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.

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).

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.

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.

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.

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 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.

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.

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.

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.

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.

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.

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.

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.

This Policy shall be binding and enforceable against all Covered Executives and their beneficiaries, heirs, executors, administrators or other legal representatives.

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.

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.

Applies to all variable compensation.

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.

The information contained in this Annual Information Form (AIF) is given as of or for the year ended Dec. 31, 2024, 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" refer to TransAlta Corporation and its subsidiaries on a consolidated basis. Reference to "TransAlta Corporation" refer to TransAlta Corporation only. Certain capitalized terms defined throughout the body of this AIF and abbreviations and acronyms that may not otherwise be defined are defined in Appendix "B" – Glossary of Terms.

Certain portions of TransAlta's management's discussion and analysis dated Feb. 19, 2025 (MD&A) are incorporated by reference into this AIF as stated below and noted elsewhere in this AIF. The MD&A can be found on SEDAR+ at www.sedarplus.ca and EDGAR at www.sec.gov.

This AIF, including the information incorporated by reference herein, includes "forward-looking information," within the meaning of applicable Canadian securities laws, and "forward-looking statements," within the meaning of applicable U.S. securities laws, including the Private Securities Litigation Reform Act of 1995 (collectively referred to herein as forward-looking statements).

In particular, this AIF (including the information incorporated by reference herein) contains forward-looking statements about the following, among other things:

•The strategic objectives of the Company and that the execution of the Company's strategy will realize value for shareholders;

•Our capital allocation and financing strategy;

•Our sustainability goals and targets, including those in our 2024 Sustainability Report;

•Our 2025 Outlook;

•Our financial and operational performance, including our hedge position;

•Optimizing and diversifying our existing assets;

•The increasingly contracted nature of our fleet;

•Expectations about strategies for growth and expansion, including opportunities for Centralia redevelopment, and data centre opportunities;

•Expected costs and schedules for planned projects;

•Expected regulatory processes and outcomes, including in relation to the Alberta restructured energy market;

•The power generation industry and the supply and demand of electricity;

•The cyclicality of our business;

•Expected outcomes with respect to legal proceedings;

•The expected impact of future tax and accounting changes; and

•Expected industry, market and economic conditions.

The forward-looking statements contained in this AIF (or incorporated herein by reference) are based on many assumptions including, but not limited to, the following:

•No significant changes to applicable laws and regulations;

•No unexpected delays in obtaining required regulatory approvals;

•No material adverse impacts to 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 interest rates;

•No significant changes to the demand and growth of renewables generation;

•No significant changes to the integrity and reliability of our facilities;

•No significant changes to the Company's debt and credit ratings;

•No unforeseen changes to economic and market conditions; and

•No significant event occurring outside the ordinary course of business.

Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this AIF (or incorporated herein by reference) include, but are not limited to:

•Fluctuations in power prices;

•Changes in supply and demand for electricity;

•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;

•Any difficulty raising needed capital in the future on reasonable terms or at all;

•Our ability to achieve our targets relating to environmental, social and governance (ESG) performance;

•Long-term commitments on gas transportation capacity that may not be fully utilized over time;

•Changes to the legislative, regulatory and political environments;

•Environmental requirements and changes in, or liabilities under, these requirements;

•Operational risks involving our facilities, including unplanned outages and equipment failure;

•Disruptions in the transmission and distribution of electricity;

•Reductions in production;

•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;

•Reduced labour availability and ability to continue to staff our operations and facilities;

•Disruptions to our supply chains;

•Climate-change related risks;

•Reductions to our generating units' relative efficiency or capacity factors;

•General economic risks, including deterioration of equity and debt markets, increasing interest rates or rising inflation;

•General domestic and international economic and political developments, including potential trade tariffs;

•Industry risk and competition;

•Counterparty credit risk;

•Inadequacy or unavailability of insurance coverage;

•Increases in the 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 "Governance and Risk Management" in the MD&A, which section is incorporated by reference herein.

Readers are urged to consider these factors carefully when evaluating the forward-looking statements and are cautioned not to place undue reliance on them. 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.

We use a number of financial measures to evaluate our performance and the performance of our business segments, including measures and ratios that do not have any standardized meaning under 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, is 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 "Additional IFRS Measures and Non-IFRS Financial Measures" and "Key Non-IFRS Financial Ratios" sections of the MD&A, for more information, which sections are incorporated by reference.

TransAlta is a corporation organized under the Canada Business Corporations Act (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 under the CBCA involving the Company and TransAlta Utilities Corporation (TransAlta Utilities or TAU). 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.

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 at several instances in connection with issuances of preferred shares including on Oct. 1, 2020, when we created the Series I Shares, a new series of redeemable, retractable first preferred shares that were issued to an affiliate of Brookfield Renewable Partners (Brookfield). See the "Capital Structure – Exchangeable Securities" section of this AIF.

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

As of Dec. 31, 2024, our principal subsidiaries and their respective jurisdictions of formation are set out in the organization chart below. The Company’s remaining subsidiaries each account for (i) less than 10 per cent of the Company’s consolidated assets as at Dec. 31, 2024 and (ii) less than 10 per cent of the Company’s consolidated revenues for the year ended Dec. 31, 2024. The diagram below does not include all of the subsidiaries of TransAlta. The total assets and revenues of excluded subsidiaries in the aggregate 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, 2024.

(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) Of the 17.01 per cent of Kent Hills Wind LP, 17.00 per cent is owned by Natural Forces Technologies Inc. and 0.01 percent is owned by Kent Hills Wind Inc.

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

(9) The remaining 0.01 per cent of Windrise Wind LP is owned by Windrise Wind Energy Inc., a wholly owned subsidiary of Canadian Hydro Developers, Inc.

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.

On Dec. 4, 2024, the Company closed the acquisition of Heartland Generation Ltd. and certain affiliates (collectively, Heartland) for a purchase price of $542 million from an affiliate of Energy Capital Partners (ECP), the parent of Heartland (the Transaction). To meet the requirements of the federal Competition Bureau, the Company entered into a consent agreement with the Commissioner of Competition pursuant to which TransAlta agreed to divest Heartland's Poplar Hill and Rainbow Lake assets (the Planned Divestitures) following closing of the Transaction. In consideration of the Planned Divestitures, TransAlta and ECP agreed to a reduction of $80 million from the original purchase price for the Transaction. ECP will be entitled to receive the proceeds from the sale of Poplar Hill and Rainbow Lake, net of certain adjustments following completion of the Planned Divestitures. TransAlta also received a further $95 million at closing of the Transaction to reflect the economic benefit of the Heartland business arising from Oct. 31, 2023 to the closing date of the Transaction, pursuant to the terms of the share purchase agreement. The net cash payment for the Transaction, before working capital adjustments, totalled $215 million, and was funded through a combination of cash on hand and draws on TransAlta's credit facilities.

