	2,976	2,721

II. Non-Current Assets

	Property, plant and equipment		Right-of-use assets		Intangible assets		Other assets
As at Dec. 31	2023	2022	2023	2022	2023	2022	2023	2022
Canada	3,578	3,817	43	49	108	123	68	62
US	1,749	1,307	71	74	88	101	42	34
Australia	387	432	3	3	27	28	69	64
Total	5,714	5,556	117	126	223	252	179	160

D. Significant Customer 

For the year ended Dec. 31, 2023, sales to the AESO represented 46 per cent of the Company’s total revenue (2022 – sales to the AESO represented 60 per cent of the Company’s total revenue). There were no other companies that accounted for more than 10 per cent of the Company's total revenue.

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Material Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

Basis of Preparation

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. 22, 2024.

Basis of Consolidation

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.

Revenue Recognition

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. Contract modifications are accounted for as separate contracts when the consideration for the additional promised goods reflects a stand-alone selling price. Otherwise, contract modifications are accounted for as part of the existing contract. If the additional goods are not considered distinct the transaction price can be affected and adjustments to previously recognized revenue can occur. If the additional goods are distinct, the existing and modified contracts are treated together as a new contract, with impacts reflected prospectively from the modification date, which can include the blending of contract prices. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the goods or services are 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 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 that has previously been constrained 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, the 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 (e.g., 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 (e.g., 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 (e.g., 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.
Generation byproducts	Generation byproducts refers to the sale of byproducts from the use of coal in the Company’s current US and previous Canadian coal operations. 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) include 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 ("VPPA"). Contracts for differences are financial contracts whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh. A VPPA is whereby the Company receives the difference between the fixed contract price per MWh and the settled market price. These arrangements meet the definition of a derivative 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.

Financial Instruments and Hedges

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 (loss) (“FVTOCI”).

Financial assets with contractual cash flows arising on specified dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows, are subsequently measured at amortized cost. Financial assets measured at FVTOCI are those that have contractual cash flows, arising on specific dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows and to sell the

financial asset and investments in equity instruments. 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 investor's investment is subsequently considered residual equity ownership with distributions classified as 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.

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.

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 income (loss) ("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 income (loss) ("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 of 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.

Cash and Cash Equivalents

Cash and Cash Equivalents

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

Inventory

Inventory

I. Fuel

The Company’s inventory balance is composed 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 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 and 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 at the estimated compliance cost required by the Company to settle its obligation in excess of government-established caps and targets. Compliance costs that are recoverable under the terms of the contracts with third parties are recognized as Revenue from Contracts with Customers.

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.

Property, Plant and Equipment

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 if it is probable that future economic benefits will be realized and the cost of the item can be measured reliably. The cost of major spare parts is capitalized and classified as PP&E, as these items can only be used in connection with an item of PP&E.

Planned maintenance is performed at regular intervals. Planned major maintenance includes inspection, repair and maintenance of existing components and the replacement of existing components. Costs incurred for planned major maintenance activities are capitalized in the period maintenance activities occur and are amortized on a straight-line basis 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. Insurance 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. 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	1-49 years
Wind and Solar generation	1-30 years
Gas generation	1-34 years
Energy Transition	1-9 years
Capital spares and other	1-49 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.

Intangible Assets

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 composed of all directly attributable costs necessary to create, produce and prepare the intangible asset to be capable of operating in the manner intended by management.

Subsequent to initial recognition, intangible assets continue to be measured using the cost model and are reported at cost less accumulated amortization and impairment losses, if any. Amortization is included in depreciation and amortization 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.

Impairment of Tangible and Intangible Assets Excluding Goodwill

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 flow 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.

Goodwill

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.

Income Taxes

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 reassessed at each reporting date and are recognized 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.

Employee Future Benefits

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 prorated based on service. The net interest cost is determined by applying the discount rate to the net defined benefit liability. The discount rate used to determine the present value of the defined benefit obligation and the net interest cost, is determined by reference to market yields at the end of the reporting period on high-quality corporate bonds with terms and currencies that match the estimated terms and currencies of the benefit obligations. Remeasurements, which include actuarial gains and losses and the return on plan assets (excluding net interest), are recognized through OCI in the period in which they occur. Actuarial gains and losses arise

from experience adjustments and changes in actuarial assumptions. Remeasurements are not reclassified to profit or loss, from OCI, in subsequent periods.

Gains or losses arising from either a curtailment or settlement of a defined benefit plan are recognized when the curtailment or settlement occurs. When the restructuring of a benefit plan gives rise to a curtailment and a settlement of obligations, the curtailment is accounted for prior to the settlement.

In determining whether statutory minimum funding requirements of the 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.

Provisions

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. 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.

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 for both the decommissioning and restoration provision and other provisions are charged to net earnings each period and is included in net interest expense.

Leases

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.

I. 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.

II. Lessor

Power Purchase Agreements ("PPAs") and other long-term contracts may contain, or may be considered, leases where the fulfilment of the arrangement is dependent on the use of a specific asset (e.g., a generating unit) and the arrangement conveys to the customer the right to 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.

Non-Controlling Interests

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 income (loss) is attributed to the non-controlling interests even if this results in the non-controlling interests having a negative balance.

When the proportion of the equity held by non-controlling interests changes, the carrying amounts of the controlling and non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiary. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received, is recognized directly in equity and attributed to shareholders.

Joint Arrangements

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.

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.

Business Combinations

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.

Significant Accounting Judgments and Key Sources of Estimation Uncertainty

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 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. 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 regard 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 2021 to 2023 is disclosed 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.

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. In 2023, a finance lease receivable was recognized as it was determined that the significant risks and rewards of ownership of the facilities were transferred to the customer. See Note 17.

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. Information regarding the impacts of the Company’s tax policies is disclosed in Note 11.

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. Transfers between levels of the fair value hierarchy are deemed to have occurred at             

the end of the reporting period in which the event or change in circumstances that caused the transfer occurred. These fair value levels are outlined and discussed in more detail in Note 14. 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 fulfilled.

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 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 when determining the amount to be capitalized. Information regarding project development costs is disclosed in Note 22 and 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). 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 to 2023 in respect of decommissioning and restoration provisions is disclosed in Notes 7, 18 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;

•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. Disclosures on employee future benefits are disclosed in Note 31.

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 8 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, to determine when this transfer occurs.

When contracts are modified, management must exercise judgment to determine, depending upon the facts and circumstances of the changes to the contract, whether the modification is accounted for as a new contract or as part of the existing contract. If it is required to be accounted for as part of the existing contract the transaction price can be affected and adjustments to previously recognized revenue can occur, or the impacts can be reflected prospectively from the modification date.

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, and this 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.

XII. Significant Influence

Upon entering into an investment, the Company must classify it as either an investment in 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, 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, 2023, there were changes in estimates relating to asset impairment charges (reversals) (Note 7), useful lives (Note 18), decommissioning and other provisions (Note 23) and defined benefit obligation (Note 26). During the year ended

Dec. 31, 2022, there were changes in estimates relating to asset impairment charges (reversals) (Note 7), asset useful lives and depreciation (Note 18), decommissioning and other provisions (Note 23) and defined benefit obligation (Note 26).

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Material Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

Disclosure of detailed information about property, plant and equipment

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

Hydro generation	1-49 years
Wind and Solar generation	1-30 years
Gas generation	1-34 years
Energy Transition	1-9 years
Capital spares and other	1-49 years

The Company recognized the following asset impairment charges (reversals):

Year ended Dec. 31	2023	2022	2021
Segments:
Hydro	(10)	21	5
Wind and Solar	(4)	43	12
Gas		—	5
Energy Transition	—	—	540
Corporate	—	(2)	27
Changes in decommissioning and restoration provisions on retired assets(1)	(34)	(53)	32
Intangible asset impairment charges - coal rights	—	—	17
Project development costs	—	—	10
Asset impairment charges (reversals)	(48)	9	648

(1)Changes relate to changes in discount rates and cash flow revisions on retired assets in 2023 and 2022 and cash flow revisions on retired assets in 2021. Refer to Note 23 for further details.

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

	Assets under construction	Land	Hydro	Wind and Solar	Gas generation	Energy Transition	Capital spares and other(1)	Total
Cost
As at Dec. 31, 2021	184	96	867	3,276	4,087	4,513	366	13,389
Additions(2)	891	—	—	—	—	—	6	897
Additions from development projects	17	—	—	—	—	—	12	29
Disposals	—	(3)	—	—	(1)	(216)	—	(220)
Impairment (charges) reversals (Note 7)	2	—	(21)	(43)	—	—	—	(62)
Changes to decommissioning and restoration costs (Note 23)	—	—	(15)	(59)	(12)	10	2	(74)
Retirement of assets	—	—	(9)	(9)	(12)	(7)	(2)	(39)
Change in foreign exchange rates	13	—	—	45	(4)	97	2	153
Transfers of assets(3)	(144)	—	18	23	472	(423)	(7)	(61)
As at Dec. 31, 2022	963	93	840	3,233	4,530	3,974	379	14,012
Additions(2)	869	—	—	—	—	—	6	875
Disposals	—	(3)	—	—	—	(30)	—	(33)
Impairment reversals (Note 7)	—	—	10	4	—	—	—	14
Changes to decommissioning and restoration costs (Note 23)	—	—	3	14	(22)	3	(1)	(3)
Retirement of assets	—	—	(7)	(18)	(124)	(7)	(108)	(264)
Change in foreign exchange rates	(26)	—	—	(18)	(7)	(42)	(1)	(94)
Transfers of assets(3)	(572)	—	38	439	50	16	31	2
Transfers to finance lease receivable (Note 17)	—	—	—	(61)	(4)	—	—	(65)
As at Dec. 31, 2023	1,234	90	884	3,593	4,423	3,914	306	14,444
Accumulated depreciation
As at Dec. 31, 2021	—	—	468	1,093	2,178	4,150	180	8,069
Depreciation	—	—	21	130	308	63	16	538
Retirement of assets	—	—	(8)	(6)	(10)	(7)	(2)	(33)
Disposals	—	—	—	—	(1)	(211)	—	(212)
Change in foreign exchange rates	—	—	—	11	2	89	—	102
Transfers of assets(3)	—	—	(3)	—	335	(340)	—	(8)
As at Dec. 31, 2022	—	—	478	1,228	2,812	3,744	194	8,456
Depreciation	—	—	25	129	342	73	16	585
Retirement of assets	—	—	(4)	(15)	(101)	(7)	(108)	(235)
Disposals	—	—	—	—	—	(30)	—	(30)
Change in foreign exchange rates	—	—	—	(5)	(3)	(39)	—	(47)
Transfers in (out) of PP&E(3)	—	—	—	—	(1)	2	—	1
As at Dec. 31, 2023	—	—	499	1,337	3,049	3,743	102	8,730
Carrying amount
As at Dec. 31, 2021	184	96	399	2,183	1,909	363	186	5,320
As at Dec. 31, 2022	963	93	362	2,005	1,718	230	185	5,556
As at Dec. 31, 2023	1,234	90	385	2,256	1,374	171	204	5,714

(1)Includes major spare parts and standby equipment available, but not in service.

(2)In 2023, the Company capitalized $57 million (2022 – $16 million) of interest to PP&E in at a weighted average rate of 6.3 per cent (2022 – 6.0 per cent).

(3)Includes transfers of assets upon commissioning to assets in service and other movements.

Disclosure of detailed information about intangible assets

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	1-7 years
Power sale contracts	1-18 years

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Revenue (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of revenue from contracts with customers [Abstract]

Disclosure of disaggregation of revenue

The majority of the Company's revenues are derived from the sale of 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, 2023	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Revenues from contracts with customers
Power and other	30	190	400	12	—	—	632
Environmental attributes(1)	14	26	—	—	—	—	40
Revenue from contracts with customers	44	216	400	12	—	—	672
Revenue from leases(2)	—	—	32	—	—	—	32
Revenue from derivatives and other trading activities(3)	44	(2)	(172)	251	220	—	341
Revenue from merchant sales	434	104	1,247	488	—	—	2,273
Other(4)	11	18	7	—	—	1	37
Total revenue	533	336	1,514	751	220	1	3,355
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	14	26	—	12	—	—	52
Over time	30	190	400	—	—	—	620
Total revenue from contracts with customers	44	216	400	12	—	—	672

(1)The environmental attributes represent environmental attribute sales not bundled with power and other sales.

(2)Total lease income from long-term contracts that meet the criteria of operating leases.

(3)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions.

(4) Other revenue includes production tax credits related to US wind facilities and other miscellaneous revenues.

Year ended Dec. 31, 2022	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Revenues from contracts with customers
Power and other	33	220	462	10	—	—	725
Environmental attributes(1)	1	50	—	—	—	—	51
Revenue from contracts with customers	34	270	462	10	—	—	776
Revenue from leases(2)	—	—	32	—	—	—	32
Revenue from derivatives and other trading activities(3)	—	(121)	(821)	243	160	(2)	(541)
Revenue from merchant sales	564	119	1,529	461	—	—	2,673
Other(4)	8	21	7	—	—	—	36
Total revenue	606	289	1,209	714	160	(2)	2,976
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	1	50	—	12	—	—	63
Over time	33	220	462	(2)	—	—	713
Total revenue from contracts with customers	34	270	462	10	—	—	776

(1)The environmental attributes represent environmental attribute sales not bundled with power and other sales.

(2)Total lease income from long-term contracts that meet the criteria of operating leases.

(3)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions.

(4)Other revenue includes production tax credits related to US wind facilities and other miscellaneous revenues.

Year ended Dec. 31, 2021	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Revenues from contracts with customers
Power and other	28	207	395	24	—	—	654
Environmental attributes(1)	—	28	—	—	—	—	28
Revenue from contracts with customers	28	235	395	24	—	—	682
Revenue from leases(2)	—	—	19	—	—	—	19
Revenue from derivatives and other trading activities(3)	—	(22)	(118)	138	211	4	213
Revenue from merchant sales	345	35	808	546	—	—	1,734
Other(4)	10	57	5	1	—	—	73
Total revenue	383	305	1,109	709	211	4	2,721
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)The environmental attributes represent environmental attribute sales not bundled with power and other sales.

(2)Total lease income from long-term contracts that meet the criteria of operating leases.

(3)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions.

(4)Other revenue includes production tax credits related to US wind facilities and other miscellaneous revenues.

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Expenses by Nature (Tables)

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Disclosure of expenses classified by nature

Fuel and purchased power and OM&A expenses classified by nature are as follows:

Year ended Dec. 31	2023		2022		2021
	Fuel and purchased power	OM&A	Fuel and purchased power	OM&A	Fuel and purchased power	OM&A
Gas fuel costs	384	—	578	—	306	—
Coal fuel costs(1)	177	—	146	—	164	—
Royalty, land lease, other direct costs	25	—	25	—	19	—
Purchased power	474	—	514	—	339	—
Mine depreciation(2)	—	—	—	—	190	—
Salaries and benefits	—	254	—	263	36	234
Other operating expenses(3)	—	285	—	258	—	277
Total	1,060	539	1,263	521	1,054	511

(1)Included in coal fuel costs for 2021 was $17 million related to the impairment of coal inventory.

(2)Included in mine depreciation for 2021 was $48 million related to mine depreciation that was initially recorded in the standard cost of coal inventory and then subsequently written down during 2021.

(3)Included in OM&A costs for 2023 was $14 million related to the write-down of parts and material inventory related to our natural-gas-fired facilities. 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.

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Asset Impairment Charges (Reversals) (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of impairment of assets [Abstract]

Disclosure of detailed information about property, plant and equipment

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

Hydro generation	1-49 years
Wind and Solar generation	1-30 years
Gas generation	1-34 years
Energy Transition	1-9 years
Capital spares and other	1-49 years

The Company recognized the following asset impairment charges (reversals):

Year ended Dec. 31	2023	2022	2021
Segments:
Hydro	(10)	21	5
Wind and Solar	(4)	43	12
Gas		—	5
Energy Transition	—	—	540
Corporate	—	(2)	27
Changes in decommissioning and restoration provisions on retired assets(1)	(34)	(53)	32
Intangible asset impairment charges - coal rights	—	—	17
Project development costs	—	—	10
Asset impairment charges (reversals)	(48)	9	648

(1)Changes relate to changes in discount rates and cash flow revisions on retired assets in 2023 and 2022 and cash flow revisions on retired assets in 2021. Refer to Note 23 for further details.

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

	Assets under construction	Land	Hydro	Wind and Solar	Gas generation	Energy Transition	Capital spares and other(1)	Total
Cost
As at Dec. 31, 2021	184	96	867	3,276	4,087	4,513	366	13,389
Additions(2)	891	—	—	—	—	—	6	897
Additions from development projects	17	—	—	—	—	—	12	29
Disposals	—	(3)	—	—	(1)	(216)	—	(220)
Impairment (charges) reversals (Note 7)	2	—	(21)	(43)	—	—	—	(62)
Changes to decommissioning and restoration costs (Note 23)	—	—	(15)	(59)	(12)	10	2	(74)
Retirement of assets	—	—	(9)	(9)	(12)	(7)	(2)	(39)
Change in foreign exchange rates	13	—	—	45	(4)	97	2	153
Transfers of assets(3)	(144)	—	18	23	472	(423)	(7)	(61)
As at Dec. 31, 2022	963	93	840	3,233	4,530	3,974	379	14,012
Additions(2)	869	—	—	—	—	—	6	875
Disposals	—	(3)	—	—	—	(30)	—	(33)
Impairment reversals (Note 7)	—	—	10	4	—	—	—	14
Changes to decommissioning and restoration costs (Note 23)	—	—	3	14	(22)	3	(1)	(3)
Retirement of assets	—	—	(7)	(18)	(124)	(7)	(108)	(264)
Change in foreign exchange rates	(26)	—	—	(18)	(7)	(42)	(1)	(94)
Transfers of assets(3)	(572)	—	38	439	50	16	31	2
Transfers to finance lease receivable (Note 17)	—	—	—	(61)	(4)	—	—	(65)
As at Dec. 31, 2023	1,234	90	884	3,593	4,423	3,914	306	14,444
Accumulated depreciation
As at Dec. 31, 2021	—	—	468	1,093	2,178	4,150	180	8,069
Depreciation	—	—	21	130	308	63	16	538
Retirement of assets	—	—	(8)	(6)	(10)	(7)	(2)	(33)
Disposals	—	—	—	—	(1)	(211)	—	(212)
Change in foreign exchange rates	—	—	—	11	2	89	—	102
Transfers of assets(3)	—	—	(3)	—	335	(340)	—	(8)
As at Dec. 31, 2022	—	—	478	1,228	2,812	3,744	194	8,456
Depreciation	—	—	25	129	342	73	16	585
Retirement of assets	—	—	(4)	(15)	(101)	(7)	(108)	(235)
Disposals	—	—	—	—	—	(30)	—	(30)
Change in foreign exchange rates	—	—	—	(5)	(3)	(39)	—	(47)
Transfers in (out) of PP&E(3)	—	—	—	—	(1)	2	—	1
As at Dec. 31, 2023	—	—	499	1,337	3,049	3,743	102	8,730
Carrying amount
As at Dec. 31, 2021	184	96	399	2,183	1,909	363	186	5,320
As at Dec. 31, 2022	963	93	362	2,005	1,718	230	185	5,556
As at Dec. 31, 2023	1,234	90	385	2,256	1,374	171	204	5,714

(1)Includes major spare parts and standby equipment available, but not in service.

(2)In 2023, the Company capitalized $57 million (2022 – $16 million) of interest to PP&E in at a weighted average rate of 6.3 per cent (2022 – 6.0 per cent).

(3)Includes transfers of assets upon commissioning to assets in service and other movements.

Disclosure of fair value less cost of disposal

The calculation of fair value less costs of disposal for all of the above facilities is most sensitive to the following assumptions:

	Location of assets	Current year contract and merchant discount rates	Prior year contract and merchant discount rates
Wind and Solar	Canada	6.4 and 7.0 per cent	6.4 and 7.1 per cent
	US	6.9 and 7.5 per cent	6.5 and 7.7 per cent
Hydro	Canada	6.1 and 6.4 per cent	5.9 and 6.4 per cent

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Net Other Operating (Income) Loss (Tables)

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Disclosure of components of net other operating (income) Loss

Net other operating (income) loss includes the following:

Year ended Dec. 31	2023	2022	2021
Alberta Off-Coal Agreement	(40)	(40)	(40)
Liquidated damages recoverable	(6)	(12)	—
Insurance recoveries	(1)	(7)	—
Supplier, other contract settlements and other	—	1	34
Onerous contract provisions	—	—	14
Net other operating (income) loss	(47)	(58)	8

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Investments (Tables)

12 Months Ended

Dec. 31, 2023

Interests In Other Entities [Abstract]

Disclosure of investments in joint ventures and associates

The change in investments is as follows:

	EMG	Skookumchuck	Tent Mountain	EIP	Ekona	Total
Classification	Equity-accounted	Equity-accounted	Equity-accounted	FVTPL	FVTOCI
Balance, Dec. 31, 2021	12	93	—	—	—	105
Investment	—	—	—	10	2	12
Equity income (loss)	(1)	10	—	—	—	9
Distributions received	—	(5)	—	—	—	(5)
Changes in foreign exchange rates	1	7	—	1	—	9
Net change in fair value recognized in OCI	—	—	—	—	(1)	(1)
Balance, Dec. 31, 2022	12	105	—	11	1	129
Investment	—	—	10	4	—	14
Equity income (loss)	(4)	8	—	—	—	4
Distributions received	—	(6)	—	—	—	(6)
Changes in foreign exchange rates	—	(3)	—	—	—	(3)
Balance, Dec. 31, 2023	8	104	10	15	1	138

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

Year ended Dec. 31	2023	2022	2021
Results of operations
Revenues and other operating income	22	24	19
Expenses	(18)	(15)	(10)
Proportionate share of net earnings	4	9	9

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Interest Expense (Tables)

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Disclosure of components of net interest expense

The components of interest expense are as follows:

	2023	2022	2021
Interest on debt	203	164	163
Interest on exchangeable debentures (Note 25)	29	29	29
Interest on exchangeable preferred shares (Note 25)	28	28	28
Capitalized interest (Note 18)	(57)	(16)	(14)
Interest on lease liabilities	9	7	7
Credit facility fees, bank charges and other interest	21	27	20
Tax shield on tax equity financing (Note 24)	—	(2)	(9)
Accretion of provisions (Note 23)	48	49	32
Interest expense	281	286	256

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Taxes [Abstract]

Disclosure of rate reconciliations

Year ended Dec. 31	2023		2022		2021
Earnings (loss) before income taxes	880		353		(380)
Net earnings attributable to non-controlling interests not subject to tax	(80)		(94)		(33)
Adjusted earnings (loss) before income taxes	800		259		(413)
Statutory Canadian federal and provincial income tax rate (%)	23.4	%	23.4	%	23.6	%
Expected income tax expense (recovery)	187		61		(98)
Increase (decrease) in income taxes resulting from:
Differences in effective foreign tax rates	9		(1)		4
Non-deductible expense(1)	58		130		—
Taxable capital (gain) loss	(2)		18		—
Deferred income tax recovery related to temporary difference on investment in subsidiaries	(3)		(2)		—
Write-down (reversal of write-down) of unrecognized deferred income tax assets	(178)		(24)		134
Statutory and other rate differences	1		(3)		4
Adjustments in respect of deferred income tax of previous years	1		6		(4)
Other	11		7		5
Income tax expense	84		192		45
Effective tax rate (%)	11	%	74	%	(11	%)

(1)This amount is related to current and prior period tax adjustments in the US to mitigate cash tax relating to the Base Erosion and Anti-Abuse Tax.

Disclosure of components of income tax expense

The components of income tax expense are as follows:

Year ended Dec. 31	2023	2022	2021
Current income tax expense	50	65	56
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences	215	153	(145)
Deferred income tax recovery related to temporary difference on investment in subsidiaries	(3)	(2)	—
Write-down (reversal of write-down) of unrecognized deferred income tax assets(1)	(178)	(24)	134
Income tax expense	84	192	45
Current income tax expense	50	65	56
Deferred income tax expense (recovery)	34	127	(11)
Income tax expense	84	192	45

(1)During the year ended Dec. 31, 2023, the Company recognized deferred tax assets of $178 million (2022 - $24 million, 2021 - $134 million write-down). The deferred income tax assets mainly relate to the tax benefits associated with tax losses related to the Company's directly owned US operations and other deductible differences. The Company has not recognized an additional $157 million of deferred tax assets on the basis that it is not probable that sufficient future taxable income would be available to utilize these tax assets.

Disclosure of aggregate current and deferred income tax related to items charged or credited to equity

The aggregate current and deferred income tax related to items charged or credited to equity are as follows:

Year ended Dec. 31	2023	2022	2021
Income tax expense (recovery) related to:
Net impact related to cash flow hedges	27	(112)	(57)
Net impact related to hedges of foreign operations	1	(3)	—
Net impact related to net actuarial gains (losses)	(1)	12	11
Transaction costs for the acquisition of TransAlta Renewables	(2)	—	—
Income tax expense (recovery) reported in equity	25	(103)	(46)

Disclosure of significant components of deferred income tax assets (liabilities)

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

As at Dec. 31	2023	2022
Non-capital losses(1)	88	244
Future decommissioning and restoration costs	111	119
Property, plant and equipment	(605)	(553)
Risk management assets and liabilities, net	144	193
Employee future benefits and compensation plans	50	48
Foreign exchange differences on US-denominated debt	12	13
Other taxable temporary differences	(8)	(5)
Net deferred income tax asset (liability), before write-down of deferred income tax assets	(208)	59
Unrecognized deferred income tax assets	(157)	(361)
Net deferred income tax liability, after write-down of deferred income tax assets	(365)	(302)

(1)Non-capital losses expire between 2033 and 2043. Net operating losses from US operations have no expiration.

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

As at Dec. 31	2023	2022
Deferred income tax assets(1)	21	50
Deferred income tax liabilities	(386)	(352)
Net deferred income tax liability	(365)	(302)

(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.

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Non-Controlling Interests (Tables)

12 Months Ended

Dec. 31, 2023

Interests In Other Entities [Abstract]

Disclosure of share of ownership and equity participation in TransAlta Renewables

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

Subsidiary / Operation	Non-controlling interest owner	Non-controlling interest as at Dec. 31, 2023	Non-controlling interest as at Dec. 31, 2022
TransAlta Cogeneration LP	Canadian Power Holdings Inc.	49.99%	49.99%
Kent Hills Wind LP	Natural Forces Technologies Inc.	17%	17%
TransAlta Renewables Inc.	Public shareholders	nil(1)	39.9%

(1)Non-controlling interest from Jan. 1, 2023 to Oct. 4, 2023 was 39.9%.

Disclosure of interests in subsidiaries

TA Cogen

Year ended Dec. 31	2023	2022	2021
Revenues	290	347	265
Net earnings and total comprehensive income	121	143	103
Amounts attributable to the non-controlling interest:
Net earnings	80	91	62
Total comprehensive income	80	91	62
Distributions paid to Canadian Power Holdings Inc.	148	87	56

As at Dec. 31	2023	2022
Current assets	43	127
Long-term assets	193	253
Current liabilities	(41)	(62)
Long-term liabilities	(34)	(27)
Total equity	(161)	(291)
Equity attributable to Canadian Power Holdings Inc.	(79)	(147)
Non-controlling interest share (per cent)	49.99	49.99

Kent Hills Wind LP

Prior to Oct 5, 2023, financial information related to the 17 per cent non-controlling interest in Kent Hills Wind LP was included in the financial information disclosed in TransAlta Renewables in this note.

Year ended Dec. 31	2023(1)
Revenues	7
Net earnings and total comprehensive income	2
Amounts attributable to the non-controlling interest:
Net earnings and total comprehensive income	—

(1)This represents financial information from Oct. 5, 2023 to Dec. 31, 2023. The net earnings attributable to non-controlling interest in Kent Hills Wind LP prior to Oct. 5, 2023, is included in the disclosures for TransAlta Renewables.

As at Dec. 31	2023
Current assets	35
Long-term assets	481
Current liabilities	(42)
Long-term liabilities	(188)
Total equity	(285)
Equity attributable to non-controlling interests	(48)
Non-controlling interest share (per cent)	17

TransAlta Renewables

The financial information disclosed below includes the 17 per cent non-controlling interest in Kent Hills Wind LP until Oct. 5, 2023.

Year ended Dec. 31	2023(1)	2022	2021
Revenues	303	560	470
Net earnings	56	74	139
Total comprehensive income (loss)	(7)	(67)	66
Amounts attributable to the non-controlling interests:
Net earnings	21	20	50
Total comprehensive income (loss)	(4)	(36)	21
Distributions paid to non-controlling interests	75	100	100

(1)Non-controlling interest share prior the close of the transaction on Oct. 5, 2023. This represents financial information from Jan. 1, 2023 to Oct. 4, 2023.

As at Dec. 31	2022
Current assets	240
Long-term assets	2,989
Current liabilities	(306)
Long-term liabilities	(1,118)
Total equity	(1,805)
Equity attributable to non-controlling interests	(732)
Non-controlling interests’ share (per cent)	39.9

Details of the Company’s principal operating subsidiaries at Dec. 31, 2023, 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	100(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

(1)On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. TransAlta Renewables at Dec. 31, 2023, is a wholly owned subsidiary of the Company (2022 – 60.1 per cent). Refer to Note 4 for more details.

