TRANSALTA CORPORATION

Management’s Discussion and Analysis

First Quarter Report for 2024

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

Table of Contents

M2	Forward-Looking Statements	M32	Cash Flows
M4	Description of the Business	M33	Other Consolidated Analysis
M6	Highlights	M34	Financial Instruments
M11	Capital Expenditures	M35	Additional IFRS Measures and Non-IFRS Measures
M12	Significant and Subsequent Events	M41	Key Non-IFRS Financial Ratios
M13	Segmented Financial Performance and Operating Results	M42	2024 Outlook
M19	Performance by Segment with Supplemental Geographical Information	M43	Material Accounting Policies and Critical Accounting Estimates
M19	Optimization of the Alberta Portfolio	M43	Accounting Changes
M21	Selected Quarterly Information	M43	Governance and Risk Management
M23	Strategy and Capability to Deliver Results	M44	Regulatory Updates
M27	Financial Position	M46	Disclosure Controls and Procedures
M29	Financial Capital

This MD&A should be read in conjunction with our unaudited interim condensed consolidated financial statements as at and for the three months ended March 31, 2024 and 2023, and should be read in conjunction with the audited annual consolidated financial statements and MD&A ("2023 Annual MD&A") contained within our 2023 Integrated 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 March 31, 2024. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted, except amounts per share, which are in whole dollars to the nearest two decimals. This MD&A is dated May 2, 2024. Additional information respecting TransAlta, including our Annual Information Form ("AIF") for the year ended Dec. 31, 2023, is available on SEDAR+ at www.sedarplus.ca, on EDGAR at www.sec.govand on our website at www.transalta.com. Information on or connected to our website is not incorporated by reference herein.

TransAlta Corporation M1

Forward-Looking Statements

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

In particular, this MD&A contains forward-looking statements including, but not limited to, statements relating to: the Company’s ability to deliver the 2024 Outlook, including Adjusted EBITDA, free cash flow, annualized dividends per share, sustaining capital spending, and energy marketing gross margin; the Company’s expanded growth targets to deliver 1.75 GW with a target investment of $3.5 billion by 2028 that will deliver annual EBITDA of $350 million; the expansion of the Company's development pipeline to 10 GW by 2028; the anticipated benefits arising from the MOU (as defined below) with the Government of Alberta; the Company’s investment strategy to deliver long-term value to shareholders; the common share dividend level through 2024; the Company's projects under construction, including capital costs, the timing of commercial operations and expected annual EBITDA, including the Horizon Hill wind development; the impact of new asset additions in 2024 including Kent Hills, Mount Keith transmission, and White Rock; the development of the early-stage and advanced-stage projects; achieving the anticipated benefits of the transfer of PTCs (defined below) generated from the White Rock and Horizon Hill wind projects; the Company's hedging strategy and the ability of such strategy to provide greater cash flow certainty; the delivery of stable and predictable cash flows; the proportion of EBITDA to be generated from renewable sources to increase to 70 per cent by the end of 2028; the Company’s ability to achieve its long-term decarbonization goal to be

net zero by 2045; the reduction of carbon emissions by 75 per cent from 2015 emissions levels by 2026; the expected impact and quantum of carbon compliance costs; the retirement of Centralia Unit 2 at the end of 2025; regulatory developments and their expected impact on the Company; expectations regarding the refinancing of debt; recognition by the Company of natural gas transportation agreements as onerous in the case the Company decides to retire certain facilities in advance of the expiry date of the natural gas transportation agreements; and the Company continuing to maintain adequate liquidity.

The forward-looking statements contained in this MD&A are based on many assumptions including, but not limited to, the following: no significant changes to applicable laws and regulations beyond those that have already been announced; no significant changes to fuel and purchased power costs; no material adverse impacts to long-term investment and credit markets; no significant changes to power price and hedging assumptions, including hedged volumes and prices; no significant changes to gas commodity prices and transport costs; no significant changes to decommissioning and restoration costs; no significant changes to interest rates; no significant changes to the demand and growth of renewables generation; no significant changes to the integrity and reliability of our assets; planned and unplanned outages and use of our assets; and no significant changes to the Company's debt and credit ratings.

Forward-looking statements are subject to a number of significant risks and uncertainties that could cause actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this MD&A include risks relating to: fluctuations in power prices, including merchant pricing in Alberta, Ontario and Mid-Columbia; failure or delay in closing the Heartland acquisition; failure to realize the benefits of the Heartland acquisition, and any loss of value in the Heartland portfolio during the interim period prior to closing; reductions in production; restricted access to capital and increased borrowing costs, including any difficulty raising debt, equity or tax equity, as applicable, on reasonable terms or at all; labour relations matters, reduced labour availability and the ability to continue to staff our operations and facilities; reliance on key personnel; disruptions to our supply chains, including our ability to secure necessary equipment; force majeure claims; our ability to obtain regulatory and any other third-party approvals on the expected timelines or at all in respect of our growth projects; long-term commitments on gas transportation capacity that may not be fully utilized over time; adverse financial impacts arising from the Company's hedged position; risks associated with

M2 TransAlta Corporation

development and construction projects, including increased capital costs, permitting challenges, labour and engineering risks, disputes with contractors and potential delays in the construction or commissioning of such projects; significant fluctuations in the Canadian dollar against the US dollar and Australian dollar; changes in short-term and long-term electricity supply and demand; counterparty credit risk and any higher rate of losses on our accounts receivables; inability to achieve our environmental, social and governance ("ESG") targets; the impact of the energy transition on our business; impairments and/or writedowns of assets; adverse impacts on our information technology systems and our internal control systems, including cybersecurity threats; commodity risk management and energy trading risks, including the effectiveness of the Company’s risk management tools associated with hedging and trading procedures to protect against significant losses; our ability to contract our generation for prices that will provide expected returns and to replace contracts as they expire; changes to the legislative, regulatory and political environments in the jurisdictions in which we operate, including the impacts of restrictions on renewable energy projects, amended Independent System Operator rules, expected changes to Transmission Regulations, and the creation of the Restructured Energy Market (defined below); environmental requirements and changes in, or liabilities under, these requirements; disruptions in the transmission and distribution of electricity; the effects of weather, including man-made or natural disasters and other climate-change related risks; increases in costs; reductions to our generating units’ relative efficiency or capacity factors; disruptions in the source of fuels, including natural gas, coal, water, solar or wind resources required to operate our facilities; operational risks, unplanned outages and equipment failure and our ability to carry out or have completed any repairs in a cost-effective or timely manner or at all; failure to meet financial expectations; general domestic, international economic and political developments, including armed hostilities, the threat of terrorism, adverse diplomatic developments or other similar events; industry risk and competition in the business in which we operate; structural subordination of securities; public health crisis risks; inadequacy or unavailability of insurance coverage; our provision for income taxes and any risk of reassessment; and legal, regulatory and contractual disputes and proceedings involving the Company. The foregoing risk factors, among others, are described in further detail in the Governance and Risk Management section of this MD&A and the Risk Factors section in our AIF for the year ended Dec. 31, 2023.

Readers are urged to consider these factors carefully when evaluating the forward-looking statements, which reflect the Company's expectations only as of the date hereof and are cautioned not to place undue reliance on them. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. The purpose of the financial outlooks contained herein is to give the reader information about management's current expectations and plans and readers are cautioned that such information may not be appropriate for other purposes. In light of these risks, uncertainties and assumptions, the forward-looking statements might occur to a different extent or at a different time than we have described, or might not occur at all. We cannot assure that projected results or events will be achieved.

TransAlta Corporation M3

Description of the Business

TransAlta is a Canadian corporation and one of Canada's largest publicly traded power generators. Established in 1911, the Company now has over 112 years of operating experience in the development, production and sale of electricity. We own, operate and manage a geographically diversified portfolio of generation assets that includes water, wind, solar, battery storage, natural gas and transition coal. We are one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta. We also have industry-leading energy marketing capabilities where we seek to maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions. Our mix of merchant and contracted assets along with our energy marketing business provides resilient cash flows that support our ability to maintain our balance sheet, return capital to our shareholders and reinvest in growth.

Portfolio of Assets

Our asset portfolio is geographically diversified with operations across Canada, the United States and Australia.

Our highly diversified portfolio consists of both high-quality contracted assets and merchant assets. Approximately 57

per cent of our total installed capacity is contracted with investment-grade or creditworthy counterparties. Our merchant assets include our unique hydro merchant portfolio and our merchant legacy thermal portfolio and wind assets. Our merchant exposure is primarily in Alberta, where 52 per cent of our capacity is located and 75 per cent of our Alberta capacity is available to participate in the merchant electricity market.

A significant portion of the thermal generation capacity in the portfolio has been hedged to provide greater cash flow certainty. The Company's hedging strategy includes maintaining a significant base of commercial and industrial customers and is supplemented with financial hedges. Refer to the 2024 Outlook and the Optimization of the Alberta Portfolio sections of this MD&A for further details.

Our diversified fleet is a key success factor in our ability to deliver resilient cash flows while capturing higher risk-adjusted returns for our shareholders.

On Jan. 1, 2024, the 100 MW White Rock West wind facility achieved commercial operation. On April 22, 2024, the 200 MW White Rock East wind facility achieved commercial operation. The Mount Keith 132kV expansion project was also completed during the first quarter of 2024.

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

	Hydro		Wind & Solar		Gas		Energy Transition		Total
As at March 31, 2024	Gross Installed Capacity (MW)	Number of facilities	Gross Installed Capacity (MW)(1)	Number of facilities	Gross Installed Capacity (MW)(1)	Number of facilities	Gross Installed Capacity (MW)	Number of facilities(2)	Gross Installed Capacity (MW)(1)	Number of facilities
Alberta	834	17	766	14	1,963	7	—	—	3,563	38
Canada, excluding Alberta	88	7	751	9	645	3	—	—	1,484	19
US	—	—	619	8	29	1	671	2	1,319	11
Australia	—	—	48	3	450	6	—	—	498	9
Total	922	24	2,184	34	3,087	17	671	2	6,864	77

(1)Gross installed capacity for consolidated reporting represents 100 per cent output of a facility. Capacity figures for the Wind and Solar segment includes 100 per cent of the Kent Hills wind facilities, and capacity figures for the Gas segment include 100 per cent of the Ottawa and Windsor facilities, 50 per cent of the Sheerness facility and 60 per cent of the Fort Saskatchewan facility.

(2)Includes Centralia Unit 1 and the Skookumchuck Hydro facility.

M4 TransAlta Corporation

Stable and Predictable Cash Flows

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

As at March 31, 2024	Hydro		Wind & Solar		Gas		Energy Transition		Total
Alberta	—		374		511		—		885
Canada, excluding Alberta	88		751		645		—		1,484
US	—		619		29		381		1,029
Australia	—		48		450		—		498
Total contracted capacity (MW)	88		1,792		1,635		381		3,896
Contracted capacity as a % of total capacity (%)	10	%	82	%	53	%	57	%	57	%

The weighted average contract life (years) of our facilities across the regions in which we operate as of March 31, 2024 is:

As at March 31, 2024	Hydro	Wind & Solar	Gas	Energy Transition	Total
Alberta(1)(2)	—	16	7	—	11
Canada, excluding Alberta(2)	10	10	8	—	9
US(2)	—	11	2	2	7
Australia(2)	—	15	15	—	15
Total weighted contract life (years)(2)	10	12	9	2	10

(1)The weighted-average remaining contract life in the Wind and Solar segment is related to the contract period for Garden Plain (130 MW), McBride Lake (38 MW), and Windrise (206 MW). The weighted-average remaining contract life in the Gas segment is related to the contract period for Poplar Creek (230 MW), Fort Saskatchewan (71 MW) and a capacity-contract that is not directly contracted with any one facility (210 MW).

(2)For power generated under long-term power purchase agreements ("PPAs") and other long-term contracts, the weighted-average remaining contract life is based on long-term average gross installed capacity.

The majority of TransAlta's long-term power purchase agreements are with investment-grade rated or creditworthy counterparties. Additionally, our financial hedging strategy including maintaining a significant base of commercial and industrial customers in Alberta further supports the delivery of stable and predictable cash flows.

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Highlights

For the three months ended March 31, 2024, the Company demonstrated strong financial and operational performance and is on track to meet its 2024 Outlook, due to active management of our merchant portfolio and hedging

strategies, which included higher production in the Hydro and Gas segments.