On Nov. 4, 2024, the Company provided notice to the Alberta Electric System Operator (AESO) that Sundance Unit 6 will be mothballed on April 1, 2025, for a period of up to two years depending on market conditions. TransAlta maintains the flexibility to return the mothballed unit to service when market fundamentals or opportunities to contract are secured. The unit remains available and fully operational for the first quarter of 2025.

Construction of the Mount Keith West Network upgrade project commenced in the fourth quarter of 2024 under the PPA with BHP Nickel West. The works comprise upgrades to the Mount Keith 132kV network via an extension of existing Gas Insulated Switchgear, new 132kV transformers and new 11kV switchrooms that will replace legacy 11kV switchgear located at TransAlta’s diesel power station.

During the year ended Dec. 31, 2024, the Company purchased and cancelled a total of 13,467,400 common shares, pursuant to its Normal Course Issuer Bid program at an average price of $10.59 per common share, for a total cost of $143 million, including taxes.

On Nov. 22, 2023, 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 145 MW Southern Cross Energy North remote network in Western Australia. The facilities are fully contracted to BHP under a PPA expiring in 2038.

Our Kent Hills wind facilities were partially returned to service in the fourth quarter of 2023, with all turbines commissioned and the remediation project completed in the first quarter of 2024. On June 2, 2022, we 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.

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.

Acquisition of TransAlta Renewables Inc.
On Oct. 5, 2023, the Company completed the acquisition of TransAlta Renewables for $1.3 billion, consisting of $800 million of cash and approximately 46 million common shares of the Company. TransAlta's acquisition of TransAlta Renewables' common shares resulted in TransAlta Renewables becoming a wholly owned subsidiary of the Company. Prior thereto, TransAlta and its affiliates collectively owned 60.1 per cent of TransAlta Renewables.

During 2023, the Company successfully recontracted the Pingston facility for a period of 20 years. Pingston is a 45 MW run-of-river hydroelectric facility located on Pingston Creek, British Columbia.

On Nov. 17, 2022, the Company issued US$400 million Senior Notes, which have a coupon rate of 7.750 per cent per annum and mature on Nov. 15, 2029.

The Company allocated 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.

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 three 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.

On Aug. 23, 2022, TransAlta 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 capacity contracts run from May 1, 2026, to April 30, 2031.

Our Hydro, Wind and Solar, Gas and Energy Transition segments are responsible for operating and maintaining our electrical generation facilities in Canada, the United States and Western Australia. Our Energy Marketing segment is responsible for marketing and scheduling our merchant asset fleet in North America (excluding Alberta) along with the procurement of natural 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 and trading.

In Alberta, the Company manages merchant exposure by executing hedging strategies that include a significant base of commercial and industrial customers, supplemented with financial hedges. A significant portion of our thermal generation capacity in Alberta is hedged to provide greater cash flow certainty while also capturing higher returns for our shareholders through the optimization of our merchant generation portfolio.

These segments are all supported by a Corporate segment.

The following map outlines the Company's operations as of Dec. 31, 2024:

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

The Hydro segment holds a net capacity interest of 922 MW of generating capacity. The facilities are located in Alberta, British Columbia, and Ontario.

As well as contracting for power, we enter into long 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 contracts, the benefit of the environmental attributes generated is provided to the contract holder.

The following table summarizes our hydroelectric facilities as at Dec. 31, 2024:

(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 Structure – Investment 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.

Barrier is a hydroelectric facility with installed capacity of 13 MW located on the Kananaskis River near Seebe, Alberta. 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 is a hydroelectric facility with installed capacity of 17 MW located on the Bow River in Calgary, Alberta. 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 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. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Ghost is a hydroelectric facility with installed capacity of 54 MW located on the Bow River near Cochrane, Alberta. 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 is a run-of-river hydroelectric facility with installed capacity of 14 MW located on the Bow River near Seebe, Alberta. 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 is a hydroelectric facility with installed capacity of 5 MW located at Kananaskis Lakes, Alberta. 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 is a run-of-river hydroelectric facility with installed capacity of 19 MW located on the Bow River in Seebe, Alberta. 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 is a hydroelectric facility with installed capacity of 15 MW located at Kananaskis Lakes, Alberta. Commercial operations began in 1955. Generation from the facility is sold in the Alberta electricity market and creates EPCs under the TIER system.

Rundle is a hydroelectric facility with installed capacity of 50 MW located in Canmore, Alberta, on the Spray system. Commercial operations began in 1951. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

Spray is a hydroelectric facility with installed capacity of 112 MW located in Canmore, Alberta, on the Spray system. 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 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. Commercial operations began in 1951. Generation from the facility is currently sold in the Alberta electricity market.

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. Commercial operations began in March 1991. Generation from the facility is currently sold in the Alberta electricity market.

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. Commercial operations began in 1992. Generation from the facility is currently sold in the Alberta electricity market.

Taylor is a run-of-river hydroelectric facility with installed capacity of 13 MW and is located adjacent to the Taylor Coulee Chute on the Waterton-St. Mary Headworks Irrigation Canal System, which is owned by the Government of Alberta. Commercial operations began in 2000. Generation from the facility is currently sold in the Alberta electricity market.

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

Bighorn is a hydroelectric facility with installed capacity of 120 MW located near Nordegg, Alberta. 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 is a hydroelectric facility with installed capacity of 355 MW located near Drayton Valley, Alberta. Commercial operations began in 1967. Generation from the facility is currently sold in the Alberta electricity market and creates EPCs under the TIER system.

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. 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 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. Commercial operations began in 2011. The output from the facility is sold to BC Hydro under a PPA that terminates in 2031.

Pingston is a run-of-river hydroelectric facility with installed capacity of 45 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. 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 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. Commercial operations began in 2005. The output from the facility is sold to BC Hydro under a PPA that terminates in 2045.

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. 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 is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Wanapitei River, near Sudbury, in northern Ontario. 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 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. 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.