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Trade and Other Receivables and Accounts Payable (Tables)

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Disclosure of trade and Other Receivables

As at Dec. 31	2023	2022
Trade accounts receivable	600	1,165
Collateral provided (Note 15)	145	304
Current portion of finance lease receivables (Note 17)	19	52
Loan receivable (Note 22)	1	4
Income taxes receivable	42	64
Trade and other receivables	807	1,589

Components of Accounts Payable

As at Dec. 31	2023	2022
Accounts payable and accrued liabilities	772	1,069
Interest payable	16	17
Collateral held (Note 15)	9	260
Accounts payable and accrued liabilities	797	1,346

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Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of detailed information about financial instruments [abstract]

Disclosure of financial assets

Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost.

Carrying value as at Dec. 31, 2023	Derivatives used for hedging	Derivatives held for trading (FVTPL)	Amortized cost	Other financial assets (FVTPL)	Other financial assets (FVOCI)	Total
Financial assets
Cash and cash equivalents(1)	—	—	348	—	—	348
Restricted cash	—	—	69	—	—	69
Trade and other receivables	—	—	807	—	—	807
Long-term portion of finance lease receivables	—	—	171	—	—	171
Long-term portion of loan receivable(2)	—	—	25	—	—	25
Other investments(3)	—	—	—	15	1	16
Risk management assets
Current	—	151	—	—	—	151
Long-term	—	52	—	—	—	52
Financial liabilities
Bank overdraft	—	—	3	—	—	3
Accounts payable and accrued liabilities	—	—	797	—	—	797
Dividends payable	—	—	49	—	—	49
Risk management liabilities
Current	125	189	—	—	—	314
Long-term	80	194	—	—	—	274
Credit facilities, long-term debt and lease liabilities(4)	—	—	3,466	—	—	3,466
Exchangeable securities	—	—	744	—	—	744

(1)Includes cash equivalents of nil.

(2)Included in other assets. Refer to Note 22.

(3)Included in investments. Refer to Note 9.

(4)Includes current portion.

Carrying value as at Dec. 31, 2022	Derivatives used for hedging	Derivatives held for trading (FVTPL)	Amortized cost	Other financial assets (FVTPL)	Other financial assets (FVTOCI)	Total
Financial assets
Cash and cash equivalents(1)	—	—	1,134	—	—	1,134
Restricted cash	—	—	70	—	—	70
Trade and other receivables	—	—	1,589	—	—	1,589
Long-term portion of finance lease receivables	—	—	129	—	—	129
Long-term portion of loan receivable(2)	—	—	33	—	—	33
Other investments(3)	—	—	—	11	1	12
Risk management assets
Current	—	709	—	—	—	709
Long-term	—	161	—	—	—	161
Financial liabilities
Bank overdraft	—	—	16	—	—	16
Accounts payable and accrued liabilities	—	—	1,346	—	—	1,346
Dividends payable	—	—	68	—	—	68
Risk management liabilities
Current	271	858	—	—	—	1,129
Long-term	76	257	—	—	—	333
Credit facilities, long-term debt and lease liabilities(4)	—	—	3,653	—	—	3,653
Exchangeable securities	—	—	739	—	—	739

(1)Includes cash equivalents of nil.

(2)Included in other assets. Refer to Note 22.

(3)Included in investments. Refer to Note 9.

(4)Includes current portion.

Disclosure of financial liabilities

Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost.

Carrying value as at Dec. 31, 2023	Derivatives used for hedging	Derivatives held for trading (FVTPL)	Amortized cost	Other financial assets (FVTPL)	Other financial assets (FVOCI)	Total
Financial assets
Cash and cash equivalents(1)	—	—	348	—	—	348
Restricted cash	—	—	69	—	—	69
Trade and other receivables	—	—	807	—	—	807
Long-term portion of finance lease receivables	—	—	171	—	—	171
Long-term portion of loan receivable(2)	—	—	25	—	—	25
Other investments(3)	—	—	—	15	1	16
Risk management assets
Current	—	151	—	—	—	151
Long-term	—	52	—	—	—	52
Financial liabilities
Bank overdraft	—	—	3	—	—	3
Accounts payable and accrued liabilities	—	—	797	—	—	797
Dividends payable	—	—	49	—	—	49
Risk management liabilities
Current	125	189	—	—	—	314
Long-term	80	194	—	—	—	274
Credit facilities, long-term debt and lease liabilities(4)	—	—	3,466	—	—	3,466
Exchangeable securities	—	—	744	—	—	744

(1)Includes cash equivalents of nil.

(2)Included in other assets. Refer to Note 22.

(3)Included in investments. Refer to Note 9.

(4)Includes current portion.

Carrying value as at Dec. 31, 2022	Derivatives used for hedging	Derivatives held for trading (FVTPL)	Amortized cost	Other financial assets (FVTPL)	Other financial assets (FVTOCI)	Total
Financial assets
Cash and cash equivalents(1)	—	—	1,134	—	—	1,134
Restricted cash	—	—	70	—	—	70
Trade and other receivables	—	—	1,589	—	—	1,589
Long-term portion of finance lease receivables	—	—	129	—	—	129
Long-term portion of loan receivable(2)	—	—	33	—	—	33
Other investments(3)	—	—	—	11	1	12
Risk management assets
Current	—	709	—	—	—	709
Long-term	—	161	—	—	—	161
Financial liabilities
Bank overdraft	—	—	16	—	—	16
Accounts payable and accrued liabilities	—	—	1,346	—	—	1,346
Dividends payable	—	—	68	—	—	68
Risk management liabilities
Current	271	858	—	—	—	1,129
Long-term	76	257	—	—	—	333
Credit facilities, long-term debt and lease liabilities(4)	—	—	3,653	—	—	3,653
Exchangeable securities	—	—	739	—	—	739

(1)Includes cash equivalents of nil.

(2)Included in other assets. Refer to Note 22.

(3)Included in investments. Refer to Note 9.

(4)Includes current portion.

Disclosure of reconciliation of changes in loss allowance and explanation of changes in gross carrying amount for financial instruments

The following table summarizes 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, 2023 and 2022, respectively:

	Year ended Dec. 31, 2023			Year ended Dec. 31, 2022
	Hedge	Non-hedge	Total	Hedge	Non-hedge	Total
Opening balance	(347)	(435)	(782)	285	(126)	159
Changes attributable to:
Market price changes on existing contracts	(123)	(6)	(129)	(611)	(298)	(909)
Market price changes on new contracts	—	18	18	—	(124)	(124)
Contracts settled	256	269	525	(38)	118	80
Change in foreign exchange rates	9	7	16	17	(5)	12
Transfers out of Level III(1)	205	—	205	—	—	—
Net risk management assets (liabilities) at end of year	—	(147)	(147)	(347)	(435)	(782)
Additional Level III information:
Losses recognized in other comprehensive loss	(114)	—	(114)	(594)	—	(594)
Total gains (losses) included in earnings before income taxes	(256)	19	(237)	38	(427)	(389)
Unrealized gains (losses) included in earnings before income taxes relating to net assets (liabilities) held at year end	—	288	288	—	(309)	(309)

(1)The Company has a long-term fixed price power sale contract in the US for delivery of power. The fair value of this instrument was transferred out of Level III to Level II as at Dec. 31, 2023 as the forward price curve is now based on observable market prices for the remaining duration of the contract.

Disclosure for sensitivity ranges for the base fair value

As at	Dec. 31, 2023
Description	Valuation technique	Unobservable input	Reasonably possible change	Sensitivity(1)
Coal transportation – US	Numerical derivative valuation	Volatility	80% to 120%	+6
		Rail rate escalation	zero to 10%	-4
Full requirements – Eastern US	Scenario analysis	Volume	96% to 104%	+3
		Cost of supply	Decrease of $2.30 per MWh or increase of $2.40 per MWh	-3
Long-term wind energy sale – Eastern US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease or increase of US$6	+24
		Illiquid future REC prices (per unit)	Price decrease of US$12 or increase of US$8
		Wind discounts	0% decrease or 9% increase	-28
Long-term wind energy sale – Canada	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of C$81 or increase of C$5	+65
		Wind discounts	16% decrease or 5% increase	-23
Long-term wind energy sale - Central US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$1 or increase of US$2	+81
		Wind discounts	5% decrease or 2% increase	-36

(1)Sensitivity represents the total increase or decrease in recognized fair value that could arise from the use of the reasonably possible changes of all unobservable inputs.

As at	Dec. 31, 2022
Description	Valuation technique	Unobservable input	Reasonably possible change	Sensitivity(1)
Coal transportation – US	Numerical derivative valuation	Illiquid future power prices (per MWh)	Price decrease of US$5 or increase of US$55	+14
		Volatility	80% to 120%
		Rail rate escalation	zero to 10%	-13
Full requirements - Eastern US	Scenario analysis	Volume	96% to 104%	+3
		Cost of supply	Decrease of US$0.50 per MWh or increase of US$3.30 per MWh	-21
Long-term wind energy sale – Eastern US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease or increase of US$6	+22
		Illiquid future REC prices (per unit)	Price decrease or increase of US$2
		Wind discounts	0% decrease or 5% increase	-18
Long-term wind energy sale – Canada	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of C$85 or increase of C$5	+47
		Wind discounts	28% decrease or 5% increase	-25
Long-term wind energy sale – Central US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease or increase of US$2	+74
		Wind discounts	2% decrease or 5% increase	-28
Long-term power sale – US	Long-term price forecast	Illiquid future power prices (per MWh)	Price decrease of US$5 or increase of US$55	+15
				-163

(1)Sensitivity represents the total increase or decrease in recognized fair value that would arise from the use of the reasonably possible changes of all unobservable inputs.

Disclosure of fair value measurement of 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, 2023	—	718	—	718	744
Long-term debt — Dec. 31, 2023	—	3,104	—	3,104	3,323
Loan receivable — Dec. 31, 2023	—	26	—	26	26
Exchangeable securities — Dec. 31, 2022	—	685	—	685	739
Long-term debt — Dec. 31, 2022	—	3,200	—	3,200	3,518
Loan receivable — Dec. 31, 2022	—	37	—	37	37

(1)Includes current portion.

Disclosure of difference between transaction price and the fair value determined using valuation model

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:

As at Dec. 31	2023	2022	2021
Unamortized net loss at beginning of year	(213)	(131)	(33)
New inception gains (losses)(1)	47	(37)	(79)
Change resulting from amended contract(2)	190	—	—
Change in foreign exchange rates	6	(10)	—
Amortization recorded in net earnings during the year	(27)	(35)	(19)
Unamortized net gain (loss) at end of year	3	(213)	(131)

(1)During 2023, the Company entered into long-term fixed price power sale contracts with certain of its US customers and as a result recognized day one inception gains that are based on the forward price curve at the inception of the contract. During 2022, the Company entered into a PPA for the Horizon Hill wind project (2021 – PPAs for the White Rock wind projects) that resulted in new inception losses 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 PPA.

(2)During 2023, the Company entered into certain contract amendments related to the Horizon Hill and White Rock wind projects. These amendments were mainly specific to obtaining price increases over the contract term. Accordingly, certain inception loss calibration adjustments were recognized within the risk management liability.

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Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Disclosure of derivative Financial Instruments

Net Risk Management Assets and Liabilities

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

As at Dec. 31, 2023
	Cash flow hedges	Not designated as a hedge	Total
Commodity risk management
Current	(125)	(53)	(178)
Long-term	(80)	(146)	(226)
Net commodity risk management liabilities	(205)	(199)	(404)
Other
Current	—	15	15
Long-term	—	4	4
Net other risk management assets	—	19	19
Total net risk management liabilities	(205)	(180)	(385)

As at Dec. 31, 2022
	Cash flow hedges	Not designated as a hedge	Total
Commodity risk management
Current	(271)	(143)	(414)
Long-term	(76)	(96)	(172)
Net commodity risk management liabilities	(347)	(239)	(586)
Other
Current	—	(6)	(6)
Long-term	—	—	—
Net other risk management liabilities	—	(6)	(6)
Total net risk management liabilities	(347)	(245)	(592)

The Company’s outstanding commodity derivative instruments not designated as hedging instruments are as follows:

As at Dec. 31	2023		2022
Type (thousands)	Notional amount sold	Notional amount purchased	Notional amount sold	Notional amount purchased
Electricity (MWh)	54,043	12,628	55,821	13,934
Natural gas (GJ)	50,949	209,348	23,464	162,384
Transmission (MWh)	—	856	—	1,643
Emissions (MWh)	212	804	274	2,297
Emissions (tonnes)	4,450	5,125	300	300
Coal (tonnes)	—	5,172	—	7,746

As at Dec. 31	2023			2022
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
AUD125	CAD113	(1)	2024-2027	AUD183	CAD168	(1)	2023-2026
USD828	CAD1,113	19	2024-2027	USD573	CAD761	(12)	2023-2025
USD100	AUD152	5	2024	USD66	AUD102	4	2023
Foreign exchange forward contracts – foreign-denominated debt
CAD190	USD140	(4)	2024	CAD159	USD120	3	2023

Disclosure of net 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, 2023	Gross amounts of recognized financial assets (liabilities)	Amounts set off	Net amounts included on the statement of financial position	Master netting arrangements(1)	Net amount
Current risk management assets	528	(355)	173	(7)	166
Long-term risk management assets	161	(91)	70	(2)	68
Current risk management liabilities	(504)	355	(149)	7	(142)
Long-term risk management liabilities	(145)	91	(54)	2	(52)
Trade and other receivables(2)	789	(646)	143	(11)	132
Accounts payable and accrued  liabilities(2)	(760)	646	(114)	11	(103)

As at Dec. 31, 2022	Gross amounts of recognized financial assets (liabilities)	Amounts set off	Net amounts included on the statement of financial position	Master netting arrangements(1)	Net amount
Current risk management assets	1,602	(883)	719	(62)	657
Long-term risk management assets	204	(43)	161	(7)	154
Current risk management liabilities	(1,953)	883	(1,070)	62	(1,008)
Long-term risk management liabilities	(449)	43	(406)	7	(399)
Trade and other receivables(2)	1,330	(934)	396	(176)	220
Accounts payable and accrued liabilities(2)	(1,344)	934	(410)	176	(234)

(1)Amounts not set off in the Consolidated Statements of Financial Position.

(2)The trade and other receivables and accounts payable and accrued liabilities include amounts related to collateral provided and held. Refer to Note 15(F) below for further details.

Disclosure 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 cents (2022 – three cents, 2021 – three cents) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter.

Year ended Dec. 31	2023		2022		2021
Currency	Net earnings decrease(1)	OCI gain(1)(2)	Net earnings increase (decrease)(1)	OCI gain(1)(2)	Net earnings decrease(1)	OCI gain(1)(2)
USD	(11)	—	(12)	—	(13)	1
AUD	(3)	—	(2)	—	1	—
Total	(14)	—	(14)	—	(12)	1

(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.

Disclosure of credit Risk

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, 2023:

	Investment grade  (per cent)	Non-investment grade  (per cent)	Total  (per cent)	Total amount
Trade and other receivables(1)	95	5	100	807
Long-term finance lease receivable	100	—	100	171
Risk management assets(1)	75	25	100	203
Loans receivable(2)	—	100	100	26
Total				1,207

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

(2)Includes $26 million loans receivable included within other assets with counterparties that have no external credit rating.

Disclosure of maturity Analysis of Financial Liabilities

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

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Bank overdraft	3	—	—	—	—	—	3
Accounts payable and accrued liabilities	797	—	—	—	—	—	797
Long-term debt(1)
Credit facilities(1)	400	—	—	—	—	—	400
Debentures	—	—	—	—	—	251	251
Senior notes	—	—	—	—	—	924	924
Non-recourse – Hydro	—	—	—	—	—	39	39
Non-recourse – Wind & Solar	66	69	67	70	75	289	636
Non-recourse and other – Gas	46	58	61	65	66	707	1,003
Tax equity financing	14	15	15	18	21	27	110
Exchangeable securities(2)	—	—	—	—	—	750	750
Commodity risk management liabilities	169	123	15	12	12	73	404
Other risk management assets	(16)	(3)	—	—	—	—	(19)
Lease liabilities(3)	4	4	4	4	4	123	143
Interest on long-term debt and lease liabilities(4)	186	167	158	151	143	711	1,516
Interest on exchangeable securities(2)(4)	53	53	53	53	53	13	278
Dividends payable	49	—	—	—	—	—	49
Total	1,771	486	373	373	374	3,907	7,284

(1)Excludes impact of hedge accounting and derivatives.

(2)Cash payment could occur after Dec. 31, 2028 if exchangeable securities are not exchanged by Brookfield Renewable Partners or its affiliates (collectively "Brookfield"). At Brookfield's option, the exchangeable securities can be exchanged, at the earliest, on Jan. 1, 2025 (Note 25).

(3)Lease liabilities exclude a lease incentive of $12 million expected to be received in 2024, which is recognized in trade and other receivables.

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

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
	2024	2025	2026	2027	2028	2029
Cash flow hedges
Commodity derivative instruments
Electricity
Notional amount (thousands of MWh)	3,338	2,628	—	—	—	—
Average price ($ per MWh)	78.18	80.13	—	—	—	—

Disclosure of hedging Instruments

The impact of the hedging instruments on the statement of financial position is as follows:

As at Dec. 31, 2023	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(1)	5,966	(205)	Risk management liabilities	(114)
Foreign currency risk
Net investment hedges
Foreign-denominated debt	USD370	CAD489	Credit facilities, long-term debt and lease liabilities	—

(1)In thousands of MWh.

As at Dec. 31, 2022	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(1)	9,295	(347)	Risk management liabilities	(594)
Foreign currency risk
Net investment hedges
Foreign-denominated debt	USD370	CAD502	Credit facilities, long-term debt and lease liabilities	—

(1)In thousands of MWh.

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

As at Dec. 31	2023		2022
	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	(114)	(129)	(594)	(279)
	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	—	(36)	—	(39)

(1)Net of tax. Included in AOCI.

Disclosure of effect of Hedges

The impact of designated cash flow hedges on OCI and net earnings is:

Year ended Dec. 31, 2023
		Effective portion		Ineffective portion
Derivatives in cash flow  hedging relationships	Pre-tax gain recognized in OCI	Location of gain 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	51	Revenue	83	Revenue	—
Forward starting interest rate swaps	—	Interest expense	(8)	Interest expense	—
OCI impact	51	OCI impact	75	Net earnings impact	—

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, 2022
		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	(747)	Revenue	124	Revenue	—
Forward starting interest rate swaps	53	Interest expense	2	Interest expense	—
OCI impact	(694)	OCI impact	126	Net earnings impact	—

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 reclassified from 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	—

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Inventory (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of inventories [Abstract]

Disclosure Of The Components Of Inventories

The components of inventory are as follows:

As at Dec. 31	2023	2022
Parts, materials and supplies	72	83
Coal	38	43
Emission credits	45	27
Natural gas	2	4
Total	157	157

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Finance Lease Receivables (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of maturity analysis of finance lease payments receivable [abstract]

Disclosure of maturity analysis of finance lease payments receivable

Amounts receivable under the Company’s finance leases include the Northern Goldfields solar facilities (2023), the Poplar Creek cogeneration facility (2023 and 2022) and the Southern Cross Energy facilities (2022), and are as follows:

As at Dec. 31	2023		2022
	Minimum lease receipts	Present value of minimum lease receipts	Minimum lease receipts	Present value of minimum lease receipts
Within one year	28	28	62	55
Second to fifth years inclusive	112	98	81	75
More than five years	117	64	60	51
	257	190	203	181
Less: unearned finance lease income	67	—	22	—
Total finance lease receivables	190	190	181	181
Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease receivables (Note 13)	19		52
Long-term portion of finance lease receivables	171		129
Total finance lease receivables	190		181

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Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of detailed information about property, plant and equipment [abstract]

Disclosure of detailed information about property, plant and equipment

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

Hydro generation	1-49 years
Wind and Solar generation	1-30 years
Gas generation	1-34 years
Energy Transition	1-9 years
Capital spares and other	1-49 years

The Company recognized the following asset impairment charges (reversals):

Year ended Dec. 31	2023	2022	2021
Segments:
Hydro	(10)	21	5
Wind and Solar	(4)	43	12
Gas		—	5
Energy Transition	—	—	540
Corporate	—	(2)	27
Changes in decommissioning and restoration provisions on retired assets(1)	(34)	(53)	32
Intangible asset impairment charges - coal rights	—	—	17
Project development costs	—	—	10
Asset impairment charges (reversals)	(48)	9	648

(1)Changes relate to changes in discount rates and cash flow revisions on retired assets in 2023 and 2022 and cash flow revisions on retired assets in 2021. Refer to Note 23 for further details.

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

	Assets under construction	Land	Hydro	Wind and Solar	Gas generation	Energy Transition	Capital spares and other(1)	Total
Cost
As at Dec. 31, 2021	184	96	867	3,276	4,087	4,513	366	13,389
Additions(2)	891	—	—	—	—	—	6	897
Additions from development projects	17	—	—	—	—	—	12	29
Disposals	—	(3)	—	—	(1)	(216)	—	(220)
Impairment (charges) reversals (Note 7)	2	—	(21)	(43)	—	—	—	(62)
Changes to decommissioning and restoration costs (Note 23)	—	—	(15)	(59)	(12)	10	2	(74)
Retirement of assets	—	—	(9)	(9)	(12)	(7)	(2)	(39)
Change in foreign exchange rates	13	—	—	45	(4)	97	2	153
Transfers of assets(3)	(144)	—	18	23	472	(423)	(7)	(61)
As at Dec. 31, 2022	963	93	840	3,233	4,530	3,974	379	14,012
Additions(2)	869	—	—	—	—	—	6	875
Disposals	—	(3)	—	—	—	(30)	—	(33)
Impairment reversals (Note 7)	—	—	10	4	—	—	—	14
Changes to decommissioning and restoration costs (Note 23)	—	—	3	14	(22)	3	(1)	(3)
Retirement of assets	—	—	(7)	(18)	(124)	(7)	(108)	(264)
Change in foreign exchange rates	(26)	—	—	(18)	(7)	(42)	(1)	(94)
Transfers of assets(3)	(572)	—	38	439	50	16	31	2
Transfers to finance lease receivable (Note 17)	—	—	—	(61)	(4)	—	—	(65)
As at Dec. 31, 2023	1,234	90	884	3,593	4,423	3,914	306	14,444
Accumulated depreciation
As at Dec. 31, 2021	—	—	468	1,093	2,178	4,150	180	8,069
Depreciation	—	—	21	130	308	63	16	538
Retirement of assets	—	—	(8)	(6)	(10)	(7)	(2)	(33)
Disposals	—	—	—	—	(1)	(211)	—	(212)
Change in foreign exchange rates	—	—	—	11	2	89	—	102
Transfers of assets(3)	—	—	(3)	—	335	(340)	—	(8)
As at Dec. 31, 2022	—	—	478	1,228	2,812	3,744	194	8,456
Depreciation	—	—	25	129	342	73	16	585
Retirement of assets	—	—	(4)	(15)	(101)	(7)	(108)	(235)
Disposals	—	—	—	—	—	(30)	—	(30)
Change in foreign exchange rates	—	—	—	(5)	(3)	(39)	—	(47)
Transfers in (out) of PP&E(3)	—	—	—	—	(1)	2	—	1
As at Dec. 31, 2023	—	—	499	1,337	3,049	3,743	102	8,730
Carrying amount
As at Dec. 31, 2021	184	96	399	2,183	1,909	363	186	5,320
As at Dec. 31, 2022	963	93	362	2,005	1,718	230	185	5,556
As at Dec. 31, 2023	1,234	90	385	2,256	1,374	171	204	5,714

(1)Includes major spare parts and standby equipment available, but not in service.

(2)In 2023, the Company capitalized $57 million (2022 – $16 million) of interest to PP&E in at a weighted average rate of 6.3 per cent (2022 – 6.0 per cent).

(3)Includes transfers of assets upon commissioning to assets in service and other movements.

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Right of Use Assets (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of leases [Abstract]

Disclosure of quantitative information about right-of-use assets

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

	Land	Buildings	Vehicles	Equipment	Total
As at Dec. 31, 2021	68	20	1	6	95
Additions	36	—	1	3	40
Depreciation	(4)	(5)	—	(2)	(11)
Change in foreign exchange rates	2	—	—	—	2
As at Dec. 31, 2022	102	15	2	7	126
Additions	2	2	1	—	5
Depreciation	(5)	(5)	—	(2)	(12)
Change in foreign exchange rates	(2)	—	—	—	(2)
As at Dec. 31, 2023	97	12	3	5	117

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Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of detailed information about intangible assets [abstract]

Disclosure of reconciliation of changes in 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, 2021	269	422	4	132	827
Additions	—	—	31	—	31
Change in foreign exchange rates	3	3	1	—	7
Transfers	—	12	(9)	—	3
As at Dec. 31, 2022	272	437	27	132	868
Additions	—	—	13	—	13
Asset impairment charges	—	(1)	—	—	(1)
Change in foreign exchange rates	(2)	(2)	(1)	—	(5)
Transfers	—	12	(12)	—	—
As at Dec. 31, 2023	270	446	27	132	875
Accumulated amortization
As at Dec. 31, 2021	140	299	—	132	571
Amortization	17	26	—	—	43
Change in foreign exchange rates	1	1	—	—	2
As at Dec. 31, 2022	158	326	—	132	616
Amortization	17	21	—	—	38
Change in foreign exchange rates	(1)	(1)	—	—	(2)
As at Dec. 31, 2023	174	346	—	132	652
Carrying amount
As at Dec. 31, 2021	129	123	4	—	256
As at Dec. 31, 2022	114	111	27	—	252
As at Dec. 31, 2023	96	100	27	—	223

Goodwill acquired through business combinations has been allocated to groups of CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments is as follows:

As at Dec. 31	2023	2022
Hydro	258	258
Wind and Solar	176	176
Energy Marketing	30	30
Total goodwill	464	464

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of detailed information about goodwill [Abstract]

Disclosure of detailed information about goodwill

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, 2021	269	422	4	132	827
Additions	—	—	31	—	31
Change in foreign exchange rates	3	3	1	—	7
Transfers	—	12	(9)	—	3
As at Dec. 31, 2022	272	437	27	132	868
Additions	—	—	13	—	13
Asset impairment charges	—	(1)	—	—	(1)
Change in foreign exchange rates	(2)	(2)	(1)	—	(5)
Transfers	—	12	(12)	—	—
As at Dec. 31, 2023	270	446	27	132	875
Accumulated amortization
As at Dec. 31, 2021	140	299	—	132	571
Amortization	17	26	—	—	43
Change in foreign exchange rates	1	1	—	—	2
As at Dec. 31, 2022	158	326	—	132	616
Amortization	17	21	—	—	38
Change in foreign exchange rates	(1)	(1)	—	—	(2)
As at Dec. 31, 2023	174	346	—	132	652
Carrying amount
As at Dec. 31, 2021	129	123	4	—	256
As at Dec. 31, 2022	114	111	27	—	252
As at Dec. 31, 2023	96	100	27	—	223

Goodwill acquired through business combinations has been allocated to groups of CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments is as follows:

As at Dec. 31	2023	2022
Hydro	258	258
Wind and Solar	176	176
Energy Marketing	30	30
Total goodwill	464	464

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Other Assets (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of financial assets [abstract]

Disclosure of components in other assets

The components of other assets are as follows:

As at Dec. 31	2023	2022
South Hedland prepaid transmission access and distribution costs	60	61
Long-term prepaids and other assets	41	40
Project development costs	35	10
Loans receivable	26	37
Transmission infrastructure	18	16
Total Other assets	180	164
Included in the Consolidated Statements of Financial Position as:
Total current other assets (Note 13)	1	4
Total long-term other assets	179	160
Total Other assets	180	164

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Decommissioning and Other Provisions (Tables)

12 Months Ended

Dec. 31, 2023

Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]

Disclosure of change in decommissioning and other provision balances

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 incurred	1	23	24
Liabilities settled	(35)	(12)	(47)
Accretion	49	—	49
Disposals	(5)	—	(5)
Revisions in estimated cash flows	95	5	100
Revisions in discount rates	(225)	—	(225)
Reversals	—	(9)	(9)
Change in foreign exchange rates	15	—	15
Balance, Dec. 31, 2022	688	41	729
Liabilities incurred	1	4	5
Liabilities settled	(37)	(13)	(50)
Accretion (Note 10)	47	1	48
Revisions in estimated cash flows	(89)	—	(89)
Revisions in discount rates	52	—	52
Change in foreign exchange rates	(6)	—	(6)
Balance, Dec. 31, 2023	656	33	689

Included in the Consolidated Statements of Financial Position as:
As at	Dec. 31, 2023	Dec. 31, 2022
Current portion	35	70
Non-current portion	654	659
Total Decommissioning and other provisions	689	729

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Credit Facilities, Long-Term Debt and Lease Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Disclosure of borrowings outstanding

The amounts outstanding are as follows:

As at Dec. 31				2023				2022
	Segment	Maturity	Currency	Carrying value	Face value	Interest(1)		Carrying value	Face value	Interest
Credit facilities
Committed syndicated bank facility(2)	Corporate	2027	CAD	—	—	—		32	33	4.7	%
Term Facility	Corporate	2024	CAD	397	400	7.4	%	396	400	6.5	%
Debentures
7.3% Medium term notes	Corporate	2029	CAD	110	110	7.3	%	110	110	7.3	%
6.9% Medium term notes	Corporate	2030	CAD	141	141	6.9	%	141	141	6.9	%
Senior notes(3)
7.8% Senior notes(4)	Corporate	2029	USD	520	528	7.8	%	533	542	7.8	%
6.5% Senior notes	Corporate	2040	USD	391	396	6.5	%	401	407	6.5	%
Non-recourse
Melancthon Wolfe Wind LP bond	Wind & Solar	2028	CAD	168	169	3.8	%	202	203	3.8	%
New Richmond Wind LP bond	Wind & Solar	2032	CAD	103	104	4.0	%	112	113	4.0	%
Kent Hills Wind LP bond	Wind & Solar	2033	CAD	193	196	4.5	%	206	209	4.5	%
Windrise Wind LP bond	Wind & Solar	2041	CAD	164	167	3.4	%	170	173	3.4	%
Pingston bond	Hydro	2043	CAD	39	39	6.2	%	45	45	3.0	%
TAPC Holdings LP bond (Poplar Creek)	Gas	2030	CAD	85	86	9.4	%	94	95	8.9	%
TEC Hedland PTY Ltd bond(5)	Gas	2042	AUD	691	699	4.1	%	711	720	4.1	%
TransAlta OCP LP bond	Gas	2030	CAD	217	218	4.5	%	241	242	4.5	%
Tax equity financing
Big Level & Antrim(6)	Wind & Solar	2029	USD	91	97	6.6	%	102	108	6.6	%
Lakeswind(7)	Wind & Solar	2029	USD	10	10	10.5	%	15	15	10.5	%
North Carolina Solar(8)	Wind & Solar	2028	USD	3	3	7.3	%	6	6	7.3	%
Other(9)	Corporate		CAD	—	—	—		1	1	5.9	%
Total long-term debt				3,323	3,363			3,518	3,563
Lease liabilities(10)				143				135
Total long-term debt and lease liabilities				3,466				3,653
Less: current portion of long-term debt				(526)				(170)
Less: current portion of lease liabilities				(6)				(8)
Total current long-term debt and lease liabilities				(532)				(178)
Total non-current credit facilities, long-term debt and lease liabilities				2,934				3,475

(1)Interest rate reflects the stipulated rate or the average rate weighted by principal amounts outstanding and 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, 2023 – US$700 million (2022 – US$700 million).