	3 months ended March 31
(in millions of Canadian dollars except where noted)	2024	2023
Operational information
Adjusted availability (%)	92.3	92.0
Production (GWh)	6,178	5,972
Select financial information
Revenues	947	1,089
Earnings before income taxes	267	383
Adjusted EBITDA(1)	328	503
Net earnings attributable to common shareholders	222	294
Cash flows
Cash flow from operating activities	244	462
Funds from operations(1)	239	374
Free cash flow(1)	206	263
Per share
Weighted average number of common shares outstanding	308	268
Net earnings per share attributable to common shareholders, basic and diluted	0.72	1.10
Funds from operations per share(1)(2)	0.78	1.40
Free cash flow per share(1)(2)	0.67	0.98
As at	March 31, 2024	Dec. 31, 2023
Liquidity and capital resources
Available liquidity	1,737	1,738
Adjusted net debt to adjusted EBITDA(1) (times)	2.8	2.5
Total consolidated net debt(1)(3)	3,384	3,453
Assets and liabilities
Total assets	8,752	8,659
Total long-term liabilities	4,487	5,253
Total liabilities	6,820	6,995

(1)These items are not defined and have no standardized meaning under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings (loss) trends more readily in comparison with prior periods’ results. Refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. Also, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(2)Funds from operations ("FFO") per share and free cash flow ("FCF") per share are calculated using the weighted average number of common shares outstanding during the period. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for the purpose of these non-IFRS ratios.

(3)Refer to the table in the Financial Capital section of this MD&A for more details on the composition of total consolidated net debt.

M6 TransAlta Corporation

Operating Performance

Adjusted Availability

The following table provides adjusted availability (%) by segment:

3 months ended March 31	2024	2023
Hydro	91.9	94.1
Wind and Solar	93.4	82.9
Gas	94.6	96.4
Energy Transition	79.0	94.5
Adjusted availability (%)	92.3	92.0

Availability is an important measure for the Company as it represents the percentage of time a facility is available to produce electricity and is therefore an important indicator of the overall performance of the fleet.

Availability is impacted by planned and unplanned outages. The Company schedules dedicated time (planned outages) to maintain, repair or make improvements to the facilities with a view to minimizing the impact to operations. In high price environments, actual outage schedules may change to accelerate the return to service of the unit.

Adjusted availability for the three months ended March 31, 2024, was 92.3 per cent, compared to 92.0 per cent in the same period in 2023.

Higher adjusted availability was primarily due to:

•The return to service of the Kent Hills wind facilities; and

•Lower unplanned outages in the Wind and Solar segment; partially offset by,

•Unplanned outages at Centralia Unit 2 in the Energy Transition segment;

•Unplanned outages at Sundance Unit 6 and the Australia gas facilities in the Gas segment; and,

•Planned major maintenance outages in the Hydro segment.

Production and Long-Term Average Generation

	2024				2023
As at March 31	Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA generation		Actual production (GWh)	LTA generation (GWh)	Production as a % of LTA generation
Hydro	351	402	87	%	306	402	76	%
Wind and Solar	1,498	1,644	91	%	1,197	1,423	84	%
Gas	3,528				3,172
Energy Transition	801				1,297
Total	6,178				5,972

In addition to adjusted availability, the Company utilizes long-term average production ("LTA generation") as another indicator of performance for the renewable assets whereby actual production levels are compared against the expected long-term average. In the short term, for each of the Hydro and Wind and Solar segments, the conditions will vary from one period to the next. Over longer durations, facilities are expected to produce in line with their long-term averages, which is considered a reliable indicator of performance.

LTA generation is calculated on an annualized basis from the average annual energy yield predicted from our simulation model based on historical resource data performed over a period of typically greater than 25 years.

LTA generation for Energy Transition is not considered as we are currently transitioning these units with the expectation that the final unit will retire by the end of 2025. The LTA generation for Gas is not applicable as these units are dispatchable and their production is largely dependent on market conditions and merchant demand.

Total production for the three months ended March 31, 2024, increased by 206 GWh or 3 per cent compared with the same period in 2023.

Production from our renewables assets for the three months ended March 31, 2024, was higher by 346 GWh, or 23 per cent compared to 2023, yielding 90 per cent of LTA generation.

TransAlta Corporation M7

The Wind and Solar production increased by 301 GWh, or 25 per cent, driven primarily by

•Production from new facilities, including the White Rock West wind facility commissioned in January 2024 and the Garden Plain wind facility commissioned in August 2023;

•The return to service of the Kent Hills wind facilities, completed in the first quarter of 2024;

•Pre-commissioning production from the White Rock East wind facility and the Horizon Hill wind project; partially offset by

•Lower wind resource in Alberta.

Hydro production increased by 45 GWh, or 15 per cent, yielding 87 per cent of LTA generation. Higher energy

production at Hydro during the quarter was in response to significant demand resulting from periods of extreme cold conditions in Alberta.

The Gas segment production increased by 356 GWh or 11 per cent. The higher production from the segment was primarily driven by the Sarnia facility as market conditions were favourable which enabled higher dispatch and resulted in higher merchant production to the Ontario grid.

Production from the Energy Transition segment was negatively impacted by higher unplanned outage hours and increased economic dispatch at the Centralia facility compared to the prior period.

Market Pricing

3 months ended March 31	2024	2023
Alberta spot power price ($/MWh)	99	142
Mid-Columbia spot power price (US$/MWh)	104	106
Ontario spot power price ($/MWh)	33	27
Natural gas price (AECO) per GJ ($)	1.94	3.08

For the three months ended March 31, 2024, spot electricity prices in Alberta were on average lower compared with the same period in 2023, driven by milder weather conditions and the additions of new natural gas, wind and solar supply in the market.

Spot electricity prices in the Pacific Northwest were comparable on average to the same period in 2023 however, this was due to high prices concentrated in January this quarter.

AECO natural gas prices for the three months ended March 31, 2024, were lower compared with the same period in 2023, mainly due to improved production and higher storage levels in Alberta and throughout North America.

M8 TransAlta Corporation

Financial Performance review on Consolidated Information

3 months ended March 31	2024	2023
Revenues	947	1,089
Fuel and purchased power	323	325
Carbon compliance	40	32
Operations, maintenance and administration	134	124
Depreciation and amortization	124	176
Earnings before income taxes	267	383
Income tax expense	29	49
Net earnings attributable to common shareholders	222	294
Net earnings attributable to non-controlling interests	16	40

First Quarter Variance Analysis (2024 versus 2023)

Revenuestotalling $947 million, decreased by $142 million, or 13 per cent, compared to the same period in 2023, primarily due to:

•Lower revenue from merchant sales in Alberta due to lower spot and hedged power prices;

•Lower production at Centralia in the Energy Transition segment; and

•Lower realized and unrealized gains from hedging and derivative positions in the Energy Marketing segment.

Fuel and purchased power costs totalling $323 million, decreased by $2 million, or 1 per cent, compared to the same period in 2023, primarily due to:

•Lower production in the Energy Transition segment; and

•Lower natural gas commodity pricing; partially offset by

•Higher production in the Gas segment.

Carbon compliance costs totalling $40 million, increased by $8 million, or 25 per cent, compared to the same period in 2023, primarily due to:

•An increase in the carbon price per tonne from $65 per tonne in 2023 to $80 per tonne in 2024; and

•Higher production in the Gas segment.

Operations, maintenance and administration ("OM&A") expenses totalling $134 million, increased by $10 million, or 8 per cent, compared to the same period in 2023, primarily due to:

•Higher spending on strategic and growth initiatives; and

•Higher OM&A from the addition of the Garden Plain and White Rock West wind facilities and the Northern Goldfields solar facilities.

Depreciation and amortization totalling $124 million, decreased by $52 million, or 30 per cent, compared to the same period in 2023, primarily due to revisions to useful lives on certain facilities in prior periods.

Earnings before income taxes totalling $267 million, decreased by $116 million, or 30 per cent, compared to the same period in 2023, due to the above noted items.

Income tax expense totalling $29 million, decreased by $20 million, or 41 per cent, compared to the same period in 2023, due to lower earnings before income taxes and lower US non-deductible expenses relating to the US operations.

Net earnings attributable to non-controlling intereststotalling $16 million, decreased by $24 million, or 60 per cent, compared to the same period in 2023, primarily due to lower net earnings for TransAlta Cogeneration, LP ("TA Cogen") and no net earnings attributable to non-controlling interests for TransAlta Renewables Inc. ("TransAlta Renewables") in the first quarter of 2024.

TransAlta Corporation M9

Adjusted EBITDA

For the three months ended March 31, 2024, the Company's adjusted EBITDA was $328 million as compared to $503 million in 2023, a decrease of $175 million. The major factors impacting adjusted EBITDA are summarized in the following table:

	3 months ended March 31
Adjusted EBITDA for the three months ended March 31, 2023	503
Hydro:lower primarily due to lower realized gains on forward contracts compared to the prior period and lower realized power and ancillary services prices in the Alberta market, partially offset by higher production and higher environmental attribute revenues.	(19)
Wind and Solar: higher primarily due to higher environmental attribute revenues, the return to service of the Kent Hills wind facilities, the commercial operation of the Garden Plain wind facility, White Rock West wind facility and Northern Goldfields solar facilities, offset by lower realized power pricing in the Alberta market, weaker wind resource across the Alberta operating fleet and higher OM&A due to the addition of the new wind and solar facilities.	1
Gas: lower primarily due to lower realized power and ancillary services prices in Alberta, lower capacity payments for Southern Cross Energy due to the conclusion of the demand capacity charge under the applicable customer contract, higher carbon costs and higher OM&A, partially offset by the commencement of capacity payments for the Mount Keith 132kV expansion and lower natural gas commodity costs.	(106)
Energy Transition: lower primarily due to lower production from higher unplanned outages and increased economic dispatch due to lower market prices, partially offset by lower fuel and purchased power costs.	(28)
Energy Marketing: lower primarily due to lower realized settled trades during the period on market positions in comparison to the prior period, partially offset by lower OM&A due to lower incentives.	(19)
Corporate: lower primarily due to increased spending to support strategic and growth initiatives.	(4)
Adjusted EBITDA(1) for the three months ended March 31, 2024	328

(1)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

M10 TransAlta Corporation

Free Cash Flow

For the three months ended March 31, 2024, the Company's FCF decreased by $57 million, or 22 per cent, compared with the same period in 2023. The major factors impacting FCF are summarized in the following table:

	3 months ended March 31
FCF for the three months ended March 31, 2023	263
Lower adjusted EBITDA: due to the items noted above.	(175)
Lower current income tax expense due to lower earnings before tax.	33
Lower sustaining capital expenditures: expenditures were offset by the receipt of a lease incentive related to the relocation of the Company's head office.	21
Lower distributions paid to subsidiaries' non-controlling interests: relating to the timing of distributions paid to TA Cogen and the cessation of distributions by TransAlta Renewables Inc.	57
Other non-cash items(1)	14
Other(2)	(7)
FCF(3) for the three months ended March 31, 2024	206

(1)Other non-cash items consists of carbon obligation, contract liabilities, and the SunHills royalty onerous contract. Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF section tables in this MD&A for more details.

(2)Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF section tables in this MD&A for more details.

(3)FCF is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Capital Expenditures

We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake sustaining capital expenditures that ensure our facilities operate reliably and safely.

3 months ended March 31	2024	2023
Hydro	3	6
Wind and Solar	2	3
Gas	3	3
Corporate	(9)	8
Total sustaining capital expenditures	(1)	20

Total sustaining capital expenditures in 2024 were $21 million lower compared with the same period in 2023, primarily due to:

•The receipt of a lease incentive related to the relocation of the Company's head office, included in the Corporate segment; and

•Lower planned major maintenance at our Alberta Hydro Assets.

3 months ended March 31	2024	2023
Hydro	2	—
Wind and Solar	41	255
Gas	3	—
Corporate(1)	9	15
Growth and development expenditures	55	270

(1)Expenditures related to projects in the development phase are included in the Corporate segment.

TransAlta Corporation M11

In the first quarter of 2024, growth and development expenditures were lower compared with the same period in 2023, primarily due to the White Rock East and Horizon Hill wind projects being in their final stages of construction. The White Rock West wind facility and Mount Keith 132kV expansion were commissioned and completed in the first quarter of 2024. In addition to these projects, 2023 growth

and development expenditures also included the Garden Plain wind facility, which commissioned in August 2023, and the Northern Goldfields solar facilities, which commissioned in November 2023. Refer to the Strategic Priorities and Clean Electricity Growth Plan to 2028 section of this MD&A for more details.

Significant and Subsequent Events

White Rock Wind Facilities Achieve Commercial Operation

On Jan. 1, 2024, the 100 MW White Rock West wind facility achieved commercial operation. On April 22, 2024, the 200 MW White Rock East wind facility was also commissioned. The White Rock wind facilities are located in Caddo County, Oklahoma and are contracted under two long-term PPAs with Amazon for the offtake of 100 per cent of the generation from the facilities. The Company's wind generating portfolio in the US now totals 819 MW in gross installed capacity.