As at Dec. 31, 2024, the Wind and Solar segment held interests in approximately 2,559 MW of net wind and solar generating capacity. This capacity consists of 12 wind facilities in Western Canada, four in Ontario, two in Québec, three in New Brunswick and eight in the United States, more specifically in Washington, Wyoming, Minnesota, Oklahoma, 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 Massachusetts and North Carolina, and a 38 MW solar facility and a 10 MW battery energy storage system in Western Australia.

In addition to contracting for the sale of the power generation, we also enter into long- and short-term contracts to sell the environmental and tax 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 PPA, the purchaser also benefits from any environmental attributes associated with the facility.

The following table summarizes our Wind and Solar generation facilities as at Dec. 31, 2024:

(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 or certain contract terms are confidential and have note been disclosed.

(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.

(6)    Includes six additional turbines at other locations.

(7)    Includes multiple facilities.

Ardenville is a 69 MW wind facility located approximately 14 kilometres south of Fort Macleod. The facility began commercial operations in November 2010. It 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 greenhouse gases (GHG) and as such we elected to participate in TIER. Generation from the facility is currently sold in the Alberta electricity market.

Blue Trail is a 66 MW wind facility 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 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 is a 39.5 MW wind facility 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 is a 19.5 MW wind facility 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 is a 130 MW wind facility 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 is a 75.2 MW wind facility 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. A 20-year PPA with ENMAX Energy Corporation terminated on April 30, 2024 and generation from the facility is currently sold in the Alberta electricity market.

Oldman is a 3.6 MW wind facility 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.

Sinnott is a 5 MW wind facility 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 is a 71 MW wind facility 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 is a 68 MW wind facility 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 is a 66 MW wind facility 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 is a 206 MW wind facility 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.

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.

Kent Breeze is a 20 MW wind facility 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 is a 96 MW wind facility 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. Generation from this facility is sold under a PPA with NB Power that expires in 2045.

Kent Hills 2 is a 54 MW wind facility 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. 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.

Kent Hills 3 is a 17.25 MW wind facility located near Moncton, New Brunswick. The facility began commercial operations in November 2018. 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. On June 2, 2022, we announced the extension of the previous 2035 PPA term for an additional 10-year period through to December 2045.

Le Nordais is a 97.5 MW wind facility located on the Gaspé Peninsula of Québec. The facility has two sites, Cap-Chat with 74 turbines and Matane 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 is a 67.5 MW wind facility 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 Medium-Term 1 (MT1) capacity contract with the IESO will begin on May 1, 2026, and terminate on April 30, 2031. The Company submitted a binding offer in January 2025 to participate in the 5-year Medium-Term 2 Energy Contract (MT2(e)), which will be awarded by April 1, 2025. If successful, this energy contract will replace the MT1 and be effective May 1, 2026 to April 30, 2031.

Melancthon 2 is a 132 MW wind facility 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 submitted a binding offer in January 2025 to participate in the 5-year MT2(e), which will be awarded by April 1, 2025. If successful, the current PPA will extend to April 30, 2029 and the MT2(e) will be effective May 1, 2029 to April 30, 2034.

New Richmond is a 68 MW wind facility 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.

Wolfe Island is a 197.8 MW wind facility 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. The Company submitted a binding offer in January 2025 to participate in the 5-year MT2(e), which will be awarded by April 1, 2025. If successful, the current PPA will terminate early and the MT2(e) will be effective May 1, 2029 to April 30, 2034.

Antrim is a 28.8 MW wind facility 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 is a 90 MW wind facility 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.

Horizon Hill is a 202 MW wind facility located in Logan County, Oklahoma. 100 per cent of the generation offtake from the project is sold to Meta, under a long-term PPA. Under the PPA, Meta receives both renewable electricity and environmental attributes. The Horizon Hill facilities achieved commercial operation on May 21, 2024. The company has entered into two 10-year transfer agreements with A+ and AA- rated customers for the sale of 100 per cent of the expected production tax credits to be generated from the Horizon Hill, White Rock East, and White Rock West facilities. See the "General Development of the Business – Three-Year History" section of this AIF for further details.

Lakeswind is a 50 MW wind facility located near Rollag, Minnesota, and 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 is a 21 MW solar portfolio consisting of multiple sites located in Massachusetts, and is contracted under long-term PPAs expiring between 2032 and 2045 with several high-quality counterparties.

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 and are automatically extended unless terminated by either party.

Skookumchuck is a 137 MW wind facility that 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.

White Rock East and White Rock West are 201.5 MW and 99.5 MW wind facilities 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 both facilities. White Rock West achieved commercial operation on Jan. 1, 2024 and White Rock East achieved commercial operation on April 22, 2024. The company has entered into two 10-year transfer agreements with A+ and AA- rated customers for the sale of 100 per cent of the expected production tax credits to be generated from the Horizon Hill, White Rock East, and White Rock West facilities. See the "General Development of the Business – Three-Year History" section of this AIF for further details.

Wyoming is a 140 MW wind facility located near Evanston, Wyoming. The facility began commercial operations in December 2003, and is contracted under a long-term PPA until 2028 with an investment-grade counterparty.

Northern Goldfields Solar facilities consist 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 to 2038. See the "General Development of the Business" section of this AIF for further details.

The Gas segment holds a net capacity ownership interest of 4,525 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, 2024:

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

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

The McMahon natural-gas-fired cogeneration facility is located in Taylor. The 120 MW McMahon facility has been in operation since 1993, and is fully contracted with Brookfield and NorthRiver Midstream for steam and BC Hydro for electricity through to 2029.

The Battle River 4 and 5 facilities are located near Forestburg. Battle River 4 and 5 are 155 MW and 395 MW, respectively, having completed their conversion to natural gas in 2021 and 2019, respectively. The end of regulatory life for Battle River 4 and 5 is set for 2033 and 2037, respectively. Generation from the facilities is currently sold in the Alberta electricity market.

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. Generation from the facility is currently sold in the Alberta electricity market.

The Joffre natural-gas-fired cogeneration facility is located in Red Deer. TransAlta owns a 40 per cent interest in the facility, with Capital Power and Nova Chemicals owning 40 per cent and 20 per cent, respectively. The 474 MW Joffre facility has been in operation since 2000 and is 26 per cent (122 MW) contracted to Nova Chemicals through to 2041. The remaining uncontracted electricity capacity is sold in the Alberta energy market.

The Keephills 2 facility is located approximately 70 kilometres west of Edmonton. Keephills 2 is a 395 MW gas-fired unit that completed its conversion to natural gas in 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.

The Keephills 3 facility is located approximately 70 kilometres west of Edmonton. Keephills 3 is a 466 MW gas-fired unit that completed its conversion to natural gas in 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.