(4)The effective interest rate for the senior notes is 5.98 per cent after the effects of gains realized on settled interest rate hedging instruments.

(5)AU face value at Dec. 31, 2023 – AU$773 million (2022 – AU$786 million).

(6)US face value at Dec. 31, 2023 – US$73 million (2022 – US$79 million).

(7)US face value at Dec. 31, 2023 – US$8 million (2022 – US$11 million).

(8)US face value at Dec. 31, 2023 – US$2 million (2022 – US$5 million).

(9)Other debt consisted of an unsecured commercial loan obligation that matured and was repaid in 2023.

(10)At Dec. 31, 2023, lease liabilities exclude a lease incentive of $12 million expected to be received in 2024, which is recognized in trade and other receivables.

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

As at Dec. 31, 2023		Utilized
Credit Facilities	Facility size	Outstanding letters of credit(1)	Cash drawings	Available capacity	Maturity date
Committed
TransAlta syndicated credit facility	1,950	417	—	1,533	Q2 2027
TransAlta bilateral credit facilities	240	178	—	62	Q2 2025
TransAlta Term Facility	400	—	400	—	Q3 2024
Total Committed	2,590	595	400	1,595
Non-Committed
TransAlta demand facilities	400	187	—	213	N/A
Total Non-Committed	400	187	—	213

(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. Letters of credit drawn against the non-committed facilities reduce the available capacity under the committed syndicated credit facilities. At Dec. 31, 2023, TransAlta provided cash collateral of $145 million.

Disclosure of principal repayments

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Principal repayments(1)	526	142	143	153	162	2,237	3,363
Lease liabilities(2)	4	4	4	4	4	123	143

(1)Excludes impact of hedge accounting and derivatives.

(2)Lease liabilities exclude a lease incentive of $12 million, expected to be received in 2024, which is recognized in trade and other receivables.

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Exchangeable Securities (Tables)

12 Months Ended

Dec. 31, 2023

Exchangeable Securities [Abstract]

Disclosure of borrowing costs

Exchangeable Securities

As at	Dec. 31, 2023				Dec. 31, 2022
	Carrying value	Face value	Interest		Carrying value	Face value	Interest
Exchangeable debentures – due May 1, 2039(1)	344	350	7	%	339	350	7	%
Exchangeable preferred shares(2)	400	400	7	%	400	400	7	%
Total exchangeable securities	744	750			739	750

(1)Seven per cent unsecured subordinated debentures due May 1, 2039.

(2)Redeemable, retractable first preferred shares (Series I). Exchangeable preferred share dividends are reported as interest expense.

Disclosure of sensitivity analysis of fair value measurement to changes in unobservable inputs, liabilities

As at	Dec. 31, 2023		Dec. 31, 2022
Description	Base fair value	Sensitivity	Base fair value	Sensitivity
Option to exchange – embedded derivative	—	+nil -25	—	+nil -25

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Defined Benefit Obligation and Other Long-Term Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Disclosure of components of defined benefit obligations and other long-term liabilities

The components of defined benefit obligation and other long-term liabilities are as follows:

As at Dec. 31	2023	2022
Defined benefit obligation (Note 31)	155	150
Retail power contract liability	83	126
Other	13	18
Total	251	294

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Common Shares (Tables)

12 Months Ended

Dec. 31, 2023

Share Capital, Reserves And Other Equity Interest [Abstract]

Disclosure of issued and outstanding

TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.

As at Dec. 31	2023		2022
	Common shares  (millions)	Amount	Common shares (millions)	Amount
Issued and outstanding, beginning of period	268.1	2,863	271.0	2,901
Purchased and cancelled under the NCIB	(7.5)	(80)	(4.3)	(46)
Share-based payment plans	0.8	6	0.9	5
Stock options exercised	0.7	5	0.5	3
Issued for acquisition of TransAlta Renewables(1) (Note 4)	46.5	510	—	—
Issued and outstanding, end of year, prior to ASPP	308.6	3,304	268.1	2,863
Provision for repurchase of common shares under ASPP	(1.7)	(19)	—	—
Issued and outstanding, end of year	306.9	3,285	268.1	2,863

(1)Net of $4 million of transaction costs.

The effects of the Company's purchase and cancellation of common shares during the period are as follows:

For the year ended Dec. 31	2023	2022
Total shares purchased(1)	7,537,500	4,342,300
Average purchase price per share	11.49	12.48
Total cost (millions)	87	54
Book value of shares cancelled	80	46
Amount recorded in deficit	(7)	(8)

(1)At Dec. 31, 2023, includes 181,800 (2022 - 164,300) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. As a result, $2 million (2022 - $2 million) was paid subsequent to the year end.

All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares.

As at Dec. 31	2023		2022
Series(1)	Number of shares  (millions)	Amount	Number of shares (millions)	Amount
Series A	9.6	235	9.6	235
Series B	2.4	58	2.4	58
Series C	10.0	243	10.0	243
Series D	1.0	26	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)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

Disclosure of earnings per share

Year ended Dec. 31	2023	2022	2021
Net earnings (loss) attributable to common shareholders	644	4	(576)
Basic and diluted weighted average number of common shares outstanding (millions)	276	271	271
Net earnings (loss) per share attributable to common shareholders, basic and diluted	2.33	0.01	(2.13)

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Preferred Shares (Tables)

12 Months Ended

Dec. 31, 2023

Share Capital, Reserves And Other Equity Interest [Abstract]

Disclosure of issued and outstanding

TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.

As at Dec. 31	2023		2022
	Common shares  (millions)	Amount	Common shares (millions)	Amount
Issued and outstanding, beginning of period	268.1	2,863	271.0	2,901
Purchased and cancelled under the NCIB	(7.5)	(80)	(4.3)	(46)
Share-based payment plans	0.8	6	0.9	5
Stock options exercised	0.7	5	0.5	3
Issued for acquisition of TransAlta Renewables(1) (Note 4)	46.5	510	—	—
Issued and outstanding, end of year, prior to ASPP	308.6	3,304	268.1	2,863
Provision for repurchase of common shares under ASPP	(1.7)	(19)	—	—
Issued and outstanding, end of year	306.9	3,285	268.1	2,863

(1)Net of $4 million of transaction costs.

The effects of the Company's purchase and cancellation of common shares during the period are as follows:

For the year ended Dec. 31	2023	2022
Total shares purchased(1)	7,537,500	4,342,300
Average purchase price per share	11.49	12.48
Total cost (millions)	87	54
Book value of shares cancelled	80	46
Amount recorded in deficit	(7)	(8)

(1)At Dec. 31, 2023, includes 181,800 (2022 - 164,300) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. As a result, $2 million (2022 - $2 million) was paid subsequent to the year end.

All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares.

As at Dec. 31	2023		2022
Series(1)	Number of shares  (millions)	Amount	Number of shares (millions)	Amount
Series A	9.6	235	9.6	235
Series B	2.4	58	2.4	58
Series C	10.0	243	10.0	243
Series D	1.0	26	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)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

Disclosure of characteristics specific to preferred share series

Characteristics specific to each first preferred share series as at Dec. 31, 2023, are as follows:

Series(1)	Rate during term	Annual dividend rate per share ($)(2)	Next conversion date	Rate spread over benchmark  (per cent)	Convertible to Series
A	Fixed	0.71924	March 31, 2026	2.03	B
B	Floating	1.718910	March 31, 2026	2.03	A
C	Fixed	1.46352	June 30, 2027	3.10	D
D	Floating	1.98695	June 30, 2027	3.10	C
E	Fixed	1.72352	Sept. 30, 2027	3.65	F
G	Fixed	1.24700	Sept. 30, 2024	3.80	H

(1)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

(2)The annual dividend rate per share represents dividends declared in 2023.

Disclosure of dividends declared on preference shares

The following table summarizes the preferred share dividends declared in 2023 and 2022:

	Total dividends declared
Series	2023(1)	2022(1)
A	7	7
B(2)	4	3
C	15	14
D(3)	2	1
E	15	13
G	8	8
Total for the year	51	46

(1)No dividends were declared in the first quarter of the year as the quarterly dividend related to the period covering the first quarter was declared in December of the prior year.

(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.

(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.

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Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of analysis of other comprehensive income by item [abstract]

Disclosure of changes in accumulated other comprehensive loss

The components of and changes in, accumulated other comprehensive loss are as follows:

	2023	2022
Currency translation adjustment
Opening balance, Jan. 1	(39)	(35)
(Losses) gains on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax	(6)	21
Gains (losses) on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax(1)	9	(25)
Balance, Dec. 31	(36)	(39)
Cash flow hedges
Opening balance, Jan. 1	(228)	228
Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax(2)	99	(456)
Balance, Dec. 31	(129)	(228)
Employee future benefits
Opening balance, Jan. 1	8	(29)
Net actuarial gains on defined benefit plans, net of tax(3)	(5)	37
Balance, Dec. 31	3	8
Other
Opening balance, Jan. 1	37	(18)
Change in ownership of TransAlta Renewables	(64)	—
Intercompany and third-party investments at FVTOCI	25	55
Balance, Dec. 31	(2)	37
Accumulated other comprehensive loss	(164)	(222)

(1)Net of income tax expense of $1 million for the year ended Dec. 31, 2023 (Dec. 31, 2022 – $3 million recovery).

(2)Net of income tax expense of $27 million for the year ended Dec. 31, 2023 (Dec. 31, 2022 – $112 million recovery).

(3)Net of income tax recovery of $1 million for the year ended Dec. 31, 2023 (Dec. 31, 2022 – $12 million).

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Share-Based Payment Plans (Tables)

12 Months Ended

Dec. 31, 2023

Share-based payment arrangements [Abstract]

Disclosure of range of exercise prices of outstanding share options

The total options outstanding and exercisable under the Stock Option Plan at Dec. 31, 2023, 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)
5.00-12.00	2.5	3.60	9.17

(1)Options currently exercisable as at Dec. 31, 2023

Disclosure of number and weighted average remaining contractual life of outstanding share options

The total options outstanding and exercisable under the Stock Option Plan at Dec. 31, 2023, 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)
5.00-12.00	2.5	3.60	9.17

(1)Options currently exercisable as at Dec. 31, 2023.

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Employee Future Benefits (Tables)

12 Months Ended

Dec. 31, 2023

Employee Benefits [Abstract]

Disclosure of 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, 2023	Registered	Supplemental	Other	Total
Current service cost	1	1	—	2
Administration expenses	1	—	—	1
Interest cost on defined benefit obligation	16	4	1	21
Interest on plan assets	(13)	(1)	—	(14)
Defined benefit expense	5	4	1	10
Defined contribution expense	11	—	—	11
Net expense	16	4	1	21
Year ended Dec. 31, 2022	Registered	Supplemental	Other	Total
Current service cost	1	1	—	2
Administration expenses	1	—	—	1
Interest cost on defined benefit obligation	13	3	—	16
Interest on plan assets	(9)	—	—	(9)
Defined benefit expense	6	4	—	10
Defined contribution expense	11	—	—	11
Net expense	17	4	—	21

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

The expected employer contributions for 2024 for the defined benefit pension and other post-employment benefit plans are as follows:

	Registered	Supplemental	Other	Total
Expected employer contributions	3	5	1	9

Disclosure of defined benefit obligation

The status of the defined benefit pension and other post-employment benefit plans is as follows:

Year ended Dec. 31, 2023	Registered	Supplemental	Other	Total
Fair value of plan assets	269	15	—	284
Present value of defined benefit obligation	(340)	(89)	(17)	(446)
Funded status – plan deficit	(71)	(74)	(17)	(162)
Amount recognized in the Consolidated Financial Statements:
Accrued current liabilities	(1)	(5)	(1)	(7)
Other long-term liabilities	(70)	(69)	(16)	(155)
Total amount recognized	(71)	(74)	(17)	(162)

Year ended Dec. 31, 2022	Registered	Supplemental	Other	Total
Fair value of plan assets	274	15	—	289
Present value of defined benefit obligation	(345)	(85)	(17)	(447)
Funded status – plan deficit	(71)	(70)	(17)	(158)
Amount recognized in the Consolidated Financial Statements:
Accrued current liabilities	(1)	(6)	(1)	(8)
Other long-term liabilities	(70)	(64)	(16)	(150)
Total amount recognized	(71)	(70)	(17)	(158)

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, 2021	469	101	23	593
Current service cost	1	1	—	2
Interest cost	13	3	—	16
Benefits paid	(57)	(5)	1	(61)
Actuarial gain arising from financial assumptions	(83)	(22)	(5)	(110)
Actuarial gain arising from experience adjustments	1	7	(2)	6
Change in foreign exchange rates	1	—	—	1
Present value of defined benefit obligation as at Dec. 31, 2022	345	85	17	447
Current service cost	1	1	—	2
Interest cost	16	4	1	21
Benefits paid	(36)	(6)	(2)	(44)
Actuarial loss arising from demographic assumptions	1	—	—	1
Actuarial loss arising from financial assumptions	12	4	1	17
Actuarial loss arising from experience adjustments	2	1	—	3
Change in foreign exchange rates	(1)	—	—	(1)
Present value of defined benefit obligation as at Dec. 31, 2023	340	89	17	446

(1)The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2023, is 10.4 years.

Disclosure of 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, 2021	339	14	—	353
Interest on plan assets	9	—	—	9
Net loss on plan assets	(55)	—	—	(55)
Contributions(1)	38	6	—	44
Benefits paid	(57)	(5)	—	(62)
Administration expenses	(1)	—	—	(1)
Change in foreign exchange rates	1	—	—	1
As at Dec. 31, 2022	274	15	—	289
Interest on plan assets	13	1	—	14
Net return on plan assets	15	(1)	—	14
Contributions(2)	5	6	2	13
Benefits paid	(36)	(6)	(2)	(44)
Administration expenses	(1)	—	—	(1)
Change in foreign exchange rates	(1)	—	—	(1)
As at Dec. 31, 2023	269	15	—	284

(1)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.

(2)The Company made a voluntary contribution of $4 million to further improve the funded status of the US Defined Benefit Pension Plan for the Centralia thermal facility.

The fair value of the Company’s defined benefit plan assets by major category is as follows:

As at Dec. 31, 2023	Level I	Level II	Level III	Total
Equity securities
Canadian	—	12	—	12
US	—	6	—	6
International	—	86	—	86
Private	—	—	1	1
Bonds
A - AAA	—	30	62	92
BBB	1	5	10	16
Below BBB	—	—	4	4
Loans(1)	—	2	—	2
Alternative funds(2)	—	—	44	44
Money market and cash and cash equivalents	2	19	—	21
Total	3	160	121	284

(1)Includes A credit rating loans of $1 million.

(2)Alternative funds include investments in infrastructure and real estate funds.

Dec. 31, 2022(1)	Level I	Level II	Level III	Total
Equity securities
Canadian	—	18	—	18
US	—	17	—	17
International	—	79	—	79
Private	—	—	1	1
Bonds
A - AAA	—	27	61	88
BBB	1	6	12	19
Below BBB	—	—	6	6
Loans(2)	—	2	—	2
Alternative funds(3)	—	—	39	39
Money market and cash and cash equivalents	—	20	—	20
Total	1	169	119	289

(1)The fair value level classifications of certain mutual fund investments has been revised for consistency with 2023 classifications.

(2)Includes A credit rating loans of $1 million and BBB credit rating loans of $1 million.

(3)Alternative funds include investments in infrastructure and real estate funds.

Disclosure of assumptions

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:

	2023			2022
As at Dec. 31 (per cent)	Registered	Supplemental	Other	Registered	Supplemental	Other
Accrued benefit obligation
Discount rate	4.6	4.6	4.7	4.7	5.0	5.0
Rate of compensation increase	2.9	3.0	—	2.6	3.0	—
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	—	—	6.8	—	—	7.1
Dental-care cost escalation	—	—	4.2	—	—	4.2
Benefit cost for the year
Discount rate	5.0	5.0	5.0	2.8	2.8	2.7
Rate of compensation increase	2.7	3.0	—	2.9	3.0	—
Assumed health-care cost trend rate
Health-care cost escalation(2)(4)	—	—	7.1	—	—	6.8
Dental-care cost escalation	—	—	4.7	—	—	4.7

(1)2023 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2033 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

(2)2023 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2032 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

(3)2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2032 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

(4)2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2031 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.

Disclosure of estimated increase in the net defined benefit obligation assuming certain changes in key assumptions

The following table outlines the estimated increase in the net defined benefit obligation assuming certain changes in key assumptions:

	Canadian plans			US plans
As at Dec. 31, 2023	Registered	Supplemental	Other	Pension
1% decrease in the discount rate	30	10	1	2
1% increase in the salary scale	1	—	—	—
1% increase in the health-care cost trend rate	—	—	1	—
10% improvement in mortality rates	13	3	—	1

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Joint Arrangements (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of interests in other entities [Abstract]

Disclosure of interests in joint arrangements

Joint arrangements at Dec. 31, 2023, 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
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
Tent Mountain	Hydro	50	Pumped hydro energy storage development project in Alberta

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Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of cash flow statement [Abstract]

Disclosure of non-cash operating working capital

Year ended Dec. 31	2023	2022	2021
(Use) source:
Accounts receivable	715	(869)	(28)
Prepaid expenses	—	—	9
Income taxes receivable	27	(61)	—
Inventory	(2)	6	42
Accounts payable, accrued liabilities and provisions	(550)	548	153
Income taxes payable	(66)	60	(2)
Change in non-cash operating working capital	124	(316)	174

Disclosure of cash flows from (used in) operating activities

	Balance Dec. 31, 2022	Cash issuances	Repayments and dividends paid(1)	New leases	Dividends declared	Foreign exchange impact	Other	Balance Dec. 31, 2023
Long-term debt and lease liabilities(2)	3,669	39	(220)	5	—	(36)	12	3,469
Exchangeable securities	739	—	—	—	—	—	5	744
Dividends payable (common and preferred)(3)	68	—	(109)	—	116	—	(26)	49
Total liabilities from financing activities	4,476	39	(329)	5	116	(36)	(9)	4,262

(1)Includes a decrease of $164 million related to the repayment of long-term debt, a $46 million net decrease in borrowings under credit facilities and a decrease in finance lease obligations of $10 million.

(2)Includes bank overdraft of $3 million.

(3)Other dividends payable related to payment of TransAlta Renewables' non-controlling interest dividend reflected within distributions paid to subsidiaries of non-controlling interests in the Consolidated Statements of Cash Flows.

	Balance Dec. 31, 2021	Cash issuances(1)	Repayments and dividends paid(2)	New leases	Dividends declared	Foreign exchange impact	Other	Balance Dec. 31, 2022
Long-term debt and lease liabilities(3)	3,267	981	(630)	40	—	39	(28)	3,669
Exchangeable securities	735	—	—	—	—	—	4	739
Dividends payable (common and preferred)	62	—	(97)	—	103	—	—	68
Total liabilities from financing activities	4,064	981	(727)	40	103	39	(24)	4,476

(1)Includes $449 million net increase in borrowings under credit facilities and an increase in issuance of long-term debt of $532 million.

(2)Includes a decrease of $621 million related to the repayment of long-term debt and a decrease in finance lease obligations of $9 million.

(3)Includes bank overdraft of $16 million.

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Capital (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of notes and other explanatory information [Abstract]

Disclosure of share capital, reserves and other equity interest

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	2023		2022
	Common shares  (millions)	Amount	Common shares (millions)	Amount
Issued and outstanding, beginning of period	268.1	2,863	271.0	2,901
Purchased and cancelled under the NCIB	(7.5)	(80)	(4.3)	(46)
Share-based payment plans	0.8	6	0.9	5
Stock options exercised	0.7	5	0.5	3
Issued for acquisition of TransAlta Renewables(1) (Note 4)	46.5	510	—	—
Issued and outstanding, end of year, prior to ASPP	308.6	3,304	268.1	2,863
Provision for repurchase of common shares under ASPP	(1.7)	(19)	—	—
Issued and outstanding, end of year	306.9	3,285	268.1	2,863

(1)Net of $4 million of transaction costs.

B. Normal Course Issuer Bid ("NCIB") Program

The effects of the Company's purchase and cancellation of common shares during the period are as follows:

For the year ended Dec. 31	2023	2022
Total shares purchased(1)	7,537,500	4,342,300
Average purchase price per share	11.49	12.48
Total cost (millions)	87	54
Book value of shares cancelled	80	46
Amount recorded in deficit	(7)	(8)

(1)At Dec. 31, 2023, includes 181,800 (2022 - 164,300) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. As a result, $2 million (2022 - $2 million) was paid subsequent to the year end.

2023

On May 26, 2023, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.29 per cent of its public float of common shares as at May 17, 2023. 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, 2023, and ends on May 30, 2024.

On Dec. 19, 2023, the Company entered into an Automatic Share Purchase Plan ("ASPP") which permits an independent broker to repurchase shares under the NCIB during the first quarter blackout period through to the end

of the ASPP. The Company has recognized a provision of $19 million for the repurchase of common shares under the ASPP within accounts payables and accrued liabilities as at Dec. 31, 2023, as a estimate of the maximum number of shares that could be repurchased during the blackout period.

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.

2022

On May 24, 2022, the TSX accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 17, 2022.

C. Shareholder Rights Plan 

The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 28, 2022. 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 28, 2022, and will need to be approved at the annual meeting of shareholders

in 2025. 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.

D. Earnings per Share

Year ended Dec. 31	2023	2022	2021
Net earnings (loss) attributable to common shareholders	644	4	(576)
Basic and diluted weighted average number of common shares outstanding (millions)	276	271	271
Net earnings (loss) per share attributable to common shareholders, basic and diluted	2.33	0.01	(2.13)

E. Dividends

On Nov. 21, 2023, the Company declared a quarterly dividend of $0.06 per common share, payable on April 1, 2024.

There have been no transactions involving common shares between the reporting date and the date of completion of these Consolidated Financial Statements.

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	2023		2022
Series(1)	Number of shares  (millions)	Amount	Number of shares (millions)	Amount
Series A	9.6	235	9.6	235
Series B	2.4	58	2.4	58
Series C	10.0	243	10.0	243
Series D	1.0	26	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)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

I. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion

On June 30, 2022, the Company converted 1,044,299 of its 11.0 million Cumulative Redeemable Rate Reset First Preferred Shares, Series C (“Series C Shares”), on a one-for-one basis, into Cumulative Redeemable Floating Rate First Preferred Shares, Series D (“Series D Shares”).

The Series C Shares pay fixed cumulative preferential cash dividends on a quarterly basis, for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The annual fixed dividend rate is 5.854 per cent, being equal to the five-year Government of Canada bond yield of 2.754 per cent determined as of May 31, 2022, plus 3.10 per cent, in accordance with the terms of the Series C Shares.

The Series D Shares pay quarterly floating rate cumulative preferential cash dividends for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The quarterly dividend rate for the Series D Shares is established each quarter, and is equal to the annual rate for the auction of 90-day Government of Canada Treasury Bills, plus 3.10 per cent, in accordance with the terms of the Series D Shares.

II. Series E Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion

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 per cent, 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.

Preferred Share Series Information 

The holders are entitled to receive cumulative fixed quarterly cash dividends at specified rates, as approved by the Board. After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed rate resets to the sum of the then five-year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified spread. Upon each Rate Reset Date, 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, 2023, are as follows:

Series(1)	Rate during term	Annual dividend rate per share ($)(2)	Next conversion date	Rate spread over benchmark  (per cent)	Convertible to Series
A	Fixed	0.71924	March 31, 2026	2.03	B
B	Floating	1.718910	March 31, 2026	2.03	A
C	Fixed	1.46352	June 30, 2027	3.10	D
D	Floating	1.98695	June 30, 2027	3.10	C
E	Fixed	1.72352	Sept. 30, 2027	3.65	F
G	Fixed	1.24700	Sept. 30, 2024	3.80	H

(1)The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 25.

(2)The annual dividend rate per share represents dividends declared in 2023.

B. Dividends

The following table summarizes the preferred share dividends declared in 2023 and 2022:

	Total dividends declared
Series	2023(1)	2022(1)
A	7	7
B(2)	4	3
C	15	14
D(3)	2	1
E	15	13
G	8	8
Total for the year	51	46

(1)No dividends were declared in the first quarter of the year as the quarterly dividend related to the period covering the first quarter was declared in December of the prior year.

(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.

(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 Dec. 11, 2023, the Company declared a quarterly dividend of $0.17981 per share on the Series A preferred shares, $0.43958 per share on the Series B preferred shares, $0.36588 per share on the Series C preferred

shares, $0.50609 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 March 31, 2024.

TransAlta’s capital is comprised of the following:

As at Dec. 31	2023	2022	Increase/ (decrease)
Long-term debt(1)	3,466	3,653	(187)
Exchangeable securities	744	739	5
Bank overdraft	3	16	(13)
Equity
Common shares	3,285	2,863	422
Preferred shares	942	942	—
Contributed surplus	41	41	—
Deficit	(2,567)	(2,514)	(53)
Accumulated other comprehensive income (loss)	(164)	(222)	58
Non-controlling interests	127	879	(752)
Less: available cash and cash equivalents(2)	(348)	(1,134)	786
Less: principal portion of restricted cash on TransAlta OCP bonds(3)	(17)	(17)	—
Less: fair value liability (asset) of hedging instruments on long-term debt(4)	5	(3)	8
Total capital	5,517	5,243	274

(1)Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt.

(2)The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed using a net debt position. 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 as 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.

Disclosure of cash flow statement

For the years ended Dec. 31, 2023 and 2022, 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 are available to fund operations, pay dividends, distribute payments to subsidiaries' non-controlling interests and invest in PP&E.

Year ended Dec. 31	2023	2022	Increase (decrease)
Cash flow from operating activities	1,464	877	587
Change in non-cash working capital	(124)	316	(440)
Cash flow from operations before changes in working capital	1,340	1,193	147
Dividends paid on common shares	(58)	(54)	(4)
Dividends paid on preferred shares	(51)	(43)	(8)
Distributions paid to subsidiaries’ non-controlling interests	(223)	(187)	(36)
Property, plant and equipment expenditures	(875)	(918)	43
Inflow (outflow)	133	(9)	142

XML

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2023

Related Party [Abstract]

Disclosure of interests in subsidiaries

TA Cogen

Year ended Dec. 31	2023	2022	2021
Revenues	290	347	265
Net earnings and total comprehensive income	121	143	103
Amounts attributable to the non-controlling interest:
Net earnings	80	91	62
Total comprehensive income	80	91	62
Distributions paid to Canadian Power Holdings Inc.	148	87	56

As at Dec. 31	2023	2022
Current assets	43	127
Long-term assets	193	253
Current liabilities	(41)	(62)
Long-term liabilities	(34)	(27)
Total equity	(161)	(291)
Equity attributable to Canadian Power Holdings Inc.	(79)	(147)
Non-controlling interest share (per cent)	49.99	49.99

Kent Hills Wind LP

Prior to Oct 5, 2023, financial information related to the 17 per cent non-controlling interest in Kent Hills Wind LP was included in the financial information disclosed in TransAlta Renewables in this note.