Annual Shareholder Meeting

The Honourable Rona Ambrose did not stand for reelection and retired from the Board following the annual shareholder meeting on April 25, 2024. The Board extends its gratitude for her service to the Company. She has been a valuable contributor to the Board since 2017 and we thank her for her leadership and insight, including her contributions as Chair of the Governance, Safety and Sustainability Committee of the Board.

At the annual general meeting of the holders of common shares of TransAlta, the Company received strong support on all items of business, including the election of 12 directors, re-appointment of auditors and Say-on-Pay.

Bow River Basin Memorandum of Understanding

On April 19, 2024, the Company announced it had signed a voluntary water-sharing memorandum of understanding with over thirty other water licence holders in the Bow River Basin. The Government of Alberta continues to anticipate and prepare for lower water conditions this summer with specific concerns in southern Alberta where agriculture could be impacted by water shortages. The Government of Alberta is leading efforts to coordinate water usage among water licence holders for Alberta river basins in an effort to ensure licensees get the water they need as opposed to the water to which they are entitled. In recognition of the unique role the Company plays in managing water flows while also serving as a key provider to Alberta's electricity grid, we look forward to working

with the Government and downstream stakeholders to maximize water storage in the early season to help mitigate any anticipated drought conditions. We anticipate the Company's water management efforts will not have an adverse impact on our electricity generating and environmental objectives.

TransAlta Announced Retirement of CFO and Appointment of New CFO

On April 11, 2024, the Company announced the retirement of Todd Stack, Executive Vice President, Finance and Chief Financial Officer from the Company, effective June 30, 2024. The Board of Directors ("the Board") expresses its deep appreciation to Todd for his contributions to TransAlta and its success during his 34-year career with the Company.

The Board has appointed Joel E. Hunter as Executive Vice President, Finance and Chief Financial Officer, effective July 1, 2024.

Normal Course Issuer Bid ("NCIB") and Automatic Share Purchase Plan ("ASPP")

TransAlta is committed to enhancing shareholder returns through appropriate capital allocation such as share buybacks and its quarterly dividend. The Company previously announced an enhanced common share repurchase program for 2024 of up to $150 million, targeting up to 42 per cent of 2024 FCF guidance being returned to shareholders in the form of share repurchases and dividends.

The Company also previously announced that it had received approval from the Toronto Stock Exchange (“TSX”) to purchase up to 14,000,000 of its common shares during the 12-month period that commenced on May 31, 2023 and will terminate on May 30, 2024. The Company intends to renew the NCIB in May 2024.

On March 19, 2024, the Company entered into an ASPP to facilitate repurchases of TransAlta’s common shares under its NCIB.

Under the ASPP, the Company’s broker may purchase common shares from the effective date of the ASPP until the termination of the ASPP. All purchases of common

M12 TransAlta Corporation

shares made under the ASPP will be included in determining the number of common shares purchased under the NCIB. The ASPP will terminate on the earliest of the date on which: (a) the maximum purchase limits under the ASPP are reached; (b) May 3, 2024; or (c) the Company terminates the ASPP in accordance with its terms.

During the three months ended March 31, 2024, the Company purchased and cancelled a total of 3,460,300 common shares, at an average price of $9.36 per common share, for a total cost of $32 million.

Mount Keith 132kV Expansion Complete

The Mount Keith 132kV expansion project was completed during the first quarter of 2024. The expansion was

developed under the existing PPA with BHP Nickel West ("BHP"), which has a term of 15 years. The expansion will facilitate the connection of additional generating capacity to the transmission network which supports BHP's operations and increases its competitiveness as a supplier of low-carbon nickel.

Production Tax Credit ("PTC") Sale Agreements

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

Segmented Financial Performance and Operating Results

Segmented information is prepared on the same basis that the Company manages its business, evaluates financial results and makes key operating decisions. The following table reflects the summary financial information on a consolidated basis for the three months ended March 31:

	Adjusted EBITDA(1)
3 months ended March 31	2024	2023
Hydro	87	106
Wind and Solar	89	88
Gas	134	240
Energy Transition	26	54
Energy Marketing	20	39
Corporate	(28)	(24)
Total adjusted EBITDA(1)	328	503
Earnings before income taxes	267	383

(1)This item is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

TransAlta Corporation M13

Hydro

3 months ended March 31	2024	2023	Change
Gross installed capacity (MW)	922	922	—	—	%
LTA generation (GWh)	402	402	—	—	%
Availability (%)	91.9	94.1	(2.2)	(2)	%
Production
Contract production (GWh)	38	23	15	65	%
Merchant production (GWh)	313	283	30	11	%
Total energy production (GWh)	351	306	45	15	%
Ancillary service volumes (GWh)(1)	661	643	18	3	%
Alberta Hydro Assets revenues(2)(3)	49	71	(22)	(31)	%
Other Hydro Assets and other revenues(2)(4)	8	6	2	33	%
Alberta Hydro ancillary services revenues(1)	36	39	(3)	(8)	%
Environmental attribute revenues	14	8	6	75	%
Revenues(5)	107	124	(17)	(14)	%
Fuel and purchased power	6	5	1	20	%
Gross margin(6)	101	119	(18)	(15)	%
OM&A	13	12	1	8	%
Taxes, other than income taxes	1	1	—	—	%
Adjusted EBITDA(6)	87	106	(19)	(18)	%
Supplemental Information:
Gross revenues per MWh
Alberta Hydro Assets energy ($/MWh)(2)(3)	152	258	(106)	(41)	%
Alberta Hydro Assets ancillary ($/MWh)(1)	54	60	(6)	(10)	%

(1)Ancillary services as described in the Alberta Electric System Operator ("AESO") Consolidated Authoritative Document Glossary.

(2)Alberta Hydro Assets include 13 hydro facilities on the Bow and North Saskatchewan river systems. Other Hydro assets includes our hydro facilities in British Columbia, Ontario and Alberta (other than the Alberta Hydro Assets) and transmission revenues.

(3)The Company entered into forward hedges for the first quarter of 2023 that are included in the Alberta Hydro Asset revenues.

(4)Other revenue includes revenues from our transmission business and other contractual arrangements, including the flood mitigation agreement with the Government of Alberta and Black Start services.

(5)For details of the adjustments to revenues included in adjusted EBITDA refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.

(6)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.

Revenues for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to:

•Lower realized power and ancillary prices in the Alberta market; and

•Lower realized gains on forward contracts compared to the prior period when the Company captured revenue through forward hedging for the Alberta Hydro Assets and realized gains from the hedging strategy in the first quarter of 2023; partially offset by

•Higher production due to significant demand in periods of extreme cold temperature conditions in Alberta; and

•Higher sales of environmental attributes to third parties.

Adjusted EBITDA for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to lower revenues as explained by the factors above.

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

M14 TransAlta Corporation

Wind and Solar

3 months ended March 31	2024	2023	Change
Gross installed capacity (MW)(1)	2,184	1,906	278	15	%
LTA generation (GWh)	1,644	1,423	221	16	%
Availability (%)	93.4	82.9	10.5	13	%
Production
Contract production (GWh)	1,154	871	283	32	%
Merchant production (GWh)	344	326	18	6	%
Total production (GWh)	1,498	1,197	301	25	%
Wind and Solar revenues	102	102	—	—	%
Environmental attribute revenues	18	13	5	38	%
Revenues(2)	120	115	5	4	%
Fuel and purchased power	9	9	—	—	%
Gross margin(3)	111	106	5	5	%
OM&A	20	17	3	18	%
Taxes, other than income taxes	4	3	1	33	%
Net other operating income	(2)	(2)	—	—	%
Adjusted EBITDA(3)	89	88	1	1	%

(1)Gross installed capacity and availability for 2024 includes the 130 MW Garden Plain wind facility that achieved commercial operation in August 2023, the 48 MW Northern Goldfields solar facilities that achieved commercial operation in November 2023 and the 100 MW White Rock West wind facility that achieved commercial operation in January 2024.

(2)For details of the adjustments to revenues included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(3)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.

Revenues for the three months ended March 31, 2024, increased compared with the same period in 2023 primarily due to:

•Higher environmental attribute revenues;

•Higher production from the return to service of the Kent Hills wind facilities;

•Commercial operation of the Garden Plain and White Rock West wind facilities and the Northern Goldfields solar facilities; offset by

•Lower realized power prices in Alberta; and

•Weaker wind resource across the Alberta operating fleet.

Adjusted EBITDA for the three months ended March 31, 2024, increased compared with the same period in 2023, primarily due to:

•Higher revenues as explained by the factors above; partially offset by

•Higher OM&A related to the addition of the Garden Plain and White Rock West wind facilities and the Northern Goldfields solar facilities, salary escalations, higher insurance costs and long-term service agreement escalations.

TransAlta Corporation M15

Gas

3 months ended March 31	2024	2023	Change
Gross installed capacity (MW)	3,087	3,084	3	—	%
Availability (%)	94.6	96.4	(1.8)	(2)	%
Production
Contract sales volume (GWh)	1,504	1,003	501	50	%
Merchant sales volume (GWh)	2,045	2,249	(204)	(9)	%
Purchased power (GWh)(1)	(21)	(80)	59	(74)	%
Total production (GWh)	3,528	3,172	356	11	%
Revenues(2)	354	435	(81)	(19)	%
Fuel and purchased power(2)	141	129	12	9	%
Carbon compliance	40	32	8	25	%
Gross margin(3)	173	274	(101)	(37)	%
OM&A	46	41	5	12	%
Taxes, other than income taxes	3	4	(1)	(25)	%
Net other operating income	(10)	(11)	1	(9)	%
Adjusted EBITDA(3)	134	240	(106)	(44)	%

(1)Power required to fulfill contractual obligations during planned and unplanned outages is included in purchased power.

(2)For details of the adjustments to revenues and fuel and purchased power included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(3)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Revenues for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to:

•Lower realized power and ancillary services prices from the Alberta merchant fleet driven by lower spot prices and the impact of lower-priced hedge contracts; and

•Lower capacity payments in 2024 for Southern Cross Energy in Australia due to the scheduled conclusion on Dec. 31, 2023 of the demand capacity charge under the customer contract, partially offset by the commencement in March 2024 of capacity payments for the Mount Keith 132kV expansion.

Adjusted EBITDA for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to:

•Lower revenues explained above;

•Higher fuel and purchased power from higher production;

•An increase in the carbon price from $65 per tonne to $80 per tonne, impacting gross margin from our Canadian gas assets; and

•Higher OM&A expenses mainly due to increased salary escalations; partially offset by

•Lower natural gas commodity costs at the Alberta gas assets.

M16 TransAlta Corporation

Energy Transition

3 months ended March 31	2024	2023	Change
Gross installed capacity (MW)	671	671	—	—	%
Availability (%)	79.0	94.5	(15.5)	(16)	%
Adjusted availability (%)(1)	79.0	94.5	(15.5)	(16)	%
Production
Contract sales volume (GWh)	830	820	10	1	%
Merchant sales volume (GWh)	933	1,343	(410)	(31)	%
Purchased power (GWh)(2)	(962)	(866)	(96)	11	%
Total production (GWh)	801	1,297	(496)	(38)	%
Revenues(3)	210	253	(43)	(17)	%
Fuel and purchased power	166	181	(15)	(8)	%
Gross margin(4)	44	72	(28)	(39)	%
OM&A	18	17	1	6	%
Taxes, other than income taxes	—	1	(1)	(100)	%
Adjusted EBITDA(4)	26	54	(28)	(52)	%
Supplemental information:
Highvale mine reclamation spend	3	2	1	50	%
Centralia mine reclamation spend	3	3	—	—	%

(1)Adjusted for dispatch optimization.

(2)All of the power produced by Centralia is sold by the Energy Marketing segment for physical market delivery, which is shown as merchant sales volumes. Power required to fulfil contractual obligations is included in purchased power. Total production from the facility includes the net result of merchant sales volumes and purchased power.

(3)For details of the adjustments to revenues included in adjusted EBITDA refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(4)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Revenues for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to:

•Lower production due to higher unplanned outages at Centralia Unit 2; and

•Increased economic dispatch due to lower market prices.

Adjusted EBITDA for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to:

•Lower revenues as explained by the factors above; and

•Higher purchased power due to increased economic dispatch; partially offset by

•Lower fuel costs due to lower production volumes.

Mine reclamation spend for the three months ended March 31, 2024, was consistent compared with the same period in 2023.

TransAlta Corporation M17

Energy Marketing

3 months ended March 31	2024	2023	Change
Revenues(1)	30	53	(23)	(43)	%
OM&A	10	14	(4)	(29)	%
Adjusted EBITDA(2)	20	39	(19)	(49)	%

(1)For details of the adjustments to revenues included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A. Adjusted EBITDA is not defined and has no standardized meaning under IFRS.