The Muskeg River natural-gas-fired cogeneration facility is located in Fort McMurray. The 202 MW Muskeg River facility has been in operation since 2003 and is fully contracted to the Athabasca Oil Sands Project, which consists of Canadian Natural Resources Limited (CNRL), Chevron and Shell, through to 2042.

The Poplar Creek natural-gas-fired 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. In 2015, 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 Poplar Creek facility will transfer to Suncor on Dec. 31, 2030.

The Primrose natural-gas-fired cogeneration facility is located near Bonnyville. TransAlta owns a 50 per cent interest with CNRL owning the remaining 50 per cent of the facility. The 100 MW Primrose facility has been in operation since 1998 and is fully contracted to CNRL through to 2028, at which time, will be transferred to CNRL at the expiry of the PPA with no remaining liabilities for TransAlta.

The Scotford natural-gas-fired cogeneration facility is located in northeast of Fort Saskatchewan. The 195 MW Scotford facility has been in operation since 2003, and is fully contracted to CNRL, Chevron and Shell through to 2043.

The Sheerness 1 and 2 facilities are located approximately 200 kilometres northeast of Calgary. The 400 MW Sheerness 1 and 400 MW Sheerness 2 facilities are gas-fired units that completed their conversion to natural gas in 2021 and 2020, respectively. The end of regulatory life for these units is set for 2037. Generation from the facilities is currently sold in the Alberta electricity market.

The Sundance 6 facility is located approximately 70 kilometres west of Edmonton. Sundance 6 is a 401 MW gas-fired unit that completed its conversion to natural gas in 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. In November of 2024, the Company announced that the unit will be mothballed at the end of the first quarter of 2025.

The Valleyview 1 and 2 natural-gas-fired simple-cycle gas turbine generator facilities are located in Valleyview. The 50 MW Valleyview 1 and 50 MW Valleyview 2 facilities have been in operation since 2001 and 2008, respectively. Generation from the facilities is currently sold in the Alberta electricity market.

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 $41 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 that include 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.

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.

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.

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. 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 Dec. 31, 2032.

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. 

In 2014, we established the Fortescue River Gas Pipeline joint venture with AGI Fortescue River Pty Limited. 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-pay natural 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 to the Solomon facility.

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 2027. Any merchant capacity and energy are sold in Western Australia's wholesale electricity market.

The South Hedland Power Station is a 150 MW combined-cycle power station located near South Hedland, Western Australia, which achieved commercial operation in 2017. The facility is contracted with two customers. Horizon Power, the state-owned electricity supplier in the region has contracted 110MW until 2042. The second customer is the port operations of FMG for 35 MW of capacity until 2037.

Southern Cross Energy Partnership (SCE) has power stations at Mount Keith, Leinster, Kalgoorlie and Kambalda. In total, a combined gas- and diesel-fired capacity of 245 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). SCE also completed the expansion of the Mount Keith 132kV transmission system to support BHP's Northern Goldfields-based operations in the first quarter of 2024.

The PPA with BHP for the facilities expires on Dec. 31, 2038. The PPA provides, among other things, SCE with the exclusive right to supply electricity, transmission, and distribution infrastructure 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.

On July 11, 2024, BHP announced a period of temporary suspension of operations for its Western Australian nickel operations in response to the low nickel price outlook. The PPA remains in place and SCE is working closely with BHP to manage the impact of reduced load. BHP intends to review the decision to temporarily suspend its Western Australian nickel operations by February 2027.

The Energy Transition segment holds a net ownership interest in 671 MW of generating capacity. The two facilities are located in the United States.

The following table summarizes our Energy Transition facilities as at Dec. 31, 2024:

(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.

The Centralia coal-fired facility is located in Centralia, Washington, 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 the Centralia thermal facility to Puget Sound Energy. The contract terminates on Dec. 31, 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 U.S. Pacific Northwest electricity market. Our strategy is to balance contracted and non-contracted sales of electricity to manage production and price risk.

Since 2015, we have invested US$55 million to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State. The initiatives are part of Centralia's transition from coal-fired operations in Washington, beginning on Dec. 31, 2020. Such 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.

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.

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 U.S. 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 2024. The total dollar value of all Mine Safety and Health Administration (MSHA) assessments is not material.

(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).

We own the Highvale mine that supplied coal to the previously coal-fired Sundance and Keephills facilities. 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.

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 cease operation on coal effective Dec. 31, 2025.

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.

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.

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

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

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 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.

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. The remaining 17 per cent is held by Natural Forces Technologies Inc., a wind developer based in Atlantic Canada that helped develop the Kent Hills wind projects with TransAlta.

Power generation is an industry in the midst of an exciting transformation and the demand for electricity has the potential to grow significantly over the long-term due to general trends toward electrification. 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;

•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;

•In tandem, the need and value of reliability within electricity systems across TransAlta's portfolio is becoming an important focus for system operators and customers. Opportunities for legacy gas-fired generation are being identified as systems seek to balance renewable demands with the need for reliable generation; and

•Growing electricity demand, from electrification and data centre development, is driving load growth. Electrification is seen as one of the most effective levers to reduce GHG emissions in many sectors, such as transportation. In tandem, growing demand related to artificial intelligence and data centre development is resulting in expanded load forecasts.

Approximately 58 per cent of our gross installed capacity is located in Alberta. As of Dec. 31, 2024, our portfolio of merchant assets in Alberta is a combination of hydro facilities, wind facilities, a battery storage facility, natural-gas-fired cogeneration and converted natural-gas-fired thermal facilities. This balance of fuel types provides us with portfolio generation diversification, along with capacity that can be monetized as ancillary services or dispatched into the energy market during times of supply tightness. To reduce the exposure from variable spot power prices on our merchant generation, we enter into 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 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 increased from 2023 to 2024 by approximately three per cent. The average pool price in Alberta declined from $134/MWh in 2023 to $63/MWh in 2024. While demand growth was

positive, lower natural gas prices and supply additions - renewables, natural gas and cogeneration - meant the market was more supplied as compared to 2023.

We currently expect additional compliance costs as a result of the Canadian federal government’s Greenhouse Gas Pollution Pricing Act (GGPPA), 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 natural gas that give us an advantage over competitors when constructing generation facilities that use these fuel types.

Our generating capacity in the U.S. Pacific Northwest includes the remaining Centralia coal unit and our 49 per cent interest in the Skookumchuck wind facility. The Centralia coal unit is 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 contract with Puget Sound Energy for up to 300 MW over the remaining life of the Centralia facility. 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.