Year ended Dec. 31	2023(1)
Revenues	7
Net earnings and total comprehensive income	2
Amounts attributable to the non-controlling interest:
Net earnings and total comprehensive income	—

(1)This represents financial information from Oct. 5, 2023 to Dec. 31, 2023. The net earnings attributable to non-controlling interest in Kent Hills Wind LP prior to Oct. 5, 2023, is included in the disclosures for TransAlta Renewables.

As at Dec. 31	2023
Current assets	35
Long-term assets	481
Current liabilities	(42)
Long-term liabilities	(188)
Total equity	(285)
Equity attributable to non-controlling interests	(48)
Non-controlling interest share (per cent)	17

TransAlta Renewables

The financial information disclosed below includes the 17 per cent non-controlling interest in Kent Hills Wind LP until Oct. 5, 2023.

Year ended Dec. 31	2023(1)	2022	2021
Revenues	303	560	470
Net earnings	56	74	139
Total comprehensive income (loss)	(7)	(67)	66
Amounts attributable to the non-controlling interests:
Net earnings	21	20	50
Total comprehensive income (loss)	(4)	(36)	21
Distributions paid to non-controlling interests	75	100	100

(1)Non-controlling interest share prior the close of the transaction on Oct. 5, 2023. This represents financial information from Jan. 1, 2023 to Oct. 4, 2023.

As at Dec. 31	2022
Current assets	240
Long-term assets	2,989
Current liabilities	(306)
Long-term liabilities	(1,118)
Total equity	(1,805)
Equity attributable to non-controlling interests	(732)
Non-controlling interests’ share (per cent)	39.9

Details of the Company’s principal operating subsidiaries at Dec. 31, 2023, 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	100(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

(1)On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. TransAlta Renewables at Dec. 31, 2023, is a wholly owned subsidiary of the Company (2022 – 60.1 per cent). Refer to Note 4 for more details.

Disclosure of information about key management personnel and transactions with associates

TransAlta’s key management personnel include the President and Chief Executive Officer ("CEO"), 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	2023	2022	2021
Total compensation	21	23	30
Comprised of:
Short-term employee benefits	11	11	14
Post-employment benefits	1	1	1
Termination benefits	1	—	—
Share-based payments	8	11	15

Year ended Dec. 31	2023	2022	2021
Power sales	135	127	27
Purchased power	2	12	3
Asset management fees paid	1	2	2

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of other provisions, contingent liabilities and contingent assets [Abstract]

Disclosure of commitments and future payments

In addition to the commitments disclosed elsewhere in the financial statements, the Company has incurred the following contractual commitments, either directly or through its interests in joint operations and joint ventures.

Approximate future payments under these agreements are as follows:

	2024	2025	2026	2027	2028	2029 and thereafter	Total
Natural gas, transportation and other contracts	55	49	50	48	57	436	695
Transmission	9	9	6	4	5	93	126
Coal supply agreements	86	71	—	—	—	—	157
Long-term service agreements	60	57	42	44	37	184	424
Operating leases	3	3	2	2	2	25	37
Growth	47	—	—	—	—	—	47
Total	260	189	100	98	101	738	1,486

XML

Segment Disclosures (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of operating segments [abstract]

Disclosure of operating segments

Year ended Dec. 31, 2023	Hydro	Wind &  Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass  adjustments	IFRS financials
Revenues	533	357	1,514	751	220	1	3,376	(21)	—	3,355
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	(4)	16	(67)	(5)	23	—	(37)	—	37	—
Realized gain (loss) on closed exchange positions	—	—	10	—	(91)	—	(81)	—	81	—
Decrease in finance lease receivable	—	—	55	—	—	—	55	—	(55)	—
Finance lease income	—	—	12	—	—	—	12	—	(12)	—
Unrealized foreign exchange loss on commodity	—	—	1	—	—	—	1	—	(1)	—
Adjusted revenues	529	373	1,525	746	152	1	3,326	(21)	50	3,355
Fuel and purchased power	19	30	453	557	—	1	1,060	—	—	1,060
Reclassifications and adjustments:
Australian interest income	—	—	(4)	—	—	—	(4)	—	4	—
Adjusted fuel and purchased power	19	30	449	557	—	1	1,056	—	4	1,060
Carbon compliance	—	—	112	—	—	—	112	—	—	112
Gross margin	510	343	964	189	152	—	2,158	(21)	46	2,183
OM&A	48	80	192	64	43	115	542	(3)	—	539
Taxes, other than income taxes	3	12	11	3	—	1	30	(1)	—	29
Net other operating income	—	(7)	(40)	—	—	—	(47)	—	—	(47)
Reclassifications and adjustments:
Insurance recovery	—	1	—	—	—	—	1	—	(1)	—
Adjusted net other operating income	—	(6)	(40)	—	—	—	(46)	—	(1)	(47)
Adjusted EBITDA(2)	459	257	801	122	109	(116)	1,632
Equity income										4
Finance lease income										12
Depreciation and amortization										(621)
Asset impairment reversals										48
Interest income										59
Interest expense										(281)
Foreign exchange loss										(7)
Gain on sale of assets and other										4
Earnings before income taxes										880

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

Year ended Dec. 31, 2022	Hydro	Wind &  Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	606	303	1,209	714	160	(2)	2,990	(14)	—	2,976
Reclassifications and adjustments:
Unrealized mark-to-market loss	1	104	251	10	12	—	378	—	(378)	—
Realized gain (loss) on closed exchange positions	—	—	(4)	—	47	—	43	—	(43)	—
Decrease in finance lease receivable	—	—	46	—	—	—	46	—	(46)	—
Finance lease income	—	—	19	—	—	—	19	—	(19)	—
Unrealized foreign exchange gain on commodity	—	—	—	—	(1)	—	(1)	—	1	—
Adjusted revenues	607	407	1,521	724	218	(2)	3,475	(14)	(485)	2,976
Fuel and purchased power	22	31	641	566	—	3	1,263	—	—	1,263
Reclassifications and adjustments:
Australian interest income	—	—	(4)	—	—	—	(4)	—	4	—
Adjusted fuel and purchased power	22	31	637	566	—	3	1,259	—	4	1,263
Carbon compliance	—	1	83	(1)	—	(5)	78	—	—	78
Gross margin	585	375	801	159	218	—	2,138	(14)	(489)	1,635
OM&A	55	68	195	69	35	101	523	(2)	—	521
Taxes, other than income taxes	3	12	15	4	—	1	35	(2)	—	33
Net other operating income	—	(23)	(38)	—	—	—	(61)	3	—	(58)
Reclassifications and adjustments:
Insurance recovery	—	7	—	—	—	—	7	—	(7)	—
Adjusted net other operating   income	—	(16)	(38)	—	—	—	(54)	3	(7)	(58)
Adjusted EBITDA(2)	527	311	629	86	183	(102)	1,634
Equity income										9
Finance lease income										19
Depreciation and amortization										(599)
Asset impairment charges										(9)
Interest income										24
Interest expense										(286)
Foreign exchange gain										4
Gain on sale of assets and other										52
Earnings before income taxes										353

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

Year ended Dec. 31, 2021	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	—
Realized gain (loss) on closed exchange positions	—	—	(6)	—	29	—	23	—	(23)	—
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	1,126	728	202	4	2,791	(18)	(52)	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 writedown	—	—	—	(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	634	236	202	—	1,770	(18)	(263)	1,489
OM&A	42	59	175	117	36	84	513	(2)	—	511
Reclassifications and adjustments:
Parts and materials writedown	—	—	(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 loss (income)	—	—	(40)	48	—	—	8	—	—	8
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties	—	—	—	(48)	—	—	(48)	—	48	—
Adjusted net other operating loss (income)	—	—	(40)	—	—	—	(40)	—	48	8
Adjusted EBITDA(2)	322	262	488	133	166	(85)	1,286
Equity income										9
Finance lease income										25
Depreciation and amortization										(529)
Asset impairment charges										(648)
Interest income										11
Interest expense										(256)
Foreign exchange gain										16
Gain on sale of assets and other										54
Loss before income taxes										(380)

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

Disclosure of selected consolidated statements of financial position information

Selected Consolidated Statements of Financial Position Information

As at As at Dec. 31, 2023	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
PP&E	462	3,360	1,543	251	—	98	5,714
Right-of-use assets	7	94	5	—	—	11	117
Intangible assets	2	141	40	4	5	31	223
Goodwill	258	176	—	—	30	—	464
As at As at Dec. 31, 2022	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
PP&E	437	2,837	1,858	313	—	111	5,556
Right-of-use assets	6	98	6	2	—	14	126
Intangible assets	2	157	49	5	8	31	252
Goodwill	258	176	—	—	30	—	464

Disclosure of components in other non-current assets

Additions to non-current assets are as follows:

Year ended Dec. 31, 2023	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	42	674	89	16	—	54	875
Intangible assets	—	—	—	—	—	13	13
Year ended Dec. 31, 2022	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	36	745	43	19	—	75	918
Intangible assets	—	19	—	—	3	9	31
Year ended Dec. 31, 2021	Hydro	Wind and Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Additions to non-current assets:
PP&E	29	166	167	90	—	28	480
Intangible assets	—	—	—	1	—	8	9

Disclosure of reconciliation between depreciation and amortization

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	2023	2022	2021
Depreciation and amortization expense on the Consolidated Statements of Earnings (Loss)	621	599	529
Depreciation included in fuel and purchased power (Note 6)	—	—	190
Depreciation and amortization on the Consolidated Statements of Cash Flows	621	599	719

Disclosure of geographical areas

Revenues

Year ended Dec. 31	2023	2022	2021
Canada	2,218	1,905	1,854
US	987	940	731
Australia	150	131	136
Total revenue	3,355	2,976	2,721

II. Non-Current Assets

	Property, plant and equipment		Right-of-use assets		Intangible assets		Other assets
As at Dec. 31	2023	2022	2023	2022	2023	2022	2023	2022
Canada	3,578	3,817	43	49	108	123	68	62
US	1,749	1,307	71	74	88	101	42	34
Australia	387	432	3	3	27	28	69	64
Total	5,714	5,556	117	126	223	252	179	160

XML

Corporate Information (Details)	Dec. 31, 2023 segment
Disclosure of operating segments [line items]
Number of segments	6
Generation Segments
Disclosure of operating segments [line items]
Number of segments	4

XML

Material Accounting Policies - Remaining Useful Lives Of Asset Class (Details)	12 Months Ended
	Dec. 31, 2023
Hydro generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	1 year
Hydro generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	49 years
Wind and Solar generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	1 year
Wind and Solar generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	30 years
Gas generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	1 year
Gas generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	34 years
Energy Transition | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	1 year
Energy Transition | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	9 years
Capital spares and other | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	1 year
Capital spares and other | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	49 years

XML

Material Accounting Policies - Remaining Useful Lives Of Intangible Assets (Details)	12 Months Ended
	Dec. 31, 2023
Software | Minimum
Disclosure of detailed information about intangible assets [line items]
Useful life measured as period of time, intangible assets other than goodwill	1 year
Software | Maximum
Disclosure of detailed information about intangible assets [line items]
Useful life measured as period of time, intangible assets other than goodwill	7 years
Power sale contracts | Minimum
Disclosure of detailed information about intangible assets [line items]
Useful life measured as period of time, intangible assets other than goodwill	1 year
Power sale contracts | Maximum
Disclosure of detailed information about intangible assets [line items]
Useful life measured as period of time, intangible assets other than goodwill	18 years

XML

Business Acquisitions (Details) $ / shares in Units, shares in Millions, $ in Millions			12 Months Ended
	Nov. 02, 2023 CAD ($)	Oct. 05, 2023 CAD ($) shares $ / shares	Dec. 31, 2023 CAD ($)
Disclosure of detailed information about business combination [line items]
Changes in non-controlling interests in TransAlta Renewables (Note 4)			$ (809)
Committed
Disclosure of detailed information about business combination [line items]
Facility size			2,590
Committed | TransAlta syndicated credit facility
Disclosure of detailed information about business combination [line items]
Facility size			1,950
Deficit
Disclosure of detailed information about business combination [line items]
Changes in non-controlling interests in TransAlta Renewables (Note 4)			(625)
Attributable to non-controlling interests
Disclosure of detailed information about business combination [line items]
Changes in non-controlling interests in TransAlta Renewables (Note 4)			(630)
Other
Disclosure of detailed information about business combination [line items]
Change in ownership of TransAlta Renewables			(64)
Heartland Generation
Disclosure of detailed information about business combination [line items]
Purchase price	$ 390
Debt assumed	268
Aggregate consideration	$ 658
TransAlta Renewables Inc.
Disclosure of detailed information about business combination [line items]
Aggregate consideration		$ 1,300
Cash consideration		$ 800
Common shares issued (in shares) | shares		46
Value of common shares issued		$ 514
Price per share of shares issued | $ / shares		$ 11.06
Transaction costs		$ 11
TransAlta Renewables Inc. | Committed | TransAlta syndicated credit facility
Disclosure of detailed information about business combination [line items]
Additional borrowings		700
Facility size		2,000
TransAlta Renewables Inc. | Issued capital
Disclosure of detailed information about business combination [line items]
Transaction costs		4	$ 4
TransAlta Renewables Inc. | Deficit
Disclosure of detailed information about business combination [line items]
Transaction costs		$ 7

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Revenue - Disaggregation of Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	$ 3,355	$ 2,976	$ 2,721
At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	52	63	53
Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	620	713	629
Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	632	725	654
Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	40	51	28
Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	32	32	19
Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	341	(541)	213
Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	2,273	2,673	1,734
Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	37	36	73
Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	672	776	682
Hydro | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	533	606	383
Hydro | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	14	1	0
Hydro | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	30	33	28
Hydro | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	30	33	28
Hydro | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	14	1	0
Hydro | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Hydro | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	44	0	0
Hydro | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	434	564	345
Hydro | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	11	8	10
Hydro | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	44	34	28
Wind and Solar | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	336	289	305
Wind and Solar | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	26	50	28
Wind and Solar | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	190	220	207
Wind and Solar | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	190	220	207
Wind and Solar | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	26	50	28
Wind and Solar | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Wind and Solar | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	(2)	(121)	(22)
Wind and Solar | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	104	119	35
Wind and Solar | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	18	21	57
Wind and Solar | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	216	270	235
Gas | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	1,514	1,209	1,109
Gas | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	2
Gas | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	400	462	393
Gas | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	400	462	395
Gas | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Gas | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	32	32	19
Gas | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	(172)	(821)	(118)
Gas | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	1,247	1,529	808
Gas | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	7	7	5
Gas | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	400	462	395
Energy Transition | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	751	714	709
Energy Transition | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	12	12	23
Energy Transition | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	(2)	1
Energy Transition | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	12	10	24
Energy Transition | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Transition | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Transition | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	251	243	138
Energy Transition | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	488	461	546
Energy Transition | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	1
Energy Transition | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	12	10	24
Energy Marketing | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	220	160	211
Energy Marketing | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	220	160	211
Energy Marketing | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	1	(2)	4
Corporate | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	(2)	4
Corporate | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	1	0	0
Corporate | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	$ 0	$ 0	$ 0

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Revenue - Narrative (Details) $ in Millions	Dec. 31, 2023 CAD ($)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	$ 2,700
2024 to 2026
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	510
2027 to 2029
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	505
2030 to 2034
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	725
2035 and Thereafter
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	$ 960

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Expenses by Nature - Expenses Classified by Nature (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of products and services [line items]
Mine depreciation	$ 0	$ 0	$ 190
Total			511
Adjustments for impairment loss (reversal of impairment loss) recognised in profit or loss, inventories			17
Fuel and purchased power
Disclosure of products and services [line items]
Gas fuel costs	384	578	306
Coal fuel costs	177	146	164
Royalty, land lease, other direct costs	25	25	19
Purchased power	474	514	339
Mine depreciation	0	0	190
Salaries and benefits	0	0	36
Other operating expenses	0	0	0
Total	1,060	1,263	1,054
Fuel and purchased power | Coal
Disclosure of products and services [line items]
Mine depreciation			48
OM&A
Disclosure of products and services [line items]
Gas fuel costs	0	0	0
Coal fuel costs	0	0	0
Royalty, land lease, other direct costs	0	0	0
Purchased power	0	0	0
Mine depreciation	0	0	0
Salaries and benefits	254	263	234
Other operating expenses	285	258	277
Total	539	$ 521	511
Write-downs	$ 14		$ 28

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Asset Impairment Charges (Reversals) - Detailed Information About Property, Plant, and Equipment (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges (reversals)		$ (48)	$ 9	$ 648
Kaybob Cogeneration Project | Corporate
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges (reversals)		0	(2)	27
Impairment charges	$ 27
Hydro
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges (reversals)		(10)	21	5
Wind and Solar
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges (reversals)		(4)	43	12
Gas
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges (reversals)			0	5
Energy Transition
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges (reversals)		0	0	540
Changes in decommissioning and restoration provisions on retired assets
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges (reversals)		(34)	(53)	32
Intangible asset impairment charges - Coal Rights
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges (reversals)		0	0	17
Project development costs
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges (reversals)		$ 0	$ 0	$ 10

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Asset Impairment Charges (Reversals) - Narrative (Details) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2022 CAD ($)	Mar. 31, 2021 CAD ($)	Dec. 31, 2023 CAD ($) facility asset MW	Dec. 31, 2022 CAD ($) facility asset	Dec. 31, 2021 CAD ($) MW
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges (reversals)			$ (48)	$ 9	$ 648
Recoverable amounts	$ 10,741		8,659	10,741
Estimated salvage value					33
Reversal of impairment loss			$ 21	$ 102
Energy Transition
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges (reversals)					191
Discount rate, measurement input
Disclosure of impairment loss recognised or reversed [line items]
Discount rates	5.0			5.0
Wind Facilities
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges				$ 13	10
Number of assets | asset			2
Wind Facilities | Level III | Non-recurring fair value measurement | Investment property
Disclosure of impairment loss recognised or reversed [line items]
Recoverable amounts					65
Kent Hills Wind L.P.
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges					$ 2
Capacity of facility (in megawatts) | MW			167		167
Keephills Unit 1 | Energy Transition
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges (reversals)					$ 94
Sundance Unit 4 | Energy Transition
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges (reversals)					56
Kaybob Cogeneration Project | Corporate
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges (reversals)			$ 0	(2)	27
Impairment charges		$ 27
Reversal of impairment loss	$ 2
Hydro
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges (reversals)			$ (10)	$ 21	5
Number of facilities | facility			2	4
Hydro | Hydro Facilities
Disclosure of impairment loss recognised or reversed [line items]
Number of assets | asset				4
Hydro | Hydro Facilities | Level III | Non-recurring fair value measurement
Disclosure of impairment loss recognised or reversed [line items]
Recoverable amounts	89		$ 70	$ 89
Wind
Disclosure of impairment loss recognised or reversed [line items]
Number of facilities | facility				5
Solar
Disclosure of impairment loss recognised or reversed [line items]
Number of facilities | facility				1
Wind and Solar
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges (reversals)			$ (4)	$ 43	12
Wind and Solar | Wind and Solar Facilities
Disclosure of impairment loss recognised or reversed [line items]
Number of assets | asset			3	6
Wind and Solar | Wind and Solar Facilities | Level III | Non-recurring fair value measurement
Disclosure of impairment loss recognised or reversed [line items]
Recoverable amounts	$ 754		$ 540	$ 754
Reversal of impairment loss			17
Wind and Solar | Wind Facilities | Level III | Non-recurring fair value measurement
Disclosure of impairment loss recognised or reversed [line items]
Recoverable amounts			$ 130
Mining assets | Highvale Mine
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges					$ 195

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Asset Impairment Charges (Reversals) - Disclosure of Fair Value Less Cost of Disposal (Details)	Dec. 31, 2023	Dec. 31, 2022
Canada | Wind and Solar | Contract Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year contract and merchant discount rates	6.40%
Prior period contract and merchant discount rates		6.40%
Canada | Wind and Solar | Merchant Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year contract and merchant discount rates	7.00%
Prior period contract and merchant discount rates		7.10%
Canada | Hydro | Contract Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year contract and merchant discount rates	6.10%
Prior period contract and merchant discount rates		5.90%
Canada | Hydro | Merchant Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year contract and merchant discount rates	6.40%
Prior period contract and merchant discount rates		6.40%
US | Wind and Solar | Contract Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year contract and merchant discount rates	6.90%
Prior period contract and merchant discount rates		6.50%
US | Wind and Solar | Merchant Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year contract and merchant discount rates	7.50%
Prior period contract and merchant discount rates		7.70%

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Net Other Operating (Income) Loss - Disclosure of Components of Net Other Operating (Income) Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Analysis of income and expense [abstract]
Alberta Off-Coal Agreement	$ (40)	$ (40)	$ (40)
Liquidated damages recoverable	(6)	(12)	0
Insurance recoveries	(1)	(7)	0
Supplier, other contract settlements and other	0	1	34
Onerous contract provisions	0	0	14
Net other operating (income) loss	$ (47)	$ (58)	$ 8

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Net Other Operating (Income) Loss - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)
Analysis of income and expenses [Line Items]
Alberta Off-Coal Agreement	$ (40)	$ (40)	$ (40)
Annual cash payments, net	37
Liquidated damages recoverable	6	12	0
Insurance recoveries	(1)	(7)	0
Supplier, other contract settlements and other	0	(1)	(34)
Onerous contract provisions	0	0	14
Sundance Unit 5
Analysis of income and expenses [Line Items]
Net deferred tax assets			$ 10	$ 8
Windrise Wind Facility
Analysis of income and expenses [Line Items]
Liquidated damages recoverable	$ 3	$ 0

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Investments - Change in Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Change In Investments [Roll Forward]
Equity income (loss)	$ 4	$ 9	$ 9
Changes in foreign exchange rates		10	0
EMG | Equity-accounted
Change In Investments [Roll Forward]
Beginning balance	12	12
Investment	0	0
Equity income (loss)	(4)	(1)
Distributions received	0	0
Changes in foreign exchange rates	0	(1)
Net change in fair value recognized in OCI		0
Ending balance	8	12	12
Skookumchuck | Equity-accounted
Change In Investments [Roll Forward]
Beginning balance	105	93
Investment	0	0
Equity income (loss)	8	10
Distributions received	(6)	(5)
Changes in foreign exchange rates	3	(7)
Net change in fair value recognized in OCI		0
Ending balance	104	105	93
Tent Mountain | Equity-accounted
Change In Investments [Roll Forward]
Beginning balance	0	0
Investment	10	0
Equity income (loss)	0	0
Distributions received	0	0
Changes in foreign exchange rates	0	0
Net change in fair value recognized in OCI		0
Ending balance	10	0	0
EIP | FVTPL
Change In Investments [Roll Forward]
Beginning balance	11	0
Investment	4	10
Equity income (loss)	0	0
Distributions received	0	0
Changes in foreign exchange rates	0	(1)
Net change in fair value recognized in OCI		0
Ending balance	15	11	0
Ekona | FVTOCI
Change In Investments [Roll Forward]
Beginning balance	1	0
Investment	0	2
Equity income (loss)	0	0
Distributions received	0	0
Changes in foreign exchange rates	0	0
Net change in fair value recognized in OCI		(1)
Ending balance	1	1	0
Consolidated structured entities
Change In Investments [Roll Forward]
Beginning balance	129	105
Investment	14	12
Equity income (loss)	4	9	9
Distributions received	(6)	(5)
Changes in foreign exchange rates	3	(9)
Net change in fair value recognized in OCI		(1)
Ending balance	$ 138	$ 129	$ 105

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Investments - Narrative (Details) $ in Millions, $ in Millions				12 Months Ended
	Apr. 24, 2023 CAD ($) MW	May 06, 2022 USD ($)	Nov. 30, 2020	Dec. 31, 2023 CAD ($) MW	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Feb. 01, 2022 CAD ($)
Investment [Line Items]
Equity investment				$ 138		$ 129
EMG
Investment [Line Items]
Ownership interest (as a percent)			3000.00%
Contingent amount paid					$ 3.5
Skookumchuck
Investment [Line Items]
Ownership interest (as a percent)				4900.00%
Capacity of facility (in megawatts) | MW				136.8
PPA, period				20 years
Tent Mountain
Investment [Line Items]
Ownership interest (as a percent)	5000.00%
Capacity of facility (in megawatts) | MW	320
Purchase price	$ 8
Aggregate consideration				$ 2
Contingent consideration	$ 17
Energy Impact Partners
Investment [Line Items]
Committed investment		$ 25.0
Committed investment, period		4 years
Ekona | Class B Preferred Shares
Investment [Line Items]
Equity investment							$ 2

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Investments - Results of Operations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of subsidiaries [line items]
Revenues and other operating income	$ 3,355	$ 2,976	$ 2,721
Equity income (loss)	4	9	9
Consolidated structured entities
Disclosure of subsidiaries [line items]
Revenues and other operating income	22	24	19
Operating expense	(18)	(15)	(10)
Equity income (loss)	$ 4	$ 9	$ 9

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Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Analysis of income and expense [abstract]
Interest on debt	$ 203	$ 164	$ 163
Interest on exchangeable debentures	29	29	29
Interest on exchangeable preferred shares	28	28	28
Capitalized interest	(57)	(16)	(14)
Interest on lease liabilities	9	7	7
Credit facility fees, bank charges and other interest	21	27	20
Tax shield on tax equity financing	0	(2)	(9)
Accretion of provisions	48	49	32
Interest expense	$ 281	$ 286	$ 256

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Income Taxes - Rate Reconciliations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Abstract]
Earnings (loss) before income taxes	$ 880	$ 353	$ (380)
Net earnings attributable to non-controlling interests not subject to tax	(80)	(94)	(33)
Adjusted earnings (loss) before income taxes	$ 800	$ 259	$ (413)
Statutory Canadian federal and provincial income tax rate (%)	23.40%	23.40%	23.60%
Expected income tax expense (recovery)	$ 187	$ 61	$ (98)
Increase (decrease) in income taxes resulting from:
Differences in effective foreign tax rates	9	(1)	4
Non-deductible expense	58	130	0
Taxable capital (gain) loss	(2)	18	0
Deferred income tax recovery related to temporary difference on investment in subsidiaries	(3)	(2)	0
Write-down (reversal of write-down) of unrecognized deferred income tax assets	(178)	(24)	134
Statutory and other rate differences	1	(3)	4
Adjustments in respect of deferred income tax of previous years	1	6	(4)
Other	11	7	5
Income tax expense	$ 84	$ 192	$ 45
Effective tax rate (%)	11.00%	74.00%	(11.00%)

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Income Taxes - Components of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Abstract]
Current income tax expense	$ 50	$ 65	$ 56
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences	215	153	(145)
Deferred income tax recovery related to temporary difference on investment in subsidiaries	(3)	(2)	0
Deferred income tax expense (recovery) arising from the unrecognized deferred income tax assets	(178)	(24)	134
Current income tax expense	50	65	56
Deferred income tax expense (recovery)	34	127	(11)
Income tax expense	84	$ 192	$ 45
Deferred tax assets yet to be recognized	$ 157

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Income Taxes - Aggregate Current and Deferred Income Tax Charged to Equity (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Abstract]
Net impact related to cash flow hedges	$ 27	$ (112)	$ (57)
Net impact related to hedges of foreign operations	1	(3)	0
Net impact related to net actuarial gains (losses)	(1)	12	11
Transaction costs for the acquisition of TransAlta Renewables	(2)	0	0
Income tax expense (recovery) reported in equity	$ 25	$ (103)	$ (46)

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Income Taxes - Significant Components of Deferred Income Tax Assets (Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Unrecognized deferred income tax assets	$ (21)	$ (50)
Net deferred tax liabilities	(365)	(302)
Cost | Non-capital losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability), before write-down of deferred income tax assets	88	244
Cost | Future decommissioning and restoration costs
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability), before write-down of deferred income tax assets	111	119
Cost | Property, plant and equipment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability), before write-down of deferred income tax assets	(605)	(553)
Cost | Risk management assets and liabilities, net
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability), before write-down of deferred income tax assets	144	193
Cost | Employee future benefits and compensation plans
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability), before write-down of deferred income tax assets	50	48
Cost | Foreign exchange differences on US-denominated debt
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability), before write-down of deferred income tax assets	12	13
Cost | Other taxable temporary differences
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability), before write-down of deferred income tax assets	(8)	(5)
Accumulated impairment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability), before write-down of deferred income tax assets	(208)	59
Unrecognized deferred income tax assets	$ (157)	$ (361)

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Income Taxes - Deferred Income Tax Liability Presentation (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Income Taxes [Abstract]
Deferred income tax assets	$ 21	$ 50
Deferred income tax liabilities	(386)	(352)
Net deferred tax liabilities	$ (365)	$ (302)