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Adjusted EBITDA for the three months ended March 31, 2024, decreased compared with the same period in 2023. This was in line with management's expectations, but lower quarter over quarter, primarily due to:

•Lower realized settled trades in the first quarter of 2024 on market positions in comparison to the prior period; partially offset by

•Lower OM&A due to lower incentives.

The Company was able to capitalize on volatility in the trading of both physical and financial power and gas products across North American deregulated markets while maintaining the overall risk profile of the business unit.

Corporate

3 months ended March 31	2024	2023	Change
OM&A	28	24	4	17	%
Adjusted EBITDA(1)	(28)	(24)	(4)	17	%

(1)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Adjusted EBITDA for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to increased spending to support strategic and growth initiatives.

M18 TransAlta Corporation

Performance by Segment with Supplemental Geographical Information

The following table provides adjusted EBITDA performance of our facilities across the regions we operate in:

3 months ended March 31, 2024	Hydro	Wind & Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Alberta	87	24	84	(3)	20	(28)	184
Canada, excluding Alberta	—	40	24	—	—	—	64
US	—	23	3	29	—	—	55
Australia	—	2	23	—	—	—	25
Adjusted EBITDA(1)	87	89	134	26	20	(28)	328
Earnings before income taxes							267
3 months ended March 31, 2023	Hydro	Wind & Solar	Gas	Energy Transition	Energy Marketing	Corporate	Total
Alberta	106	31	178	(2)	39	(24)	328
Canada, excluding Alberta	—	30	25	—	—	—	55
US	—	27	2	56	—	—	85
Australia	—	—	35	—	—	—	35
Adjusted EBITDA(1)	106	88	240	54	39	(24)	503
Earnings before income taxes							383

(1)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Presenting this from period to period provides management and investors with the ability to evaluate earnings (loss) trends more readily in comparison with prior periods’ results. Refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. Also, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

Optimization of the Alberta Portfolio

Our merchant exposure is primarily in Alberta, where 52 per cent of our capacity is located and 75 per cent of our Alberta assets are available to participate in the merchant market. Our portfolio of merchant assets in Alberta consists of hydro facilities, wind facilities, a battery storage facility and natural gas generation facilities.

Generating capacity in Alberta is subject to market forces. Power from commercial generation is cleared through a wholesale electricity market. Power is dispatched in accordance with an economic merit order administered by the AESO, based upon offers by generators to sell power in the real-time energy-only market. Our merchant Alberta fleet operates under this framework and we internally manage our offers to sell power.

Optimization of portfolio performance in the Alberta merchant market is driven by the diversity of fuel types and enables portfolio management. It also provides us with capacity that can be monetized as ancillary services are

dispatched into the energy market during times of supply tightness. A significant portion of the thermal generation capacity in the portfolio has been hedged to provide greater cash flow certainty. The Company's hedging strategy includes maintaining a significant base of commercial and industrial customers and is supplemented with financial hedges.

In the three months ended March 31, 2024, 87 per cent of our energy production in Alberta was sold under long-term contracts or fixed-price hedges.

The Alberta hydro fleet provides ancillary services and grid reliability products such as Black Start service, in the event of a system-wide blackout in the province, and drought mitigation, by systematically regulating river flows. Our Alberta wind and hydro fleets provide a steady stream of environmental credits to meet ESG goals.

TransAlta Corporation M19

	2024										2023
3 months ended March 31	Hydro		Wind & Solar		Gas		Energy Transition		Total		Hydro		Wind & Solar		Gas		Energy Transition		Total
Gross installed capacity (MW)	834		766		1,963		—		3,563		834		636		1,960		—		3,430
Total production (GWh)	313		494		2,366		—		3,173		283		502		2,369		—		3,154
Contract production (GWh)	—		239		608		—		847		—		176		150		—		326
Merchant production (GWh)	313		255		1,758		—		2,326		283		326		2,219		—		2,828
Hedged production (GWh)	84		36		1,788		—		1,908		165		—		1,880		—		2,046
Production contracted or hedged (%)	27	%	56	%	101	%	—	%	87	%	—	%	35	%	86	%	—	%	70	%
Revenues(1) ($)	103		38		244		1		386		121		44		325		2		492
Fuel and purchased power ($)	5		4		110		—		119		4		7		103		—		114
Carbon compliance ($)	—		—		36		—		36		—		—		29		—		29
Gross margin ($)	98		34		98		1		231		117		37		193		2		349

(1)Revenues have been adjusted to exclude the impact of unrealized mark-to-market gains or losses and to include realized gains and losses on closed exchange positions.

Total production for the three months ended March 31, 2024, was 3,173 GWh compared to 3,154 GWh of electricity in the same period in 2023. The increase of 19 GWh, or 1 per cent, was primarily due to:

•Stronger production from the Alberta Hydro assets in response to high demand in periods of extreme cold conditions in the quarter; and

•The addition of the Garden Plain wind facility which was commissioned in August 2023; partially offset by

•Lower wind resource.

Hedged production volumes for the three months ended March 31, 2024 decreased compared to the same period in 2023, primarily from fewer strategic hedges executed for the first quarter of 2024.

Gross margin for the three months ended March 31, 2024, was $231 million compared to $349 million in the same period in 2023. The decrease of $118 million, or 34 per cent, was primarily due to:

•The impacts of lower Alberta realized spot prices and lower fixed-price hedges; partially offset by

•Higher environmental attribute revenues.

M20 TransAlta Corporation

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

3 months ended March 31	2024	2023
Alberta Market
Spot power price average per MWh	99	142
Natural gas price (AECO) per GJ	1.94	3.08
Carbon compliance price per tonne	80	65
Alberta Portfolio Results
Realized merchant power price per MWh(1)	119	156
Hydro energy spot power price per MWh	152	168
Hydro ancillary spot price per MWh	54	60
Wind energy spot power price per MWh	51	89
Gas spot power price per MWh	118	156
Hedged power price average per MWh	88	136
Hedged volume (GWh)	1,908	2,046
Fuel and purchased power per MWh(2)	50	48
Carbon compliance cost per MWh(2)	15	12

(1)Realized merchant power price for the Alberta electricity portfolio is the average price realized as a result of the Company's merchant power sales and portfolio optimization activities (excluding assets under long-term contract and ancillary revenues) divided by total merchant GWh produced.

(2)Fuel and purchased power per MWh and carbon compliance cost per MWh are calculated on production from carbon-emitting generation in the Gas and Energy Transition segments.

The average spot power price per MWh for the three months ended March 31, 2024 decreased from $142 per MWh in 2023 to $99 per MWh in 2024, primarily due to:

•Milder weather compared with the same period in 2023;

•Lower natural gas prices; and

•Higher generation from the additions of new wind and solar supply in the market compared to the prior period.

Realized merchant power price per MWh of production for the three months ended March 31, 2024, decreased by $37 per MWh, compared to the same period in 2023, primarily due to:

•Lower average spot power prices as explained above; and

•Lower hedge prices compared to the same period in 2023.

Fuel and purchased power cost per MWh for the three months ended March 31, 2024, increased by $2 per MWh, compared to the same period in 2023, primarily due to:

•Higher purchased power to fulfill contractual obligations; partially offset by

•Lower natural gas prices.

Carbon compliance cost per MWh of production for the three months ended March 31, 2024, increased by $3 per MWh, compared to the same period in 2023, primarily due to an increase in carbon pricing from $65 per tonne to $80 per tonne.

Selected Quarterly Information

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

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

TransAlta Corporation M21

	Q2 2023	Q3 2023	Q4 2023	Q1 2024
Revenues	625	1,017	624	947
Earnings (loss) before income taxes	79	453	(35)	267
Net earnings (loss) attributable to common shareholders	62	372	(84)	222
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1)	0.23	1.41	(0.27)	0.72
Cash flow from operating activities	11	681	310	244

	Q2 2022	Q3 2022	Q4 2022	Q1 2023
Revenues	458	929	854	1,089
Earnings (loss) before income taxes	(22)	126	7	383
Net earnings (loss) attributable to common shareholders	(80)	61	(163)	294
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1)	(0.30)	0.23	(0.61)	1.10
Cash flow from (used in) operating activities(2)	(129)	204	351	462

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

(2)The cash flow used in operating activities for the second quarter of 2022 was negative due to unfavourable changes in working capital mainly due to movements in our collateral accounts related to higher commodity prices and volatility in the markets.

Operating results have been impacted by the following events:

•Commissioning of the Garden Plain wind facility in the third quarter of 2023, the Northern Goldfields solar facilities in the fourth quarter of 2023 and the White Rock West wind facility in the first quarter of 2024; and

•The outage of the Kent Hills 1 and 2 wind facilities from the first quarter of 2022 through to the fourth quarter of 2023. The remediation project was completed in the first quarter of 2024.

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

•Higher production in the first, second, and third quarters of 2023 and in the first quarter of 2024; and

•Lower realized pricing in the third and fourth quarters of 2023 and the first quarter of 2024 compared to the same periods in the prior years, due to lower volumes of power imported from adjacent markets and higher power prices during periods of overlapping outages and lower renewable operations.

Earnings (loss) before income taxes has been impacted by the following:

•The items described above;

•Lower natural gas commodity pricing in the last four quarters compared to the same periods in the prior year;

•Higher costs of carbon per tonne. In 2022, cost of carbon was $50 per tonne and increased to $65 per tonne in 2023 and to $80 per tonne in 2024;

•In the second quarter of 2022, lower carbon costs as the Company utilized emission credits to settle a portion of our greenhouse gas ("GHG") obligation;

•OM&A costs in the second quarter of 2023 and the first quarter of 2024 were higher than the same periods in the prior years due to higher spending on strategic and growth initiatives;

•Depreciation in the last three quarters decreased compared to the same periods in the prior year due to revisions in useful lives on certain facilities that occurred in the third quarter of 2023;

•The effect of changes in decommissioning provisions for retired assets from an increase in discount rates in the second and third quarters of 2022;

•The effects of changes in decommissioning provisions for retired assets due to changes in estimated cash flows and changes in useful lives, recognized in the third quarter of 2022 and 2023;

•Insurance proceeds for the single tower failure at Kent Hills wind facilities of $7 million recognized in the second quarter of 2022;

•Liquidated damages recoverable from turbine availability being below the contractual target at the Windrise wind facility recorded in all quarters, with higher amounts recognized in the second quarter of 2022 and the first quarter of 2023; and

•Gains relating to the sale of assets being recognized in the fourth quarter of 2022.

Net earnings (loss) attributable to common shareholders has been impacted by fluctuations in current and deferred tax expense with earnings before tax across the quarters.

M22 TransAlta Corporation

Strategy and Capability to Deliver Results

Our strategic focus is to invest in clean electricity solutions that meet the needs and objectives of our customers and communities. We invest in a disciplined and prudent manner to deliver appropriate risk-adjusted returns to our shareholders. To support this strategy, we maintain a growing pipeline of project opportunities focused on hydro, wind, solar, energy storage and gas. 

On Nov. 21, 2023, the Company updated its five-year strategic growth targets and Clean Electricity Growth Plan. The Company established six strategic priorities to focus our path from 2024 to 2028. Refer to the Strategy and Capacity to Deliver Results and Strategic Priorities and Clean Electricity Growth Plan to 2028 sections of the Annual MD&A for further details.

Impact of Alberta Government Electricity Announcements on Renewable Projects

On Feb. 28, 2024, the Government of Alberta (“GoA”) announced new restrictions and requirements that it will impose on new renewable projects and power plant regulatory approval processes. This includes prohibiting wind generation development within 35 kilometres of a protected area or other areas designated as a "pristine viewscape" by the GoA, restricting renewable development on class 1 and 2 agricultural lands, imposing new mandatory requirements to post bonds and/or provide financial security to meet reclamation obligations, and granting municipalities standing in Alberta Utilities Commission ("AUC") power plant regulatory proceedings.

The Riplinger wind project was impacted by the new restriction, specifically the restrictions on development near protected areas and pristine viewscapes, and will not be advanced. The project has been removed from our early-stage development projects.

On March 11, 2024, the GoA announced a wholesale electricity market redesign and associated interim regulations. This announcement followed a review process that kicked off in mid-2023 and was based on the GoA’s acceptance of recommendations made to the Minister of Affordability and Utilities by the AESO and the Market Surveillance Administrator to pursue detailed design work on a "Restructured Energy Market". While these changes have had an immediate impact on market stability, TransAlta believes the near-term impacts on the Company’s existing assets will be muted given current market conditions, while new growth projects will be paused until the new market structure is defined. The Company will remain actively involved in the design process through consultation efforts with the GoA and associated agencies.

The interim regulations filed by the GoA prescribe specific changes that the AESO and AUC must implement by July 1, 2024:

•The Market Power Mitigation Regulation imposes an offer cap on the gas-fired generating units controlled by a market participant who has offer control of at least 5 per cent of total installed capacity. The offer cap would only restrict our offering price, not our settlement price, and would be based on the greater of $125 per MWh or 25 times the day-ahead natural gas price and is triggered when a hypothetical high efficiency natural gas fired combined cycle generator has earned 2-months’ worth of net revenues. This calculation is based upon a monthly cumulative settlement calculation that is set out in the regulation and is applied for the remainder of the calendar month in which the offer cap is triggered.

•The Supply Cushion Regulation requires the AESO to forecast and direct generation, that takes one hour or more to synchronize to the grid, into service when the supply cushion is expected to be equal to or less than 932 MW. Long-lead time generation will receive a cost guarantee that covers incremental start-up and variable costs if the pool price revenues are not sufficient to compensate.

The AESO currently projects that the Restructured Energy Market design will be finalized by the end of 2025 with implementation in 2026. The proposed changes include, but are not limited to: (i) the introduction of a day-ahead market and administrative scarcity pricing mechanism (to replace economic withholding; (ii) the allowance of negative pricing alongside a higher price cap; and (iii) the reduction of settlement windows (from one hour to fifteen or five minutes). The proposal also intends to implement additional market power mitigation, centralize dispatch and incentivize new generation to locate near existing infrastructure with sufficient capacity.

As a result of these announcements and surrounding uncertainty, the Company has paused the development of three advanced-stage greenfield projects in Alberta – WaterCharger, Tempest and Pinnacle. These projects will be reconsidered once the GoA provides sufficient clarity regarding future market structure, due to the market exposure of each project.

The Company has a robust pipeline of approximately 5 GW distributed among Canada, the United States and Australia, and will continue to allocate development capital to markets which bring geographic diversity, stability and strong returns.

TransAlta Corporation M23

Capital Allocation Decisions

In February 2024, the Company announced an enhanced common share repurchase program for 2024 of up to $150 million towards the repurchase of common shares.

During the three months ended March 31, 2024, the Company purchased and cancelled a total of 3,460,300 common shares, at an average price of $9.36 per common share, for a total cost of $32 million.

Advanced-Stage Development

These projects have detailed engineering, advanced positions in the interconnection queue and/or are progressing offtake opportunities. Projects in advanced-stage development are progressing towards final investment decision and do not have final approval from the Board of Directors at time of reporting.

The following table shows the pipeline of future growth projects currently under advanced-stage development:

Project	Type	Region	Target investment date	MW	Estimated spend	Average annual EBITDA(1)
Tempest	Wind	Alberta	On hold	100	On hold	On hold
SCE Capacity Expansion	Gas	Western Australia	2024	94	AU$210-AU$230	AU$28-AU$32
WaterCharger	Battery Storage	Alberta	On hold	180	On hold	On hold
Pinnacle 1 & 2	Gas	Alberta	On hold	44	On hold	On hold
Total(2)				418	$191 - $209	$25 - $29

(1)This item is not defined, has no standardized meaning under IFRS and is forward-looking. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

(2)Total expected spending and average annual EBITDA was converted using a Canadian dollar forward exchange rate for 2024.

Early-Stage Development

These projects are in the early stages and may or may not move ahead. Generally, these projects will have:

•Collected meteorological data;

•Begun securing land control;

•Started environmental studies;

•Confirmed appropriate access to transmission; and

•Started preliminary permitting and other regulatory approval processes.

M24 TransAlta Corporation

The following table shows the pipeline of future growth projects currently under early-stage development:

Project	Type	Region	Potential investment date(1)	MW
Canada
New Brunswick Battery	Battery	New Brunswick	2025	10
Sunhills Solar	Solar	Alberta	2026	170
McNeil Solar	Solar	Alberta	2026	57
Tent Mountain Pumped Storage(2)	Hydro	Alberta	2026	160
Provost	Wind	Alberta	2026	170
Red Rock	Wind	Alberta	2027	100
Willow Creek 1	Wind	Alberta	2027	70
Willow Creek 2	Wind	Alberta	2027	70
Antelope Coulee	Wind	Saskatchewan	2027+	200
Other Canadian Opportunities	Wind	Various	2026+	190
Brazeau Pumped Hydro	Hydro	Alberta	TBD	300-900
Alberta Thermal Redevelopment(3)	Various	Alberta	TBD	250-500
		Total		1,747 - 2,597
United States
Monument Road	Wind	Nebraska	2025	152
Swan Creek	Wind	Nebraska	2025	126
Dos Rios	Wind	Oklahoma	2025	242
Cotton Belle 1	Solar	Texas	2026	104
Cotton Belle 2	Solar	Texas	2026	81
Square Top	Solar	Oklahoma	2026	195
Old Town	Wind	Illinois	2026	185
Canadian River	Wind	Oklahoma	2026	250
Prairie Violet	Wind	Illinois	2026	130
Quick Draw	Wind	Texas	2026	174
Big Timber	Wind	Pennsylvania	2026	50
Trapper Valley	Wind	Wyoming	2027	225
Wild Waters	Wind	Minnesota	2027+	40
Other US Opportunities	Wind	Various	2026+	144
Centralia Site Redevelopment(3)	Various	Washington	TBD	250-500
		Total		2,348 - 2,598
Australia
Boodarie Solar	Solar	Western Australia	2024	50
Southern Cross Energy	Wind and Solar	Western Australia	TBD	120
Other Australian Opportunities	Gas, Solar, Transmission	Western Australia	2024+	230
		Total		400
Canada, United States and Australia		Total		4,495 - 5,595

(1)Potential investment date is to be determined ("TBD").

(2)This represents the Company's 50 per cent interest in Tent Mountain Renewable Energy Complex.

(3)The Company is currently evaluating redevelopment opportunities at these brownfield sites.

TransAlta Corporation M25

Projects under Construction

The following projects have been approved by the Board of Directors, have executed power purchase agreements ("PPAs") and are currently under construction or in the process of being commissioned. The projects under construction will be financed through existing liquidity in the near term. We will continue to explore permanent financing solutions on an asset-by-asset basis.

We are continually monitoring the timing and costs on our projects under construction. Our US projects have

experienced schedule delays and increased costs attributable to complexities relating to transmission interconnections and wind turbine erection. The White Rock East wind facility achieved commercial operation on April 22, 2024, and has therefore been removed from the table below. The 200 MW Horizon Hill wind project transmission lines are fully energized and is expected to achieve commercial operation in the second quarter of 2024.

				Total project (millions)
Project	Type	Region	MW	Estimated spend			Spent to date	Target completion date	PPA Term(1)	Average annual EBITDA(2)	Status
United States
Horizon Hill	Wind	OK	200	US$330	—	US$340	US$307	Q2 2024	—	US$31-US$33	•Long-term PPA executed •Installation/assembly complete •Final stages of commissioning underway
Australia
Mount Keith West Network Upgrade	Transmission	WA	n/a	AU$37	—	AU$40	AU$13	Q2 2025	14	AU$6 - AU$7	•Major equipment orders placed •Detailed design and execution planning underway •On track to be completed on schedule
Total(3)			200	$502	—	$519	$423			$47 - $50

(1)The PPA term is confidential for the Horizon Hill wind project.

(2)This item is not defined and has no standardized meaning under IFRS and is forward-looking. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.

(3)Total expected spending and average annual EBITDA were converted using a Canadian dollar forward exchange rate for 2024. Spend to date was converted using the period-end closing rate.

M26 TransAlta Corporation

Financial Position

The following table highlights significant changes in the unaudited interim condensed consolidated statements of financial position from Dec. 31, 2023, to March 31, 2024:

	March 31, 2024	Dec. 31, 2023	Increase/(decrease)
Assets
Current assets
Cash and cash equivalents	419	348	71
Trade and other receivables	690	807	(117)
Risk management assets	240	151	89
Other current assets(1)	260	274	(14)
Total current assets	1,609	1,580	29
Non-current assets
Risk management assets	135	52	83
Property, plant and equipment, net	5,659	5,714	(55)
Long-term portion of finance lease receivable	211	171	40
Other non-current assets(2)	1,138	1,142	(4)
Total non-current assets	7,143	7,079	64
Total assets	8,752	8,659	93
Liabilities
Current liabilities
Accounts payable and accrued liabilities	674	797	(123)
Exchangeable securities	745	—	745
Other current liabilities(3)	914	945	(31)
Total current liabilities	2,333	1,742	591
Non-current liabilities
Exchangeable securities	—	744	(744)
Other non-current liabilities(4)	4,487	4,509	(22)
Total non-current liabilities	4,487	5,253	(766)
Total liabilities	6,820	6,995	(175)
Equity
Equity attributable to shareholders	1,808	1,537	271
Non-controlling interests	124	127	(3)
Total equity	1,932	1,664	268
Total liabilities and equity	8,752	8,659	93

(1)Includes restricted cash, prepaid expenses and other, and inventory.

(2)Includes investments, right-of-use assets, intangible assets, goodwill, deferred income tax assets and other assets.

(3)Includes bank overdraft, current portion of decommissioning and other provisions, current portion of risk management liabilities, current portion of contract liabilities, income taxes payable, dividends payable and current portion of long-term debt and lease liabilities.

(4)Includes credit facilities, long-term debt and lease liabilities, long-term decommissioning and other provisions, deferred income tax liabilities, long-term portion of risk management liabilities, contract liabilities and defined benefit obligation and other long-term liabilities.

TransAlta Corporation M27

Significant changes in TransAlta's condensed consolidated statements of financial position were as follows:

Working Capital

The deficit of current assets over current liabilities, including the current portion of long-term debt and lease liabilities, was $724 million as at March 31, 2024 (Dec. 31, 2023 – excess of current assets over current liabilities of $162 million), primarily as a result of the exchangeable securities being reclassified from long-term to current liabilities in the period as the conversion option can be exercised at any time after Jan. 1, 2025 at Brookfield's option, although there is no obligation to deliver cash equivalent resources and the holder cannot call for repayment.

Current assets increased by $29 million to $1,609 million as at March 31, 2024, from $1,580 million as at Dec. 31, 2023, primarily due to:

•Higher risk management assets mainly due to volatility in market prices;

•Higher collateral provided by the Energy Marketing segment due to trading activity and volatility in market prices;

•Higher cash and cash equivalents; partially offset by

•Lower trade receivables from lower revenues recognized in the first quarter of 2024.

Current liabilities increased by $591 million from $1,742 million as at Dec. 31, 2023, to $2,333 million as at March 31, 2024, mainly due to:

•The exchangeable securities classified as current as the conversion option can be exercised at any time after Jan. 1, 2025 at Brookfield's option, although there is no obligation to deliver cash equivalent resources and the holder cannot call for repayment. Refer to the Accounting Changes section of this MD&A for more details; and

•Higher collateral received by the Energy Marketing segment due to trading activity and volatility in market prices; partially offset by

•Lower accounts payable and accrued liabilities.

Non-Current Assets

Non-current assets as at March 31, 2024, were $7,143 million, an increase of $64 million from $7,079 million as at Dec. 31, 2023, primarily due to:

•Higher risk management assets due to volatility in market pricing across multiple markets; and

•Higher net investment in finance leases related to the Northern Goldfields solar facilities; partially offset by

•Lower property, plant and equipment ("PP&E") resulting from depreciation of $124 million and lower capital additions of $216 million.

Non-Current Liabilities

Non-current liabilities as at March 31, 2024, were $4,487 million, a decrease of $766 million from $5,253 million as at Dec. 31, 2023, mainly due to the exchangeable securities being classified to current liabilities.

Total Equity

As at March 31, 2024, the increase in total equity of $268 million was due to:

•Net earnings of $238 million; and

•Net gains on derivatives from cash flow hedges of $84 million; partially offset by

•Share repurchases under the NCIB of $32 million; and

•Distributions to non-controlling interests of $19 million.

M28 TransAlta Corporation

Financial Capital

The Company is focused on maintaining a strong balance sheet and financial position to ensure access to sufficient financial capital.

Capital Structure

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

	March 31, 2024		Dec. 31, 2023
	$	%	$	%
Net senior unsecured debt
Recourse debt - CAD debentures	251	4	251	5
Recourse debt - US senior notes	938	16	911	17
Credit facilities	397	7	397	7
Less: cash and cash equivalents(1)	(417)	(7)	(345)	(6)
Less: other cash and liquid assets(2)	—	—	(12)	—
Net senior unsecured debt	1,169	20	1,202	23
Other debt liabilities
Exchangeable debentures	345	6	344	6
Non-recourse debt
TAPC Holdings LP bond	83	1	85	1
Pingston bond	39	1	39	1
Melancthon Wolfe Wind bond	168	3	168	3
New Richmond Wind bond	103	2	103	2
Kent Hills Wind bond	190	3	193	3
Windrise Wind bond	161	3	164	3
South Hedland non-recourse debt	673	12	691	13
OCP Bond	205	4	217	4
US tax equity financing	103	2	104	1
Lease liabilities	145	3	143	3
Total consolidated net debt(3)(4)(5)	3,384	60	3,453	63
Exchangeable preferred securities(5)	400	7	400	7
Equity attributable to shareholders
Common shares	3,258	57	3,285	60
Preferred shares	942	16	942	17
Contributed surplus, deficit and accumulated other comprehensive loss	(2,392)	(42)	(2,690)	(49)
Non-controlling interests	124	2	127	2
Total capital	5,716	100	5,517	100

(1)Cash and cash equivalents is net of bank overdraft.

(2)Includes principal portion of the TransAlta OCP LP restricted cash related to the TransAlta OCP LP bonds as this cash is restricted specifically to repay outstanding debt and also includes the fair value of economic and designated hedging instruments on debt, as the carrying value of the related debt is impacted by changes in foreign exchange rates.

(3)These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion, including reconciliations to measures calculated in accordance with IFRS.

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

(5)The total consolidated net debt excludes the exchangeable preferred securities as they are considered equity with dividend payments for credit purposes.

TransAlta Corporation M29

Between 2024 and 2026, we have $779 million of debt maturing, including $400 million of recourse debt relating to the Term Facility, with the balance mainly related to scheduled non-recourse debt repayments. The $750 million of exchangeable securities can be exchanged at the earliest on Jan. 1, 2025.

Credit Facilities

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

As at March 31, 2024		Utilized		Available capacity	Maturity date
Credit facilities	Facility size	Outstanding letters of credit(1)	Cash drawings
Committed
TransAlta syndicated credit facility	1,950	492	—	1,458	Q2 2027
TransAlta bilateral credit facilities	240	181	—	59	Q2 2025
TransAlta Term Facility	400	—	400	—	Q3 2024
Total committed	2,590	673	400	1,517
Non-committed
TransAlta demand facilities	400	201	—	199	N/A
Total non-committed	400	201	—	199

(1)TransAlta has obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase obligations. Letters of credit drawn against the non-committed facilities reduce available capacity under the committed syndicated credit facilities.

Non-Recourse Debt and Other

The Melancthon Wolfe Wind LP, TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd. and Windrise Wind LP non-recourse bonds, and TransAlta OCP LP bonds, are subject to customary financing conditions and covenants that may restrict the Company’s ability to access funds generated by the facilities’ operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the first quarter of 2024, with the exception of Kent Hills Wind LP. Kent Hills Wind LP cannot make any distributions to its partners until the independent engineer's report has been finalized and the the debt service coverage ratio is met. The funds in the entities that have accumulated since the first quarter test will remain there until the next debt service coverage test can be performed in the second quarter of 2024. At March 31, 2024, $88 million (Dec. 31, 2023 – $79 million) of cash was subject to these financial restrictions.

At March 31, 2024, $4 million (AU$4 million) of funds held by TEC Hedland Pty Ltd are not able to be accessed by other corporate entities as the funds must be solely used by the project entities for the purpose of paying major maintenance costs.

Additionally, certain non-recourse bonds require that reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit.

M30 TransAlta Corporation

Returns to Providers of Capital

Interest Income and Interest Expense

Interest income and the components of interest expense are shown below:

3 months ended March 31	2024	2023
Interest income	7	15
Interest on debt	49	50
Interest on exchangeable debentures	7	7
Interest on exchangeable preferred shares	7	7
Capitalized interest	(14)	(13)
Interest on lease liabilities	2	2
Credit facility fees, bank charges and other interest	6	8
Tax shield on tax equity financing	—	(1)
Accretion of provisions	12	14
Interest expense	69	74

Interest income was lower due to lower cash balances. Interest expense was lower when compared to the same period in 2023, primarily due to lower outstanding letters of credit resulting in lower fees, and lower accretion of provisions.

Share Capital

The following tables outline the common and preferred shares issued and outstanding:

	Number of shares (millions)
As at	May 2, 2024	March 31, 2024	Dec. 31, 2023(1)
Common shares issued and outstanding, end of period	304.1	306.5	308.6
Preferred shares
Series A	9.6	9.6	9.6
Series B	2.4	2.4	2.4
Series C	10.0	10.0	10.0
Series D	1.0	1.0	1.0
Series E	9.0	9.0	9.0
Series G	6.6	6.6	6.6
Preferred shares issued and outstanding in equity	38.6	38.6	38.6
Series I - Exchangeable Securities(2)	0.4	0.4	0.4
Preferred shares issued and outstanding	39.0	39.0	39.0

(1)Common shares issued and outstanding as at Dec. 31, 2023, excludes the provision for repurchase of 1.7 million common shares under the ASPP.

(2)Brookfield invested $400 million in consideration for redeemable, retractable, first preferred shares. For accounting purposes, these preferred shares are considered debt and disclosed as such in the unaudited interim condensed consolidated financial statements.

TransAlta Corporation M31

Non-Controlling Interests

On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. At March 31, 2024, TransAlta Renewables is a wholly-owned subsidiary and has no remaining non-controlling interest.

As at March 31, 2024, the Company owned 50.01 per cent of TA Cogen (March 31, 2023 – 50.01 per cent), which owns, operates or has an interest in three natural-gas-fired cogeneration facilities (Ottawa, Windsor and Fort Saskatchewan) and a natural-gas-fired facility (Sheerness). As at March 31, 2024, the Company owned 83 per cent of Kent Hills Wind LP (prior to Oct. 5, 2023 financial information related to the 17 per cent non-controlling

interest in Kent Hills Wind LP was included in the disclosures for TransAlta Renewables), which owns and operates three wind facilities.

Since we own a controlling interest in TA Cogen and Kent Hills Wind LP, we consolidated the entire earnings, assets and liabilities in relation to the subsidiaries.

The reported net earnings attributable to non-controlling interests for the three months ended March 31, 2024, decreased by $24 million, compared to 2023, primarily as a result of lower TA Cogen net earnings attributable to non-controlling interests resulting from lower production and lower merchant pricing in the Alberta market and no net earnings attributable to non-controlling interests in TransAlta Renewables in 2024.

Cash Flows

Cash and cash equivalents for the three months ended March 31, 2024, has decreased by $828 million, compared to the same period in 2023. On Oct. 5, 2023, the Company paid total consideration of $1.3 billion, comprising of $800

million cash and 46 million common shares valued at $514 million, for the acquisition of TransAlta Renewables as discussed above.

The following table highlights additional significant changes in the unaudited interim condensed consolidated statements of cash flows for the three months ended March 31, 2024 and March 31, 2023:

3 months ended March 31	2024	2023	Increase/ (decrease)
Cash and cash equivalents, beginning of period	348	1,134	(786)
Provided by (used in):
Operating activities	244	462	(218)
Investing activities	(58)	(182)	124
Financing activities	(114)	(165)	51
Translation of foreign currency cash	(1)	(2)	1
Cash and cash equivalents, end of period	419	1,247	(828)

M32 TransAlta Corporation

Cash Flow from Operating Activities

Cash from operating activities for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to the following:

	3 months ended March 31
Cash flow from operating activities for the three months ended March 31, 2023	462
Lower gross margin: Lower revenues net of unrealized gains from risk management activities and higher carbon compliance costs.	(209)
Lower current income tax expense due to decrease in earnings before tax.	33
Unfavourable change in non-cash operating working capital balances: Lower accounts payables and accrued liabilities and higher collateral provided as a result of market price volatility, partially offset by lower accounts receivable from lower revenues and higher collateral received related to derivative instruments.	(35)
Other	(7)
Cash flow from operating activities for the three months ended March 31, 2024	244

Cash Flow used in Investing Activities

Cash used in investing activities for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to the following:

	3 months ended March 31
Cash flow used in investing activities for the three months ended March 31, 2023	(182)
Lower additions to PP&E: Additions in 2023 were mainly for the construction of the Garden Plain wind facility which achieved commercial operation in August 2023, the Northern Goldfields solar facilities which achieved commercial operation in November 2023, and the construction of the White Rock and Horizon Hill wind projects. In 2024, the White Rock and Horizon Hill wind projects were nearing completion resulting in lower additions.	216
Lower proceeds on sale of PP&E: In 2023, the Company closed the sale of equipment related to its Sundance Unit 5 energy transition assets.	(22)
Unfavourable change in non-cash investing working capital balances: Lower capital accruals.	(70)
Cash flow used in investing activities for the three months ended March 31, 2024	(58)

Cash Flow used in Financing Activities

Cash used in financing activities for the three months ended March 31, 2024, decreased compared with the same period in 2023, primarily due to the following:

	3 months ended March 31
Cash flow used in financing activities for the three months ended March 31, 2023	(165)
Lower distributions paid to non-controlling interests: Timing of distributions by TA Cogen and no distributions to non-controlling interests by TransAlta Renewables Inc. in 2024.	57
Other	(6)
Cash flow used in financing activities for the three months ended March 31, 2024	(114)

TransAlta Corporation M33

Other Consolidated Analysis

Commitments

The Company has not incurred any additional contractual commitments in the three months ended March 31, 2024, either directly or through its interests in joint operations and joint ventures. Refer to the commitments disclosed elsewhere in the unaudited interim condensed consolidated financial statements and those disclosed in the 2023 annual audited financial statements.

Natural Gas Transportation Contracts 

The Company has natural gas transportation contracts, which include 15-year natural gas transportation agreements for a total of up to 400 terajoules ("TJ") per day on a firm basis, related to the Sundance and Keephills facilities, ending in 2036 to 2038. The Company is currently utilizing 200 TJ per day on average, and up to 350 TJ per day during peak demand periods, and also

remarkets a portion of the excess capacity. In addition, there is an eight-year natural gas transportation agreements for 75 TJ per day on a firm basis, related to the Sheerness facility, ending in 2030 to 2031.

The Company may be required to recognize the natural gas transportation agreements as onerous contracts if any of the related facilities are retired in advance of the maturity of the transportation contracts.

Contingencies

For the current material outstanding contingencies, please refer to Note 36 of the 2023 audited annual consolidated financial statements. There were no material changes to the contingencies in the three months ended March 31, 2024.

Financial Instruments

Refer to Note 14 of the notes to the audited annual 2023 consolidated financial statements and Note 9 and 10 of our unaudited interim condensed consolidated financial statements as at and for the three months ended March 31, 2024, for details on Financial instruments.

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 March 31, 2024, Level III instruments had a net liability carrying value of $80 million (Dec. 31, 2023 – net liability $147 million). Our risk management profile and practices have not changed materially from Dec. 31, 2023.

M34 TransAlta Corporation

Additional IFRS Measures and Non-IFRS Measures

An additional IFRS measure is a line item, heading or subtotal that is relevant to an understanding of the unaudited interim condensed consolidated financial statements but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an understanding of the unaudited interim condensed consolidated financial statements but is not presented elsewhere in the unaudited interim condensed consolidated financial statements. We have included line items entitled gross margin and operating income (loss) in our unaudited interim condensed consolidated statements of earnings (loss) for the three months ended March 31, 2024 and 2023. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.

We use a number of financial measures to evaluate our performance and the performance of our business segments, including measures and ratios that are presented on a non-IFRS basis, as described below. Unless otherwise indicated, all amounts are in Canadian dollars and have been derived from our unaudited interim 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.

Non-IFRS Financial Measures

Adjusted EBITDA, FFO, FCF, total net debt, total consolidated net debt and adjusted net debt are non-IFRS measures that are presented in this MD&A. Refer to the Segmented Financial Performance and Operating Results, Selected Quarterly Information, Financial Capital and Key Non-IFRS Financial Ratios sections of this MD&A for additional information, including a reconciliation of such non-IFRS measures to the most comparable IFRS measure.

Adjusted EBITDA

Each business segment assumes responsibility for its operating results measured by adjusted EBITDA. Adjusted EBITDA is an important metric for management that represents our core operational results. Interest, taxes, depreciation and amortization are not included, as differences in accounting treatments may distort our core business results. In addition, certain reclassifications and adjustments are made to better assess results, excluding those items that may not be reflective of ongoing business performance. This presentation may facilitate the readers' analysis of trends.

The following are descriptions of the adjustments made.

Adjustments to Revenue

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

•Adjusted EBITDA is adjusted to exclude the impact of unrealized mark-to-market gains or losses and unrealized foreign exchange gains or losses on commodity transactions.

•Adjustments are made for gains and losses related to closed positions effectively settled by offsetting positions with exchanges that have been recorded in the period the positions are settled.

Adjustments to Fuel and Purchased Power

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

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

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

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

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Adjustments for Equity-Accounted Investments

•During the fourth quarter of 2020, we acquired a 49 per cent interest in the Skookumchuck wind facility, which is treated as an equity investment under IFRS and our proportionate share of the net earnings is reflected as equity income on the statement of earnings under IFRS. As this investment is part of our regular power-generating operations, we have included our proportionate share of the adjusted EBITDA of 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 EMG International, LLC’s adjusted EBITDA in our total adjusted EBITDA as it does not represent our regular power-generating operations.

Average Annual EBITDA

Average annual EBITDA is a forward-looking non-IFRS financial measure that is used to show the average annual EBITDA that the project currently under construction is expected to generate upon completion.

Funds From Operations ("FFO")

FFO is an important metric as it provides a proxy for cash generated from operating activities before changes in working capital and provides the ability to evaluate cash flow trends in comparison with results from prior periods. FFO is a non-IFRS measure.

Adjustments to Cash Flow from Operations

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

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

•Cash received/paid on closed positions are reflected in the period that the position is settled.

•Other adjustments include payments/receipts for production tax credits associated with tax equity financing, which are reductions to tax equity debt and include distributions from equity-accounted joint ventures.

Free Cash Flow ("FCF")

FCF is an important metric as it represents the amount of cash that is available to invest in growth initiatives, make scheduled principal repayments on debt, repay maturing debt, pay common share dividends or repurchase common shares. Changes in working capital are excluded so FFO and FCF are not distorted by changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and timing of receipts and payments. FCF is a non-IFRS measure.

Non-IFRS Ratios

FFO per share, FCF per share and adjusted net debt to adjusted EBITDA are non-IFRS ratios that are presented in the MD&A. Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF and Key Non-IFRS Financial Ratios sections of this MD&A for additional information.

FFO per Share and FCF per Share

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

Supplementary Financial Measures

The Alberta electricity portfolio metrics disclosed are supplementary financial measures used to present the gross margin by segment for the Alberta market. Refer to the Alberta Electricity Portfolio section of this MD&A for additional information.

M36 TransAlta Corporation

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

The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the three months ended March 31, 2024:

	Hydro	Wind & Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	112	139	433	217	52	—	953	(6)	—	947
Reclassifications and adjustments:
Unrealized mark-to-market gain	(5)	(21)	(91)	(6)	(3)	—	(126)	—	126	—
Realized gain (loss) on closed exchange positions	—	—	8	(1)	(19)	—	(12)	—	12	—
Decrease in finance lease receivable	—	1	4	—	—	—	5	—	(5)	—
Finance lease income	—	1	1	—	—	—	2	—	(2)	—
Unrealized foreign exchange gain on commodity	—	—	(1)	—	—	—	(1)	—	1	—
Adjusted revenues	107	120	354	210	30	—	821	(6)	132	947
Fuel and purchased power	6	9	142	166	—	—	323	—	—	323
Reclassifications and adjustments:
Australian interest income	—	—	(1)	—	—	—	(1)	—	1	—
Adjusted fuel and purchased power	6	9	141	166	—	—	322	—	1	323
Carbon compliance	—	—	40	—	—	—	40	—	—	40
Gross margin	101	111	173	44	30	—	459	(6)	131	584
OM&A	13	20	46	18	10	28	135	(1)	—	134
Taxes, other than income taxes	1	4	3	—	—	—	8	—	—	8
Net other operating income	—	(2)	(10)	—	—	—	(12)	—	—	(12)
Adjusted EBITDA(2)	87	89	134	26	20	(28)	328
Equity income										1
Finance lease income										2
Depreciation and amortization										(124)
Asset impairment charges										(1)
Interest income										7
Interest expense										(69)
Foreign exchange loss and other										(3)
Earnings before income taxes										267

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

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the three months ended March 31, 2023:

	Hydro	Wind & Solar(1)	Gas	Energy Transition	Energy Marketing	Corporate	Total	Equity- accounted investments(1)	Reclass adjustments	IFRS financials
Revenues	125	115	495	267	92	—	1,094	(5)	—	1,089
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	(1)	—	(64)	(14)	16	—	(63)	—	63	—
Realized gain (loss) on closed exchange positions	—	—	(13)	—	(55)	—	(68)	—	68	—
Decrease in finance lease receivable	—	—	13	—	—	—	13	—	(13)	—
Finance lease income	—	—	4	—	—	—	4	—	(4)	—
Adjusted revenues	124	115	435	253	53	—	980	(5)	114	1,089
Fuel and purchased power	5	9	130	181	—	—	325	—	—	325
Reclassifications and adjustments:
Australian interest income	—	—	(1)	—	—	—	(1)	—	1	—
Adjusted fuel and purchased power	5	9	129	181	—	—	324	—	1	325
Carbon compliance	—	—	32	—	—	—	32	—	—	32
Gross margin	119	106	274	72	53	—	624	(5)	113	732
OM&A	12	17	41	17	14	24	125	(1)	—	124
Taxes, other than income taxes	1	3	4	1	—	—	9	—	—	9
Net other operating income	—	(2)	(11)	—	—	—	(13)	—	—	(13)
Adjusted EBITDA(2)	106	88	240	54	39	(24)	503
Equity income										2
Finance lease income										4
Depreciation and amortization										(176)
Asset impairment reversals										3
Interest income										15
Interest expense										(74)
Foreign exchange loss										(3)
Earnings before income taxes										383

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

(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

M38 TransAlta Corporation

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 March 31	2024	2023
Cash flow from operating activities(1)	244	462
Change in non-cash operating working capital balances	(7)	(42)
Cash flow from operations before changes in working capital	237	420
Adjustments
Share of adjusted FFO from joint venture(1)	2	3
Decrease in finance lease receivable	5	13
Realized loss on closed exchanged positions	(12)	(68)
Other(2)	7	6
FFO(3)	239	374
Deduct:
Sustaining capital(1)	1	(20)
Dividends paid on preferred shares	(13)	(13)
Distributions paid to subsidiaries’ non-controlling interests	(19)	(76)
Principal payments on lease liabilities	(1)	(2)
Other	(1)	—
FCF(3)	206	263
Weighted average number of common shares outstanding in the period	308	268
FFO per share(3)	0.78	1.40
FCF per share(3)	0.67	0.98

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

(2)Other consists of production tax credits, which is a reduction to tax equity debt, less distributions from equity-accounted joint venture.

(3)These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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

3 months ended March 31	2024	2023
Adjusted EBITDA(1)(4)	328	503
Provisions	—	3
Net interest expense(2)	(48)	(45)
Current income tax expense	(27)	(60)
Realized foreign exchange loss	(8)	(7)
Decommissioning and restoration costs settled	(7)	(7)
Other non-cash items	1	(13)
FFO(3)(4)	239	374
Deduct:
Sustaining capital(4)	1	(20)
Dividends paid on preferred shares	(13)	(13)
Distributions paid to subsidiaries’ non-controlling interests	(19)	(76)
Principal payments on lease liabilities	(1)	(2)
Other	(1)	—
FCF(3)(4)	206	263

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

(2)Net interest expense includes interest expense for the period less interest income.

(3)These items are not defined and have no standardized meaning under IFRS. FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section of this MD&A and reconciled to cash flow from operating activities above.

(4)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture. Refer to the Capital Expenditures section of this MD&A for details of sustaining capital expenditures.

M40 TransAlta Corporation

Key Non-IFRS Financial Ratios

The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and ratios are not defined and have no

standardized meaning under IFRS and may not be comparable to those used by other entities or by rating agencies.

Adjusted Net Debt to Adjusted EBITDA

As at	March 31, 2024	Dec. 31, 2023
Period-end long-term debt(1)	3,457	3,466
Exchangeable debentures	345	344
Less: Cash and cash equivalents(2)	(417)	(345)
Add: 50 per cent of issued preferred shares and exchangeable preferred shares(3)	671	671
Other(4)	—	(12)
Adjusted net debt(5)	4,056	4,124
Adjusted EBITDA(6)	1,457	1,632
Adjusted net debt to adjusted EBITDA (times)	2.8	2.5

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

(2)Cash and cash equivalents, net of bank overdraft.

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

(4)Includes principal portion of TransAlta OCP restricted cash (nil for the period ended March 31, 2024 and $17 million for the year ended Dec. 31, 2023) and fair value of hedging instruments on debt (included in risk management assets and/or liabilities on the unaudited interim condensed consolidated statements of financial position).

(5)The tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in this amount. Adjusted net debt is not defined and has no standardized meaning under IFRS. Presenting this item from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

(6)Last 12 months.

The Company's capital is managed using a net debt position. We use the adjusted net debt to adjusted EBITDA ratio as a measurement of financial leverage and to assess our ability to service debt. Our target for adjusted net debt to adjusted EBITDA is 3.0 to 4.0 times.

Our adjusted net debt to adjusted EBITDA ratio for March 31, 2024 was higher compared to Dec. 31, 2023, primarily due to lower adjusted EBITDA.

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2024 Outlook

The following table outlines our expectations on key financial targets and related assumptions for 2024 and should be read in conjunction with the narrative discussion that follows and the Governance and Risk Management section of this MD&A:

Measure	2024 Target	2023 Actuals
Adjusted EBITDA(1)	$1,150 million - $1,300 million	$1,632 million
FCF(1)	$450 million - $600 million	$890 million
FCF per share	$1.47 - $1.96	$3.22
Dividend	$0.24 per share annualized	$0.22 per share annualized

(1)These items are not defined and have no standardized meaning under IFRS. Refer to the Reconciliation of Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

The Company's outlook for 2024 may be impacted by a number of factors as detailed further below.

Range of key 2024 power and gas price assumptions

Market	2024 Assumptions
Alberta spot ($/MWh)	$75 to $95
Mid-C spot (US$/MWh)	US$75 to US$85
AECO gas price ($/GJ)	$1.75 to $2.25

Alberta spot price sensitivity: a +/- $1 per MWh change in spot price is expected to have a +/-$3 million impact on adjusted EBITDA for balance of year 2024.

Other assumptions relevant to the 2024 outlook

	2024 Expectations
Energy Marketing gross margin	$110 million to $130 million
Sustaining capital	$130 million to $150 million
Corporate cash taxes	$95 million to $130 million
Cash interest	$240 million to $260 million

Alberta Hedging

Range of hedging assumptions	Q2 2024	Q3 2024	Q4 2024	Full year 2025	Full year 2026
Hedged production (GWh)	1,983	2,249	2,153	4,614	3,215
Hedge price ($/MWh)	$85	$85	$85	$79	$80
Hedged gas volumes (GJ)	14 million	14 million	15 million	28 million	18 million
Hedge gas prices ($/GJ)	$2.80	$2.84	$2.80	$3.52	$3.67

Refer to the 2024 Outlook section in our 2023 Annual MD&A for further details relating to our Outlook and related assumptions.

Liquidity and Capital Resources

We expect to maintain adequate available liquidity under our committed credit facilities. As at March 31, 2024, we had access to $1.7 billion in liquidity, including $417 million in cash, net of bank overdraft.

M42 TransAlta Corporation

Material Accounting Policies and Critical Accounting Estimates

The preparation of unaudited interim condensed consolidated financial statements requires management to make judgments, estimates and assumptions that could affect the reported amounts of assets, liabilities, revenues, expenses and disclosures of contingent assets and liabilities during the period. These estimates are subject to

uncertainty. Actual results could differ from these estimates due to factors such as fluctuations in interest rates, foreign exchange rates, inflation and commodity prices, and changes in economic conditions, legislation and regulations. There were no material changes in estimates in the quarter.

Accounting Changes

Current Accounting Changes

Amendments to IAS 1 Non-current Liabilities with Covenants and Classification of Liabilities as Current or Non-current 

In October 2022, the IASB issued Non-current Liabilities with Covenants, which amends IAS 1 Presentation of Financial Statements, to clarify how conditions with which an entity must comply within 12 months after the reporting period affect the classification of a liability. In January 2020, the IASB issued Classification of Liabilities as Current or Non-current, which amends IAS 1 Presentation of Financial Statements regarding the classification of liabilities as current or non‐current, clarifying that contractual rights and conditions existing at the end of the reporting period are relevant in determining whether the Company has a right to defer settlement of a liability by at least 12 months.

Additionally, the IASB clarified that the classification of a liability is unaffected by the likelihood that an entity will exercise its deferral right. The amendments are applied

retrospectively, effective for annual periods beginning on or after Jan. 1, 2024, and were adopted by the Company on that date. 

On Jan. 1, 2024, the Company reclassified the Exchangeable Securities from non-current liabilities to current liabilities as the conversion option can be exercised at any time after Jan. 1, 2025, although there is no obligation to deliver cash equivalent resources and the holder cannot call for repayment. This accounting is consistent with the amendment.

Future Accounting Changes

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.

Governance and Risk Management

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

Please refer to the Governance and Risk Management section of our 2023 Annual MD&A and Note 10 of our unaudited interim condensed consolidated financial statements for details on our risks and how we manage them. Our risk management profile and practices have not changed materially from Dec. 31, 2023.

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Regulatory Updates

Refer to the Policy and Legal Risks discussion in our 2023 Annual MD&A for further details that supplement the recent developments as discussed below:

Canada

Federal Climate Plan

In April 2021, the Government of Canada announced a revised national GHG emissions reductions target of 40 per cent to 45 per cent below 2005 levels by 2030. In 2022, the Government of Canada’s Department of Environment and Climate Change Canada (“ECCC”) released the proposed framework for the Clean Electricity Regulations ("CER") to achieve a net-zero electricity sector in Canada by 2035. The draft CER was published in Canada Gazette Part I on Aug. 19, 2023. A seventy five-day formal comment period closed on Nov. 2, 2023. The Government of Canada released a public update report on Feb. 15, 2024 with a 30-day comment period for feedback. The CER is expected to be finalized in 2024.

In the 2023 federal budget, the government announced additional investment tax credit ("ITC") categories and details aimed at supporting the net zero transition. The ITCs are expected to support investments in net zero technologies in the electricity sector. On June 6, 2023 the Department of Finance launched consultations seeking feedback on design details regarding the ITC components included in Budget 2023. The Government of Canada subsequently released draft legislation on Aug. 4, 2023, for consultation to advance key budget priorities, including the Clean Technology ITC, Clean Technology Manufacturing ITC and ITC for Carbon Capture Utilization and Storage. Legislation is expected to be finalized in 2024. A draft legislative proposal for the Hydrogen and Clean Technology Manufacturing ITC was also released by the Government of Canada on Dec. 20, 2023 for consultation.

Alberta

On April 19, 2023, the Government of Alberta released the Emissions Reduction and Energy Development Plan, which outlines an aspiration to achieve a carbon neutral economy by 2050. The plan frames Alberta's approach to enhance the province's position as a global leader in emissions reductions, clean technology and innovation, while maintaining Alberta's competitiveness from a sustainable resource development perspective. The plan is guided by eight strategic principles and outlines the actions, opportunities and new commitments that will reduce emissions and maintain energy security.

On Feb. 28, 2024, the Government of Alberta announced new restrictions and requirements that it will impose on new renewable projects and power plant regulatory approval processes. This includes prohibiting wind

generation development within 35 kilometres of a protected area or other area designated a "pristine viewscape" by the Government, restricting renewable developments on class 1 and 2 agricultural lands, imposing new mandatory requirements to post bonds and/or provide financial security to meet reclamation obligations, and granting municipalities standing in AUC power plant regulatory proceedings. The Government and regulatory agencies are expected to plan future engagements to consult on and implement these new requirements. The Riplinger wind project was impacted by the new restriction, specifically the restrictions on development near protected areas and pristine viewscapes, and will not be advanced. The project has been removed from our early development projects.

The Government also lifted its renewables approvals pause, which was in place from Aug. 3, 2023 to Feb. 29, 2024.

The Government also stated that it would bring forth changes to the Transmission Regulation by July 2024. The Government conducted two consultations in the previous three years that considered potential changes to transmission policy and the regulation. The Government alluded to changes that it seeks to make to allocate transmission costs to renewable projects.

The AUC provided a report to the Minister of Affordability and Utilities on the impacts of renewable growth on the generation supply mix and system reliability in Alberta. The AUC's report is based on a modeling study that concludes that additional renewable growth will reduce energy prices but also squeeze out thermal dispatchable resources and result in deteriorating system reliability that breaches Alberta's long term adequacy thresholds.

On March 11, 2024, the Government announced its decision to accept the AESO recommendation to pursue detailed design work on a "Restructured Energy Market". Concurrently, the Government publicly released the Market Surveillance Administrator's Dec. 21, 2023 report and AESO's Jan. 31, 2024 report to the Minister; both reports proposed incremental changes to the existing energy market that were largely consistent with and complementary to each other.

The AESO plans to develop the detailed design using an industry working group that will commence regular meetings in mid-April and will work towards a first or second quarter of 2025 target date for a full Restructured Energy Market detailed design proposal. TransAlta will be an active participant in the AESO's working group process. The new market rules that will implement the detailed design will be filed with the AUC in the first or second quarter of 2025 and are planned to be approved by the fourth quarter of 2025 or the first quarter of 2026.

TransAlta Corporation M44

The Government also filed two new interim regulations under Ministerial Order on March 11, 2024. The new regulations prescribe specific changes that the AESO and AUC must implement through new and amended Independent System Operator rules by July 1, 2024. Both regulations expire on Nov. 30, 2027, when the new Restructured Energy Market is expected to be implemented.

The Market Power Mitigation Regulation imposes an offer cap on the gas-fired generating units controlled by a large market participant (with offer control of 5 per cent of all generation). The offer cap would only restrict our offering price, not settlement price, and is triggered when the pool prices hit a threshold of two-months worth of net revenue for a hypothetical natural gas-fired combined cycle power plant. The offer cap is set at $125 per MWh or 25 times the day-ahead natural gas price and applies to the remainder of the calendar month in which the threshold was triggered. This regulation is not expected to have a significant impact given the weaker pricing conditions expected over the period of time that the regulation will be in place.

The Supply Cushion Regulation imposes specific requirements on the AESO to direct long-lead time generation (generators that require one hour or more to synchronize to the grid). The AESO is required to forecast and take action to direct long-lead time generation on line when the supply cushion is expected to be equal to or less than 932 MW. Long-lead time generation will receive a cost guarantee that will provide top ups to compensate a resource that is directed on by the AESO if the pool price revenues do not provide sufficient compensation to cover fuel and variable costs. The impacts of this regulation are still unclear given that lack of any details about the proposed mechanism - notably, the AESO has existing authority to make these decisions and provide compensation for costs but has never issued a directive to a long-lead time unit.

United States

On March 6, 2024, the U.S. Securities and Exchange Commission ("SEC") adopted final rules for climate-related disclosures. On April 4, 2024, SEC paused the implementation of these rules as it awaits a court review of the new rules following a series of legal challenges by several states and business groups. The Company is exempt from these rules because TransAlta is a multi jurisdictional disclosure system issuer filing on Form 40-F. The Canadian Securities Administrators anticipates seeking comment on a revised rule for climate-related disclosures after considering the SEC’s final rules and the Canadian Sustainability Standards Board’s climate-related disclosures standard to be released in 2024.

Australia

Since the Labour Party formed government on May 21, 2022, Australia has increased its Nationally Determined Contribution commitment to increase the country’s 2030 emissions reduction goal to 43 per cent below 2005 levels and confirmed its intent to boost renewable electricity production to 82 per cent of the electricity supply by 2030.

Prime Minister Anthony Albanese has worked quickly to implement one of his government’s key energy policies, the Powering Australia Plan, which includes: the Rewiring the Nation initiative that will provide AU$20 billion to support the Australian Energy Market Operator’s (“AEMO”) integrated system plan to modernize the transmission system and enable additional renewable penetration; Powering the Regions Fund (AU$1.9 billion) supporting industry to decarbonize, developing new clean energy industries and supporting workforce development; and a AU$15 billion National Reconstruction Fund to diversify and transform Australia’s economy and industry, including investments in green metals, clean energy component manufacturing and deployment of low-emissions technologies. Decarbonization efforts have been centered on funding for clean technologies, upgrading electricity grid to support more renewables, regulating and reporting of GHGs, and incentivizing zero-emission vehicles adoption.

TransAlta continues to monitor the development of climate-related financial disclosure legislation by the Australian Government, which is anticipated to be in effect in 2024.

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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 months ended March 31, 2024, 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 unaudited interim 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) in order to assess the effectiveness of the Company’s ICFR.

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

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

Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our ICFR and DC&P as of the end of the period covered by this MD&A. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as at March 31, 2024, the end of the period covered by this MD&A, our ICFR and DC&P were effective.

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Glossary of Key Terms

Adjusted Availability

Availability is adjusted when economic conditions exist, such that planned routine and major maintenance activities are scheduled to minimize expenditures. In high price environments, actual outage schedules would change to accelerate the generating unit's return to service.

Alberta Electric System Operator (AESO)

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

Alberta Hydro Assets

The Company's hydroelectric assets, owned through a wholly owned subsidiary, TransAlta Renewables Inc. These assets are located in Alberta consisting of the Barrier, Bearspaw, Cascade, Ghost, Horseshoe, Interlakes, Kananaskis, Pocaterra, Rundle, Spray, Three Sisters, Bighorn and Brazeau hydro facilities.

Alberta Thermal

The business segment previously disclosed as Canadian Coal has been renamed to reflect the ongoing conversion of the boilers to burn gas in place of coal. The segment includes the legacy and converted generating units at our Sundance and Keephills sites and includes the Highvale Mine.

Ancillary Services

As defined by the Electric Utilities Act, Ancillary Services are those services required to ensure that the interconnected electric system is operated in a manner that provides a satisfactory level of service with acceptable levels of voltage and frequency.

Automatic Share Purchase Plan (ASPP)

The ASPP is intended to facilitate repurchases of common shares under the NCIB, including at times when the Company would ordinarily not be permitted to make purchases due to regulatory restrictions or self-imposed blackout periods.

Availability

A measure of time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year, that a generating unit is capable of generating electricity, regardless of whether or not it is actually generating electricity.

Capacity

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

Cogeneration

A generating facility that produces electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, heating or cooling purposes.

Disclosure Controls and Procedures (DC&P)

Refers to controls and other procedures designed to ensure that information required to be disclosed in the reports filed by the Company or submitted under securities legislation is recorded, processed, summarized and reported within the time frame specified in applicable securities legislation. DC&P include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in its reports that it files or submits under applicable securities legislation is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Dispatch optimization

Purchasing power to fulfill contractual obligations, when economical.

Economic Dispatch

Power is not produced during periods of low market price, but is purchased in the market to fulfil the contract.

Emissions Performance Standards (EPS)

Under the Government of Ontario, emission performance standards establish greenhouse gas (GHG) emissions limits for covered facilities.

EPCs

Emission Performance Credits.

Force Majeure

Literally means “greater force.” These clauses excuse a party from liability if some unforeseen event beyond the control of that party prevents it from performing its obligations under the contract.

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Free Cash Flow (FCF)

Represents the amount of cash that is available to invest in growth initiatives, make scheduled principal repayments on debt, repay maturing debt, pay common share dividends or repurchase common shares. Amount is calculated as cash generated by the Company through its operations (cash from operations) minus the funds used by the Company for the purchase improvement, or maintenance of the long-term assets to improve the efficiency or capacity of the Company (capital expenditures).

Funds from Operations (FFO)

Represents a proxy for cash generated from operating activities before changes in working capital and provides the ability to evaluate cash flow trends in comparison with results from prior periods. Amount is calculated as cash flow from operating activities before changes in working capital and is adjusted for transactions and amounts that the Company believes are not representative of ongoing cash flows from operations.

Gigajoule (GJ)

A metric unit of energy commonly used in the energy industry. One GJ equals 947,817 British Thermal Units ("Btu"). One GJ is also equal to 277.8 kilowatt hours ("kWh").

Gigawatt (GW)

A measure of electric power equal to 1,000 megawatts.

Gigawatt hour (GWh)

A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.

Greenhouse Gas (GHG)

A gas that has the potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons and perfluorocarbons.

ICFR

Internal control over financial reporting.

IFRS

International Financial Reporting Standards.

ITC

The investment tax credit ("ITC") is a federal income tax credit for investments in certain types of qualifying clean electricity projects.

Megawatt (MW)

A measure of electric power equal to 1,000,000 watts.

Megawatt Hour (MWh)

A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.

Merchant

A term used to describe assets that are not contracted and are exposed to market pricing.

NCIB

Normal Course Issuer Bid.

OM&A

Operations, maintenance and administration costs.

Other Hydro Assets

The Company's hydroelectric assets located in British Columbia, Ontario and assets owned by TransAlta Renewables which include the Taylor, Belly River, Waterton, St. Mary, Upper Mamquam, Pingston, Bone Creek, Akolkolex, Ragged Chute, Misema, Galetta, and Moose Rapids facilities.

Planned outage

Periodic planned shutdown of a generating unit for major maintenance and repairs. Duration is normally in weeks. The time is measured from unit shutdown to putting the unit back on line.

Power Purchase Agreement (PPA)

A long-term commercial agreement for the sale of electric energy to PPA buyers.

PP&E

Property, plant and equipment.

Turbine

A machine for generating rotary mechanical power from the energy of a stream of fluid (such as water, steam or hot gas). Turbines convert the kinetic energy of fluids to mechanical energy through the principles of impulse and reaction or a mixture of the two.

Unplanned outage

The shutdown of a generating unit due to an unanticipated breakdown.

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