Our business is solely in Western Australia, and is focused on the large, remote mining industry in the state. The primary exports from Western Australia are iron ore, natural gas and gold. Commodity exports from Western Australia contribute significantly to the economy, driven by large-scale creditworthy producers. Remote mining operations are exploring options to add renewable generation with firming options via thermal generation and battery energy storage systems to their existing and new sites in an effort to reduce the amount of gas and diesel required in these operations. We expect this trend to continue and to create further opportunities for our business in Western Australia.

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. Where possible, we aim to reduce our cost of capital and improve our competitive profile through efficient financing structures. In the United States, our substantial tax attributes further increase our competitiveness.

In renewables, we are primarily evaluating greenfield opportunities in Western Canada and the United States 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 experienced development and construction teams 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.

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 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 regions. 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.

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

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. In addition, the Clean Electricity Regulations (CER), issued by the Canadian federal government on Dec. 17, 2024, impose further emission limits on electricity generation facilities in Canada. See the "Environmental Risk Management – Climate-Related Financial Disclosure" and "Environmental Risk Management – Canadian Federal Government" sections of this AIF for further details.

Alberta operates under a competitive wholesale energy-only market structure where generators offer their power supply into a power pool and those offers clear against power demand. Market clearing prices are determined by the dynamics of supply and demand in the wholesale electricity market. Since the first quarter of 2024, the Government of Alberta and the AESO have advanced a Restructured Energy Market (REM) that will replace the existing market design and is expected to be implemented in 2027.

On July 3, 2024, Alberta's Minister of Affordability and Utilities issued a letter to the AESO identifying a proposed high-level design for the REM that includes: (i) a mandatory day-ahead market; (ii) a review of the wholesale electricity market price floor and price cap; (iii) a uniform system-wide market price; (iv) co-optimization of the energy and ancillary services markets; and (v) optimization of dispatch around transmission constraints. The REM contemplates additional changes that will impact the Alberta energy market including a move away from the congestion-free planning paradigm to an "optimally planned transmission standard" as well as a strategic reserve mechanism to contract with out-of-market generation for reliability purposes. The AESO commenced detailed design sessions in consultation with industry stakeholders in October 2024 and issued a High-Level Design Proposal for the REM for stakeholder comment in December 2024. Development of the detailed REM is scheduled to take place in the first quarter and early in the second quarter of 2025. The provincial government plans to propose legislative changes to enable the REM in spring 2025, which will be followed by AESO market rule development activities between December 2025 and December 2026 before REM is implemented in 2027.

The Government of Alberta also continues to make changes to the policy framework for the development of renewable energy facilities. This work follows the government's pause on the issuance of power plant approvals for new renewable energy facilities that occurred between Aug. 3, 2023 and Feb. 29, 2024, and the recommendations stemming from the Alberta Utilities Commission inquiry that occurred during that time. On Dec. 6, 2024, the government issued a new Electric Energy Land Use and Visual Assessment Regulation that establishes visual impact assessment requirements for renewable energy facilities proposed within buffer zones and visual impact assessment zones and agricultural impact assessment requirements for renewable energy facilities proposed on high-quality agricultural lands (Class 1 and 2 lands, and Class 3 lands in certain

areas). The Government of Alberta is also amending the Activities Designation Regulation and Conservation and Reclamation Regulation to require renewable energy operators to post security with the Government of Alberta that is sufficient to cover estimated decommissioning and reclamation costs, or provide evidence that such security has been provided to the application landowner(s) pursuant to a surface lease.

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 and Electrification 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 market manual development and settlement rule testing, finalization and approval, with the intent to implement the Market Renewal Program in the second quarter of 2025. The program includes the introduction of a day-ahead market, locational pricing, enhanced unit commitment and market power mitigation. The impact on existing facilities is mitigated due to existing contracts and related proposed amendments that account for the impacts of the Market Renewal Program (e.g., capacity contracts for gas facilities and wind power purchase arrangements for wind facilities). The IESO is coordinating its changes to its energy market with new resource adequacy procurements, including new contract types for medium- and long-term requests for proposals, 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.

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.

Centralia and Skookumchuck are operated in the state of Washington. 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, 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.

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.

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.

We have prepared an assessment of climate-related risks and opportunities to partially align with the IFRS S2 Climate-related Disclosures Standard and Task Force on Climate-related Financial Disclosures describing our climate change strategy, governance, risk management approach, metrics and targets. In 2024, we reviewed and updated our climate transition plan and prepared climate-related financial metrics. See the "Sustainability" section of the 2024 Integrated Report for further details.

On June 21, 2018, the Canadian federal 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 carbon dioxide equivalent (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 CER to achieve a net-zero electricity sector in Canada by 2035. The draft CER was published in Canada Gazette I in August 2023 and the finalized regulations were issued under the Canadian Environmental Protection Act, 1999 on Dec. 17, 2024. The CER imposes an annual emissions limit (AEL) on electricity generation units that use fossil fuels based on each unit’s generation capacity, its annual hours of operation and an applicable emissions intensity. The applicable emissions intensity is 65 tonnes of CO2e/GWh between 2035 and 2049, during which time regulated units may emit up to 35 t/GWh above the AEL by remitting an equivalent amount of eligible offset credits. The applicable emissions intensity is reduced to 0 t/GWh as of 2050, but up to 42 t/GWh of emissions are permitted, subject to remitting an equivalent amount of eligible offset credits. Eligible offset credits include those issued or recognized under the GGPPA regime, including several TIER offset protocols. Subject to limited exceptions, the AEL will apply to most generating units as of Jan. 1, 2035. At this time, TransAlta does not expect the CER to have a material impact on its business.

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.

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 has been ongoing since that time. The draft Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations were introduced on Nov. 4, 2024. The proposed regulations would set a cap on GHG emissions within the sector, equivalent to 35 per cent below 2019 levels and create a cap and trade system to incentivize emission reductions and facilitate compliance across the sector. While the proposed cap-and-trade system is expected to allow for cross-recognition of offset credits from other emission reduction regimes, the interplay between the proposed cap-and-trade system and regulations like TIER remains unclear. The public comment period for the draft regulations closed on Jan. 8, 2025, and the government is expected to publish final regulations later in 2025. 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 final 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 reductions in the province) at the current carbon price; (b) making emission 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 to ensure alignment with the Canadian federal government's requirements under the GGPPA, which included the following changes:

•The TIER Fund price for the 2023 to 2030 period was set via a Ministerial Order. The price was set at $65 per tonne of CO2e in 2023, 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 CO2e tonnes per MWh in 2023 to 0.3108 CO2e tonnes per MWh in 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 offset crediting for new renewables projects but, all things being equal, should also result in higher demand for emissions offset 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.