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Income Taxes - Contingencies (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Uncertain tax positions
Disclosure of contingent liabilities [line items]
Provision for uncertain tax positions	$ 0	$ 0

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Non-Controlling Interests - Subsidiaries and Operations with Non-Controlling Interests (Details) - CAD ($) $ in Millions	9 Months Ended	12 Months Ended
	Oct. 04, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of subsidiaries [line items]
Total comprehensive income (loss)		$ 893	$ (263)	$ (610)
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Ownership interests		49.99%	49.99%
Total comprehensive income (loss)		$ 121	$ 143	103
Dividends paid to non-controlling interests		$ 148	$ 87	$ 56
Kent Hills wind farm
Disclosure of subsidiaries [line items]
Ownership interests	17.00%	17.00%	17.00%
Kent Hills wind farm | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Ownership interests	17.00%
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Ownership interests	39.90%		39.90%
Coal facility | TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Ownership interests		50.00%

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Non-Controlling Interests - Narrative (Details) - MW	9 Months Ended	12 Months Ended
	Oct. 04, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Kent Hills Wind L.P.
Disclosure of subsidiaries [line items]
Capacity of facility (in megawatts)		167		167
Coal facility | TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Ownership interests		50.00%
Kent Hills wind farm
Disclosure of subsidiaries [line items]
Ownership interests	17.00%	17.00%	17.00%
Kent Hills wind farm | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Ownership interests	17.00%

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Non-Controlling Interests - Earnings of Subsidiaries with Non-Controlling Interests (Details) - CAD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2023	Oct. 04, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of subsidiaries [line items]
Revenue			$ 3,355	$ 2,976	$ 2,721
Net earnings (loss)			796	161	(425)
Total comprehensive income (loss)			893	(263)	(610)
Amounts attributable to the non-controlling interests:
Net earnings (loss)			101	111	112
Total comprehensive income (loss)			76	55	83
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Revenue			290	347	265
Net earnings (loss)			121	143	103
Total comprehensive income (loss)			121	143	103
Amounts attributable to the non-controlling interests:
Net earnings (loss)			80	91	62
Total comprehensive income (loss)			80	91	62
Dividends paid to non-controlling interests			$ 148	87	56
Kent Hills Wind L.P.
Disclosure of subsidiaries [line items]
Revenue	$ 7
Net earnings (loss)	2
Total comprehensive income (loss)	2
Amounts attributable to the non-controlling interests:
Net earnings (loss)	0
Total comprehensive income (loss)	$ 0
TransAlta Renewables, Inc. Including Kent Hills Wind LP
Disclosure of subsidiaries [line items]
Revenue		$ 303		560	470
Net earnings (loss)		56		74	139
Total comprehensive income (loss)		(7)		(67)	66
Amounts attributable to the non-controlling interests:
Net earnings (loss)		21		20	50
Total comprehensive income (loss)		(4)		(36)	21
Dividends paid to non-controlling interests		$ 75		$ 100	$ 100

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Non-Controlling Interests - Financial Position of Non-Controlling Interests (Details) - CAD ($) $ in Millions	9 Months Ended	12 Months Ended
	Oct. 04, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of subsidiaries [line items]
Current assets		$ 1,580	$ 3,714
Current liabilities		(1,742)	(2,888)
Total equity		1,664	1,989	$ 2,593
Equity attributable to non-controlling interests		127	879
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Current assets		43	127
Long-term assets		193	253
Current liabilities		(41)	(62)
Long-term liabilities		(34)	(27)
Total equity		(161)	(291)
Equity attributable to non-controlling interests		$ (79)	$ (147)
Non-controlling interests’ share (per cent)		49.99%	49.99%
Kent Hills Wind L.P.
Disclosure of subsidiaries [line items]
Current assets		$ 35
Long-term assets		481
Current liabilities		(42)
Long-term liabilities		(188)
Total equity		(285)
Equity attributable to non-controlling interests		$ (48)
Non-controlling interests’ share (per cent)		17.00%
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Current assets			$ 240
Long-term assets			2,989
Current liabilities			(306)
Long-term liabilities			(1,118)
Total equity			(1,805)
Equity attributable to non-controlling interests			$ (732)
Non-controlling interests’ share (per cent)	39.90%		39.90%

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Trade and Other Receivables and Accounts Payable (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Trade accounts receivable	$ 600	$ 1,165
Collateral provided	145	304
Current portion of finance lease receivables	19	52
Loan receivable	1	4
Income taxes receivable	42	64
Trade and other receivables	807	1,589
Accounts payable and accrued liabilities	772	1,069
Interest payable	16	17
Collateral held	9	260
Accounts payable and accrued liabilities	$ 797	$ 1,346

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Financial Instruments - Carrying Amounts and Classifications of Financial Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	$ 3,466	$ 3,653
Cash equivalents	0	0
Bank overdraft
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3	16
Bank overdraft | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3	16
Accounts payable and accrued liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	797	1,346
Accounts payable and accrued liabilities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	797	1,346
Dividends payable (common and preferred)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	49	68
Dividends payable (common and preferred) | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	49	68
Credit facilities, long-term debt and lease liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,466	3,653
Credit facilities, long-term debt and lease liabilities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,466	3,653
Exchangeable securities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	744	739
Exchangeable securities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	744	739
Within one year | Risk Management Liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	314	1,129
Within one year | Derivatives | Risk Management Liabilities | Derivatives used for hedging
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	125	271
Within one year | Derivatives | Risk Management Liabilities | Derivatives held for trading (FVTPL)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	189	858
Later than one year | Risk Management Liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	274	333
Later than one year | Derivatives | Risk Management Liabilities | Derivatives used for hedging
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	80	76
Later than one year | Derivatives | Risk Management Liabilities | Derivatives held for trading (FVTPL)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	194	257
Cash and cash equivalents
Disclosure of detailed information about financial instruments [line items]
Financial assets	348	1,134
Cash and cash equivalents | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	348	1,134
Restricted cash
Disclosure of detailed information about financial instruments [line items]
Financial assets	69	70
Restricted cash | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	69	70
Trade and other receivables
Disclosure of detailed information about financial instruments [line items]
Financial assets	807	1,589
Trade and other receivables | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	807	1,589
Long-term portion of finance lease receivables
Disclosure of detailed information about financial instruments [line items]
Financial assets	171	129
Long-term portion of finance lease receivables | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	171	129
Long-term portion of loan receivable
Disclosure of detailed information about financial instruments [line items]
Financial assets	25	33
Long-term portion of loan receivable | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	25	33
Other investments(3)
Disclosure of detailed information about financial instruments [line items]
Financial assets	16	12
Other investments(3) | Other financial assets (FVTPL)
Disclosure of detailed information about financial instruments [line items]
Financial assets	15	11
Other investments(3) | Other financial assets (FVOCI)
Disclosure of detailed information about financial instruments [line items]
Financial assets	1	1
Risk management assets | Within one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	151	709
Risk management assets | Later than one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	52	161
Risk management assets | Derivatives used for hedging | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	0	0
Risk management assets | Derivatives used for hedging | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	0	0
Risk management assets | Derivatives held for trading (FVTPL) | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	151	709
Risk management assets | Derivatives held for trading (FVTPL) | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	$ 52	$ 161

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Financial Instruments - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) MW	Dec. 31, 2022 CAD ($) MW	Apr. 05, 2022 MW	Dec. 31, 2021 CAD ($)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	$ 3,466	$ 3,653
Long-term wind energy sale – Eastern US
Disclosure of detailed information about financial instruments [line items]
Membership interest	100.00%
Capacity of facility (in megawatts) | MW	90
Long-term wind energy sale – Canada
Disclosure of detailed information about financial instruments [line items]
Membership interest	100.00%
Garden Plain Wind Project
Disclosure of detailed information about financial instruments [line items]
Capacity of facility (in megawatts) | MW	130
Weighted average extension period (in years)	17 years
Long-term wind energy sale - Central US
Disclosure of detailed information about financial instruments [line items]
Membership interest	100.00%
White Rock East And White Rock West Wind Power Projects
Disclosure of detailed information about financial instruments [line items]
Capacity of facility (in megawatts) | MW		300
Horizon Hill Wind Project
Disclosure of detailed information about financial instruments [line items]
Membership interest			10000.00%
Capacity of facility (in megawatts) | MW			200
Maximum | Fixed-price contracts
Disclosure of detailed information about financial instruments [line items]
Capacity long-term fixed price power sale | MW	380
Minimum | Fixed-price contracts
Disclosure of detailed information about financial instruments [line items]
Capacity long-term fixed price power sale | MW	300
Level I | Recurring fair value measurement
Disclosure of detailed information about financial instruments [line items]
Commodity risk management assets and liabilities	$ (13)	$ 23
Level II | Recurring fair value measurement
Disclosure of detailed information about financial instruments [line items]
Commodity risk management assets and liabilities	(244)	173
Level III | Recurring fair value measurement
Disclosure of detailed information about financial instruments [line items]
Commodity risk management assets and liabilities	(147)	(782)		$ 159
Level III | Recurring fair value measurement | Other
Disclosure of detailed information about financial instruments [line items]
Commodity risk management assets and liabilities	19	6
Level III | Recurring fair value measurement | Financial liabilities at fair value through profit or loss, category
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	203	813
Level III | Recurring fair value measurement | Other financial assets (FVTPL)
Disclosure of detailed information about financial instruments [line items]
Financial assets	$ 56	$ 31

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Financial Instruments - Fair Value of the Commodity Risk Management Assets and Liabilities by Classification Level (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of risk management strategy related to hedge accounting [line items]
Change in foreign exchange rates	$ (7)	$ 4	$ 16
Losses recognized in other comprehensive loss	75	126	(8)
Total gains (losses) included in earnings before income taxes	51	(694)	(255)
Level III | Recurring fair value measurement
Disclosure of risk management strategy related to hedge accounting [line items]
Commodity risk management assets and liabilities	(147)	(782)	159
Market price changes	525	80
Change in foreign exchange rates	16	12
Transfers out of Level III(1)	205	0
Level III | Recurring fair value measurement | Market price changes on existing contracts
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(129)	(909)
Level III | Recurring fair value measurement | Market price changes on new contracts
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	18	(124)
Level III | Non-recurring fair value measurement
Disclosure of risk management strategy related to hedge accounting [line items]
Losses recognized in other comprehensive loss	(114)	(594)
Total gains (losses) included in earnings before income taxes	(237)	(389)
Unrealized gains (losses) included in earnings before income taxes relating to net assets (liabilities) held at year end	288	(309)
Level III | Hedge | Recurring fair value measurement
Disclosure of risk management strategy related to hedge accounting [line items]
Commodity risk management assets and liabilities	0	(347)	285
Market price changes	256	(38)
Change in foreign exchange rates	9	17
Transfers out of Level III(1)	205	0
Level III | Hedge | Recurring fair value measurement | Market price changes on existing contracts
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(123)	(611)
Level III | Hedge | Recurring fair value measurement | Market price changes on new contracts
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	0	0
Level III | Hedge | Non-recurring fair value measurement
Disclosure of risk management strategy related to hedge accounting [line items]
Losses recognized in other comprehensive loss	(114)	(594)
Total gains (losses) included in earnings before income taxes	(256)	38
Unrealized gains (losses) included in earnings before income taxes relating to net assets (liabilities) held at year end	0	0
Level III | Non-hedge | Recurring fair value measurement
Disclosure of risk management strategy related to hedge accounting [line items]
Commodity risk management assets and liabilities	(147)	(435)	$ (126)
Market price changes	269	118
Change in foreign exchange rates	7	(5)
Transfers out of Level III(1)	0	0
Level III | Non-hedge | Recurring fair value measurement | Market price changes on existing contracts
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(6)	(298)
Level III | Non-hedge | Recurring fair value measurement | Market price changes on new contracts
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	18	(124)
Level III | Non-hedge | Non-recurring fair value measurement
Disclosure of risk management strategy related to hedge accounting [line items]
Losses recognized in other comprehensive loss	0	0
Total gains (losses) included in earnings before income taxes	19	(427)
Unrealized gains (losses) included in earnings before income taxes relating to net assets (liabilities) held at year end	$ 288	$ (309)

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Financial Instruments - Sensitivity Ranges for the Base Fair Values (Details)	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)
Long-term wind energy sale – Eastern US | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible				$ 6
Long-term wind energy sale - Central US | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible			$ 2
Forward contract | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ (6)
Minimum | Long-term power sale – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible				$ (5)
Sensitivity			163,000,000
Minimum | Coal transportation – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 4,000,000		$ 13,000,000
Minimum | Coal transportation – US | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in rail rate escalation expressed as a percentage			0	0
Minimum | Coal transportation – US | Long-term contracts | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in rail rate escalation expressed as a percentage	0	0
Minimum | Coal transportation – US | Long-term contracts | US | Volatility
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	0.80	0.80	0.80	0.80
Minimum | Full requirements – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 3,000,000		$ (21,000,000)
Minimum | Full requirements – Eastern US | Cost of supply
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ (2.30)		$ 0.50
Minimum | Full requirements – Eastern US | US | Volume
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	0.96	0.96	0.96	0.96
Minimum | Long-term wind energy sale – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in monthly wind discounts expressed as a percentage	0.00%	0.00%
Sensitivity	$ 28,000,000		$ 18,000,000
Minimum | Long-term wind energy sale – Eastern US | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible				$ 0
Minimum | Long-term wind energy sale – Canada
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in monthly wind discounts expressed as a percentage	16.00%	16.00%	(5.00%)	(5.00%)
Sensitivity	$ 23,000,000		$ 25,000,000
Minimum | Long-term wind energy sale – Canada | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible	$ 81		$ 85
Minimum | Long-term wind energy sale - Central US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in monthly wind discounts expressed as a percentage	5.00%	5.00%	2.00%	2.00%
Sensitivity	$ 36,000,000		$ 28,000,000
Minimum | Long-term wind energy sale - Central US | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ 1
Minimum | Fixed-price contracts | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ (12)		$ (2)
Maximum | Long-term power sale – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible				$ 55
Sensitivity			15,000,000
Maximum | Coal transportation – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 6,000,000		$ 14,000,000
Maximum | Coal transportation – US | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in rail rate escalation expressed as a percentage			0.10	0.10
Maximum | Coal transportation – US | Long-term contracts | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in rail rate escalation expressed as a percentage	0.10	0.10
Maximum | Coal transportation – US | Long-term contracts | US | Volatility
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	1.20	1.20	1.20	1.20
Maximum | Full requirements – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 3,000,000		$ 3,000,000
Maximum | Full requirements – Eastern US | Cost of supply
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ 2.40		$ 3.30
Maximum | Full requirements – Eastern US | US | Volume
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	1.04	1.04	1.04	1.04
Maximum | Long-term wind energy sale – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in monthly wind discounts expressed as a percentage	9.00%	9.00%
Sensitivity	$ 24,000,000		$ 22,000,000
Maximum | Long-term wind energy sale – Eastern US | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible				$ 0.05
Maximum | Long-term wind energy sale – Canada
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in monthly wind discounts expressed as a percentage	5.00%	5.00%	(28.00%)	(28.00%)
Sensitivity	$ 65,000,000		$ 47,000,000
Maximum | Long-term wind energy sale – Canada | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible	$ (5)		$ (5)
Maximum | Long-term wind energy sale - Central US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in monthly wind discounts expressed as a percentage	2.00%	2.00%	5.00%	5.00%
Sensitivity	$ 81,000,000		$ 74,000,000
Maximum | Long-term wind energy sale - Central US | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ (2)
Maximum | Fixed-price contracts | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ 8

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Financial Instruments - Fair Value of Financial Assets and Liabilities Measured at Other than Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	$ 3,466	$ 3,653
Other financial assets (FVTPL) | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	26	37
Exchangeable securities
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	744	739
Long-term debt
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,323	3,518
Recurring fair value measurement | Other financial assets (FVTPL) | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	26	37
Recurring fair value measurement | Exchangeable securities | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	718	685
Recurring fair value measurement | Long-term debt | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,104	3,200
Recurring fair value measurement | Level I | Other financial assets (FVTPL) | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	0	0
Recurring fair value measurement | Level I | Exchangeable securities | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	0	0
Recurring fair value measurement | Level I | Long-term debt | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	0	0
Recurring fair value measurement | Level II | Other financial assets (FVTPL) | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	26	37
Recurring fair value measurement | Level II | Exchangeable securities | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	718	685
Recurring fair value measurement | Level II | Long-term debt | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,104	3,200
Recurring fair value measurement | Level III | Other financial assets (FVTPL)
Disclosure of fair value measurement of liabilities [line items]
Financial assets	56	31
Recurring fair value measurement | Level III | Other financial assets (FVTPL) | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	0	0
Recurring fair value measurement | Level III | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	203	813
Recurring fair value measurement | Level III | Exchangeable securities | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	0	0
Recurring fair value measurement | Level III | Long-term debt | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	$ 0	$ 0

XML

Financial Instruments - Inception Gains And Losses (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Changes in aggregate difference between fair value at initial recognition and transaction price yet to be recognised in profit or loss [abstract]
Unamortized net gain (loss) at beginning of year	$ (213)	$ (131)	$ (33)
New inception loss		(37)	(79)
Change resulting from amended contract		0	0
Change in foreign exchange rates		(10)	0
Amortization recorded in net earnings during the year		(35)	(19)
Unamortized net gain (loss) at end of year		(213)	$ (131)
Impacts of the PPA Contract Amendments
Changes in aggregate difference between fair value at initial recognition and transaction price yet to be recognised in profit or loss [abstract]
Unamortized net gain (loss) at beginning of year	(213)
New inception loss	47
Change resulting from amended contract	190
Change in foreign exchange rates	6
Amortization recorded in net earnings during the year	(27)
Unamortized net gain (loss) at end of year	$ 3	$ (213)

XML

Risk Management Activities - Net Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	$ (385)	$ (592)
Commodity risk management | Current risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(178)	(414)
Commodity risk management | Long-term risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(226)	(172)
Commodity risk management | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(404)	(586)
Other | Current risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		(6)
Other | Long-term risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		0
Other | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		(6)
Current | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	15
Long-term | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	4
Financial Assets | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	19
Cash flow hedges | Cash flow hedges | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(205)	(347)
Cash flow hedges | Cash flow hedges | Commodity risk management | Current risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(125)	(271)
Cash flow hedges | Cash flow hedges | Commodity risk management | Long-term risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(80)	(76)
Cash flow hedges | Cash flow hedges | Commodity risk management | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(205)	(347)
Cash flow hedges | Cash flow hedges | Other | Current risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		0
Cash flow hedges | Cash flow hedges | Other | Long-term risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		0
Cash flow hedges | Cash flow hedges | Other | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		0
Cash flow hedges | Current | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	0
Cash flow hedges | Long-term | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	0
Cash flow hedges | Financial Assets | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	0
Not designated as a hedge | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(180)	(245)
Not designated as a hedge | Commodity risk management | Current risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(53)	(143)
Not designated as a hedge | Commodity risk management | Long-term risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(146)	(96)
Not designated as a hedge | Commodity risk management | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(199)	(239)
Not designated as a hedge | Other | Current risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		(6)
Not designated as a hedge | Other | Long-term risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		0
Not designated as a hedge | Other | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		$ (6)
Not designated as a hedge | Current | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	15
Not designated as a hedge | Long-term | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	4
Not designated as a hedge | Financial Assets | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	$ 19

XML

Risk Management Activities - Netting Arrangements (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current risk management liabilities
Disclosure of financial liabilities [abstract]
Gross amounts of recognized financial liabilities	$ (504)	$ (1,953)
Amounts set off	355	883
Net amounts included on the statement of financial position	(149)	(1,070)
Master netting arrangements	7	62
Net amount	(142)	(1,008)
Long-term risk management liabilities
Disclosure of financial liabilities [abstract]
Gross amounts of recognized financial liabilities	(145)	(449)
Amounts set off	91	43
Net amounts included on the statement of financial position	(54)	(406)
Master netting arrangements	2	7
Net amount	(52)	(399)
Accounts payable and accrued liabilities
Disclosure of financial liabilities [abstract]
Gross amounts of recognized financial liabilities	(760)	(1,344)
Amounts set off	646	934
Net amounts included on the statement of financial position	(114)	(410)
Master netting arrangements	11	176
Net amount	(103)	(234)
Current risk management assets
Disclosure of financial assets [abstract]
Gross amounts of recognized financial assets	528	1,602
Amounts set off	(355)	(883)
Net amounts included on the statement of financial position	173	719
Master netting arrangements	(7)	(62)
Net amount	166	657
Long-term risk management assets
Disclosure of financial assets [abstract]
Gross amounts of recognized financial assets	161	204
Amounts set off	(91)	(43)
Net amounts included on the statement of financial position	70	161
Master netting arrangements	(2)	(7)
Net amount	68	154
Trade and other receivables
Disclosure of financial assets [abstract]
Gross amounts of recognized financial assets	789	1,330
Amounts set off	(646)	(934)
Net amounts included on the statement of financial position	143	396
Master netting arrangements	(11)	(176)
Net amount	$ 132	$ 220

XML

Risk Management Activities - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) agency	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2023 USD ($) agency	Dec. 31, 2022 USD ($)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Floating interest rates	14.00%	1500.00%		14.00%	1500.00%
Outstanding credit facilities	$ (46,000,000)	$ 449,000,000	$ (114,000,000)
Target percentage, four year period	6000.00%
Sensitivity analysis average	$ 0.03	0.03	0.03
Maximum credit exposure	$ 23,000,000	64,000,000
Number of credit rating agency | agency	1			1
Debt maturing	$ 400,000,000
After-tax gain reclassified from AOCI to net earnings	102,000,000	(460,000,000)	(222,000,000)
Net unrealized gain	44,000,000	384,000,000	97,000,000
Gains on foreign exchange and other derivatives	11,000,000	20,000,000	6,000,000
Unrealised Gains On Change In Fair Value Of Derivatives	(27,000,000)		(4,000,000)
Unrealised loss on foreign exchange and other derivatives		11,000,000
Net realised loss on change in fair value of derivatives	16,000,000
Net realized gains on foreign exchange and other derivatives		31,000,000	2,000,000
Collateral provided	145,000,000	304,000,000
Cash collateral	9,000,000	260,000,000
Additional collateral requirement	$ 154,000,000	594,000,000
Number Of Below Investment Grade Ratings From Credit Rating Agencies | agency	2			2
Trade and other receivables	$ 807,000,000	1,589,000,000
Recourse Debt
Disclosure of nature and extent of risks arising from financial instruments [line items]
Debt maturing	411,000,000
Letter of credit
Disclosure of nature and extent of risks arising from financial instruments [line items]
Collateral posted on derivative liabilities	392,000,000	820,000,000
Surety Bonds
Disclosure of nature and extent of risks arising from financial instruments [line items]
Collateral posted on derivative liabilities	19,000,000	6,000,000
Within one year
Disclosure of nature and extent of risks arising from financial instruments [line items]
After-tax gain reclassified from AOCI to net earnings	(89,000,000)
Within one year | Lease Incentive Receivable
Disclosure of nature and extent of risks arising from financial instruments [line items]
Trade and other receivables	12,000,000
Long-term debt | Net investment hedges
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount				$ 370	$ 370
Interest rate swap contract [member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Outstanding credit facilities	400,000,000	433,000,000
Commodity Price Risk - Proprietary Trading
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	4,000,000	4,000,000	2,000,000
Commodity Price Risk - Generation
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	23,000,000	97,000,000	33,000,000
Commodity Price Risk - Generation - Mark To Market Value
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	16,000,000	45,000,000	$ 34,000,000
Interest rate risk | TAPC Holdings LP bond (Poplar Creek)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount	86,000,000	$ 95,000,000
Commodity risk management | Cash flow hedges
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	$ 0

XML

Risk Management Activities - Commodity Derivative Instruments Not Designated as Hedging Instruments (Details) - Non-hedge - Commodity risk management	Dec. 31, 2023 MWh J t	Dec. 31, 2022 MWh J t
Electricity
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	54,043,000	55,821,000
Notional amount purchased	12,628,000	13,934,000
Natural Gas
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold | J	50,949,000	23,464,000
Notional amount purchased | J	209,348,000	162,384,000
Transmission
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	0	0
Notional amount purchased	856,000	1,643,000
Emissions
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	212,000	274,000
Notional amount purchased	804,000	2,297,000
Notional amount sold | t	4,450,000	300,000
Notional amount purchased | t	5,125,000	300,000
Coal
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold | t	0	0
Notional amount purchased | t	5,172,000	7,746,000

XML

Risk Management Activities - Non-Hedges (Details) $ in Millions, $ in Millions, $ in Millions	Dec. 31, 2023 AUD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 AUD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)
Disclosure of detailed information about hedges [line items]
Fair value liability		$ 5
Fair value asset					$ 3
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2024-2027, Contract One
Disclosure of detailed information about hedges [line items]
Fair value liability		(1)
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2024-2027, Contract Two
Disclosure of detailed information about hedges [line items]
Fair value asset		19
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2026
Disclosure of detailed information about hedges [line items]
Fair value liability					(1)
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2025, Contract Two
Disclosure of detailed information about hedges [line items]
Fair value liability					(12)
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2024
Disclosure of detailed information about hedges [line items]
Fair value asset		5
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023
Disclosure of detailed information about hedges [line items]
Fair value asset					4
Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2024
Disclosure of detailed information about hedges [line items]
Fair value liability		(4)
Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2023
Disclosure of detailed information about hedges [line items]
Fair value asset					3
AUD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2024-2027, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount sold	$ 125
AUD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2026
Disclosure of detailed information about hedges [line items]
Notional amount sold				$ 183
AUD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2024
Disclosure of detailed information about hedges [line items]
Notional amount purchased	$ 152
AUD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023
Disclosure of detailed information about hedges [line items]
Notional amount purchased				$ 102
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2024-2027, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount purchased		113
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2024-2027, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount purchased		1,113
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2026
Disclosure of detailed information about hedges [line items]
Notional amount purchased					168
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2025, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount purchased					761
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2024
Disclosure of detailed information about hedges [line items]
Notional amount sold		$ 190
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2023
Disclosure of detailed information about hedges [line items]
Notional amount sold					$ 159
USD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2024-2027, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount sold			$ 828
USD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2025, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount sold						$ 573
USD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2024
Disclosure of detailed information about hedges [line items]
Notional amount sold			100
USD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023
Disclosure of detailed information about hedges [line items]
Notional amount sold						66
USD | Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2024
Disclosure of detailed information about hedges [line items]
Notional amount purchased			$ 140
USD | Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2023
Disclosure of detailed information about hedges [line items]
Notional amount purchased						$ 120

XML

Risk Management Activities - Impacts of currency rate risk (Details) - Currency risk - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of credit risk exposure [line items]
Net earnings increase (decrease)	$ (14)	$ (14)	$ (12)
OCI gain	0	0	1
USD
Disclosure of credit risk exposure [line items]
Net earnings increase (decrease)	(11)	(12)	(13)
OCI gain	0	0	1
AUD
Disclosure of credit risk exposure [line items]
Net earnings increase (decrease)	(3)	(2)	1
OCI gain	$ 0	$ 0	$ 0

XML

Risk Management Activities - Maximum Exposure to Credit Risk (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of credit risk exposure [line items]
Maximum credit exposure	$ 23	$ 64
Credit risk
Disclosure of credit risk exposure [line items]
Maximum credit exposure	1,207
Credit risk | Trade and other receivables
Disclosure of credit risk exposure [line items]
Maximum credit exposure	$ 807
Trade and other receivables | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Trade and other receivables | Investment grade (per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	95.00%
Trade and other receivables | Non-investment grade (per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	5.00%
Long-term portion of finance lease receivables | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Maximum credit exposure	$ 171
Long-term portion of finance lease receivables | Investment grade (per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Long-term portion of finance lease receivables | Non-investment grade (per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	0.00%
Risk management assets | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Maximum credit exposure	$ 203
Risk management assets | Investment grade (per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	75.00%
Risk management assets | Non-investment grade (per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	25.00%
Loan receivable | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Maximum credit exposure	$ 26
Loan receivable | Investment grade (per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	0.00%
Loan receivable | Non-investment grade (per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%

