TransAlta (NYSE: TAC) swings to H1 2026 profit as cash flow falls

Q: How did TransAlta (TAC) perform financially in Q2 2026?

TransAlta generated $487 million of revenue in Q2 2026 and earnings before income taxes of $80 million , versus a $95 million loss a year earlier. Net earnings attributable to common shareholders were $35 million , compared with a $112 million loss in Q2 2025.

Q: What were TransAlta (TAC)'s first-half 2026 Adjusted EBITDA and free cash flow?

For the six months ended June 30, 2026, TransAlta reported Adjusted EBITDA of $495 million and free cash flow of $245 million . These were down 20 per cent and 22 per cent, respectively, compared with the same period in 2025, mainly due to weaker Alberta pricing and lost Centralia generation.

Q: What major growth transactions did TransAlta (TAC) announce in 2026?

TransAlta agreed to acquire Mountain Peak Power and Canyon Peak Power , 318 MW of gas peakers near Denver, for US$1 billion including US$750 million of project debt, and bought Far North for $95 million . It also signed a Keephills data centre MOU for up to 1 GW of load.

Q: What is TransAlta (TAC)'s 2026 outlook and hedging position?

Management reaffirmed 2026 targets of $950 million–$1,050 million Adjusted EBITDA and $350 million–$450 million free cash flow. For 2026, Alberta output of 8,985 GWh is hedged at about $66/MWh , with 37 million GJ of gas hedged at roughly $3.17/GJ and a $1.5 million EBITDA impact per $1/MWh spot move.

Q: What is TransAlta (TAC)'s liquidity and leverage as of June 30, 2026?

TransAlta reported available liquidity of about $1.8 billion , including $302 million of cash and undrawn committed credit facilities. Total Consolidated Net Debt was $3,529 million , and the Adjusted Net Debt to Adjusted EBITDA ratio was 4.3 times .

Q: Have there been recent changes to TransAlta (TAC)'s dividend and credit ratings?

The board approved an 8 per cent increase in the annualized common dividend to $0.28 per share. S&P Global Ratings affirmed the BB+ rating but revised the outlook to negative , while Moody’s maintained a Ba1 rating with a stable outlook.

Filing Impact

(Neutral)

Filing Sentiment

(Neutral)

Form Type

6-K

Rhea-AI Filing Summary

TransAlta Corporation reported Q2 2026 revenue of $487 million and first-half 2026 revenue of $1,052 million. Q2 earnings before income taxes were $80 million, compared with a loss a year earlier, and net earnings attributable to common shareholders were $35 million versus a $112 million loss.

Despite this swing to profit, Q2 Adjusted EBITDA declined 17 per cent to $291 million, and first-half Adjusted EBITDA fell 20 per cent to $495 million; free cash flow decreased 22 per cent to $245 million, mainly due to lower Alberta power prices and the loss of Centralia output. The company reaffirmed 2026 guidance for Adjusted EBITDA of $950 million to $1,050 million and FCF of $350 million to $450 million, supported by Alberta hedges of 8,985 GWh at about $66/MWh, and available liquidity of roughly $1.8 billion. Strategic moves included a US$1 billion deal to acquire 318 MW of Colorado gas peakers, the $95 million Far North acquisition, an 8 per cent dividend increase to $0.28 annualized, and an MOU to develop a data centre at Keephills. S&P affirmed the BB+ rating but revised the outlook to negative, while Moody’s kept Ba1 with a stable outlook.

Positive

Dividend raised 8%: the board approved an increase to an annualized common share dividend of $0.28, with a quarterly dividend of $0.07 per share, signalling confidence in cash generation.
Strong liquidity: TransAlta reported available liquidity of about $1.8 billion as of June 30, 2026, with $2.2 billion of committed credit capacity and no cash drawings on its syndicated facility.

Negative

Cash generation weaker: first-half 2026 Adjusted EBITDA declined 20% to $495 million, and free cash flow fell 22% to $245 million compared with 2025, reflecting softer Alberta prices and no Centralia output.
Credit outlook revised negative: S&P Global Ratings affirmed TransAlta’s BB+ senior unsecured and issuer ratings on July 24, 2026, but changed the outlook from stable to negative, highlighting increased perceived risk.

Filing Explained

The June offering added 18.23 million common shares, while the Colorado acquisition remains conditional and is expected to close in early fourth quarter 2026.

The company reports that its June 9, 2026 public offering was completed for 18,230,000 common shares at $19.20 per share and approximately $350 million in gross proceeds, while the Colorado acquisition remains subject to conditions and is not yet complete.

Because issuing additional shares increases the total share count, the completed offering reduces an existing common holder’s percentage ownership absent offsetting changes; the proceeds are intended to fund the acquisition’s cash purchase price.

The filing also incorporates its interim MD&A and financial statements into specified S-8 and F-10 registration statements, which is a registration-document step separate from the completed June offering.

The key resolution point is the Colorado acquisition, expected in early fourth quarter 2026 only if Canyon Peak reaches commercial in-service and customary closing conditions, including regulatory approvals, are satisfied.

Key Figures

Q2 2026 Revenue: $487 million H1 2026 Revenue: $1,052 million H1 2026 Adjusted EBITDA: $495 million +5 more

8 metrics

Q2 2026 Revenue $487 million Consolidated revenue for the three months ended June 30, 2026

H1 2026 Revenue $1,052 million Consolidated revenue for the six months ended June 30, 2026

H1 2026 Adjusted EBITDA $495 million Non-IFRS Adjusted EBITDA, down 20% versus the first half of 2025

H1 2026 Free Cash Flow $245 million Non-IFRS FCF, a 22% decrease compared with the first half of 2025

H1 2026 Net Earnings to Common $48 million Net earnings attributable to common shareholders, versus a $66 million loss in 2025

Available Liquidity $1,751 million Liquidity as at June 30, 2026, based on cash and undrawn committed facilities

Adjusted Net Debt to Adjusted EBITDA 4.3 times Non-IFRS leverage ratio as at June 30, 2026, compared with 4.0 times at December 31, 2025

Mountain/Canyon Peak Acquisition Price US$1 billion Purchase price including assumption of US$750 million of project debt for 318 MW of gas peakers

Key Terms

Adjusted EBITDA, free cash flow (FCF), ancillary services, non-recourse debt, +2 more

6 terms

Adjusted EBITDA financial

"For the three and six months ended June 30, 2026, the Company's Adjusted EBITDA was $291 million and $495 million"

Adjusted EBITDA is a way companies measure how much money they make from their core operations, like running a business, by removing certain costs or income that aren’t part of regular business activities. It helps investors see how well a company is doing without distractions from unusual expenses or gains, making it easier to compare companies or track performance over time.

free cash flow (FCF) financial

"For the three and six months ended June 30, 2026, the Company's FCF decreased by $34 million, or 19 per cent and $71 million, or 22 per cent"

Free cash flow (FCF) is the cash a company generates from its regular business after paying for necessary investments like equipment, buildings, or repairs—think of it as the money left in your wallet after paying bills and fixing the car. Investors watch FCF because it shows how much real, spendable cash a company has to pay dividends, pay down debt, buy back shares, or fund growth, making it a key measure of financial health and flexibility.

ancillary services financial

"Alberta Hydro Assets ancillary services revenues are revenues earned from providing services required to ensure that the interconnected electric system is operated"

Ancillary services are the extra goods or services that support and complement a company’s main product or activity, like maintenance, testing, delivery, or billing. For investors they matter because these add-on offerings can create steady, often higher-margin revenue streams that diversify income and make a business less dependent on its core product — think of them like the accessories and service plans that keep a phone useful and also boost the seller’s profits.

non-recourse debt financial

"All non-recourse debt and the OCP LP Bond are subject to customary financing covenants that may restrict the Company’s ability to access funds"

A non-recourse debt is a loan where the lender can seize only the specific asset pledged as security (for example, a building or equipment) if the borrower defaults, and cannot pursue the borrower’s other assets or income. Investors care because this limits how much downside the borrower’s other holdings absorb and changes who bears loss in trouble: lenders face higher recovery risk while equity holders can be wiped out more easily, affecting valuation and risk assessment.

tax equity financing financial

"Tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in these amounts"

A financing structure where investors put money into a project or company primarily to receive tax credits, tax deductions, or other tax benefits alongside project cash flows; the investor and project owner share income, losses, and tax attributes according to an agreement. It matters to investors because those tax benefits can change expected after-tax returns, risk exposure, and cash timing—like buying a stream of tax advantages that alters the economics of a regular investment.

decommissioning and restoration provisions financial

"Lower asset impairment charges primarily related to a change in the discount rates on decommissioning and restoration provisions on retired assets"

AI-generated analysis. How Rhea-AI works. Not financial advice.

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Available on EDGAR 07/31/2026 - 07:02 AM Accepted by SEC EDGAR 07/31/2026 - 07:02 AM

FAQ

How did TransAlta (TAC) perform financially in Q2 2026?

TransAlta generated $487 million of revenue in Q2 2026 and earnings before income taxes of $80 million, versus a $95 million loss a year earlier. Net earnings attributable to common shareholders were $35 million, compared with a $112 million loss in Q2 2025.

What were TransAlta (TAC)'s first-half 2026 Adjusted EBITDA and free cash flow?

For the six months ended June 30, 2026, TransAlta reported Adjusted EBITDA of $495 million and free cash flow of $245 million. These were down 20 per cent and 22 per cent, respectively, compared with the same period in 2025, mainly due to weaker Alberta pricing and lost Centralia generation.

What major growth transactions did TransAlta (TAC) announce in 2026?

TransAlta agreed to acquire Mountain Peak Power and Canyon Peak Power, 318 MW of gas peakers near Denver, for US$1 billion including US$750 million of project debt, and bought Far North for $95 million. It also signed a Keephills data centre MOU for up to 1 GW of load.

What is TransAlta (TAC)'s 2026 outlook and hedging position?

Management reaffirmed 2026 targets of $950 million–$1,050 million Adjusted EBITDA and $350 million–$450 million free cash flow. For 2026, Alberta output of 8,985 GWh is hedged at about $66/MWh, with 37 million GJ of gas hedged at roughly $3.17/GJ and a $1.5 million EBITDA impact per $1/MWh spot move.

What is TransAlta (TAC)'s liquidity and leverage as of June 30, 2026?

TransAlta reported available liquidity of about $1.8 billion, including $302 million of cash and undrawn committed credit facilities. Total Consolidated Net Debt was $3,529 million, and the Adjusted Net Debt to Adjusted EBITDA ratio was 4.3 times.

Have there been recent changes to TransAlta (TAC)'s dividend and credit ratings?

The board approved an 8 per cent increase in the annualized common dividend to $0.28 per share. S&P Global Ratings affirmed the BB+ rating but revised the outlook to negative, while Moody’s maintained a Ba1 rating with a stable outlook.

FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of July 2026

Commission File Number 001-15214

TRANSALTA CORPORATION

(Translation of registrant’s name into English)

Suite 1400, 1100 - 1st Street S.E., Calgary, Alberta, T2G 1B1

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.


Form 20-F____			Form 40-F X

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):_____

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):_____

The documents listed below in this Section and filed as Exhibits 99.2 and 99.3 to this form 6-K are hereby filed with the Securities and Exchange Commission for the purpose of being and hereby are incorporated by reference into the following registration statements filed by TransAlta Corporation under the Securities Act of 1933, as amended:

Form Registration No.

S-8 333-72454

S-8 333-101470

S-8 333-236894

S-8 333-260935

F-10 333-292019

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


			TRANSALTA CORPORATION



			/s/ Mike Politeski
			Mike Politeski
			Executive Vice President, Finance and Chief Financial Officer

Date: July 30, 2026

EXHIBIT INDEX


99.2						Management’s Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended June 30, 2026
99.3						Consolidated comparative interim unaudited financial statements of the registrant as at and for the period ended June 30, 2026

TRANSALTA CORPORATION

Management’s Discussion and Analysis

This Management’s Discussion and Analysis (MD&A) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. Refer to the "Forward-Looking Statements" section of this MD&A for additional information.

Table of Contents

Forward-Looking Statements

M31

Cash Flows

Description of the Business

M32

Capital Expenditures

Highlights

M33

Other Consolidated Analysis

Significant and Subsequent Events

M33

Financial Instruments

Operating and Financial Performance

M33

Non-IFRS and Supplementary IFRS Measures

M14

2026 Outlook

M44

Material Accounting Policies, Accounting Changes and Critical Estimates

M15

Segmented Financial Performance and Operating Results by Geographical Location

M44

Governance and Risk Management

M21

Optimization of the Alberta Portfolio

M45

Regulatory Updates

M25

Selected Quarterly Information

M46

Disclosure Controls and Procedures

M26

Financial Condition

This MD&A should be read in conjunction with our unaudited interim condensed consolidated financial statements as at and for the six months ended June 30, 2026 and 2025, the audited annual consolidated financial statements and MD&A (2025 Annual MD&A) contained within our 2025 Annual Report. In this MD&A, unless the context otherwise requires, “we”, “our”, “us”, the “Company” and “TransAlta” refer to TransAlta Corporation and its subsidiaries. The unaudited interim condensed 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 June 30, 2026. 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 July 30, 2026. Additional information with respect to TransAlta, including our Annual Information form (AIF) for the year ended Dec. 31, 2025, 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. For the Glossary of Key Terms used in this MD&A refer to the 2025 Annual Report.


TransAlta Corporation			M1

Forward-Looking Statements

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

Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may", "will", "can", "could", "would", "shall", "believe", "expect", "estimate", "anticipate", "intend", "plan", "forecast", "foresee", "potential", "enable", "continue" or other comparable terminology. In particular, this MD&A contains forward-looking statements about the following, among other things:

•Our 2026 Outlook and the targets contained therein;

•Our hedging assumptions;

•Our estimated spot price sensitivity and the associated impacts on our Adjusted EBITDA target;

•Our expectation that cash flow from our operating activities will be sufficient to meet our short and long-term financial obligations;

•Our expectations about strategies for growth and expansion;

•Expected costs and schedules for planned projects, including the Centralia planned coal-to-gas conversion project;

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

•The cyclicality of our business;

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

•Expected industry, market and economic conditions.

The forward-looking statements contained in this MD&A are based on many assumptions including, but not limited to, the following:

•No significant changes to applicable laws and regulations, including carbon pricing, renewable energy incentives, royalty rates and climate-related regulations;

•No unexpected delays in obtaining required regulatory and other third-party approvals;

•No material adverse impacts to investment and credit markets;

•power price, gas commodity price, transport cost and hedging assumptions;

•interest and foreign exchange rates;

•demand for, and growth of, electricity generation;

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

•No significant changes to the Company's debt and credit ratings and the Company's ability to access the capital markets on reasonable terms;

•No significant changes to the Company's ability to develop, access or implement, on a timely basis and on reasonable terms, the technology necessary to efficiently and effectively operate the Company's assets and achieve expected future results;

•No significant supply chain disruptions or shortages of raw materials or skilled labour; and

•No material changes to international trade laws, regulations, agreements, treaties, taxes, tariffs, duties or policies of Canada, the United States or other countries.

These assumptions are based on information currently available to TransAlta, including information obtained from third-party sources. Actual results may differ materially from those predicted by such assumptions. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this MD&A include, but are not limited to:

•Changes in supply and demand for electricity;

•Fluctuations in power prices;

•Our ability to contract our electricity generation for prices that will provide expected returns and replace contracts as they expire;

•Risks associated with development projects and acquisitions;

•Our ability to develop, access or implement, on a timely basis and on reasonable terms, the technology necessary to efficiently and effectively operate our assets and achieve expected future results;

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

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

•Changes to legislative, regulatory and political environments, including changes to environmental laws, including but not limited to carbon pricing, renewable energy policies and emissions regulations in Canada, the United States and Australia;

•Operational risks involving our facilities, including unplanned outages and equipment failure, which may result in reductions in electricity production;

•Grid reliability, including but not limited to disruptions in the transmission and distribution of electricity;

•Impairments and/or writedowns of assets;

•Adverse impacts on our information technology systems, including increased cybersecurity threats;

•Commodity risk management and energy-trading risks, including but not limited to counterparty credit risks;

•Reduced labour availability, ability to continue to staff our operations and facilities, loss of key personnel and other labour relations matters;

•Disruptions to our supply chains;

•Climate change-related risks, including the increased frequency and severity of extreme weather events, and


M2			TransAlta Corporation

the impact of such extreme weather events on electricity supply and demand;

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

•General economic risks, including deterioration of equity markets, increasing interest rates, changes to foreign exchange rates or rising inflation;

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

•Industry risk and competition, including from emerging technologies affecting the demand, generation, distribution or storage of electricity;

•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; and

•Reputational and stakeholder-related risks.

The foregoing risk factors, among others, are described in further detail in the "Risk Management" section of the 2025 Annual Report.

Readers are urged to consider these factors carefully when evaluating the forward-looking statements, which reflect the Company's expectations only as of the date of this MD&A and are cautioned not to place undue reliance on them. The forward-looking statements included in this document are made only as of the date of its release 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 in this document is to give the reader information about management's current expectations and plans and readers are cautioned that such information may not be appropriate for other purposes. In light of these risks, uncertainties and assumptions, the forward-looking statements might occur to a different extent or at a different time than we have described, or might not occur at all. We cannot assure that projected results or events will be achieved.


TransAlta Corporation			M3

Description of the Business

TransAlta Corporation is one of Canada’s largest publicly traded power generators, with operations across Canada, the United States (U.S.) and Western Australia. Our diversified fleet includes hydro, wind, solar, battery storage and thermal generation, complemented by asset optimization and energy marketing activities. As one of Canada’s largest producers of wind and thermal generation and Alberta’s largest producer of hydroelectric power, TransAlta remains committed to a diverse generation mix. With strong cash flows underpinned by a high-quality portfolio, TransAlta strives to deliver sustainable long-term shareholder value in an evolving energy landscape. We have four generation segments including Hydro, Wind and Solar, Gas and Energy Transition, along with two non-generation segments including Energy Marketing and Corporate.

Our diversified portfolio consists of both high-quality contracted assets and merchant assets. Our contracted

assets provide stable long-term cash flow and earnings, balancing our merchant fleet. Our merchant assets include our unique hydro portfolio, legacy and peaking thermal assets and wind assets. Our merchant exposure is primarily in Alberta, where 61 per cent of our generating capacity is located and 77 per cent exposed to the merchant market.

In Alberta, the Company manages its 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 and hydro generation capacity in Alberta may be hedged to enhance cash flow predictability while maintaining exposure to market upside.

Refer to the "2026 Outlook" and the "Optimization of the Alberta Portfolio" sections of this MD&A for further details.

The following table provides our consolidated ownership by segment of our facilities across Alberta and other regions in which we operate as at June 30, 2026:


As at June 30, 2026		Hydro	Wind & Solar	Gas(4)(5)	Total
Alberta	Gross installed capacity (MW)(2)	834	764	3,650	5,248
	Number of facilities	17	14	15	46
	Weighted average contract life (years)	—	15	8	10
	Contracted capacity (MW)	—	336	887	1,223
	Contracted capacity as a % of total capacity (%)	—	44	24	23

















Other regions(1)	Gross installed capacity (MW)(2)	88	1,823	1,464	3,375
	Number of facilities	7	22	14	43
	Weighted average contract life (years)	14	10	7	9
	Contracted capacity (MW)	88	1,823	1,464	3,375
	Contracted capacity as a % of total capacity (%)	100	100	100	100
Total	Gross installed capacity (MW)(2)	922	2,587	5,114	8,623
	Number of facilities	24	36	29	89
	Weighted average contract life (years)	14	11	8	9
	Contracted capacity (MW)	88	2,159	2,351	4,598
	Contracted capacity as a % of total capacity (%)(3)	10	83	46	53

(1)Other regions include the U.S., Western Australia and Canada, excluding Alberta. Gross installed capacity across all segments for the U.S., Western Australia and Canada, excluding Alberta, totaled 1,024 MW, 498 MW and 1,853 MW, respectively, with the number of facilities across all segments totaling 10, 9 and 24, respectively. Refer to 2025 Annual Report for details.

(2)Gross installed capacity for consolidated reporting is based on a proportionate interest held in a facility.

(3)Approximately 53 per cent of our total installed capacity is contracted with creditworthy counterparties.

(4)Gas segment includes gross installed capacity of 310 MW from four facilities in Ontario attributable to the acquisition of Far North. Refer to the "Significant and Subsequent events" section.

(5)Gas segment excludes Ada Cogeneration facility in the U.S, with a fully contracted gross installed capacity of 29 MW, due to its retirement on Jan. 5, 2026.


M4			TransAlta Corporation

Following Centralia's cessation of coal-fired operations at the end of 2025 in the normal course, the Energy Transition segment is no longer considered a reportable segment. The segment has therefore been excluded from the table above. Refer to Note 16 of our unaudited interim condensed consolidated financial statements for details.

The facility currently remains available for power generation in accordance with and for the duration of the order received from the U.S. Department of Energy. Refer to the "Significant and Subsequent Events" section for details.

Highlights



	3 months ended June 30		6 months ended June 30
(in millions of Canadian dollars except where noted)	2026	2025	2026	2025
Operational information(1)
Availability (%)	90.2	91.6	92.0	93.3
Production (GWh)	4,720	4,813	10,164	11,645
Select financial information(1)
Revenues	487	433	1,052	1,191



Adjusted EBITDA(2)	291	349	495	619
Adjusted Earnings before Income Taxes(2)	105	122	135	150
Earnings (loss) before income taxes	80	(95)	103	(46)
Adjusted Net Earnings Attributable to Common Shareholders(2)	54	54	72	84
Net earnings (loss) attributable to common shareholders	35	(112)	48	(66)
Cash flows(1)
Cash flow from operating activities	62	157	185	164
Funds from operations(2)	201	252	338	431
Free cash flow(2)	143	177	245	316
Per share(1)
Weighted average number of common shares outstanding (in millions)	302	297	300	297
Adjusted Net Earnings Attributable to Common Shareholders per share(2)(3)(4)	0.18	0.18	0.19	0.28
Net earnings (loss) per share attributable to common shareholders, basic and diluted(4)	0.12	(0.38)	0.11	(0.22)
Dividends declared per common share	—	—	0.07	0.07

Cash flow from operating activities per share(5)	0.21	0.53	0.62	0.55
Funds from operations per share(2)(3)	0.67	0.85	1.13	1.45
Free cash flow per share(2)(3)	0.47	0.60	0.82	1.06

(1)IFRS financial statements for the six months ended June 30, 2025 include the results attributable to Poplar Hill and Rainbow Lake facilities (collectively, the Required Divestitures), which the Company divested in accordance with a consent agreement entered into with the Commissioner of Competition for Canada. Our non-IFRS measures and operational Key Performance Indicators exclude the results of the Required Divestitures.

(2)These are non-IFRS measures and ratios, which are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Segmented Financial Performance and Operating Results by Geographical Location" section of this MD&A for further discussion of these items. Also, refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding these non-IFRS measures and ratios, including, where applicable, reconciliations to measures calculated in accordance with IFRS.

(3)Adjusted Net Earnings Attributable to Common Shareholders per share, 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 "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding these non-IFRS measures and ratios.

(4)Net earnings (loss) attributable to common shareholders and Adjusted Net Earnings Attributable to Common Shareholders used in calculating net earnings (loss) per share attributable to common shareholders and Adjusted Net Earnings Attributable to Common Shareholders per share reflect the cumulative preferred share dividend entitlement required for the current period.

(5)Represents a supplementary financial measure and is calculated as cash flow from operating activities for the period divided by the weighted average number of common shares outstanding during the period.


TransAlta Corporation			M5


(in millions of Canadian dollars except where noted)
As at	June 30, 2026	Dec. 31, 2025
Liquidity and capital resources
Available liquidity(1)	1,751	1,500
Adjusted Net Debt to Adjusted EBITDA (times)(2)(3)	4.3	4.0
Adjusted Net Debt(2)(4)	4,200	4,396
Assets and liabilities
Total assets	8,842	8,661
Total long-term liabilities(5)	5,302	5,366
Total liabilities	6,993	7,196

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

(3)The most directly comparable IFRS ratio to Adjusted Net Debt to Adjusted EBITDA (times) is calculated as credit facilities, long-term debt and lease liabilities of $3,489 million (Dec. 31, 2025 — $3,593 million) divided by earnings before income taxes for the last four quarters of $8 million (Dec. 31, 2025 — loss before income taxes $141 million) and is equal to 436 times (Dec. 31, 2025 — (25) times). Refer to the "Financial Condition" section of this MD&A for details of the calculation.

(4)The most directly comparable IFRS measure to Adjusted Net Debt is total credit facilities, long-term debt and lease liabilities, which is equal to $3,489 million (Dec. 31, 2025 — $3,593 million). Refer to the table in the "Financial Condition" section of this MD&A for more details on the composition of Adjusted Net Debt.

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

Significant and Subsequent Events

Centralia Unit 2 Mandated to Remain Available for additional 90 days

On June 12, 2026, the Company received another order from the U.S. Department of Energy (the Order) requiring that our 700 MW Centralia Unit 2 facility (Facility) remain available for operation for an additional period of 90 days, until Sept. 13, 2026. As previously communicated, the Company has been subject to the Order from the U.S. Department of Energy since Dec. 16, 2025. The Company is currently compliant with the Order and continues to work with the state and federal governments in relation thereto. The facility had no generation during the six months ended June 30, 2026.

Acquisition of Mountain Peak Power and Canyon Peak Power and associated public offering of common shares

On June 3, 2026, the Company announced that it had entered into an agreement with an indirect subsidiary of Blackstone, Inc., to acquire Mountain Peak Power and Canyon Peak Power, two fully contracted natural gas-fired peaking facilities totaling 318 MW near Denver, Colorado (the "Acquisition"). The purchase price for the Acquisition

is US$1 billion, including the assumption of US$750 million of project debt.

On June 9, 2026 the Company closed a public offering of 18,230,000 common shares at a price of $19.20 per share through a syndicate of underwriters, for total gross proceeds of approximately $350 million, which will be used to fund the cash portion of the purchase price for the Acquisition. The proceeds received in advance of the Acquisition were partially used to repay the drawn amounts under the syndicated credit facility.

The Acquisition is subject to Canyon Peak Power achieving commercial in-service as well as customary closing conditions, including receipt of regulatory approvals. The Acquisition is expected to close early in the fourth quarter of 2026.

Executive Team Changes

John Kousinioris, President and Chief Executive Officer and a Director of TransAlta, retired on April 30, 2026. Joel Hunter, TransAlta's Executive Vice President, Finance and CFO, succeeded Mr. Kousinioris as President and Chief Executive Officer effective April 30, 2026. Mr. Hunter was also elected to the Board of Directors at the Corporation's annual shareholder meeting on April 30, 2026.


M6			TransAlta Corporation

Mike Politeski was appointed Executive Vice President, Finance and CFO, effective May 1, 2026 and Grant Arnold was appointed Executive Vice President, Growth and Chief Commercial Officer, effective May 6, 2026. Nancy Brennan, who previously held the position of Executive Vice President, Legal and External Affairs, was appointed Chief Legal, People and Corporate Affairs Officer, effective June 8, 2026. Chris Fralick, who previously held the position of Executive Vice President, Generation was appointed Executive Vice President, Generation and Chief Operating Officer, effective June 8, 2026.

Memorandum of Understanding for Data Centre Development at Keephills Site Signed

On Feb. 26, 2026, the Company entered into a Memorandum of Understanding (MOU) with Canada Pension Plan Investments and Brookfield to advance a data centre development in Alberta, for which TransAlta is the exclusive site and power provider. The MOU establishes a framework for phased development at the Company's Keephills site in Parkland County, including an initial long-term power purchase agreement for approximately 230 MW and the evaluation of additional development aggregating up to 1 gigawatt of load. Development is subject to regulatory approvals and the parties reaching definitive agreements.

Declared Increase in Common Share Dividend

The Company’s Board has approved a $0.02 annualized (eight per cent) increase to the common share dividend and declared a dividend of $0.07 per common share on Feb. 25, 2026 to be payable on July 1, 2026 to shareholders of record at the close of business on June 1, 2026. The quarterly dividend of $0.07 per common share represents an annualized dividend of $0.28 per common share.

On July 28, 2026 TransAlta's Board approved the quarterly dividend payment of $0.07 per common share.

Mothballing of Sheerness Unit 1

On Apr. 1, 2026, the Company mothballed Sheerness Unit 1. The Company initially provided notice to the Alberta Electric System Operator (AESO) on Dec. 18, 2025, that Sheerness Unit 1 would be mothballed on April 1, 2026, for a period of up to two years. The Company maintains the flexibility to return the mothballed unit to service when market fundamentals improve or contracting opportunities are secured.

Acquisition of Far North

On Feb. 2, 2026, the Company closed the acquisition of Far North Power Corporation (Far North), including 310 MW of capacity from four natural gas-fired facilities, for a purchase price of $95 million from an affiliate of Hut 8 Corporation, subject to working capital and other adjustments. The net cash payment for the transaction was funded through a combination of cash on hand and borrowings under TransAlta's credit facilities.


TransAlta Corporation			M7

Operating and Financial Performance

Operating Performance

Availability

The following table provides availability (%) by segment:


	3 months ended June 30,		6 months ended June 30,
	2026	2025	2026	2025
Hydro	89.1	97.0	92.2	95.3
Wind and Solar	94.0	94.7	93.4	94.3
Gas	88.0	90.2	91.1	92.9
Energy Transition(1)	100.0	81.3	100.0	89.1
Availability(1) (%)	90.2	91.6	92.0	93.3

(1)Centralia Unit 2 facility ceased coal-fired operations at the end of 2025 in the normal course and therefore, the facility is excluded from total availability. The facility remains available for power generation as mandated by the United States Department of Energy.

Availability measures the percentage of time a facility is able to produce electricity and is a key indicator of fleet performance.

Availability for the three and six months ended June 30,

2026, was 90.2 and 92.0 per cent compared to 91.6 and 93.3 per cent, respectively, for the same periods in 2025, primarily due to higher unplanned maintenance outages in the Gas, Hydro and Wind and Solar segments.

Production and Long-Term Average Generation

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


	2026				2025
3 months ended June 30	Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA		Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA
Hydro	685	568	121	%	572	593	96	%
Wind and Solar	1,558	1,603	97	%	1,513	1,754	86	%


Gas	2,477				2,486
Energy Transition	—				242


Total	4,720				4,813


	2026				2025
6 months ended June 30	Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA		Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA
Hydro	1,045	941	111	%	955	995	96	%
Wind and Solar	3,496	3,524	99	%	3,418	3,810	90	%


Gas	5,623				5,990
Energy Transition	—				1,282


Total	10,164				11,645


M8			TransAlta Corporation

In addition to availability, the Company uses long‑term average (LTA) generation as a key performance indicator for its renewable facilities, comparing actual production to expected long‑term output. While Hydro and Wind and Solar production can vary period to period, over longer durations, facilities are expected to perform in-line with their LTA, which represents an annualized energy output expected from our facilities based on historical resource data, observed operating performance and forward‑looking assumptions about future conditions. LTA generation is not applicable to the Gas segment, as these dispatchable facilities operate based on market conditions, and merchant and customer demand.

Total production for the three and six months ended June 30, 2026, decreased by 93 and 1,481 GWh, or two and 13

per cent, respectively, compared to the same periods in 2025, primarily due to:

•No production at Centralia Unit 2 in the Energy Transition segment. Refer to the "Description of the Business" section of this MD&A; partially offset by

•Higher production in the Hydro segment due to higher water resource; and

•Higher production volumes in the Wind and Solar segment due to higher wind resource.

Total production for the six months ended June 30, 2026 was further impacted by lower market prices, resulting in higher dispatch optimization in Alberta in the Gas segment.

Financial Performance Review of Consolidated Information



	3 months ended June 30,		6 months ended June 30,
	2026	2025	2026	2025
Revenues	487	433	1,052	1,191


Gross Margin	433	334	794	766
Operations, maintenance and administration	(175)	(173)	(356)	(346)
Depreciation and amortization	(105)	(150)	(210)	(296)



Interest expense	(84)	(88)	(166)	(181)

Earnings (loss) before income taxes	80	(95)	103	(46)

Net earnings (loss) attributable to common shareholders	35	(112)	48	(66)


Adjusted Earnings before Income Taxes(1)	105	122	135	150
Adjusted Net Earnings Attributable to Common Shareholders(1)	54	54	72	84

(1)These are non-IFRS measures. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.

Three months ended June 30, 2026 Variance Analysis (2026 versus 2025)

Revenues for the three months ended June 30, 2026, increased by $54 million, or 12 per cent, compared to the same period in 2025, primarily due to:

•Lower unrealized mark-to-market losses and an increase in favourable hedge positions settled, which generated positive contributions over settled spot prices; partially offset by

•No production at Centralia Unit 2;

•Lower revenues in the Gas and Hydro segments due to lower spot and ancillary services prices in the Alberta market, partially offset by higher merchant volumes in the Hydro segment; and

•Lower revenue from the Sarnia gas facility due to contract renewal at a lower price and the retirement of the Ada Cogeneration facility.

Mark-to-market losses in the current period were also impacted by the adoption of IFRS 9 hedge accounting, effective Jan. 1, 2026. Refer to the "Material Accounting Policies, Accounting Changes and Critical Accounting Estimates" section of this MD&A for details.

Gross Margin for the three months ended June 30, 2026, increased by $99 million, or 30 per cent, compared to the same period in 2025, primarily due to the factors which increased revenues, as explained above. This was partially offset by lower carbon compliance recovery due to the use of fewer emission credits to settle a portion of our 2025 GHG obligation compared to the emission credits used to settle the 2024 obligation.

OM&A expenses for the three months ended June 30, 2026 were comparable to the same period in 2025, primarily due to:

•Higher termination and restructuring costs; and


TransAlta Corporation			M9

•Addition of OM&A from the acquisition of Far North facilities; partially offset by

•Lower spending due to one-time costs incurred during the prior period and current period saving initiatives;

•Lower spending following the successful completion of an upgrade to our enterprise resource planning (ERP) system during the three months ended March 31, 2026; and

•Expected cost recoveries as a result of complying with the Order related to Centralia.

Depreciation and amortization for the three months ended June 30, 2026, decreased by $45 million, or 30 per cent, compared to the same period in 2025, primarily due to:

•Lower depreciation in the Gas segment in the current period due to a change in the useful life assumptions in 2025 for the Sheerness facilities; and

•Lower depreciation for Centralia Unit 2 due to the cessation of coal-fired operations in the normal course.

Interest expense for the three months ended June 30, 2026, decreased by $4 million, or 5 per cent, compared to 2025, primarily due to:

•Lower interest on certain senior notes following their refinancing at lower interest rates during 2025; and

•Lower accretion on provisions primarily due to lower interest rates in the current period.

Earnings before income taxes for the three months ended June 30, 2026, increased by $175 million, or 184 per cent, from loss before income taxes in the same period in 2025, primarily due to:

•The items noted above; and

•Higher unrealized and realized foreign exchange gains mainly due to favourable changes in foreign currency rates.

Net earnings attributable to common shareholders for the three months ended June 30, 2026, increased by $147 million, or 131 per cent, from net loss attributable to common shareholders in the same period of 2025, primarily due to:

•The items noted above; partially offset by

•Higher income taxes due to an increase in earnings before income taxes; partially offset by

•Lower writedown of unrecognized deferred tax assets; and

•Higher net earnings attributable to non-controlling interests in the current period.

Adjusted Earnings before Income Taxes for the three months ended June 30, 2026, decreased by $17 million, or 14 per cent, compared to the same period in 2025, primarily due to:

•The factors causing lower Adjusted EBITDA described in the "Adjusted EBITDA" section of this MD&A; partially offset by

•Lower depreciation and amortization, and lower interest expense as explained above.

Adjusted Net Earnings Attributable to Common Shareholders for the three months ended June 30, 2026 were comparable to the same period in 2025.

Six months ended June 30, 2026 Variance Analysis (2026 versus 2025)

Revenues for the six months ended June 30, 2026 totalled $1,052 million, a decrease of $139 million, or 12 per cent, compared to the same period in 2025, primarily due to:

•No production at Centralia Unit 2;

•Lower revenues for the Hydro and Gas segments due to lower spot and ancillary services prices in the Alberta market;

•Lower revenue from the Sarnia gas facility due to contract renewal at a lower price and the retirement of the Ada Cogeneration facility;

•Lower availability and wind resource in Eastern Canada; and

•Lower environmental and tax attributes revenues in the Hydro segment due to lower sales of emission credits to third parties; partially offset by

•Lower unrealized mark-to-market losses and an increase in favourable hedge positions settled, which generated positive contributions over settled spot prices.

Gross Margin for the six months ended June 30, 2026 increased by $28 million, or 4 per cent, compared to the same period in 2025, primarily due to the factors which decreased revenues, as explained above, and was further impacted by lower carbon compliance recovery due to the use of fewer emission credits to settle a portion of our 2025 GHG obligation compared to the emission credits used to settle the 2024 obligation.

OM&A expenses for the six months ended June 30, 2026 increased by $10 million, or 3 per cent, compared to the same period in 2025, primarily due to:

•Higher termination and restructuring costs;


M10			TransAlta Corporation

•Higher legal costs arising from cost determinations made after the conclusion of arbitration proceedings; and

•Addition of OM&A from the acquisition of Far North facilities; partially offset by

•Lower spending due to one-time costs incurred during the prior period and current period saving initiatives; and

•Expected cost recoveries as a result of complying with the Order related to Centralia.

Depreciation and amortization for the six months ended June 30, 2026 totalled $210 million, a decrease of $86 million, or 29 per cent, compared to the same period in 2025, primarily due to the factors listed above in the three month ended June 30, 2026 variance analysis.

Interest expense for the six months ended June 30, 2026 totalled $166 million, a decrease of $15 million, or 8 per cent, compared to the same period in 2025, due to the factors listed above in the three month ended June 30, 2026 variance analysis.

Earnings before income taxes for the six months ended June 30, 2026 totalled $103 million, an increase of $149 million, or 324 per cent from loss before income taxes in the same period in 2025, primarily due to:

•The items noted above;

•Higher unrealized and realized foreign exchange gains mainly due to favourable changes in foreign currency rates;

•Lower asset impairment charges primarily related to a change in the discount rates on decommissioning and restoration provisions on retired assets; partially offset by

•Impairment reversal in the comparative period related to generation equipment classified as held for sale; and

•Higher other operating income due to legal settlement recoveries.

Net earnings attributable to common shareholders for the six months ended June 30, 2026 increased by $114 million, or 173 per cent from net loss attributable to common shareholders in the same period in 2025, primarily due to:

•The items noted above; partially offset by

•Higher income taxes due to an increase in earnings before income taxes, partially offset by other non-taxable differences; and

•Higher net earnings attributable to non-controlling interests in the current period.

Adjusted Earnings before Income Taxes for the six months ended June 30, 2026, decreased by $15 million, or 10 per cent, compared to the same period in 2025, primarily due to:

•The factors causing lower Adjusted EBITDA described in the "Adjusted EBITDA" section of this MD&A; partially offset by

•Lower depreciation and amortization, and lower interest expense as explained above.

Adjusted Net Earnings Attributable to Common Shareholders for the six months ended June 30, 2026, decreased by $12 million, or 14 per cent compared to the same period in 2025, primarily due to:

•Higher net earnings attributable to non-controlling interests as explained above;

•The factors causing lower Adjusted Earnings before Income Taxes explained above;

•Higher income tax expense as explained above; partially offset by

•Lower calculated tax expense on adjustments and reclassifications compared to the same period in 2025.

Refer to the "Segmented Financial Performance and Operating Results by Geographical Location" section for additional information.


TransAlta Corporation			M11

Adjusted EBITDA

For the three and six months ended June 30, 2026, the Company's Adjusted EBITDA was $291 million and $495 million, respectively, compared to $349 million and $619 million, respectively, for the same period in 2025, a decrease of $58 million and $124 million, or 17 and 20 per cent, respectively.

The major factors impacting Adjusted EBITDA are summarized in the following table:


			3 months ended June 30
Adjusted EBITDA(1) for the three months ended June 30, 2025			349
Hydro: Lower primarily driven by reduced environmental and tax attributes revenues, reflecting lower intercompany sales of emission credits to the Gas segment to meet GHG compliance obligations and lower sales of emission credits to third parties. Results were also negatively impacted by lower Alberta spot power and ancillary services prices. These decreases were partially offset by favourable hedge pricing and higher merchant volumes resulting from higher water resources.			(39)
Wind and Solar: Comparable due to higher revenue due to higher availability and wind resource in the U.S., partially offset by lower availability and lower wind resource in Eastern Canada, and lower Alberta spot power prices.			1
Gas: Higher primarily due to higher favourable hedge positions settled, which generated positive contribution over settled spot prices in Alberta and a positive contribution from the acquisition of Far North facilities. This was partially offset by lower expected revenue from Sarnia following contract renewal at a lower price and the retirement of the Ada Cogeneration facility and higher dispatch optimization in the current period.			14
Energy Marketing: Lower primarily due to comparatively subdued market volatility across North American natural gas and power markets and lower realized gains in the current period compared to the same period in the prior year.			(16)
Corporate: Comparable to the same period in 2025.			3
Energy Transition: Lower due to no production at Centralia Unit 2.			(21)
Adjusted EBITDA(1) for the three months ended June 30, 2026			291

(1)Adjusted EBITDA is a non-IFRS measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A. The most directly comparable IFRS measure is earnings before income taxes of $80 million (loss before income taxes of $95 million for the three months ended June 30, 2025). Refer to the "Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segments" section of this MD&A.


			6 months ended June 30
Adjusted EBITDA(1) for the six months ended June 30, 2025			619
Hydro: Lower primarily driven by reduced environmental and tax attributes revenues, reflecting lower intercompany sales of emission credits to the Gas segment to meet GHG obligations and lower sales of emission credits to third parties. Results were also negatively impacted by lower Alberta spot power and ancillary services prices. These decreases were partially offset by favourable hedge pricing and higher merchant volumes resulting from higher water resources.			(51)
Wind and Solar: Lower due to reduced availability and reduced wind resource in Eastern Canada, lower Alberta spot power prices, partially offset by higher availability and wind resource in the U.S.			(6)
Gas: Comparable primarily due to lower revenue from the Sarnia gas facility due to contract renewal at a lower price and the retirement of the Ada Cogeneration facility. This was partially offset by a positive contribution from the acquisition of Far North facilities, higher average realized pricing in Eastern Canada and lower purchased power costs due to lower market prices.			3
Energy Marketing: Lower primarily due to comparatively subdued market volatility across North American natural gas and power markets and lower realized gains in the current period compared to the same period in the prior year.			(20)
Corporate: Higher primarily due to lower OM&A driven by one-time costs incurred during the prior period and current period saving initiatives.			7
Energy Transition: Lower due to no production at Centralia Unit 2.			(57)
Adjusted EBITDA(1) for the six months ended June 30, 2026			495

(1)Adjusted EBITDA is a non-IFRS measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A. The most directly comparable IFRS measure is earnings before income taxes of $103 million (loss before income taxes of $46 million for the six months ended June 30, 2025). Refer to "Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segments" section of this MD&A.


M12			TransAlta Corporation

Free Cash Flow

For the three and six months ended June 30, 2026, the Company's FCF decreased by $34 million, or 19 per cent and $71 million, or 22 per cent, respectively, compared to the same periods in 2025.

The major factors impacting FCF are summarized in the following table:


			3 months ended June 30
FCF(1) for the three months ended June 30, 2025			177
Lower Adjusted EBITDA due to the items noted above.			(58)

Lower current income tax expense.			20
Lower sustaining capital expenditures at our Canadian gas facilities due to timing of spend.			18




Other(2)			(14)

FCF(1) for the three months ended June 30, 2026			143

(1)FCF is a non-IFRS measure, is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding this measure. The most directly comparable IFRS measure is cash flow from operating activities, which was $62 million and $157 million for the three months ended June 30, 2026 and 2025, respectively. Refer to the "Cash Flows" section of this MD&A.

(2)Other consists primarily of changes in contract assets and liabilities, deferred payments, onerous contracts and legal settlement. Other also includes higher realized foreign exchange loss from operating activities, higher provisions settled, partially offset by lower net interest expense and lower decommissioning and restoration costs settled.


			6 months ended June 30
FCF(1) for the six months ended June 30, 2025			316
Lower Adjusted EBITDA due to the items noted above.			(124)
Lower current income tax expense.			21
Lower Net Interest Expense(2) due to lower interest on certain senior notes following their refinancing at lower interest rates during 2025.			17


Lower sustaining capital expenditures at our Canadian gas facilities due to timing of spend.			20
Higher realized foreign exchange gains from operating activities.			12




Other(3)			(17)
FCF(1) for the six months ended June 30, 2026			245

(1)FCF is a non-IFRS measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding this measure. The most directly comparable IFRS measure is cash flow from operating activities, which was $185 million and $164 million for the six months ended June 30, 2026 and 2025, respectively. Refer to the "Cash Flows" section of this MD&A.

(2)Net Interest Expense is a non-IFRS measure. Net Interest Expense reconciliation is available in "Financial Condition" section of this MD&A. The most directly comparable IFRS measure is interest expense of $166 million and $181 million for the six months ended June 30, 2026 and 2025, respectively.

(3)Other primarily consists of changes in contract assets and liabilities, deferred payments, onerous contracts and legal settlement. Other also includes higher provisions settled and lower decommissioning and restoration costs settled.


TransAlta Corporation			M13

2026 Outlook

For 2026, the Company reaffirms Adjusted EBITDA to be in the range of $950 million to $1,050 million and FCF to be in the range of $350 million to $450 million. For details, please refer to the "2026 Outlook" section of the 2025 Annual Report for the assumptions which have remained the same.

The following table outlines our expectations on key financial targets and related assumptions for 2026 and should be read in conjunction with the narrative discussion that follows and the "Risk Management" section of the 2025 Annual MD&A:

Measure

6 months ended June 30, 2026(2)

2026 Target(3)

2025 Actual(4)

Adjusted EBITDA(1)

$495 million

$950 million to $1,050 million

$1,104 million

FCF(1)

$245 million

$350 million to $450 million

$514 million

FCF per share(1)

$0.82

$1.18 to $1.51

$1.73

Dividend per share

$0.07

$0.28 annualized

$0.26 annualized

(1)These are non-IFRS measures. Refer to the "Reconciliation of Non-IFRS Measures" section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.

(2)The six month ended June 30, 2026 amounts for the most directly comparable IFRS measures for Adjusted EBITDA and FCF were as follows: Earnings before income taxes of $103 million and cash flow from operating activities of $185 million. The most directly comparable IFRS ratio to FCF per share is cash flow from operating activities per share of $0.62. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for additional information.

(3)Represents forward-looking information.

(4)The actual 2025 amounts for the most directly comparable IFRS measures for Adjusted EBITDA and FCF were as follows: Loss before income taxes of $141 million and Cash flow from operating activities of $646 million. The most directly comparable IFRS ratio to FCF per share is cash flow from operating activities per share of $2.18. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for additional information.

The Company's 2026 outlook may be impacted by a number of factors, including hedging assumptions detailed further below.

Alberta Hedging


Range of hedging assumptions	Q3 2026	Q4 2026	Full Year 2026	Full year 2027
Hedged production (GWh)	2,394	2,089	8,985	6,631
Hedge price ($/MWh)	$64	$65	$66	$64
Hedged gas amounts (GJ)	9 million	7 million	37 million	28 million
Hedge gas prices ($/GJ)	$3.06	$3.39	$3.17	$2.79

Alberta spot price sensitivity: a +/- $1 per MWh change in spot price is expected to have a +/- $1.5 million impact on Adjusted EBITDA for the remainder of 2026.


M14			TransAlta Corporation

Segmented Financial Performance and Operating Results by Geographical Location

Segmented information is prepared on the same basis that the Company manages its business, evaluates financial results and makes key operating decisions. The following table reflects the Adjusted EBITDA by segment across the regions we operate in for the three and six months ended June 30, 2026 and 2025:


















3 months ended June 30, 2026	Hydro	Wind & Solar(2)	Gas	Energy Marketing	Corporate	Energy Transition	Total
Alberta	83	22	95	10	(36)	(3)	171
Canada, excluding Alberta	4	26	21	—	—	—	51
U.S.	—	40	(1)	—	—	1	40
Western Australia	—	2	27	—	—	—	29
Adjusted EBITDA(1)	87	90	142	10	(36)	(2)	291
Adjusted Earnings (Loss) before Income Taxes(1)	76	41	101	10	(120)	(3)	105
Earnings (loss) before income taxes	73	34	94	18	(131)	(8)	80

3 months ended June 30, 2025	Hydro	Wind & Solar(2)	Gas	Energy Marketing	Corporate	Energy Transition	Total
Alberta	120	21	76	26	(39)	(3)	201
Canada, excluding Alberta	6	32	27	—	—	—	65
U.S.	—	34	2	—	—	22	58
Western Australia	—	2	23	—	—	—	25
Adjusted EBITDA(1)	126	89	128	26	(39)	19	349
Adjusted Earnings (Loss) before Income Taxes(1)	118	37	54	26	(119)	6	122
Earnings (loss) before income taxes	100	(32)	(23)	30	(150)	(20)	(95)

(1)Adjusted EBITDA and Adjusted Earnings (Loss) before Income Taxes are non-IFRS measures. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.

(2)Earnings (loss) before income taxes for the Wind and Solar segment exclude the contribution from Skookumchuck wind facility.


TransAlta Corporation			M15


6 months ended June 30, 2026	Hydro	Wind & Solar(2)	Gas	Energy Marketing	Corporate	Energy Transition	Total
Alberta	118	34	142	27	(73)	(4)	244
Canada, excluding Alberta	4	59	40	—	—	—	103
U.S.	—	88	(1)	—	—	3	90
Western Australia	—	4	54	—	—	—	58
Adjusted EBITDA(1)	122	185	235	27	(73)	(1)	495
Adjusted Earnings (Loss) before Income Taxes(1)	102	86	152	27	(230)	(2)	135
Earnings (loss) before income taxes	102	80	157	46	(274)	(8)	103

6 months ended June 30, 2025	Hydro	Wind & Solar(2)	Gas	Energy Marketing	Corporate	Energy Transition	Total
Alberta	167	31	126	47	(80)	(5)	286
Canada, excluding Alberta	6	80	54	—	—	—	140
U.S.	—	76	5	—	—	61	142
Western Australia	—	4	47	—	—	—	51
Adjusted EBITDA(1)	173	191	232	47	(80)	56	619
Adjusted Earnings (Loss) before Income Taxes(1)	156	86	94	45	(259)	28	150
Earnings (loss) before income taxes	159	(21)	42	48	(301)	27	(46)

(1)Adjusted EBITDA and Adjusted Earnings (Loss) before Income Taxes are non-IFRS measures. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.

(2)Earnings (loss) before income taxes for the Wind and Solar segment exclude the contribution from Skookumchuck wind facility.


M16			TransAlta Corporation

Hydro



	3 months ended June 30					6 months ended June 30
	2026	2025	Change			2026	2025	Change




Production
Contract production (GWh)	120	139	(19)	(14)	%	172	177	(5)	(3)	%
Merchant production (GWh)	565	433	132	30	%	873	778	95	12	%
Total energy production (GWh)	685	572	113	20	%	1,045	955	90	9	%
Ancillary service volumes (GWh)(1)	730	786	(56)	(7)	%	1,556	1,499	57	4	%

Alberta Hydro Assets ancillary services revenues(1)	24	33	(9)	(27)	%	47	53	(6)	(11)	%
Alberta Hydro Assets revenues(2)	32	39	(7)	(18)	%	54	65	(11)	(17)	%
Other Hydro Assets revenues and other Hydro revenues(3)	19	15	4	27	%	27	24	3	13	%

Environmental and tax attributes revenues	28	60	(32)	(53)	%	29	70	(41)	(59)	%


Adjusted Revenues(4)	103	147	(44)	(30)	%	157	212	(55)	(26)	%





Adjusted EBITDA(4)	87	126	(39)	(31)	%	122	173	(51)	(29)	%


Earnings before income taxes	73	100	(27)	(27)	%	102	159	(57)	(36)	%

(1)Alberta Hydro Assets ancillary services revenues is a supplementary financial measure. Alberta Hydro Assets ancillary services revenues are revenues earned from providing services required to ensure that the interconnected electric system is operated in a manner that provides a satisfactory level of service with acceptable levels of voltage and frequency as described in the AESO Consolidated Authoritative Document Glossary. Revenues per MWh are calculated by dividing Alberta Hydro Assets ancillary services revenues by ancillary service volumes in MWh.

(2)Alberta Hydro Assets revenues is a supplementary financial measure and is comprised of revenues from 13 hydro facilities on the Bow and North Saskatchewan river systems, as well as revenues from swaps and forward hedges. Revenues per MWh are calculated by dividing Alberta Hydro Assets revenues by merchant production in MWh.

(3)Other Hydro Assets revenues is a supplementary financial measure and consists of revenues from our hydro facilities in British Columbia, Ontario and Alberta (other than the Alberta Hydro Assets). Other Hydro revenues is a supplementary financial measure and includes revenues from our transmission business and other contractual arrangements, including the flood mitigation agreement with the Government of Alberta and black start services.

(4)Adjusted Revenues and Adjusted EBITDA are non-IFRS measures, are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding these measures. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $100 million and $157 million for the three and six months ended June 30, 2026, respectively (June 30, 2025 — $129 million and $215 million), to Adjusted EBITDA — earnings before income taxes of $73 million and $102 million for the three and six months ended June 30, 2026, respectively (June 30, 2025 — $100 million and $159 million).

Adjusted Revenues and Adjusted EBITDA for the three and six months ended June 30, 2026 decreased compared to the same periods in 2025, primarily due to:

•Lower environmental and tax attributes revenues due to lower intercompany sales of emission credits to the Gas segment to fulfill our GHG obligation and lower sales of emission credits to third parties; and

•Lower spot and ancillary services prices in the Alberta market, net of favourable hedge pricing; partially offset by

•Higher merchant volumes due to higher water resource.

Earnings before income taxes for the three and six months ended June 30, 2026 decreased compared to the same period in 2025, primarily due to lower Adjusted EBITDA as explained above.

Earnings before income taxes for the three months ended June 30, 2026 was further impacted by lower unrealized mark-to-market losses due to favourable changes in forward prices in the current period.

For further discussion on Alberta market conditions and pricing, refer to the "Optimization of Alberta Portfolio" section of this MD&A.


TransAlta Corporation			M17

Wind and Solar



	3 months ended June 30					6 months ended June 30
	2026	2025	Change			2026	2025	Change




Production
Contract production (GWh)	1,325	1,292	33	3	%	2,895	2,902	(7)	—	%
Merchant production (GWh)	233	221	12	5	%	601	516	85	16	%
Total production (GWh)	1,558	1,513	45	3	%	3,496	3,418	78	2	%



Adjusted Revenues(1)(2)(3)	124	129	(5)	(4)	%	257	274	(17)	(6)	%






Adjusted EBITDA(2)(3)	90	89	1	1	%	185	191	(6)	(3)	%


Earnings (loss) before income taxes(4)	34	(32)	66	(206)	%	80	(21)	101	(481)	%
Supplementary information:
Environmental and tax attributes revenues(1)	39	39	—	—	%	63	65	(2)	(3)	%

(1)Production Tax Credits related to the U.S. wind facilities that are subject to tax equity financing arrangements are excluded from the Environmental and tax attributes revenues line and are included under Adjusted Revenues line.

(2)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(3)Adjusted Revenues and Adjusted EBITDA are non-IFRS measures. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $110 million and $228 million for the three and six months ended June 30, 2026, respectively (June 30, 2025 — $56 million and $156 million) and to Adjusted EBITDA — earnings before income taxes of $34 million and $80 million for the three and six months ended June 30, 2026, respectively (June 30, 2025 — loss before income taxes $32 million and $21 million).

(4)Earnings before income taxes exclude the contribution from Skookumchuck wind facility.

Adjusted Revenues for the three and six months ended June 30, 2026 decreased compared to the same periods in 2025, primarily due to:

•Lower availability and wind resource in Eastern Canada; and

•Lower spot power prices in the Alberta market; partially offset by

•Higher availability and wind resource in the U.S.

Adjusted EBITDA for the three and six months ended June 30, 2026 was comparable to the same period of prior year.

Earnings before income taxes for the three and six months ended June 30, 2026 increased from loss before income taxes for the same periods in 2025, primarily due to lower unrealized mark-to-market losses in the current period mainly due to the adoption of IFRS 9 hedge accounting. Refer to the "Material Accounting Policies, Accounting Changes and Critical Accounting Estimates" section of this MD&A for details.

Earnings before income taxes for the six months ended June 30, 2026 were further impacted by higher legal settlement recoveries compared to the same period in 2025.


M18			TransAlta Corporation

Gas



	3 months ended June 30					6 months ended June 30
	2026	2025	Change			2026	2025	Change



Contract sales volume (GWh)	2,187	2,197	(10)	—	%	4,581	4,747	(166)	(3)	%
Merchant sales volume (GWh)	543	580	(37)	(6)	%	1,543	1,872	(329)	(18)	%
Purchased power (GWh)(1)	(253)	(291)	38	(13)	%	(501)	(629)	128	(20)	%
Total production (GWh)	2,477	2,486	(9)	—	%	5,623	5,990	(367)	(6)	%

Adjusted Revenues(2)	304	282	22	8	%	646	648	(2)	—	%





Adjusted EBITDA(2)	142	128	14	11	%	235	232	3	1	%


Earnings (loss) before income taxes	94	(23)	117	(509)	%	157	42	115	274	%

Supplementary information:
Carbon compliance recovery (costs)	6	8	(2)	(25)	%	(33)	(41)	8	(20)	%

(1)Power required to fulfil contractual obligations is included in purchased power.

(2)Adjusted Revenues and Adjusted EBITDA are non-IFRS measures. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $293 million and $641 million for the three and six months ended June 30, 2026, respectively (June 30, 2025 — $204 million and $594 million) and to Adjusted EBITDA — earnings before income taxes of $94 million and $157 million for the three and six months ended June 30, 2026, respectively (June 30, 2025 — loss before income taxes of $23 million and earnings before income taxes $42 million).

Three months ended June 30, 2026

Adjusted Revenues and Adjusted EBITDA for the three months ended June 30, 2026 increased compared to the same period in 2025, primarily due to:

•Favourable hedge positions settled, which generated positive contribution over settled spot prices in Alberta; and

•Positive contribution from the acquisition of Far North facilities; partially offset by

•Lower revenue from the Sarnia gas facility due to contract renewal at a lower price and the retirement of the Ada Cogeneration facility; and

•Higher dispatch optimization in the Alberta market.

Earnings before income taxes for the three months ended June 30, 2026 increased from loss before income taxes for the same period in 2025, primarily due to:

•Lower unrealized mark-to-market losses in the current period;

•Lower depreciation driven by a change in the useful life assumptions in 2025 for the Sheerness facilities; and

•Higher Adjusted EBITDA as explained above.

Six months ended June 30, 2026

Adjusted Revenues and Adjusted EBITDA for the six months ended June 30, 2026 were comparable to the same period in 2025, primarily due to:

•Lower revenue from the Sarnia gas facility due to contract renewal at a lower price and the retirement of the Ada Cogeneration facility; partially offset by

•Positive contribution from the acquisition of Far North facilities; and

•Higher realized pricing in Eastern Canada.

Adjusted EBITDA for the six months ended June 30, 2026 was further impacted by lower purchased power costs due to lower market prices.

Earnings before income taxes for the six months ended June 30, 2026 increased compared to 2025, primarily due to:

•Higher unrealized mark-to-market gains due to more favourable hedges;

•Higher Adjusted EBITDA as explained above; and

•Lower depreciation driven by a change in the useful life assumptions in 2025 for the Sheerness facilities.


TransAlta Corporation			M19

Energy Marketing



	3 months ended June 30					6 months ended June 30
	2026	2025	Change			2026	2025	Change
Adjusted Revenues(1)	19	34	(15)	(44)	%	47	62	(15)	(24)	%


Adjusted EBITDA(1)	10	26	(16)	(62)	%	27	47	(20)	(43)	%


Earnings before income taxes	18	30	(12)	(40)	%	46	48	(2)	(4)	%

(1)Adjusted Revenues and Adjusted EBITDA are non-IFRS measures. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $27 million and $66 million for the three and six months ended June 30, 2026, respectively (June 30, 2025 — $38 million and $65 million) and to Adjusted EBITDA — earnings before income taxes of $18 million and $46 million for the three and six months ended June 30, 2026, respectively (June 30, 2025 — $30 million and $48 million).

Adjusted Revenues and Adjusted EBITDA for the three and six months ended June 30, 2026 were lower compared to the same periods in 2025, primarily due to:

•Comparatively subdued market volatility across Western U.S. natural gas and power markets; and

•Lower realized gains in the current period compared to the same periods in the prior year.

Earnings before income taxes for the three and six months ended June 30, 2026 decreased compared to the same periods in 2025, due to:

•Lower Adjusted EBITDA as explained above; partially offset by

•Higher unrealized mark-to-market gains due to more favourable trading positions, the majority of which are expected to settle by year end.

Corporate



	3 months ended June 30					6 months ended June 30
	2026	2025	Change			2026	2025	Change


Adjusted EBITDA(1)	(36)	(39)	3	(8)	%	(73)	(80)	7	(9)	%






Loss before income taxes	(131)	(150)	19	(13)	%	(274)	(301)	27	(9	%)

(1)Adjusted EBITDA are non-IFRS measures. The most directly comparable IFRS measure to Adjusted EBITDA is loss before income taxes of $131 million and $274 for the three and six months ended June 30, 2026, respectively (June 30, 2025 — $150 million and $301 million).

Adjusted EBITDA for the three months ended June 30, 2026 was comparable to the same period in 2025.

Adjusted EBITDA for the six months ended June 30, 2026 increased compared to the same periods in 2025, primarily due to lower OM&A driven by one-time costs incurred during the prior period and current period saving initiatives.

Loss before income taxes for the three and six months ended June 30, 2026 decreased compared to the same period in 2025 due to:

•Higher unrealized foreign exchange gains driven by favourable changes in foreign currency rates;

•Lower interest expense on certain senior notes, following their refinancing at lower interest rates during 2025 and lower accretion primarily due to lower interest rates in the current period; and

•Lower spending following the successful completion of an upgrade to our ERP system during the three months ended March 31, 2026; partially offset by

•Higher termination and restructuring costs.

Loss before income taxes for the six months ended June 30, 2026 was further impacted by higher legal costs arising from cost determinations made after the conclusion of arbitration proceedings in the first quarter of 2026.


M20			TransAlta Corporation

Energy Transition(1)



	3 months ended June 30					6 months ended June 30
	2026	2025	Change			2026	2025	Change







Total production(2) (GWh)	—	242	(242)	(100)	%	—	1,282	(1,282)	(100)	%

Adjusted Revenues(3)	3	88	(85)	(97)	%	5	241	(236)	(98)	%






Adjusted EBITDA(3)	(2)	19	(21)	(111)	%	(1)	56	(57)	(102)	%


(Loss) earnings before income taxes	(8)	(20)	12	(60)	%	(8)	27	(35)	(130)	%
Supplementary information:
Highvale mine reclamation spend(4)	2	3	(1)	(33)	%	5	6	(1)	(17)	%
Centralia mine reclamation spend(4)	4	4	—	—	%	7	8	(1)	(13)	%

(1)The Energy Transition segment is a non-reportable segment as at June 30, 2026. Refer to Note 16 of the condensed consolidated financial statements the six months ended June 30, 2026.

(2)Centralia Unit 2 facility ceased coal-fired operations at the end of 2025 in the normal course. The facility remains available for power generation as mandated by the United States Department of Energy.

(3)Adjusted Revenues and Adjusted EBITDA are non-IFRS measures. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $3 million and $5 for the three and six months ended June 30, 2026, respectively (June 30, 2025 — $73 million and $227 million) and to Adjusted EBITDA — loss before income taxes of $8 million for the three and six months ended June 30, 2026 (June 30, 2025 — loss before income taxes $20 million and earnings before income taxes $27 million).

(4)Highvale and Centralia mine reclamation spending, which represent the costs necessary to bring the sites to their original condition, are supplementary financial measures and are included in the decommissioning and restoration liabilities settled during the period in the Condensed Consolidated Statements of Financial Position under IFRS.

Centralia ceased coal-fired operations at the end of 2025 in the normal course, therefore there is no production in the current period. The facility currently remains available for power generation in accordance with and for the duration of the Order received from the U.S. Department of Energy and the expected cost recoveries as a result of complying with the Order has been recorded in OM&A.

Refer to the "Significant and Subsequent Events" and "Regulatory Updates" sections for details.

Mine reclamation spend for the three and six months ended June 30, 2026 was consistent with the same periods in 2025.

Optimization of the Alberta Portfolio

The Alberta electricity portfolio metrics disclosed below are supplementary financial measures used to provide additional insight into the segment performance in the Alberta market.

Approximately 61 per cent of our generating capacity is located in Alberta, with 77 per cent exposed to the merchant market. Our portfolio of assets consists of hydro, wind, battery storage and natural gas generation facilities.

Our hydro and gas fleets provide ancillary services, with hydro assets also supporting grid reliability, including black start capability and contributing to drought mitigation through regulated river flows. Our Alberta wind and hydro assets generate environmental credits sold to third parties and our Gas segment.

Portfolio performance is supported by fuel and asset diversity, enabling optimization between energy production

and ancillary services. A significant portion of our Alberta capacity is hedged through commercial and industrial customer contracts and financial instruments to enhance cash‑flow stability.

During periods of low market prices, we may elect not to dispatch gas generation and instead monetize contracted or hedged positions. In the six months ended June 30, 2026, this strategy resulted in higher margins for the portfolio through realized hedging gains and lower operating costs.

In anticipation of the risk of lower prices in 2026, the Company deployed a defensive strategy to increase financial hedges for the merchant portfolio at attractive margins. Realized gains and losses on financial hedges are included in Adjusted Revenues in the tables below.


TransAlta Corporation			M21

The following table provides information for the Company's Alberta electricity portfolio:


	2026						2025
3 months ended June 30	Hydro		Wind & Solar		Gas		Total		Hydro		Wind & Solar		Gas		Total
Gross installed capacity (MW)	834		764		3,650		5,248		834		764		3,650		5,248
Total production(1) (GWh)	566		439		1,602		2,607		433		440		1,593		2,466
Contract production (GWh)	—		214		1,175		1,389		—		219		1,148		1,367
Merchant production (GWh)	566		225		427		1,218		433		221		445		1,099

Ancillary services volumes (GWh)	730		12		177		919		786		18		103		907
Hedged volumes (GWh)	433		14		1,995		2,442		327		28		1,513		1,868
Production contracted or hedged (%)	77	%	52	%	198	%	147	%	76	%	56	%	167	%	131	%
Hedged volumes as a percentage of gross installed capacity (%)	24	%	1	%	25	%	21	%	18	%	2	%	19	%	16	%

Adjusted Revenues(2)(3) ($)	97		35		194		326		137		36		170		343
Fuel ($)	—		(1)		(64)		(65)		(2)		(3)		(62)		(67)
Purchased power ($)	(3)		—		(7)		(10)		(4)		—		(14)		(18)
Carbon compliance (costs) recovery(3)($)	—		—		11		11		—		(1)		13		12
Adjusted Gross Margin ($)	94		34		134		262		131		32		107		270

(1)Total production includes contract and merchant production and excludes ancillary services volumes.

(2)Revenues have been adjusted to exclude the impact of unrealized mark-to-market gains or losses. The Energy Transition segment is a non-reportable segment as at June 30, 2026 and is no longer included in the table above. Refer to Note 16 of the condensed consolidated financial statements for the six months ended June 30, 2026.

(3)The intercompany sales of emission credits from the Hydro and Wind and Solar segments to the Gas segment are eliminated on consolidation in the Corporate segment. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.

Three months ended June 30, 2026

Total production for the Alberta portfolio for the three months ended June 30, 2026, was 2,607 GWh, compared to 2,466 GWh for the same period in 2025. An increase of 141 GWh, or 6 per cent, was primarily due to higher production in the Hydro segment due to higher water resource.

Ancillary services volumes for the three months ended June 30, 2026 were comparable to the the same period of 2025.


M22			TransAlta Corporation


	2026						2025
6 months ended June 30	Hydro		Wind & Solar		Gas		Total		Hydro		Wind & Solar		Gas		Total
Gross installed capacity (MW)	834		764		3,650		5,248		834		764		3,650		5,248
Total production(1) (GWh)	874		1,098		3,607		5,579		778		997		3,886		5,661
Contract production (GWh)	—		506		2,493		2,999		—		481		2,518		2,999
Merchant production (GWh)	874		592		1,114		2,580		778		516		1,368		2,662
Ancillary services volumes (GWh)	1,556		26		322		1,904		1,499		37		371		1,907

Hedged volumes (GWh)	675		37		4,083		4,795		602		66		3,579		4,247
Production contracted or hedged (%)	77	%	49	%	182	%	140	%	77	%	55	%	157	%	128	%
Hedged volumes as a percentage of gross installed capacity (%)	19	%	1	%	26	%	21	%	33	%	4	%	45	%	37	%

Adjusted Revenues(2)(3) ($)	146		61		393		600		199		64		396		659
Fuel ($)	(1)		(4)		(149)		(154)		(3)		(7)		(161)		(171)
Purchased power ($)	(5)		(1)		(15)		(21)		(7)		(1)		(25)		(33)
Carbon compliance costs(3) ($)	—		—		(19)		(19)		—		(2)		(23)		(25)
Adjusted Gross Margin(2) ($)	140		56		210		406		189		54		187		430

(1)Total production includes contract and merchant production and excludes ancillary services volumes.

Six months ended June 30, 2026

Total production for the Alberta portfolio for the six months ended June 30, 2026 was 5,579 GWh, compared to 5,661 GWh in 2025. A decrease of 82 GWh, or one per cent, was primarily due to:

•Lower merchant production in the Gas segment due to higher dispatch optimization driven by lower market prices; partially offset by

•Higher production volumes in the Wind and Solar segment due to higher wind resource; and

•Higher production in the Hydro segment due to higher water resource.

Ancillary services volumes for the six months ended June 30, 2026 were comparable to the same period in 2025.


TransAlta Corporation			M23

The following table provides selected information for the Company's Alberta electricity portfolio:



	3 months ended June 30		6 months ended June 30
	2026	2025	2026	2025
Alberta Market
Spot power price average per MWh	29	40	31	40
Natural gas price (AECO) per GJ	1.54	1.64	1.73	1.83
Statutory carbon compliance price per tonne	95	95	95	95
Alberta Portfolio Results
Realized merchant power price per MWh(1)	121	111	105	111
Ancillary services price per MWh(2)	33	39	31	32
Hydro energy spot power price per MWh	36	82	40	77
Hydro ancillary services price per MWh	33	42	30	35
Wind energy spot power price per MWh	14	23	18	21
Gas spot power price per MWh	68	61	56	57
Hedged power price average per MWh(3)	63	70	65	70
Hedged volume (GWh)	2,442	1,868	4,795	4,247
Fuel cost per MWh(4)	41	42	43	44
Carbon compliance (recovery) cost per MWh(5)	(7)	(8)	5	6

(1)Realized merchant power price per MWh for the Alberta electricity portfolio is a supplementary financial measure and represents the average price realized as a result of the Company's merchant power sales and portfolio optimization activities. It is calculated as merchant revenues (excluding assets under long-term contract and ancillary revenues, but including the impact of realized gains and losses from derivatives and trading activities) for the reporting period divided by total merchant GWh produced during the reporting period.

(2)Ancillary services price per MWh for the Alberta electricity portfolio is a supplementary financial measure and represents the average ancillary services price across Hydro, Gas and Wind and Solar segments.

(3)Hedged power price average per MWh is a supplementary financial measure and is calculated as the average sales price for all hedges and direct customer sales during the reporting period.

(4)Fuel cost per MWh is a supplementary financial measure and is calculated as total fuel costs for the facilities in Alberta divided by production from carbon-emitting generation in the Gas segment.

(5)Carbon compliance per MWh is a supplementary financial measure and is calculated as total carbon compliance costs for the Gas segment in Alberta divided by production from carbon-emitting generation in the Gas segment.

The average spot power price per MWh in Alberta for the three and six months ended June 30, 2026, decreased by $11 and $9 per MWh, respectively, compared to the same periods in 2025, primarily due to the impact of milder weather during the current period.

The realized merchant power price per MWh of production for Alberta for the three and six months ended June 30, 2026, was impacted by:

•Lower average spot and lower hedge power prices during the current period; and

•Favourable hedge positions settling in the period and production optimization, which generated positive contributions over settled spot prices in Alberta.

Fuel cost per MWh and Carbon compliance cost per MWh for the three and six months ended June 30, 2026, were comparable to the same periods in 2025.


M24			TransAlta Corporation

Selected Quarterly Information

Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are often incurred in the spring and fall when electricity prices are expected to be lower, and electricity prices generally increase in the peak winter and summer months in our main markets due to increased heating and cooling loads. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting

from spring runoff and rainfall in the Pacific Northwest. Typically, hydroelectric facilities generate most of their electricity and revenues during the spring months when melting snow starts feeding watersheds and rivers. Inversely, wind speeds are historically greater during the cold winter months and lower in the warm summer months.


	Q3 2025	Q4 2025	Q1 2026	Q2 2026
Revenues	615	599	565	487
Gross margin	353	301	361	433
OM&A	179	186	181	175
Depreciation and amortization	135	148	105	105

(Loss) earnings before income taxes	(53)	(42)	23	80


Net (loss) earnings attributable to common shareholders	(62)	(62)	13	35
Net (loss) earnings per share attributable to common shareholders, basic and diluted(1)	(0.20)	(0.21)	0.04	0.12


	Q3 2024	Q4 2024	Q1 2025	Q2 2025
Revenues	638	678	758	433
Gross margin	384	390	432	334
OM&A	143	234	173	173
Depreciation and amortization	133	143	146	150
Earnings (loss) before income taxes	9	(51)	49	(95)
Net (loss) earnings attributable to common shareholders	(36)	(65)	46	(112)
Net (loss) earnings per share attributable to common shareholders, basic and diluted(1)	(0.12)	(0.22)	0.15	(0.38)

				(112)

(1)Basic and diluted earnings (loss) per share attributable to common shareholders is calculated in each period using the basic and diluted weighted average common shares outstanding during the period, respectively. As a result, the sum of the earnings (loss) per share for the four quarters making up the calendar year may sometimes differ from the annual earnings (loss) per share.

Operating results have been impacted by the following events:

•The acquisition of Far North on Feb. 2, 2026;

•The acquisition of Heartland on Dec. 4, 2024; and

•No production at Centralia starting the first quarter of 2026 due to the cessation of coal-fired operations in the normal course.

Refer to the "Description of the Business" section of this MD&A.

In addition to the items described above, revenues have been impacted by:

•Alberta spot and hedged power prices, which were trending downwards;

•Mid-Columbia power prices until the fourth quarter of 2025, which were trending downwards;

•Ontario spot power prices, which were trending upwards during 2025 and the first quarter of 2026;

•The effects of unrealized mark-to-market gains and losses from hedging and derivative positions due to favourable and unfavourable changes in forward rates; and

•The effects of realized mark-to-market gains and losses on settled trades.

Effective Jan. 1, 2026, certain VPPA contracts were designated as cash flow hedges. As a result, the effective portion of unrealized gains and losses due to changes in fair value is recognized in other comprehensive income, while the ineffective portion is recognized in revenue.


TransAlta Corporation			M25

Gross Margin has been impacted by:

•Factors impacting revenues as described above;

•Natural gas prices;

•Purchased power costs;

•Carbon price per tonne, which increased from $80 in 2024 to $95 in 2025 and 2026; and

•Lower carbon compliance recovery in the second quarter of 2026 due to the use of fewer emission credits to settle a portion of our 2025 GHG obligation, compared to the emission credits used to settle the 2024 obligation.

OM&A has been impacted by:

•Higher spending on strategic and growth initiatives;

•Termination, restructuring and facility shutdown costs;

•Legal costs arising from cost determinations made after the conclusion of arbitration proceedings in the first quarter of 2026;

•Expected recoveries for Centralia in the first and second quarters of 2026 as a result of complying with the Order;

•Brazeau penalties assessed by the Alberta Market Surveillance Administrator in the fourth quarter of 2024 for self-reported contraventions pertaining to ancillary services provided during 2021 and 2022;

•Heartland acquisition-related transaction and restructuring costs in the fourth quarter of 2024; and

•Our ERP system upgrade during the fourth quarter of 2024, all four quarters of 2025 and the first quarter of 2026.

Depreciation has been impacted by:

•Lower depreciation in the Gas segment in the first and second quarters of 2026 due to a change in the useful life assumptions in 2025 for the Sheerness facilities;

•Lower depreciation for Centralia Unit 2 facility due to the cessation of coal-fired operations in the normal course in the end of 2025; and

•The revision to the useful lives of certain facilities in the third quarter of 2024.

Earnings (loss) before income taxes have been impacted by:

•The factors explained above.

Net (loss) earnings attributable to common shareholders have been impacted by:

•The factors impacting earnings (loss) before income taxes as explained above.

Financial Condition

Balance Sheet Analysis

The following table highlights significant changes in the Consolidated Statements of Financial Position from Dec. 31, 2025 to June 30, 2026:


As at	June 30, 2026	Dec. 31, 2025	Increase/(decrease)
Total current assets	1,427	1,336	91
Total non-current assets	7,415	7,325	90
Total assets	8,842	8,661	181

Total current liabilities	1,691	1,830	(139)
Total non-current liabilities	5,302	5,366	(64)
Total liabilities	6,993	7,196	(203)

Working Capital

The deficit of current assets relative to current liabilities, including the current portion of long-term debt and lease liabilities, was $264 million as at June 30, 2026 (Dec. 31, 2025 – $494 million).

The working capital deficit was primarily caused by the classification of exchangeable securities totaling $750 million as current liabilities as a result of Brookfield's conversion option that can be exercised at any time after Dec. 31, 2024, although there is no obligation to deliver

cash equivalent resources and Brookfield cannot call for repayment. Refer to Note 26 of the 2025 consolidated financial statements for details.

The deficit as at June 30, 2026, decreased from Dec. 31, 2025 primarily as a result of lower accounts payable and accrued liabilities, higher cash balance due to a public offering of common shares and higher income taxes receivable, partially offset by lower accounts receivable and collateral provided. For the working capital management discussion, refer to the "Financial Capital" section below.


M26			TransAlta Corporation

Non-Current Assets

Non-current assets as at June 30, 2026, were $7,415 million, an increase of $90 million from $7,325 million as at Dec. 31, 2025, primarily due to higher long-term prepaids, included in other assets, related to a turbine reservation payment, higher property, plant and equipment (PP&E) resulting from the acquisition of Far North totaling $102 million, capital additions of $72 million and higher foreign exchange gains on translation of foreign-currency denominated balances to the presentation currency, partially offset by depreciation and amortization of $210 million for the six months ended June 30, 2026.

Non-Current Liabilities

Non-current liabilities as at June 30, 2026, were $5,302 million, a decrease of $64 million from $5,366 million as at Dec. 31, 2025, mainly due to a decrease in credit facilities, long-term debt and lease liabilities driven by no cash drawings outstanding under the syndicated credit facility,

partially offset by an increase in the carrying value of USD denominated debt due to an increase in foreign exchange rate. This was further offset by an increase in risk management liabilities due to unfavourable changes in market pricing and an increase in decommissioning and other provisions primarily due to accretion and Far North acquisition during the six months ended June 30, 2026.

Contractual Obligations

For changes to the Company’s contractual obligations during the six months ended June 30, 2026 refer to Note 14 of the Condensed Consolidated Statements of Financial Position for the six months ended June 30, 2026. The Company’s significant contractual commitments are described in Note 36 Commitments and Contingencies of the consolidated financial statements for the year ended Dec. 31, 2025 and "Financial Condition" section of the Annual MD&A for the year ended Dec. 31, 2025.

Financial Capital

The Company is focused on maintaining a strong balance sheet and financial position to ensure access to sufficient financial capital. The Company expects cash flow from operating activities to be sufficient to meet its obligations, support sustaining capital expenditures and fund dividends over both the short- and long-term. Given its financing track record in recent years, the Company has robust access to capital markets for future funding needs. The Company maintains a strong financial position, with $1.8 billion in liquidity as at June 30, 2026. Credit facilities are the primary source of short-term liquidity after internally generated cash flow.

The Company manages working capital deficits primarily through cash generated from operating activities and the availability of credit facilities. Management regularly monitors liquidity and funding requirements, and evaluates the Company's capital structure in light of prevailing

market conditions. Current leverage levels are considered manageable, they reflect management’s ongoing assessment of the risk profile and cash flow characteristics associated with the Company’s assets.

On July 24, 2026, S&P Global Ratings affirmed the Company’s senior unsecured debt rating and issuer credit rating of BB+ and revised its outlook from stable to negative. On June 18, 2026, Moody's Ratings affirmed the Company's Ba1 rating with stable outlook. The Company’s Morningstar DBRS ratings remain unchanged as disclosed in the 2025 Annual Report. For information on Company's credit ratings, refer to "Financial Condition" section of the 2025 Annual Report. Risks associated with our credit ratings are discussed in the "Risk Management" section of the 2025 Annual Report.


TransAlta Corporation			M27

Capital Structure

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


As at	June 30, 2026		Dec. 31, 2025
	$	% of total	$	% of total

Senior unsecured debt	1,674	29	1,639	29


Credit facilities	—	—	95	2
Non-recourse debt	1,447	25	1,471	26








Recourse debt - OCP LP Bond	153	3	166	3

Tax equity financing	67	1	76	1
Lease liabilities	148	3	146	3
Credit facilities, long-term debt and lease liabilities(1)	3,489	61	3,593	64
Add: Exchangeable debentures	350	6	350	6

Less: Cash and cash equivalents	(302)	(5)	(205)	(3)
Less: TransAlta OCP LP restricted cash(2)	—	—	(17)	—
Less: Fair value of foreign exchange forward contracts on foreign-currency denominated debt	(8)	—	4	—
Total Consolidated Net Debt(3)(4)(5)	3,529	62	3,725	67
Exchangeable preferred securities(5)	400	7	400	7
Total equity	1,849	31	1,465	26





Total capital	5,778	100	5,590	100

(1)Credit facilities, long-term debt and lease liabilities consist of current and non-current portions in the Condensed Consolidated Statements of Financial Position.

(2)Principal portion of the TransAlta OCP LP restricted cash related to the TransAlta OCP LP bonds, as this cash is restricted specifically to repay the bonds.

(3)Total Consolidated Net Debt is a non-IFRS measure, which is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. The most directly comparable IFRS measure is total credit facilities, long-term debt and lease liabilities. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for further discussion.

(4)Tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in these amounts.

(5)Total Consolidated Net Debt excludes the exchangeable preferred shares as they are considered equity with dividend payments for credit purposes.

Credit Facilities

The Company's credit facilities are summarized in Note 10 of the condensed consolidated financial statements.

As at June 30, 2026, the Company had total committed capacity of $2.2 billion, against which $556 million of letters of credit were issued and nil was drawn in cash. Under the $400 million non-committed capacity, the Company issued $217 million of fully backstopped letters of credit, which reduced the available capacity on the committed credit facilities.

In addition to the net $1.4 billion of remaining committed capacity, the Company held $302 million in cash and cash equivalents, resulting in total available liquidity of $1.8 billion as at June 30, 2026.

TransAlta's debt has terms and conditions, including financial covenants, that are considered ordinary and customary. As at June 30, 2026, the Company was in compliance with all of its debt covenants and all undrawn amounts under the credit facilities are fully available.

On July 17, 2026, the Company executed agreements to extend committed credit facilities totalling $2.1 billion with a syndicate of lenders. The revised agreements extend the maturity dates of the syndicated credit facility from June 30, 2029 to June 30, 2030 and the bilateral credit facilities from June 30, 2027 to June 30, 2028.


M28			TransAlta Corporation

Non-Recourse Debt and Other

All non-recourse debt and the OCP LP Bond are subject to customary financing covenants that may restrict the Company’s ability to access funds generated by the facilities’ operations. Funds may be distributed to parent entities upon satisfaction of quarterly distribution tests, including applicable debt service coverage ratio thresholds. These requirements were met in the second quarter of 2026 for all entities.

Certain non-recourse bonds require that reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit. Additionally, cash held by certain subsidiaries is not accessible by other corporate entities as the funds are designated solely for project-level major maintenance costs. As at June 30, 2026, $72 million (Dec. 31, 2025 – $101 million) of cash was subject to such restrictions.

Returns to Providers of Capital

Interest Income and Interest Expense

The components of interest expense are disclosed in Note 6 of the condensed consolidated financial statements. Net Interest Expense in the reconciliation of our Adjusted EBITDA to our FFO and FCF is calculated as follows:


	3 months ended June 30		6 months ended June 30
	2026	2025	2026	2025
Interest expense	84	88	166	181
Less: Interest Income	(7)	(6)	(14)	(11)
Less: non-cash items(1)	(17)	(16)	(31)	(32)






Net Interest Expense(2)	60	66	121	138

(1)Non-cash items consists of accretion of provisions, financing cost amortization, interest paid in kind and other non-cash items.

(2)Net Interest Expense is a non-IFRS measure, is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.

Interest expense for the three and six months ended June 30, 2026 was lower compared to the same periods in 2025, primarily due to lower interest on certain senior notes, following their refinancing at lower interest rates during 2025 and lower accretion primarily due to lower interest rates in the current period.

Interest income for the three and six months ended June 30, 2026 was comparable to the same periods in 2025.

Series B Preferred Shares conversion

On March 31, 2026, holders of Series B preferred shares converted 1,148,549 of the 2,370,087 outstanding Series B shares into Series A shares on a one‑for‑one basis. As a result of the conversion, on June 30, 2026, the Company had 10,778,462 Series A Shares and 1,221,538 Series B Shares issued and outstanding.

Other Series Preferred Shares

Other Series preferred shares outstanding for the six months ended June 30, 2026 remained unchanged.

Share Capital

On June 9, 2026, TransAlta completed a public offering of 18,230,000 common shares at a price of $19.20 per share for total gross proceeds of approximately $350 million. Refer to the "Significant and Subsequent Events" section of this MD&A for details.

For details on common and preferred shares issued and outstanding refer to Notes 11 and 12 of the condensed consolidated financial statements.

As at July 30, 2026, the outstanding number of common shares was 316.3 million. The outstanding number of preferred shares was as follows: Series A 10.8 million, Series B 1.2 million, Series C 10.0 million, Series D 1.0 million, Series E 9.0 million and Series G 6.6 million.


TransAlta Corporation			M29

Adjusted Net Debt to Adjusted EBITDA

The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position.

These metrics and ratios are not defined and have no standardized meaning under IFRS and may not be comparable to those used by other entities or by rating agencies.


(in millions of Canadian dollars except where noted)
As at	June 30, 2026	Dec. 31, 2025
Credit facilities, long-term debt and lease liabilities(1)	3,489	3,593
Exchangeable debentures	350	350
Less: Cash and cash equivalents	(302)	(205)

Add: 50 per cent of issued preferred shares and exchangeable preferred shares(2)	671	671
Other(3)	(8)	(13)
Adjusted Net Debt(4)	4,200	4,396
Adjusted EBITDA(5)	980	1,104
Adjusted Net Debt to Adjusted EBITDA (times)	4.3	4.0

(1)Consists of current and non-current portions of long-term debt, which includes lease liabilities and tax equity financing.

(2)Exchangeable preferred shares are considered equity with dividend payments for credit-rating purposes. For accounting purposes, they are accounted for as debt with interest expense in the condensed consolidated financial statements. For purposes of this ratio, we consider 50 per cent of issued preferred shares, including exchangeable preferred shares, as debt.

(3)Includes principal portion of TransAlta OCP restricted cash of nil as at June 30, 2026 (Dec. 31, 2025 - $17 million) and fair value of hedging instruments on debt (included in risk management assets and/or liabilities on the Condensed Consolidated Statements of Financial Position).

(4)The tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in this amount. Adjusted Net Debt is a non-IFRS measure, is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Presenting this item from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.

(5)Last four quarters.

The Company's capital is managed using a net debt position. We use the Adjusted Net Debt to Adjusted EBITDA ratio as a measurement of financial leverage and an assessment of our ability to service debt. Our long-term target for Adjusted Net Debt to Adjusted EBITDA ratio is 3.0 to 4.0 times.

Our Adjusted Net Debt to Adjusted EBITDA ratio as at June 30, 2026 was higher compared to Dec. 31, 2025 due to lower trailing twelve months Adjusted EBITDA, partially offset by lower net debt as at June 30, 2026, compared to Dec. 31, 2025, primarily due to no cash drawings outstanding under the syndicated credit facility and a higher cash balance due to a public offering of common shares.


M30			TransAlta Corporation

Cash Flows

The following table highlights significant changes in the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2026 and June 30, 2025:



6 months ended June 30	2026	2025	Increase/ (decrease)
Cash and cash equivalents, beginning of period	205	337	(132)
Provided by (used in):
Operating activities	185	164	21
Investing activities	(162)	(201)	39
Financing activities	70	(77)	147
Effect of translation on foreign currency cash	4	(1)	5

Cash and cash equivalents, end of period	302	222	80

Cash Flow from Operating Activities

Cash from operating activities increased in the six months ended June 30, 2026, primarily due to favourable working capital movements driven by lower accounts receivable and collateral provided, partially offset by lower accounts payable and accrued liabilities compared to the same period of prior year. Cash flow from operations before changes in working capital was lower primarily due to the same factors impacting Adjusted EBITDA. Cash taxes decreased during the six months ended June 30, 2026, primarily due to lower tax obligation as at Dec. 31, 2025, resulting from lower earnings before income taxes for the year ended Dec. 31, 2025 compared to 2024.

Cash Flow used in Investing Activities

Cash used in investing activities for the six months ended June 30, 2026, decreased compared to the same period in 2025, primarily due to Nova facilities issued during the same period of 2025 and lower PP&E additions in the current period due to lower major maintenance for our Canadian gas facilities. This was partially offset by the cash paid to acquire the Far North facilities in the current period.

Cash Flow from Financing Activities

Cash from financing activities for the six months ended June 30, 2026, increased compared to cash used in the same period in 2025, primarily due to a public offering of common shares in the current period (refer to the "Significant and Subsequent events" section of this MD&A), partially offset by the repayment of cash drawings under the syndicated credit facility. During the same period in 2025, cash used in the financing activity was higher primarily due to a repayment $400 million variable rate term loan facility, which was offset by the issuance of $450 million senior notes and higher cash drawings under the syndicated credit facility.


TransAlta Corporation			M31

Capital Expenditures

Sustaining capital, growth and development capital expenditures represent supplementary financial measures used to present our spending related to the safe and reliable operation of our existing facilities and the

construction of projects, respectively. Refer to the "Capital Expenditures" section of the 2025 Annual Report for more details.

Sustaining Capital Expenditures

The Company's sustaining capital expenditures by segment are summarized in the table below:


	3 months ended June 30		6 months ended June 30
	2026	2025	2026	2025
Hydro	8	6	9	10
Wind and Solar	4	7	8	11
Gas	23	40	37	51

Corporate	4	4	6	8

Sustaining capital expenditures	39	57	60	80

Total sustaining capital expenditures during the three and six months ended June 30, 2026 were $18 million and $20 million lower, respectively, compared with the same

periods in 2025, primarily due to timing of spend on major maintenance for our Canadian gas facilities.

Growth and Development Capital Expenditures

On December 9, 2025, the Company entered into a tolling agreement with Puget Sound Energy to convert the 700 MW Centralia Unit 2 facility from coal to natural gas. The agreement provides contracted capacity payments through 2044.

The project is expected to require approximately US$600 million of capital. A final investment decision is expected in early 2027, with operations anticipated to begin in late 2028.

The following table provides our growth and development spending by segment:


	3 months ended June 30		6 months ended June 30
	2026	2025	2026	2025
Hydro	1	1	2	1

Gas	1	15	5	26
Energy Transition	6	2	9	2

Growth and development expenditures	8	18	16	29

Growth and development expenditures for the three and six months ended June 30, 2026 were lower compared to the same periods in 2025 primarily due to:

•Lower spend in the Gas segment due to a completion of Mount Keith West network upgrade transmission project. Additionally, spend in the Gas segment was higher in the three and six months ended June 30, 2025 due to capital maintenance at Sarnia, which improved facility performance following the outage in the fourth quarter of 2024; partially offset by

•Higher spending in the Energy Transition segment related to the Centralia conversion from coal to natural gas, which extends the operating life of the existing facility.

Refer to the "Strategic Priorities" section of the 2025 Annual Report for more details.

Projects under Construction

The Mount Keith West network upgrade transmission project was completed during the six months ended June 30, 2026. Accordingly, the Company derecognized $39 million from the assets under construction and recognized a finance lease receivable.


M32			TransAlta Corporation

Other Consolidated Analysis

Related-Party Transactions

There were no material related party transactions during the six months ended June 30, 2026. Refer to Note 35 of the 2025 audited annual consolidated financial statements for further details.

Commitments

During the six months ended June 30, 2026, the Company entered into a $45 million maintenance agreement for one of its facilities, running until 2036, and signed a turbine reservation contract with a remaining expected payment of $28 million due in Oct. 2026. The Company has not incurred any other material contractual commitments in the six months ended June 30, 2026, either directly or through its interests in joint operations and joint ventures. For the current material outstanding commitments, please refer to

Note 14 Commitments and Contingencies in the condensed consolidated financial statements and Note 36 of the 2025 audited annual consolidated financial statements.

Contingencies

For the current material outstanding contingencies, please refer to Note 36 of the 2025 audited annual consolidated financial statements. There were no material changes to the contingencies during the six months ended June 30, 2026.

Off-balance sheet arrangements

The Company has not entered into any new material off-balance sheet arrangements during the six months ended June 30, 2026. Refer to the "Financial Condition" section of the 2025 Annual MD&A.

Financial Instruments

For details on Financial instruments refer to Note 14 of the notes to the audited annual 2025 consolidated financial statements and Note 7 of our unaudited interim condensed consolidated financial statements as at and for the six months ended June 30, 2026.

We may enter into commodity transactions involving non-standard features for which market-observable data is not available. These transactions are defined under IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable from the market and fair value is therefore determined using valuation techniques. Fair values are validated by using reasonably possible alternative assumptions as inputs to valuation techniques

and any material differences are disclosed in the notes to the unaudited interim condensed consolidated financial statements.

At June 30, 2026, Level III instruments had a net liabilities carrying value of $331 million (Dec. 31, 2025 – net liabilities $312 million). The Level III liabilities increased during the six months ended June 30, 2026 due to contract settlements and changes in foreign exchange rates, partially offset by volatility in market prices across multiple markets on existing and new contracts. Our risk management profile and practices have not changed materially from Dec. 31, 2025.

Non-IFRS and Supplementary Financial Measures

We use a number of financial measures to evaluate our performance and the performance of our business segments, including measures and ratios that are presented on a non-IFRS basis, as described below. Unless otherwise indicated, all amounts are in Canadian dollars and have been derived from our condensed consolidated financial statements prepared in accordance with IFRS. We believe that these non-IFRS amounts, measures and ratios, read together with our IFRS amounts, provide readers with a better understanding of how management assesses results.

Non-IFRS amounts, measures and ratios do not have standardized meanings under IFRS. They are unlikely to be comparable to similar measures presented by other

companies and should not be viewed in isolation from, as an alternative to, or more meaningful than our IFRS results.

We calculate adjusted measures by adjusting certain IFRS measures for certain items that we do not believe reflect our ongoing operations in the period. Except as otherwise described, these adjusted measures are calculated on a consistent basis from period to period.

Non-IFRS Financial Measures

This section provides additional information on these non-IFRS measures, including their reconciliation to the most comparable IFRS measure.


TransAlta Corporation			M33

Adjusted EBITDA

Each business segment assumes responsibility for its operating results measured by Adjusted EBITDA. Adjusted EBITDA is an important metric for management that represents our core operational results.

Interest, taxes, depreciation and amortization are not included, as differences in accounting treatment may distort our core business results. In addition, certain reclassifications and adjustments are made to better assess results, excluding those items that may not be reflective of ongoing business performance. This presentation may facilitate the readers' analysis of trends. The most directly comparable IFRS measure is earnings before income taxes.

The following are descriptions of the adjustments made to arrive at the non-IFRS measures:

Adjusted Revenue

Adjusted Revenues are revenues (the most directly comparable IFRS measure) adjusted to exclude:

•The impact of unrealized mark-to-market gains or losses and unrealized foreign exchange gains or losses on commodity transactions.

•Certain assets that we own in Canada and Western Australia are fully contracted and recorded as finance leases under IFRS. We believe that it is more appropriate to reflect the payments we receive under the contracts as a capacity payment in our revenues instead of as finance lease income and a decrease in finance lease receivables.

•Revenues from the Required Divestitures as they do not reflect ongoing business performance.

Adjusted Fuel and Purchased Power

Adjusted Fuel and Purchased Power is fuel and purchased power (the most directly comparable IFRS measure) adjusted to exclude fuel and purchased power from the Required Divestitures as it does not reflect ongoing business performance.

Adjusted OM&A

Adjusted OM&A is OM&A (the most directly comparable IFRS measure) adjusted to exclude:

•Termination and restructuring costs mainly for costs incurred as part of strategic decisions, and that do not represent ongoing business performance and are not reflective of the Company's ability to generate cash flows in the future. Termination and restructuring costs mainly include termination, severance, and related costs.

•Legal costs arising from cost determinations made after the conclusion of arbitration proceedings that are not reflective of ongoing business performance.

•The expenses related to the Centralia community fund (Fund), which was established under the Company'’s obligations in the Energy Transition Bill related to the retirement of coal operations at Centralia, with a total commitment of US$55 million over the 2015–2026 period. With the coal facility reaching end of life on Dec. 31, 2025, and all commercial operations now ceased, expenditures associated with the Fund in 2026 no longer relate to a revenue-generating facility and are not reflective of ongoing business performance.

•ERP integration costs representing planning, design and implementation costs of upgrades to the existing ERP system as they represent project costs that do not occur on a regular basis, and therefore do not reflect ongoing business performance.

•Acquisition-related transaction and restructuring costs, mainly comprising severance, legal and consultant fees as these do not reflect ongoing business performance.

•OM&A from the Required Divestitures as it does not reflect ongoing business performance.

Adjusted Net Other Operating Income

Adjusted Net Other Operating Income is net other operating income (the most directly comparable IFRS measure) adjusted to exclude:

•Insurance recoveries related to the Kent Hills replacement costs of the tower collapse as these relate to investing activities and are not reflective of ongoing business performance; and

•Legal settlement recoveries related to investing activities and not reflective of operating performance.

Additional Adjustments

Adjustments to Earnings (Loss) in Addition to Interest, Taxes, Depreciation and Amortization

•Fair value change in contingent consideration payable is not included as it is not reflective of ongoing business performance.

•Asset impairment charges and reversals are not included as these are accounting adjustments that impact depreciation and amortization and do not reflect ongoing business performance.

•Any gains or losses on asset sales or foreign exchange gains or losses are not included as these are not part of operating income.

Adjustments for Equity-Accounted Investments

During the fourth quarter of 2020, we acquired a 49 per cent interest in the Skookumchuck wind facility, which is treated as an equity investment under IFRS and our proportionate share of the net earnings is reflected as equity income on the statement of earnings under IFRS. As this investment is part of our regular power-generating operations, we have included our


M34			TransAlta Corporation

proportionate share of Adjusted EBITDA for the Skookumchuck wind facility in our total Adjusted EBITDA. In addition, in the Wind and Solar adjusted results, we have included our proportionate share of revenues and expenses to reflect the full operational results of this investment. We have not included Adjusted EBITDA of other equity-accounted investments in our total Adjusted EBITDA as it does not represent our regular power-generating operations.

Adjusted Earnings (Loss) before Income Taxes

Adjusted Earnings (Loss) before Income Taxes represents segmented earnings (loss) adjusted for certain items that we believe do not reflect ongoing business performance and is an important metric for evaluating performance trends in each segment.

For details of the adjustments made to earnings (loss) before income taxes (the most directly comparable IFRS measure) to calculate Adjusted Earnings (Loss) before Income Taxes, refer to the "Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment" section of this MD&A.

Adjusted Net Earnings (Loss) Attributable to Common Shareholders

Adjusted Net Earnings (Loss) Attributable to Common Shareholders represents net earnings (loss) attributable to common shareholders adjusted for specific reclassifications and adjustments and their tax impact, and is an important metric for evaluating performance. For details of the reclassifications and adjustments made to net earnings (loss) attributable to common shareholders (the most directly comparable IFRS measure), please refer to the reconciliation of net earnings attributable to common shareholders to Adjusted Net Earnings Attributable to Common Shareholders of this section of MD&A.

Adjusted Net Earnings (Loss) per Common Share Attributable to Common Shareholders

Adjusted Net Earnings (Loss) per Common Share Attributable to Common Shareholders is calculated as Adjusted Net Earnings (Loss) attributable to Common Shareholders divided by a weighted average number of common shares outstanding during the period. The measure is useful in showing the earnings per common share for our core operational results as it excludes the impact of items that do not reflect an ongoing business performance. Adjusted Net Earnings (Loss) Attributable per Common Share is a non-IFRS ratio and the most directly comparable IFRS measure is net income (loss) per common share attributable to common shareholders. Refer to the reconciliation of net earnings attributable to common shareholders to Adjusted Net Earnings Attributable to Common Shareholders of this section of MD&A.

Funds From Operations (FFO)

FFO is an important metric as it provides a proxy for cash generated from operating activities before changes in working capital and provides the ability to evaluate cash flow trends in comparison with results from prior periods. FFO is a non-IFRS measure. For a description of the adjustments made to cash flow from operating activities (the most directly comparable IFRS measure) to calculate FFO, refer to the "Reconciliation of Cash Flow from Operations to FFO and FCF" section of this MD&A.

Adjustments to Cash Flow from Operations

•FFO related to the Skookumchuck wind facility, which is treated as an equity-accounted investment under IFRS and equity income, net of distributions from joint ventures, is included in cash flow from operations under IFRS. As this investment is part of our regular power-generating operations, we have included our proportionate share of FFO.

•Payments received on finance lease receivables are reclassified to reflect cash from operations.

•Penalties totalling $33 million were issued by the Alberta Market Surveillance Administrator for self-reported contraventions pertaining to ancillary services provided during 2021 and 2022 at our Brazeau hydro facility. The penalties were paid during the first quarter of 2025 and have been excluded from FFO composition.

•Other adjustments primarily include costs associated with acquisition-related transactions, restructuring costs and legal costs related to arbitration proceedings that are not reflective of ongoing business performance, payments/receipts for production tax credits, which are reductions to tax equity debt and distributions from equity-accounted joint ventures.

Free Cash Flow (FCF)

FCF is an important metric as it represents the amount of cash that is available to invest in growth initiatives, make scheduled principal debt repayments, repay maturing debt, pay common share dividends or repurchase common shares, and it provides the ability to compare cash flow trends with results from prior periods. Changes in working capital are excluded so that FFO and FCF are not distorted by changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and timing of receipts and payments. FCF is a non-IFRS measure. For a description of the adjustments made to cash flow from operating activities (the most directly comparable IFRS measure) to calculate FCF, refer to the "Reconciliation of Cash Flow from Operations to FFO and FCF" section of this MD&A.


TransAlta Corporation			M35

Adjusted Net Debt

Adjusted Net Debt is calculated as a sum of current and non-current portions of credit facilities, long-term debt and lease liabilities, exchangeable debentures, 50 per cent of issued preferred shares and exchangeable preferred shares, less cash and cash equivalents, less the principal portion of TransAlta OCP restricted cash and fair value of hedging instruments on debt. Presenting this item from period to period provides management and investors with the ability to evaluate leverage trends more readily in comparison with prior periods’ results. The most directly comparable IFRS measure is total credit facilities, long-term debt and lease liabilities.

Total Consolidated Net Debt

Total consolidated debt is calculated as a sum of current and non-current portions of credit facilities, long-term debt and lease liabilities, exchangeable debentures, less principal portion of TransAlta OCP restricted cash. Total Consolidated Net Debt excludes the exchangeable preferred shares as they are considered equity with dividend payments for credit purposes. Presenting this item from period to period provides management and investors with the ability to evaluate leverage trends more readily in comparison with prior periods’ results. The most directly comparable IFRS measure is total credit facilities, long-term debt and lease liabilities; for reconciliation, refer to "Financial Capital" section of this MD&A.

Net Interest Expense

Net Interest Expense is calculated as total interest expense less total interest income and non-cash items. For detailed calculation refer to the table in the "Reconciliation of Adjusted EBITDA to FFO and FCF" section of this MD&A. Net Interest Expense is a proxy for the actual cash interest paid that approximates the cash outflow in the FFO and FCF calculation. The most directly comparable IFRS measure is total interest expense.

Adjusted Gross Margin

Adjusted Gross Margin is calculated as Adjusted Revenues less Adjusted Fuel and Purchased Power and carbon compliance costs, where adjustments to revenue or fuel and purchased power were applied as stated above. The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment. The most directly comparable IFRS measure is gross margin in the Condensed Consolidated Statement of Earnings (Loss).

Non-IFRS Ratios

FFO per share, FCF per share and Adjusted Net Debt to Adjusted EBITDA are non-IFRS ratios that are presented in this MD&A. Refer to the "Reconciliation of Cash Flow from Operations to FFO and FCF" and "Financial Capital" sections of this MD&A for additional information.

FFO per Share and FCF per Share

FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period.

Supplementary Financial Measures

•Available liquidity

•Cash flow from operating activities per share

•Sustaining capital expenditures

•Growth and development expenditures

•Alberta Hydro Assets ancillary services revenues

•Alberta Hydro Assets revenues

•Other Hydro Assets revenues

•Other Hydro revenues

•Highvale mine reclamation spend

•Centralia mine reclamation spend

•Realized foreign exchange gain (loss)

•Unrealized foreign exchange gain (loss)

•The Alberta electricity portfolio metrics

•Realized merchant power price per MWh

•Ancillary services price per MWh

•Hedged power price average per MWh

•Fuel cost per MWh

•Carbon compliance per MWh


M36			TransAlta Corporation

Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment

The following table reflects Adjusted EBITDA and Adjusted Earnings (Loss) before income taxes by segment and provides reconciliation to earnings (loss) before income taxes for the three months ended June 30, 2026:


	Hydro	Wind & Solar(1)	Gas	Energy Marketing	Corporate	Energy Transition	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	100	115	293	27	(46)	3	492	(5)	—	487
Reclassifications and adjustments:
Unrealized mark-to-market loss (gain)	3	7	—	(8)	—	—	2	—	(2)	—

Decrease in finance lease receivable	—	—	8	—	—	—	8	—	(8)	—
Finance lease income	—	2	4	—	—	—	6	—	(6)	—


Unrealized foreign exchange gain on commodity	—	—	(1)	—	—	—	(1)	—	1	—
Adjusted Revenue	103	124	304	19	(46)	3	507	(5)	(15)	487
Fuel and purchased power	(4)	(4)	(97)	—	(1)	—	(106)	—	—	(106)




Carbon compliance recovery	—	—	6	—	46	—	52	—	—	52
Adjusted Gross Margin	99	120	213	19	(1)	3	453	(5)	(15)	433
OM&A	(11)	(26)	(77)	(9)	(43)	(10)	(176)	1	—	(175)
Reclassifications and adjustments:
Termination and restructuring costs	—	—	—	—	7	—	7	—	(7)	—

Centralia community fund expenses	—	—	—	—	—	4	4	—	(4)	—

ERP integration costs	—	—	—	—	1	—	1	—	(1)	—

Adjusted OM&A	(11)	(26)	(77)	(9)	(35)	(6)	(164)	1	(12)	(175)
Taxes, other than income taxes	(1)	(5)	(5)	—	—	—	(11)	—	—	(11)
Net other operating income	—	1	11	—	—	1	13	—	—	13



Adjusted EBITDA(2)	87	90	142	10	(36)	(2)	291
Depreciation and amortization	(11)	(49)	(41)	—	(5)	(1)	(107)	2	—	(105)
Equity income	—	—	—	—	1	—	1	—	—	1
Interest income	—	—	—	—	6	—	6	1	—	7
Interest expense	—	—	—	—	(85)	—	(85)	1	—	(84)
Realized foreign exchange loss(3)	—	—	—	—	(1)	—	(1)	—	—	(1)
Adjusted Earnings (Loss) before income taxes(2)	76	41	101	10	(120)	(3)	105
Reclassifications and adjustments above	(3)	(9)	(11)	8	(8)	(4)	(27)
Finance lease income	—	2	4	—	—	—	6	—	—	6


Asset impairment charges	—	—	—	—	(10)	(1)	(11)	—	—	(11)

Unrealized foreign exchange gain(3)	—	—	—	—	7	—	7	—	—	7

Earnings (loss) before income taxes	73	34	94	18	(131)	(8)	80	—	—	80

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA, Adjusted Earnings (Loss) before income taxes are non-IFRS measures, are not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Additional IFRS Measures and Non-IFRS Measures" section of this MD&A.

(3)Realized and unrealized foreign exchange (loss) gain are supplementary financial measures. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.


TransAlta Corporation			M37


	Hydro	Wind & Solar(1)	Gas	Energy Marketing	Corporate	Energy Transition	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	129	59	204	38	(67)	73	436	(3)	—	433
Reclassifications and adjustments:
Unrealized mark-to-market loss (gain)	18	68	71	(2)	—	15	170	—	(170)	—

Decrease in finance lease receivable	—	—	7	—	—	—	7	—	(7)	—
Finance lease income	—	2	3	—	—	—	5	—	(5)	—
Revenues from Required Divestitures	—	—	(3)	—	—	—	(3)	—	3	—

Unrealized foreign exchange gain on commodity	—	—	—	(2)	—	—	(2)	—	2	—
Adjusted Revenues	147	129	282	34	(67)	88	613	(3)	(177)	433
Fuel and purchased power	(7)	(9)	(106)	—	—	(51)	(173)	—	—	(173)
Reclassifications and adjustments:
Fuel and purchased power related to Required Divestitures	—	—	1	—	—	—	1	—	(1)	—



Adjusted Fuel and Purchased Power	(7)	(9)	(105)	—	—	(51)	(172)	—	(1)	(173)
Carbon compliance (costs) recovery	—	(1)	8	—	67	—	74	—	—	74
Adjusted Gross Margin	140	119	185	34	—	37	515	(3)	(178)	334
OM&A	(13)	(25)	(65)	(8)	(45)	(18)	(174)	1	—	(173)
Reclassifications and adjustments:
OM&A related to Required Divestitures	—	—	1	—	—	—	1	—	(1)	—
ERP integration costs	—	—	—	—	6	—	6	—	(6)	—
Acquisition-related transaction and restructuring costs	—	—	—	—	1	—	1	—	(1)	—
Adjusted OM&A	(13)	(25)	(64)	(8)	(38)	(18)	(166)	1	(8)	(173)
Taxes, other than income taxes	(1)	(5)	(5)	—	(1)	—	(12)	—	—	(12)
Net other operating income	—	—	12	—	—	—	12	—	—	12




Adjusted EBITDA(2)	126	89	128	26	(39)	19	349
Depreciation and amortization	(8)	(52)	(74)	—	(4)	(13)	(151)	1	—	(150)
Equity income	—	—	—	—	—	—	—	—	1	1
Interest income	—	—	—	—	7	—	7	(1)	—	6
Interest expense	—	—	—	—	(89)	—	(89)	1	—	(88)
Realized foreign exchange gain(3)	—	—	—	—	6	—	6	—	—	6
Adjusted Earnings (Loss) before income taxes(2)	118	37	54	26	(119)	6	122
Reclassifications and adjustments above	(18)	(70)	(80)	4	(7)	(15)	(186)
Finance lease income	—	2	3	—	—	—	5	—	—	5
Skookumchuk earnings reclass to equity income(1)	—	(1)	—	—	1	—	—	—	—	—

Asset impairment charges	—	—	—	—	(2)	(11)	(13)	—	—	(13)
Unrealized foreign exchange loss	—	—	—	—	(23)	—	(23)	—	—	(23)

Earnings (loss) before income taxes	100	(32)	(23)	30	(150)	(20)	(95)	—	—	(95)

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA, Adjusted Earnings (Loss) before income taxes are non-IFRS measures, are not defined, have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.

(3)Realized and unrealized foreign exchange (loss) gain are supplementary financial measures. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.


M38			TransAlta Corporation

The following table reflects Adjusted EBITDA by segment and provides reconciliation to earnings (loss) before income taxes for the six months ended June 30, 2026:


	Hydro	Wind & Solar(1)	Gas	Energy Marketing	Corporate	Energy Transition	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	157	240	641	66	(45)	5	1,064	(12)	—	1,052
Reclassifications and adjustments:
Unrealized mark-to-market loss (gain)	—	13	(18)	(19)	—	—	(24)	—	24	—

Decrease in finance lease receivable	—	1	15	—	—	—	16	—	(16)	—
Finance lease income	—	3	10	—	—	—	13	—	(13)	—


Unrealized foreign exchange gain on commodity	—	—	(2)	—	—	—	(2)	—	2	—
Adjusted Revenue	157	257	646	47	(45)	5	1,067	(12)	(3)	1,052
Fuel and purchased power	(8)	(11)	(251)	—	(1)	—	(271)	—	—	(271)




Carbon compliance (costs) recovery	—	—	(33)	—	46	—	13	—	—	13
Adjusted Gross Margin	149	246	362	47	—	5	809	(12)	(3)	794
OM&A	(25)	(51)	(139)	(20)	(105)	(18)	(358)	2	—	(356)
Reclassifications and adjustments:
Termination and restructuring costs	—	—	—	—	18	—	18	—	(18)	—
Legal costs related to arbitration proceedings	—	—	—	—	9	—	9	—	(9)	—

Centralia community fund expenses	—	—	—	—	—	11	11	—	(11)	—
ERP integration costs	—	—	—	—	4	—	4	—	(4)	—
Acquisition-related transaction and restructuring costs	—	—	—	—	1	—	1	—	(1)	—
Adjusted OM&A	(25)	(51)	(139)	(20)	(73)	(7)	(315)	2	(43)	(356)
Taxes, other than income taxes	(2)	(12)	(10)	—	—	—	(24)	—	—	(24)
Net other operating income	—	14	22	—	—	1	37	—	—	37
Reclassifications and adjustments:

Legal settlement recoveries	—	(12)	—	—	—	—	(12)	—	12	—

Adjusted Net Other Operating Income	—	2	22	—	—	1	25	—	12	37
Adjusted EBITDA(2)	122	185	235	27	(73)	(1)	495
Depreciation and amortization	(20)	(99)	(83)	—	(9)	(1)	(212)	2	—	(210)
Equity income	—	—	—	—	—	—	—	—	4	4
Interest income	—	—	—	—	13	—	13	1	—	14
Interest expense	—	—	—	—	(169)	—	(169)	3	—	(166)
Realized foreign exchange gain(3)	—	—	—	—	8	—	8	—	—	8
Adjusted Earnings (Loss) before income taxes(2)	102	86	152	27	(230)	(2)	135
Reclassifications and adjustments above:	—	(5)	(5)	19	(32)	(11)	(34)
Finance lease income	—	3	10	—	—	—	13	—	—	13
Skookumchuk earnings reclass to Equity income(1)	—	(4)	—	—	4	—	—	—	—	—

Asset impairment (charges) reversals	—	—	—	—	(10)	5	(5)	—	—	(5)
Loss on sale of assets and other	—	—	—	—	(2)	—	(2)	—	—	(2)
Unrealized foreign exchange loss(3)	—	—	—	—	(4)	—	(4)	—	—	(4)
Earnings (loss) before income taxes	102	80	157	46	(274)	(8)	103	—	—	103

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)Adjusted EBITDA, Adjusted Earnings (loss) before income taxes are non-IFRS measures, are not defined, have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.

(3)Realized and unrealized foreign exchange (loss) gain are supplementary financial measures. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.


TransAlta Corporation			M39

The following table reflects Adjusted EBITDA by segment and provides reconciliation to earnings (loss) before income taxes for the six months ended June 30, 2025:


	Hydro	Wind & Solar(1)	Gas	Energy Marketing	Corporate	Energy Transition	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	215	166	594	65	(66)	227	1,201	(10)	—	1,191
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	(3)	104	39	(1)	—	14	153	—	(153)	—

Decrease in finance lease receivable	—	1	14	—	—	—	15	—	(15)	—
Finance lease income	—	3	8	—	—	—	11	—	(11)	—
Revenues from Required Divestitures	—	—	(7)	—	—	—	(7)	—	7	—

Unrealized foreign exchange gain on commodity	—	—	—	(2)	—	—	(2)	—	2	—
Adjusted Revenues	212	274	648	62	(66)	241	1,371	(10)	(170)	1,191
Fuel and purchased power	(11)	(19)	(269)	—	(2)	(149)	(450)	—	—	(450)
Reclassifications and adjustments:
Fuel and purchased power related to Required Divestitures	—	—	3	—	—	—	3	—	(3)	—
Adjusted Fuel and Purchased Power	(11)	(19)	(266)	—	(2)	(149)	(447)	—	(3)	(450)
Carbon compliance (costs) recovery	—	(2)	(41)	—	68	—	25	—	—	25
Adjusted Gross Margin	201	253	341	62	—	92	949	(10)	(173)	766
OM&A	(26)	(54)	(124)	(15)	(94)	(35)	(348)	2	—	(346)
Reclassification and adjustments:
OM&A related to Required Divestitures	—	—	3	—	—	—	3	—	(3)	—
ERP integration costs	—	—	—	—	10	—	10	—	(10)	—
Acquisition-related transaction and restructuring costs	—	—	—	—	5	—	5	—	(5)	—
Adjusted OM&A	(26)	(54)	(121)	(15)	(79)	(35)	(330)	2	(18)	(346)
Taxes, other than income taxes	(2)	(10)	(10)	—	(1)	(1)	(24)	—	—	(24)
Net other operating income	—	4	22	—	—	—	26	—	—	26
Reclassifications and adjustments:
Insurance recovery	—	(2)	—	—	—	—	(2)	—	2	—
Adjusted Net Other Operating Income	—	2	22	—	—	—	24	—	2	26
Adjusted EBITDA(2)	173	191	232	47	(80)	56	619
Depreciation and amortization	(17)	(105)	(138)	(2)	(9)	(28)	(299)	3	—	(296)
Equity income	—	—	—	—	(1)	—	(1)	—	4	3
Interest income	—	—	—	—	12	—	12	(1)	—	11
Interest expense	—	—	—	—	(183)	—	(183)	2	—	(181)
Realized foreign exchange gain(3)	—	—	—	—	2	—	2	—	—	2
Adjusted earnings (loss) before income taxes(2)	156	86	94	45	(259)	28	150
Reclassifications and adjustments above	3	(106)	(60)	3	(15)	(14)	(189)
Finance lease income	—	3	8	—	—	—	11	—	—	11
Skookumchuk earnings reclass to equity income(1)	—	(4)	—	—	4	—	—	—	—	—
Fair value change in contingent consideration payable	—	—	34	—	—	—	34	—	—	34
Asset impairment (charges) reversals	—	—	(34)	—	(7)	13	(28)	—	—	(28)
Loss on sale of assets and other	—	—	—	—	(1)	—	(1)		—	(1)
Unrealized foreign exchange loss(3)	—	—	—	—	(23)	—	(23)	—	—	(23)
Earnings (loss) before income taxes	159	(21)	42	48	(301)	27	(46)	—	—	(46)

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(3)Realized and unrealized foreign exchange (loss) gain are supplementary financial measures. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.


M40			TransAlta Corporation

Reconciliation of Net Earnings Attributable to Common Shareholders to Adjusted Net Earnings Attributable to Common Shareholders

The following table reflects reconciliation of net earnings (loss) attributable to common shareholders to Adjusted Net Earnings Attributable to Common Shareholders for the three and six months ended June 30, 2026 and 2025:



	3 months ended June 30		6 months ended June 30,
(in millions of Canadian dollars except where noted)	2026	2025	2026	2025





Net earnings (loss) attributable to common shareholders	35	(112)	48	(66)
Adjustments and reclassifications (pre-tax):





Adjustments and reclassifications to revenues	15	177	3	170


Adjustments and reclassifications to fuel and purchased power	—	1	—	3


Adjustments and reclassifications to OM&A	12	8	43	18

Adjustments and reclassifications to net other operating income	—	—	(12)	(2)
Fair value gain on contingent consideration	—	—	—	(34)
Finance lease income	(6)	(5)	(13)	(11)
Asset impairment charges	11	13	5	28
Loss on sale of assets and other	—	—	2	1
Unrealized foreign exchange (gain) loss(1)	(7)	23	4	23
Calculated tax expense on adjustments and reclassifications(2)	(6)	(51)	(8)	(46)
Adjusted Net Earnings Attributable to Common Shareholders(3)	54	54	72	84
Weighted average number of common shares outstanding in the period (in millions)	302	297	300	297
Net earnings per common share attributable to common shareholders(4)	0.12	(0.38)	0.11	(0.22)
Adjustments and reclassifications (net of tax)	0.06	0.56	0.08	0.50
Adjusted Net Earnings per Common Share Attributable to Common Shareholders(3)(4)	0.18	0.18	0.19	0.28

(1)Unrealized foreign exchange loss is a supplementary financial measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.

(2)Represents a theoretical tax calculated by applying the Company's consolidated effective tax rate of 23.3 per cent for the three and six months ended June 30, 2026 and June 30, 2025 — 23.3 per cent. The amount does not take into account the impact of different tax jurisdictions the Company's operations are domiciled and does not include the impact of deferred taxes.

(3)Adjusted Net Earnings Attributable to Common Shareholders and Adjusted Net Earnings per Common Share attributable to Common Shareholders are non-IFRS measures, are not defined, have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. The most directly comparable IFRS measures are net earnings attributable to common shareholders and net earnings per share attributable to common shareholders, basic and diluted. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.

(4)Net earnings attributable to common shareholders and Adjusted Net Earnings Attributable to Common Shareholders used in calculating net earnings per common share attributable to common shareholders and Adjusted Net Earnings per Common Share Attributable to Common Shareholders reflect the cumulative preferred share dividend entitlement required for the current period.


TransAlta Corporation			M41

Reconciliation of Cash Flow from Operations to FFO and FCF

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



	3 months ended June 30		6 months ended June 30,
(in millions of Canadian dollars except where noted)	2026	2025	2026	2025
Cash flow from operating activities(1)	62	157	185	164
Change in non-cash operating working capital balances	120	81	101	198
Cash flow from operations before changes in working capital	182	238	286	362
Adjustments
Share of adjusted FFO from joint venture(1)	1	1	4	3
Decrease in finance lease receivable	8	7	16	15
Brazeau penalties payment	—	—	—	33




Other(2)	10	6	32	18
FFO(4)	201	252	338	431
Deduct:
Sustaining capital expenditures(1)	(39)	(57)	(60)	(80)

Dividends paid on preferred shares	(14)	(13)	(27)	(26)
Distributions paid to subsidiaries’ non-controlling interests	(4)	(2)	(5)	(2)

Other(3)	(1)	(3)	(1)	(7)
FCF(4)	143	177	245	316
Weighted average number of common shares outstanding in the period	302	297	300	297
Cash flow from operating activities per share	0.21	0.53	0.62	0.55
FFO per share(4)	0.67	0.85	1.13	1.45
FCF per share(4)	0.47	0.60	0.82	1.06

(1)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture. Supplementary financial measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.

(2)Other consists of production tax credits, which is a reduction to tax equity debt, adjustments to OM&A that are not reflective of ongoing operations and distributions from an equity-accounted joint venture.

(3)Other consists of principal payments on lease liabilities and unsecured loan advances by the Company's subsidiary, Kent Hills Wind LP to its 17 per cent partner.

(4)These items are non-IFRS measures, which are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.


M42			TransAlta Corporation

Reconciliation of Adjusted EBITDA to FFO and FCF

The table below provides a reconciliation of our Adjusted EBITDA to our FFO and FCF:



	3 months ended June 30		6 months ended June 30,
	2026	2025	2026	2025
Adjusted EBITDA(1)(2)	291	349	495	619
Provisions	(6)	(2)	1	6
Net Interest Expense(3)	(60)	(66)	(121)	(138)
Current income tax expense	(26)	(46)	(38)	(59)
Realized foreign exchange (loss) gain(4)	(1)	4	14	2
Decommissioning and restoration costs settled	(8)	(11)	(14)	(20)
Other non-cash items(5)	11	24	1	21
FFO(2)(7)	201	252	338	431
Deduct:
Sustaining capital(2)(4)	(39)	(57)	(60)	(80)

Dividends paid on preferred shares	(14)	(13)	(27)	(26)
Distributions paid to subsidiaries’ non-controlling interests	(4)	(2)	(5)	(2)

Other(6)	(1)	(3)	(1)	(7)
FCF(2)(7)	143	177	245	316

(1)Adjusted EBITDA is defined in the "Non-IFRS and Supplementary Financial Measures" section of this MD&A and reconciled to earnings before income taxes above.

(2)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture.

(3)Net Interest Expense is a non-IFRS measure, not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Net Interest Expense includes interest expense less interest income and excludes non-cash items like financing amortization and accretion. Net Interest Expense reconciliation is available in "Financial Capital" section of this MD&A.

(4)Supplementary financial measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.

(5)Other non-cash items primarily consist of changes in contract assets and liabilities, deferred payments, onerous contracts and legal settlement.

(6)Other consists of principal payments on lease liabilities and unsecured loan advances by the Company's subsidiary, Kent Hills Wind LP to its 17 per cent partner.

(7)These items are non-IFRS measures, are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. FFO and FCF are defined in the "Non-IFRS and Supplementary Financial Measures" section of this MD&A and reconciled to cash flow from operating activities above.


TransAlta Corporation			M43

Material Accounting Policies, Accounting Changes and Critical Accounting Estimates

Material Accounting Policies and Accounting Changes

Our material accounting policies are described in Note 2 of the consolidated financial statements for the year ended Dec. 31, 2025.

In accordance with the amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments, effective Jan. 1, 2026, the Company has prospectively designated certain pre-existing VPPAs within the Wind and Solar segment as held for hedging and has applied hedge accounting. As a result, the effective portion of changes in the fair value of these hedging derivatives, arising on or after Jan. 1, 2026, will be recognised in OCI while any ineffective portion will be recognized in net earnings. The transitional provisions did not permit retrospective designation.

For a description of current and future accounting changes impacting our business, refer to Note 2 of the condensed consolidated financial statements for the six months ended June 30, 2026.

Critical Accounting Judgments and Estimates

The preparation of the condensed consolidated financial statements in accordance with IFRS requires management to apply judgment and to develop estimates and assumptions based on the conditions and information available as of the reporting date. These judgments, estimates, and assumptions influence the reported amounts of assets, liabilities, revenue, and expenses, and actual results may differ from those estimates.

Management reviews these judgments and estimates on a continuous basis. Any revisions are recognized in the period in which they are identified and in any subsequent periods impacted by the change. Refer to Note 2 of the consolidated financial statements for the year ended Dec. 31, 2025 for a description of our significant accounting judgments and key sources of estimation uncertainty.

Governance and Risk Management

Our business activities expose us to a variety of risks and opportunities including, but not limited to, regulatory changes, rapidly changing market dynamics and increased volatility in our key commodity markets. Our goal is to manage these risks and opportunities so that we are in a position to develop our business and achieve our goals while remaining reasonably protected from an unacceptable level of risk or financial exposure. We use a multi-level risk management oversight structure to manage the risks and opportunities arising from our business activities, the markets in which we operate and the political environments and structures with which we interact.

Please refer to the "Risk Management" section of our 2025 Annual MD&A and Note 8 of our unaudited interim condensed consolidated financial statements for the six months ended June 30, 2026 for details on our risks and how we manage them.

There have been no material changes to the Company’s risk profile from those disclosed in the 2025 Annual MD&A.


M44			TransAlta Corporation

Regulatory Updates

Refer to the Significant and Subsequent Events and Risk Management discussions in our 2025 Annual MD&A for further details on the corporation's assessment and management of policy and regulatory risks that supplement the recent developments as discussed below:

Canada

Federal

The Liberal government in Canada was elected on April 28, 2025, as a minority government. Through by-election results and floor crossings, the Liberal party now holds a majority of the seats in the House of Commons.

On Nov. 27, 2025, the Canadian and Alberta governments signed a Memorandum of Understanding (MOU) that among other items, agreed to place the Canadian Electricity Regulations (CER) in abeyance, upon completion of a new carbon pricing agreement administered through Alberta's TIER program.

On May 15, 2026, the governments signed the implementation agreement to operationalize the MOU. That same week, a National Electricity Strategy was released and proposed doubling generation capacity by 2050 and providing some flexibility with the CER to allow greater use of natural gas, expanded carbon offset flexibility and extended lifespans for existing assets.

In June, the federal government released a federal AI Strategy. The MOU, AI and electricity strategies focus on enabling large scale economic growth driven by electrification and digital infrastructure while maintaining system reliability and competitiveness.

Alberta

On Jun. 9, 2026, the Government released a new Data Centre Regulation for new large data centres (≥ 75 MW) seeking system access service to connect to the transmission system, including a "bring your own generation" requirement. The regulation introduces the concept of "tethering" under which a large load data centre system access service request is linked to a new or modified system access service request for a generating unit, energy storage facility or deemed underutilized facility. Tethering requires the large load data centre to identify the power source that will satisfy the resource adequacy or "bring your own generation" requirement for serving the new large load. The regulation also authorizes the AESO to designate an existing generating unit as underutilized and eligible to be tethered to a new large load data centre.

On Jun. 25, 2026, the AESO followed the release of the Data Centre Regulation with a proposed new Phase 2a connection process for large loads. The proposed process sets out requirements for large load data centres requesting grid connection, including tethering to new gas-fired generation and satisfying mandatory and project readiness checklist requirements before a connection request may advance. The process also allows projects that receive a connection approval to request "bridging", which would permit the data centre to draw from the grid for a temporary period of up to three years before the large load's tethered generation comes online. The AESO proposes to cap the total volume of bridging load to 1,600 MW. The Phase 2a process will apply to data centre projects that have in-service dates in 2028 and beyond.

United States

On Jun. 12, 2026, the the U.S. Department of Energy (U.S. DOE) issued its third consecutive 90-day order for the Centralia facility for the period of Jun. 15 to Sep. 12, 2026. At the state level, on March 11, 2026, Washington Governor Ferguson signed HB 2367 into law, which ended exemptions at the Centralia facility related to GHG emission performance standards and limitations after Dec. 31, 2025. The facility had previously been exempt from these standards under the 2011 Memorandum of Agreement with the State.

On Apr. 30, 2026, TransAlta filed a petition for cost recovery for the first 90-day 202(c) order. The Company continues to work with the state and federal governments in relation to the order and filing.

At the federal level, TransAlta continues to monitor policies and agency developments related to our business, including but not limited to: wind, solar and battery tax credits; permit issuance for land-based wind and solar projects; electricity infrastructure permitting reform legislation; large load integration; and regulatory reforms for thermal power generation.

Australia

In 2025, the federal and Western Australian governments both held elections, resulting in majority, renewed terms for both incumbent governments. TransAlta continues to monitor policy developments in Australia.


TransAlta Corporation			M45

Disclosure Controls and Procedures

Management is responsible for establishing and maintaining adequate internal control over financial reporting (ICFR) and disclosure controls and procedures (DC&P). During the three and six months ended June 30, 2026, the majority of our workforce supporting and executing our ICFR and DC&P continue to work on a hybrid basis. The Company has implemented appropriate controls and oversight for both in-office and remote work. There has been minimal impact to the design and performance of our internal controls.

ICFR is a framework designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the condensed consolidated financial statements for external purposes in accordance with IFRS. Management has used the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) to assess the effectiveness of the Company’s ICFR.

DC&P refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under securities legislation is recorded, processed, summarized and reported within the time frame specified in applicable securities legislation. DC&P include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under applicable securities legislation is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure.

Together, the ICFR and DC&P frameworks provide internal control over financial reporting and disclosure. In designing and evaluating our ICFR and DC&P, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and as such may not prevent or detect all misstatements and management is required to apply its judgment in evaluating and implementing possible controls and procedures. Further, the effectiveness of ICFR is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may change.

In Jan. 2026, the Company implemented an upgrade to our Enterprise Resource Planning (ERP) system across the organization resulting in the modification to a number of its internal controls. No other changes to the internal control over financial reporting occurred during the three and six months ended June 30, 2026 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. Management will continue to evaluate the Company's disclosure controls, procedures and internal control over financial reporting to make modifications as deemed necessary.

In accordance with the provisions of National Instrument (NI) 52-109 and consistent with U.S. Securities and Exchange Commission guidance, the scope of the evaluation did not include internal controls over financial reporting of Far North, which the Company acquired on Feb. 2, 2026. Far North was excluded from management's evaluation of the effectiveness of the Company's internal control over financial reporting as at June 30, 2026, due to the proximity of the acquisition to the end of the reporting period. Further details related to the acquisition are disclosed in Note 3 of the condensed consolidated financial statements for the three months ended June 30, 2026. Far North's total and net assets represented approximately one and five per cent of the Company's total and net assets, respectively, as at June 30, 2026 and one and three per cent of the Company's revenues and net earnings, respectively, for the three months ended June 30, 2026.

Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our ICFR and DC&P as of the end of the period covered by this MD&A. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as at June 30, 2026, the end of the period covered by this MD&A, our ICFR and DC&P were effective.


M46			TransAlta Corporation

Condensed Consolidated Statements of Earnings (Loss)

(in millions of Canadian dollars except where noted)


	3 months ended June 30		6 months ended June 30
Unaudited	2026	2025	2026	2025
Revenues (Note 4)	487	433	1,052	1,191
Fuel and purchased power (Note 5)	106	173	271	450
Carbon compliance recovery (Note 5)	(52)	(74)	(13)	(25)
Gross margin	433	334	794	766
Operations, maintenance and administration (Note 5)	175	173	356	346
Depreciation and amortization	105	150	210	296
Asset impairment charges	11	13	5	28
Taxes, other than income taxes	11	12	24	24
Net other operating income	(13)	(12)	(37)	(26)
Operating income (loss)	144	(2)	236	98
Equity income	1	1	4	3

Fair value change in contingent consideration payable	—	—	—	34
Finance lease income	6	5	13	11
Interest income	7	6	14	11
Interest expense (Note 6)	(84)	(88)	(166)	(181)
Foreign exchange gain (loss)	6	(17)	4	(21)
Loss on sale of assets and other	—	—	(2)	(1)
Earnings (loss) before income taxes	80	(95)	103	(46)
Current income tax expense	26	46	38	59
Deferred income tax expense (recovery)	2	(35)	(4)	(41)
Net earnings (loss)	52	(106)	69	(64)
Net earnings (loss) attributable to:
Common shareholders	49	(99)	62	(53)
Non-controlling interests	3	(7)	7	(11)
	52	(106)	69	(64)

Net earnings (loss) attributable to TransAlta shareholders	49	(99)	62	(53)
Preferred share dividends declared (Note 12)	14	13	14	13
Net earnings (loss) attributable to common shareholders	35	(112)	48	(66)
Weighted average number of common shares outstanding in the period (millions)	302	297	300	297
Net earnings (loss) per share attributable to common shareholders, basic and diluted (Note 11)	0.12	(0.38)	0.11	(0.22)

See accompanying notes.


			TransAlta Corporation			F1

Condensed Consolidated Statements of Comprehensive Income (Loss)

(in millions of Canadian dollars)


	3 months ended June 30		6 months ended June 30
Unaudited	2026	2025	2026	2025
Net earnings (loss)	52	(106)	69	(64)
Other comprehensive (loss) income
Net actuarial gains on defined benefit plans, net of tax(1)	5	2	5	2


Total items that will not be reclassified subsequently to net earnings	5	2	5	2
Gains (losses) on translating net assets of foreign operations	8	(17)	20	(18)

(Losses) gains on financial instruments designated as hedges of foreign operations, net of tax(2)	(2)	13	(5)	14

(Losses) gains on derivatives designated as cash flow hedges, net of tax(3)	(16)	(27)	6	(28)
Reclassification of losses (gains) on derivatives designated as cash flow hedges to net earnings, net of tax(4)	4	(19)	(1)	(28)
Total items that will be reclassified subsequently to net earnings	(6)	(50)	20	(60)
Other comprehensive (loss) income	(1)	(48)	25	(58)
Total comprehensive income (loss)	51	(154)	94	(122)

Total comprehensive income (loss) attributable to:
TransAlta shareholders	48	(147)	87	(111)
Non-controlling interests	3	(7)	7	(11)
	51	(154)	94	(122)

(1)Net of income tax expense of $2 million for the three and six months ended June 30, 2026 (June 30, 2025 - $1 million expense for the three and six months).

(2)Net of income tax recovery of $1 million for the three and six months ended June 30, 2026 (June 30, 2025 – $2 million expense for the three and six months).

(3)Net of income tax recovery of $4 million and expense of $3 million for the three and six months ended June 30, 2026 (June 30, 2025 – $3 million and $5 million recovery).

(4)Net of reclassification of income tax recovery of nil and $1 million for the three and six months ended June 30, 2026 (June 30, 2025 – $8 million and $10 million recovery).

See accompanying notes.


F2			TransAlta Corporation

Condensed Consolidated Statements of Financial Position

(in millions of Canadian dollars) (Unaudited)


As at	June 30, 2026	Dec. 31, 2025

Current assets
Cash and cash equivalents	302	205
Restricted cash (Note 10)	60	78
Trade and other receivables	659	699
Prepaid expenses and other	85	51
Risk management assets (Note 7 and 8)	165	162
Inventory	126	111
Assets held for sale	30	30
	1,427	1,336
Non-current assets

Investments	153	144
Long-term portion of finance lease receivables	311	277
Risk management assets (Note 7 and 8)	37	32



Property, plant and equipment (Note 3 and 9)	5,671	5,665
Right-of-use assets	111	111
Intangible assets	230	243
Goodwill (Note 3)	523	516
Deferred income tax assets	51	41
Long-term financial assets (Note 7)	143	140
Other assets	185	156

Total assets	8,842	8,661

Current liabilities


Accounts payable, accrued liabilities and other current liabilities (Note 5)	516	613
Current portion of decommissioning and other provisions	92	84
Risk management liabilities (Note 7 and 8)	126	156


Dividends payable (Note 11 and 12)	21	52
Exchangeable securities	750	750


Current portion of long-term debt and lease liabilities (Note 10)	186	175
	1,691	1,830
Non-current liabilities
Credit facilities, long-term debt and lease liabilities (Note 10)	3,303	3,418


Decommissioning and other provisions (Note 3)	824	807
Deferred income tax liabilities	434	423
Risk management liabilities (Note 7 and 8)	548	519
Contract liabilities	28	26
Defined benefit obligation and other long-term liabilities	165	173
Total liabilities	6,993	7,196

Equity
Common shares (Note 11)	3,513	3,169
Preferred shares (Note 12)	942	942
Contributed surplus	28	42
Deficit	(2,703)	(2,730)
Accumulated other comprehensive income (loss)	1	(24)
Equity attributable to shareholders	1,781	1,399
Non-controlling interests	68	66
Total equity	1,849	1,465
Total liabilities and equity	8,842	8,661

Commitments and contingencies (Note 14)

See accompanying notes.


TransAlta Corporation			F3

Condensed Consolidated Statements of Changes in Equity

(in millions of Canadian dollars)



Unaudited 6 months ended June 30, 2026	Common shares	Preferred shares	Contributed surplus	Deficit	Accumulated other comprehensive income (loss)	Attributable to shareholders	Attributable to non-controlling interests	Total















Balance, Dec. 31, 2025	3,169	942	42	(2,730)	(24)	1,399	66	1,465
Net earnings	—	—	—	62	—	62	7	69
Other comprehensive income:
Net gains on translating net assets of foreign operations, net of hedges and tax	—	—	—	—	15	15	—	15
Net gains on derivatives designated as cash flow hedges, net of tax	—	—	—	—	5	5	—	5
Net actuarial gains on defined benefits plans, net of tax	—	—	—	—	5	5	—	5

Total comprehensive earnings	—	—	—	62	25	87	7	94
Common shares issued (Note 11)	338	—	—	—	—	338	—	338
Common share dividends declared (Note 11)	—	—	—	(21)	—	(21)	—	(21)
Preferred share dividends declared (Note 12)	—	—	—	(14)	—	(14)	—	(14)


Share-based payment plans and stock options exercised	6	—	(14)	—	—	(8)	—	(8)

Distributions declared to non-controlling interests	—	—	—	—	—	—	(5)	(5)
Balance, June 30, 2026	3,513	942	28	(2,703)	1	1,781	68	1,849


6 months ended June 30, 2025	Common shares	Preferred shares	Contributed surplus	Deficit	Accumulated other comprehensive income (loss)	Attributable to shareholders	Attributable to non-controlling interests	Total















Balance, Dec. 31, 2024	3,179	942	42	(2,458)	41	1,746	97	1,843
Net loss	—	—	—	(53)	—	(53)	(11)	(64)
Other comprehensive loss:
Net losses on translating net assets of foreign operations, net of hedges and tax	—	—	—	—	(4)	(4)	—	(4)
Net losses on derivatives designated as cash flow hedges, net of tax	—	—	—	—	(56)	(56)	—	(56)
Net actuarial gains on defined benefits plans, net of tax	—	—	—	—	2	2	—	2

Total comprehensive loss	—	—	—	(53)	(58)	(111)	(11)	(122)

Common share dividends declared	—	—	—	(19)	—	(19)	—	(19)
Preferred share dividends declared	—	—	—	(13)	—	(13)	—	(13)
Shares purchased under normal course issuer bid (NCIB) (Note 11)	(20)	—	—	(4)	—	(24)	—	(24)


Share-based payment plans and stock options exercised	7	—	(7)	—	—	—	—	—
Distributions declared to non-controlling interests	—	—	—	—	—	—	(2)	(2)
Balance, June 30, 2025	3,166	942	35	(2,547)	(17)	1,579	84	1,663

See accompanying notes.


F4			TransAlta Corporation

Condensed Consolidated Statements of Cash Flows

(in millions of Canadian dollars)


	3 months ended June 30		6 months ended June 30
Unaudited	2026	2025	2026	2025
Operating activities
Net earnings (loss)	52	(106)	69	(64)
Depreciation and amortization	105	150	210	296

Accretion of provisions (Note 6)	12	14	25	29

Decommissioning and restoration costs settled	(8)	(11)	(14)	(20)
Deferred income tax expense (recovery)	2	(35)	(4)	(41)
Unrealized loss (gain) from commodity risk management activities	1	169	(24)	157
Unrealized foreign exchange (gain) loss	(7)	20	4	20
Provisions and contract liabilities	(8)	(2)	(1)	(34)
Asset impairment charges	11	13	5	28

Other non-cash items	22	26	16	(9)
Cash flow from operations before changes in working capital	182	238	286	362
Change in non-cash operating working capital balances (Note 13)	(120)	(81)	(101)	(198)
Cash flow from operating activities	62	157	185	164
Investing activities
Additions to property, plant and equipment (Note 9)	(45)	(73)	(72)	(105)

Restricted cash (Note 10)	1	1	21	19

Acquisitions, net of cash acquired (Note 3)	(1)	(1)	(107)	(2)
Net decrease (increase) in long-term financial assets (Note 7)	(5)	—	4	(107)








Decrease in finance lease receivable	8	7	16	15

Long-term prepaids and other	(15)	(6)	(4)	(15)
Change in non-cash investing working capital balances	(12)	15	(20)	(6)
Cash flow used in investing activities	(69)	(57)	(162)	(201)
Financing activities
Net proceeds on issuance of common shares (Note 11)	338	—	338	—
Net (decrease) increase under credit facilities and other borrowings (Note 10)	(207)	4	(98)	(343)
Repayment of long-term debt (Note 10)	(56)	(64)	(91)	(90)
Issuance of long-term debt (Note 10)	—	—	—	450


Dividends paid on common shares (Note 11)	(20)	(18)	(39)	(36)
Dividends paid on preferred shares (Note 12)	(14)	(13)	(27)	(26)


Repurchase of common shares under NCIB (Note 11)	—	(21)	—	(24)


Distributions paid to subsidiaries' non-controlling interests	(4)	(2)	(5)	(2)

Financing fees and other	(3)	—	(6)	(5)
Change in non-cash financing working capital balances	(2)	(1)	(2)	(1)
Cash flow from (used in) financing activities	32	(115)	70	(77)
Cash flow from (used in) operating, investing and financing activities	25	(15)	93	(114)
Effect of translation on foreign currency cash	3	(1)	4	(1)
Increase (decrease) in cash and cash equivalents	28	(16)	97	(115)
Cash and cash equivalents, beginning of period	274	238	205	337

Cash and cash equivalents, end of period	302	222	302	222
Cash taxes paid	27	27	66	94
Cash interest paid	49	74	115	138
Cash interest received	7	6	14	10

See accompanying notes.


TransAlta Corporation			F5

Notes to the Condensed Consolidated Financial Statements

(Tabular amounts in millions of Canadian dollars, except as otherwise noted)

1. Corporate Information

A. Description of the Business

TransAlta Corporation (TransAlta or the Company) was incorporated under the Canada Business Corporations Act in March 1985 and became a public company in December 1992. The Company's head office is located in Calgary, Alberta.

B. Basis of Preparation

These unaudited interim condensed consolidated financial statements have been prepared in compliance with International Financial Reporting Standard (IFRS) and International Accounting Standard (IAS) 34 Interim Financial Reporting using the same accounting policies as those used in the Company's most recent audited annual consolidated financial statements, except as described in Note 2. These unaudited interim condensed consolidated financial statements do not include all of the disclosures included in the Company's audited annual consolidated financial statements. Accordingly, they should be read in conjunction with the Company's most recent audited annual consolidated financial statements which are available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.

The unaudited interim condensed consolidated financial statements include the accounts of the Company and the subsidiaries that it controls.

The unaudited interim condensed consolidated financial statements have been prepared on a historical cost basis except for certain financial instruments, which are stated at fair value.

These unaudited interim condensed consolidated financial statements reflect all adjustments which consist of normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of results. Interim results will fluctuate due to plant maintenance schedules, the seasonal demands for electricity and changes in energy prices. Consequently, interim condensed results are not necessarily indicative of annual results. TransAlta’s results are partly seasonal due to the nature of the electricity market and related fuel costs.

These unaudited interim condensed consolidated financial statements were authorized for issue by the Audit, Finance and Risk Committee on behalf of TransAlta's Board of Directors (the Board) on July 30, 2026.

C. Significant Accounting Judgments and Key Sources of Estimation Uncertainty

The preparation of these unaudited interim condensed consolidated financial statements in accordance with IAS 34 requires management to use judgment and make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosures of contingent assets and liabilities. These estimates are subject to uncertainty. Actual results could differ from these estimates due to factors such as fluctuations in interest rates, foreign exchange rates, inflation and commodity prices, and changes in economic conditions, legislation and regulations.

In the process of applying the Company’s accounting policies, management has to make judgments and estimates about matters that are highly uncertain at the time the estimates are made and that could significantly affect the amounts recognized in the unaudited interim condensed consolidated financial statements. Different estimates with respect to key variables used in the calculations, or changes to estimates, could potentially have a material impact on the Company’s financial position or performance.

Refer to Note 2(Q) of the Company's 2025 audited annual consolidated financial statements for further details on the significant accounting judgments and key sources of estimation uncertainty.

Business Combinations

The fair value of assets acquired and liabilities assumed in a business combination, is estimated based on information available at the date of acquisition. While management uses best estimates and assumptions to accurately value assets acquired and liabilities assumed at the date of acquisition, estimates are inherently uncertain and subject to refinement.


F6			TransAlta Corporation

Accounting for business combinations requires significant judgment, estimates and assumptions at the acquisition date. In developing estimates of fair values at the acquisition date, management uses a variety of factors including market data, market prices, capacity, historical

and future expected cash flows, growth rates and discount rates. Information regarding a business combination that occurred during the six months ended June 30, 2026 has been included in Note 3.

2. Accounting Changes

The accounting policies adopted in the preparation of the unaudited interim condensed consolidated financial statements are consistent with those followed in the preparation of the Company’s annual consolidated financial statements for the year ended Dec. 31, 2025, except for the adoption of new standards effective as of Jan. 1, 2026.

A. Current Accounting Changes

Amendments to IFRS 9 and IFRS 7 — Nature-Dependent Electricity Contracts

On Dec. 18, 2024, the IASB issued amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosure to improve reporting of the financial effects of nature-dependent electricity (e.g., wind and solar) contracts, which are often structured as power purchase agreements. Under these contracts, the amount of electricity generated can vary based on uncontrollable factors such as weather conditions.

The amendments clarify the application of own-use requirements, permit hedge accounting if these contracts are used as hedging instruments and add new disclosure requirements about the effect of these contracts on a company's financial performance and cash flows. Specifically, the amendments will now allow for hedge accounting to be applied in instances where there is variability in the underlying amount of electricity because the source of electricity generation depends on uncontrollable natural conditions.

The amendments are effective for annual reporting periods beginning on or after Jan. 1, 2026.

In accordance with the permitted transitional provisions, effective Jan. 1, 2026, the Company has prospectively designated certain pre-existing Virtual Power Purchase Agreements (VPPAs) within the Wind and Solar segment as held for hedging and has applied hedge accounting. As a result, the effective portion of changes in the fair value of these hedging derivatives, arising on or after Jan. 1, 2026, will be recognised in OCI while any ineffective portion will be recognized in net earnings. The transitional provisions did not permit retrospective designation. Refer to Note 8 Risk Management for details.

Amendments to IFRS 7 and IFRS 9 — Classification and Measurement of Financial Instruments

On May 29, 2024, the IASB issued Amendments to the Classification and Measurement of Financial Instruments effective Jan. 1, 2026 impacting IFRS 7 and 9. The amendments clarified the date of recognition and derecognition of financial assets and liabilities, including an exception for certain financial liabilities settled through an electronic payment system. The amendments also clarified the requirements for assessing contractual cash flow characteristics of financial assets, including those with ESG-linked features. The amendments did not have a material impact on the consolidated financial statements.

B. Future Accounting Changes

The Company closely monitors both new accounting standards and amendments to existing accounting standards issued by the IASB. The following standards have been issued but are not yet in effect.

IFRS 18 — Presentation and Disclosure in Financial Statements

On April 9, 2024, the IASB issued a new standard, IFRS 18 Presentation and Disclosure in Financial Statements, which introduced new requirements for improved comparability in the statement of profit or loss, enhanced transparency of management-defined performance measures and more useful grouping of information in the financial statements. The standard is effective for annual reporting periods beginning on or after Jan. 1, 2027. The Company is currently evaluating the impacts to the financial statements.

C. Comparative Figures

Certain comparative figures have been reclassified to conform to the current period’s presentation. These reclassifications did not impact previously reported net earnings.


TransAlta Corporation			F7

3. Business Acquisitions

TransAlta to Acquire Mountain Peak Power and Canyon Peak Power

On June 3, 2026, the Company announced that it had entered into an agreement (the "Agreement") with an indirect subsidiary of Blackstone, Inc., to acquire Mountain Peak Power and Canyon Peak Power, two fully contracted natural gas-fired peaking facilities totaling 318 MW near Denver, Colorado. The purchase price for the acquisition is US$1 billion, including the assumption of US$750 million of project debt and US$250 million of equity. The equity portion was funded by a common share offering for $350 million completed during the three months ended June 30, 2026 (Note 11). The Acquisition is subject to Canyon Peak Power achieving commercial in-service as well as customary closing conditions, including receipt of regulatory approvals. The Acquisition is expected to close in the fourth quarter of 2026.

Acquisition of Far North

On Feb. 2, 2026, the Company acquired all issued and outstanding common shares of Far North Corporation (Far North) from an affiliate of Hut 8 Corp. (the Far North Acquisition). The Far North Acquisition, which includes Far North and its subsidiaries' entire business operations in

Ontario consisting of four natural gas-fired generation facilities totaling 310 MW, was completed for an aggregate purchase price of $107 million including working capital adjustments of $12 million. The Far North Acquisition was funded through a combination of cash on hand and draws on the Company's credit facilities.

The acquired tangible assets and assumed liabilities are recorded at their estimated fair values at the date of the Acquisition. The total consideration was allocated to the tangible acquired and liabilities assumed, with any excess recorded to goodwill. Goodwill of $6 million recognized on the transaction is a result of net deferred tax liabilities recognized on the transaction, which are recorded at the Company's effective tax rate without discounting. None of the goodwill is expected to be deductible for tax purposes.

The preliminary purchase price allocation reflects management's best estimate of the fair value of the acquired assets and liabilities based on the analysis of information obtained to date. Management is continuing to obtain specific information to support the valuation of the decommissioning provision, property, plant and equipment, and deferred taxes. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition.

The following table summarizes the preliminary fair values that were assigned to the net assets acquired as at the Acquisition Date.


			Feb. 2, 2026
Current Assets and Non-Current Assets
Cash and cash equivalents			1
Trade and other receivables			9

Prepaid expenses and other			6
Inventory			2



Property, plant and equipment			102


Deferred income tax assets			5
Current Liabilities and Non-Current Liabilities
Accounts payable and accrued liabilities			4






Decommissioning provision non-current portion			9

Deferred income tax liabilities			11



Total identifiable net assets at fair value			101
Goodwill arising on acquisition			6
Net assets acquired			107




Total purchase consideration transferred in cash			107

Revenue generated by the Far North Acquisition for the period Feb. 2, 2026 to June 30, 2026 was $12 million. Net loss before taxes for the same period was $2 million.

Had Far North been acquired at the beginning of the year, the assets would have contributed $15 million to revenues and a $3 million loss to net earnings before taxes on a proforma basis.


F8			TransAlta Corporation

4. Revenue

Disaggregation of Revenue

The majority of the Company's revenues are derived from the sale of power, capacity and environmental and tax attributes, and from asset optimization activities, which the

Company disaggregates into the following groups to determine how economic factors affect the recognition of revenue.


	Reportable Segments(1)
3 months ended June 30, 2026	Hydro	Wind and Solar	Gas	Energy Marketing	Corporate(2)	Energy Transition	Total
Revenues from contracts with customers
Power and other	13	58	162	—	—	3	236

Environmental and tax attributes(3)	28	39	2	2	(46)	—	25
Revenue from contracts with customers	41	97	164	2	(46)	3	261

Revenue from derivatives and other trading activities(4)	11	1	68	25	—	—	105
Revenue from merchant sales	45	8	57	—	—	—	110
Other(5)	3	4	4	—	—	—	11
Total revenue	100	110	293	27	(46)	3	487
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	28	57	2	2	(46)	3	46
Over time	13	40	162	—	—	—	215
Total revenue from contracts with customers	41	97	164	2	(46)	3	261


	Reportable Segments(1)
3 months ended June 30, 2025	Hydro	Wind and Solar	Gas	Energy Marketing	Corporate(2)	Energy Transition	Total
Revenues from contracts with customers
Power and other	13	62	198	5	—	2	280
Environmental and tax attributes(3)	60	39	4	—	(67)	—	36
Revenue from contracts with customers	73	101	202	5	(67)	2	316

Revenue from derivatives and other trading activities(4)	(16)	(62)	(67)	33	—	56	(56)
Revenue from merchant sales	69	13	65	—	—	14	161
Other(5)	3	4	4	—	—	1	12
Total revenue	129	56	204	38	(67)	73	433
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	60	23	4	—	(67)	2	22
Over time	13	78	198	5	—	—	294
Total revenue from contracts with customers	73	101	202	5	(67)	2	316

(1)Refer to Note 16 Segment disclosures for details.

(2)The elimination of intercompany sales is reflected in the Corporate segment with $26 million attributed to Hydro (June 30, 2025 - $52 million), $18 million attributed to Wind and Solar (June 30, 2025 - $15 million), and $2 million attributed to Energy Marketing (June 30, 2025 - nil).

(3)The environmental and tax attributes represent environmental attributes and production tax transfer sales not bundled with power and other sales.

(4)Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary significantly from period to period and impact movements in derivative positions. Effective Jan. 1, 2026, the Company applied hedge accounting to certain VPPAs within the Wind and Solar segment prospectively. Accordingly, the effective portion of unrealized gains or losses on the hedging instruments was recognized through OCI. Refer to Note 8 for details.

(5)Other revenue includes production tax credits related to U.S. wind facilities subject to tax equity financing arrangements, total lease income from long-term contracts that meet the criteria of operating leases and other miscellaneous revenues.


TransAlta Corporation			F9


	Reportable Segments(1)
6 months ended June 30, 2026	Hydro	Wind and Solar	Gas	Energy Marketing	Corporate(2)	Energy Transition	Total
Revenues from contracts with customers
Power and other	20	127	321	4	—	5	477

Environmental and tax attributes(3)	28	63	6	2	(46)	—	53
Revenue from contracts with customers	48	190	327	6	(46)	5	530

Revenue from derivatives and other trading activities(4)	21	(4)	157	60	1	—	235
Revenue from merchant sales	82	33	152	—	—	—	267
Other(5)	6	9	5		—	—	20
Total revenue	157	228	641	66	(45)	5	1,052
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	28	63	6	2	(46)	5	58
Over time	20	127	321	4	—	—	472
Total revenue from contracts with customers	48	190	327	6	(46)	5	530


	Reportable Segments(1)
6 months ended June 30, 2025	Hydro	Wind and Solar	Gas	Energy Marketing	Corporate(2)	Energy Transition	Total
Revenues from contracts with customers
Power and other	18	144	360	9	2	5	538
Environmental and tax attributes(3)	70	65	11	—	(68)	—	78
Revenue from contracts with customers	88	209	371	9	(66)	5	616

Revenue from derivatives and other trading activities(4)	6	(95)	36	56	—	119	122
Revenue from merchant sales	116	33	180	—	—	102	431
Other(5)	5	9	7	—	—	1	22
Total revenue	215	156	594	65	(66)	227	1,191
Revenues from contracts with customers
Timing of revenue recognition
At a point in time	70	32	11	—	(68)	5	50
Over time	18	177	360	9	2	—	566
Total revenue from contracts with customers	88	209	371	9	(66)	5	616

(1)Refer to Note 16 Segment disclosures for details.

(2)The elimination of intercompany sales is reflected in the Corporate segment with $26 million attributed to Hydro (June 30, 2025 - $52 million), $18 million attributed to Wind and Solar (June 30, 2025 - $16 million), and $1 million attributed to Energy Marketing (June 30, 2025 - $(2) million).

(3)The environmental and tax attributes represent environmental attributes and production tax transfer sales not bundled with power and other sales.


F10			TransAlta Corporation

5. Expenses by Nature

Fuel, Purchased Power and Operations, Maintenance and Administration (OM&A)

Fuel and purchased power and OM&A expenses classified by nature are as follows:



	3 months ended June 30				6 months ended June 30
	2026		2025		2026		2025
	Fuel and purchased power	OM&A	Fuel and purchased power	OM&A	Fuel and purchased power	OM&A	Fuel and purchased power	OM&A
Gas fuel costs	75	—	88	—	214	—	230	—
Coal fuel costs	—	—	10	—	—	—	54	—
Royalty, land lease, other direct costs	12	—	10	—	18	—	16	—
Purchased power	19	—	65	—	39	—	150	—

Salaries and benefits	—	88	—	77	—	187	—	153
Other operating expenses(1)	—	87	—	96	—	169	—	193
Total	106	175	173	173	271	356	450	346

(1)Other operating expenses include contracted manpower, materials, insurance, office costs and other administrative and overhead costs.

Carbon Compliance

As at June 30, 2026, the Company holds 580,417 emission credits in inventory that were purchased externally with a recorded book value of $26 million (Dec. 31, 2025 — 383,192 emission credits with a recorded book value of $14 million). The Company also has 1,501,737 (Dec. 31, 2025 — 1,860,384) of internally generated eligible emission credits, including credits pending serialization by the issuing authority, from the Company's Wind and Solar and Hydro segments which have no recorded book value.

During the three and six months ended June 30, 2026, the Company utilized 924,899 emission credits (June 30, 2025 - 1,498,447 emission credits) with a carrying value of $9 million (June 30, 2025 - $17 million), to settle a portion of

the 2025 carbon compliance obligation (June 30, 2025 - 2024 carbon compliance obligation). During the three and six months ended June 30, 2026, $78 million (June 30, 2025 - $103 million) was recognized as a reduction in the Company's carbon compliance costs, which also decreased Accounts Payable and accrued liabilities as at June 30, 2026.

Emission credits can be sold externally or can be used to offset future emission obligations from our gas facilities located in Alberta. The compliance price of carbon for the 2025 and 2026 obligation was $95 per tonne.


TransAlta Corporation			F11

6. Interest Expense

The components of interest expense are as follows:



	3 months ended June 30		6 months ended June 30
	2026	2025	2026	2025
Interest on debt	51	51	99	102
Interest on exchangeable debentures	6	6	12	12
Interest on exchangeable preferred shares(1)	7	7	14	14


Interest on lease liabilities	3	4	5	9
Credit facility fees, bank charges and other interest	5	6	11	15


Accretion of provisions	12	14	25	29
Interest expense	84	88	166	181

(1)On July 28, 2026, the Company declared a dividend of $7 million in aggregate on the Series I Preferred Shares at the fixed rate of 1.745% per cent, per share, payable on Aug. 31, 2026.

7. Financial Instruments

A. Financial Assets and Liabilities — Classification and Measurement

Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost.

The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the lowest level input that is significant to the derivation of the fair value. The Level III classification is the lowest level classification in the fair value hierarchy.

There were no changes in the Company's valuation processes, valuation techniques and types of inputs used in the fair value measurements during the period. Refer to Note 14 of the 2025 audited annual consolidated financial statements for further details.

B. Net Risk Management Assets and Liabilities

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


As at June 30, 2026
	Cash flow hedges(1)	Not designated as a hedge	Total
Commodity risk management
Current	15	25	40
Long-term	(452)	(60)	(512)
Net commodity risk management liabilities	(437)	(35)	(472)
Other
Current	—	(1)	(1)
Long-term	—	1	1
Net other risk management liabilities	—	—	—
Total net risk management liabilities	(437)	(35)	(472)

(1)Effective Jan. 1, 2026, the Company has prospectively designated certain pre-existing VPPAs within the Wind and Solar segment as held for hedging and has applied hedge accounting. Refer to Note 15, section A of the annual consolidated financial statements for the year ended Dec. 31, 2025 for additional disclosure related to the designation of hedges.


F12			TransAlta Corporation


As at Dec. 31, 2025
	Cash flow hedges	Not designated as a hedge	Total
Commodity risk management
Current	—	4	4
Long-term	—	(494)	(494)
Net commodity risk management liabilities	—	(490)	(490)
Other
Current	—	2	2
Long-term	—	7	7
Net other risk management assets	—	9	9
Total net risk management liabilities	—	(481)	(481)

I. Commodity Risk Management Assets and Liabilities

Commodity risk management assets and liabilities classified by fair value levels as at June 30, 2026, are as follows: Level I – $7 million net liability (Dec. 31, 2025 – $10 million net liability), Level II – $9 million net asset (Dec. 31, 2025 – $33 million net liability) and Level III – $474 million net liability (Dec. 31, 2025 – $447 million net liability).

Significant changes in commodity net risk management assets and liabilities during the six months ended June 30, 2026, are primarily attributable to volatility in market prices across multiple markets on existing contracts and contract settlements.

The following table summarizes the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification during the six months ended June 30, 2026 and 2025, respectively:


	6 months ended June 30, 2026			6 months ended June 30, 2025
	Hedge	Non-hedge	Total	Hedge	Non-hedge	Total
Opening balance	—	(447)	(447)	—	(153)	(153)
Changes attributable to:
Change in hedge designation due to IFRS 9 amendment	(442)	442	—	—	—	—
Market price changes on existing contracts	27	(15)	12	—	(118)	(118)
Market price changes on new contracts	—	9	9	—	(4)	(4)
Contracts settled	(10)	(27)	(37)	—	(37)	(37)
Change in foreign exchange rates	(12)	1	(11)	—	6	6

Net risk management liabilities at end of period	(437)	(37)	(474)	—	(306)	(306)
Additional Level III information:
Gains recognized in other comprehensive earnings	7	—	7	—	—	—
Total gains (losses) included in earnings before income taxes	22	(5)	17	—	(116)	(116)
Unrealized gains (losses) included in earnings before income taxes relating to net assets (liabilities) held at period end	11	(32)	(21)	—	(153)	(153)


TransAlta Corporation			F13

As at June 30, 2026, the total Level III risk management asset balance was $50 million (Dec. 31, 2025 – $65 million) and the Level III risk management liability balance was $524 million (Dec. 31, 2025 – $512 million). The net risk management liabilities increased mainly due to volatility in market prices across multiple markets on existing contracts and contract settlements.

Included in the Level III classification are several long-term wind energy sales agreements, including contracts for differences and VPPAs, that are recognized as derivatives for accounting purposes. Effective Jan. 1, 2026, the Company has prospectively designated certain pre-existing VPPAs within the Wind and Solar segment as held for hedging and has applied hedge accounting. The effective portion of unrealized gains and losses due to changes in fair

value is recognized in other comprehensive income, while the ineffective portion is recognized in revenue. Realized gains and losses are reclassified to revenue when the hedged transactions impact earnings.

The sensitivity tables below reflect the potential impacts of unobservable inputs on the fair value of the long-term wind energy sales agreements for both derivatives designated as hedges and derivatives without hedge designation. These agreements are backed by physical assets to effectively reduce our market exposure.

For a detailed description of the long-term wind energy sales agreements, please refer to Note 14 of the 2025 audited annual consolidated financial statements.

As at

June 30, 2026

Description

Valuation technique

Unobservable input

Reasonably possible change

Potential change in fair value(1)

Long-term wind energy sale — Eastern U.S.

Long-term price forecast

Illiquid future power prices (per MWh)

Price decrease of US$6 or increase of US$6

Illiquid future REC(2) prices (per unit)

Price decrease of US$4

or increase of US$17

+27

-44

Wind discounts

—% decrease or 5% increase

Long-term wind energy sale — Canada

Long-term price forecast

Illiquid future power prices (per MWh)

Price decrease of $5

or increase of $10

+21

-24

Wind discounts

5% decrease or 5% increase

Long-term wind energy sale — Central U.S.

Long-term price forecast

Illiquid future power prices (per MWh)

Price decrease of US$5

or increase of US$3

+48

-84

Wind discounts

2% decrease or 7% increase

(1)Potential change in fair value represents the total increase or decrease in recognized fair value that could arise from the use of the reasonably possible changes of all unobservable inputs.

(2)Renewable energy credits

As at

Dec. 31, 2025

Description

Valuation
technique

Unobservable input

Reasonably possible change

Potential change in fair value(1)

Long-term wind energy sale — Eastern U.S.

Long-term price forecast

Illiquid future power prices (per MWh)

Price decrease

or increase of US$6

Illiquid future REC(2) prices (per unit)

Price decrease of US$4

or increase of US$17

+26

-43

Wind discounts

—% decrease or 5% increase

Long-term wind energy sale — Canada

Long-term price forecast

Illiquid future power prices (per MWh)

Price decrease of $21

or increase of $10

+55

-22

Wind discounts

5% decrease or increase

Long-term wind energy sale — Central U.S.

Long-term price forecast

Illiquid future power prices (per MWh)

Price decrease of US$7

or increase of US$3

+47

-52

Wind discounts

2% decrease or 6% increase

(1)Potential change in fair value represents the total increase or decrease in recognized fair value that would arise from the use of the reasonably possible changes of all unobservable inputs.

(2)Renewable energy credits


F14			TransAlta Corporation

II. Other Risk Management Assets and Liabilities

Other risk management assets and liabilities primarily include risk management assets and liabilities that are used to manage exposures on non-energy marketing transactions such as interest rates, the net investment in foreign operations and other foreign currency risks. Hedge accounting is not always applied.

Other risk management liabilities with a net fair value of nil as at June 30, 2026 (Dec. 31, 2025 – $9 million net assets) are classified as Level II fair value measurements.

C. Other Financial Assets and Liabilities

The fair value of financial assets and liabilities measured at other than fair value is as follows:


	Fair value(2)				Total carrying value(2)
	Level I	Level II	Level III	Total
Long-term debt — June 30, 2026	—	3,119	—	3,119	3,341
Exchangeable securities — June 30, 2026	—	751	—	751	750
Long-term financial asset — June 30, 2026	—	—	143	143	143
Loan receivable — June 30, 2026(1)	—	30	—	30	30
Long-term debt — Dec. 31, 2025	—	3,255	—	3,255	3,447
Exchangeable securities — Dec. 31, 2025	—	752	—	752	750
Long-term financial asset — Dec. 31, 2025	—	—	140	140	140
Loan receivable — Dec. 31, 2025(1)	—	31	—	31	31

(1)Included within Other assets.

(2)Includes current and non-current portions.

The fair values of the Company’s debentures, senior notes and exchangeable securities are determined using prices observed in secondary markets. Non-recourse and other long-term debt fair values are determined by calculating an implied price based on a current assessment of the yield to maturity.

The carrying amount of other short-term financial assets and liabilities (cash and cash equivalents, restricted cash, trade accounts receivable, collateral provided, bank overdraft, accounts payable and accrued liabilities, collateral held and dividends payable) approximates fair value due to the liquid nature of the asset or liability. The fair values of the finance lease receivables approximate the carrying amounts as the amounts receivable represent cash flows from repayments of principal and interest.

Long-term Financial Asset

As at June 30, 2026 the carrying amount of Nova facilities totalled $143 million, which approximates fair value. Nova facilities are classified as Level III within the fair value hierarchy as it is determined using a binomial model with multiple inputs such as volatility and equity value for which observable market data is not available. A reasonably possible change in inputs would not result in a material impact in the fair value of the Nova facilities.

Refer to Note 14, Section IV of the 2025 consolidated financial statements for the year ended Dec. 31, 2025 for details.

8. Risk Management

A. Risk Management Strategy

The Company is exposed to market risk from changes in commodity prices, foreign exchange rates, interest rates, credit risk and liquidity risk. These risks affect the Company’s earnings and the value of associated financial instruments that the Company holds. In certain cases, the Company seeks to minimize the effects of these risks by using derivatives to hedge its risk exposures.

The Company’s risk management strategy, policies and controls are designed to ensure that the risks it assumes comply with the Company’s internal objectives and risk tolerance. Refer to Note 15 of the 2025 audited annual consolidated financial statements for further details of the Company's risk management activities.


TransAlta Corporation			F15

B. Nature and Extent of Risks Arising from Financial Instruments

I. Market Risk

i. Commodity Price Risk Management – Proprietary Trading

The Company’s Energy Marketing segment conducts proprietary trading activities and uses a variety of instruments to manage risk, earn trading revenue and gain market information.

A value at risk (VaR) measure gives, for a specific confidence level, an estimated pre-tax loss that could be incurred over a specified period of time. VaR is used to determine the potential change in value of the Company’s proprietary trading portfolio, over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations.

Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes occur. VaR at June 30, 2026, associated with the Company’s proprietary trading activities was $1 million (Dec. 31, 2025 – $1 million).

ii. Commodity Price Risk Management – Generation

The generation segments use various commodity contracts to manage the commodity price risk associated with electricity generation, fuel purchases, emissions and byproducts, as considered appropriate.

For positions and economic hedges that do not meet hedge accounting requirements these transactions are marked to the market value with changes in market prices associated with these transactions affecting net earnings in the period in which the price change occurs. VaR at June 30, 2026, associated with these transactions was $5 million (Dec. 31, 2025 – $9 million).

For an estimate of the uncertainty related to long-term power sale and long-term wind energy sales contracts, refer to the Level III measurements table and the related unobservable inputs and sensitivities in Note 7(B)(I).

iii. Commodity Price Risk Management – Hedges

Effective Jan. 1, 2026, the Company has prospectively designated certain pre-existing VPPAs within the Wind and Solar segment as held for hedging and has applied hedge accounting. Any ineffectiveness, such as locational price basis differences, is recognized in net earnings. Refer to Note 2 for details.

II. Credit Risk

The Company uses external credit ratings, as well as internal ratings in circumstances where external ratings are not available, to establish credit limits for customers and counterparties.

The following table outlines the Company’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at June 30, 2026:


	Investment grade (per cent)	Non-investment grade (per cent)	Total (per cent)	Total amount
Trade and other receivables(1)	82	18	100	659
Long-term finance lease receivable	100	—	100	311
Risk management assets(1)	62	38	100	202
Long-term financial assets(2)	—	100	100	143
Loans receivable(3)	—	100	100	30
Total				1,345

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

(2)Included within long-term financial assets with counterparties that have no external credit rating. Refer to Note 7 for further details.

(3)Includes $30 million loans receivable included within other assets with counterparties that have no external credit rating.

The Company did not have material expected credit losses as at June 30, 2026. The Company’s maximum exposure to credit risk at June 30, 2026, without taking into account collateral held or right of set-off, is represented by the current carrying amounts of receivables and risk management assets as per the Condensed Consolidated Statements of Financial Position. Letters of credit, cash and first priority liens on assets are the primary types of collateral held as security related to these amounts. The maximum credit exposure to any one customer for commodity trading operations and hedging, including the

fair value of open trading, net of any collateral held, at June 30, 2026, was $31 million (Dec. 31, 2025 – $51 million). The Company has counterparty credit insurance programs that mitigate our exposure to credit risk.


F16			TransAlta Corporation

III. Liquidity Risk

The Company has sufficient existing liquidity available to meet its upcoming debt maturities. Our highly diversified asset portfolio, by both fuel type and operating region, and our long-term contracted asset base provide stability in our cash flows.

Liquidity risk relates to the Company’s ability to access capital to be used for capital projects, debt refinancing, proprietary trading activities, commodity hedging and general corporate purposes.

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


	2026	2027	2028	2029	2030	2031 and thereafter	Total

Accounts payable, accrued liabilities and other current liabilities	516	—	—	—	—	—	516
Long-term debt(1)	84	333	166	245	283	2,269	3,380









Exchangeable securities(2)	—	—	—	—	—	750	750
Commodity risk management (assets) liabilities(3)	(37)	2	20	28	27	432	472
Other risk management (assets) liabilities	11	(9)	—	3	2	(7)	—
Lease liabilities	3	6	6	6	5	122	148
Interest on long-term debt and lease liabilities(4)	99	184	166	158	143	732	1,482
Interest on exchangeable securities(2)(4)	26	53	53	53	53	457	695
Dividends payable	21	—	—	—	—	—	21
Total	723	569	411	493	513	4,755	7,464

(1)Excludes impact of hedge accounting and derivatives.

(2)The exchangeable debentures are due May 1, 2039 and the exchangeable preferred shares are perpetual. However, a cash payment could occur after Dec. 31, 2028, at the Company's option, if the exchangeable securities are not exchanged by Brookfield Renewable Partners or its affiliates (collectively Brookfield). At Brookfield's option, the exchangeable securities are currently exchangeable into an equity ownership interest in TransAlta’s Alberta Hydro Assets after Dec. 31, 2024.

(3)Negative amount represents a receivable position or cash inflow.

(4)Not recognized as a financial liability on the Condensed Consolidated Statements of Financial Position and excludes the impact of interest rate swaps.

C. Collateral

I. Financial Assets Provided as Collateral

At June 30, 2026, the Company provided $70 million (Dec. 31, 2025 – $92 million) in cash and cash equivalents as collateral to regulated clearing agents as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents. Collateral provided is included within trade and other receivables in the Condensed Consolidated Statements of Financial Position. At June 30, 2026, the Company provided $21 million (Dec. 31, 2025 – $20 million) in surety bonds as security for commodity trading activities.

II. Financial Assets Held as Collateral

At June 30, 2026, the Company held $23 million (Dec. 31, 2025 – $3 million) in cash collateral associated with counterparty obligations. Under the terms of the contracts, the Company may be obligated to pay interest on the outstanding balances and to return the principal when the counterparties have met their contractual obligations or when the amount of the obligation declines as a result of changes in market value.

Interest payable to the counterparties on the collateral received is calculated in accordance with each contract. Collateral held is related to physical and financial derivative transactions in a net asset position and is included in accounts payable and accrued liabilities in the Condensed Consolidated Statements of Financial Position.

III. Contingent Features in Derivative Instruments

Collateral is posted in the normal course of business based on the Company’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs.

At June 30, 2026, the Company had posted collateral of $254 million (Dec. 31, 2025 – $338 million) in the form of letters of credit on physical and financial derivative transactions in a net liability position. Certain derivative agreements contain credit-risk-contingent features, which if triggered could result in the Company having to post an additional $85 million (Dec. 31, 2025 – $92 million) of collateral to its counterparties.


TransAlta Corporation			F17

9. Property, Plant and Equipment

During the three and six months ended June 30, 2026, the Company had additions of $45 million and $72 million primarily related to assets under construction in the Gas segment. Additions during the six months ended June 30, 2026 also included $102 million from the acquisition of Far North.

During the six months ended June 30, 2026, the Mount Keith West Network Upgrade project was completed. As a result, the Company derecognized assets under construction and recognized a finance lease receivable of $39 million.

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

A. Amounts Outstanding


As at	June 30, 2026	Dec. 31, 2025


Senior unsecured debt	1,674		1,639


Credit facilities	—		95
Non-recourse debt	1,447		1,471








Recourse debt - OCP LP Bond	153		166

Tax equity financing	67		76
Lease liabilities	148		146
Total Credit facilities, long-term debt and lease liabilities	3,489		3,593

Current portion	186		175
Non-current portion	3,303		3,418
Total Credit facilities, long-term debt and lease liabilities	3,489		3,593

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


As at June 30, 2026		Utilized
Credit facilities	Facility size	Outstanding letters of credit(2)	Cash drawings	Available capacity	Maturity date
Committed
Syndicated credit facility(1)	1,900	373	—	1,527	Q2 2029

Bilateral credit facilities(1)	240	155	—	85	Q2 2027


Heartland EDC letter of credit facility	30	8	—	22	Q4 2026
Heartland DSR letter of credit facility	27	20	—	7	Q4 2027

Heartland revolving facility	25	—	—	25	Q4 2027

Total committed	2,222	556	—	1,666
Non-committed

Demand facility	400	217	—	183	N/A
Total Non-committed	400	217	—	183

(1)The Company extended the maturity dates of syndicated and bilateral credit facilities on July 17, 2026. Refer to section "E. Credit Facility Extension" below.

(2)TransAlta has obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase obligations. Letters of credit drawn against the non-committed facilities reduce the available capacity under the committed syndicated credit facilities.


F18			TransAlta Corporation

The credit facilities are the primary source of short-term liquidity after the cash flow generated from the Company's business.

B. Restrictions Related to Non-Recourse and Other Debt

All non-recourse debt and the OCP LP Bond, with a total carrying value of $1.6 billion as at June 30, 2026 (Dec. 31, 2025 – $1.6 billion), are subject to customary financing conditions and covenants that may restrict the Company’s ability to access funds generated by the facilities’ operations. At June 30, 2026, $72 million (Dec. 31, 2025 – $101 million) of cash was subject to these financial restrictions.

Upon meeting certain distribution tests, typically performed once per quarter, the funds can be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the second quarter of 2026.

At June 30, 2026, $10 million (AU$10 million) of funds held by TEC Hedland Pty Ltd. cannot be accessed by other corporate entities as the funds must be solely used by the project entities and to pay major maintenance costs. Additionally, certain non-recourse bonds require that certain reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit.

C. Restricted Cash

As at June 30, 2026, the Company had nil (Dec. 31, 2025 – $17 million) of restricted cash related to the TransAlta OCP bonds, which is required to be held in a debt service reserve account in the third and fourth quarters of the year to fund scheduled future debt repayments.

The Company also had $4 million (Dec. 31, 2025 – $4 million) of restricted cash related to holdbacks associated with the sale of the Poplar Hill and Rainbow Lake facilities, which the Company divested in accordance with a consent agreement entered into with the Commissioner of Competition for Canada (Required Divestitures) and $56 million (Dec. 31, 2025 – $57 million) of restricted cash related to the TEC Hedland Pty Ltd. bond. These cash reserves are required to be held under commercial arrangements and for debt service, which may be replaced by letters of credit in the future.

D. Currency Impacts

The strengthening of the U.S. dollar has increased the U.S. dollar-denominated long-term debt balances, mainly the senior notes and tax equity financings, by $38 million during the six months ended June 30, 2026 (June 30, 2025 – decreased $54 million due to the weakening of the U.S. dollar). Almost all of the U.S.-dollar-denominated debt is hedged either through financial contracts or a hedge of net investments in U.S. operations.

Additionally, the strengthening of the Australian dollar has increased the Australian-dollar-denominated non-recourse senior secured notes balance by approximately $44 million during the six months ended June 30, 2026 (June 30, 2025 – decreased by $2 million due to weakening of the Australia dollar). As this debt is issued by an Australian subsidiary, the foreign currency translation impacts are recognized within other comprehensive income (loss).

E. Credit Facility Extension


TransAlta Corporation			F19

11. Common Shares

A. Issued and Outstanding

TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.



6 months ended June 30,	2026		2025
	Common shares (millions)	Amount	Common shares (millions)	Amount
Issued and outstanding, beginning of period	296.7	3,169	297.5	3,179

Issued under public offering(1)	18.2	338	—	—
Purchased and cancelled under the NCIB(2)	—	—	(1.9)	(20)
Share-based payment plans	0.9	4	0.8	7
Stock options exercised	0.2	2	—	—




Issued and outstanding, end of period	316.0	3,513	296.4	3,166

(1)Net of after-tax issuance costs of $12 million (issuance costs of $16 million less tax-effect of $4 million).

(2)Shares purchased by the Company under the NCIB are recognized as a reduction to share capital equal to the average carrying value of the common shares. Any difference between the aggregate purchase price and the average carrying value of the common shares is recorded in retained earnings (deficit).

B. Public Offering

On June 9, 2026, TransAlta completed a public offering of 18,230,000 common shares at a price of $19.20 per share for total gross proceeds of approximately $350 million.

C. Dividends

On July 28, 2026, the Company declared a quarterly dividend of $0.070 per common share, payable on Oct. 1, 2026. There have been no material transactions involving common shares between the reporting date and the date of

completion of these condensed consolidated financial statements.

D. Earnings Per Share

Net earnings (loss) attributable to common shareholders used in calculating basic and diluted net earnings (loss) per share reflects net earnings (loss) attributable to TransAlta shareholders, less preferred-share dividends declared and any cumulative preferred-share dividend entitlements for the period.

12. Preferred Shares

A. Issued and Outstanding

All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares.

Series B Cumulative Redeemable Floating Rate First Series B Preferred Shares conversion

On March 31, 2026, holders of Series B preferred shares converted 1,148,549 of the 2,370,087 outstanding Series B shares into Series A shares on a one‑for‑one basis.

As a result, on June 30, 2026, the Company had 10,778,462 Series A preferred shares issued and outstanding and 1,221,538 Series B preferred shares issued and outstanding.

The number of Series C, D, E and G preferred shares issued and outstanding remains unchanged since Dec. 31, 2025.

B. Dividends

On July 28, 2026, the Company declared quarterly preferred share dividends, payable on Sept. 30, 2026, as follows: $0.29888 per Series A share, $0.2743 per Series B share, $0.36588 per Series C share, $0.34172 per Series D share, $0.43088 per Series E share and $0.42331 per Series G share.


F20			TransAlta Corporation

13. Cash Flow Information

Change in Non-Cash Operating Working Capital


	3 months ended June 30		6 months ended June 30
	2026	2025	2026	2025
Source (use):
Accounts receivable	(1)	87	97	16
Prepaid expenses	(11)	2	(25)	(17)
Income taxes receivable	(1)	(2)	(22)	(38)
Inventory	(8)	(5)	(12)	(4)
Accounts payable, accrued liabilities and provisions	(101)	(183)	(133)	(158)
Income taxes payable	2	20	(6)	3
Change in non-cash operating working capital	(120)	(81)	(101)	(198)

14. Commitments and Contingencies

During the six months ended June 30, 2026, the Company entered into a $45 million maintenance agreement for one of its facilities, running until 2036, and signed a turbine reservation contract with a remaining expected payment of $28 million due in Oct. 2026. The Company has not incurred any other additional material contractual commitments, either directly or through its interests in joint operations and joint ventures.

There were no material changes to the contingencies during the six months ended June 30, 2026.

Refer to Note 36 of the 2025 audited annual consolidated financial statements for the current material outstanding commitments and contingencies.

15. Related-Party Transactions

There were no material related party transactions during the six months ended June 30, 2026.

Refer to Note 35 of the 2025 audited annual consolidated financial statements for further details.

16. Segment Disclosures

A. Description of Reportable Segments

The Company is comprised of four generation segments: Hydro, Wind and Solar, Gas and Energy Transition and two non-generation segments: Energy Marketing and Corporate.

During the first quarter of 2026, the Company updated its assessment of reportable segments to reflect changes in how the Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance and allocates resources. As a result of the reassessment, the Company concluded that the Energy Transition segment no longer meets the quantitative thresholds under IFRS 8 to be presented as a reportable segment, primarily due to Centralia Unit 2 ceasing coal-fired operations, as scheduled at the end of 2025 in the normal course, however the unit remains available to operate in accordance with and for the

duration of the order received from the United States Department of Energy.

Accordingly, as at June 30, 2026 the Company has five reportable segments, reflecting the revised assessment for the Energy Transition segment compared to six reportable segments as at Dec. 31, 2025.

The segment results are presented using Adjusted EBITDA, consistent with the measure reviewed by the CODM when assessing performance and making operating decisions across the Company's segments.

The tables below show the reconciliation of the total segment results and Adjusted EBITDA (non-IFRS measure) to the statement of earnings reported under IFRS.


TransAlta Corporation			F21

B. Reported Adjusted Segment Earnings

I. Reconciliation of Adjusted EBITDA to Earnings before Income Tax


	Reportable Segments
3 months ended June 30, 2026	Hydro	Wind & Solar(1)	Gas	Energy Marketing	Corporate	Energy Transition(2)	Total	Equity- accounted investments	Reclass adjustments	IFRS financials
Revenues	100	115	293	27	(46)	3	492	(5)	—	487
Reclassifications and adjustments:
Unrealized mark-to-market loss (gain)	3	7	—	(8)	—	—	2	—	(2)	—

Decrease in finance lease receivable	—	—	8	—	—	—	8	—	(8)	—
Finance lease income	—	2	4	—	—	—	6	—	(6)	—


Unrealized foreign exchange gain on commodity	—	—	(1)	—	—	—	(1)	—	1	—
Adjusted Revenue	103	124	304	19	(46)	3	507	(5)	(15)	487
Fuel and purchased power	(4)	(4)	(97)	—	(1)	—	(106)	—	—	(106)




Carbon compliance recovery	—	—	6	—	46	—	52	—	—	52
Adjusted Gross Margin	99	120	213	19	(1)	3	453	(5)	(15)	433
OM&A	(11)	(26)	(77)	(9)	(43)	(10)	(176)	1	—	(175)
Reclassifications and adjustments:
Termination and restructuring costs	—	—	—	—	7	—	7	—	(7)	—

Centralia community fund expense	—	—	—	—	—	4	4	—	(4)	—

ERP integration costs	—	—	—	—	1	—	1	—	(1)	—

Adjusted OM&A	(11)	(26)	(77)	(9)	(35)	(6)	(164)	1	(12)	(175)
Taxes, other than income taxes	(1)	(5)	(5)	—	—	—	(11)	—	—	(11)
Net other operating income	—	1	11	—	—	1	13	—	—	13





Adjusted EBITDA(3)	87	90	142	10	(36)	(2)	291
Equity income										1
Finance lease income										6

Depreciation and amortization										(105)
Asset impairment charges										(11)
Interest income										7
Interest expense										(84)
Foreign exchange gain										6


Earnings before income taxes										80

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)The Energy Transition segment no longer meets the quantitative thresholds under IFRS 8 to be presented as a reportable segment starting Jan. 1, 2026.

(3)Adjusted EBITDA is not defined, has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.


F22			TransAlta Corporation


	Reportable Segments
3 months ended June 30, 2025	Hydro	Wind & Solar(1)	Gas	Energy Marketing	Corporate	Energy Transition(2)	Total	Equity- accounted investments	Reclass adjustments	IFRS financials
Revenues	129	59	204	38	(67)	73	436	(3)	—	433
Reclassifications and adjustments:
Unrealized mark-to-market loss (gain)	18	68	71	(2)	—	15	170	—	(170)	—

Decrease in finance lease receivable	—	—	7	—	—	—	7	—	(7)	—
Finance lease income	—	2	3	—	—	—	5	—	(5)	—
Revenues from Required Divestitures	—	—	(3)	—	—	—	(3)	—	3	—

Unrealized foreign exchange gain on commodity	—	—	—	(2)	—	—	(2)	—	2	—
Adjusted Revenues	147	129	282	34	(67)	88	613	(3)	(177)	433
Fuel and purchased power	(7)	(9)	(106)	—	—	(51)	(173)	—	—	(173)
Reclassifications and adjustments:
Fuel and purchased power related to the Required Divestitures	—	—	1	—	—	—	1	—	(1)	—



Adjusted Fuel and Purchased Power	(7)	(9)	(105)	—	—	(51)	(172)	—	(1)	(173)
Carbon compliance (costs) recovery	—	(1)	8	—	67	—	74	—	—	74
Adjusted Gross Margin	140	119	185	34	—	37	515	(3)	(178)	334
OM&A	(13)	(25)	(65)	(8)	(45)	(18)	(174)	1	—	(173)




Reclassifications and adjustments:
OM&A related to the Required Divestitures	—	—	1	—	—	—	1	—	(1)	—
ERP integration costs	—	—	—	—	6	—	6	—	(6)	—
Acquisition-related transaction and restructuring costs	—	—	—	—	1	—	1	—	(1)	—
Adjusted OM&A	(13)	(25)	(64)	(8)	(38)	(18)	(166)	1	(8)	(173)
Taxes, other than income taxes	(1)	(5)	(5)	—	(1)	—	(12)	—	—	(12)
Net other operating income	—	—	12	—	—	—	12	—	—	12



Adjusted EBITDA(3)	126	89	128	26	(39)	19	349
Equity income										1
Finance lease income										5
Depreciation and amortization										(150)
Asset impairment charges										(13)
Interest income										6
Interest expense										(88)
Foreign exchange loss										(17)


Loss before income taxes										(95)

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)The Energy Transition segment no longer meets the quantitative thresholds under IFRS 8 to be presented as a reportable segment starting Jan. 1, 2026.

(3)Adjusted EBITDA is not defined, has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.


TransAlta Corporation			F23


	Reportable Segments
6 months ended June 30, 2026	Hydro	Wind & Solar(1)	Gas	Energy Marketing	Corporate	Energy Transition(2)	Total	Equity- accounted investments	Reclass adjustments	IFRS financials
Revenues	157	240	641	66	(45)	5	1,064	(12)	—	1,052
Reclassifications and adjustments:
Unrealized mark-to-market loss (gain)	—	13	(18)	(19)	—	—	(24)	—	24	—

Decrease in finance lease receivable	—	1	15	—	—	—	16	—	(16)	—
Finance lease income	—	3	10	—	—	—	13	—	(13)	—


Unrealized foreign exchange gain on commodity	—	—	(2)	—	—	—	(2)	—	2	—
Adjusted Revenue	157	257	646	47	(45)	5	1,067	(12)	(3)	1,052
Fuel and purchased power	(8)	(11)	(251)	—	(1)	—	(271)	—	—	(271)




Carbon compliance (costs) recovery	—	—	(33)	—	46	—	13	—	—	13
Adjusted Gross Margin	149	246	362	47	—	5	809	(12)	(3)	794
OM&A	(25)	(51)	(139)	(20)	(105)	(18)	(358)	2	—	(356)
Reclassifications and adjustments:
Termination and restructuring costs	—	—	—	—	18	—	18	—	(18)	—
Legal costs related to arbitration proceedings	—	—	—	—	9	—	9	—	(9)	—
Centralia community fund expense	—	—	—	—	—	11	11	—	(11)	—

ERP integration costs	—	—	—	—	4	—	4	—	(4)	—
Acquisition-related transaction and restructuring costs	—	—	—	—	1	—	1	—	(1)	—
Adjusted OM&A	(25)	(51)	(139)	(20)	(73)	(7)	(315)	2	(43)	(356)
Taxes, other than income taxes	(2)	(12)	(10)	—	—	—	(24)	—	—	(24)
Net other operating income	—	14	22	—	—	1	37	—	—	37
Reclassifications and adjustments:
Legal settlement recoveries	—	(12)	—	—	—	—	(12)	—	12	—


Adjusted Net Other Operating Income	—	2	22	—	—	1	25	—	12	37
Adjusted EBITDA(3)	122	185	235	27	(73)	(1)	495
Equity income										4
Finance lease income										13

Depreciation and amortization										(210)
Asset impairment charges										(5)
Interest income										14
Interest expense										(166)
Foreign exchange gain										4

Loss on sale of assets and other										(2)
Earnings before income taxes										103

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)The Energy Transition segment no longer meets the quantitative thresholds under IFRS 8 to be presented as a reportable segment starting Jan. 1, 2026.

(3)Adjusted EBITDA is not defined, has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.


F24			TransAlta Corporation


	Reportable Segments
6 months ended June 30, 2025	Hydro	Wind & Solar(1)	Gas	Energy Marketing	Corporate	Energy Transition(2)	Total	Equity- accounted investments	Reclass adjustments	IFRS financials
Revenues	215	166	594	65	(66)	227	1,201	(10)	—	1,191
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	(3)	104	39	(1)	—	14	153	—	(153)	—

Decrease in finance lease receivable	—	1	14	—	—	—	15	—	(15)	—
Finance lease income	—	3	8	—	—	—	11	—	(11)	—
Revenues from Required Divestitures	—	—	(7)	—	—	—	(7)	—	7	—

Unrealized foreign exchange gain on commodity	—	—	—	(2)	—	—	(2)	—	2	—
Adjusted Revenues	212	274	648	62	(66)	241	1,371	(10)	(170)	1,191
Fuel and purchased power	(11)	(19)	(269)	—	(2)	(149)	(450)	—	—	(450)
Reclassifications and adjustments:
Fuel and purchased power related to the Required Divestitures	—	—	3	—	—	—	3	—	(3)	—



Adjusted Fuel and Purchased Power	(11)	(19)	(266)	—	(2)	(149)	(447)	—	(3)	(450)
Carbon compliance (costs) recovery	—	(2)	(41)	—	68	—	25	—	—	25
Adjusted Gross Margin	201	253	341	62	—	92	949	(10)	(173)	766
OM&A	(26)	(54)	(124)	(15)	(94)	(35)	(348)	2	—	(346)




Reclassifications and adjustments:
OM&A related to the Planned Divestitures	—	—	3	—	—	—	3	—	(3)	—
ERP integration costs	—	—	—	—	10	—	10	—	(10)	—
Acquisition-related transaction and restructuring costs	—	—	—	—	5	—	5	—	(5)	—
Adjusted OM&A	(26)	(54)	(121)	(15)	(79)	(35)	(330)	2	(18)	(346)
Taxes, other than income taxes	(2)	(10)	(10)	—	(1)	(1)	(24)	—	—	(24)
Net other operating income	—	4	22	—	—	—	26	—	—	26
Reclassifications and adjustments:
Insurance recovery	—	(2)	—	—	—	—	(2)	—	2	—
Adjusted Net Other Operating Income	—	2	22	—	—	—	24	—	2	26
Adjusted EBITDA(3)	173	191	232	47	(80)	56	619
Equity income										3
Finance lease income										11
Depreciation and amortization										(296)
Asset impairment charges										(28)
Interest income										11
Interest expense										(181)
Foreign exchange loss										(21)
Fair value change in contingent consideration										34
Loss on sale of assets and other										(1)
Loss before income taxes										(46)

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.

(2)The Energy Transition segment no longer meets the quantitative thresholds under IFRS 8 to be presented as a reportable segment starting Jan. 1, 2026.

(3)Adjusted EBITDA is not defined, has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.


TransAlta Corporation			F25

Source: View Original Filing on SEC EDGAR

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