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 to ensure alignment with the Canadian federal government's requirements under the GGPPA. 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 using 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.

Ontario is continuing its work on the natural gas transition and has developed a voluntary clean energy credit market for specified asset types 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.

Following the inauguration of President Trump on Jan. 20, 2025, the President signed an Executive Order, directing the withdrawal of the United States from the Paris Agreement. It is expected that the United States may reduce current climate commitments; however, state level governments may choose to retain targets if this occurs. Existing commitments for carbon emissions reductions, include: 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 United States does not have a national carbon pricing regime, it currently offers 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 United States, with many state governments operating under renewable portfolio standards and carbon pricing regimes. Similar to Canada, independent estimates suggest that the United States will require substantial growth in zero-emissions generation to meet its national climate targets.

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. 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 GHG emissions and then auctions or allocates emissions allowances. TransAlta’s Centralia coal 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 in 2024. The auctions offered 2023 and 2024 vintage allowances, and an advance auction of 2027 vintage allowances. TransAlta continues to track the cap-and-invest program as it develops and moves into its second year of implementation. The Company will engage when necessary with relevant government departments should there be any future implementation changes that impact our operations or energy trading in Washington.

In October 2021, the Australian government announced a target to reach net-zero emissions by 2050. Following the May 2022 federal election, the 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 the 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 has 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.

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.

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 GHG emissions and compliance. We take a proactive approach to minimizing environmental and safety risks to our results. The board of directors of the Company (the Board or the Board of Directors) provides oversight to our environmental management programs and emissions reduction initiatives in order to ensure continued compliance with environmental regulations.

For a description of our environmental management system and other aspects of our environmental strategy see the "Managing Environmental Resources" section of the MD&A, which is incorporated by reference herein.

TransAlta also maintains a GHG emissions offset portfolio with a variety of instruments that can be used for compliance purposes or otherwise banked or sold. We continue to examine additional emission offset opportunities that also allow us to meet our emissions 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.

For a discussion of risk factors affecting TransAlta, see the "Governance and Risk Management" section of the MD&A, which is incorporated by reference herein.

The Company is required to develop and retain a skilled workforce for its operations. Many of TransAlta's employees possess specialized skills and training and we must compete in the labour market for these workers. As at Dec. 31, 2024, we had 1205 active employees, which includes full-time, part-time and temporary employees. Approximately 29 per cent of our employees are represented by labour unions. We are currently a party to 12 different collective bargaining agreements. As at Dec. 31, 2024, women accounted for 28 per cent of all employees and 32 per cent of our executive team.

For a description of social policies implemented by TransAlta please see "Engaging with Our Stakeholders to Create Positive Relationships" and "Building a Diverse and Inclusive Workforce" sections of the MD&A which are incorporated by reference herein.

Our authorized share capital consists of an unlimited number of common shares and an unlimited number of first preferred shares, issuable in series. For the number of common shares and first preferred shares issued and outstanding as at Dec. 31, 2024, see the "Financial Capital – Share Capital" section of the MD&A, which is incorporated by reference herein.

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 pre-emptive rights. The common shares are not entitled to cumulative voting.

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.

The holders of Series A, C, E and G first preferred shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, as and when declared by the Board, to be reset periodically on prescribed dates to an annualized rate equal to the sum of the then five-year Government of Canada bond yield, calculated at the start of the applicable five-year period, and a spread as set forth in the table below and have the right to convert their shares into cumulative redeemable Series B, D, F and H first preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below. The Series A, C, E and G first preferred shares are redeemable by TransAlta in whole or in part on such redemption dates as set forth in the table below, 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.

The holders of Series B, D, F and H first preferred shares will be entitled to receive quarterly floating rate cumulative preferential cash dividends, as and when declared by the Board, at an annualized rate equal to the sum of the then 90-day Government of Canada treasury bill rate, recalculated quarterly, and a spread as set forth in the table below and have the right to convert their shares into Series A, C, E and G first preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below. The Series B, D, F and H first preferred shares are redeemable by TransAlta in whole or in part after their respective initial redemption date as set forth in the table below, by the payment of an amount in cash for each share to be redeemed equal to (i) $25.00 in the case of redemptions on such redemption dates as set out in the table below, or (ii) $25.50 in the case of redemptions on any other date, in each case plus all accrued and unpaid dividends thereon.

The holders of the Series A, B, C, D, E, F and G first preferred shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on such series of first preferred 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 the first preferred shares of such series will be entitled: (i) 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); (ii) to one vote in respect of each first preferred share of such series held on all matters in respect of which shareholders vote; and (iii) to vote, together with all other holders of first preferred shares of any series, as a combined class, to elect two directors of the Company if the Board of Directors then consists of fewer 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.

The first preferred shares, Series I (Series I Shares), are issued to an affiliate of 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).

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 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.

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.

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 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 and Special Meeting of Shareholders, unless ratified and extended by a further vote of the shareholders. For further particulars, see the Rights Plan Agreement, as amended and restated. 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. 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.

For additional information regarding our Capital Structure, please refer see the "Financial Capital" section of the MD&A, which is incorporated by reference herein.

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 Structure – First Preferred Shares – Series I First Preferred Shares" section of this AIF for further details.

The following description of certain provisions of the Investment Agreement is a summary only; it is not comprehensive and is qualified in its entirety by reference to the full text of the Investment Agreement, a copy 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 nine per cent by May 1, 2021. As of Dec. 31, 2024, Brookfield, through its affiliates, held, owned or had control over an aggregate of 35,523,345 common shares, representing 11.9 per cent of the issued and outstanding common shares, calculated on an undiluted basis. On January 7, 2025, Brookfield, through its affiliates, sold 8,600,000 common shares reducing its ownership to 26,923,345 common shares, representing approximately nine per cent of the issued and outstanding common shares on an undiluted basis.

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. So long as Brookfield holds the Exchangeable Securities, it is entitled to nominate two directors for election to the Board.

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.

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 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 and the Registration Rights Agreement are also available on SEDAR+ and on EDGAR. Shareholders are encouraged to read these documents in their entirety.