XML

Risk Management Activities - Maturity Analysis of Financial Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	$ 3	$ 16
Accounts payable and accrued liabilities	797	1,346
Principal repayments	3,466	3,653
Exchangeable securities	744	739
Dividends payable	49	68
Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0	$ 1
2024
Disclosure of maturity analysis for derivative financial liabilities [line items]
Lease incentive	12
Cost
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	3
Accounts payable and accrued liabilities	797
Principal repayments	3,363
Exchangeable securities	750
Other risk management assets	(19)
Lease liabilities	143
Interest expense on borrowings	1,516
Dividends payable	49
Total	7,284
Cost | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	400
Cost | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	251
Cost | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	924
Cost | Non-recourse – Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	39
Cost | Non-recourse – Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	636
Cost | Non-recourse and other – Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	1,003
Cost | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	110
Cost | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	278
Cost | Commodity risk management liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management liabilities	404
Cost | 2024
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	3
Accounts payable and accrued liabilities	797
Principal repayments	526
Exchangeable securities	0
Other risk management assets	(16)
Lease liabilities	4
Interest expense on borrowings	186
Dividends payable	49
Total	1,771
Cost | 2024 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	400
Cost | 2024 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2024 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2024 | Non-recourse – Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2024 | Non-recourse – Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	66
Cost | 2024 | Non-recourse and other – Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	46
Cost | 2024 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	14
Cost | 2024 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	53
Cost | 2024 | Commodity risk management liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management liabilities	169
Cost | 2025
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	142
Exchangeable securities	0
Other risk management assets	(3)
Lease liabilities	4
Interest expense on borrowings	167
Dividends payable	0
Total	486
Cost | 2025 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2025 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2025 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2025 | Non-recourse – Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2025 | Non-recourse – Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	69
Cost | 2025 | Non-recourse and other – Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	58
Cost | 2025 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	15
Cost | 2025 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	53
Cost | 2025 | Commodity risk management liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management liabilities	123
Cost | 2026
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	143
Exchangeable securities	0
Other risk management assets	0
Lease liabilities	4
Interest expense on borrowings	158
Dividends payable	0
Total	373
Cost | 2026 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2026 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2026 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2026 | Non-recourse – Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2026 | Non-recourse – Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	67
Cost | 2026 | Non-recourse and other – Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	61
Cost | 2026 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	15
Cost | 2026 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	53
Cost | 2026 | Commodity risk management liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management liabilities	15
Cost | 2027
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	153
Exchangeable securities	0
Other risk management assets	0
Lease liabilities	4
Interest expense on borrowings	151
Dividends payable	0
Total	373
Cost | 2027 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2027 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2027 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2027 | Non-recourse – Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2027 | Non-recourse – Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	70
Cost | 2027 | Non-recourse and other – Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	65
Cost | 2027 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	18
Cost | 2027 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	53
Cost | 2027 | Commodity risk management liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management liabilities	12
Cost | 2028
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	162
Exchangeable securities	0
Other risk management assets	0
Lease liabilities	4
Interest expense on borrowings	143
Dividends payable	0
Total	374
Cost | 2028 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2028 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2028 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2028 | Non-recourse – Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2028 | Non-recourse – Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	75
Cost | 2028 | Non-recourse and other – Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	66
Cost | 2028 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	21
Cost | 2028 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	53
Cost | 2028 | Commodity risk management liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management liabilities	12
Cost | 2029 and thereafter
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	2,237
Exchangeable securities	750
Other risk management assets	0
Lease liabilities	123
Interest expense on borrowings	711
Dividends payable	0
Total	3,907
Cost | 2029 and thereafter | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2029 and thereafter | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	251
Cost | 2029 and thereafter | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	924
Cost | 2029 and thereafter | Non-recourse – Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	39
Cost | 2029 and thereafter | Non-recourse – Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	289
Cost | 2029 and thereafter | Non-recourse and other – Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	707
Cost | 2029 and thereafter | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	27
Cost | 2029 and thereafter | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	13
Cost | 2029 and thereafter | Commodity risk management liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management liabilities	$ 73

XML

Risk Management Activities - Maturity of Non-Hedges (Details) - Electricity - Non-hedge - Commodity risk management	Dec. 31, 2023 CAD ($) $ / MWh
2024
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 3,338
Average prices | $ / MWh	$ 78.18
2025
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 2,628
Average prices | $ / MWh	$ 80.13
2026
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 0
Average prices | $ / MWh	$ 0
2027
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 0
Average prices | $ / MWh	$ 0
2028
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 0
Average prices | $ / MWh	$ 0
2029 and thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 0
Average prices | $ / MWh	$ 0

XML

Risk Management Activities - Effect of Hedges (Details) MWh in Thousands, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) MWh	Dec. 31, 2022 CAD ($) MWh	Dec. 31, 2023 USD ($) MWh	Dec. 31, 2022 USD ($) MWh
Disclosure of detailed information about hedging instruments [line items]
Fair value asset		$ 3
Fair value liability	$ 5
Physical power sales | Cash flow hedges | Commodity risk management
Disclosure of detailed information about hedging instruments [line items]
Notional amount (MMWH) | MWh	5,966	9,295	5,966	9,295
Fair value liability	$ (205)	$ (347)
Gain (loss) on hedge ineffectiveness	(114)	(594)
Foreign-denominated Debt | Net Investment Hedge | Currency risk
Disclosure of detailed information about hedging instruments [line items]
Fair value asset	489	502
Gain (loss) on hedge ineffectiveness	$ 0	$ 0
Foreign-denominated Debt | Net Investment Hedge | Currency risk | USD
Disclosure of detailed information about hedging instruments [line items]
Notional amount			$ 370	$ 370

XML

Risk Management Activities - Hedged Items on the Statement of Financial Position (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Physical power sales | Cash flow hedges | Commodity risk management
Disclosure of detailed information about hedging instruments [line items]
Gain (loss) on hedge ineffectiveness	$ (114)	$ (594)
Reserve of cash flow hedges	(129)	(279)
Foreign-denominated Debt | Net Investment Hedge | Currency risk
Disclosure of detailed information about hedging instruments [line items]
Gain (loss) on hedge ineffectiveness	0	0
Reserve of cash flow hedges	$ (36)	$ (39)

XML

Risk Management Activities - Impact of Hedged Items Designated in Hedging Relationships on OCI and Net Earnings (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about hedging instruments [line items]
Total gains (losses) included in earnings before income taxes	$ 51	$ (694)	$ (255)
Losses recognized in other comprehensive loss	75	126	(8)
Location of (gain) loss reclassified from OCI	0	0	0
Commodity Contracts
Disclosure of detailed information about hedging instruments [line items]
Total gains (losses) included in earnings before income taxes	51	(747)	(268)
Commodity Contracts | Revenue
Disclosure of detailed information about hedging instruments [line items]
Losses recognized in other comprehensive loss	83	124	(13)
Location of (gain) loss reclassified from OCI	0	0	0
Foreign Exchange Forwards On Project Hedges
Disclosure of detailed information about hedging instruments [line items]
Total gains (losses) included in earnings before income taxes			0
Foreign Exchange Forwards On Project Hedges | Property Plants And Equipment
Disclosure of detailed information about hedging instruments [line items]
Losses recognized in other comprehensive loss			1
Location of (gain) loss reclassified from OCI			0
Forward Starting Interest Rate Swaps
Disclosure of detailed information about hedging instruments [line items]
Total gains (losses) included in earnings before income taxes	0	53	13
Forward Starting Interest Rate Swaps | Interest Expense1
Disclosure of detailed information about hedging instruments [line items]
Losses recognized in other comprehensive loss	(8)	2	4
Location of (gain) loss reclassified from OCI	$ 0	$ 0	$ 0

XML

Inventory - Components of Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of inventories [Abstract]
Parts, materials and supplies	$ 72	$ 83
Coal	38	43
Emission credits	45	27
Natural gas	2	4
Total	$ 157	$ 157

XML

Inventory - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) emissionCredit $ / t	Dec. 31, 2022 CAD ($) emissionCredit $ / t
Analysis of income and expenses [Line Items]
Emission credits | emissionCredit	962,548	963,068
Purchased emission credits	$ 45	$ 27
Emission credits in inventory | emissionCredit	3,121,837	3,619,450
Carbon compliance obligation, settlement amount | $ / t	65	50
Emission credits utilized | emissionCredit		1,169,333
Carrying value		$ 35
Carbon compliance obligation settlement		47
Carbon compliance costs		$ 12

XML

Finance Lease Receivables (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Nov. 22, 2023	Dec. 31, 2022
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	$ 257		$ 203
Present value of minimum lease receipts	190		181
Less: unearned finance lease income	67		22
Less: unearned finance lease income	0		0
Total finance lease receivables	190	$ 61	181
Current portion of finance lease receivables	19		52
Long-term portion of finance lease receivables	171		129
Within one year
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	28		62
Present value of minimum lease receipts	28		55
Second to fifth years inclusive
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	112		81
Present value of minimum lease receipts	98		75
More than five years
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	117		60
Present value of minimum lease receipts	$ 64		$ 51

XML

Assets Held for Sale - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Investment [Line Items]
Proceeds on sale of Pioneer Pipeline	$ 0	$ 0	$ 128
Gain on sale of assets and other	$ 4	$ 52	$ 54

XML

Property, Plant, and Equipment - Reconciliation of the Changes in the Carrying Amount of PP&E (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	$ 5,556	$ 5,320
Disposals		5
End of the period	5,714	5,556
Other work performed by entity and capitalised	$ 57	$ 16
Weighted average rate	6.30%	6.00%
Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	$ 14,012	$ 13,389
Additions	875	897
Additions from development projects		29
Disposals	33	220
Impairment (charges) reversals	(14)	62
Retirement of assets	264	39
Change in foreign exchange rates	(94)	153
Transfers to assets	2	(61)
Transfers to finance lease receivable	(65)
End of the period	14,444	14,012
Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(8,456)	(8,069)
Depreciation	585	538
Disposals	(30)	(212)
Retirement of assets	(235)	(33)
Change in foreign exchange rates	(47)	102
Transfers to assets		(8)
Transfers in (out) of PP&E	1
End of the period	(8,730)	(8,456)
Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	963	184
End of the period	1,234	963
Assets under construction | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	963	184
Additions	869	891
Additions from development projects		17
Disposals	0	0
Impairment (charges) reversals	0	(2)
Retirement of assets	0	0
Change in foreign exchange rates	(26)	13
Transfers to assets	(572)	(144)
Transfers to finance lease receivable	0
End of the period	1,234	963
Assets under construction | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	0	0
Depreciation	0	0
Disposals	0	0
Retirement of assets	0	0
Change in foreign exchange rates	0	0
Transfers to assets		0
Transfers in (out) of PP&E	0
End of the period	0	0
Land
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	93	96
End of the period	90	93
Land | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	93	96
Additions	0	0
Additions from development projects		0
Disposals	3	3
Impairment (charges) reversals	0	0
Retirement of assets	0	0
Change in foreign exchange rates	0	0
Transfers to assets	0	0
Transfers to finance lease receivable	0
End of the period	90	93
Land | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	0	0
Depreciation	0	0
Disposals	0	0
Retirement of assets	0	0
Change in foreign exchange rates	0	0
Transfers to assets		0
Transfers in (out) of PP&E	0
End of the period	0	0
Hydro
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	362	399
End of the period	385	362
Hydro | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	840	867
Additions	0	0
Additions from development projects		0
Disposals	0	0
Impairment (charges) reversals	(10)	21
Retirement of assets	7	9
Change in foreign exchange rates	0	0
Transfers to assets	38	18
Transfers to finance lease receivable	0
End of the period	884	840
Hydro | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(478)	(468)
Depreciation	25	21
Disposals	0	0
Retirement of assets	(4)	(8)
Change in foreign exchange rates	0	0
Transfers to assets		(3)
Transfers in (out) of PP&E	0
End of the period	(499)	(478)
Wind and Solar
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	2,005	2,183
End of the period	2,256	2,005
Wind and Solar | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	3,233	3,276
Additions	0	0
Additions from development projects		0
Disposals	0	0
Impairment (charges) reversals	(4)	43
Retirement of assets	18	9
Change in foreign exchange rates	(18)	45
Transfers to assets	439	23
Transfers to finance lease receivable	(61)
End of the period	3,593	3,233
Wind and Solar | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(1,228)	(1,093)
Depreciation	129	130
Disposals	0	0
Retirement of assets	(15)	(6)
Change in foreign exchange rates	(5)	11
Transfers to assets		0
Transfers in (out) of PP&E	0
End of the period	(1,337)	(1,228)
Gas generation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	1,718	1,909
End of the period	1,374	1,718
Gas generation | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	4,530	4,087
Additions	0	0
Additions from development projects		0
Disposals	0	1
Impairment (charges) reversals	0	0
Retirement of assets	124	12
Change in foreign exchange rates	(7)	(4)
Transfers to assets	50	472
Transfers to finance lease receivable	(4)
End of the period	4,423	4,530
Gas generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(2,812)	(2,178)
Depreciation	342	308
Disposals	0	(1)
Retirement of assets	(101)	(10)
Change in foreign exchange rates	(3)	2
Transfers to assets		335
Transfers in (out) of PP&E	(1)
End of the period	(3,049)	(2,812)
Energy Transition
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	230	363
End of the period	171	230
Energy Transition | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	3,974	4,513
Additions	0	0
Additions from development projects		0
Disposals	30	216
Impairment (charges) reversals	0	0
Retirement of assets	7	7
Change in foreign exchange rates	(42)	97
Transfers to assets	16	(423)
Transfers to finance lease receivable	0
End of the period	3,914	3,974
Energy Transition | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(3,744)	(4,150)
Depreciation	73	63
Disposals	(30)	(211)
Retirement of assets	(7)	(7)
Change in foreign exchange rates	(39)	89
Transfers to assets		(340)
Transfers in (out) of PP&E	2
End of the period	(3,743)	(3,744)
Capital spares and other
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	185	186
End of the period	204	185
Capital spares and other | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	379	366
Additions	6	6
Additions from development projects		12
Disposals	0	0
Impairment (charges) reversals	0	0
Retirement of assets	108	2
Change in foreign exchange rates	(1)	2
Transfers to assets	31	(7)
Transfers to finance lease receivable	0
End of the period	306	379
Capital spares and other | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(194)	(180)
Depreciation	16	16
Disposals	0	0
Retirement of assets	(108)	(2)
Change in foreign exchange rates	0	0
Transfers to assets		0
Transfers in (out) of PP&E	0
End of the period	(102)	(194)
Decommissioning and restoration
Disclosure of detailed information about property, plant and equipment [line items]
Disposals		5
Decommissioning and restoration | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	(3)	(74)
Decommissioning and restoration | Assets under construction | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	0	0
Decommissioning and restoration | Land | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	0	0
Decommissioning and restoration | Hydro | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	3	(15)
Decommissioning and restoration | Wind and Solar | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	14	(59)
Decommissioning and restoration | Gas generation | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	(22)	(12)
Decommissioning and restoration | Energy Transition | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	3	10
Decommissioning and restoration | Capital spares and other | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	$ (1)	$ 2

XML

Property, Plant, and Equipment - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about property, plant and equipment [line items]
Mine depreciation	$ 0	$ 0	$ 190
Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Mine depreciation	$ 92	$ 132

XML

Right of Use Assets - Reconciliation of Changes of the Right of Use Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	$ 126	$ 95
Additions	5	40
Depreciation	(12)	(11)
Change in foreign exchange rates	(2)	2
Right-of-use assets, ending balance	117	126
Land
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	102	68
Additions	2	36
Depreciation	(5)	(4)
Change in foreign exchange rates	(2)	2
Right-of-use assets, ending balance	97	102
Buildings
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	15	20
Additions	2	0
Depreciation	(5)	(5)
Change in foreign exchange rates	0	0
Right-of-use assets, ending balance	12	15
Vehicles
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	2	1
Additions	1	1
Depreciation	0	0
Change in foreign exchange rates	0	0
Right-of-use assets, ending balance	3	2
Equipment
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	7	6
Additions	0	3
Depreciation	(2)	(2)
Change in foreign exchange rates	0	0
Right-of-use assets, ending balance	$ 5	$ 7

XML

Right of Use Assets - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of leases [Abstract]
Lease liabilities recognized	$ 19	$ 16
Principal repayments	10	9
Interest on lease liabilities	9	7	$ 7
Expense relating to short-term and low value leases	1	2	0
Expense relating to variable lease payments	$ 8	$ 8	$ 6

XML

Intangible Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	$ 252	$ 256
Change in foreign exchange rates	(2)	2
Ending balance	223	252
Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	868	827
Additions	13	31
Change in foreign exchange rates	(5)	7
Asset impairment charges	(1)
Transfers	0	3
Ending balance	875	868
Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(616)	(571)
Change in foreign exchange rates	(2)	2
Amortization	38	43
Ending balance	(652)	(616)
Power sale contracts
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	114	129
Ending balance	96	114
Power sale contracts | Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	272	269
Additions	0	0
Change in foreign exchange rates	(2)	3
Asset impairment charges	0
Transfers	0	0
Ending balance	270	272
Power sale contracts | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(158)	(140)
Change in foreign exchange rates	(1)	1
Amortization	17	17
Ending balance	(174)	(158)
Software
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	111	123
Ending balance	100	111
Software | Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	437	422
Additions	0	0
Change in foreign exchange rates	(2)	3
Asset impairment charges	(1)
Transfers	12	12
Ending balance	446	437
Software | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(326)	(299)
Change in foreign exchange rates	(1)	1
Amortization	21	26
Ending balance	(346)	(326)
Intangibles under development
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	27	4
Ending balance	27	27
Intangibles under development | Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	27	4
Additions	13	31
Change in foreign exchange rates	(1)	1
Asset impairment charges	0
Transfers	(12)	(9)
Ending balance	27	27
Intangibles under development | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	0	0
Change in foreign exchange rates	0	0
Amortization	0	0
Ending balance	0	0
Coal rights
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	0	0
Ending balance	0	0
Coal rights | Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	132	132
Additions	0	0
Change in foreign exchange rates	0	0
Asset impairment charges	0
Transfers	0	0
Ending balance	132	132
Coal rights | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(132)	(132)
Change in foreign exchange rates	0	0
Amortization	0	0
Ending balance	$ (132)	$ (132)

XML

Goodwill (Details)	12 Months Ended
	Dec. 31, 2023 CAD ($) $ / MWh	Dec. 31, 2022 CAD ($) $ / MWh
Disclosure of detailed information about intangible assets [line items]
Goodwill	$ 464,000,000	$ 464,000,000
Impairment of goodwill	0
Hydro
Disclosure of detailed information about intangible assets [line items]
Goodwill	258,000,000	258,000,000
Wind and Solar
Disclosure of detailed information about intangible assets [line items]
Goodwill	176,000,000	176,000,000
Energy Marketing
Disclosure of detailed information about intangible assets [line items]
Goodwill	$ 30,000,000	$ 30,000,000
Minimum
Disclosure of detailed information about intangible assets [line items]
Discount rate used to calculate goodwill impairment	5.90%	5.90%
Electricity prices | $ / MWh	20	28
Maximum
Disclosure of detailed information about intangible assets [line items]
Discount rate used to calculate goodwill impairment	8.20%	8.20%
Electricity prices | $ / MWh	238	233

XML

Other Assets - Disclosure of Components in Other Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of financial assets [abstract]
South Hedland prepaid transmission access and distribution costs	$ 60	$ 61
Long-term prepaids and other assets	41	40
Project development costs	35	10
Loans receivable	26	37
Transmission infrastructure	18	16
Total current other assets	1	4
Total long-term other assets	179	160
Total Other assets	$ 180	$ 164

XML

Other Assets - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Jul. 30, 2015 USD ($)
Disclosure of joint operations [line items]
TransAlta Energy Transition Bill			$ 55
Loans receivable	$ 26	$ 37
Kent Hills Wind L.P.
Disclosure of joint operations [line items]
Loans receivable	$ 25
Ownership interests	17.00%
Interest	4.55%
Repayments received	$ 12	$ 18

XML

Decommissioning and Other Provisions - Change in Decommissioning and Other Provision Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of changes in other provisions [abstract]
Balance	$ 729	$ 827
Liabilities incurred	5	24
Liabilities settled	(50)	(47)
Accretion	48	49
Disposals		(5)
Revisions in estimated cash flows	(89)	100
Revisions in discount rates	52	(225)
Reversals		(9)
Change in foreign exchange rates	(6)	15
Balance	689	729
Decommissioning and restoration
Reconciliation of changes in other provisions [abstract]
Balance	688	793
Liabilities incurred	1	1
Liabilities settled	(37)	(35)
Accretion	47	49
Disposals		(5)
Revisions in estimated cash flows	(89)	95
Revisions in discount rates	52	(225)
Reversals		0
Change in foreign exchange rates	(6)	15
Balance	656	688
Other provisions
Reconciliation of changes in other provisions [abstract]
Balance	41	34
Liabilities incurred	4	23
Liabilities settled	(13)	(12)
Accretion	1	0
Disposals		0
Revisions in estimated cash flows	0	5
Revisions in discount rates	0	0
Reversals		(9)
Change in foreign exchange rates	0	0
Balance	$ 33	$ 41

XML

Decommissioning and Other Provisions - Current and Non-Current Portion of Decommissioning and Other Provisions (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Current portion	$ 35	$ 70
Non-current portion	654	659
Balance	$ 689	$ 729	$ 827

XML

Decommissioning and Other Provisions - Decommissioning and Restoration - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Disclosure of detailed information about borrowings [line items]
Undiscounted cash amount	$ 1,700,000,000
Increase (decrease) in PP&E	31,000,000	$ (123,000,000)
Reversal of impairment loss	(21,000,000)	(102,000,000)
Revisions in discount rates	52,000,000	(225,000,000)
Increase (decrease) through change in estimated cash flows	(89,000,000)	100,000,000
Onerous contract provisions	0	0	$ (14,000,000)
Gas
Disclosure of detailed information about borrowings [line items]
Decommissioning and restoration provision	34,000,000	46,000,000
Centralia Coal Mine | Surety Bonds
Disclosure of detailed information about borrowings [line items]
Bonds issued				$ 147	$ 147
Alberta Mine | Letters Of Credit
Disclosure of detailed information about borrowings [line items]
Bonds issued	188,000,000	187,000,000
Minimum
Disclosure of detailed information about borrowings [line items]
Revisions in discount rates	6.0	7.0
Maximum
Disclosure of detailed information about borrowings [line items]
Revisions in discount rates	0.090	9.7
Decommissioning and restoration
Disclosure of detailed information about borrowings [line items]
Decommissioning and restoration provision	52,000,000	225,000,000
Decommissioning and restoration
Disclosure of detailed information about borrowings [line items]
Increase (decrease) in PP&E	55,000,000	49,000,000
Revisions in discount rates	52,000,000	(225,000,000)
Increase (decrease) through change in estimated cash flows	$ (89,000,000)	$ 95,000,000

XML

Credit Facilities, Long-Term Debt and Lease Liabilities - Amounts Outstanding (Details) $ in Millions, $ in Millions, $ in Millions	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 AUD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 AUD ($)	Nov. 15, 2022 CAD ($)
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 3,466			$ 3,653
Less: current portion of long-term debt	(526)			(170)
Less: current portion of lease liabilities	(6)			(8)
Total current long-term debt and lease liabilities	(532)			(178)
Total non-current credit facilities, long-term debt and lease liabilities	2,934			3,475
Within one year
Disclosure of detailed information about borrowings [line items]
Lease incentive	12
TAPC Holdings LP bond (Poplar Creek) | Interest rate risk
Disclosure of detailed information about borrowings [line items]
Notional amount	86			95
Committed syndicated bank facility
Disclosure of detailed information about borrowings [line items]
Carrying value	0			32
Notional amount	0			33
Term Facility
Disclosure of detailed information about borrowings [line items]
Carrying value	397			396
Notional amount	400			400
7.3% Medium term notes
Disclosure of detailed information about borrowings [line items]
Carrying value	110			110
Notional amount	110			110
6.9% Medium term notes
Disclosure of detailed information about borrowings [line items]
Carrying value	141			141
Notional amount	141			141
7.8% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	520			533
Notional amount	528			542
6.5% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	391			401
Notional amount	$ 396			407
4.5% Senior notes
Disclosure of detailed information about borrowings [line items]
Carrying value							$ 400
Interest	4.50%	4.50%	4.50%
Melancthon Wolfe Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 168			202
Notional amount	169			203
New Richmond Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	103			112
Notional amount	104			113
Kent Hills Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	193			206
Notional amount	$ 196			209
Interest	4.50%	4.50%	4.50%
Windrise Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 164			170
Notional amount	167			173
Pingston bond
Disclosure of detailed information about borrowings [line items]
Carrying value	39			45
Notional amount	39			45
TAPC Holdings LP bond (Poplar Creek)
Disclosure of detailed information about borrowings [line items]
Carrying value	85			94
Notional amount				95
TEC Hedland PTY Ltd bond(5) | AUD
Disclosure of detailed information about borrowings [line items]
Carrying value	691			711
Notional amount	699			720
TransAlta OCP LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	217			241
Notional amount	218			242
Big Level & Antrim | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	91			102
Notional amount	97	$ 73		108	$ 79
Lakeswind | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	10			15
Notional amount	10	8		15	11
North Carolina Solar | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	3			6
Notional amount	3	2		6	5
Other
Disclosure of detailed information about borrowings [line items]
Carrying value	0			1
Notional amount	0			1
Total long-term debt
Disclosure of detailed information about borrowings [line items]
Carrying value	3,323			3,518
Notional amount	3,363			3,563
Lease liabilities
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 143			$ 135
Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 700			$ 700
South Hedland Bond | AUD
Disclosure of detailed information about borrowings [line items]
Carrying value			$ 773			$ 786
Weighted average | Committed syndicated bank facility
Disclosure of detailed information about borrowings [line items]
Interest	0.00%	0.00%	0.00%	4.70%	4.70%	4.70%
Weighted average | Term Facility
Disclosure of detailed information about borrowings [line items]
Interest	7.40%	7.40%	7.40%	6.50%	6.50%	6.50%
Weighted average | 7.3% Medium term notes
Disclosure of detailed information about borrowings [line items]
Interest	7.30%	7.30%	7.30%	7.30%	7.30%	7.30%
Weighted average | 6.9% Medium term notes
Disclosure of detailed information about borrowings [line items]
Interest	6.90%	6.90%	6.90%	6.90%	6.90%	6.90%
Weighted average | 7.8% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Interest	7.80%	7.80%	7.80%	7.80%	7.80%	7.80%
Weighted average | 6.5% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Interest	6.50%	6.50%	6.50%	6.50%	6.50%	6.50%
Weighted average | Melancthon Wolfe Wind LP bond
Disclosure of detailed information about borrowings [line items]
Interest	3.80%	3.80%	3.80%	3.80%	3.80%	3.80%
Weighted average | New Richmond Wind LP bond
Disclosure of detailed information about borrowings [line items]
Interest	4.00%	4.00%	4.00%	4.00%	4.00%	4.00%
Weighted average | Kent Hills Wind LP bond
Disclosure of detailed information about borrowings [line items]
Interest				4.50%	4.50%	4.50%
Weighted average | Windrise Wind LP bond
Disclosure of detailed information about borrowings [line items]
Interest	3.40%	3.40%	3.40%	3.40%	3.40%	3.40%
Weighted average | Pingston bond
Disclosure of detailed information about borrowings [line items]
Interest	6.20%	6.20%	6.20%	3.00%	3.00%	3.00%
Weighted average | TAPC Holdings LP bond (Poplar Creek)
Disclosure of detailed information about borrowings [line items]
Interest	9.40%	9.40%	9.40%	8.90%	8.90%	8.90%
Weighted average | TEC Hedland PTY Ltd bond(5) | AUD
Disclosure of detailed information about borrowings [line items]
Interest	4.10%	4.10%	4.10%	4.10%	4.10%	4.10%
Weighted average | TransAlta OCP LP bond
Disclosure of detailed information about borrowings [line items]
Interest	4.50%	4.50%	4.50%	4.50%	4.50%	4.50%
Weighted average | Big Level & Antrim | USD
Disclosure of detailed information about borrowings [line items]
Interest	6.60%	6.60%	6.60%	6.60%	6.60%	6.60%
Weighted average | Lakeswind | USD
Disclosure of detailed information about borrowings [line items]
Interest	10.50%	10.50%	10.50%	10.50%	10.50%	10.50%
Weighted average | North Carolina Solar | USD
Disclosure of detailed information about borrowings [line items]
Interest	7.30%	7.30%	7.30%	7.30%	7.30%	7.30%
Weighted average | Other
Disclosure of detailed information about borrowings [line items]
Interest	0.00%	0.00%	0.00%	5.90%	5.90%	5.90%
Borrowings effective interest rate	598.00%	598.00%	598.00%

XML

Credit Facilities, Long-Term Debt and Lease Liabilities - Credit facilities summarized (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of detailed information about borrowings [line items]
Cash drawings	$ 3,466	$ 3,653
Cash collateral	9	260
Committed
Disclosure of detailed information about borrowings [line items]
Facility size	2,590
Outstanding letters of credit	595
Cash drawings	400
Available capacity	1,595
Non-Committed
Disclosure of detailed information about borrowings [line items]
Facility size	400
Outstanding letters of credit	187
Cash drawings	0
Available capacity	213
TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Cash collateral	145
TransAlta syndicated credit facility | Committed
Disclosure of detailed information about borrowings [line items]
Facility size	1,950
Outstanding letters of credit	417
Cash drawings	0
Available capacity	1,533
TransAlta bilateral credit facilities | Committed
Disclosure of detailed information about borrowings [line items]
Facility size	240
Outstanding letters of credit	178
Cash drawings	0
Available capacity	62
TransAlta Term Facility
Disclosure of detailed information about borrowings [line items]
Cash drawings	397	$ 396
TransAlta Term Facility | Committed
Disclosure of detailed information about borrowings [line items]
Facility size	400
Outstanding letters of credit	0
Cash drawings	400
Available capacity	0
TransAlta demand facilities | Non-Committed
Disclosure of detailed information about borrowings [line items]
Facility size	400
Outstanding letters of credit	187
Cash drawings	0
Available capacity	$ 213

XML

Credit Facilities, Long-Term Debt and Lease Liabilities - Credit Facilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about borrowings [line items]
Cash and cash equivalents	$ 348	$ 1,134	$ 947	$ 703
Non-Committed
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	187
Committed syndicated bank facility | Committed credit facilities
Disclosure of detailed information about borrowings [line items]
Undrawn borrowing capacity	1,400	$ 1,000
Committed
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	595
Committed | TransAlta syndicated credit facility
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	417
Committed | TransAlta syndicated credit facility | TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Cash and cash equivalents	$ 345

XML

Credit Facilities, Long-Term Debt and Lease Liabilities - Senior Notes (Details) $ in Millions, $ in Millions	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Nov. 17, 2022 USD ($)	Nov. 15, 2022 CAD ($)
Disclosure of detailed information about borrowings [line items]
Cash drawings	$ 3,466		$ 3,653
Interest rate swap contract [member]
Disclosure of detailed information about borrowings [line items]
Interest					598.20%
Long-term debt | Net investment hedges
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 370		$ 370
7.750 Per cent Senior Notes Due Nov. 15, 2029
Disclosure of detailed information about borrowings [line items]
Cash drawings					$ 400
Interest					775.00%
4.5% Senior notes
Disclosure of detailed information about borrowings [line items]
Cash drawings						$ 400
Interest	4.50%	4.50%

XML

Credit Facilities, Long-Term Debt and Lease Liabilities - Non-Recourse Debt (Details) - Non-recourse Pingston Power Inc Bond - CAD ($) $ in Millions	Sep. 14, 2023	May 08, 2023
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 39	$ 46
Interest	614.50%

XML

Credit Facilities, Long-Term Debt and Lease Liabilities - Restrictions on Non-Recourse Debt and Security (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 AUD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Disclosure of detailed information about borrowings [line items]
Exchangeable securities	$ 744		$ 739
Property, plant and equipment	5,714		5,556	$ 5,320
Intangible assets other than goodwill	223		252	256
Annual cash payments	40		40	$ 40
Annual cash payments, net	37
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash	17		17
Renewable generation facilities
Disclosure of detailed information about borrowings [line items]
Property, plant and equipment	1,500		1,500
Intangible assets other than goodwill	61		70
Non-recourse
Disclosure of detailed information about borrowings [line items]
Exchangeable securities	1,700		1,800
Restricted cash	79		50
Non-recourse | Secured by first rate ranking charge over subsidiaries
Disclosure of detailed information about borrowings [line items]
Notional amount	1,400		1,400
Non-recourse | Secured by equity interests of the issuer
Disclosure of detailed information about borrowings [line items]
Notional amount	85		94
Restricted Use Debt
Disclosure of detailed information about borrowings [line items]
Proceeds received	3	$ 3
Secured Debt | TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 217		$ 241

XML

Credit Facilities, Long-Term Debt and Lease Liabilities - Principal Repayments (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of detailed information about borrowings [line items]
Principal repayments	$ 3,466	$ 3,653
2024
Disclosure of detailed information about borrowings [line items]
Lease incentive	12
Cost
Disclosure of detailed information about borrowings [line items]
Principal repayments	3,363
Lease liabilities	143
Cost | 2024
Disclosure of detailed information about borrowings [line items]
Principal repayments	526
Lease liabilities	4
Cost | 2025
Disclosure of detailed information about borrowings [line items]
Principal repayments	142
Lease liabilities	4
Cost | 2026
Disclosure of detailed information about borrowings [line items]
Principal repayments	143
Lease liabilities	4
Cost | 2027
Disclosure of detailed information about borrowings [line items]
Principal repayments	153
Lease liabilities	4
Cost | 2028
Disclosure of detailed information about borrowings [line items]
Principal repayments	162
Lease liabilities	4
Cost | 2029 and thereafter
Disclosure of detailed information about borrowings [line items]
Principal repayments	2,237
Lease liabilities	$ 123

XML

Credit Facilities, Long-Term Debt and Lease Liabilities - Restricted Cash and Letters of Credit (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Letter of credit
Disclosure of detailed information about borrowings [line items]
Bonds issued	$ 782	$ 1,175
Exercised amount	0	0
Uncommitted demand letter facility
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	187
Committed
Disclosure of detailed information about borrowings [line items]
Facility size	2,590
Outstanding letters of credit	595
Committed | TransAlta syndicated credit facility
Disclosure of detailed information about borrowings [line items]
Facility size	1,950
Outstanding letters of credit	417
Committed | TransAlta bilateral credit facilities
Disclosure of detailed information about borrowings [line items]
Facility size	240
Outstanding letters of credit	178
Non-Committed
Disclosure of detailed information about borrowings [line items]
Facility size	400
Outstanding letters of credit	187
Non-Committed | TransAlta demand facilities
Disclosure of detailed information about borrowings [line items]
Facility size	400
Outstanding letters of credit	187
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash	17	17
TEC
Disclosure of detailed information about borrowings [line items]
Restricted cash	$ 52	$ 53

XML

Credit Facilities, Long-Term Debt and Lease Liabilities - Currency Impacts (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about borrowings [line items]
Net increase (decrease) in borrowings under credit facilities	$ 46	$ (449)	$ 114
USD | Senior Notes and Tax Equity
Disclosure of detailed information about borrowings [line items]
Notional amount	27	41
AUD | Non-Recourse Senior Secured Notes
Disclosure of detailed information about borrowings [line items]
Net increase (decrease) in borrowings under credit facilities	$ (9)	$ (9)

XML

Exchangeable Securities - Narrative (Details) - Brookfield Renewable Partners - Investment Agreement - CAD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Dec. 11, 2023	Mar. 22, 2019	Dec. 31, 2023
Disclosure of detailed information about borrowings [line items]
Proceeds on sale of facilities		$ 750
Dividend declared	$ 7
Fixed rate	1.764%
Minimum ownership interest threshold
Disclosure of detailed information about borrowings [line items]
Ownership interests			8.50%
Hydro | Ownership interest, less than, threshold
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary			49.00%
Hydro | Top up option for ownership interest percentage, 20 day VWAP is not less than $14 per share
Disclosure of detailed information about borrowings [line items]
Additional proportion of ownership interests			10.00%
Hydro | Top Up Option For Ownership Interest Percentage, 20 day VWAP is not less than $17 per share
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary			49.00%
Hydro | Ownership interest threshold exceeded
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary			49.00%
Maximum | Hydro
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary			49.00%
Maximum | Hydro | Top Up Option For Ownership Interest Percentage, 20 day VWAP is not less than $17 per share
Disclosure of detailed information about borrowings [line items]
Weighted average share price (in CAD per shares)			$ 17
Minimum | Hydro | Top Up Option For Ownership Interest Percentage, 20 day VWAP is not less than $17 per share
Disclosure of detailed information about borrowings [line items]
Weighted average share price (in CAD per shares)			$ 14

XML

Exchangeable Securities - Schedule of Exchangeable Securities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	May 01, 2019
Disclosure of detailed information about borrowings [line items]
Total exchangeable securities	$ 2,934	$ 3,475
7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of detailed information about borrowings [line items]
Exchangeable debentures – due May 1, 2039	$ 350	$ 350
Interest	7.00%	7.00%	7.00%
Exchangeable preferred shares	$ 400	$ 400
Total exchangeable securities	750	750
Cost | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of detailed information about borrowings [line items]
Exchangeable debentures – due May 1, 2039	344	339
Exchangeable preferred shares	400	400
Total exchangeable securities	$ 744	$ 739

XML

Exchangeable Securities - Option To Exchange (Details) - Option to exchange – embedded derivative - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of detailed information about borrowings [line items]
Base fair value	$ 0	$ 0
Minimum
Disclosure of detailed information about borrowings [line items]
Sensitivity	0	0
Maximum
Disclosure of detailed information about borrowings [line items]
Sensitivity	$ (25)	$ (25)

XML

Defined Benefit Obligation and Other Long-Term Liabilities - Components of Defined Benefit Obligations and Other Long-term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Defined benefit obligation	$ 155	$ 150
Retail power contract liability	83	126
Other	13	18
Total	$ 251	$ 294

XML

Defined Benefit Obligation and Other Long-Term Liabilities - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 01, 2022 CAD ($)
Disclosure of fair value measurement of liabilities [line items]
Increase (decrease) in defined benefit obligation	$ 5
Defined benefit obligation	155		$ 150
Voluntary contribution	$ 4	$ 3	35
Increase in discount rates	100.00%
Level II | Recurring fair value measurement
Disclosure of fair value measurement of liabilities [line items]
Commodity risk management assets and liabilities	$ (244)		$ 173
Level II | Recurring fair value measurement | retail power contract liabilities
Disclosure of fair value measurement of liabilities [line items]
Commodity risk management assets and liabilities				$ 129
Risk management assets | Level II | Recurring fair value measurement
Disclosure of fair value measurement of liabilities [line items]
Commodity risk management assets and liabilities				$ 139
Pro Forma
Disclosure of fair value measurement of liabilities [line items]
Increase (decrease) in defined benefit obligation	$ 40

XML

Common Shares - Issued and Outstanding (Details) - CAD ($) shares in Millions, $ in Millions			12 Months Ended
	Dec. 31, 2023	Oct. 05, 2023	Dec. 31, 2023	Dec. 31, 2022
Common shares
Provision for repurchase of common shares under ASPP	$ (19)
TransAlta Renewables Inc.
Common shares
Transaction costs		$ 11
TransAlta Renewables Inc. | Issued capital
Common shares
Transaction costs		$ 4	$ 4
Common shares
Common shares
Issued and outstanding, beginning of period			268.1	271.0
Purchased and cancelled under the NCIB			(7.5)	(4.3)
Share-based payment plans			0.8	0.9
Stock options exercised			0.7	0.5
Issued for acquisition of TransAlta Renewables			46.5	0.0
Provision for repurchase of common shares under ASPP			(1.7)
Issued and outstanding, end of year	306.9		306.9	268.1
Issued and outstanding, end of year			$ 2,863	$ 2,901
Purchased and cancelled under the NCIB			(80)	(46)
Share-based payment plans			6	5
Stock options exercised			5	3
Issued for acquisition of TransAlta Renewables			510	0
Provision for repurchase of common shares under ASPP			(19)
Issued and outstanding, end of year	$ 3,285		$ 3,285	$ 2,863
Common shares | Prior To Automatic Share Purchase Plan
Common shares
Issued and outstanding, end of year	308.6		308.6
Issued and outstanding, end of year	$ 3,304		$ 3,304

XML

Common Shares - Normal Course Issuer Bid ("NCIB") Program (Details) $ in Millions	Dec. 31, 2023 CAD ($)
Disclosure of classes of share capital [line items]
Provision for repurchase of common shares under ASPP	$ 19

XML

Common Shares - The effects of the Corporation's purchase and cancellation of the common shares (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	May 26, 2023	May 24, 2022
Disclosure of classes of share capital [line items]
Amount recorded in deficit	$ (2,567)	$ (2,514)
Percentage of public float of common shares			729.00%	716.00%
Shares repurchased but not cancelled	181,800	164,300
Payments for shares repurchased but not cancelled	$ 2	$ 2
Percentage of public float of common shares			729.00%	716.00%
NCIB Program
Disclosure of classes of share capital [line items]
Total shares purchased	7,537,500	4,342,300
Average purchase price per share	$ 11.49	$ 12.48
Total cost (millions)	$ 87	$ 54
Book value of shares cancelled	80	46
Amount recorded in deficit	$ (7)	$ (8)
Repurchase of maximum common shares (in shares)			14,000,000	14,000,000
Repurchase of maximum common shares (in shares)			14,000,000	14,000,000

XML

Common Shares - Shareholder Rights Plan (Details)	12 Months Ended
	Dec. 31, 2023
Shareholder Rights Plan | Common shares | Minimum
Disclosure of classes of share capital [line items]
Common shares acquired	20.00%

XML

Common Shares - Earnings per Common Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions		12 Months Ended
	Nov. 21, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share Capital, Reserves And Other Equity Interest [Abstract]
Net earnings (loss) attributable to common shareholders		$ 644	$ 4	$ (576)
Basic weighted average number of common shares outstanding (in shares)		276	271	271
Diluted weighted average number of common shares outstanding (in shares)		276	271	271
Net earnings (loss) per share attributable to common shareholders, basic (in CAD per share)		$ 2.33	$ 0.01	$ (2.13)
Net earnings (loss) per share attributable to common shareholders, diluted (in CAD per share)		$ 2.33	$ 0.01	$ (2.13)
Dividends declared per share (in CAD per share)	$ 0.06

XML

Preferred Shares - Issued and Outstanding (Details) - CAD ($) shares in Millions, $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Jun. 30, 2022
Preferred Shares
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	38.6	38.6
Number of shares issued (in shares)	38.6	38.6
Amount	$ 942	$ 942
Series A
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	9.6	9.6
Number of shares issued (in shares)	9.6	9.6
Amount	$ 235	$ 235
Series B
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	2.4	2.4
Number of shares issued (in shares)	2.4	2.4
Amount	$ 58	$ 58
Series C
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	10.0	10.0	11.0
Number of shares issued (in shares)	10.0	10.0	11.0
Amount	$ 243	$ 243
Series D
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	1.0	1.0
Number of shares issued (in shares)	1.0	1.0
Amount	$ 26	$ 26
Series E
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	9.0	9.0
Number of shares issued (in shares)	9.0	9.0
Amount	$ 219	$ 219
Series G
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	6.6	6.6
Number of shares issued (in shares)	6.6	6.6
Amount	$ 161	$ 161

XML

Preferred Shares - Series Cumulative Redeemable Rate Reset Preferred Shares Conversion (Details) - shares			12 Months Ended
	Sep. 21, 2022	Jun. 30, 2022	Dec. 31, 2023	Dec. 31, 2022
Series A
Disclosure of classes of share capital [line items]
Number of shares issued (in shares)			9,600,000	9,600,000
Number of shares outstanding (in shares)			9,600,000	9,600,000
Series B
Disclosure of classes of share capital [line items]
Number of shares issued (in shares)			2,400,000	2,400,000
Number of shares outstanding (in shares)			2,400,000	2,400,000
Dividend rate on preference shares			2.00%
Series C
Disclosure of classes of share capital [line items]
Number of shares issued (in shares)		11,000,000	10,000,000.0	10,000,000.0
Number of shares outstanding (in shares)		11,000,000	10,000,000.0	10,000,000.0
Basis spread on variable rate		100.00%
Number of shares converted into other classes of shares (in shares)		1,044,299
Bond yield, period		5 years
Annualized fixed dividend rate		585.40%
Bond yield		275.40%
Dividend rate on preference shares		310.00%
Series D
Disclosure of classes of share capital [line items]
Number of shares issued (in shares)			1,000,000.0	1,000,000.0
Number of shares outstanding (in shares)			1,000,000.0	1,000,000.0
Bond yield, period		5 years
Dividend rate on preference shares		310.00%	3.10%
Series E
Disclosure of classes of share capital [line items]
Number of shares issued (in shares)			9,000,000.0	9,000,000.0
Number of shares outstanding (in shares)			9,000,000.0	9,000,000.0
Number of shares converted into other classes of shares (in shares)	89,945
Required shares conversion (in shares)	1,000,000
Bond yield, period			5 years
Annualized fixed dividend rate			689.40%
Bond yield			324.40%
Dividend rate on preference shares			365.00%

XML

Preferred Shares - Preferred Share Series Information (Details) - Preferred Shares	12 Months Ended
	Dec. 31, 2023 $ / shares
Disclosure of classes of share capital [line items]
Fixed rate reset term	5 years
Amount per share redeemable at reset date (in CAD per share)	$ 25.00

XML

Preferred Shares - Characteristics Specific to Series of Preferred Shares (Details)	12 Months Ended
	Dec. 31, 2023 $ / shares
Series A
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 0.71924
Series A | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	2.03%
Series B
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.718910
Series B | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	2.03%
Series C
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.46352
Series C | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.10%
Series D
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.98695
Series D | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.10%
Series E
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.72352
Series E | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.65%
Series G
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.24700
Series G | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.80%

XML

Preferred Shares - Preferred Share Dividends Declared (Details) - CAD ($) $ / shares in Units, $ in Millions				12 Months Ended
	Dec. 11, 2023	Nov. 21, 2023	Jun. 30, 2022	Dec. 31, 2023	Dec. 31, 2022
Disclosure of classes of share capital [line items]
Dividends declared per share (in CAD per share)		$ 0.06
Series A
Disclosure of classes of share capital [line items]
Total dividends declared				$ 7	$ 7
Dividends declared per share (in CAD per share)	$ 0.17981
Series B
Disclosure of classes of share capital [line items]
Total dividends declared				$ 4	3
Dividend rate on preference shares				2.00%
Dividends declared per share (in CAD per share)	0.43958
Series C
Disclosure of classes of share capital [line items]
Total dividends declared				$ 15	14
Dividend rate on preference shares			310.00%
Dividends declared per share (in CAD per share)	0.36588
Series D
Disclosure of classes of share capital [line items]
Total dividends declared				$ 2	1
Dividend rate on preference shares			310.00%	3.10%
Dividends declared per share (in CAD per share)	0.50609
Series E
Disclosure of classes of share capital [line items]
Total dividends declared				$ 15	13
Dividend rate on preference shares				365.00%
Dividends declared per share (in CAD per share)	0.43088
Series G
Disclosure of classes of share capital [line items]
Total dividends declared				$ 8	8
Dividends declared per share (in CAD per share)	$ 0.31175
Preferred Shares
Disclosure of classes of share capital [line items]
Total dividends declared				$ 51	$ 46

XML

Accumulated Other Comprehensive Loss (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		$ (222)
Currency translation adjustment
(Losses) gains on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		(3)	$ 4
Gains (losses) on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax	[1]	9	(25)	$ 0
Cash flow hedges
Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax	[2]	41	(556)	(200)
Other
Intercompany and third-party investments at FVTOCI		0	(1)
Accumulated other comprehensive income, end of the period		(164)	(222)
Net income tax expense (recovery) relating to gains (losses) on financial instruments		1	(3)	0
Net impact related to cash flow hedges		27	(112)	(57)
Net of income tax expense		1	(12)	(11)
Currency translation adjustment
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(39)	(35)
Currency translation adjustment
(Losses) gains on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		(6)	21
Gains (losses) on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax		9	(25)
Other
Accumulated other comprehensive income, end of the period		(36)	(39)	(35)
Cash flow hedges
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(228)	228
Cash flow hedges
Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax		99	(456)
Other
Accumulated other comprehensive income, end of the period		(129)	(228)	228
Net impact related to cash flow hedges		(27)	112
Employee future benefits
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		8	(29)
Employee future benefits
Net actuarial gains on defined benefit plans, net of tax		(5)	37
Other
Accumulated other comprehensive income, end of the period		3	8	(29)
Net of income tax expense		(1)	12
Other
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		37	(18)
Other
Change in ownership of TransAlta Renewables		(64)
Intercompany and third-party investments at FVTOCI		25	55
Accumulated other comprehensive income, end of the period		$ (2)	$ 37	$ (18)

[1] Net of income tax expense of $1 million for the year ended Dec. 31, 2023 (2022 – $3 million recovery, 2021 – nil).

[2] Net of income tax expense of $10 million for the year ended Dec. 31, 2023 (2022 – $138 million recovery, 2021 – $55 million recovery).

XML

Share-Based Payment Plans - Narrative (Details) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) shares $ / shares	Dec. 31, 2022 CAD ($) $ / shares	Dec. 31, 2021 CAD ($) $ / shares
Executive officers
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of share options granted (in shares)	0.4	0.3	0.7
Weighted average exercise price (in CAD per share) | $ / shares	$ 12.02	$ 12.66	$ 9.86
PSUs and RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Performance period	3 years
Vesting period	3 years
Compensation expense (reversal)	$ 21.0	$ 20.0	$ 14.0
PSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Performance period	3 years
DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Compensation expense (reversal)	$ 1.0	0.0	3.0
Stock Options | Executive officers
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	3 years
Compensation expense (reversal)	$ 1.0	$ 1.0	$ 2.0
Expiration period of shares granted	7 years

XML

Share-Based Payment Plans - Stock Options (Details) - Exercise price range one shares in Millions	Dec. 31, 2023 shares $ / shares	Dec. 31, 2023 shares $ / shares
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Number of options (in shares) | shares	2.5	2.5
Weighted average exercise price (in CAD per share)		$ 9.17
Minimum
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Range of exercise prices (in CAD per share)	$ 5.00
Maximum
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Range of exercise prices (in CAD per share)	$ 12.00

XML

Employee Future Benefits - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2023 age	Dec. 31, 2023	Dec. 31, 2023 Rate	Mar. 31, 2023 CAD ($)
Disclosure of defined benefit plans [line items]
Weighted average duration of defined benefit obligation	10 years 4 months 24 days
Minimum
Disclosure of defined benefit plans [line items]
Employer contribution (as percent)			500.00%
Maximum
Disclosure of defined benefit plans [line items]
Employer contribution (as percent)			1100.00%
Registered | Letter of credit
Disclosure of defined benefit plans [line items]
Letter of credit, posted					$ 88
Registered | Surety Bonds
Disclosure of defined benefit plans [line items]
Letter of credit, posted					$ 70
Other
Disclosure of defined benefit plans [line items]
Maximum age disabled and retired members eligible for benefits		65		65

XML

Employee Future Benefits - Costs Recognized (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	$ 2	$ 2	$ 6
Administration expenses	1	1	1
Defined benefit expense	10	10	6
Defined contribution expense	11	11	8
Net expense	21	21	14
Interest cost on defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost on defined benefit obligation	21	16	14
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest on plan assets	(14)	(9)	(8)
Curtailment and amendment gain			(7)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	1	1	3
Administration expenses	1	1	1
Defined benefit expense	5	6	1
Defined contribution expense	11	11	8
Net expense	16	17	9
Registered | Interest cost on defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost on defined benefit obligation	16	13	12
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest on plan assets	(13)	(9)	(8)
Curtailment and amendment gain			(7)
Supplemental
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	1	1	2
Administration expenses	0	0	0
Defined benefit expense	4	4	4
Defined contribution expense	0	0	0
Net expense	4	4	4
Supplemental | Interest cost on defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost on defined benefit obligation	4	3	2
Supplemental | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest on plan assets	(1)	0	0
Curtailment and amendment gain			0
Other
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	0	0	1
Administration expenses	0	0	0
Defined benefit expense	1	0	1
Defined contribution expense	0	0	0
Net expense	1	0	1
Other | Interest cost on defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost on defined benefit obligation	1	0	0
Other | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest on plan assets	$ 0	$ 0	0
Curtailment and amendment gain			$ 0

XML

Employee Future Benefits - Status of Plans (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	$ (162)	$ (158)
Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(7)	(8)
Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(155)	(150)
Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	284	289	$ 353
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(446)	(447)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(71)	(71)
Registered | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(1)	(1)
Registered | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(70)	(70)
Registered | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	269	274	339
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(340)	(345)	(469)
Supplemental
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(74)	(70)
Supplemental | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(5)	(6)
Supplemental | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(69)	(64)
Supplemental | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	15	15	14
Supplemental | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(89)	(85)	(101)
Other
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(17)	(17)
Other | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(1)	(1)
Other | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(16)	(16)
Other | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	0	0	0
Other | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	$ (17)	$ (17)	$ (23)

XML

Employee Future Benefits - Fair Value of Plan Assets (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period		$ (158)
Administration expenses		(1)	$ (1)	$ (1)
Net asset, ending of period		(162)	(158)
Voluntary contribution	$ 3	4	35
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period		289	353
Interest on plan assets		14	9
Net loss on plan assets		14	(55)
Contributions		13	44
Benefits paid		(44)	(62)
Change in foreign exchange rates		(1)	1
Net asset, ending of period		284	289	353
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period		(71)
Administration expenses		(1)	(1)	(1)
Net asset, ending of period		(71)	(71)
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period		274	339
Interest on plan assets		13	9
Net loss on plan assets		15	(55)
Contributions		5	38
Benefits paid		(36)	(57)
Change in foreign exchange rates		(1)	1
Net asset, ending of period		269	274	339
Supplemental
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period		(70)
Administration expenses		0	0	0
Net asset, ending of period		(74)	(70)
Supplemental | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period		15	14
Interest on plan assets		1	0
Net loss on plan assets		(1)	0
Contributions		6	6
Benefits paid		(6)	(5)
Change in foreign exchange rates		0	0
Net asset, ending of period		15	15	14
Other
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period		(17)
Administration expenses		0	0	0
Net asset, ending of period		(17)	(17)
Other | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period		0	0
Interest on plan assets		0	0
Net loss on plan assets		0	0
Contributions		2	0
Benefits paid		(2)	0
Change in foreign exchange rates		0	0
Net asset, ending of period		$ 0	$ 0	$ 0

XML

Employee Future Benefits - Fair Value of Plan Assets by Major Category (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of fair value of plan assets [line items]
Loans(1)	$ 2	$ 2
Alternative funds	44	39
Money market and cash and cash equivalents	21	20
Total	284	289
Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	12	18
US
Disclosure of fair value of plan assets [line items]
Equity securities	6	17
International
Disclosure of fair value of plan assets [line items]
Equity securities	86	79
Private
Disclosure of fair value of plan assets [line items]
Equity securities	1	1
A - AAA
Disclosure of fair value of plan assets [line items]
Bonds	92	88
BBB
Disclosure of fair value of plan assets [line items]
Bonds	16	19
Loans(1)		1
Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	4	6
A
Disclosure of fair value of plan assets [line items]
Loans(1)	1	1
Level I
Disclosure of fair value of plan assets [line items]
Loans(1)	0	0
Alternative funds	0	0
Money market and cash and cash equivalents	2	0
Total	3	1
Level I | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level I | US
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level I | International
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level I | Private
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level I | A - AAA
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Level I | BBB
Disclosure of fair value of plan assets [line items]
Bonds	1	1
Level I | Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Level II
Disclosure of fair value of plan assets [line items]
Loans(1)	2	2
Alternative funds	0	0
Money market and cash and cash equivalents	19	20
Total	160	169
Level II | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	12	18
Level II | US
Disclosure of fair value of plan assets [line items]
Equity securities	6	17
Level II | International
Disclosure of fair value of plan assets [line items]
Equity securities	86	79
Level II | Private
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level II | A - AAA
Disclosure of fair value of plan assets [line items]
Bonds	30	27
Level II | BBB
Disclosure of fair value of plan assets [line items]
Bonds	5	6
Level II | Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Level III
Disclosure of fair value of plan assets [line items]
Loans(1)	0	0
Alternative funds	44	39
Money market and cash and cash equivalents	0	0
Total	121	119
Level III | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level III | US
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level III | International
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level III | Private
Disclosure of fair value of plan assets [line items]
Equity securities	1	1
Level III | A - AAA
Disclosure of fair value of plan assets [line items]
Bonds	62	61
Level III | BBB
Disclosure of fair value of plan assets [line items]
Bonds	10	12
Level III | Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	$ 4	$ 6

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Employee Future Benefits - Defined Benefit Obligation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	$ 158
Actuarial loss arising from demographic assumptions	5	$ (37)
Defined benefit obligation, ending of period	162	158
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	447
Defined benefit obligation, ending of period	446	447
Registered
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	71
Defined benefit obligation, ending of period	71	71
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	345	469
Current service cost	1	1
Interest cost	16	13
Benefits paid	(36)	(57)
Actuarial loss arising from demographic assumptions	1
Actuarial gain arising from financial assumptions	12	(83)
Actuarial loss arising from experience adjustments	2	1
Change in foreign exchange rates	(1)	1
Defined benefit obligation, ending of period	340	345
Supplemental
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	70
Defined benefit obligation, ending of period	74	70
Supplemental | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	85	101
Current service cost	1	1
Interest cost	4	3
Benefits paid	(6)	(5)
Actuarial loss arising from demographic assumptions	0
Actuarial gain arising from financial assumptions	4	(22)
Actuarial loss arising from experience adjustments	1	7
Change in foreign exchange rates	0	0
Defined benefit obligation, ending of period	89	85
Other
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	17
Defined benefit obligation, ending of period	17	17
Other | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	17	23
Current service cost	0	0
Interest cost	1	0
Benefits paid	(2)	1
Actuarial loss arising from demographic assumptions	0
Actuarial gain arising from financial assumptions	1	(5)
Actuarial loss arising from experience adjustments	0	(2)
Change in foreign exchange rates	0	0
Defined benefit obligation, ending of period	17	17
Total | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	447	593
Current service cost	2	2
Interest cost	21	16
Benefits paid	(44)	(61)
Actuarial loss arising from demographic assumptions	1
Actuarial gain arising from financial assumptions	17	(110)
Actuarial loss arising from experience adjustments	3	6
Change in foreign exchange rates	(1)	1
Defined benefit obligation, ending of period	$ 446	$ 447

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Employee Future Benefits - Contributions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)
Registered
Disclosure of defined benefit plans [line items]
Expected employer contributions	$ 3
Supplemental
Disclosure of defined benefit plans [line items]
Expected employer contributions	5
Other
Disclosure of defined benefit plans [line items]
Expected employer contributions	1
Total
Disclosure of defined benefit plans [line items]
Expected employer contributions	$ 9

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Employee Future Benefits - Assumptions (Details)	12 Months Ended
	Dec. 31, 2023 age	Dec. 31, 2023 Rate	Dec. 31, 2022 Rate
Other, through 2027
Assumed health-care cost trend rate
Health-care cost escalation	4.50%	4.50%
Maximum age disabled and retired members eligible for benefits	65	65
Percentage of reasonably possible decrease in actuarial assumption	0.30%	0.30%
Other Post-Employment Benefit Plans, through 2032
Assumed health-care cost trend rate
Health-care cost escalation	4.50%	4.50%	450.00%
Maximum age disabled and retired members eligible for benefits		65	65
Percentage of reasonably possible decrease in actuarial assumption	0.30%	0.30%	30.00%
Other Post-Employment Benefit Plans, through 2032 | Canada
Assumed health-care cost trend rate
Health-care cost escalation	4.50%	4.50%	450.00%
Other, 2030 through 2031
Assumed health-care cost trend rate
Health-care cost escalation			450.00%
Maximum age disabled and retired members eligible for benefits			65
Percentage of reasonably possible decrease in actuarial assumption			30.00%
Other, 2030 through 2031 | Canada
Assumed health-care cost trend rate
Health-care cost escalation			4.50%
Accrued Benefit Obligation | Registered
Disclosure of defined benefit plans [line items]
Discount rate	4.60%	4.60%	4.70%
Rate of compensation increase	2.90%	2.90%	2.60%
Assumed health-care cost trend rate
Health-care cost escalation	0.00%	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%	0.00%
Accrued Benefit Obligation | Supplemental
Disclosure of defined benefit plans [line items]
Discount rate	4.60%	4.60%	5.00%
Rate of compensation increase	3.00%	3.00%	3.00%
Assumed health-care cost trend rate
Health-care cost escalation	0.00%	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%	0.00%
Accrued Benefit Obligation | Other, through 2027
Disclosure of defined benefit plans [line items]
Discount rate	4.70%	4.70%	5.00%
Rate of compensation increase	0.00%	0.00%	0.00%
Assumed health-care cost trend rate
Health-care cost escalation	6.80%	6.80%	7.10%
Dental-care cost escalation	4.20%	4.20%	4.20%
Other, through 2027 | Registered
Disclosure of defined benefit plans [line items]
Discount rate	5.00%	5.00%	2.80%
Rate of compensation increase	2.70%	2.70%	2.90%
Assumed health-care cost trend rate
Health-care cost escalation	0.00%	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%	0.00%
Other, through 2027 | Supplemental
Disclosure of defined benefit plans [line items]
Discount rate	5.00%	5.00%	2.80%
Rate of compensation increase	3.00%	3.00%	3.00%
Assumed health-care cost trend rate
Health-care cost escalation	0.00%	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%	0.00%
Other, through 2027 | Other, through 2027
Disclosure of defined benefit plans [line items]
Discount rate	5.00%	5.00%	2.70%
Rate of compensation increase	0.00%	0.00%	0.00%
Assumed health-care cost trend rate
Health-care cost escalation	7.10%	7.10%	6.80%
Dental-care cost escalation	4.70%	4.70%	4.70%

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Employee Future Benefits - Sensitivity Analysis (Details) $ in Millions	Dec. 31, 2023 CAD ($)
1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible increase in actuarial assumption (as percent)	1.00%
1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible increase in actuarial assumption (as percent)	1.00%
1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible increase in actuarial assumption (as percent)	1.00%
10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible increase in actuarial assumption (as percent)	10.00%
Registered Pension Plan | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	$ 30
Registered Pension Plan | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1
Registered Pension Plan | Canada | 1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Registered Pension Plan | Canada | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	13
Registered Pension Plan | US | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	2
Registered Pension Plan | US | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Registered Pension Plan | US | 1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Registered Pension Plan | US | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1
Supplemental | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	10
Supplemental | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Supplemental | Canada | 1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Supplemental | Canada | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	3
Other | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1
Other | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Other | Canada | 1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1
Other | Canada | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	$ 0

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Joint Arrangements (Details)	12 Months Ended
	Dec. 31, 2023
Wind and Solar | Skookumchuck
Disclosure of joint operations [line items]
Proportion of ownership interest in joint venture	49.00%
Hydro | Tent Mountain
Disclosure of joint operations [line items]
Proportion of ownership interest in joint venture	50.00%
Sheerness | Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Goldfields Power | Australian Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Fort Saskatchewan | Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	60.00%
Fortescue River Gas Pipeline | Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	43.00%
McBride Lake | Wind and Solar
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Soderglen | Wind and Solar
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Pingston | Hydro
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%

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Cash Flow Information - Disclosure of Non-cash Operating Working Capital (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of cash flow statement [Abstract]
Accounts receivable	$ 715	$ (869)	$ (28)
Prepaid expenses	0	0	9
Income taxes receivable	27	(61)	0
Inventory	(2)	6	42
Accounts payable, accrued liabilities and provisions	(550)	548	153
Income taxes payable	(66)	60	(2)
Change in non-cash operating working capital	$ 124	$ (316)	$ 174

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Cash Flow Information Changes in Liabilities from Financing Activities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	$ 4,476	$ 4,064
Cash issuances	39	981
Repayments and dividends paid	(329)	(727)
New leases	5	40
Dividends declared	116	103
Foreign exchange impact	(36)	39
Other	(9)	(24)
Balance at end of the period	4,262	4,476	$ 4,064
Net increase (decrease) in borrowings under credit facilities	(46)	449	(114)
Issuance of long-term debt	39	532	173
Repayment of long-term debt	(164)	(621)	(92)
Decrease in lease liabilities	(10)	(9)	(8)
Long-term debt and lease liabilities
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	3,669	3,267
Cash issuances	39	981
Repayments and dividends paid	(220)	(630)
New leases	5	40
Dividends declared	0	0
Foreign exchange impact	(36)	39
Other	12	(28)
Balance at end of the period	3,469	3,669	3,267
Exchangeable securities
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	739	735
Cash issuances	0	0
Repayments and dividends paid	0	0
New leases	0	0
Dividends declared	0	0
Foreign exchange impact	0	0
Other	5	4
Balance at end of the period	744	739	735
Dividends payable (common and preferred)
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	68	62
Cash issuances	0	0
Repayments and dividends paid	(109)	(97)
New leases	0	0
Dividends declared	116	103
Foreign exchange impact	0	0
Other	(26)	0
Balance at end of the period	$ 49	$ 68	$ 62

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Capital - Disclosure of Components of Capital (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of components of capital [Line Items]
Long-term debt		$ 3,466	$ 3,653
Increase (decrease) in long-term debt		(187)
Exchangeable securities		744	739
Increase (decrease) in exchangeable securities		5
Bank overdraft		3	16
Increase (decrease) in bank overdrafts		(13)
Equity		1,664	1,989	$ 2,593
Less: available cash and cash equivalents(2)		(348)	(1,134)
Increase (decrease) in available cash and cash equivalents		786
Less: principal portion of restricted cash on TransAlta OCP bonds		(69)	(70)
Less: fair value liability (asset) of hedging instruments on long-term debt		5
Less: fair value asset of hedging instruments on long-term debt			(3)
Increase (decrease) in fair value asset of hedging instruments on long-term debt		8
Total capital		5,517	5,243
Increase (decrease) in total capital		274
Common shares
Disclosure of components of capital [Line Items]
Equity		3,285	2,863
Increase (decrease) in equity		422
Preferred shares
Disclosure of components of capital [Line Items]
Equity		942	942
Increase (decrease) in equity		0
Contributed surplus
Disclosure of components of capital [Line Items]
Equity		41	41	46
Increase (decrease) in equity		0
Deficit
Disclosure of components of capital [Line Items]
Equity		(2,567)	(2,514)	(2,453)
Increase (decrease) in equity		(53)
Accumulated other comprehensive income (loss)
Disclosure of components of capital [Line Items]
Equity	[1]	(164)	(222)	146
Increase (decrease) in equity		58
Non-controlling interests
Disclosure of components of capital [Line Items]
Equity		127	879	$ 1,011
Increase (decrease) in equity		(752)
TransAlta OCP
Disclosure of components of capital [Line Items]
Less: principal portion of restricted cash on TransAlta OCP bonds		(17)	$ (17)
Increase (decrease) in principal portion of restricted cash on TransAlta OCP bonds		$ 0

[1] (1)Refer to Note 29 for details on components of and changes in, accumulated other comprehensive income (loss).

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Capital - Disclosure of Cash Flow Statement (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of classes of share capital [line items]
Cash flow from operating activities	$ 1,464	$ 877	$ 1,001
Increase (decrease) in cash flow from operating activities	587
Change in non-cash working capital	(124)	316	(174)
Increase (decrease) in change in non-cash working capital	(440)
Cash flow from operations before changes in working capital	1,340	1,193	827
Increase (decrease) in cash flow from operations before changes in working capital	147
Distributions paid to subsidiaries’ non-controlling interests	223	187	156
Increase (decrease) in dividends paid to non controlling interests	(36)
Property, plant and equipment expenditures	875	918	480
Increase (decrease) in property, plant and equipment expenditure	43
Net inflows (outflows) of cash	133	(9)
Increase (decrease) in net inflows (outflows) of cash	142
Committed syndicated bank facility | Committed credit facilities
Disclosure of classes of share capital [line items]
Undrawn borrowing capacity	1,400	1,000
Common shares
Disclosure of classes of share capital [line items]
Dividends paid	58	54	48
Increase (decrease) in dividends paid	(4)
Preferred shares
Disclosure of classes of share capital [line items]
Dividends paid	51	$ 43	$ 39
Increase (decrease) in dividends paid	$ (8)

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Related Party Transactions - Disclosure of Interests in Subsidiaries (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Canada | TransAlta Generation Partnership
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100.00%
Canada | TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	50.01%
Canada | TransAlta Energy Marketing Corp.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100.00%
Canada | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100.00%	60.10%
US | Skookumchuck
Disclosure of subsidiaries [line items]
Proportion of ownership interest in joint venture	49.00%
US | TransAlta Centralia Generation, LLC
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100.00%
US | TransAlta Energy Marketing (U.S.), Inc.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100.00%
Australia | TransAlta Energy (Australia), Pty Ltd.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100.00%

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Related Party Transactions - Disclosure of Information about Key Management Personnel (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party [Abstract]
Total compensation	$ 21	$ 23	$ 30
Short-term employee benefits	11	11	14
Post-employment benefits	1	1	1
Termination benefits	1	0	0
Share-based payments	$ 8	$ 11	$ 15

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Related Party Transactions - Disclosure of Transactions with Associates (Details) - Associates - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of transactions between related parties [line items]
Power sales	$ 135	$ 127	$ 27
Purchased power	2	12	3
Asset management fees paid	$ 1	$ 2	$ 2

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Commitments and Contingencies - Commitments (Details) $ in Millions	Dec. 31, 2023 CAD ($)
Disclosure of Commitments [Line Items]
Coal supply agreements	$ 157
Long-term service agreements	424
Operating leases	37
Growth	47
Total	1,486
Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	695
Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	126
2024
Disclosure of Commitments [Line Items]
Coal supply agreements	86
Long-term service agreements	60
Operating leases	3
Growth	47
Total	260
2024 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	55
2024 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	9
2025
Disclosure of Commitments [Line Items]
Coal supply agreements	71
Long-term service agreements	57
Operating leases	3
Growth	0
Total	189
2025 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	49
2025 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	9
2026
Disclosure of Commitments [Line Items]
Coal supply agreements	0
Long-term service agreements	42
Operating leases	2
Growth	0
Total	100
2026 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	50
2026 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	6
2027
Disclosure of Commitments [Line Items]
Coal supply agreements	0
Long-term service agreements	44
Operating leases	2
Growth	0
Total	98
2027 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	48
2027 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	4
2028
Disclosure of Commitments [Line Items]
Coal supply agreements	0
Long-term service agreements	37
Operating leases	2
Growth	0
Total	101
2028 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	57
2028 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	5
2029 and thereafter
Disclosure of Commitments [Line Items]
Coal supply agreements	0
Long-term service agreements	184
Operating leases	25
Growth	0
Total	738
2029 and thereafter | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	436
2029 and thereafter | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	$ 93

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Commitments and Contingencies - Narrative (Details) TJ in Millions	Dec. 31, 2023 TJ
Disclosure of Commitments [Line Items]
Total firm natural gas transportation	75
Pioneer Pipeline
Disclosure of Commitments [Line Items]
Total firm natural gas transportation	400

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Segments Disclosures - Additional Information (Details) - segment	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of major customers [line items]
Number of segments	6
Customer 1
Disclosure of major customers [line items]
Percentage of entity's revenue	46.00%	60.00%

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Segments Disclosures - Reported Segment Earnings (Loss) and Segment Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of operating segments [line items]
Revenue	$ 3,355	$ 2,976	$ 2,721
Fuel and purchased power	1,060	1,263	1,054
Carbon compliance	112	78	178
Gross margin	2,183	1,635	1,489
OM&A			511
Taxes, other than income taxes	29	33	32
Net other operating loss (income)	(47)	(58)	8
Equity income	4	9	9
Finance lease income	12	19	25
Depreciation and amortization	(621)	(599)	(529)
Asset impairment charges	48	(9)	(648)
Interest income	59	24	11
Interest expense	281	286	256
Foreign exchange gain (loss)	(7)	4	16
Gain on sale of assets and other	4	52	54
Earnings (loss) before income taxes	880	353	(380)
Previously Reported
Disclosure of operating segments [line items]
Revenue	3,355	2,976	2,721
Fuel and purchased power	1,060	1,263	1,054
OM&A	539	521	511
Net other operating loss (income)	(47)	(58)	8
Operating segments
Disclosure of operating segments [line items]
Revenue	3,326	3,475	2,791
Fuel and purchased power	1,056	1,259	843
Carbon compliance	112	78	178
Gross margin	2,158	2,138	1,770
OM&A			491
Taxes, other than income taxes	30	35	33
Net other operating loss (income)	(46)	(54)	(40)
Adjusted EBITDA	1,632	1,634	1,286
Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenue	3,376	2,990	2,739
Fuel and purchased power	1,060	1,263	1,054
OM&A	542	523	513
Net other operating loss (income)	(47)	(61)	8
Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenue	(37)	378	(34)
Operating segments | Realized gain (loss) on closed exchange positions
Disclosure of operating segments [line items]
Revenue	(81)	43	23
Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenue	55	46	41
Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenue	12	19	25
Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenue	1	(1)	(3)
Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	(4)	(4)	(4)
Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating loss (income)	1	7
Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power			(190)
Operating segments | Coal inventory writedown
Disclosure of operating segments [line items]
Fuel and purchased power			(17)
Operating segments | Parts and materials writedown
Disclosure of operating segments [line items]
OM&A			(28)
Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A			6
Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating loss (income)			(48)
Material reconciling items
Disclosure of operating segments [line items]
Revenue	50	(485)	(52)
Fuel and purchased power	4	4	211
Carbon compliance	0	0	0
Gross margin	46	(489)	(263)
OM&A			22
Taxes, other than income taxes	0	0	0
Net other operating loss (income)	(1)	(7)	48
Material reconciling items | Previously Reported
Disclosure of operating segments [line items]
Revenue	0	0	0
Fuel and purchased power	0	0	0
OM&A	0	0	0
Net other operating loss (income)	0	0	0
Material reconciling items | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenue	37	(378)	34
Material reconciling items | Realized gain (loss) on closed exchange positions
Disclosure of operating segments [line items]
Revenue	81	(43)	(23)
Material reconciling items | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenue	(55)	(46)	(41)
Material reconciling items | Finance lease income
Disclosure of operating segments [line items]
Revenue	(12)	(19)	(25)
Material reconciling items | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenue	(1)	1	3
Material reconciling items | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	4	4	4
Material reconciling items | Insurance recovery
Disclosure of operating segments [line items]
Net other operating loss (income)	(1)	(7)
Material reconciling items | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power			190
Material reconciling items | Coal inventory writedown
Disclosure of operating segments [line items]
Fuel and purchased power			17
Material reconciling items | Parts and materials writedown
Disclosure of operating segments [line items]
OM&A			28
Material reconciling items | Curtailment gain
Disclosure of operating segments [line items]
OM&A			(6)
Material reconciling items | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating loss (income)			48
Material reconciling items | Contribution from equity accounted investments
Disclosure of operating segments [line items]
Revenue	(21)	(14)	(18)
Fuel and purchased power	0	0	0
Carbon compliance	0	0	0
Gross margin	(21)	(14)	(18)
OM&A			(2)
Taxes, other than income taxes	(1)	(2)	(1)
Net other operating loss (income)	0	3	0
Material reconciling items | Contribution from equity accounted investments | Previously Reported
Disclosure of operating segments [line items]
Revenue	(21)	(14)	(18)
Fuel and purchased power	0	0	0
OM&A	(3)	(2)	(2)
Net other operating loss (income)	0	3	0
Material reconciling items | Contribution from equity accounted investments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenue	0	0	0
Material reconciling items | Contribution from equity accounted investments | Realized gain (loss) on closed exchange positions
Disclosure of operating segments [line items]
Revenue	0	0	0
Material reconciling items | Contribution from equity accounted investments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenue	0	0	0
Material reconciling items | Contribution from equity accounted investments | Finance lease income
Disclosure of operating segments [line items]
Revenue	0	0	0
Material reconciling items | Contribution from equity accounted investments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenue	0	0	0
Material reconciling items | Contribution from equity accounted investments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Material reconciling items | Contribution from equity accounted investments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating loss (income)	0	0
Material reconciling items | Contribution from equity accounted investments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power			0
Material reconciling items | Contribution from equity accounted investments | Coal inventory writedown
Disclosure of operating segments [line items]
Fuel and purchased power			0
Material reconciling items | Contribution from equity accounted investments | Parts and materials writedown
Disclosure of operating segments [line items]
OM&A			0
Material reconciling items | Contribution from equity accounted investments | Curtailment gain
Disclosure of operating segments [line items]
OM&A			0
Material reconciling items | Contribution from equity accounted investments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating loss (income)			0
Hydro | Operating segments
Disclosure of operating segments [line items]
Revenue	529	607	383
Fuel and purchased power	19	22	16
Carbon compliance	0	0	0
Gross margin	510	585	367
OM&A			42
Taxes, other than income taxes	3	3	3
Net other operating loss (income)	0	0	0
Adjusted EBITDA	459	527	322
Hydro | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenue	533	606	383
Fuel and purchased power	19	22	16
OM&A	48	55	42
Net other operating loss (income)	0	0	0
Hydro | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenue	(4)	1	0
Hydro | Operating segments | Realized gain (loss) on closed exchange positions
Disclosure of operating segments [line items]
Revenue	0	0	0
Hydro | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenue	0	0	0
Hydro | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenue	0	0	0
Hydro | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenue	0	0	0
Hydro | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Hydro | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating loss (income)	0	0
Hydro | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power			0
Hydro | Operating segments | Coal inventory writedown
Disclosure of operating segments [line items]
Fuel and purchased power			0
Hydro | Operating segments | Parts and materials writedown
Disclosure of operating segments [line items]
OM&A			0
Hydro | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A			0
Hydro | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating loss (income)			0
Wind and Solar | Operating segments
Disclosure of operating segments [line items]
Revenue	373	407	348
Fuel and purchased power	30	31	17
Carbon compliance	0	1	0
Gross margin	343	375	331
OM&A			59
Taxes, other than income taxes	12	12	10
Net other operating loss (income)	(6)	(16)	0
Adjusted EBITDA	257	311	262
Wind and Solar | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenue	357	303	323
Fuel and purchased power	30	31	17
OM&A	80	68	59
Net other operating loss (income)	(7)	(23)	0
Wind and Solar | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenue	16	104	25
Wind and Solar | Operating segments | Realized gain (loss) on closed exchange positions
Disclosure of operating segments [line items]
Revenue	0	0	0
Wind and Solar | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenue	0	0	0
Wind and Solar | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenue	0	0	0
Wind and Solar | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenue	0	0	0
Wind and Solar | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Wind and Solar | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating loss (income)	1	7
Wind and Solar | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power			0
Wind and Solar | Operating segments | Coal inventory writedown
Disclosure of operating segments [line items]
Fuel and purchased power			0
Wind and Solar | Operating segments | Parts and materials writedown
Disclosure of operating segments [line items]
OM&A			0
Wind and Solar | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A			0
Wind and Solar | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating loss (income)			0
Gas | Operating segments
Disclosure of operating segments [line items]
Revenue	1,525	1,521	1,126
Fuel and purchased power	449	637	374
Carbon compliance	112	83	118
Gross margin	964	801	634
OM&A			173
Taxes, other than income taxes	11	15	13
Net other operating loss (income)	(40)	(38)	(40)
Adjusted EBITDA	801	629	488
Gas | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenue	1,514	1,209	1,109
Fuel and purchased power	453	641	457
OM&A	192	195	175
Net other operating loss (income)	(40)	(38)	(40)
Gas | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenue	(67)	251	(40)
Gas | Operating segments | Realized gain (loss) on closed exchange positions
Disclosure of operating segments [line items]
Revenue	10	(4)	(6)
Gas | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenue	55	46	41
Gas | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenue	12	19	25
Gas | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenue	1	0	(3)
Gas | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	(4)	(4)	(4)
Gas | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating loss (income)	0	0
Gas | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power			(79)
Gas | Operating segments | Coal inventory writedown
Disclosure of operating segments [line items]
Fuel and purchased power			0
Gas | Operating segments | Parts and materials writedown
Disclosure of operating segments [line items]
OM&A			(2)
Gas | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A			0
Gas | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating loss (income)			0
Energy Transition
Disclosure of operating segments [line items]
Asset impairment charges			(191)
Energy Transition | Operating segments
Disclosure of operating segments [line items]
Revenue	746	724	728
Fuel and purchased power	557	566	432
Carbon compliance	0	(1)	60
Gross margin	189	159	236
OM&A			97
Taxes, other than income taxes	3	4	6
Net other operating loss (income)	0	0	0
Adjusted EBITDA	122	86	133
Energy Transition | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenue	751	714	709
Fuel and purchased power	557	566	560
OM&A	64	69	117
Net other operating loss (income)	0	0	48
Energy Transition | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenue	(5)	10	19
Energy Transition | Operating segments | Realized gain (loss) on closed exchange positions
Disclosure of operating segments [line items]
Revenue	0	0	0
Energy Transition | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenue	0	0	0
Energy Transition | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenue	0	0	0
Energy Transition | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenue	0	0	0
Energy Transition | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Energy Transition | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating loss (income)	0	0
Energy Transition | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power			(111)
Energy Transition | Operating segments | Coal inventory writedown
Disclosure of operating segments [line items]
Fuel and purchased power			(17)
Energy Transition | Operating segments | Parts and materials writedown
Disclosure of operating segments [line items]
OM&A			(26)
Energy Transition | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A			6
Energy Transition | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating loss (income)			(48)
Energy Marketing | Operating segments
Disclosure of operating segments [line items]
Revenue	152	218	202
Fuel and purchased power	0	0	0
Carbon compliance	0	0	0
Gross margin	152	218	202
OM&A			36
Taxes, other than income taxes	0	0	0
Net other operating loss (income)	0	0	0
Adjusted EBITDA	109	183	166
Energy Marketing | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenue	220	160	211
Fuel and purchased power	0	0	0
OM&A	43	35	36
Net other operating loss (income)	0	0	0
Energy Marketing | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenue	23	12	(38)
Energy Marketing | Operating segments | Realized gain (loss) on closed exchange positions
Disclosure of operating segments [line items]
Revenue	(91)	47	29
Energy Marketing | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenue	0	0	0
Energy Marketing | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenue	0	0	0
Energy Marketing | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenue	0	(1)	0
Energy Marketing | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Energy Marketing | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating loss (income)	0	0
Energy Marketing | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power			0
Energy Marketing | Operating segments | Coal inventory writedown
Disclosure of operating segments [line items]
Fuel and purchased power			0
Energy Marketing | Operating segments | Parts and materials writedown
Disclosure of operating segments [line items]
OM&A			0
Energy Marketing | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A			0
Energy Marketing | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating loss (income)			0
Corporate | Operating segments
Disclosure of operating segments [line items]
Revenue	1	(2)	4
Fuel and purchased power	1	3	4
Carbon compliance	0	(5)	0
Gross margin	0	0	0
OM&A			84
Taxes, other than income taxes	1	1	1
Net other operating loss (income)	0	0	0
Adjusted EBITDA	(116)	(102)	(85)
Corporate | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenue	1	(2)	4
Fuel and purchased power	1	3	4
OM&A	115	101	84
Net other operating loss (income)	0	0	0
Corporate | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenue	0	0	0
Corporate | Operating segments | Realized gain (loss) on closed exchange positions
Disclosure of operating segments [line items]
Revenue	0	0	0
Corporate | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenue	0	0	0
Corporate | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenue	0	0	0
Corporate | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenue	0	0	0
Corporate | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Corporate | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating loss (income)	$ 0	$ 0
Corporate | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power			0
Corporate | Operating segments | Coal inventory writedown
Disclosure of operating segments [line items]
Fuel and purchased power			0
Corporate | Operating segments | Parts and materials writedown
Disclosure of operating segments [line items]
OM&A			0
Corporate | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A			0
Corporate | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating loss (income)			$ 0

XML

Segments Disclosures - Selected Consolidated Statements of Financial Position Information (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of operating segments [line items]
PP&E	$ 5,714	$ 5,556	$ 5,320
Right-of-use assets	117	126	95
Intangible assets	223	252	$ 256
Goodwill	464	464
Wind and Solar
Disclosure of operating segments [line items]
Goodwill	176	176
Energy Marketing
Disclosure of operating segments [line items]
Goodwill	30	30
Corporate
Disclosure of operating segments [line items]
PP&E	98	111
Right-of-use assets	11	14
Intangible assets	31	31
Goodwill	0	0
Operating segments | Hydro
Disclosure of operating segments [line items]
PP&E	462	437
Right-of-use assets	7	6
Intangible assets	2	2
Goodwill	258	258
Operating segments | Wind and Solar
Disclosure of operating segments [line items]
PP&E	3,360	2,837
Right-of-use assets	94	98
Intangible assets	141	157
Goodwill	176	176
Operating segments | Gas
Disclosure of operating segments [line items]
PP&E	1,543	1,858
Right-of-use assets	5	6
Intangible assets	40	49
Goodwill	0	0
Operating segments | Energy Transition
Disclosure of operating segments [line items]
PP&E	251	313
Right-of-use assets	0	2
Intangible assets	4	5
Goodwill	0	0
Operating segments | Energy Marketing
Disclosure of operating segments [line items]
PP&E	0	0
Right-of-use assets	0	0
Intangible assets	5	8
Goodwill	$ 30	$ 30

XML

Segments Disclosures - Additions to non-current assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of operating segments [line items]
PP&E	$ 875	$ 918	$ 480
Intangible assets	13	31	9
Corporate
Disclosure of operating segments [line items]
PP&E	54	75	28
Intangible assets	13	9	8
Operating segments | Hydro
Disclosure of operating segments [line items]
PP&E	42	36	29
Intangible assets	0	0	0
Operating segments | Wind and Solar
Disclosure of operating segments [line items]
PP&E	674	745	166
Intangible assets	0	19	0
Operating segments | Gas
Disclosure of operating segments [line items]
PP&E	89	43	167
Intangible assets	0	0	0
Operating segments | Energy Transition
Disclosure of operating segments [line items]
PP&E	16	19	90
Intangible assets	0	0	1
Operating segments | Energy Marketing
Disclosure of operating segments [line items]
PP&E	0	0	0
Intangible assets	$ 0	$ 3	$ 0

XML

Segments Disclosures - Depreciation and Amortization on the Consolidated Statements of Cash Flows (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of operating segments [abstract]
Depreciation and amortization expense on the Consolidated Statements of Earnings (Loss)	$ 621	$ 599	$ 529
Depreciation included in fuel and purchased power (Note 6)	0	0	190
Depreciation and amortization on the Consolidated Statements of Cash Flows	$ 621	$ 599	$ 719

XML

Segments Disclosures - Geographic Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of geographical areas [line items]
Total revenue from contracts with customers	$ 3,355	$ 2,976	$ 2,721
Property, plant and equipment	5,714	5,556	5,320
Right-of-use assets	117	126	95
Intangible assets other than goodwill	223	252	256
Total long-term other assets	179	160
Canada
Disclosure of geographical areas [line items]
Total revenue from contracts with customers	2,218	1,905	1,854
Property, plant and equipment	3,578	3,817
Right-of-use assets	43	49
Intangible assets other than goodwill	108	123
Total long-term other assets	68	62
US
Disclosure of geographical areas [line items]
Total revenue from contracts with customers	987	940	731
Property, plant and equipment	1,749	1,307
Right-of-use assets	71	74
Intangible assets other than goodwill	88	101
Total long-term other assets	42	34
Australia
Disclosure of geographical areas [line items]
Total revenue from contracts with customers	150	131	$ 136
Property, plant and equipment	387	432
Right-of-use assets	3	3
Intangible assets other than goodwill	27	28
Total long-term other assets	$ 69	$ 64