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. Our credit ratings as at Dec. 31, 2024, are as follows:

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

Morningstar 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, 2024, our issuer rating was BBB (low) with a stable outlook. An issuer rating of BBB means the issuer has adequate credit quality, its capacity for the payment of financial obligations is considered acceptable, and it may be vulnerable to future events. 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. A BBB rating is the fourth highest out of 10 categories.

The Morningstar 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 Morningstar 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, B, C, D, E and G first preferred shares have been rated Pfd-3 (low) (stable). The Pfd-3 rating is the third highest out of six categories.

The Morningstar 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. A BBB rating is the fourth highest out of 10 categories.

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 refer to an obligation or class of debt and thus does not reflect priority of claim. As at Dec. 31, 2024, our Corporate Family Rating was Ba1 with a stable outlook. Obligations rated Ba are judged to be speculative and are subject to substantial credit risk. Moody's appends 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 11 months or more and reflect both the likelihood of a default or impairment on contractual financial obligations and the expected financial loss suffered in the event of default or impairment. As at Dec. 31, 2024, our senior unsecured long-term debt is rated Ba1/LGD4. The Ba rating category is the fifth-highest rating out of nine rating categories. Obligations rated Ba are judged to be speculative and are subject to substantial credit risk.

Moody's Loss Given Default (LGD) assessments are point-in-time opinions about expected loss given default expressed as a percentage of principal and accrued interest at the resolution of the default. One of the six LGD assessments is 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, 2024, 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.

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, 2024, our issuer credit rating was BB+ with a stable outlook. This is the fifth highest of 11 ratings categories. An obligor rated BB is less vulnerable in the near-term than other lower-rated obligors. However, it faces major ongoing uncertainties and exposure to adverse business, financial, or economic conditions that could lead to the obligor's inadequate capacity to meet its financial commitments. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.

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). 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 more vulnerable to nonpayment than obligations rated BB, but the obligor currently has the capacity to meet its financial commitments on the obligation. Adverse business, financial or economic conditions will likely 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.

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

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.

Dividends on our first preferred shares are payable quarterly, as and when declared by the Board.

TransAlta has declared and paid the following dividends per share on its outstanding common shares and Series A, B, C, D, E, and G first preferred shares for the past three years:

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

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, 2023, up to but excluding Dec. 31, 2024. The Series I Shares are entitled to a seven per cent cumulative dividend payable quarterly in cash.

Our common shares are listed on the Toronto Stock Exchange (TSX) under the symbol "TA" and on the New York Stock Exchange (NYSE) under the symbol "TAC".

Our Series A, B, C, D, E, and G first preferred shares are listed on the TSX under the symbols "TA.PR.D", "TA.PR.E", "TA.PR.F", "TA.PR.G", "TA.PR.H" and "TA.PR.J", respectively.

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:

The following table sets forth the reported high and low trading prices and trading volumes of our Series A, B, C, D, E and G first preferred shares as reported by the TSX for the periods indicated:

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

The name, province or state and country of residence of each of our executive officers as at Feb. 19, 2025, their respective position and office and their respective principal occupation are set out below.

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

•Prior to April 2021, Mr. Kousinioris was Chief Operating Officer of TransAlta.

•Prior to July 2024, Mr. Hunter was Executive Vice-President and Chief Financial Officer at TC Energy Corporation. Prior to August 2021, Mr. Hunter was Senior Vice-President, Capital Markets at TC Energy Corporation.

•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 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 July 2024, Mr. Flickinger was Vice President of Engineering and Construction of Pattern Energy Group LP.

•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 December 2024, Ms. Brennan was Executive Vice President, Legal, External Affairs and Corporate Secretary. Prior to July 2024, Ms. Brennan was Executive Vice President, Legal of TransAlta. Prior to February 2024, Ms. Brennan was Senior Vice President, Sustainability, External Relations and General Counsel of Keyera Corp.

•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.

As of Feb. 19, 2025, 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.

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 2025 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.

Since Jan. 1, 2024, 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.

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. (Denbury), which filed for bankruptcy protection in the United States 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.

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.

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.

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 Structure – Exchangeable Securities – Investment Agreement" section of this AIF for further details.

•Registration Rights Agreement – See the "Capital Structure – Exchangeable Securities – 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.

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 members 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.

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.

On Sept. 9, 2022, the Company filed a Statement of Claim against the Government of Alberta 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 a 1960 agreement between the Company and the Alberta Government; and (b) the Government of Alberta 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 Government of Alberta 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 is scheduled to be heard in September or October 2025 in the event the parties are unable to resolve the dispute prior to such date.

The transfer agent and registrar for our common shares and Series A, B, C, D, E and G first preferred shares is Odyssey Trust Company. Common shares are transferable in Vancouver, Calgary and Toronto. Series A, B, C, D, E and G first preferred shares are transferable in Calgary and Toronto. The transfer agent and registrar for our common shares in the United States is Odyssey Transfer and Trust Company at its principal office in Woodbury, Minnesota.

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

Our auditors, Ernst & Young LLP is the Company’s independent public accountant in the context of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta and the rules and regulations adopted by the United States Securities and Exchange Commission and the Public Company Accounting Oversight Board (United States).

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, 2024, and in the related MD&A.

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 U.S. 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: Thomas M. O'Flynn (Chair), Alan J. Fohrer, Candace J. MacGibbon, Bryan D. Pinney and Manjit K. Sharma.

All members of the committee are financially literate pursuant to both Canadian and U.S. 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 U.S. Sarbanes-Oxley Act of 2002.

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

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.

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, 2024, are:

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.

For the years ended Dec. 31, 2024, and Dec. 31, 2023, Ernst & Young LLP and its affiliates billed $4,407,734 and $4,788,655, respectively, as detailed below.

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 pension audits and other compliance audits.

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

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 and advice and assistance with ESG services provided by the auditor.

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.

The Audit, Finance and Risk Committee (the "Committee") of the board of directors (the "Board") of TransAlta Corporation (the "Corporation") shall consist of not less than three directors. All members of the Committee shall be determined by the Board to be independent as required under the provisions of Canadian Securities Regulators' Multilateral Instrument 52-110 Audit Committees, Section 303A of the New York Stock Exchange rules and Rule 10A-3 of the U.S. Securities and Exchange Act of 1934, as such rules apply to audit committee members. All members of the Committee must be financially literate pursuant to both Canadian and 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 United States 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 (the "GSSC") of the Board.

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.

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.

The Board shall appoint a Chair for the Committee on the recommendation of the GSSC.

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.

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

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

The Committee shall also meet in separate executive sessions.

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.

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.

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.

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.

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.

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, or 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.

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.

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.

(a)    Review with Management and the external auditors the Corporation's financial reporting process the work to be conducted in conjunction with the annual audit and the preparation of the financial statements, including, without limitation, the annual audit plan of the external auditors, the judgment of the external auditors as to the quality, not just the acceptability, of and the appropriateness of the Corporation's accounting principles as applied in its financial reporting and the degree of aggressiveness or conservatism of the Corporation's accounting principles and underlying estimates;

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

(c)    Review with Management and the external auditors the Corporation's interim financial statements, including the notes thereto, "Management's Discussion and Analysis," the related earnings release, and approve their release to the public as required;

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

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

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

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

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

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

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

(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 (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.

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

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

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

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

(iv)    review and discuss annually with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors' independence, including, without limitation: (a) requesting, receiving and reviewing, at least annually, a formal written statement from the external auditors delineating all relationships that may reasonably be thought to bear on their independence with the Corporation; (b) discussing with the external auditors any relationships or services that the external auditors believe may affect their objectivity and professional skepticism; (c) reviewing with the external auditors the experience and qualifications of the senior personnel who are providing audit services to the Corporation; (d) reviewing the quality control procedures of the external auditors, including obtaining confirmation that the external auditors are in compliance with Canadian and U.S. 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 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.

(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.

(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.

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

The Committee shall:

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

(b)    Receive and review Managements' quarterly risk update including an update on residual risks;

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

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

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

(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.

(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.

(a)    Review annually the Annual Pension Report and financial statements of the Corporation's pension plans including the actuarial valuation, asset/liability forecast, asset allocation, manager performance and plan operating costs, and reporting thereon to the Board annually; and

(b)    Together with the Human Resources Committee of the Board, review annually, and as required, the overall governance of the Corporation's pension plans, approving the broad objectives of the plans, the statement of investment policy, the appointment of investment managers, and reporting thereon to the Board annually.

(a)    Receive biannually a system status update with respect to the Corporation's core IT operating systems;

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

(c) Review periodically developments in respect of artificial and generative artificial intelligence, including opportunities, challenges and/or associated risks which could have a material impact on the execution of the Corporation’s strategy or key business objectives.

(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.

(a)    The responsibilities of the Committee comply with applicable Canadian laws and regulations, such as the rules of the Canadian Securities Administrators, and with the disclosure and listing requirements of the Toronto Stock Exchange, as they exist on the date hereof. In addition, this Charter complies with applicable U.S. laws, such as the Sarbanes-Oxley Act and the rules and regulations adopted thereunder, and with the New York Stock 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.

"AER" – Alberta Energy Regulator

"AESO" – The independent system operator and regulatory authority for the Alberta Interconnected Electric System.

"BC Hydro" – British Columbia Hydro and Power Authority

"BIA" – Bankruptcy and Insolvency Act (Canada)

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

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

"CBCA" – Canada Business Corporations Act.

"CER" – Clean Electricity Regulations

"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.

"ECCC" – Environment and Climate Change Canada

"FERC" – Federal Energy Regulatory Commission.

"GGPPA" – Greenhouse Gas Pollution Pricing Act (Canada).

"GHG" – Greenhouse gases that have the potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons.

"GW" – Gigawatt – A measure of electric power equal to 1,000 MW.

"GW/h" – 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.

"MSA" – Market Surveillance Administrator.

"MSHA" – Mine Safety and Health Administration.

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

"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.

"NEM" – National Electricity Market

"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.

"NWIS" – North West Interconnected System

"NYSE" – New York Stock Exchange.

"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.

"SGM" – Australian Government's National Safeguard Mechanism

"TIER" – Technology Innovation and Emission Reduction Regulation in Alberta.

"TSX" – Toronto Stock Exchange.

"VWAP" – Volume weighted average price

"WEM" – Wholesale Electricity Market

"WTUC" – Washington Transportation and Utilities Commission

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.

This MD&A should be read in conjunction with our 2024 audited annual consolidated financial statements (the consolidated financial statements) and our 2024 Annual Information Form (AIF), each for the fiscal year ended Dec. 31, 2024. 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, 2024. 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. 19, 2025. Additional information respecting TransAlta, including our AIF for the year ended Dec. 31, 2024, is available on SEDAR+ at www.sedarplus.ca, on EDGAR at www.sec.gov and on our website at www.transalta.com. Information on or connected to our website is not incorporated by reference herein.

(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.

The following table provides our consolidated ownership by segment of our facilities across the regions in which we operate as of Dec. 31, 2024:

(1)Gross installed capacity for consolidated reporting is based on a proportionate interest held in a facility. Refer to the Plant Summary section for details.

(2)Includes 1,747 MW of capacity attributable to nine facilities acquired from Heartland, which exclude the Planned Divestitures. Refer to the Significant and Subsequent events section.

(3)Includes the Centralia coal facility and the Skookumchuck hydro facility.

The following table provides our contracted capacity by segment in MW and as a percentage of total gross installed capacity of our facilities across the regions in which we operate as of Dec. 31, 2024:

(1)Includes contracted capacity of 436 MW from facilities acquired from Heartland: 376 MW in Alberta and 60 MW in Canada, excluding Alberta. The figures exclude the contracted capacity of Planned Divestitures. Refer to the Significant and Subsequent events section.

Approximately 52 per cent of our total installed capacity is contracted. Contracts are primarily with strong creditworthy counterparties.

The following table provides the weighted average contract life by segment of our contracted and merchant facilities across the regions in which we operate as of Dec. 31, 2024:

(1)Total weighted average contract life calculation of our gas facilities as at Dec. 31, 2024 includes the contracts added from the acquisition of Heartland and excludes the contracts pertaining to Planned Divestitures.

(2)The contract life of merchant facilities is included as nil years.

(1)These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. 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.

(4)During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the Company has applied this composition to all previously reported periods. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(5)Available liquidity is calculated as a sum of total available capacity under the committed credit and term facilities and cash and cash equivalents net of bank overdraft, less the amounts drawn under the non-committed demand facilities.

(6)Total long-term liabilities correspond to total non-current liabilities in the consolidated statements of financial position under IFRS .

(7)Total liabilities correspond to a sum of current and non-current liabilities in the consolidated statements of financial position under IFRS.

(1)Availability adjusted for dispatch optimization for the year ended 2022 was 79 per cent.

The following table provides the long-term average generation (LTA generation) on a consolidated basis for each of our segments: