EX-13.2 3 a20231231tacex132mda.htm EX-13.2
TRANSALTA CORPORATION
Management’s Discussion and Analysis
This Management’s Discussion and Analysis (“MD&A”) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. Refer to the Forward-Looking Statements section of this MD&A for additional information.
Table of Contents

M2 | Forward-Looking Statements |  | M59 | Key Non-IFRS Financial Ratios
M4 | Description of the Business |  | M59 | 2024 Outlook
M6 | Highlights |  | M62 | Material Accounting Policies and Critical Accounting Estimates
M11 | Capital Expenditures |  | M67 | Accounting Changes
M12 | Significant and Subsequent Events |  | M67 | Environmental, Social and Governance
M15 | Segmented Financial Performance and Operating Results |  | M69 | Accelerating Our Business Transformation with a Target to Become Net-Zero by 2045
M23 | Performance by Segment with Supplemental Geographical Information |  | M70 | Our 2023 Sustainability Performance
M23 | Optimization of the Alberta Portfolio |  | M72 | 2024+Sustainability Targets
M26 | Fourth Quarter Highlights |  | M75 | Decarbonizing Our Energy Mix
M28 | Segmented Financial Performance and Operating Results for the Fourth Quarter |  | M81 | Key Climate Scenario Findings
M29 | Selected Quarterly Information |  | M84 | Managing Climate Change Risks and Opportunities
M31 | Strategy and Capability to Deliver Results |  | M94 | Enabling Innovation and Technology Adoption
M31 | Strategic Priorities and Clean Electricity Growth Plan to 2028 |  | M97 | Engaging with Our Stakeholders to Create Positive Relationships
M36 | Financial Position |  | M103 | Building a Diverse and Inclusive Workforce
M37 | Financial Capital |  | M106 | Progressive Environmental Stewardship
M42 | Cash Flows |  | M112 | Delivering Reliable and Affordable Energy
M44 | Other Consolidated Analysis |  | M113 | Sustainability Governance
M46 | Financial Instruments |  | M114 | Governance and Risk Management
M48 | Additional IFRS Measures and Non-IFRS Measures |  | M125 | Disclosure Controls and Procedures

This MD&A should be read in conjunction with our 2023 audited annual consolidated financial statements (the "consolidated financial statements") and our 2023 Annual Information Form ("AIF"), each for the fiscal year ended Dec. 31, 2023. In this MD&A, unless the context otherwise requires, “we”, “our”, “us”, the “Company” and “TransAlta” refer to TransAlta Corporation and its subsidiaries. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) for Canadian publicly accountable enterprises as issued by the International Accounting Standards Board (“IASB”) and in effect at Dec. 31, 2023. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted, except amounts per share, which are in whole dollars to the nearest two decimals. This MD&A is dated Feb. 22, 2024. Additional information respecting TransAlta, including our AIF for the year ended Dec. 31, 2023, is available on SEDAR+ at www.sedarplus.ca, on EDGAR at www.sec.gov and on our website at www.transalta.com. Information on or connected to our website is not incorporated by reference herein.

TransAlta Corporation | 2023 Integrated Report | M1

Forward-Looking Statements
This MD&A includes "forward-looking information" within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of applicable United States securities laws, including the Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements"). All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made and on management's experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may", "will", "can", "could", "would", "shall", "believe", "expect", "estimate", "anticipate", "intend", "plan", "forecast", "foresee", "potential", "enable", "continue" or other comparable terminology. These statements are not guarantees of our future performance, events or results and are subject to risks, uncertainties and other important factors that could cause our actual performance, events or results to be materially different from those set out in or implied by the forward-looking statements.
In particular, this MD&A contains forward-looking statements including, but not limited to, statements relating to: the acquisition of Heartland (as defined below) and its entire business operations in Alberta and British Columbia, including closing conditions and regulatory approvals pursuant to the Heartland acquisition and the anticipated timing and completion of the acquisition; the annual average earnings before interest, taxes, depreciation and amortization ("EBITDA") to be generated from the Heartland acquisition and other benefits expected to arise from such transaction; the Company’s 2024 Outlook, including Adjusted EBITDA, free cash flow, annualized dividend per share, sustaining capital and energy marketing gross margin; the Company’s expanded growth targets to deliver 1.75 GW with a target investment of $3.5 billion by 2028 which is anticipated to deliver annual EBITDA of $350 million; the expansion of the Company's development pipeline to 10 GW by 2028; the Company’s investment strategy to deliver long-term value to shareholders; the common share dividend level through 2024; the Company's projects under construction, including capital costs, the timing of commercial operations and expected annual EBITDA; the impact of new asset additions in 2024 of Garden Plain, Northern Goldfields solar, Kent Hills, Mount Keith transmission, White Rock and Horizon Hill; the development of the early-stage and advanced-stage projects; achieving the anticipated benefits of the transfer of PTCs (defined below) generated
from the White Rock and Horizon Hill wind projects; executing growth with Hancock under the Joint Development Agreement; the proportion of EBITDA to be generated from renewable sources to increase to 70 per cent by the end of 2028; the Company’s ability to achieve its long-term decarbonization goal to be net zero by 2045; the reduction of carbon emissions by 75 per cent from 2015 emissions levels by 2026; the expected impact and quantum of carbon compliance costs; regulatory developments and their expected impact on the Company; expectations regarding refinancing debt; and the Company continuing to maintain adequate liquidity.
The forward-looking statements contained in this MD&A are based on many assumptions including, but not limited to, the following: no significant changes to applicable laws and regulations beyond those that have already been announced; no significant changes to fuel and purchased power costs; no material adverse impacts to long-term investment and credit markets; no significant changes to power price and hedging assumptions, including hedged volumes and prices; no significant changes to gas commodity prices and transport costs; no significant changes to decommissioning and restoration costs; no significant changes to interest rates; no significant changes to the demand and growth of renewables generation; no significant changes to the integrity and reliability of our assets; planned and unplanned outages and use of our assets; and no significant changes to the Company's debt and credit ratings.
Forward-looking statements are subject to a number of significant risks and uncertainties that could cause actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this MD&A include risks relating to: fluctuations in power prices, including merchant pricing in Alberta, Ontario and Mid-Columbia; failure or delay in closing the Heartland acquisition; failure to realize the benefits of the Heartland acquisition, including the inability to advance the Battle River Carbon Hub Project to final investment decision or commercial operation, and any loss of value in the Heartland portfolio during the interim period prior to closing; reductions in production; restricted access to capital and increased borrowing costs, including any difficulty raising debt, equity or tax equity, as applicable, on reasonable terms or at all; labour relations matters, reduced labour availability and the ability to continue to staff our operations and facilities; reliance on key personnel; disruptions to our supply chains, including our ability to secure necessary equipment; force majeure claims; our ability to obtain regulatory and any other third-party approvals on the expected timelines or at all in respect of our growth projects; long-term commitments on

M2 | TransAlta Corporation | 2023 Integrated Report

gas transportation capacity that may not be fully utilized over time; adverse financial impacts arising from the Company's hedged position; risks associated with development and construction projects, including as it pertains to increased capital costs, permitting, labour and engineering risks, disputes with contractors and potential delays in the construction or commissioning of such projects; significant fluctuations in the Canadian dollar against the US dollar and Australian dollar; changes in short-term and long-term electricity supply and demand; counterparty credit risk and any higher rate of losses on our accounts receivables; inability to achieve our environmental, social and governance ("ESG") targets; the impact of the energy transition on our business; impairments and/or writedowns of assets; adverse impacts on our information technology systems and our internal control systems, including cybersecurity threats; commodity risk management and energy trading risks, including the effectiveness of the Company’s risk management tools associated with hedging and trading procedures to protect against significant losses; our ability to contract our generation for prices that will provide expected returns and to replace contracts as they expire; changes to the legislative, regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; disruptions in the transmission and distribution of electricity; the effects of weather, including man-made or natural disasters and other climate-change related risks; increases in costs; reductions to our generating units’ relative efficiency or capacity factors; disruptions in the source of fuels, including natural gas, coal, water, solar or wind resources required to operate our facilities; operational risks, unplanned outages and equipment failure and our ability to carry out or have completed any repairs in a cost-effective or timely manner or at all; failure to meet financial expectations; general domestic and international economic and political developments, including armed hostilities, the threat of terrorism, adverse diplomatic developments or other similar events; industry risk and competition in the business in which we operate; structural subordination of securities; public health crisis risks; inadequacy or unavailability of insurance coverage; our provision for income taxes and any risk of reassessment; and legal, regulatory and contractual disputes and proceedings involving the Company. The foregoing risk factors, among others, are described in further detail in the Governance and Risk Management section of this MD&A and the Risk Factors section in our AIF for the year ended Dec. 31, 2023.
Readers are urged to consider these factors carefully when evaluating the forward-looking statements, which reflect the Company's expectations only as of the date hereof and are cautioned not to place undue reliance on them. The forward-looking statements included in this document are
made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. The purpose of the financial outlooks contained herein is to give the reader information about management's current expectations and plans and readers are cautioned that such information may not be appropriate for other purposes. In light of these risks, uncertainties and assumptions, the forward-looking statements might occur to a different extent or at a different time than we have described, or might not occur at all. We cannot assure that projected results or events will be achieved.

TransAlta Corporation | 2023 Integrated Report | M3

Description of the Business
TransAlta is a Canadian corporation and one of Canada's largest publicly traded power generators. Established in 1911, the Company now has over 112 years of operating experience in the development, production and sale of electricity. We own, operate and manage a geographically diversified portfolio of generation assets that include water, wind, solar, battery storage, natural gas and transition coal. We are one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta. We also have industry-leading energy marketing capabilities where we seek to maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions. Our mix of merchant and contracted assets along with our energy marketing business provides resilient and growing cash flows that support our ability to pay dividends to our shareholders and reinvest in growth.
The Company's goal is to be a leading clean electricity company that is committed to a sustainable future and a responsible energy transition. Our strategic priorities include accelerating growth into customer-centred renewables and storage, selectively expanding flexible generation and reliability assets to support the transition, defining the next generation of power solutions and maintaining financial strength and capital allocation discipline. We are primarily focused on opportunities within our core markets of Canada, the US and Western Australia.
Our sustainability goals and our Clean Electricity Growth Plan remain the focus of our strategy, which includes our commitment to retire our last remaining operational coal facility at the end of 2025. We remain on track to achieve our 2026 greenhouse gas ("GHG") emissions reduction target of 75 per cent scope 1 and 2 GHG emissions reductions since 2015 and our carbon net-zero goal by 2045. Since 2005, we have reduced our scope 1 and 2 GHG emissions by 31 million tonnes ("MT") of CO 2 e or a 74 per cent reduction, proudly representing approximately 10 per cent of Canada's Paris Agreement 2030 decarbonization target(1).
Portfolio of Assets
Our asset portfolio is geographically diversified with operations across Canada, the United States and Australia. The portfolio also generates power using a diverse set generation technologies and reliably supplies a broad cross section of counterparties.
Our Hydro, Wind and Solar, Gas and Energy Transition segments are responsible for operating and maintaining our electrical generation facilities. Our Energy Marketing segment is responsible for marketing and scheduling our merchant asset fleet in North America (excluding Alberta) along with the procurement of gas, transport and storage for our gas fleet, providing knowledge to support our growth team, and generating a stand-alone gross margin separate from our asset business through a leading North American energy marketing and trading platform.
Our highly diversified portfolio consists of both high-quality contracted assets and merchant assets. Approximately, 56 percent of our total installed capacity, including 81 per cent of our Wind and Solar fleet and 53 per cent of our Gas fleet, is contracted with investment-grade or creditworthy counterparties. The weighted-average contract life for these contracted facilities is 10 years.
Our merchant assets include our unique hydro merchant portfolio and our merchant legacy thermal portfolio and wind assets. Our merchant exposure is primarily in Alberta, where 53 per cent of our capacity is located and 75 per cent of our Alberta capacity is available to participate in the merchant market. The Alberta optimization team is responsible for marketing and scheduling our merchant asset fleet in Alberta.
A significant portion of the thermal generation capacity in the portfolio has been hedged to provide cash flow certainty. The Company's hedging strategy includes maintaining a significant base of commercial and industrial customers and is supplemented with financial hedges. In 2023, 78 per cent of our energy production in Alberta was sold under long term contracts or fixed price hedges. Refer to the 2024 Outlook section and the Optimization of the Alberta Portfolio of this MD&A for further details.
Our diversified fleet is a key success factor in our ability to deliver resilient cash flows while capturing higher risk-adjusted returns for our shareholders.
(1)In 2005, TransAlta's estimated scope 1 and 2 GHG emissions were 41.9 MT of CO 2 e, which did not receive independent limited assurance. Canada's Paris Agreement 2030 decarbonization target assumed 293 MT of CO 2 e or a 40 per cent reduction from a 2005 baseline of 732 MT of CO 2 e.

M4 | TransAlta Corporation | 2023 Integrated Report

The following table provides our consolidated ownership of our facilities across the regions in which we operate as of
Dec. 31, 2023:

| Hydro | Wind & Solar | Gas | Energy Transition |  |  | Total
Year ended Dec. 31, 2023 | Gross Installed Capacity (MW) | Number of facilities | Gross Installed Capacity (MW)(1) | Number of facilities | Gross Installed Capacity (MW)(1) | Number of facilities | Gross Installed Capacity (MW) | Number of facilities |  |  | Gross Installed Capacity (MW)(1) | Number of facilities
Alberta | 834 |  | 17 |  | 766 |  | 14 |  | 1,960 |  | 7 |  | — |  | — |  |  |  | 3,560 |  | 38 |
Canada, excluding Alberta | 88 |  | 7 |  | 751 |  | 9 |  | 645 |  | 3 |  | — |  | — |  |  |  | 1,484 |  | 19 |
US | — |  | — |  | 519 |  | 7 |  | 29 |  | 1 |  | 671 |  | 2 |  |  |  | 1,219 |  | 10 |
Australia | — |  | — |  | 48 |  | 3 |  | 450 |  | 6 |  | — |  | — |  |  |  | 498 |  | 9 |
Total | 922 |  | 24 |  | 2,084 |  | 33 |  | 3,084 |  | 17 |  | 671 |  | 2 |  |  |  | 6,761 |  | 76 |

(1)Gross installed capacity for consolidated reporting represents 100 per cent output of a facility. Capacity figures for the Wind and Solar segment includes 100 per cent of the Kent Hills wind facilities, and capacity figures for the Gas segment include 100 per cent of the Ottawa and Windsor facilities, 100 per cent of the Poplar Creek facility, 50 per cent of the Sheerness facility and 60 per cent of the Fort Saskatchewan facility.
Stable and Predictable Cash Flows
The following table provides our contracted capacity by MW and as a percentage of total gross installed capacity of our facilities across the regions in which we operate as of Dec. 31, 2023:

As at Dec. 31, 2023 | Hydro | Wind & Solar | Gas | Energy Transition |  |  | Total
Alberta | — | 374 | 511 | — |  |  | 885
Canada, excluding Alberta | 88 | 751 | 645 | — |  |  | 1,484
US | — | 519 | 29 | 381 |  |  | 929
Australia | — | 48 | 450 | — |  |  | 498
Total contracted capacity (MW) | 88 | 1,692 | 1,635 | 381 |  |  | 3,796
Contracted capacity as a % of total capacity (%) | 10 | % | 81 | % | 53 | % | 57 | % |  |  | 56 | %

The weighted average contract life (years) of our facilities across the regions in which we operate as of Dec. 31, 2023 is:

As at Dec. 31, 2023 | Hydro | Wind & Solar | Gas | Energy Transition |  |  | Total
Alberta(1)(2) | — |  | 16 |  | 7 |  | — |  |  |  | 11 |
Canada, excluding Alberta(2) | 10 |  | 10 |  | 8 |  | — |  |  |  | 9 |
US(2) | — |  | 10 |  | 2 |  | 2 |  |  |  | 7 |
Australia(2) | — |  | 15 |  | 15 |  | — |  |  |  | 15 |
Total weighted contract life (years)(2) | 10 |  | 12 |  | 10 |  | 2 |  |  |  | 10 |

(1)The weighted-average remaining contract life in the Wind and Solar segment is related to the contract period for Garden Plain (130 MW), McBride Lake (38 MW), and Windrise (206 MW). The weighted-average remaining contract life in the Gas segment is related to the contract period for Poplar Creek (230 MW), Fort Saskatchewan (71 MW) and a capacity-contract that is not directly contracted with any one facility (210 MW).
(2)For power generated under long-term power purchase agreements ("PPAs") and other long-term contracts, the weighted-average remaining contract life is based on long-term average gross installed capacity.
The majority of TransAlta's long-term power purchase agreements are with investment-grade rated or creditworthy counterparties.

TransAlta Corporation | 2023 Integrated Report | M5

Highlights
For the year ended Dec. 31, 2023, the Company demonstrated strong performance mainly due to the continued strong market conditions in Alberta in the first half of the year, higher production in the Gas and Energy Transition segments, and higher hedged volumes and
lower realized gas prices in the Gas segment, partially offset by lower wind and water resources. The Energy Marketing segment's performance was lower compared to 2022 due to the lower realized settled trades during the year on market positions compared to the prior year.

Year ended Dec. 31 |  |  | 2023 | 2022 | 2021
Operational information |  |  |  |  |
Adjusted availability (%) |  |  | 88.8 |  | 90.0 |  | 86.6 |
Production (GWh) |  |  | 22,029 |  | 21,258 |  | 22,105 |
Select financial information |  |  |  |  |
Revenues |  |  | 3,355 |  | 2,976 |  | 2,721 |
Earnings (loss) before income taxes |  |  | 880 |  | 353 |  | (380) |
Adjusted EBITDA(1) |  |  | 1,632 |  | 1,634 |  | 1,286 |
Net earnings (loss) attributable to common shareholders |  |  | 644 |  | 4 |  | (576) |
Cash flows |  |  |  |  |
Cash flow from operating activities |  |  | 1,464 |  | 877 |  | 1,001 |
Funds from operations(1) |  |  | 1,351 |  | 1,346 |  | 994 |
Free cash flow(1) |  |  | 890 |  | 961 |  | 585 |
Per share |  |  |  |  |
Weighted average number of common shares outstanding |  |  | 276 |  | 271 |  | 271 |
Net earnings (loss) per share attributable to common shareholders, basic and diluted |  |  | 2.33 |  | 0.01 |  | (2.13) |
Dividends declared per common share |  |  | 0.22 |  | 0.21 |  | 0.19 |
Funds from operations per share(1)(2) |  |  | 4.89 |  | 4.97 |  | 3.67 |
Free cash flow per share(1)(2) |  |  | 3.22 |  | 3.55 |  | 2.16 |
Liquidity and capital resources |  |  |  |  |
Available liquidity |  |  | 1,738 |  | 2,118 |  | 2,177 |
Adjusted net debt to adjusted EBITDA(1) (times) |  |  | 2.5 |  | 2.2 |  | 2.6 |
Total consolidated net debt(1)(3) |  |  | 3,453 |  | 2,854 |  | 2,636 |
As at Dec. 31 |  |  | 2023 | 2022 | 2021
Total assets |  |  | 8,659 |  | 10,741 |  | 9,226 |
Total long-term liabilities |  |  | 5,253 |  | 5,864 |  | 4,702 |
Total liabilities |  |  | 6,995 |  | 8,752 |  | 6,633 |

(1)These items are not defined and have no standardized meaning under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings (loss) trends more readily in comparison with prior periods’ results. Refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. Also, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(2)Funds from operations ("FFO") per share and free cash flow ("FCF") per share are calculated using the weighted average number of common shares outstanding during the period. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for the purpose of these non-IFRS ratios.
(3)Refer to the table in the Financial Capital section of this MD&A for more details on the composition of total consolidated net debt.

M6 | TransAlta Corporation | 2023 Integrated Report

Operating Performance
Adjusted Availability
The following table provides adjusted availability (%) by segment:

Year ended Dec. 31 |  |  | 2023 | 2022 | 2021
Hydro |  |  | 90.8 |  | 96.7 |  | 92.4 |
Wind and Solar |  |  | 86.9 |  | 83.8 |  | 91.9 |
Gas |  |  | 91.6 |  | 94.6 |  | 85.7 |
Energy Transition(1) |  |  | 79.8 |  | 79.0 |  | 78.8 |
Adjusted availability (%) |  |  | 88.8 |  | 90.0 |  | 86.6 |

(1)Availability, not adjusted for dispatch optimization, was 79.8 per cent for the year ended Dec. 31, 2023 (2022 - 77.2 per cent; 2021 - 75.3 per cent).
Availability is an important measure for the Company as it represents the percentage of time a facility is available to produce electricity and is therefore an important indicator of the overall performance of the fleet.
Availability is impacted by planned and unplanned outages, including the extended outage at the Kent Hills wind facility within the Wind and Solar fleet. Availability adjusted to exclude the Kent Hills extended outage for the years ended Dec. 31, 2022 and 2023, was 91.0 per cent and 92.8 per cent, respectively. The Company schedules dedicated time (planned outages) to maintain, repair or make improvements to the facilities at a time that will minimize the impact to the operations. In high price environments, actual outage schedules may change to accelerate the return to service of the unit.
Adjusted availability for the year ended Dec. 31, 2023, was 88.8 per cent, compared to 90.0 per cent in 2022, and was consistent with management's expectations. Lower adjusted availability was primarily due to:
•Planned outages in the Hydro segment, mainly at our Alberta Hydro Assets, to perform scheduled maintenance and
•Planned outages at Sundance Unit 6, Sheerness Unit 1, Keephills Units 2 and 3 and Sarnia for scheduled maintenance in the Gas segment, partially offset by
•Lower planned outages at Centralia Unit 2 in the Energy Transition segment and
•The partial return to service of the Kent Hills wind facilities.
Production and Long-Term Average Generation

| 2023 | 2022 | 2021
Year ended Dec. 31 | Actual production (GWh) | LTA generation (GWh) | Production as a % of LTA | Actual production (GWh) | LTA generation (GWh) | Production as a % of LTA | Actual production (GWh) | LTA generation (GWh) | Production as a % of LTA |
Hydro | 1,769 |  | 2,015 |  | 88 | % | 1,988 |  | 2,015 |  | 99 | % | 1,936 |  | 2,030 |  | 95 | % |  |  |
Wind and Solar | 4,243 |  | 5,387 |  | 79 | % | 4,248 |  | 4,950 |  | 86 | % | 3,898 |  | 4,345 |  | 90 | % |  |  |
Gas | 11,873 |  |  |  | 11,448 |  |  |  | 10,565 |  |  |  |  |  |
Energy Transition | 4,144 |  |  |  | 3,574 |  |  |  | 5,706 |  |  |  |  |  |
Total | 22,029 |  |  |  | 21,258 |  |  |  | 22,105 |  |  |  |  |  |

In addition to adjusted availability, the Company utilizes long-term average production ("LTA generation") as another indicator of performance for the renewable assets whereby actual production levels are compared against the expected long-term average. In the short term, for each of the Hydro and Wind and Solar segments, the conditions will vary from one period to the next. Over longer durations, facilities are expected to produce in line with their long-term averages, which is considered a reliable indicator of performance.
LTA generation is calculated on an annualized basis from the average annual energy yield predicted from our simulation model based on historical resource data performed over a period of typically greater than 25 years.
LTA generation for Energy Transition is not considered as we are currently transitioning these units with the expectation that they will retire by the end of 2025 and the LTA generation for Gas is not applicable as these units are dispatchable and their production is largely dependent on market conditions and merchant demand.

TransAlta Corporation | 2023 Integrated Report | M7

Total production for 2023, increased by 771 GWh or 4 per cent compared to 2022.
Production from the Centralia facility within the Energy Transition segment benefited from fewer planned and unplanned outage hours compared to the prior year and was able to be dispatched during periods of higher merchant pricing for the region.
The Company's Gas segment had a strong performance, resulting in production that was both higher than the prior year as well as higher than expectations for the year. The Gas segment was available during periods of supply tightness, allowing for the Company to operate during periods of peak pricing. The Gas segment was unfavourably impacted by relatively mild weather in the fourth quarter of 2023, as the Company did not experience
the same weather conditions compared to the same period in 2022, which had tighter supply due to the extreme cold weather in Alberta.
Production for our renewables assets for the year ended Dec. 31, 2023, was lower by 224 GWh, or 4 per cent, compared to 2022 and was 81 per cent of LTA generation.
Lower than average renewable resources in the year impacted production in both the Hydro and the Wind and Solar segments. Hydro production was further impacted by lower availability due to increased planned maintenance outages compared to 2022, while the Wind and Solar segment production was positively impacted by the addition of the Garden Plain wind facility, the partial return to service of the Kent Hills wind facility and the addition of the Northern Goldfields solar facilities during the year.
Market Pricing

Year ended Dec. 31, 2023 | 2023 | 2022 | 2021
Alberta spot power price ($/MWh) | 134 |  | 162 |  | 102 |
Mid-Columbia spot power price (US$/MWh) | 76 |  | 82 |  | 49 |
Ontario spot power price ($/MWh) | 28 |  | 47 |  | 30 |
Natural gas price (AECO) per GJ ($) | 2.54 |  | 5.08 |  | 3.39 |

For the year ended Dec. 31, 2023, spot electricity prices in Alberta and the Pacific Northwest were lower compared to 2022. Lower prices in both regions resulted from lower natural gas prices and overall weaker weather-driven demand in the second half of 2023, with notably lower prices due to above normal weather patterns in the fourth quarter of 2023. For Alberta specifically, warm weather in
the fourth quarter resulted in a strong wind resource pattern which, combined with new installed capacity, added supply in the market compared to the prior year.
AECO natural gas prices for the year ended Dec. 31, 2023, were lower compared to 2022 mainly due to improved production and storage levels in Alberta and North America.
Financial Performance review on Consolidated Information

Year ended Dec. 31 |  |  | 2023 |  | 2022 | 2021
Revenues |  |  | 3,355 |  |  | 2,976 |  | 2,721 |
Fuel and purchased power |  |  | 1,060 |  |  | 1,263 |  | 1,054 |
Carbon compliance |  |  | 112 |  |  | 78 |  | 178 |
Operations, maintenance and administration |  |  | 539 |  |  | 521 |  | 511 |
Depreciation and amortization |  |  | 621 |  |  | 599 |  | 529 |
Asset impairment charges (reversals) |  |  | (48) |  |  | 9 |  | 648 |
Interest income |  |  | 59 |  |  | 24 |  | 11 |
Earnings (loss) before income taxes |  |  | 880 |  |  | 353 |  | (380) |
Income tax expense |  |  | 84 |  |  | 192 |  | 45 |
Net earnings (loss) attributable to common shareholders |  |  | 644 |  |  | 4 |  | (576) |
Net earnings attributable to non-controlling interests |  |  | 101 |  |  | 111 |  | 112 |

M8 | TransAlta Corporation | 2023 Integrated Report

Current Year Variance Analysis (2023 versus 2022)
Revenues totalling $3,355 million, increased by $379 million, or 13 per cent, compared to 2022, primarily due to:
•Higher realized and unrealized gains from hedging and derivative positions across the segments, partially offset by
•Lower revenue from merchant sales due to lower spot power prices and production in Alberta.
Fuel and purchased power costs totalling $1,060 million, decreased by $203 million, or 16 per cent, compared to 2022, primarily due to:
•Lower natural gas commodity pricing, partially offset by
•Higher fuel usage in both the Gas and Energy Transition segments.
Carbon compliance costs totalling $112 million, increased by $34 million, or 44 per cent, compared to 2022, primarily due to:
•An increase in the carbon price per tonne from $50 per tonne in 2022 to $65 per tonne in 2023,
•Higher production in the Gas segment and
•No utilization of emission credits to settle GHG obligations as was done in the prior year.
Operations, maintenance and administration ("OM&A") expenses totalling $539 million, increased by $18 million, or 3 per cent, compared to 2022, primarily due to:
•Higher spending on strategic and growth initiatives,
•Higher costs associated with the relocation of the Company's head office and
•Increased costs due to inflationary pressures.
Depreciation and amortization totalling $621 million, increased by $22 million, or 4 per cent, compared to 2022, primarily due to:
•Revisions to useful lives on certain facilities and
•Commercial operation of new facilities.
Asset impairment reversals totalling $48 million, increased by $57 million, or 633 per cent, compared to an asset impairment charge in 2022, primarily due to:
•Decommissioning and restoration provisions for retired assets being favourably impacted by a change in timing of expected cash outflows, partially offset by lower discount rates, resulting in a net impairment reversal of $34 million and
•A Hydro segment impairment reversal of $10 million due to a contract extension and favourable changes in power price assumptions.
Interest income totalling $59 million increased by $35 million, or 146 per cent, compared to 2022, primarily due to higher cash balances and favourable interest rates.
Earnings before income taxes totalling $880 million, increased by $527 million, or 149 per cent, compared to 2022, due to the above noted items.
Income tax expense totalling $84 million, decreased by $108 million, or 56 per cent, compared to 2022, due to a recovery relating to the reversal of previously derecognized Canadian deferred tax assets and lower US non-deductible expenses relating to the US operations, partially offset by higher earnings from Canadian operations.
Net earnings attributable to non-controlling interests totalling $101 million, decreased by $10 million, or 9 per cent, compared to 2022, primarily due to lower net earnings for TA Cogen.

TransAlta Corporation | 2023 Integrated Report | M9

Adjusted EBITDA
For the year ended Dec. 31, 2023, the Company's adjusted EBITDA was $1,632 million as compared to $1,634 million in 2022, a decrease of $2 million. The major factors impacting adjusted EBITDA are summarized in the following table:

| Year ended Dec. 31
Adjusted EBITDA for the year ended Dec. 31, 2022 | 1,634 |
Hydro: lower primarily due to lower ancillary services volumes, lower spot power and ancillary services prices and lower than average water resources, partially offset by realized gains from hedging and sales of environmental attributes. | (68) |
Wind and Solar: lower primarily due to lower environmental attribute revenues, lower spot power pricing in Alberta, lower wind resource across the operating fleets, lower liquidated damages recognized at the Windrise wind facility and higher OM&A, partially offset by the commercial operation of the Garden Plain wind facility, the Northern Goldfields solar facilities and the partial return of service of the Kent Hills wind facilities. | (54) |
Gas: higher primarily due to higher power price hedges partially offsetting the impacts of lower Alberta spot prices, lower natural gas commodity costs and higher production, partially offset by lower thermal revenues, higher carbon prices and higher carbon costs and fuel usage related to production. The Gas fleet significantly exceeded management's expectations. | 172 |
Energy Transition: higher primarily due to higher production from higher availability and higher merchant sales volumes, partially offset by lower market prices compared to the prior year. | 36 |
Energy Marketing: lower primarily due to lower realized settled trades during the year on market positions in comparison to prior year and higher OM&A. Energy Marketing results were in line with management's expectations and performance was consistent with our revised full year financial guidance provided in the second quarter of 2023. | (74) |
Corporate: lower primarily due to increased spending to support strategic and growth initiatives and higher costs associated with the relocation of the Company's head office. | (14) |
Adjusted EBITDA(1) for the year ended Dec. 31, 2023 | 1,632 |

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

M10 | TransAlta Corporation | 2023 Integrated Report

Free Cash Flow
During the second quarter of 2023, the Company revised and increased our 2023 guidance for FCF based on the strong financial performance attained in the first half of the year and our expectations for the balance of the year. For
the year ended Dec. 31, 2023, the Company's FCF decreased by $71 million, or 7 per cent, compared to 2022, and was in line with our revised expected full year financial guidance. The major factors impacting FCF are summarized in the following table:

| Year ended Dec. 31
FCF for the year ended Dec. 31, 2022 | 961 |
Lower adjusted EBITDA: lower FCF due to the items noted in Adjusted EBITDA above. | (2) |
Higher interest income: Higher cash balances and favourable interest rates positively impacting FCF. | 35 |
Lower current income tax expense: Previously restricted non-capital loss carryforwards were utilized to offset taxable income resulting in higher FCF. | 15 |
Higher sustaining capital expenditures: Higher planned major maintenance costs for the Hydro and Gas segments, partially offset by lower planned major maintenance in Wind and Solar and Energy Transition segments, resulting in lower FCF. | (31) |
Higher distributions paid to subsidiaries' non-controlling interests: Related to timing of distributions paid to TA Cogen, partially offset by lower distributions paid to TransAlta Renewables resulting in lower FCF. | (36) |
Lower provisions: Lower provisions being accrued compared to the prior year, with no notable settlements being recorded in either year resulting in lower FCF due to the timing of provisions accrued. | (26) |
Other non-cash items(1) | (12) |
Other(2) | (14) |
FCF(3) for the year ended Dec. 31, 2023 | 890 |

(1)Other non-cash items consists of Alberta market pool incentives, carbon obligation, contract liabilities, and the SunHills royalty onerous contract. Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF section tables in this MD&A for more details.
(2)Other consists of higher realized foreign exchange loss, higher decommissioning and restoration costs settled, higher dividends paid on preferred shares and higher principal payments on lease liabilities. Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF section tables in this MD&A for more details.
(3)FCF is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
Capital Expenditures
We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake sustaining capital expenditures that ensure our facilities operate reliably and safely.

Year ended Dec. 31 | 2023 | 2022 | 2021
Hydro | 41 |  | 35 |  | 26 |
Wind and Solar | 15 |  | 18 |  | 13 |
Gas | 76 |  | 41 |  | 128 |
Energy Transition | 15 |  | 19 |  | 19 |
Corporate | 27 |  | 29 |  | 13 |
Total sustaining capital expenditures | 174 |  | 142 |  | 199 |

Total sustaining capital expenditures in 2023 were $32 million higher compared to 2022, primarily due to:
•Higher planned major maintenance at our Alberta Hydro Assets,
•Higher planned major maintenance at our Sarnia, Sundance Unit 6 and Keephills Units 2 and 3 facilities in the Gas segments, partially offset by
•Lower planned major maintenance in the Wind and Solar segment primarily due to a reduction in major component replacements and
•Lower planned outage work performed in the Energy Transition segment.

TransAlta Corporation | 2023 Integrated Report | M11

Total sustaining capital expenditures in 2022 were $57 million lower compared to 2021, primarily due to:
•Coal-to-gas conversions being completed in 2021, partially offset by
•Higher planned major maintenance in 2022 in the Hydro segment and a higher level of major component replacements in 2022 in the Wind and Solar segment and
•Higher spend on leasehold improvements associated with the planned relocation of the Company's head office.

Year ended Dec. 31 | 2023 | 2022 | 2021
Hydro | 6 |  | 2 |  | 3 |
Wind and Solar | 659 |  | 759 |  | 124 |
Gas | 13 |  | 3 |  | 38 |
Energy Transition | — |  | — |  | 70 |
Corporate(1) | 61 |  | 10 |  | 47 |
Total growth and development expenditures | 739 |  | 774 |  | 282 |

(1)Expenditures related to projects in the development phase are included in the Corporate segment.
In 2023 and 2022, the growth and development expenditures incurred primarily related to:
•The Garden Plain wind facility, which achieved commercial operation in August 2023;
•The Northern Goldfields solar facilities, which achieved commercial operation in November 2023;
•The White Rock wind projects, which are expected to reach commercial operation in the first quarter of 2024;
•The Horizon Hill wind project, which is expected to reach commercial operation in the first quarter of 2024; and
•The Mount Keith 132kV expansion, which is on track to be completed in the first quarter of 2024.
Refer to the Strategic Priorities and Clean Electricity Growth Plan to 2028 section of this MD&A for more details.
Significant and Subsequent Events
Change to Board of Directors
The Honourable Rona Ambrose has decided that she will not stand for re-election and will retire from the Board of Directors ("the Board") following the annual shareholder meeting on April 25, 2024. The Board extends its gratitude for her service to the Company. She has been a valuable contributor to the Board since 2017 and we thank her for her leadership and insights during her tenure, especially as Chair of the Governance, Safety and Sustainability Committee of the Board.
Production Tax Credit ("PTC") Sale Agreements
On Feb. 22, 2024, the Company entered into 10-year transfer agreements with an AA- rated customer for the sale of approximately 80 per cent of the expected PTCs to be generated from the White Rock wind projects and the Horizon Hill wind project. The expected annual average EBITDA from these contracts is approximately $57 million (US$43 million).
Normal Course Issuer Bid ("NCIB") and Automatic Share Purchase Plan ("ASPP")
On May 26, 2023, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.29 per cent of its public float of common shares as at May 17, 2023. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2023, and ends on May 30, 2024, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election.

M12 | TransAlta Corporation | 2023 Integrated Report

On Dec. 19, 2023, the Company entered into an ASPP to facilitate repurchases of TransAlta’s common shares under its NCIB.
Under the ASPP, the Company’s broker may purchase common shares from the effective date of the ASPP until the end of the ASPP. All purchases of common shares made under the ASPP will be included in determining the number of common shares purchased under the NCIB. The ASPP will terminate on the earliest of the date on which: (a) the maximum purchase limits under the ASPP are reached; (b) Feb. 24, 2024; or (c) the Company terminates the ASPP in accordance with its terms.
During the year ended Dec. 31, 2023, the Company purchased and cancelled a total of 7,537,500 common shares, at an average price of $11.49 per common share, for a total cost of $87 million.
The NCIB provides the Company with a capital allocation alternative with a view to ensuring long-term shareholder value. TransAlta’s Board of Directors and management believe that, from time to time, the market price of the common shares might not be reflective of the underlying value and purchases of common shares for cancellation under the NCIB may provide an opportunity to enhance shareholder value.
Northern Goldfields Solar Achieves Commercial Operation
On Nov. 22, 2023, the Company announced that the 48 MW Northern Goldfields solar and battery storage facilities achieved commercial operation. The facilities consist of the 27 MW Mount Keith solar facility, the 11 MW Leinster solar facility, the 10 MW Leinster battery energy storage system and interconnecting transmission infrastructure, all of which are now integrated into TransAlta’s existing 169 MW Southern Cross Energy North remote network in Western Australia. The facilities are fully contracted to BHP Nickel West for a term of 15 years and are expected to reduce BHP's scope 2 emissions at Mount Keith and Leinster by 12 per cent annually.
TransAlta Announces Growth Targets to 2028 and Declares 9% Dividend Increase
On Nov. 21, 2023, the Company held its 2023 Investor Day event and announced it had updated its strategic growth targets to 2028, which strengthens the Company’s commitment to being a leader in clean electricity by delivering customer-centred power solutions. The growth targets include:
•Adding up to 1.75 GW of new capacity to the Company's fleet by investing approximately $3.5 billion to develop, construct or acquire new assets through to the end of 2028,
•A focus on customer-centred renewables and storage through the development of its 4.8 GW development pipeline and
•Expanding the Company’s development pipeline to 10 GW by 2028.
The Board approved an annualized $0.02 per share increase, or 9 per cent increase to our common share dividend and declared a dividend of $0.06 per common share to be paid on April 1, 2024. The quarterly dividend of $0.06 per common share represents an annualized dividend of $0.24 per common share.
TransAlta Enters Joint Development Agreement with Hancock
On Nov. 21, 2023, the Company entered into a joint development agreement with Hancock Prospecting Pty Ltd. (“Hancock”), Australia’s fourth largest iron ore producer. This arrangement will build on TransAlta’s expertise in supplying power to remote mining operations in Western Australia. TransAlta will work collaboratively with Hancock to define and supply behind-the-fence generation solutions for Hancock in the Port Hedland area.
TransAlta to Acquire Heartland Generation from Energy Capital Partners
On Nov. 2, 2023, the Company announced that it had entered into a definitive share purchase agreement with an affiliate of Energy Capital Partners, the parent of Heartland Generation Ltd. and Alberta Power (2000) Ltd. (collectively, "Heartland"), pursuant to which TransAlta will acquire Heartland and its entire business operations in Alberta and British Columbia. The acquisition will add 10 facilities to TransAlta’s fleet, totalling 1,844 MW of new capacity. The transaction is expected to close in the first half of 2024, subject to customary closing conditions, including receipt of regulatory approvals.
The purchase price for the acquisition is $390 million, subject to working capital and other adjustments, as well as the assumption of $268 million of low-cost debt. The Company will finance the transaction using cash on hand and drawing on its credit facilities.
The assets are expected to add approximately $115 million of average annual EBITDA including synergies. Approximately 55 per cent of revenues are under contract with highly creditworthy counterparties, with a weighted-average remaining contract life of 16 years. Corporate pre-tax synergies are expected to exceed $20 million annually.
The acquisition will competitively position the Company to respond to the highly dynamic and shifting electricity landscape in Alberta given the expected significant increase in renewables and other large baseload generation coming online in the next several years in the

TransAlta Corporation | 2023 Integrated Report | M13

province. The Clean Electricity Growth Plan continues to be at the heart of our strategy and is primarily focused on meeting the future needs of our customers with clean electricity solutions.
TransAlta Corporation Completes Acquisition of TransAlta Renewables Inc.
On Oct. 5, 2023, the Company completed the acquisition of TransAlta Renewables pursuant to the terms of the previously announced arrangement agreement between the parties (the "Arrangement"). TransAlta acquired all of the outstanding common shares of TransAlta Renewables ("RNW Shares") not already owned, directly or indirectly, by TransAlta and certain of its affiliates, resulting in TransAlta Renewables becoming a wholly owned subsidiary of the Company. Prior to the Arrangement, TransAlta and its affiliates collectively held 160,398,217 RNW Shares, representing 60.1 per cent of the issued and outstanding RNW Shares, with the remaining 106,510,884 RNW Shares held by TransAlta Renewables shareholders ("RNW Shareholders") other than TransAlta and its affiliates.
The Arrangement was approved by RNW Shareholders at a special meeting of shareholders held on Sept. 26, 2023, and by the Court of King’s Bench of Alberta on Oct. 4, 2023. The consideration paid totalled $1.3 billion which consisted of $800 million of cash and approximately 46 million common shares of the Company.
The closing of the acquisition of TransAlta Renewables represents a key milestone for the Company and the simplified and unified corporate structure positions it well for future success.
TransAlta Tops Newsweek's Inaugural List of World's Most Trustworthy Companies
On Sept. 14, 2023, the Company announced that it ranked first on Newsweek's inaugural “World's Most Trustworthy Companies 2023” list for the Energy and Utilities category. The list identifies the top 1,000 companies in 21 countries and across 23 industries. Newsweek’s 2023 World’s Most Trustworthy Companies were chosen based on a holistic approach to evaluating three pillars of public trust – customers, investors and employees. The list was compiled based on an extensive survey of over 70,000 participants, gathering 269,000 evaluations of companies that people trust as a customer, as an investor or as an employee.
Garden Plain Wind Facility Achieved Commercial Operation
In August 2023, the Garden Plain wind facility was commissioned adding 130 MW to our gross installed capacity. The facility is fully contracted with Pembina
Pipeline Corporation and PepsiCo Canada, with a weighted average contract life of approximately 17 years.
Tent Mountain Pumped Hydro Development Project
On April 24, 2023, the Company acquired a 50 per cent interest in the Tent Mountain Renewable Energy Complex (“Tent Mountain”), an early-stage 320 MW pumped storage hydro development project located in southwest Alberta, from Evolve Power Ltd. ("Evolve"), formerly known as Montem Resources Limited. The acquisition includes land rights, fixed assets and intellectual property associated with Tent Mountain.
The Company and Evolve own the Tent Mountain project within a special purpose partnership that is jointly managed, with the Company acting as project developer. The partnership is actively seeking an offtake agreement for the energy and environmental attributes that will be generated by the facility.
Annual Shareholder Meeting
On April 28, 2023, the Company held its annual meeting of shareholders. All director nominees were elected to the Board, including Candace MacGibbon, a new member to the Board.
The Company also received strong support on all other items of business, including say-on-pay and an amendment to the Company's Share Unit Plan.

M14 | TransAlta Corporation | 2023 Integrated Report

Segmented Financial Performance and Operating Results
Segmented information is prepared on the same basis that the Company manages its business, evaluates financial results and makes key operating decisions. The following table reflects the summary financial information on a consolidated basis for the year ended Dec. 31:

| Adjusted EBITDA(1)
Year ended Dec. 31 | 2023 | 2022 | 2021
Hydro | 459 |  | 527 |  | 322 |
Wind and Solar | 257 |  | 311 |  | 262 |
Gas | 801 |  | 629 |  | 488 |
Energy Transition | 122 |  | 86 |  | 133 |
Energy Marketing | 109 |  | 183 |  | 166 |
Corporate | (116) |  | (102) |  | (85) |
Total adjusted EBITDA(1) | 1,632 |  | 1,634 |  | 1,286 |
Earnings (loss) before income taxes | 880 |  | 353 |  | (380) |

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

TransAlta Corporation | 2023 Integrated Report | M15

Hydro

Year ended Dec. 31 |  |  | 2023 | 2022 | Change | 2021 | Change
Gross installed capacity (MW)(1) |  |  | 922 |  | 922 |  | — |  | — | % | 925 | (3) |  | — | %
LTA generation (GWh)(2) |  |  | 2,015 |  | 2,015 |  | — |  | — | % | 2,030 |  | (15) |  | (1) | %
Availability (%) |  |  | 90.8 |  | 96.7 |  | (5.9) |  | (6) | % | 92.4 |  | 4.3 |  | 5 | %
Production |  |  |  |  |  |  |  |  |
Contract production (GWh) |  |  | 277 |  | 323 |  | (46) |  | (14) | % | 434 |  | (111) |  | (26) | %
Merchant production (GWh) |  |  | 1,492 |  | 1,665 |  | (173) |  | (10) | % | 1,502 |  | 163 |  | 11 | %
Total energy production (GWh) |  |  | 1,769 |  | 1,988 |  | (219) |  | (11) | % | 1,936 |  | 52 |  | 3 | %
Ancillary service volumes (GWh)(3) |  |  | 2,582 |  | 3,124 |  | (542) |  | (17) | % | 2,897 |  | 227 |  | 8 | %
Alberta Hydro Assets revenues(4)(5) |  |  | 291 |  | 328 |  | (37) |  | (11) | % | 185 |  | 143 |  | 77 | %
Other Hydro Assets and other revenues(4)(6) |  |  | 51 |  | 42 |  | 9 |  | 21 | % | 41 |  | 1 |  | 2 | %
Alberta Hydro ancillary services revenues(3) |  |  | 173 |  | 236 |  | (63) |  | (27) | % | 160 |  | 76 |  | 48 | %
Environmental attribute revenues |  |  | 14 |  | 1 |  | 13 |  | 1300 | % | 1 |  | — |  | — | %
Total gross revenues |  |  | 529 |  | 607 |  | (78) |  | (13) | % | 387 |  | 220 |  | 57 | %
Net payment relating to Alberta Hydro PPA |  |  | — |  | — |  | — |  | — | % | (4) |  | 4 |  | (100) | %
Revenues(7) |  |  | 529 |  | 607 |  | (78) |  | (13) | % | 383 |  | 224 |  | 58 | %
Fuel and purchased power |  |  | 19 |  | 22 |  | (3) |  | (14) | % | 16 |  | 6 |  | 38 | %
Gross margin(8) |  |  | 510 |  | 585 |  | (75) |  | (13) | % | 367 |  | 218 |  | 59 | %
OM&A |  |  | 48 |  | 55 |  | (7) |  | (13) | % | 42 |  | 13 |  | 31 | %
Taxes, other than income taxes |  |  | 3 |  | 3 |  | — |  | — | % | 3 |  | — |  | — | %
Adjusted EBITDA(8) |  |  | 459 |  | 527 |  | (68) |  | (13) | % | 322 |  | 205 |  | 64 | %
Supplemental Information: |  |  |  |  |  |  |  |  |
Gross revenues per MWh |  |  |  |  |  |  |  |  |
Alberta Hydro Assets energy ($/MWh)(4)(5) |  |  | 175 |  | 197 |  | (22) |  | (11) | % | 123 | 74 |  | 60 | %
Alberta Hydro Assets ancillary ($/MWh)(3) |  |  | 67 |  | 76 |  | (9) |  | (12) | % | 55 | 21 |  | 38 | %

(1)In the fourth quarter of 2022, the Company closed the sale of two Hydro assets resulting in a reduction in capacity of 3 MW.
(2)2022 and 2021 LTA generation revised for consistency with calculation methodology used in 2023.
(3)Ancillary services as described in the AESO Consolidated Authoritative Document Glossary.
(4)Alberta Hydro Assets include 13 hydro facilities on the Bow and North Saskatchewan river systems. Other Hydro assets includes our hydro facilities in BC and Ontario, hydro facilities in Alberta (other than the Alberta Hydro Assets) and transmission revenues.
(5)The Company entered into forward hedges for the first and third quarter of 2023 that are included in the Alberta Hydro Asset revenues.
(6)Other revenue includes revenues from our transmission business and other contractual arrangements, including the flood mitigation agreement with the Government of Alberta and Black Start services.
(7)For details of the adjustments to revenues included in adjusted EBITDA refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.
(8)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.

M16 | TransAlta Corporation | 2023 Integrated Report

2023
Revenues for the year ended Dec. 31, 2023, decreased compared to 2022, primarily due to:
•Lower ancillary services volumes due to the AESO procuring lower volumes given its decision to reduce the cumulative volume of imports into Alberta,
•Lower spot power prices and ancillary services prices in the Alberta market and
•Lower production due to lower availability from planned outages at our Alberta Hydro Assets and lower than average water resources, partially offset by
•Realized gains from our hedging strategy for the Alberta Hydro Assets and
•Sales of environmental attributes driven by an increase in emission credit sales.
Adjusted EBITDA for the year ended Dec. 31, 2023, decreased compared to 2022, primarily due to:
•Lower revenues as explained by the factors above.
For further discussion on the Alberta market conditions and pricing, refer to the Alberta Electricity Portfolio section of this MD&A.
2022
Revenues for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:
•Higher merchant and ancillary service prices and volumes in the Alberta market,
•Higher production and higher availability due to lower planned and unplanned outages at our Alberta Hydro Assets and
•Higher ancillary service volumes due to higher availability and demand.
Adjusted EBITDA for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:
•Higher revenues as explained by the factors above, partially offset by
•Higher OM&A costs for the year related to increased insurance premiums for updated replacement value coverage and the Company's performance-related incentive accruals.

TransAlta Corporation | 2023 Integrated Report | M17

Wind and Solar

Year ended Dec. 31 |  |  | 2023 |  | 2022 |  | Change | 2021 | Change
Gross installed capacity (MW)(1) |  |  | 2,084 |  |  | 1,906 |  | 178 |  | 9 | % | 1,906 |  | — |  | — | %
LTA generation (GWh) |  |  | 5,387 |  |  | 4,950 |  | 437 |  | 9 | % | 4,345 |  | 605 |  | 14 | %
Availability (%) |  |  | 86.9 |  |  | 83.8 |  | 3.1 |  | 4 | % | 91.9 |  | (8.1) |  | (9) | %
Production |  |  |  |  |  |  |  |  |  |  |
Contract production (GWh) |  |  | 3,095 |  |  | 3,182 |  |  | (87) |  | (3) | % | 2,850 |  | 332 |  | 12 | %
Merchant production (GWh) |  |  | 1,148 |  |  | 1,066 |  |  | 82 |  | 8 | % | 1,048 |  | 18 |  | 2 | %
Total production (GWh) |  |  | 4,243 |  |  | 4,248 |  |  | (5) |  | — | % | 3,898 |  | 350 |  | 9 | %
Wind and Solar revenues |  |  | 347 |  |  | 357 |  |  | (10) |  | (3) | % | 320 |  | 37 |  | 12 | %
Environmental attribute revenues |  |  | 26 |  |  | 50 |  |  | (24) |  | (48) | % | 28 |  | 22 |  | 79 | %
Revenues(2) |  |  | 373 |  |  | 407 |  |  | (34) |  | (8) | % | 348 |  | 59 |  | 17 | %
Fuel and purchased power |  |  | 30 |  |  | 31 |  |  | (1) |  | (3) | % | 17 |  | 14 |  | 82 | %
Carbon compliance |  |  | — |  |  | 1 |  |  | (1) |  | (100) | % | — |  | 1 |  | 100 | %
Gross margin(3) |  |  | 343 |  |  | 375 |  |  | (32) |  | (9) | % | 331 |  | 44 |  | 13 | %
OM&A |  |  | 80 |  |  | 68 |  |  | 12 |  | 18 | % | 59 |  | 9 |  | 15 | %
Taxes, other than income taxes |  |  | 12 |  |  | 12 |  |  | — |  | — | % | 10 |  | 2 |  | 20 | %
Net other operating income(2) |  |  | (6) |  |  | (16) |  |  | 10 |  | (63) | % | — |  | (16) |  | (100) | %
Adjusted EBITDA(3) |  |  | 257 |  |  | 311 |  |  | (54) |  | (17) | % | 262 |  | 49 |  | 19 | %
Supplemental information: |  |  |  |  |  |  |  |  |  |  |
Kent Hills wind rehabilitation expenditures(4) |  |  | 87 |  |  | 77 |  |  | 10 |  | 13 | % | — |  | 77 |  | 100 | %
Insurance proceeds - Kent Hills |  |  | (1) |  |  | (7) |  |  | 6 |  | (86) | % | — |  | (7) |  | (100) | %

(1)Gross installed capacity and availability for 2023 includes the 130 MW Garden Plain wind facility that achieved commercial operation in August 2023 and the 48 MW Northern Goldfields solar facilities that achieved commercial operation in November 2023.
(2)For details of the adjustments to revenues and net other operating income included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(3)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.
(4)The Kent Hills wind facilities rehabilitation capital expenditures are segregated from the sustaining capital expenditures due to the extraordinary nature of the expenditures.

M18 | TransAlta Corporation | 2023 Integrated Report

2023
Revenues for the year ended Dec. 31, 2023, decreased compared to 2022 primarily due to:
•Lower environmental attribute revenues driven by a reduction of offsets and emission credit sales,
•Lower spot power pricing in Alberta and
•Weaker than long-term average wind resource across the operating fleets, partially offset by
•Commercial operation of the Garden Plain wind facility and the Northern Goldfield Solar facilities in the third and fourth quarter, respectively and
•The partial return to service of the Kent Hills wind facilities.
Adjusted EBITDA for the year ended Dec. 31, 2023, decreased compared to the same period in 2022, primarily due to:
•Lower revenues as explained by the factors above,
•Higher OM&A related to salary escalations, higher insurance costs and long-term service agreement escalations and
•Lower liquidated damages recognized at the Windrise wind facility.
2022
Revenues for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:
•Higher production from the addition of the Windrise wind facility and the acquisition of the North Carolina Solar facilities in the fourth quarter of 2021 and higher wind resources in Eastern Canada,
•Higher realized merchant and spot power pricing in Alberta and
•Higher environmental attribute revenue, partially offset by
•Lower availability as a result of the extended outage at the Kent Hills 1 and 2 wind facilities.
Adjusted EBITDA for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:
•Higher revenue as explained by the factors above and
•The recognition of liquidated damages recoverable from turbine availability being below the contractual target at the Windrise wind facility, partially offset by
•Higher fuel and purchased power from increases in transmission rates,
•Higher OM&A related to the addition of the Windrise wind and North Carolina Solar facilities during the year and
•A one-time favourable adjustment as a result of the AESO transmission line loss ruling that was included in 2021.

TransAlta Corporation | 2023 Integrated Report | M19

Gas

Year ended Dec. 31 |  |  | 2023 |  | 2022 |  | Change | 2021 | Change
Gross installed capacity (MW) |  |  | 3,084 |  |  | 3,084 |  |  | — |  | — | % | 3,084 |  | — |  | — | %
Availability (%) |  |  | 91.6 |  |  | 94.6 |  |  | (3.0) |  | (3) | % | 85.7 |  | 8.9 |  | 10 | %
Production |  |  |  |  |  |  |  |  |  |  |
Contract sales volume (GWh) |  |  | 4,172 |  |  | 3,609 |  |  | 563 |  | 16 | % | 3,622 |  | (13) |  | — | %
Merchant sales volume (GWh) |  |  | 7,889 |  |  | 7,927 |  |  | (38) |  | — | % | 7,084 |  | 843 |  | 12 | %
Purchased power (GWh)(1) |  |  | (188) |  |  | (88) |  |  | (100) |  | 114 | % | (141) |  | 53 |  | (38) | %
Total production (GWh) |  |  | 11,873 |  |  | 11,448 |  |  | 425 |  | 4 | % | 10,565 |  | 883 |  | 8 | %
Revenues(2) |  |  | 1,525 |  |  | 1,521 |  |  | 4 |  | — | % | 1,126 |  | 395 |  | 35 | %
Fuel and purchased power(2) |  |  | 449 |  |  | 637 |  |  | (188) |  | (30) | % | 374 |  | 263 |  | 70 | %
Carbon compliance |  |  | 112 |  |  | 83 |  |  | 29 |  | 35 | % | 118 |  | (35) |  | (30) | %
Gross margin(3) |  |  | 964 |  |  | 801 |  |  | 163 |  | 20 | % | 634 |  | 167 |  | 26 | %
OM&A |  |  | 192 |  |  | 195 |  |  | (3) |  | (2) | % | 173 |  | 22 |  | 13 | %
Taxes, other than income taxes |  |  | 11 |  |  | 15 |  |  | (4) |  | (27) | % | 13 |  | 2 |  | 15 | %
Net other operating income |  |  | (40) |  |  | (38) |  |  | (2) |  | 5 | % | (40) |  | 2 |  | (5) | %
Adjusted EBITDA(3) |  |  | 801 |  |  | 629 |  |  | 172 |  | 27 | % | 488 |  | 141 |  | 29 | %

(1)Power required to fulfill contractual obligations during planned and unplanned outages is included in purchased power.
(2)For details of the adjustments to revenues and fuel and purchased power included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(3)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
2023
Revenues for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:
•Higher production due to the fleet being available during periods of supply tightness and peak pricing and
•Higher power price hedges, partially offsetting the impact of lower Alberta spot prices, partially offset by
•Lower thermal revenues due to lower steam revenue pricing at the Sarnia facility compared to 2022.
Adjusted EBITDA for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:
•Lower natural gas commodity costs for the Alberta gas assets and
•Higher revenues explained above, partially offset by
•Higher carbon costs and fuel usage related to production with the utilization of emission credits to settle a portion of the GHG obligation in 2022 and
•Carbon price increases from $50 per tonne to $65 per tonne, impacting our Canadian gas assets.
The Gas fleet significantly exceeded management's expectations for the segment.
2022
Revenues for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:
•Higher production due to higher availability and dispatch optimization of the Alberta assets,
•Higher realized energy prices through dispatch optimization of our Alberta assets, net of hedging and
•Higher Ontario merchant pricing and steam generation.
Adjusted EBITDA for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:
•Higher revenues explained above and
•Lower carbon compliance costs due to reductions in GHG emissions as a result of operating exclusively on natural gas in Alberta rather than coal, and the utilization of compliance credits to settle a portion of the GHG obligation, partially offset by
•Increased natural gas consumption on recently converted units and higher natural gas prices,
•Carbon price increases from $35 per tonne to $50 per tonne and
•Higher OM&A due to the Company's performance-related incentive accruals and increased general operating expenses.

M20 | TransAlta Corporation | 2023 Integrated Report

Energy Transition

Year ended Dec. 31 |  |  | 2023 |  | 2022 |  | Change | 2021 | Change
Gross installed capacity (MW)(1) |  |  | 671 |  |  | 671 |  |  | — |  | — | % | 1,472 |  | (801) |  | (54) | %
Availability (%) |  |  | 79.8 |  |  | 77.2 |  |  | 2.6 |  | 3 | % | 75.3 |  | 1.9 |  | 3 | %
Adjusted availability (%)(2) |  |  | 79.8 |  |  | 79.0 |  |  | 0.8 |  | 1 | % | 78.8 |  | 0.2 |  | — | %
Production |  |  |  |  |  |  |  |  |  |  |
Contract sales volume (GWh) |  |  | 3,329 |  |  | 3,329 |  |  | — |  | — | % | 3,329 |  | — |  | — | %
Merchant sales volume (GWh) |  |  | 4,417 |  |  | 3,951 |  |  | 466 |  | 12 | % | 6,052 |  | (2,101) |  | (35) | %
Purchased power (GWh)(3) |  |  | (3,602) |  |  | (3,706) |  |  | 104 |  | (3) | % | (3,675) |  | (31) |  | 1 | %
Total production (GWh) |  |  | 4,144 |  |  | 3,574 |  |  | 570 |  | 16 | % | 5,706 |  | (2,132) |  | (37) | %
Revenues(4) |  |  | 746 |  |  | 724 |  |  | 22 |  | 3 | % | 728 |  | (4) |  | (1) | %
Fuel and purchased power |  |  | 557 |  |  | 566 |  |  | (9) |  | (2) | % | 432 |  | 134 |  | 31 | %
Carbon compliance |  |  | — |  |  | (1) |  |  | 1 |  | (100) | % | 60 |  | (61) |  | (102) | %
Gross margin(5) |  |  | 189 |  |  | 159 |  |  | 30 |  | 19 | % | 236 |  | (77) |  | (33) | %
OM&A |  |  | 64 |  |  | 69 |  |  | (5) |  | (7) | % | 97 |  | (28) |  | (29) | %
Taxes, other than income taxes |  |  | 3 |  |  | 4 |  |  | (1) |  | (25) | % | 6 |  | (2) |  | (33) | %
Adjusted EBITDA(5) |  |  | 122 |  |  | 86 |  |  | 36 |  | 42 | % | 133 |  | (47) |  | (35) | %
Supplemental information: |  |  |  |  |  |  |  |  |  |  |
Highvale mine reclamation spend |  |  | 15 |  |  | 12 |  |  | 3 |  | 25 | % | 6 | 6 |  | 100 | %
Centralia mine reclamation spend |  |  | 13 |  |  | 16 |  |  | (3) |  | (19) | % | 9 | 7 |  | 78 | %

(1)The gross installed capacity for 2023 and 2022, excludes Keephills Unit 1 (395 MW retired on Dec. 31, 2021) and Sundance Unit 4 (406 MW retired on March 31, 2022).
(2)Adjusted for dispatch optimization.
(3)All of the power produced by Centralia is sold by the Energy Marketing segment for physical market delivery, which is shown as merchant sales volumes. Power required to fulfil contractual obligations is included in purchased power. Total production from the facility includes the net result of merchant sales volumes and purchased power.
(4)For details of the adjustments to revenues included in adjusted EBITDA refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(5)Adjusted EBITDA and gross margin are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
2023
Revenues for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:
•Higher production from higher availability due to lower planned and unplanned outages at Centralia Unit 2 and
•Less economic dispatch leading to higher merchant sales volumes, partially offset by
•Lower market prices.
Adjusted EBITDA for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:
•Higher revenues as explained by the factors above,
•Lower purchased power costs due to lower pricing and increased volumes of production and
•Lower OM&A expenses due to the retirement of Sundance Unit 4 in the first quarter of 2022.
Mine reclamation spend for the year ended Dec. 31, 2023, was consistent compared to 2022.
2022
Revenues for the year ended Dec. 31, 2022, decreased compared to 2021, primarily due to:
•Lower production due to the retirements of the Keephills Unit 1 and Sundance Unit 4, partially offset by
•Increased production from higher availability at Centralia Unit 2 from lower planned and unplanned outages and
•Higher merchant and contract prices at Centralia.
Adjusted EBITDA for the year ended Dec. 31, 2022, decreased compared to 2021 primarily due to:
•Lower revenues as explained by the factors above and
•Higher purchased power costs during outages at Centralia, partially offset by

TransAlta Corporation | 2023 Integrated Report | M21

•Lower OM&A as a result of lower operating costs relating to retirements on the coal fleet in 2021 and
•Lower carbon costs in Alberta related to the retirements on the coal fleet, thereby reducing emissions generated.
Mine reclamation spend for the Highvale and Centralia mines increased compared to 2021, primarily due to the advancement of reclamation activities.
Energy Marketing

Year ended Dec. 31 |  |  | 2023 | 2022 | Change | 2021 | Change
Revenues(1) |  |  | 152 |  | 218 |  | (66) |  | (30) | % | 202 |  | 16 |  | 8 | %
OM&A |  |  | 43 |  | 35 |  | 8 |  | 23 | % | 36 |  | (1) |  | (3) | %
Adjusted EBITDA(2) |  |  | 109 |  | 183 |  | (74) |  | (40) | % | 166 |  | 17 |  | 10 | %

(1)For details of the adjustments to revenues included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A. Adjusted EBITDA is not defined and has no standardized meaning under IFRS.
(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
2023
Adjusted EBITDA for the year ended Dec. 31, 2023, decreased compared to 2022. This was in line with management's expectations, but lower year over year, primarily due to:
•Lower realized settled trades during the year on market positions in comparison to the prior year and
•OM&A increased mainly due to higher incentives related to revenues before adjustments.
The Company was able to capitalize on volatility in the trading of both physical and financial power and gas products across North American deregulated markets while maintaining the overall risk profile of the business unit.
2022
Adjusted EBITDA for the year ended Dec. 31, 2022, increased compared to 2021, primarily due to:
•Higher realized settled trades during the year on market positions in comparison to prior year and
•The Company capitalizing on short-term volatility in the trading markets without materially changing the risk profile of the business unit.
Corporate

Year ended Dec. 31 |  |  | 2023 |  | 2022 |  | Change | 2021 | Change
OM&A |  |  | 115 |  |  | 101 |  |  | 14 |  | 14 | % | 84 |  | 17 |  | 20 | %
Taxes, other than income taxes |  |  | 1 |  |  | 1 |  |  | — |  | — | % | 1 |  | — |  | — | %
Adjusted EBITDA(1) |  |  | (116) |  |  | (102) |  |  | (14) |  | 14 | % | (85) |  | (17) |  | 20 | %

(1)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
2023
Adjusted EBITDA for the year ended Dec. 31, 2023, decreased compared to 2022, primarily due to:
•Increased spending to support strategic and growth initiatives,
•Higher costs associated with the relocation of the Company's head office and
•Increased costs due to inflationary pressures.
2022
Adjusted EBITDA for the year ended Dec. 31, 2022, decreased compared to 2021, primarily due to:
•Higher incentive accruals reflecting the Company's performance;
•No additional receipts of Canada Emergency Wage Subsidy proceeds as occurred in 2021 and
•Higher losses on the total return swap.

M22 | TransAlta Corporation | 2023 Integrated Report

Performance by Segment with Supplemental Geographical Information
The following table provides adjusted EBITDA performance of our facilities across the regions we operate in:

Year ended Dec. 31, 2023 |  | Hydro | Wind & Solar | Gas | Energy Transition | Energy Marketing | Corporate | Total
Alberta |  | 451 |  | 77 |  | 571 |  | (10) |  | 109 |  | (116) |  | 1,082 |
Canada, excluding Alberta |  | 8 |  | 95 |  | 89 |  | — |  | — |  | — |  | 192 |
US |  | — |  | 84 |  | 10 |  | 132 |  | — |  | — |  | 226 |
Australia |  | — |  | 1 |  | 131 |  | — |  | — |  | — |  | 132 |
Adjusted EBITDA(1) |  | 459 |  | 257 |  | 801 |  | 122 |  | 109 |  | (116) |  | 1,632 |
Earnings before income taxes |  |  |  |  |  |  |  | 880 |
Year ended Dec. 31, 2022 |  | Hydro | Wind & Solar | Gas | Energy Transition | Energy Marketing | Corporate | Total
Alberta |  | 515 |  | 114 |  | 404 |  | (18) |  | 183 |  | (102) |  | 1,096 |
Canada, excluding Alberta |  | 12 |  | 106 |  | 87 |  | — |  | — |  | — |  | 205 |
US |  | — |  | 91 |  | 8 |  | 104 |  | — |  | — |  | 203 |
Australia |  | — |  | — |  | 130 |  | — |  | — |  | — |  | 130 |
Adjusted EBITDA(1) |  | 527 |  | 311 |  | 629 |  | 86 |  | 183 |  | (102) |  | 1,634 |
Earnings before income taxes |  |  |  |  |  |  |  | 353 |

(1)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Presenting this from period to period provides management and investors with the ability to evaluate earnings (loss) trends more readily in comparison with prior periods’ results. Refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. Also, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
Optimization of the Alberta Portfolio
Our merchant exposure is primarily in Alberta, where 53 per cent of our capacity is located, and 75 per cent of our Alberta assets are available to participate in the merchant market. Our portfolio of merchant assets in Alberta consists of hydro facilities, wind facilities, a battery storage facility and natural gas generation facilities.
Generating capacity in Alberta is subject to market forces, rather than rate regulation. Power from commercial generation is cleared through a wholesale electricity market. Power is dispatched in accordance with an economic merit order administered by the AESO, based upon offers by generators to sell power in the real-time energy-only market. Our merchant Alberta fleet operates under this framework and we internally manage our offers to sell power.
Optimization of portfolio performance in the Alberta merchant market is driven by the diversity of fuel types and enables portfolio management. It also provides us with capacity that can be monetized as ancillary services or dispatched into the energy market during times of supply tightness. A significant portion of the thermal generation capacity in the portfolio has been hedged to provide cash
flow certainty. The Company's hedging strategy includes maintaining a significant base of commercial and industrial customers and is supplemented with financial hedges. In 2023, 78 per cent of our energy production in Alberta was sold under long-term contracts or fixed price hedges.
The Alberta hydro fleet provides ancillary services and grid reliability products such as Black Start service in the event of a system-wide blackout in the province and drought mitigation by systematically regulating river flows. Our Alberta wind and hydro fleets provide a steady stream of environmental credits to meet ESG goals.
During 2023, the Company entered into a definitive share purchase agreement relating to Heartland Generation Ltd. and Alberta Power (2000) Ltd. (collectively "Heartland") and expects to close the transaction in the first half of 2024, subject to certain customary closing conditions being met. The Heartland acquisition will further expand our portfolio capabilities. The fast-ramping nature of certain of the Heartland units will be ideally positioned to capture expected price swings and periodic higher realized prices in the Alberta market.

TransAlta Corporation | 2023 Integrated Report | M23

| 2023 | 2022 | 2021 |
Year ended Dec. 31 | Hydro | Wind & Solar | Gas | Energy Transition | Total | Hydro | Wind & Solar | Gas | Energy Transition | Total | Hydro | Wind & Solar | Gas | Energy Transition | Total |
Gross installed capacity (MW) | 834 |  | 766 |  | 1,960 |  | — |  | 3,560 |  | 834 |  | 636 |  | 1,960 |  | — |  | 3,430 |  | 834 |  | 636 |  | 1,960 |  | 801 |  | 4,231 |  |
Total production (GWh) | 1,492 |  | 1,907 |  | 8,360 |  | — |  | 11,759 |  | 1,665 |  | 1,686 |  | 8,106 |  | 19 |  | 11,476 |  | 1,586 |  | 1,319 |  | 7,281 |  | 2,591 |  | 12,777 |  |
Contract production (GWh) | — |  | 774 |  | 861 |  | — |  | 1,635 |  | — |  | 620 |  | 526 |  | — |  | 1,146 |  | — |  | 271 |  | 509 |  | — |  | 780 |  |
Merchant production (GWh) | 1,492 |  | 1,133 |  | 7,499 |  | — |  | 10,124 |  | 1,665 |  | 1,066 |  | 7,580 |  | 19 |  | 10,330 |  | 1,586 |  | 1,048 |  | 6,772 |  | 2,591 |  | 11,997 |  |
Hedged production (GWh) | 378 |  | — |  | 7,172 |  | — |  | 7,550 |  | — |  | — |  | 7,228 |  | — |  | 7,228 |  | — |  | — |  | 6,992 |  | — |  | 6,992 |  |
Production contracted or hedged (%) | 25 | % | 41 | % | 96 | % | — | % | 78 | % | — | % | 37 | % | 96 | % | — | % | 73 | % | — | % | 21 | % | 103 | % | — | % | 61 | % |
Revenues(1) ($) | 509 |  | 130 |  | 1,083 |  | 5 |  | 1,727 |  | 583 |  | 155 |  | 989 |  | 6 |  | 1,733 |  | 358 |  | 97 |  | 674 |  | 257 |  | 1,386 |  |
Fuel and purchased power ($) | 17 |  | 20 |  | 336 |  | — |  | 373 |  | 18 |  | 21 |  | 442 |  | 5 |  | 486 |  | 13 |  | 9 |  | 258 |  | 92 |  | 372 |  |
Carbon compliance ($) | — |  | — |  | 106 |  | — |  | 106 |  | — |  | 1 |  | 70 |  | (1) |  | 70 |  | — |  | — |  | 96 |  | 60 |  | 156 |  |
Gross margin ($) | 492 |  | 110 |  | 641 |  | 5 |  | 1,248 |  | 565 |  | 133 |  | 477 |  | 2 |  | 1,177 |  | 345 |  | 88 |  | 320 |  | 105 |  | 858 |  |

(1)Revenues have been adjusted to exclude the impact of unrealized mark-to-market gains or losses and to include realized gains and losses on closed exchange positions.
Total production for the year ended Dec. 31, 2023, was 11,759 GWh compared to 11,476 GWh of electricity in 2022. The increase of 283 GWh, or 2 per cent, was primarily due to:
•The commercial operation of the Garden Plain wind facility in the third quarter of 2023,
•Higher production from our Gas assets due to strong market conditions in the first half of 2023, partially offset by
•Lower water resources in the Alberta Hydro assets.
Hedged production for the year ended Dec. 31, 2023, increased compared to 2022, primarily due to:
•The opportunity to secure additional margins with strategic hedges for the hydro assets.
Gross margin for the year ended Dec. 31, 2023, was $1,248 million compared to $1,177 million in 2022. The increase of $71 million, or 6 per cent, was primarily due to:
•Higher power price hedges, partially offsetting the impacts of lower Alberta spot prices and
•Lower natural gas prices compared to 2022, partially offset by
•Lower ancillary services revenues due to the AESO procuring lower volumes given its decision to reduce the cumulative volume of imports into Alberta.

M24 | TransAlta Corporation | 2023 Integrated Report

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

Year ended Dec. 31, 2023 |  |  | 2023 | 2022 | 2021
Alberta Market |  |  |  |  |
Spot power price average per MWh |  |  | 134 |  | 162 |  | 102 |
Natural gas price (AECO) per GJ |  |  | 2.54 |  | 5.08 |  | 3.39 |
Carbon compliance price per tonne |  |  | 65 |  | 50 |  | 40 |
Alberta Portfolio Results |  |  |  |  |
Realized merchant power price per MWh(1) |  |  | 136 |  | 126 |  | 91 |
Hydro energy spot power price per MWh |  |  | 175 |  | 197 |  | 122 |
Hydro ancillary spot price per MWh |  |  | 67 |  | 76 |  | 55 |
Wind energy spot power price per MWh |  |  | 73 |  | 90 |  | 63 |
Gas and Energy Transition spot power price per MWh |  |  | 162 |  | 194 |  | 114 |
Hedged power price average per MWh |  |  | 111 |  | 86 |  | 72 |
Hedged volume (GWh) |  |  | 7,550 |  | 7,228 |  | 6,992 |
Fuel and purchased power per MWh(2) |  |  | 45 |  | 60 |  | 38 |
Carbon compliance cost per MWh(2) |  |  | 13 |  | 9 |  | 16 |

(1)Realized merchant power price for the Alberta electricity portfolio is the average price realized as a result of the Company's merchant power sales and portfolio optimization activities (excluding assets under long-term contract and ancillary revenues) divided by total merchant GWh produced.
(2)Fuel and purchased power per MWh and carbon compliance cost per MWh are calculated on production from carbon-emitting generation in the Gas and Energy Transition segments, and carbon compliance cost per MWh includes emission credits used to settle a portion of GHG carbon pricing obligations.
The average spot power price per MWh for the year ended Dec. 31, 2023 decreased from $162 per MWh in 2022 to $134 per MWh in 2023, primarily due to:
•Moderate temperatures in the last six months of the year compared with the prior year;
•Higher total renewable generation in the Alberta market from new wind and solar facilities and higher wind resources during the fourth quarter of 2023; and
•Lower natural gas prices.
Realized merchant power price per MWh of production for the year ended Dec. 31, 2023, increased by $10 per MWh, compared to 2022, primarily due to:
•Optimization of our available capacity across all fuel types; and
•Higher hedge prices compared to the prior year.
Fuel and purchased power cost per MWh for the year ended Dec. 31, 2023, decreased by $15 per MWh, compared to 2022, primarily due to lower natural gas prices.
Carbon compliance cost per MWh of production for the year ended Dec. 31, 2023, increased by $4 per MWh, compared to 2022, primarily due to:
•Carbon compliance prices increasing from $50 per tonne in 2022 to $65 per tonne in 2023; and
•No utilization of emission credits to settle the GHG obligation during the year. In the prior year, the Company used emission credits to settle a portion of the carbon compliance obligation resulting in a lower carbon cost per MWh.

TransAlta Corporation | 2023 Integrated Report | M25

Fourth Quarter Highlights
The Hydro, Wind and Gas facilities in the Alberta electricity portfolio in the fourth quarter of 2022 had high availability during periods of peak pricing, which resulted from extreme cold weather and periods of province-wide planned and unplanned outages resulting in exceptional
financial performance during the quarter. The Company did not experience the same weather conditions in the fourth quarter of 2023; with the weather being relatively mild compared to the fourth quarter of 2022.
Consolidated Financial Highlights

Three months ended Dec. 31 | 2023 |  | 2022
Operational information |  |  |
Adjusted availability (%) | 86.9 |  |  | 89.5 |
Production (GWh) | 5,783 |  |  | 6,005 |
Select financial information |  |  |
Revenues | 624 |  |  | 854 |
Earnings (loss) before income taxes | (35) |  |  | 7 |
Adjusted EBITDA(1) | 289 |  |  | 541 |
Net (loss) attributable to common shareholders | (84) |  |  | (163) |
Cash flows |  |  |
Cash flow from operating activities | 310 |  |  | 351 |
Funds from operations(1) | 229 |  |  | 459 |
Free cash flow(1) | 121 |  |  | 315 |
Per share |  |  |
Weighted average number of common shares outstanding | 308 |  |  | 269 |
Net (loss) per share attributable to common shareholders, basic and diluted | (0.27) |  |  | (0.61) |
Dividends declared per common share | 0.12 |  |  | 0.11 |
Funds from operations per share(1)(2) | 0.74 |  |  | 1.71 |
Free cash flow per share(1)(2) | 0.39 |  |  | 1.17 |

(1)These items are not defined and have no standardized meaning under IFRS. Refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. Also, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(2)FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for the purpose of these non-IFRS ratios.
Operating Performance
Adjusted Availability
The following table provides adjusted availability (%) by segment:

Three months ended Dec. 31 |  |  | 2023 | 2022 |
Hydro |  |  | 76.6 |  | 96.8 |  |
Wind and Solar |  |  | 90.3 |  | 85.7 |  |
Gas |  |  | 89.5 |  | 92.8 |  |
Energy Transition |  |  | 79.6 |  | 76.4 |  |
Adjusted availability (%) |  |  | 86.9 |  | 89.5 |  |

M26 | TransAlta Corporation | 2023 Integrated Report

Adjusted availability for the three months ended Dec. 31, 2023, was 86.9 per cent compared to 89.5 per cent for the same period in 2022, primarily due to:
•Planned outages in the Gas segment and Hydro segment, partially offset by
•Higher availability for the Wind and Solar segment, mainly due to the partial return to service of the Kent Hills wind facilities and
•Lower unplanned outages in the Energy Transition segment.
Production and Long-Term Average Generation

| 2023 |  | 2022
Three months ended Dec. 31 | Actual production (GWh) | LTA generation (GWh) | Production as a % of LTA |  | Actual production (GWh) | LTA generation (GWh) | Production as a % of LTA
Hydro | 326 |  | 447 |  | 73 | % |  | 344 |  | 435 |  | 79 | %
Wind and Solar | 1,479 |  | 1,621 |  | 91 | % |  | 1,222 |  | 1,499 |  | 82 | %
Gas | 2,892 |  |  |  |  | 3,375 |  |  |
Energy Transition | 1,086 |  |  |  |  | 1,064 |  |  |
Total | 5,783 |  |  |  |  | 6,005 |  |  |

Production for the three months ended Dec. 31, 2023, was 5,783 GWh compared to 6,005 GWh for the same period in 2022. The decrease was primarily due to:
•Lower dispatch of the Alberta Gas assets due to warmer temperatures and
•Lower availability, partially offset by
•Higher production in the Wind and Solar segment with the addition of the Garden Plain wind facility.
During the fourth quarter of 2023, weather impacts were relatively mild compared to the prior period, as the Company did not experience the same weather conditions as the fourth quarter of 2022, which had extreme cold weather in Alberta, resulting in periods of exceptional peak pricing in 2022.
Financial Performance review on Consolidated Information

Three months ended Dec. 31 | 2023 |  | 2022
Revenues | 624 |  |  | 854 |
Fuel and purchased power | 278 |  |  | 446 |
Carbon compliance | 27 |  |  | 27 |
Operations, maintenance and administration | 150 |  |  | 157 |
Depreciation and amortization | 132 |  |  | 188 |
Gain on sale of assets and other | — |  |  | 46 |
Earnings (loss) before income taxes | (35) |  |  | 7 |
Income tax expense | 19 |  |  | 89 |
Net loss attributable to common shareholders | (84) |  |  | (163) |
Net earnings attributable to non-controlling interests | 5 |  |  | 56 |

Current Year Variance Analysis (Fourth quarter 2023 versus 2022)
Revenues for the three months ended Dec. 31, 2023, decreased by $230 million, or 27 per cent, compared to the same period in 2022, primarily due to:
•Lower merchant sales due to lower spot power prices and production in Alberta and
•Lower realized ancillary services prices and volumes in the Hydro segment, partially offset by
•Higher realized and unrealized gains from hedging and derivative positions across the segments.
Fuel and purchased power costs for the three months ended Dec. 31, 2023, decreased by $168 million, or 38 per cent, compared to the same period in 2022, primarily due to:

TransAlta Corporation | 2023 Integrated Report | M27

•Lower natural gas commodity costs and
•Lower consumption of natural gas within our Gas segment.
Carbon compliance costs for the three months ended Dec. 31, 2023, were consistent with the same period in 2022 due to:
•Carbon price increases from $50 per tonne to $65 per tonne, offset by
•Reduced production volumes.
OM&A expenses for the three months ended Dec. 31, 2023, decreased by $7 million, or 4 per cent, compared to the same period in 2022, primarily due to:
•Lower incentive accruals in line with the Company's performance in comparison to the Company's exceptional performance in the fourth quarter of 2022, partially offset by
•The write-down of parts and material inventory for the gas facilities.
Depreciation and amortization for the three months ended Dec. 31, 2023, decreased by $56 million, or 30 per cent, compared to the same period in 2022, primarily due to:
•Revisions to useful lives on certain facilities, partially offset by
•Commercial operation of new facilities.
Gain on sale of assets and other for the three months ended Dec. 31, 2023, decreased by $46 million, or 100 per cent, compared to the same period in 2022, primarily due to the sale of certain gas generation assets in 2022.
Loss before income taxes totalling $35 million, decreased by $42 million, or 600 per cent, compared to earnings before income taxes of $7 million in 2022, due to the above noted items.
Income tax expense for the three months ended Dec. 31, 2023, decreased by $70 million, or 79 per cent, compared to 2022, due to lower earnings before tax in 2023 and the reduction of non-deductible expenses in the U.S.
Net loss attributable to common shareholders in the three months ended Dec. 31, 2023 was $84 million compared to a net loss of $163 million in the same period of 2022, an improvement of $79 million, or 48 percent, primarily due to the above noted items.
Net earnings attributable to non-controlling interests for the three months ended Dec. 31, 2023, decreased by $51 million, or 91 per cent, compared to the same period in 2022, primarily due to lower net earnings for TA Cogen and the acquisition of TransAlta Renewables on Oct. 5, 2023.
Segmented Financial Performance and Operating Results for the Fourth Quarter
A summary of our adjusted EBITDA by segment and earnings (loss) before income taxes for the three months ended Dec. 31, 2023, and 2022 is as follows:

| Adjusted EBITDA(1)
Three months ended Dec. 31 | 2023 | 2022
Hydro | 56 |  |  | 133 |
Wind and Solar | 82 |  |  | 92 |
Gas | 141 |  |  | 264 |
Energy Transition | 26 |  |  | 19 |
Energy Marketing | 14 |  |  | 63 |
Corporate | (30) |  |  | (30) |
Total adjusted EBITDA(1) | 289 |  |  | 541 |
Earnings (loss) before income taxes | (35) |  |  | 7 |

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

M28 | TransAlta Corporation | 2023 Integrated Report

The major factors impacting adjusted EBITDA for the three months ended Dec. 31, 2023, are summarized in the following table:

| Three months ended Dec. 31
Adjusted EBITDA for the three months ended Dec. 31, 2022 | 541 |
Hydro: lower due to decreased revenues from lower merchant and ancillary prices in the Alberta market and lower ancillary services volumes. | (77) |
Wind and Solar: lower due to lower merchant pricing in Alberta, lower wind resource in Eastern Canada and the US and higher OM&A due to new long-term service agreements, partially offset by higher revenues related to the partial return to service of the Kent Hills facilities and the addition of the Garden Plain wind facility and Northern Goldfields solar facilities. | (10) |
Gas: lower due to lower realized prices and production volume in the Alberta market, lower thermal revenues due to lower steam revenue pricing at the Sarnia facility compared to 2022, and higher OM&A with the inventory writedown at the Sundance and Keephills 2 facilities. | (123) |
Energy Transition: higher due to higher production due to lower unplanned outages, partially offset by lower revenues as a result of lower market prices. | 7 |
Energy Marketing: lower realized settled trades during the fourth quarter on market positions in comparison to the prior period in 2022. | (49) |
Corporate: consistent with the same period in 2022. | — |
Adjusted EBITDA(1) for the three months ended Dec. 31, 2023 | 289 |

(1)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
FCF for the three months ended Dec. 31, 2023, decreased by $194 million or 62 per cent, compared to the same period in 2022.

| Three months ended Dec. 31
FCF for the three months ended Dec. 31, 2022 | 315 |
Lower adjusted EBITDA: lower FCF due to the items noted above. | (252) |
Lower distributions paid to subsidiaries' non-controlling interests: lower net earnings in TA Cogen and no dividends paid to TransAlta Renewables shareholders resulting in higher FCF. | 42 |
Other(1) | 16 |
FCF(2) for the three months ended Dec. 31, 2023 | 121 |

(1)Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF section tables in this MD&A for more details.
(2)FCF is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
Selected Quarterly Information
Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are often incurred in the spring and fall when electricity prices are expected to be lower; electricity prices generally increase in the peak winter and summer months in our main markets due to increased heating and cooling loads. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting from
spring runoff and rainfall in the Pacific Northwest, which impacts production at Centralia. Typically, hydroelectric facilities generate most of their electricity and revenues during the spring months when melting snow starts feeding watersheds and rivers. Inversely, wind speeds are historically greater during the cold winter months and lower in the warm summer months.

TransAlta Corporation | 2023 Integrated Report | M29

| Q1 2023 | Q2 2023 | Q3 2023 | Q4 2023
Revenues | 1,089 |  | 625 |  | 1,017 |  | 624 |
Earnings (loss) before income taxes | 383 |  | 79 |  | 453 |  | (35) |
Net earnings (loss) attributable to common shareholders | 294 |  | 62 |  | 372 |  | (84) |
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1) | 1.10 |  | 0.23 |  | 1.41 |  | (0.27) |
Cash flow from operating activities | 462 |  | 11 |  | 681 |  | 310 |

| Q1 2022 | Q2 2022 | Q3 2022 | Q4 2022
Revenues | 735 |  | 458 |  | 929 |  | 854 |
Earnings (loss) before income taxes | 242 |  | (22) |  | 126 |  | 7 |
Net earnings (loss) attributable to common shareholders | 186 |  | (80) |  | 61 |  | (163) |
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1) | 0.69 |  | (0.30) |  | 0.23 |  | (0.61) |
Cash flow from (used in) operating activities(2) | 451 |  | (129) |  | 204 |  | 351 |

(1)Basic and diluted earnings (loss) per share attributable to common shareholders is calculated in each period using the basic and diluted weighted average common shares outstanding during the period, respectively. As a result, the sum of the earnings (loss) per share for the four quarters making up the calendar year may sometimes differ from the annual earnings (loss) per share.
(2)The cash flow used in operating activities for the second quarter of 2022 was negative due to unfavourable changes in working capital mainly due to movements in our collateral accounts related to higher commodity prices and volatility in the markets.
Net earnings (loss) attributable to common shareholders over the prior eight quarters has also been impacted by the following variations and events:
•Higher revenues arising from higher overall availability during periods of peak pricing and higher power prices in Alberta in the second, third and fourth quarters of 2022 and the first and second quarters of 2023;
•Lower natural gas pricing in 2023 and higher natural gas pricing in 2022;
•Lower carbon costs in 2022 were realized as the Company utilized emission credits to settle a portion of our GHG obligation in the second quarter of 2022. In 2023, the Company settled its carbon obligation with cash. Higher carbon costs in the first three quarters of 2023 were due to higher carbon price per tonne and were also due to higher production in the second quarter of 2023;
•The continued extended outage of the Kent Hills 1 and 2 wind facilities from the first quarter of 2022 through to the third quarter of 2023. The facilities were partially returned to service in the fourth quarter of 2023, with all turbines now commissioned and the remediation project completed in the first quarter of 2024;
•The effects of asset impairment reversals recognized in the first, second and third quarters of 2023 and the effects of asset impairment charges and reversals during all periods shown;
•The effects of changes in decommissioning provisions for retired assets from changes in estimated cash flows and discount rates in all periods shown, and changes in useful
lives, recognized in the third quarter of 2022 and the third and fourth quarters of 2023;
•Insurance proceeds for the single tower failure at Kent Hills wind facilities of $7 million recognized in the second quarter of 2022;
•Liquidated damages recoverable from turbine availability being below the contractual target at the Windrise wind facility recorded in each quarter in 2022 and in each quarter in 2023;
•Sundance Unit 4 being retired in the first quarter of 2022;
•Commissioning of the Garden Plain wind facility in the third quarter of 2023 and the Northern Goldfields solar facilities in the fourth quarter of 2023;
•Gains relating to the sale of assets being recognized in the fourth quarter of 2022;
•Fluctuations in the Canadian dollar relative to the US dollar resulting in foreign exchange gains and losses on our US-denominated long-term debt balances not designated as hedges; and
•Fluctuations in current and deferred tax expense with earnings before tax across the quarters. Deferred tax expense decreased from 2022 mainly due to a lower non-deductible tax adjustment relating to the US along with a deferred tax recovery of a previous derecognition of Canadian tax assets.

M30 | TransAlta Corporation | 2023 Integrated Report

Strategy and Capability to Deliver Results
Our strategic focus is to invest in clean electricity solutions that meet the needs and objectives of our customers and communities. We invest in a disciplined and prudent manner to deliver appropriately risk-adjusted returns to our shareholders. To support this strategy, we maintain a growing pipeline of project opportunities focused on hydro, wind, solar, energy storage and low emissions gas generation.
In 2021, we set out clear targets under the Clean Electricity Growth Plan. These targets included delivering 2 GW of incremental renewable capacity with a target capital investment of $3.6 billion in order to drive additional cumulative annual EBITDA of $315 million from new growth projects. Over the last two years, the Company achieved over 40 per cent of that original target by adding 800 MW of new capacity, together with the transmission expansion project for BHP Nickel West.
In 2023, given the market challenges of rising equipment and capital costs, we remained disciplined and patient with our greenfield efforts and shifted our focus towards priorities of simplification, contracted renewables and flexible generation. We looked to two strategic acquisitions that would position the Company well for the future, TransAlta Renewables and Heartland Generation Ltd.
We deployed $1.3 billion toward the acquisition of TransAlta Renewables which provided economic
contribution from an incremental 1.2 GW of generating capacity, increasing the proportionate EBITDA and contractedness of the Company.
We also entered into a definitive share purchase agreement to acquire Heartland Generation Ltd. for an estimated total cost of $658 million. The acquisition will competitively position the Company in response to the changing dynamics in Alberta, given the expected significant increase in renewables and other large baseload generation coming online in the next several years in the highly dynamic and shifting electricity landscape in the province.
In 2023, our growth and execution teams progressed construction on new facilities, in all three of our core geographies, through one of the largest construction programs that the Company has ever undertaken. The fully contracted 130 MW Garden Plain and 48 MW Northern Goldfields solar and battery storage facilities reached commercial operation, adding $21-$23 million in incremental EBITDA. The 300 MW White Rock East and the White Rock West projects and the 200 MW Horizon Hill wind project are expected to reach commercial operation in the first quarter of 2024, adding $76-$82 million and $41-$44 million, respectively, in incremental EBITDA.
Strategic Priorities and Clean Electricity Growth Plan to 2028
On Nov. 21, 2023, the Company updated its five-year strategic growth targets and Clean Electricity Growth Plan. The Company established six strategic priorities to focus our path from 2024 to 2028. They are outlined below and include goals for growth, investment and ESG priorities.
The Company's growth targets include adding up to 1.75 GW of new generating capacity to the Company’s fleet while targeting cumulative annual EBITDA from new growth of $350 million by investing approximately $3.5 billion to develop, construct and acquire new assets through 2024 to the end of 2028. The growth will focus on customer-centered renewables and storage through the execution of its current 5.3 GW development pipeline that it plans to expand to reach 10 GW by 2028.
We expect the Company's adjusted EBITDA generated from renewable sources, including hydro, wind and solar technologies, to increase to 70 per cent by the end of 2028. The Clean Electricity Growth Plan will largely be funded from current cash balances, cash generated from operations and debt financing.
Our investment focus to 2028 will focus on renewables and storage, but may also include efficient and flexible natural gas generation and new technology. The Company has a long-term decarbonization goal of net-zero by 2045.
Our current progress towards achieving these strategic targets is summarized below:

TransAlta Corporation | 2023 Integrated Report | M31

Strategic Targets 2024 to 2028

Goals | Target | Results | Comments
Optimize Alberta portfolio | Continue to optimize our existing asset base and maximize the value of our hydro fleet in Alberta. | On Track | The acquisition of Heartland will add 1,844 MW of complementary flexible capacity to the Alberta portfolio including contracted cogeneration, peaking generation, transmission capacity and development opportunities in hydrogen.
Execute Clean Electricity Growth Plan | Deliver up to 1.75 GW of renewable capacity with an estimated capital investment of $3.5 billion by the end of 2028. | On Track | The Company is currently advancing 418 MW of advanced-stage projects towards final investment decision in 2024.
Deliver incremental average annual EBITDA of $350 million by the end of 2028. | On Track | In 2024, the Company plans to make investment decisions on new projects that will produce at least $80 million in incremental EBITDA.
Expand the Company's development pipeline to 10 GW by the end of 2028. | On Track | In 2024, The Company plans to add an additional 1,500 MW to its development pipeline to further support our Clean Electricity Growth Plan.
Selective Expansion of Flexible Generation and Reliability Assets | Selectively expand our portfolio offerings in flexible generation and reliability assets such as peaking generation and short-term and long-term storage. | On Track | The Company plans to selectively invest in peaking generation and battery storage assets to optimize our portfolio. The acquisition of Heartland will add 387 MW of peaking gas capacity to our portfolio, the peaking assets will be optimized by the Company to address increasing intermittency in Alberta.
Maintain Our Financial Strength and Capital Allocation Discipline | Deliver strong cash flow from our existing portfolio to allocate towards our funding priorities including growth, dividends, debt repayments and share repurchases. | On Track | The Company had liquidity of $1.7 billion as at Dec. 31, 2023. The Company increased the annual common share dividend by 9 per cent to $0.24 per year effective April 1, 2024. In 2024, the Company announced that it intends to repurchase up to $150 million of common shares. The increased annual common share dividend, along with the share repurchase commitment, will represent a return of up to approximately 40 per cent of the midpoint of our 2024 FCF guidance to shareholders.
Define the Next Generation of Power Solutions | Meet the needs of our customers and communities through the implementation of innovative electricity solutions and parallel investments in new complementary sectors by the end of 2028. | On Track | The Company established an Energy Innovation team to progress our goals in this area. The team has completed an equity investment in Ekona Power Inc. ("Ekona"), an early-stage hydrogen production company, in order to pursue commercialization of low cost, net-zero aligned hydrogen. The Company also committed to invest US$25 million over the next four years in the Energy Impact Partners Frontier Fund, which provides a portfolio approach to investing in emerging technologies focused on net-zero emissions. In total, the Company invested US$12 million to this fund as at Dec. 31, 2023.
Lead in ESG and Market Policy Development | Actively participate in policy development to ensure the electricity that we provide contributes to emissions reduction, grid reliability and competitive energy prices to enable the successful evolution of the markets in which we operate and compete. | On Track | The Company is actively engaging the Government of Canada and Government of Alberta on the proposed federal Clean Electricity Regulations, as well as electricity market and renewable approval changes under review in Alberta. This includes participation in the AESO's Executive Working Group and the Canada Electricity Advisory Council. TransAlta's input is focused on how to achieve emissions reductions while maintaining reliability and affordability. The Company continues to work with the Government of Canada on the design details of the investment tax credits and clean technology funding provided through the Government of Canada, as well as exploring funding opportunities through the Government of Alberta.

M32 | TransAlta Corporation | 2023 Integrated Report

Advanced-Stage Development
These projects have detailed engineering, advanced positions in the interconnection queue and/or are progressing offtake opportunities. Projects in advanced-stage development are progressing towards
final investment decision and do not have final approval from the Board of Directors at time of reporting. The following table shows the pipeline of future growth projects currently under advanced-stage development:

Project | Type | Region | Target investment date | MW | Estimated spend | Average annual EBITDA(1)
Tempest | Wind | Alberta | 2024 |  | 100 |  | $260-$280 | $22-$26
SCE Capacity Expansion | Gas | Western Australia | 2024 |  | 94 |  | AU$210-AU$230 | AU$28-AU$32
WaterCharger | Battery Storage | Alberta | 2024 |  | 180 |  | $160-$180(2) | $15-$17
Pinnacle 1 & 2 | Gas | Alberta | 2024 |  | 44 |  | $65-$75 | $13-$15
Total(3) |  |  |  | 418 |  | $740 - $813 | $82 - $94

(1)This item is not defined, has no standardized meaning under IFRS and is forward-looking. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.
(2)Estimated spend is net of government funding and anticipated tax credits.
(3)Total expected spending and average annual EBITDA was converted using a Canadian dollar forward exchange rate for 2023.
Early-Stage Development
These projects are in the early stages and may or may not move ahead. Generally, these projects will have:
•Collected meteorological data;
•Begun securing land control;
•Started environmental studies;
•Confirmed appropriate access to transmission; and
•Started preliminary permitting and other regulatory approval processes.

TransAlta Corporation | 2023 Integrated Report | M33

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

Project | Type | Region | Potential investment date(1) | MW
Canada |  |  |  |
Riplinger Wind | Wind | Alberta | 2025 |  | 300 |
Sunhills Solar | Solar | Alberta | 2025 |  | 170 |
McNeil Solar | Solar | Alberta | 2025 |  | 57 |
New Brunswick Battery | Battery | New Brunswick | 2025 |  | 10 |
Tent Mountain Pumped Storage(2) | Hydro | Alberta | 2026 |  | 160 |
Provost | Wind | Alberta | 2026 |  | 170 |
Antelope Coulee | Wind | Saskatchewan | 2027+ | 200 |
Red Rock | Wind | Alberta | 2027 |  | 100 |
Willow Creek 1 | Wind | Alberta | 2027 |  | 70 |
Willow Creek 2 | Wind | Alberta | 2027 |  | 70 |
Other Canadian Opportunities | Wind | Various | 2026+ | 190 |
Brazeau Pumped Hydro | Hydro | Alberta | TBD | 300-900
Alberta Thermal Redevelopment(3) | Various | Alberta | TBD | 250-500
|  | Total |  | 2,047 - 2,897
United States |  |  |  |
Monument Road | Wind | Nebraska | 2025 |  | 152 |
Swan Creek | Wind | Nebraska | 2025 |  | 126 |
Dos Rios | Wind | Oklahoma | 2025 |  | 242 |
Cotton Belle 1 | Solar | Texas | 2025 |  | 104 |
Cotton Belle 2 | Solar | Texas | 2025 |  | 81 |
Square Top | Solar | Oklahoma | 2026 |  | 195 |
Old Town | Wind | Illinois | 2026 |  | 185 |
Canadian River | Wind | Oklahoma | 2026 |  | 250 |
Prairie Violet | Wind | Illinois | 2026 |  | 130 |
Quick Draw | Wind | Texas | 2026 |  | 174 |
Big Timber | Wind | Pennsylvania | 2026 |  | 50 |
Trapper Valley | Wind | Wyoming | 2027 |  | 225 |
Wild Waters | Wind | Minnesota | 2027+ | 40 |
Coolspring | Wind | Pennsylvania | 2027+ | 120 |
Other US Opportunities | Wind | Various | 2026+ | 144 |
Centralia Site Redevelopment(3) | Various | Washington | TBD | 250-500
|  | Total |  | 2,468 - 2,718
Australia |  |  |  |
Boodarie Solar | Solar | Western Australia | 2024 |  | 50 |
Southern Cross Energy | Wind and Solar | Western Australia | TBD | 120 |
Other Australian Opportunities | Gas, Solar, Transmission | Western Australia | 2024+ | 230 |
|  | Total |  | 400 |
Canada, United States and Australia |  | Total |  | 4,915 - 6,015

(1)Potential investment date is to be determined ("TBD").
(2)This represents the Company's 50 per cent interest in Tent Mountain. See the Significant and Subsequent Events section of this MD&A for more details.
(3)The Company is currently evaluating redevelopment opportunities at these brownfield sites.

M34 | TransAlta Corporation | 2023 Integrated Report

Projects under Construction
The following projects have been approved by the Board of Directors, have executed PPAs and are currently under construction or in the process of being commissioned. The projects under construction will be financed through existing liquidity in the near term. We will continue to explore permanent financing solutions on an asset-by-asset basis.
We are continually monitoring the timing and costs on our projects under construction. Our US projects have
experienced schedule delays and increased costs attributable to complexities relating to transmission interconnections and wind turbine erection. The 300 MW White Rock wind projects and the 200 MW Horizon Hill wind project transmission lines are fully energized. The projects are expected to achieve commercial operation in the first quarter of 2024.

|  |  |  | Total project (millions) |  |  |  |  |
Project | Type | Region | MW | Estimated spend | Spent to date | Target completion date | PPA Term(1) | Average annual EBITDA(2) |  | Status
United States |  |  |  |  |  |  |  |  |  |  |
White Rock | Wind | OK | 300 | US$510 |  | — | US$530 | US$477 | Q1 2024 | — | US$53-US$57 |  | •Long-term PPAs executed •Installation/assembly complete •Final stages of commissioning underway
Horizon Hill | Wind | OK | 200 | US$330 |  | — | US$340 | US$307 | Q1 2024 | — | US$31-US$33 |  | •Long-term PPA executed •Installation/assembly complete •Final stages of commissioning underway
Australia |  |  |  |  |  |  |  |  |  |  |
Mount Keith 132kV Expansion | Transmission | WA | n/a | AU$54 |  | — | AU$57 | AU$45 | Q1 2024 | 15 | AU$6 - AU$7 |  | •Installation/assembly complete •Final stages of commissioning underway
Mount Keith West Network Upgrade | Transmission | WA | n/a | AU$37 |  | — | AU$40 | AU$12 | Q2 2025 | 14 | AU$6 - AU$7 |  | •Major equipment orders placed •Detailed design and execution planning underway •On track to be completed on schedule
Total(3) |  |  | 500 | $1,228 |  | — | $1,274 |  | 1,360 |  |  | $125 - $135 |  |

(1)The PPA term is confidential for the White Rock wind projects and Horizon Hill wind project.
(2)This item is not defined and has no standardized meaning under IFRS and is forward-looking. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.
(3)Total expected spending and average annual EBITDA were converted using a Canadian dollar forward exchange rate for 2023. Spend to date was converted using the period-end closing rate.

TransAlta Corporation | 2023 Integrated Report | M35

Financial Position
The following table highlights significant changes in the Consolidated Statements of Financial Position from Dec. 31, 2022, to Dec. 31, 2023:

| Dec. 31, 2023 | Dec. 31, 2022 | Increase/(decrease)
Assets |  |  |
Current assets |  |  |
Cash and cash equivalents | 348 |  | 1,134 |  | (786) |
Trade and other receivables | 807 |  | 1,589 |  | (782) |
Risk management assets | 151 |  | 709 |  | (558) |
Other current assets(1) | 274 |  | 282 |  | (8) |
Total current assets | 1,580 |  | 3,714 |  | (2,134) |
Non-current assets |  |  |
Risk management assets | 52 |  | 161 |  | (109) |
Property, plant and equipment, net | 5,714 |  | 5,556 |  | 158 |
Long-term portion of finance lease receivable | 171 |  | 129 |  | 42 |
Other non-current assets(2) | 1,142 |  | 1,181 |  | (39) |
Total non-current assets | 7,079 |  | 7,027 |  | 52 |
Total assets | 8,659 |  | 10,741 |  | (2,082) |
Liabilities |  |  |
Current liabilities |  |  |
Accounts payable and accrued liabilities | 797 |  | 1,346 |  | (549) |
Risk management liabilities | 314 |  | 1,129 |  | (815) |
Income taxes payable | 9 |  | 73 |  | (64) |
Credit facilities, long-term debt and lease liabilities | 532 |  | 178 |  | 354 |
Other current liabilities(3) | 90 |  | 162 |  | (72) |
Total current liabilities | 1,742 |  | 2,888 |  | (1,146) |
Non-current liabilities |  |  |
Credit facilities, long-term debt and lease liabilities | 2,934 |  | 3,475 |  | (541) |
Risk management liabilities (long-term) | 274 |  | 333 |  | (59) |
Defined benefit obligation and other long-term liabilities | 251 |  | 294 |  | (43) |
Deferred income tax liabilities | 386 |  | 352 |  | 34 |
Other non-current liabilities(4) | 1,408 |  | 1,410 |  | (2) |
Total non-current liabilities | 5,253 |  | 5,864 |  | (611) |
Total liabilities | 6,995 |  | 8,752 |  | (1,757) |
Equity |  |  |
Equity attributable to shareholders | 1,537 |  | 1,110 |  | 427 |
Non-controlling interests | 127 |  | 879 |  | (752) |
Total equity | 1,664 |  | 1,989 |  | (325) |
Total liabilities and equity | 8,659 |  | 10,741 |  | (2,082) |

(1)Includes restricted cash, prepaid expenses and other, and inventory.
(2)Includes investments, right-of-use assets, intangible assets, goodwill, deferred income tax assets and other assets.
(3)Includes bank overdraft, current portion of decommissioning and other provisions, current portion of contract liabilities and dividends payable.
(4)Includes exchangeable securities, long-term decommissioning and other provisions and contract liabilities.
(5)Significant changes in TransAlta's Consolidated Statements of Financial Position were as follows:

M36 | TransAlta Corporation | 2023 Integrated Report

Working Capital
The deficit of current assets over current liabilities, including the current portion of long-term debt and lease liabilities, was $162 million as at Dec. 31, 2023 (Dec. 31, 2022 – excess of current assets over current liabilities of $826 million), primarily as a result of the $400 million Term Facility being reclassified from long-term to current liabilities in the period as it is due to be repaid in September 2024, along with lower receivables and collateral provided in the Energy Marketing segment due to reduced volatility in the market and market prices.
Current assets decreased by $2,134 million to $1,580 million as at Dec. 31, 2023, from $3,714 million as at Dec. 31, 2022, primarily due to:
•Lower trade receivables related to collections from higher revenues recognized in December 2022, and lower receivables and collateral provided in the Energy Marketing segment due to lower market prices,
•Lower cash and cash equivalents, mainly from the use of cash to complete the acquisition of the RNW Shares and
•Lower risk management assets mainly due to lower market prices and higher contract settlements.
Current liabilities decreased by $1,146 million from $2,888 million as at Dec. 31, 2022, to $1,742 million as at Dec. 31, 2023, mainly due to:
•Lower risk management liabilities due to lower market prices, as well as higher contract settlements during the year,
•Lower accounts payable and accrued liabilities including returning collateral received in the Energy Marketing segment due to lower market prices and
•Lower income taxes payable, partially offset by
•Higher debt classified as current as the $400 million Term Facility matures in the third quarter of 2024.
Non-Current Assets
Non-current assets as at Dec. 31, 2023, were $7,079 million, an increase of $52 million from $7,027 million as at Dec. 31, 2022, primarily due to:
•Higher property, plant and equipment ("PP&E") resulting from higher capital additions of $875 million, mainly related to the construction of growth projects and the rehabilitation of the Kent Hills wind facilities of $157 million, inclusive of insurance proceeds. The increase in PP&E additions was partially offset by depreciation of $585 million and
•Higher net investment in finance leases related to the Northern Goldfields solar facilities, partially offset by
•Lower risk management assets due to changes in market pricing across multiple markets and contract settlements.
Non-Current Liabilities
Non-current liabilities as at Dec. 31, 2023, were $5,253 million, a decrease of $611 million from $5,864 million as at Dec. 31, 2022, mainly due to:
•Lower long-term debt and lease liabilities related to scheduled debt repayments and the reclassification of the $400 million Term Facility to current liabilities,
•Lower risk management liabilities of $59 million related to contract settlements and pricing and
•Lower defined benefit obligations due to higher interest rates and a voluntary pension payment made to reduce our pension obligations, partially offset by
•Higher deferred tax liabilities.
Total Equity
As at Dec. 31, 2023, the decrease in total equity of $325 million was due to:
•A net decrease of $809 million from the acquisition of TransAlta Renewables,
•Distributions to non-controlling interests of $198 million,
•Share repurchases under the NCIB of $87 million and
•Dividends declared on common and preferred shares of $116 million, partially offset by
•Net earnings of $796 million and
•Net gains on derivatives from cash flow hedges of $99 million.
Financial Capital
The Company is focused on maintaining a strong balance sheet and financial position to ensure access to sufficient financial capital. Credit ratings provide information relating to the Company's financing costs, liquidity and operations, and affect the Company's ability to obtain short-term and long-term financing and/or the cost of such financing. Maintaining a strong balance sheet also allows the Company to enter into contracts with a variety of counterparties on terms and prices that are favourable to the Company’s financial results and provide TransAlta with
better access to capital markets through commodity and credit cycles.
In 2023, Moody's reaffirmed the Company's long-term rating of Ba1 with a stable outlook. Morningstar DBRS reaffirmed the Company's issuer rating and unsecured debt/medium-term notes rating of BBB (low) and the Company's preferred shares rating of Pfd-3 (low), all with stable outlook. In addition, S&P Global Ratings reaffirmed the Company's senior unsecured debt rating and issuer

TransAlta Corporation | 2023 Integrated Report | M37

credit rating of BB+ with a stable outlook. Risks associated with our credit ratings are discussed in the Governance and Risk Management section of this MD&A.
Capital Structure
Our capital structure consists of the following components as shown below:

| 2023 |  | 2022 | 2021
| $ | % | $ | % | $ | %
Net senior unsecured debt |  |  |  |  |  |  |  |
Recourse debt - CAD debentures | 251 |  |  | 5 |  |  | 251 |  | 5 |  | 251 |  | 4 |
Recourse debt - US senior notes | 911 |  |  | 17 |  |  | 934 |  | 18 |  | 888 |  | 16 |
Credit facilities | 397 |  |  | 7 |  |  | 428 |  | 9 |  | — |  | — |
Other | — |  |  | — |  |  | 1 |  | — |  | 4 |  | — |
Less: cash and cash equivalents(1) | (345) |  |  | (6) |  |  | (1,118) |  | (21) |  | (947) |  | (17) |
Less: other cash and liquid assets(2) | (12) |  |  | — |  |  | (20) |  | — |  | (19) |  | — |
Net senior unsecured debt | 1,202 |  |  | 23 |  |  | 476 | 11 |  | 177 |  | 3 |
Other debt liabilities |  |  |  |  |  |  |  |
Exchangeable debentures | 344 |  |  | 6 |  |  | 339 |  | 6 |  | 335 |  | 6 |
Non-recourse debt |  |  |  |  |  |  |  |
TAPC Holdings LP bond | 85 |  |  | 1 |  |  | 94 |  | 2 |  | 102 |  | 2 |
Pingston bond | 39 |  |  | 1 |  |  | 45 |  | 1 |  | 45 |  | 1 |
Melancthon Wolfe Wind bond | 168 |  |  | 3 |  |  | 202 |  | 4 |  | 235 |  | 4 |
New Richmond Wind bond | 103 |  |  | 2 |  |  | 112 |  | 2 |  | 120 |  | 2 |
Kent Hills Wind bond | 193 |  |  | 3 |  |  | 206 |  | 4 |  | 221 |  | 4 |
Windrise Wind bond | 164 |  |  | 3 |  |  | 170 |  | 3 |  | 171 |  | 3 |
South Hedland non-recourse debt | 691 |  |  | 13 |  |  | 711 |  | 14 |  | 732 |  | 13 |
OCP Bond | 217 |  |  | 4 |  |  | 241 |  | 4 |  | 263 |  | 5 |
US tax equity financing | 104 |  |  | 1 |  |  | 123 |  | 2 |  | 135 |  | 2 |
Lease liabilities | 143 |  |  | 3 |  |  | 135 |  | 2 |  | 100 |  | 2 |
Total consolidated net debt(3)(4)(5) | 3,453 |  |  | 63 |  |  | 2,854 |  | 55 |  | 2,636 |  | 47 |
Exchangeable preferred securities(5) | 400 |  |  | 7 |  |  | 400 |  | 7 |  | 400 |  | 7 |
Equity attributable to shareholders |  |  |  |  |  |  |  |
Common shares | 3,285 |  |  | 60 |  |  | 2,863 |  | 54 |  | 2,901 |  | 51 |
Preferred shares | 942 |  |  | 17 |  |  | 942 |  | 18 |  | 942 |  | 17 |
Contributed surplus, deficit and accumulated other comprehensive loss | (2,690) |  |  | (49) |  |  | (2,695) |  | (51) |  | (2,261) |  | (40) |
Non-controlling interests | 127 |  |  | 2 |  |  | 879 |  | 17 |  | 1,011 |  | 18 |
Total capital | 5,517 |  |  | 100 |  |  | 5,243 |  | 100 |  | 5,629 |  | 100 |

(1)Cash and cash equivalents is net of bank overdraft.
(2)Includes principal portion of the TransAlta OCP restricted cash related to the TransAlta OCP bonds as this cash is restricted specifically to repay outstanding debt and also includes the fair value of economic and designated hedging instruments on debt, as the carrying value of the related debt is impacted by changes in foreign exchange rates.
(3)These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion, including reconciliations to measures calculated in accordance with IFRS.
(4)The tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in these amounts.
(5)The total consolidated net debt excludes the exchangeable preferred securities as they are considered equity with dividend payments for credit purposes.

M38 | TransAlta Corporation | 2023 Integrated Report

We have enhanced liquidity and shareholder value through the following:
2023
•Extended the committed syndicated credit facility by one year to June 30, 2027 and the committed bilateral credit facilities by one year to June 30, 2025;
•Refinanced the $45 million Pingston non-recourse bond due in 2023 with a non-recourse bond for approximately $39 million, with a fixed interest rate of 6.145 per cent per annum, payable semi-annually, and maturing on May 8, 2043; and
•Purchased and cancelled 7,537,500 common shares at an average price of $11.49 per share through our NCIB program, for a total cost of $87 million.
2022
•Issued US$400 million Senior Green Bonds, with a fixed coupon rate of 7.75 per cent per annum (effective interest rate of 5.98 per cent), due on Nov. 15, 2029;
•Repaid the US$400 million 4.50 per cent unsecured senior notes due 2022;
•Extended the committed syndicated credit facilities by one year to June 30, 2026 and the committed bilateral credit facilities by one year to June 30, 2024;
•Closed a two-year floating rate Term Facility with our banking syndicate for $400 million with a maturity date of Sept. 7, 2024. The Term Facility has interest rates that vary depending on the option selected (e.g. Canadian prime and bankers' acceptances); and
•Purchased and cancelled 4,342,300 common shares at an average price of $12.48 per share through our NCIB program, for a total cost of $54 million.
2021
•Obtained $173 million in project financing related to our Windrise wind facility.
Credit Facilities
The Company's credit facilities are summarized in the table below:

As at Dec. 31, 2023 |  | Utilized | Available capacity | Maturity date
Credit facilities | Facility size | Outstanding letters of credit(1) | Cash drawings
Committed |  |  |  |  |
TransAlta syndicated credit facility | 1,950 |  | 417 |  | — |  | 1,533 |  | Q2 2027
TransAlta bilateral credit facilities | 240 |  | 178 |  | — |  | 62 |  | Q2 2025
TransAlta Term Facility | 400 |  | — |  | 400 |  | — |  | Q3 2024
Total committed | 2,590 |  | 595 |  | 400 |  | 1,595 |  |
Non-committed |  |  |  |  |
TransAlta demand facilities | 400 |  | 187 |  | — |  | 213 |  | N/A
Total non-committed | 400 |  | 187 |  | — |  | 213 |  |

(1)TransAlta has obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase obligations. Letters of credit drawn against the non-committed facilities reduce available capacity under the committed syndicated credit facilities.
On Oct. 5, 2023, upon closing the TransAlta Renewables transaction, the syndicated credit facilities were amended to effectively consolidate the TransAlta Renewables syndicated credit facility and non-committed demand facility into the TransAlta credit facilities. The cash drawings on the TransAlta Renewables' syndicated credit facility were repaid and the outstanding letters of credit were transferred to the TransAlta non-committed demand facility. The TransAlta Renewables credit facilities were then terminated.
This resulted in the TransAlta syndicated credit facility increasing by $700 million to approximately $2.0 billion.
See the Significant and Subsequent events section of this MD&A for more details.

TransAlta Corporation | 2023 Integrated Report | M39

Non-Recourse Debt and Other
The Melancthon Wolfe Wind LP, TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd. and Windrise Wind LP non-recourse bonds, and TransAlta OCP LP bonds, are subject to customary financing conditions and covenants that may restrict the Company’s ability to access funds generated by the facilities’ operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the fourth quarter of 2023, with the exception of Kent Hills Wind LP and TAPC Holdings LP. Kent Hills Wind LP cannot make any distributions to its partners until the foundation replacement work has been completed and TAPC Holdings LP has been impacted by higher interest rates in 2023. The funds in these entities that have accumulated since the fourth quarter test will remain there until the next debt service coverage ratio is calculated in the first quarter of 2024. At Dec. 31, 2023, $79 million (Dec. 31, 2022 – $50 million) of cash was subject to these financial restrictions.
At Dec. 31, 2023, $3 million (AU$3 million) of funds held by TEC Hedland Pty Ltd. are not able to be accessed by other corporate entities as the funds must be solely used by the project entities for the purpose of paying major maintenance costs.
Additionally, certain non-recourse bonds require that reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit.
Between 2024 and 2026, we have a total of $811 million of debt repayments, including the $400 million maturity of the Term Facility, with the balance of $411 million related to scheduled non-recourse debt repayments. The $750 million of exchangeable securities can be exchanged at the earliest on Jan. 1, 2025.
US Tax Equity Financing and Production Tax Credits
The Company owns equity interests in wind facilities that are eligible for tax incentives available for renewable energy facilities in the US. Current US tax law allows qualified wind energy projects to receive production tax credits ("PTCs") that are earned for each MWh of generation during the first 10 years of the project's operation. In order to monetize tax incentives, the Company has partnered with Tax Equity Investors (“TEI”) who invest in these facilities in exchange for a share of the tax incentives and cash. TransAlta accounts for the TEI interest as long-term debt, where cash distributions and allocations of tax incentives to the TEI primarily reduce the long-term debt balance. Upon the TEI achieving an agreed-upon after-tax investment return, the project Flip Point occurs. Prior to achieving the Flip Point, the TEI are allocated substantially all of the taxable attributes including PTCs produced and a proportion of cash. After the Flip Point has been reached, the Company retains substantially all of the cash and the taxable income (losses) generated by the facility.
In 2023, US tax laws were amended to allow entities to monetize certain clean energy tax credits, including PTCs, by transferring (selling) them to third-party taxpayers, in exchange for cash consideration.
The following table outlines information regarding the Company's tax equity financing arrangements with PTC eligibility:

Facility | Commercial operation date | Expected Flip Point | Initial TEI investment ($) | Expected annual PTC ($) |  | TEI allocation of cash distributions (pre-Flip Point) Undiscounted(1) ($) | TEI allocation of taxable income and PTCs (pre-Flip Point) |
Lakeswind | 2014 | 2029 | 45 |  | 1 |  |  | 11 |  | 99 | % |
Big Level and Antrim | 2019 | 2030 | 126 |  | 10 |  |  | 46 |  | 99 | % |
Skookumchuck(2) | 2020 | 2030 | 121 |  | 10 |  |  | 21 |  | 99 | % |

(1)Cumulative expected cash distributions from Dec. 31, 2023 to the expected Flip Point.
(2)The Company has a 49 per cent interest in the Skookumchuck wind facility, which is treated as an equity investment under IFRS and our proportionate share of the net earnings is reflected as equity income on the statement of earnings under IFRS.

M40 | TransAlta Corporation | 2023 Integrated Report

Returns to Providers of Capital
Interest Income and Interest Expense
Interest income and the components of interest expense are shown below:

Year ended Dec. 31 |  |  | 2023 | 2022 | 2021
Interest income |  |  | 59 |  | 24 |  | 11 |
Interest on debt |  |  | 203 |  | 164 |  | 163 |
Interest on exchangeable debentures |  |  | 29 |  | 29 |  | 29 |
Interest on exchangeable preferred shares |  |  | 28 |  | 28 |  | 28 |
Capitalized interest |  |  | (57) |  | (16) |  | (14) |
Interest on lease liabilities |  |  | 9 |  | 7 |  | 7 |
Credit facility fees, bank charges and other interest |  |  | 21 |  | 27 |  | 20 |
Tax shield on tax equity financing |  |  | — |  | (2) |  | (9) |
Accretion of provisions |  |  | 48 |  | 49 |  | 32 |
Interest expense |  |  | 281 |  | 286 |  | 256 |

Interest income was higher due to higher cash balances and favourable interest rates. Interest expense was lower than 2022, primarily due to higher capitalized interest resulting from higher capital expenditures on growth
projects. This was partially offset by higher interest on debt due to higher credit facility borrowings and higher year-over-year interest rates on variable rate debt.
Share Capital
The following tables outline the common and preferred shares issued and outstanding:

| Number of shares (millions)
As at | Feb. 22, 2024 | Dec. 31, 2023 | Dec. 31, 2022
Common shares issued and outstanding, end of period | 307.1 |  | 308.6 |  | 268.1 |
Preferred shares |  |  |
Series A | 9.6 |  | 9.6 |  | 9.6 |
Series B | 2.4 |  | 2.4 |  | 2.4 |
Series C | 10.0 |  | 10.0 |  | 10.0 |
Series D | 1.0 |  | 1.0 |  | 1.0 |
Series E | 9.0 |  | 9.0 |  | 9.0 |
Series G | 6.6 |  | 6.6 |  | 6.6 |
Preferred shares issued and outstanding in equity | 38.6 |  | 38.6 |  | 38.6 |
Series I - Exchangeable Securities(1) | 0.4 |  | 0.4 |  | 0.4 |
Preferred shares issued and outstanding | 39.0 |  | 39.0 |  | 39.0 |

(1)Brookfield invested $400 million in consideration for redeemable, retractable, first preferred shares. For accounting purposes, these preferred shares are considered debt and disclosed as such in the consolidated financial statements.
Non-Controlling Interests
On Oct. 5, 2023, the Company acquired all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates. See the Significant and Subsequent Events section of this MD&A for details.
As at Dec. 31, 2023, the Company owned 50.01 per cent of TransAlta Cogeneration, LP (“TA Cogen”) (Dec. 31, 2022 – 50.01 per cent), which owns, operates or has an interest in three natural-gas-fired cogeneration facilities (Ottawa, Windsor and Fort Saskatchewan) and a natural-gas-fired facility (Sheerness). As at Dec. 31, 2023, the Company

TransAlta Corporation | 2023 Integrated Report | M41

owned 83 per cent of Kent Hills Wind LP (Dec. 31, 2022 - 83 per cent), which owns and operates three wind facilities. Throughout 2022, on Dec. 31, 2022, and from Jan. 1, 2023 to Oct. 4, 2023, the Company owned 60.1 per cent of TransAlta Renewables.
Since the Company owned a controlling interest in TA Cogen and Kent Hills Wind LP, we consolidated the entire earnings, assets and liabilities in relation to the subsidiaries. Earnings, assets and liabilities of these subsidiaries, and of TransAlta Renewables prior to Oct. 5, 2023, were allocated to the other owners in proportion to their ownership interests.
The reported net earnings attributable to non-controlling interests for the year ended Dec. 31, 2023, decreased by $10 million, compared to 2022, primarily as a result of lower TA Cogen net earnings attributable to non-controlling interests resulting from lower production and lower merchant pricing in the Alberta market. TransAlta Renewables net earnings attributable to non-controlling interests increased by $1 million for the year ended Dec. 31, 2023 compared to 2022.
Cash Flows
The following highlights significant changes in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2023 and Dec. 31, 2022:

Year ended Dec. 31 | 2023 |  | 2022 | Increase/ (decrease)
Cash and cash equivalents, beginning of year | 1,134 |  |  | 947 |  | 187 |
Provided by (used in): |  |  |  |
Operating activities | 1,464 |  |  | 877 |  | 587 |
Investing activities | (814) |  |  | (741) |  | (73) |
Financing activities | (1,432) |  |  | 45 |  | (1,477) |
Translation of foreign currency cash | (4) |  |  | 6 |  | (10) |
Cash and cash equivalents, end of year | 348 |  |  | 1,134 |  | (786) |

Cash Flow from Operating Activities
Cash from operating activities for the year ended Dec. 31, 2023, increased compared with the same period in 2022, primarily due to the following:

| Year ended Dec. 31
Cash flow from operating activities for the year ended Dec. 31, 2022 | 877 |
Higher gross margin: Lower natural gas costs included in fuel and purchased power, partially offset by lower revenues net of unrealized gains and losses from risk management activities and higher carbon compliance costs. | 127 |
Higher OM&A: Increased spending on strategic and growth initiatives; higher costs associated with the relocation of the Company's head office; and increased costs due to inflationary pressures. | (18) |
Lower current income tax expense: Previously restricted non-capital loss carryforwards were utilized to offset taxable income. | 15 |
Higher interest income: Higher cash balances and favourable interest rates | 35 |
Favourable change in non-cash operating working capital balances: Lower accounts receivable and collateral provided as a result of volatility in the market and market prices, partially offset by lower accounts payable and collateral received related to derivative instruments. | 440 |
Other | (12) |
Cash flow from operating activities for the year ended Dec. 31, 2023 | 1,464 |

M42 | TransAlta Corporation | 2023 Integrated Report

Cash Flow used in Investing Activities
Cash used in investing activities for the year ended Dec. 31, 2023, increased compared with the same period in 2022, primarily due to the following:

| Year ended Dec. 31
Cash flow used in investing activities for the year ended Dec. 31, 2022 | (741) |
Lower additions to PP&E: Additions in 2022 were mainly for the construction of the White Rock wind projects, Garden Plain wind facility, the Horizon Hill wind project and the Northern Goldfields solar facilities. In 2023, most of these facilities achieved commercial operation. | 43 |
Lower intangible assets: Lower additions of intangibles under development. | 18 |
Lower proceeds on sale of PP&E: In 2022, the Company closed the sale of two hydro facilities and sold equipment related to its Sundance Unit 5 energy transition assets and other equipment. | (37) |
Unfavourable change in non-cash investing working capital balances: Lower capital accruals. | (28) |
Other(1) | (69) |
Cash flow used in investing activities for the year ended Dec. 31, 2023 | (814) |

(1)Other is mainly comprised of higher spend on project development costs in 2023, higher contributions to investments in 2023, lower insurance proceeds in 2023 and lower settlements in 2023.
Cash Flow from (used in) Financing Activities
Cash used in financing activities for the year ended Dec. 31, 2023, increased compared with the same period in 2022, primarily due to the following:

| Year ended Dec. 31
Cash flow from financing activities for the year ended Dec. 31, 2022 | 45 |
Lower repayment of long-term debt: In 2022, the Company repaid the US$400 million senior notes. | 457 |
Higher share capital issuance: Used cash and issued shares to acquire TransAlta Renewables. | (811) |
Lower net increase in borrowings under credit facilities: In 2022, the Company fully utilized the $400 million Term Facility, which continues to remain outstanding. | (495) |
Lower issuance of long-term debt: In 2022, the Company issued US$400 million senior notes. | (493) |
Lower realized gains on financial instruments: The Company recognized a gain on the repayment of US$400 million senior notes in 2022. | (72) |
Higher distributions paid to non-controlling interests: Timing of distributions to TA Cogen, partially offset by lower distributions to TransAlta. | (36) |
Higher repurchases of common shares under the NCIB. | (35) |
Other | 8 |
Cash flow used in financing activities for the year ended Dec. 31, 2023 | (1,432) |

TransAlta Corporation | 2023 Integrated Report | M43

Other Consolidated Analysis
Unconsolidated Structured Entities or Arrangements
Disclosure is required of all unconsolidated structured entities or arrangements such as transactions, agreements or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. We currently have no such unconsolidated structured entities or arrangements.
Related-Party Transactions
In the normal course of operations, we enter into transactions on market terms with related parties, including consolidated and equity accounted entities, which have been measured at exchange value and are recognized in the consolidated financial statements, including, but not limited to asset management fees, power purchase and derivative contracts. Refer to Note 35, Related-Party Transactions in the consolidated financial statements for further details.
Guarantee Contracts
We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase obligations. At Dec. 31, 2023, we provided letters of credit totalling $782 million (2022 – $1.2 billion) and cash collateral of $145 million (2022 – $304 million).
These letters of credit and cash collateral secure certain amounts included on our Consolidated Statements of Financial Position under risk management liabilities, defined benefit obligations and other long-term liabilities and decommissioning and other provisions. The decrease in the amount of letters of credit issued during 2023 relates to lower letters of credit on physical and financial derivative transactions in a net liability position.
Commitments
Contractual commitments are as follows:

| 2024 | 2025 | 2026 | 2027 | 2028 | 2029 and thereafter | Total
Natural gas and transportation contracts(1) | 55 |  | 49 |  | 50 |  | 48 |  | 57 |  | 436 |  | 695 |
Transmission(1) | 9 |  | 9 |  | 6 |  | 4 |  | 5 |  | 93 |  | 126 |
Coal supply and mining agreements(1) | 86 |  | 71 |  | — |  | — |  | — |  | — |  | 157 |
Long-term service agreements(1) | 60 |  | 57 |  | 42 |  | 44 |  | 37 |  | 184 |  | 424 |
Operating leases(1,2) | 3 |  | 3 |  | 2 |  | 2 |  | 2 |  | 25 |  | 37 |
Long-term debt(3) | 526 |  | 142 |  | 143 |  | 153 |  | 162 |  | 2,237 |  | 3,363 |
Exchangeable securities(4) | — |  | — |  | — |  | — |  | — |  | 750 |  | 750 |
Principal payments on lease liabilities(5) | 4 |  | 4 |  | 4 |  | 4 |  | 4 |  | 123 |  | 143 |
Interest on long-term debt and lease liabilities(1,6) | 186 |  | 167 |  | 158 |  | 151 |  | 143 |  | 711 |  | 1,516 |
Interest on exchangeable securities(1,4) | 53 |  | 53 |  | 53 |  | 53 |  | 53 |  | 13 |  | 278 |
Growth(1,7) | 47 |  | — |  | — |  | — |  | — |  | — |  | 47 |
Total | 1,029 |  | 555 |  | 458 |  | 459 |  | 463 |  | 4,572 |  | 7,536 |

(1)Not recognized as a financial liability on the Consolidated Statements of Financial Position.
(2)Includes leases that have not been recognized as a lease liability and leases that have not yet commenced.
(3)Excludes impact of hedge accounting and derivatives.
(4)Cash payment could occur after Dec. 31, 2028 if exchangeable securities are not exchanged by Brookfield Renewable Partners or its affiliates (collectively "Brookfield"). At Brookfield's option, the exchangeable securities can be exchanged, at the earliest, on Jan. 1, 2025.
(5)Lease liabilities exclude a lease incentive of $12 million expected to be received in 2024, which is recognized in trade and other receivables.
(6)Interest on long-term debt is based on debt currently in place with no assumption as to refinancing on maturity.
(7)For further details on growth commitments, refer to the Strategy and Capability to Deliver Results section of this MD&A.

M44 | TransAlta Corporation | 2023 Integrated Report

Contingencies
TransAlta is occasionally named as a party in various claims and legal and regulatory proceedings that arise during the normal course of its business. TransAlta reviews each of these claims, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in the Company’s favour or that such claims may not have a material adverse effect on TransAlta. Inquiries from regulatory bodies may also arise in the normal course of business, to which the Company responds as required.
The Company conducts internal reviews of its offers and offer behaviour in both the energy and ancillary services markets in Alberta on an ongoing basis and will self-report suspected contraventions or respond to inquiries from regulatory agencies as required. There currently is no certainty that any particular matter will be resolved in the Company’s favour or that such matters may not have a material adverse effect on TransAlta.
Brazeau Facility - Well Licence Applications to Consider Hydraulic Fracturing Activities
The Alberta Energy Regulator ("AER") issued a subsurface order on May 27, 2019, which does not permit any hydraulic fracturing within three kilometres of the Brazeau facility but permits hydraulic fracturing in all formations (except the Duvernay) within three to five kilometres of the Brazeau facility. Subsequently, two oil and gas operators submitted applications to the AER for 10 well licences (which include hydraulic fracturing activities) within three to five kilometres of the Brazeau facility.
The Company's position, based on independent expert analysis commissioned by the Government of Alberta, is that hydraulic fracturing activities within five kilometres of the Brazeau facility pose an unacceptable risk and that the applications should be denied. The regulatory hearing to consider these applications - Proceeding 379 - was adjourned to April 2025. The other parties to the hearing, including the Company, have supported the adjournment.
Brazeau Facility - Claim Against the Government of Alberta
On Sept. 9, 2022, the Company filed a Statement of Claim against the Alberta Government in the Alberta Court of King’s Bench seeking a declaration that: (a) granting mineral leases within five kilometres of the Brazeau facility is a breach of the 1960 agreement between the Company and the Alberta Government; and (b) the Alberta Government is required to indemnify the Company for any costs or damages that result from the risks of hydraulic fracturing near the Brazeau facility. On Sept. 29, 2022, the Alberta Government filed its Statement of Defence, which asserts, among other things, that the Company: (a) is trying
to usurp the jurisdiction of the AER; and (b) is out of time under the Limitations Act (Alberta). The trial was scheduled for two weeks starting Feb. 26, 2024. The parties to the matter, along with Cenovus Energy Inc., sought an adjournment when AER Proceeding 379 was adjourned. The trial is scheduled to resume in February 2025 in the event the parties are unable to resolve the dispute prior to such date.
Garden Plain
Garden Plain I LP, a wholly owned subsidiary of the Company, retained a third-party contractor to construct the Garden Plain wind project near Hanna, Alberta. The contractor experienced scheduling delays, challenges with construction and significant cost overruns, resulting in overdue deadlines, and has asserted a claim for $49 million in damages. The Company disputes this claim in its entirety and asserts a counterclaim. The parties have initiated the dispute resolution procedure, and the arbitration hearing is set down for three weeks starting April 14, 2025.
Hydro Power Purchase Arrangement ("Hydro PPA") Emissions Performance Credits
The Balancing Pool claimed entitlement to 1,750,000 Emission Performance Credits ("EPCs") earned by the Alberta Hydro facilities as a result of TransAlta opting those facilities into the Carbon Competitiveness Incentive Regulation and Technology Innovation and Emissions Reduction Regulation from 2018-2020 inclusive. The EPCs under dispute had no recorded book value as they were internally generated. The Balancing Pool claimed ownership of the EPCs because it believed the change-in-law provisions under the Hydro PPA required the EPCs to be passed through to the Balancing Pool. TransAlta disputed this claim. The parties have reached a confidential settlement and this matter is now resolved.
Sundance A Decommissioning
TransAlta filed an application with the Alberta Utilities Commission seeking payment from the Balancing Pool for TransAlta’s decommissioning costs for Sundance A, including its proportionate share of the Highvale mine. The Balancing Pool and Utilities Consumer Advocate are participating as interveners because they take issue with the decommissioning costs claimed by TransAlta. The application is being heard in the first quarter of 2024 with a decision expected to be rendered in the third quarter of 2024.

TransAlta Corporation | 2023 Integrated Report | M45

Financial Instruments
Financial instruments are used for proprietary trading purposes and to manage our exposure to interest rates, commodity prices and currency fluctuations, as well as other market risks. We may currently use physical and financial swaps, forward sale and purchase contracts, futures contracts, foreign exchange contracts, interest rate swaps and options to achieve our risk management objectives. Some of our physical commodity contracts have been entered into and are held for the purposes of meeting our expected purchase, sale or usage requirements and, as such, are not considered financial instruments, and are not recognized as a financial asset or financial liability. Other physical commodity contracts that are not held for normal purchase or sale requirements, and derivative financial instruments are recognized on the Consolidated Statements of Financial Position and are accounted for using the fair value method of accounting. The initial recognition of fair value and subsequent changes in fair value can affect reported earnings in the period the change occurs if hedge accounting is not elected. Otherwise, changes in fair value will generally not affect earnings until the financial instrument is settled.
Some of our financial instruments and physical commodity contracts qualify for, and are recorded under, hedge accounting rules. The accounting for those contracts, for which we have elected to apply hedge accounting, depends on the type of hedge. Our financial instruments are mainly used for cash flow hedges or non-hedges. These categories and their associated accounting treatments are explained in further detail below.
For all types of hedges, we test for effectiveness at the end of each reporting period to determine if the instruments are performing as intended and hedge accounting can still be applied. The financial instruments we enter into are designed to ensure that future cash inflows and outflows are predictable. In a hedging relationship, the effective portion of the change in the fair value of the hedging derivative does not impact net earnings (loss), while any ineffective portion is recognized in net earnings (loss).
We have certain contracts in our portfolio that, at their inception, do not qualify for, or we have chosen not to elect to apply, hedge accounting. For these contracts, we recognize in net earnings (loss) mark-to-market gains and losses resulting from changes in forward prices compared to the price at which these contracts were transacted. These changes in price alter the timing of earnings recognition, but do not necessarily determine the final settlement amount received. The fair value of future contracts will continue to fluctuate as market prices change. The fair value of derivatives that are not traded on an active exchange, or extend beyond the time period for
which exchange-based quotes are available, are determined using valuation techniques or models.
Cash Flow Hedges
Cash flow hedges are categorized as project, foreign exchange, interest rate or commodity hedges and are used to offset foreign exchange, interest rate and commodity price exposures resulting from market fluctuations.
Foreign currency forward contracts and cross-currency swaps may be used to hedge foreign exchange exposures resulting from anticipated contracts and firm commitments denominated in foreign currencies, primarily related to capital expenditures and currency exposures related to US-denominated debt.
Physical and financial swaps, forward sale and purchase contracts, futures contracts and options may be used primarily to offset the variability in future cash flows caused by fluctuations in electricity and natural gas prices. Interest rate swaps may be used to convert the fixed interest cash flows related to interest expense at debt to floating rates and vice versa.
In a cash flow hedge, changes in the fair value of the hedging instrument (a forward contract or financial swap, for example) are recognized in risk management assets or liabilities and the related gains or losses are recognized in other comprehensive income or loss ("OCI"). These gains or losses are subsequently reclassified from OCI to net earnings (loss) in the same period as the hedged forecast cash flows impact net earnings (loss) and offset the losses or gains arising from the forecast transactions. For project hedges, the gains and losses reclassified from OCI are included in the carrying amount of the related PP&E.
Hedge accounting follows a principles-based approach for qualifying hedges that is aligned with an entity's approach to risk management. When we do not elect hedge accounting or when the hedge is no longer effective and does not qualify for hedge accounting, the gains or losses as a result of changes in prices, interest or exchange rates related to these financial instruments are recorded in net earnings (loss) in the period in which they arise.
Net Investment Hedges
Foreign-denominated long-term debt is used to hedge exposure to changes in the carrying values of our net investments in foreign operations that have a functional currency other than the Canadian dollar. Our net investment hedges using US-denominated debt remain effective and in place. Gains or losses on these instruments are recognized and deferred in OCI and reclassified to net earnings on the disposal of the foreign operation. We also manage foreign exchange risk by

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matching foreign-denominated expenses with revenues, such as offsetting revenues from our US operations with interest payments on our US-dollar debt.
Non-Hedges
Financial instruments not designated as hedges are used for proprietary trading and to reduce commodity price, foreign exchange and interest rate risks. Changes in the fair value of financial instruments not designated as hedges are recognized in risk management assets or liabilities and the related gains or losses are recognized in net earnings (loss) in the period in which the change occurs.
Fair Values
The majority of fair values for our foreign exchange, interest rate, commodity hedges and non-hedge derivatives are calculated using adjusted quoted prices from an active market or inputs validated by broker quotes. We may enter into commodity transactions involving non-standard features for which market-observable data is not available. These transactions are defined under IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable from the market and fair
value is therefore determined using valuation techniques. Fair values are validated by using reasonably possible alternative assumptions as inputs to valuation techniques and any material differences are disclosed in the notes to the consolidated financial statements.
At Dec. 31, 2023, Level III instruments had a net liabilities carrying value of $147 million (2022 – net liabilities $782 million). The Level III liabilities decreased in 2023 primarily due to market price changes and contracts settled in the year. Additionally, the long-term fixed price power sale contract in the US for delivery of power was transferred to Level II from Level III as all inputs were observable at Dec. 31, 2023. Our risk management profile has decreased in 2023 as most energy markets have moderated considerably from the extreme price and high volatility environment experienced for much of 2022. Our risk management profile and practices have not changed materially from Dec. 31, 2022.
Refer to the Material Accounting Policies and Critical Accounting Estimates section of this MD&A for further details regarding valuation techniques.

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Additional IFRS Measures and Non-IFRS Measures
An additional IFRS measure is a line item, heading or subtotal that is relevant to an understanding of the consolidated financial statements but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an understanding of the consolidated financial statements but is not presented elsewhere in the consolidated financial statements. We have included line items entitled gross margin and operating income (loss) in our Consolidated Statements of Earnings (Loss) for the years ended Dec. 31, 2023, 2022 and 2021. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.
We use a number of financial measures to evaluate our performance and the performance of our business segments, including measures and ratios that are presented on a non-IFRS basis, as described below. Unless otherwise indicated, all amounts are in Canadian dollars and have been derived from our consolidated financial statements prepared in accordance with IFRS. We believe that these non-IFRS amounts, measures and ratios, read together with our IFRS amounts, provide readers with a better understanding of how management assesses results.
Non-IFRS amounts, measures and ratios do not have standardized meanings under IFRS. They are unlikely to be comparable to similar measures presented by other companies and should not be viewed in isolation from, as an alternative to, or more meaningful than, our IFRS results.
Non-IFRS Financial Measures
Adjusted EBITDA, FFO, FCF, total net debt, total consolidated net debt and adjusted net debt are non-IFRS measures that are presented in this MD&A. Refer to the Segmented Financial Performance and Operating Results, Selected Quarterly Information, Financial Capital and Key Non-IFRS Financial Ratios sections of this MD&A for additional information, including a reconciliation of such non-IFRS measures to the most comparable IFRS measure.
Adjusted EBITDA
Each business segment assumes responsibility for its operating results measured by adjusted EBITDA. Adjusted EBITDA is an important metric for management that represents our core operational results. Interest, taxes, depreciation and amortization are not included, as differences in accounting treatments may distort our core business results. In addition, certain reclassifications and adjustments are made to better assess results, excluding those items that may not be reflective of ongoing business
performance. This presentation may facilitate the readers' analysis of trends.
The following are descriptions of the adjustments made.
Adjustments to Revenue
•Certain assets that we own in Canada and in Australia are fully contracted and recorded as finance leases under IFRS. We believe that it is more appropriate to reflect the payments we receive under the contracts as a capacity payment in our revenues instead of as finance lease income and a decrease in finance lease receivables.
•Adjusted EBITDA is adjusted to exclude the impact of unrealized mark-to-market gains or losses and unrealized foreign exchange gains or losses on commodity transactions.
•Adjustments are made for gains and losses related to closed positions effectively settled by offsetting positions with exchanges that have been recorded in the period the positions are settled.
Adjustments to Fuel and Purchased Power
•On the commissioning of the South Hedland facility in July 2017, we prepaid approximately $74 million of electricity transmission and distribution costs. Interest income is recorded on the prepaid funds. We reclassify this interest income as a reduction in the transmission and distribution costs expensed each period to reflect the net cost to the business.
Adjustments to Net Other Operating Income
•Insurance recoveries related to the Kent Hills tower collapse are not included as these relate to investing activities and are not reflective of ongoing business performance.
Adjustments to Earnings (Loss) in Addition to Interest, Taxes, Depreciation and Amortization
•Asset impairment charges and reversals are not included as these are accounting adjustments that impact depreciation and amortization and do not reflect ongoing business performance.
•Any gains or losses on asset sales or foreign exchange gains or losses are not included as these are not part of operating income.
Adjustments for Equity-Accounted Investments
•During the fourth quarter of 2020, we acquired a 49 per cent interest in the Skookumchuck wind facility, which is treated as an equity investment under IFRS and our proportionate share of the net earnings is reflected as equity income on the statement of earnings under IFRS. As this investment is part of our regular power-generating operations, we have included our proportionate share of the adjusted EBITDA of the Skookumchuck wind facility in our total adjusted EBITDA.

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In addition, in the Wind and Solar adjusted results, we have included our proportionate share of revenues and expenses to reflect the full operational results of this investment. We have not included EMG International, LLC’s adjusted EBITDA in our total adjusted EBITDA as it does not represent our regular power-generating operations.
Average Annual EBITDA
Average annual EBITDA is a forward-looking non-IFRS financial measure that is used to show the average annual EBITDA that the project currently under construction is expected to generate upon completion.
Funds From Operations ("FFO")
FFO is an important metric as it provides a proxy for cash generated from operating activities before changes in working capital and provides the ability to evaluate cash flow trends in comparison with results from prior periods. FFO is a non-IFRS measure.
Adjustments to Cash Flow from Operations
•FFO related to the Skookumchuck wind facility, which is treated as an equity-accounted investment under IFRS and equity income, net of distributions from joint ventures, is included in cash flow from operations under IFRS. As this investment is part of our regular power generating operations, we have included our proportionate share of FFO.
•Payments received on finance lease receivables are reclassified to reflect cash from operations.
•We adjust for items within the Energy Transition segment that may not be reflective of ongoing operations including certain costs related to decisions made to accelerate our transition off-coal in Alberta and our planned transition off-coal for Centralia. These are included in the "Clean energy transition provisions and adjustments" in the reconciliation.
•Cash received/paid on closed positions are reflected in the period that the position is settled.
•Other adjustments include payments/receipts for production tax credits, which are reductions to tax equity debt and include distributions from equity-accounted joint ventures.
Free Cash Flow ("FCF")
FCF is an important metric as it represents the amount of cash that is available to invest in growth initiatives, make scheduled principal repayments on debt, repay maturing debt, pay common share dividends or repurchase common shares. Changes in working capital are excluded so FFO and FCF are not distorted by changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and timing of receipts and payments. FCF is a non-IFRS measure.
Non-IFRS Ratios
FFO per share, FCF per share and adjusted net debt to adjusted EBITDA are non-IFRS ratios that are presented in the MD&A. Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF and Key Non-IFRS Financial Ratios sections of this MD&A for additional information.
FFO per Share and FCF per Share
FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period. FFO per share and FCF per share are non-IFRS ratios.
Supplementary Financial Measures
The Alberta electricity portfolio metrics disclosed are supplementary financial measures used to present the gross margin by segment for the Alberta market. Refer to the Alberta Electricity Portfolio section of this MD&A for additional information.

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Full Year Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment
The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the year ended Dec. 31, 2023:

| Hydro | Wind & Solar(1) | Gas | Energy Transition | Energy Marketing | Corporate | Total | Equity- accounted investments(1) | Reclass adjustments | IFRS financials
Revenues | 533 |  | 357 |  | 1,514 |  | 751 |  | 220 |  | 1 |  | 3,376 |  | (21) |  | — |  | 3,355 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Unrealized mark-to-market (gain) loss | (4) |  | 16 |  | (67) |  | (5) |  | 23 |  | — |  | (37) |  | — |  | 37 |  | — |
Realized gain (loss) on closed exchange positions | — |  | — |  | 10 |  | — |  | (91) |  | — |  | (81) |  | — |  | 81 |  | — |
Decrease in finance lease receivable | — |  | — |  | 55 |  | — |  | — |  | — |  | 55 |  | — |  | (55) |  | — |
Finance lease income | — |  | — |  | 12 |  | — |  | — |  | — |  | 12 |  | — |  | (12) |  | — |
Unrealized foreign exchange loss on commodity | — |  | — |  | 1 |  | — |  | — |  | — |  | 1 |  | — |  | (1) |  | — |
Adjusted revenues | 529 |  | 373 |  | 1,525 |  | 746 |  | 152 |  | 1 |  | 3,326 |  | (21) |  | 50 |  | 3,355 |
Fuel and purchased power | 19 |  | 30 |  | 453 |  | 557 |  | — |  | 1 |  | 1,060 |  | — |  | — |  | 1,060 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Australian interest income | — |  | — |  | (4) |  | — |  | — |  | — |  | (4) |  | — |  | 4 |  | — |
Adjusted fuel and purchased power | 19 |  | 30 |  | 449 |  | 557 |  | — |  | 1 |  | 1,056 |  | — |  | 4 |  | 1,060 |
Carbon compliance | — |  | — |  | 112 |  | — |  | — |  | — |  | 112 |  | — |  | — |  | 112 |
Gross margin | 510 | 343 |  | 964 |  | 189 |  | 152 |  | — |  | 2,158 |  | (21) |  | 46 |  | 2,183 |
OM&A | 48 |  | 80 |  | 192 |  | 64 |  | 43 |  | 115 |  | 542 |  | (3) |  | — |  | 539 |
Taxes, other than income taxes | 3 |  | 12 |  | 11 |  | 3 |  | — |  | 1 |  | 30 |  | (1) |  | — |  | 29 |
Net other operating income | — |  | (7) |  | (40) |  | — |  | — |  | — |  | (47) |  | — |  | — |  | (47) |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Insurance recovery | — |  | 1 |  | — |  | — |  | — |  | — |  | 1 |  | — |  | (1) |  | — |
Adjusted net other operating income | — |  | (6) |  | (40) |  | — |  | — |  | — |  | (46) |  | — |  | (1) |  | (47) |
Adjusted EBITDA(2) | 459 |  | 257 |  | 801 |  | 122 |  | 109 |  | (116) |  | 1,632 |  |  |  |
Equity income |  |  |  |  |  |  |  |  |  | 4 |
Finance lease income |  |  |  |  |  |  |  |  |  | 12 |
Depreciation and amortization |  |  |  |  |  |  |  |  |  | (621) |
Asset impairment reversals |  |  |  |  |  |  |  |  |  | 48 |
Interest income |  |  |  |  |  |  |  |  |  | 59 |
Interest expense |  |  |  |  |  |  |  |  |  | (281) |
Foreign exchange loss |  |  |  |  |  |  |  |  |  | (7) |
Gain on sale of assets and other |  |  |  |  |  |  |  |  |  | 4 |
Earnings before income taxes |  |  |  |  |  |  |  |  |  | 880 |

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the year ended Dec. 31, 2022:

| Hydro | Wind & Solar(1) | Gas | Energy Transition | Energy Marketing | Corporate | Total | Equity- accounted investments(1) | Reclass adjustments | IFRS financials
Revenues | 606 |  | 303 |  | 1,209 |  | 714 |  | 160 |  | (2) |  | 2,990 |  | (14) |  | — |  | 2,976 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Unrealized mark-to-market loss | 1 |  | 104 |  | 251 |  | 10 |  | 12 |  | — |  | 378 |  | — |  | (378) |  | — |
Realized gain (loss) on closed exchange positions | — |  | — |  | (4) |  | — |  | 47 |  | — |  | 43 |  | — |  | (43) |  | — |
Decrease in finance lease receivable | — |  | — |  | 46 |  | — |  | — |  | — |  | 46 |  | — |  | (46) |  | — |
Finance lease income | — |  | — |  | 19 |  | — |  | — |  | — |  | 19 |  | — |  | (19) |  | — |
Unrealized foreign exchange gain on commodity | — |  | — |  | — |  | — |  | (1) |  | — |  | (1) |  | — |  | 1 |  | — |
Adjusted revenues | 607 |  | 407 |  | 1,521 |  | 724 |  | 218 |  | (2) |  | 3,475 |  | (14) |  | (485) |  | 2,976 |
Fuel and purchased power | 22 |  | 31 |  | 641 |  | 566 |  | — |  | 3 |  | 1,263 |  | — |  | — |  | 1,263 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Australian interest income | — |  | — |  | (4) |  | — |  | — |  | — |  | (4) |  | — |  | 4 |  | — |
Adjusted fuel and purchased power | 22 |  | 31 |  | 637 |  | 566 |  | — |  | 3 |  | 1,259 |  | — |  | 4 |  | 1,263 |
Carbon compliance | — |  | 1 |  | 83 |  | (1) |  | — |  | (5) |  | 78 |  | — |  | — |  | 78 |
Gross margin | 585 |  | 375 |  | 801 |  | 159 |  | 218 |  | — |  | 2,138 |  | (14) |  | (489) |  | 1,635 |
OM&A | 55 |  | 68 |  | 195 |  | 69 |  | 35 |  | 101 |  | 523 |  | (2) |  | — |  | 521 |
Taxes, other than income taxes | 3 |  | 12 |  | 15 |  | 4 |  | — |  | 1 |  | 35 |  | (2) |  | — |  | 33 |
Net other operating income | — |  | (23) |  | (38) |  | — |  | — |  | — |  | (61) |  | 3 |  | — |  | (58) |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Insurance recovery | — |  | 7 |  | — |  | — |  | — |  | — |  | 7 |  | — |  | (7) |  | — |
Adjusted net other operating income | — |  | (16) |  | (38) |  | — |  | — |  | — |  | (54) |  | 3 |  | (7) |  | (58) |
Adjusted EBITDA(2) | 527 |  | 311 |  | 629 |  | 86 |  | 183 |  | (102) |  | 1,634 |  |  |  |
Equity income |  |  |  |  |  |  |  |  |  | 9 |
Finance lease income |  |  |  |  |  |  |  |  |  | 19 |
Depreciation and amortization |  |  |  |  |  |  |  |  |  | (599) |
Asset impairment charges |  |  |  |  |  |  |  |  |  | (9) |
Interest income |  |  |  |  |  |  |  |  |  | 24 |
Interest expense |  |  |  |  |  |  |  |  |  | (286) |
Foreign exchange gain |  |  |  |  |  |  |  |  |  | 4 |
Gain on sale of assets and other |  |  |  |  |  |  |  |  |  | 52 |
Earnings before income taxes |  |  |  |  |  |  |  |  |  | 353 |

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the year ended Dec. 31, 2021:

| Hydro | Wind & Solar(1) | Gas | Energy Transition | Energy Marketing | Corporate | Total | Equity- accounted investments(1) | Reclass adjustments | IFRS financials
Revenues | 383 |  | 323 |  | 1,109 |  | 709 |  | 211 |  | 4 |  | 2,739 |  | (18) |  | — |  | 2,721 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Unrealized mark-to-market (gain) loss | — |  | 25 |  | (40) |  | 19 |  | (38) |  | — |  | (34) |  | — |  | 34 |  | — |
Realized gain (loss) on closed exchange positions | — |  | — |  | (6) |  | — |  | 29 |  | — |  | 23 |  | — |  | (23) |  | — |
Decrease in finance lease receivable | — |  | — |  | 41 |  | — |  | — |  | — |  | 41 |  | — |  | (41) |  | — |
Finance lease income | — |  | — |  | 25 |  | — |  | — |  | — |  | 25 |  | — |  | (25) |  | — |
Unrealized foreign exchange gain on commodity | — |  | — |  | (3) |  | — |  | — |  | — |  | (3) |  | — |  | 3 |  | — |
Adjusted revenues | 383 |  | 348 |  | 1,126 |  | 728 |  | 202 |  | 4 |  | 2,791 |  | (18) |  | (52) |  | 2,721 |
Fuel and purchased power | 16 |  | 17 |  | 457 |  | 560 |  | — |  | 4 |  | 1,054 |  | — |  | — |  | 1,054 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Australian interest income | — |  | — |  | (4) |  | — |  | — |  | — |  | (4) |  | — |  | 4 |  | — |
Mine depreciation | — |  | — |  | (79) |  | (111) |  | — |  | — |  | (190) |  | — |  | 190 |  | — |
Coal inventory writedown | — |  | — |  | — |  | (17) |  | — |  | — |  | (17) |  | — |  | 17 |  | — |
Adjusted fuel and purchased power | 16 |  | 17 |  | 374 |  | 432 |  | — |  | 4 |  | 843 |  | — |  | 211 |  | 1,054 |
Carbon compliance | — |  | — |  | 118 |  | 60 |  | — |  | — |  | 178 |  | — |  | — |  | 178 |
Gross margin | 367 |  | 331 |  | 634 |  | 236 |  | 202 |  | — |  | 1,770 |  | (18) |  | (263) |  | 1,489 |
OM&A | 42 |  | 59 |  | 175 |  | 117 |  | 36 |  | 84 |  | 513 |  | (2) |  | — |  | 511 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Parts and materials writedown | — |  | — |  | (2) |  | (26) |  | — |  | — |  | (28) |  | — |  | 28 |  | — |
Curtailment gain | — |  | — |  | — |  | 6 |  | — |  | — |  | 6 |  | — |  | (6) |  | — |
Adjusted OM&A | 42 |  | 59 |  | 173 |  | 97 |  | 36 |  | 84 |  | 491 |  | (2) |  | 22 |  | 511 |
Taxes, other than income taxes | 3 |  | 10 |  | 13 |  | 6 |  | — |  | 1 |  | 33 |  | (1) |  | — |  | 32 |
Net other operating income | — |  | — |  | (40) |  | 48 |  | — |  | — |  | 8 |  | — |  | — |  | 8 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Royalty onerous contract and contract termination penalties | — |  | — |  | — |  | (48) |  | — |  | — |  | (48) |  | — |  | 48 |  | — |
Adjusted net other operating income | — |  | — |  | (40) |  | — |  | — |  | — |  | (40) |  | — |  | 48 |  | 8 |
Adjusted EBITDA(2) | 322 |  | 262 |  | 488 |  | 133 |  | 166 |  | (85) |  | 1,286 |  |  |  |
Equity income |  |  |  |  |  |  |  |  |  | 9 |
Finance lease income |  |  |  |  |  |  |  |  |  | 25 |
Depreciation and amortization |  |  |  |  |  |  |  |  |  | (529) |
Asset impairment charges |  |  |  |  |  |  |  |  |  | (648) |
Interest income |  |  |  |  |  |  |  |  |  | 11 |
Interest expense |  |  |  |  |  |  |  |  |  | (256) |
Foreign exchange gain |  |  |  |  |  |  |  |  |  | 16 |
Gain on sale of assets and other |  |  |  |  |  |  |  |  |  | 54 |
Loss before income taxes |  |  |  |  |  |  |  |  |  | (380) |

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

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Full Year Reconciliation of Cash Flow from Operations to FFO and FCF
The table below reconciles our cash flow from operating activities to our FFO and FCF:

|  |  | 2023 |  | 2022 | 2021
Cash flow from operating activities(1) |  |  | 1,464 |  |  | 877 |  | 1,001 |
Change in non-cash operating working capital balances |  |  | (124) |  |  | 316 |  | (174) |
Cash flow from operations before changes in working capital |  |  | 1,340 |  |  | 1,193 |  | 827 |
Adjustments |  |  |  |  |  |
Share of adjusted FFO from joint venture(1) |  |  | 8 |  |  | 8 |  | 13 |
Decrease in finance lease receivable |  |  | 55 |  |  | 46 |  | 41 |
Clean energy transition provisions and adjustments(2) |  |  | 11 |  |  | 42 |  | 79 |
Realized gain (loss) on closed exchanged positions |  |  | (81) |  |  | 37 |  | 23 |
Other(3) |  |  | 18 |  |  | 20 |  | 11 |
FFO(4) |  |  | 1,351 |  |  | 1,346 |  | 994 |
Deduct: |  |  |  |  |  |
Sustaining capital(1) |  |  | (174) |  |  | (142) |  | (199) |
Productivity capital |  |  | (3) |  |  | (4) |  | (4) |
Dividends paid on preferred shares |  |  | (51) |  |  | (43) |  | (39) |
Distributions paid to subsidiaries’ non-controlling interests |  |  | (223) |  |  | (187) |  | (159) |
Principal payments on lease liabilities |  |  | (10) |  |  | (9) |  | (8) |
FCF(4) |  |  | 890 |  |  | 961 |  | 585 |
Weighted average number of common shares outstanding in the period |  |  | 276 |  |  | 271 |  | 271 |
FFO per share(4) |  |  | 4.89 |  |  | 4.97 |  | 3.67 |
FCF per share(4) |  |  | 3.22 |  |  | 3.55 |  | 2.16 |

(1)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture.
(2)2023 includes amounts related to onerous contracts recognized in 2021 and a voluntary contribution to the US Defined Benefit Pension Plan for the Centralia thermal facility. During 2022, to support the employees affected by the closure of the Highvale mine and our transition off coal to cleaner sources, the Company made a voluntary special contribution of $35 million to the Highvale mine pension plan. 2022 also includes amounts related to onerous contracts recognized in 2021. 2021 includes a write-down on parts and material inventory and coal inventory for our coal operations and amounts related to onerous contracts and contract termination penalties.
(3)Other consists of production tax credits, which is a reduction to tax equity debt, less distributions from equity-accounted joint venture.
(4)These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

TransAlta Corporation | 2023 Integrated Report | M53

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

Year ended Dec. 31 |  |  | 2023 |  | 2022 | 2021
Adjusted EBITDA(1)(4) |  |  | 1,632 |  |  | 1,634 |  | 1,286 |
Provisions |  |  | (1) |  |  | 25 |  | (43) |
Net interest expense(2) |  |  | (164) |  |  | (200) |  | (200) |
Current income tax expense |  |  | (50) |  |  | (65) |  | (56) |
Realized foreign exchange loss |  |  | (4) |  |  | — |  | (2) |
Decommissioning and restoration costs settled |  |  | (37) |  |  | (35) |  | (18) |
Other non-cash items |  |  | (25) |  |  | (13) |  | 27 |
FFO(3)(4) |  |  | 1,351 |  |  | 1,346 |  | 994 |
Deduct: |  |  |  |  |  |
Sustaining capital(4) |  |  | (174) |  |  | (142) |  | (199) |
Productivity capital |  |  | (3) |  |  | (4) |  | (4) |
Dividends paid on preferred shares |  |  | (51) |  |  | (43) |  | (39) |
Distributions paid to subsidiaries’ non-controlling interests |  |  | (223) |  |  | (187) |  | (159) |
Principal payments on lease liabilities |  |  | (10) |  |  | (9) |  | (8) |
FCF(4) |  |  | 890 |  |  | 961 |  | 585 |

(1)Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section of this MD&A and reconciled to earnings (loss) before income taxes above.
(2)Net interest expense includes interest expense for the period less interest income.
(3)These items are not defined and have no standardized meaning under IFRS. FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section of this MD&A and reconciled to cash flow from operating activities above.
(4)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture.

M54 | TransAlta Corporation | 2023 Integrated Report

Fourth Quarter Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment
The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the three months ended Dec. 31, 2023:

| Hydro | Wind & Solar(1) | Gas | Energy Transition | Energy Marketing | Corporate | Total | Equity- accounted investments(1) | Reclass adjustments | IFRS financials
Revenues | 77 |  | 94 |  | 246 |  | 175 |  | 39 |  | — |  | 631 |  | (7) |  | — |  | 624 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Unrealized mark-to-market (gain) loss | (2) |  | 20 |  | 53 |  | 7 |  | (19) |  | — |  | 59 |  | — |  | (59) |  | — |
Realized gain on closed exchange positions | — |  | — |  | 23 |  | — |  | 4 |  | — |  | 27 |  | — |  | (27) |  | — |
Decrease in finance lease receivable | — |  | — |  | 15 |  | — |  | — |  | — |  | 15 |  | — |  | (15) |  | — |
Finance lease income | — |  | — |  | 2 |  | — |  | — |  | — |  | 2 |  | — |  | (2) |  | — |
Unrealized foreign exchange gain on commodity | — |  | — |  | 1 |  | — |  | — |  | — |  | 1 |  | — |  | (1) |  | — |
Adjusted revenues | 75 |  | 114 |  | 340 |  | 182 |  | 24 |  | — |  | 735 |  | (7) |  | (104) |  | 624 |
Fuel and purchased power | 5 |  | 8 |  | 127 |  | 138 |  | — |  | — |  | 278 |  | — |  | — |  | 278 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Australian interest income | — |  | — |  | (1) |  | — |  | — |  | — |  | (1) |  | — |  | 1 |  | — |
Adjusted fuel and purchased power | 5 |  | 8 |  | 126 |  | 138 |  | — |  | — |  | 277 |  | — |  | 1 |  | 278 |
Carbon compliance | — |  | — |  | 27 |  | — |  | — |  | — |  | 27 |  | — |  | — |  | 27 |
Gross margin | 70 |  | 106 |  | 187 |  | 44 |  | 24 |  | — |  | 431 |  | (7) |  | (105) |  | 319 |
OM&A | 13 |  | 25 |  | 56 |  | 18 |  | 10 |  | 29 |  | 151 |  | (1) |  | — |  | 150 |
Taxes, other than income taxes | 1 |  | 1 |  | — |  | — |  | — |  | 1 |  | 3 |  | — |  | — |  | 3 |
Net other operating income | — |  | (3) |  | (10) |  | — |  | — |  | — |  | (13) |  | — |  | — |  | (13) |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Insurance recovery | — |  | 1 |  | — |  | — |  | — |  | — |  | 1 |  | — |  | (1) |  | — |
Adjusted net other operating income | — |  | (2) |  | (10) |  | — |  | — |  | — |  | (12) |  | — |  | (1) |  | (13) |
Adjusted EBITDA(2) | 56 |  | 82 |  | 141 |  | 26 |  | 14 |  | (30) |  | 289 |  |  |  |
Equity income |  |  |  |  |  |  |  |  |  | 3 |
Finance lease income |  |  |  |  |  |  |  |  |  | 2 |
Depreciation and amortization |  |  |  |  |  |  |  |  |  | (132) |
Asset impairment reversals |  |  |  |  |  |  |  |  |  | (26) |
Interest income |  |  |  |  |  |  |  |  |  | 12 |
Interest expense |  |  |  |  |  |  |  |  |  | (66) |
Foreign exchange loss |  |  |  |  |  |  |  |  |  | (7) |
Loss before income taxes |  |  |  |  |  |  |  |  | (35) |

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

TransAlta Corporation | 2023 Integrated Report | M55

The following table reflects adjusted EBITDA by segment and provides reconciliation to loss before income taxes for the three months ended Dec. 31, 2022:

| Hydro | Wind & Solar(1) | Gas | Energy Transition | Energy Marketing | Corporate | Total | Equity- accounted investments(1) | Reclass adjustments | IFRS financials
Revenues | 159 |  | 98 |  | 276 |  | 281 |  | 44 |  | — |  | 858 |  | (4) |  | — |  | 854 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Unrealized mark-to-market (gain) loss | 1 |  | 23 |  | 238 |  | (7) |  | 12 |  | — |  | 267 |  | — |  | (267) |  | — |
Realized gain on closed exchange positions | — |  | — |  | 7 |  | — |  | 20 |  | — |  | 27 |  | — |  | (27) |  | — |
Decrease in finance lease receivable | — |  | — |  | 12 |  | — |  | — |  | — |  | 12 |  | — |  | (12) |  | — |
Finance lease income | — |  | — |  | 4 |  | — |  | — |  | — |  | 4 |  | — |  | (4) |  | — |
Unrealized foreign exchange gain on commodity | — |  | — |  | — |  | — |  | (1) |  | — |  | (1) |  | — |  | 1 |  | — |
Adjusted revenues | 160 |  | 121 |  | 537 |  | 274 |  | 75 |  | — |  | 1,167 |  | (4) |  | (309) |  | 854 |
Fuel and purchased power | 5 |  | 11 |  | 196 |  | 234 |  | — |  | — |  | 446 |  | — |  | — |  | 446 |
Reclassifications and adjustments: |  |  |  |  |  |  |  |  |  |
Australian interest income | — |  | — |  | (1) |  | — |  | — |  | — |  | (1) |  | — |  | 1 |  | — |
Adjusted fuel and purchased power | 5 |  | 11 |  | 195 |  | 234 |  | — |  | — |  | 445 |  | — |  | 1 |  | 446 |
Carbon compliance | — |  | — |  | 27 |  | — |  | — |  | — |  | 27 |  | — |  | — |  | 27 |
Gross margin | 155 |  | 110 |  | 315 |  | 40 |  | 75 |  | — |  | 695 |  | (4) |  | (310) |  | 381 |
OM&A | 22 |  | 18 |  | 57 |  | 19 |  | 12 |  | 30 |  | 158 |  | (1) |  | — |  | 157 |
Taxes, other than income taxes | — |  | 5 |  | 2 |  | 2 |  | — |  | — |  | 9 |  | (1) |  | — |  | 8 |
Net other operating income | — |  | (5) |  | (8) |  | — |  | — |  | — |  | (13) |  | 3 |  | — |  | (10) |
Adjusted EBITDA(2) | 133 |  | 92 |  | 264 |  | 19 |  | 63 |  | (30) |  | 541 |  |  |  |
Equity income |  |  |  |  |  |  |  |  |  | 4 |
Finance lease income |  |  |  |  |  |  |  |  |  | 4 |
Depreciation and amortization |  |  |  |  |  |  |  |  |  | (188) |
Asset impairment charges |  |  |  |  |  |  |  |  |  | (5) |
Interest income |  |  |  |  |  |  |  |  |  | 10 |
Interest expense |  |  |  |  |  |  |  |  |  | (77) |
Foreign exchange loss |  |  |  |  |  |  |  |  |  | (13) |
Gain on sale of assets and other |  |  |  |  |  |  |  |  |  | 46 |
Earnings before income taxes |  |  |  |  |  |  |  |  |  | 7 |

(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

M56 | TransAlta Corporation | 2023 Integrated Report

Fourth Quarter Reconciliation of Cash Flow from Operations to FFO and FCF
The table below reconciles our cash flow from operating activities to our FFO and FCF:

Three months ended Dec. 31 | 2023 |  | 2022 |  |  |
Cash flow from operating activities(1) | 310 |  |  | 351 |  |  |  |
Change in non-cash operating working capital balances | (135) |  |  | 64 |  |  |  |
Cash flow from operations before changes in working capital | 175 |  |  | 415 |  |  |  |
Adjustments |  |  |  |  |  |
Share of adjusted FFO from joint venture(1) | (2) |  |  | 1 |  |  |  |
Decrease in finance lease receivable | 15 |  |  | 12 |  |  |  |
Clean energy transition provisions and adjustments(2) | 4 |  |  | 7 |  |  |  |
Realized gain on closed exchanged positions | 27 |  |  | 21 |  |  |  |
Other(3) | 10 |  |  | 3 |  |  |  |
FFO(3) | 229 |  |  | 459 |  |  |  |
Deduct: |  |  |  |  |  |
Sustaining capital(1) | (74) |  |  | (67) |  |  |  |
Productivity capital | (1) |  |  | (1) |  |  |  |
Dividends paid on preferred shares | (12) |  |  | (12) |  |  |  |
Distributions paid to subsidiaries’ non-controlling interests | (19) |  |  | (61) |  |  |  |
Principal payments on lease liabilities | (2) |  |  | (3) |  |  |  |
FCF(4) | 121 |  |  | 315 |  |  |  |
Weighted average number of common shares outstanding in the period | 308 |  |  | 269 |  |  |  |
FFO per share(4) | 0.74 |  |  | 1.71 |  |  |  |
FCF per share(4) | 0.39 |  |  | 1.17 |  |  |  |

(1)Includes our share of amounts for Skookumchuck, an equity-accounted joint venture.
(2)Includes amounts related to onerous contracts recognized in 2021 and a voluntary contribution to the US Defined Benefit Pension Plan for the Centralia thermal facility.
(3)Other consists of production tax credits, which is a reduction to tax equity debt, less distributions from the equity-accounted joint venture.
(4)These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

TransAlta Corporation | 2023 Integrated Report | M57

The table below provides a reconciliation of our adjusted EBITDA to our FFO and FCF for the three months ended Dec 31. 2023 and 2022:

Three months ended Dec. 31 | 2023 |  | 2022 |  |
Adjusted EBITDA(1)(4) | 289 |  |  | 541 |  |  |
Provisions | (1) |  |  | 20 |  |  |
Net interest expense(2) | (41) |  |  | (49) |  |  |
Current income tax recovery (expense) | 5 |  |  | (29) |  |  |
Realized foreign exchange gain (loss) | 9 |  |  | (18) |  |  |
Decommissioning and restoration costs settled | (15) |  |  | (12) |  |  |
Other non-cash items | (17) |  |  | 6 |  |  |
FFO(3)(4) | 229 |  |  | 459 |  |  |
Deduct: |  |  |  |  |
Sustaining capital(4) | (74) |  |  | (67) |  |  |
Productivity capital | (1) |  |  | (1) |  |  |
Dividends paid on preferred shares | (12) |  |  | (12) |  |  |
Distributions paid to subsidiaries’ non-controlling interests | (19) |  |  | (61) |  |  |
Principal payments on lease liabilities | (2) |  |  | (3) |  |  |
FCF(4) | 121 |  |  | 315 |  |  |

(1)Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section of this MD&A and reconciled to earnings (loss) before income taxes above.
(2)Net interest expense includes interest expense for the period less interest income.
(3)These items are not defined and have no standardized meaning under IFRS. FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section of this MD&A and reconciled to cash flow from operating activities above.
(4)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture.

M58 | TransAlta Corporation | 2023 Integrated Report

Key Non-IFRS Financial Ratios
The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These
metrics and ratios are not defined and have no standardized meaning under IFRS and may not be comparable to those used by other entities or by rating agencies.
Adjusted Net Debt to Adjusted EBITDA

Year ended Dec. 31 | 2023 |  | 2022 | 2021
Period-end long-term debt(1) | 3,466 |  |  | 3,653 |  | 3,267 |
Exchangeable debentures | 344 |  |  | 339 |  | 335 |
Less: Cash and cash equivalents(2) | (345) |  |  | (1,118) |  | (947) |
Add: 50 per cent of issued preferred shares and exchangeable preferred shares(3) | 671 |  |  | 671 |  | 671 |
Other(4) | (12) |  |  | (20) |  | (19) |
Adjusted net debt(5) | 4,124 |  |  | 3,525 |  | 3,307 |
Adjusted EBITDA(6) | 1,632 |  |  | 1,634 |  | 1,286 |
Adjusted net debt to adjusted EBITDA (times) | 2.5 |  |  | 2.2 |  | 2.6 |

(1)Consists of current and long-term portion of debt, which includes lease liabilities and tax equity financing.
(2)Cash and cash equivalents, net of bank overdraft.
(3)Exchangeable preferred shares are considered equity with dividend payments for credit-rating purposes. For accounting purposes, they are accounted for as debt with interest expense in the consolidated financial statements. For purposes of this ratio, we consider 50 per cent of issued preferred shares, including these, as debt.
(4)Includes principal portion of TransAlta OCP restricted cash ($17 million for 2023, 2022 and 2021) and fair value of hedging instruments on debt (included in risk management assets and/or liabilities on the Consolidated Statements of Financial Position).
(5)The tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in this amount. Adjusted net debt is not defined and has no standardized meaning under IFRS. Presenting this item from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(6)Last 12 months.
The Company's capital is managed using a net debt position. We use the adjusted net debt to adjusted EBITDA ratio as a measurement of financial leverage and to assess our ability to service debt. Our target for adjusted net debt to adjusted EBITDA is 3.0 to 4.0 times. Our adjusted net debt
to adjusted EBITDA ratio for Dec. 31, 2023 was higher compared to Dec. 31, 2022, due to higher adjusted net debt resulting from lower cash and cash equivalents due to the acquisition of TransAlta Renewables, partially offset by scheduled debt repayments and a lower amount outstanding on the credit facility at the end of 2023.
2024 Outlook
For 2024, the Company expects adjusted EBITDA to be in the range of $1.15 billion to $1.3 billion and FCF to be in the range of $450 million to $600 million which is based on the following:
•Higher contribution from the wind and solar portfolio due to the full year impact of new asset additions of the Garden Plain wind facility and Northern Goldfields solar facilities, as well as the full return to service of Kent Hills wind facilities in the first quarter of 2024;
•Contributions from the addition of Mount Keith transmission;
•Contributions from the commercial operation of the White Rock and Horizon Hill wind projects which are expected in the first quarter of 2024;
•Contribution from the Heartland Generation acquisition, which is expected to close in 2024;
•Lower contributions from the legacy merchant hydro, wind and gas portfolio in Alberta which are expected to step down due to lower expected average power prices in Alberta given the baseload gas and renewables supply additions expected in 2024;

TransAlta Corporation | 2023 Integrated Report | M59

•Higher expected current income tax expense in 2024 in the absence of growth that could defer or partially offset the Company's tax horizon; and
•Increased net interest expense in 2024 as a result of lower interest income earned on lower cash deposits and lower capitalized interest on growth projects.
The following table outlines our expectations on key financial targets and related assumptions for 2024 and should be read in conjunction with the narrative discussion that follows and the Governance and Risk Management section of this MD&A:

Measure | 2024 Target | Updated Target 2023 | 2023 Actuals
Adjusted EBITDA(1)(2) | $1,150 million - $1,300 million | $1,700 million - $1,800 million | $1,632 million
FCF(1)(2) | $450 million - $600 million | $850 million - $950 million | $890 million
FCF per share | $1.47 - $1.96 | $2.77 - $3.10 | $3.22
Dividend | $0.24 per share annualized | $0.22 per share annualized | $0.22 per share annualized

(1)These items are not defined and have no standardized meaning under IFRS. Refer to the Reconciliation of Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(2)During the second quarter of 2023, the Company revised and increased our 2023 guidance for adjusted EBITDA and FCF based on the strong financial performance attained in the first half of the year and our expectations for the balance of the year.
The Company's outlook for 2024 may be impacted by a number of factors as detailed further below.
Range of key 2024 power and gas price assumptions

Market |  | 2024 Assumptions | Updated Target 2023 | 2023 Actuals |
Alberta spot ($/MWh) |  | $75 to $95 | $150 to $170 | $134 |
Mid-C spot (US$/MWh) |  | US$85 to US$95 | US$90 to US$110 | US$76 |
AECO gas price ($/GJ) |  | $2.50 to $3.00 | $2.50 | $2.54 |

Alberta spot price sensitivity: a +/- $1 per MWh change in spot price is expected to have a +/-$5 million impact on adjusted EBITDA for 2024.
Other assumptions relevant to the 2024 outlook

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

Alberta Hedging

Range of hedging assumptions |  |  |  | 2024 |
Hedged production (GWh) |  |  |  | 8,152 |  |
Hedge price ($/MWh) |  |  |  | $85 |
Hedged gas volumes (GJ) |  |  |  | 62 million |
Hedge gas prices ($/GJ) |  |  |  | $2.76 |

M60 | TransAlta Corporation | 2023 Integrated Report

Market Pricing
The following graphs include 2024 pricing based on a range of assumptions and is subject to change:
Annual Average Spot Electricity Prices
Annual Average Gas (AECO) Prices
For 2024, spot electricity prices in Alberta are expected to be lower compared to 2023, driven by normalized weather expectations and the anticipated additions of new natural gas, and wind and solar supply. Spot electricity prices in the Pacific Northwest are expected to be higher in 2024, but will depend on the actual hydrology for the region during the year.
AECO natural gas prices are expected to be comparable to 2023.
The objective of our portfolio management strategy in Alberta is to balance opportunity and risk and to deliver optimization strategies that contribute to our total
investment, which includes a return on invested capital. We can be more or less hedged in a given period, and we expect to realize our annual targets through a combination of forward hedging and selling generation into the spot market. The assets within the Alberta electricity portfolio are managed as a portfolio to maximize the overall value of generation and capacity from our hydro, wind, energy storage and thermal facilities. Hedging is a key component of cash flow certainty and the hedges are primarily tied to our portfolio of gas assets and opportunistically allocated to our portfolio of hydro facilities rather than a single facility.
Sustaining Capital Expenditures
Our estimate for total sustaining capital is as follows:

|  | Spent in 2023 | Expected spend in 2024
Total sustaining capital (millions) |  | 174 |  | 130-150

The Company expects sustaining capital to be in the range of $130 million to $150 million. The midpoint for the range represents a 10 per cent decrease from the midpoint of the 2023 outlook sustaining capital range of $140 million to $170 million, and a 20 per cent decrease from 2023 sustaining capital spend. This is driven by lower sustaining capital expenditures for planned major maintenance related to the gas assets and lower costs associated with the relocation of the Company's head office.
Liquidity and Capital Resources
We expect to maintain adequate available liquidity under our committed credit facilities. As at Dec. 31, 2023, we had access to $1.7 billion in liquidity, including $345 million in cash, net of bank overdraft; which significantly exceeds the funds required for committed growth, sustaining capital and productivity projects. .

TransAlta Corporation | 2023 Integrated Report | M61

Material Accounting Policies and Critical Accounting Estimates
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules and guidance have changed. Accounting rules generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing rules and the use of judgment relative to the circumstances existing in the business. Every effort is made to comply with all applicable rules on or before the effective date and we believe the proper implementation and consistent application of accounting rules is critical.
However, not all situations are specifically addressed in the accounting literature. In these cases, our best judgment is used to adopt a policy for accounting for these situations. We draw analogies to similar situations and the accounting guidelines governing them, consider foreign accounting standards and consult with our independent auditors about the appropriate interpretation and application of these policies. Each of the critical accounting policies involves complex situations and a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our consolidated financial statements.
Our material accounting policies are described in Note 2 of the consolidated financial statements. Each policy involves a number of estimates and assumptions to be made about matters that are uncertain at the time the estimate is made. Different estimates, with respect to key variables used for the calculations, or changes to estimates, could potentially have a material impact on our financial position or results of operations.
We have discussed the development and selection of these critical accounting estimates with the Audit, Finance and Risk Committee ("AFRC") of the Board of Directors and our independent auditors. The AFRC has reviewed and approved our disclosure relating to critical accounting estimates in this MD&A. These critical accounting estimates are described as follows:
Revenue Recognition
Revenue from Contracts with Customers
Identification of Performance Obligations
Where contracts contain multiple promises for goods or services, management exercises judgment in determining whether goods or services constitute distinct goods or services or a series of distinct goods or services that are substantially the same and that have the same pattern of transfer to the customer. The determination of a performance obligation affects whether the transaction price is recognized at a point in time or over time. Management considers both the mechanics of the contract
and the economic and operating environment of the contract in determining whether the goods or services in a contract are distinct.
Transaction Price
In determining the transaction price and estimates of variable consideration, management considers the past history of customer usage and capacity requirements when estimating the goods and services to be provided to the customer. The Company also considers the historical production levels and operating conditions for its variable generating assets.
Allocation of Transaction Price to Performance Obligations
When multiple performance obligations are present in a contract, transaction price is allocated to each performance obligation in an amount that depicts the consideration the Company expects to be entitled to in exchange for transferring the good or service.
The Company’s contracts generally outline a specific amount to be invoiced to a customer associated with each performance obligation in the contract. Where contracts do not specify amounts for individual performance obligations, the Company estimates the amount of the transaction price to allocate to individual performance obligations based on their standalone selling price, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions.
Satisfaction of Performance Obligations
The satisfaction of performance obligations requires management to use judgment as to when control of the underlying good or service transfers to the customer. Determining when a performance obligation is satisfied affects the timing of revenue recognition. Management considers both customer acceptance of the good or service and the impact of laws and regulations such as certification requirements in determining when this transfer occurs. Management also applies judgment in determining whether the invoice practical expedient permits recognition of revenue at the invoiced amount if that invoiced amount corresponds directly with the entity's performance to date.
Revenue from Other Sources
Revenue from Derivatives
Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales contracts, futures contracts and options that are used to earn revenues and to gain market information. These derivatives are accounted for using fair value accounting. The determination of the fair value of commodity risk management contracts and derivative instruments is complex and relies on judgments concerning future prices, volatility and liquidity, among other factors.

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Some of our derivatives are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available, requiring us to use internal valuation techniques or other models such as numerical derivative valuation or scenario analysis.
Merchant Revenue
Revenues from non-contracted capacity (i.e., merchant) are comprised of energy payments, at market price, for each MWh produced and are recognized upon delivery.
Financial Instruments
The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by reference to prices for instruments in active markets to which we have access. In the absence of an active market, we determine fair values based on valuation models or by reference to other similar products in active markets.
Fair values determined using valuation models require the use of assumptions. In determining those assumptions, we look primarily to external readily observable market inputs. However, if not available, we use inputs that are not based on observable market data.
Level Determinations and Classifications
The Level I, II and III classifications in the fair value hierarchy are utilized by the Company. The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the lowest level input that is significant to the derivation of the fair value. Refer to Note 14(I) and (II) from our consolidated financial statements for further details on the inputs used for each level.
The effect of using reasonably possible alternative assumptions as inputs to valuation techniques for contracts included in the Level III fair value measurements at Dec. 31, 2023, is an estimated total upside of $92 million (2022 – $193 million) and total downside of $116 million (2022 – $287 million) impact to the carrying value of the financial instruments. Fair values are stressed for unobservable inputs, which can include variable volumes, unobservable prices and wind discounts, among other inputs. The variable volumes are stressed up and down based on historically available production data. Prices are stressed for longer-term deals where there are no liquid market quotes using various internal and external forecasting sources to establish a high and a low price range. Wind discounts represent price to volume relationships and are stressed specific to each location.
In addition to the Level III fair value measurements discussed above, the Brookfield Investment Agreement allows Brookfield the option to exchange all of the
outstanding exchangeable securities into an equity ownership interest of up to a maximum of 49 per cent in an entity formed to hold TransAlta’s Alberta Hydro Assets after Dec. 31, 2024. The fair value of the option to exchange is considered a Level III fair value measurement, with an estimated downside of $25 million (2022 – $25 million) potential impact to the carrying value of nil as at Dec. 31, 2023 (2022 – nil). The sensitivity analysis has been prepared using the Company’s assessment that a change in the implied discount rate of the future cash flow of one per cent is a reasonably possible change.
Valuation of PP&E and Associated Contracts
At the end of each reporting period, we assess whether there is any indication that PP&E and finite life intangible assets are impaired or whether a previously recognized impairment may no longer exist or may have decreased.
Our operations, the market and business environment are routinely monitored and judgments and assessments are made to determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is made of the recoverable amount of the asset or cash-generating unit (“CGU”) to which the asset belongs. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets and goodwill is allocated to each CGU or group of CGUs that is expected to benefit from the synergies of the acquisition from which the goodwill arose. The recoverable amount is the higher of an asset’s fair value less costs of disposal or its value in use. Fair value is the price that would be received to sell an asset in an orderly transaction between market participants at the measurement date. In determining fair value less costs of disposal, information about third-party transactions for similar assets is used and if none is available, other valuation techniques, such as discounted cash flows, are used. Value in use is computed using the present value of management’s best estimates of future cash flows based on the current use and present condition of the asset. In estimating either fair value less costs of disposal or value in use using discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel consumed, capital expenditures, retirement costs and other related cash inflows and outflows over the life of the facilities, which can range from 30 to 49 years. In developing these assumptions, management uses estimates of contracted and future market prices based on expected market supply and demand in the region in which the facility operates, anticipated production levels, planned and unplanned outages, changes to regulations and transmission capacity or constraints for the remaining life of the facilities.

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Discount rates are determined by employing a weighted average cost of capital methodology that is based on capital structure, cost of equity and cost of debt assumptions based on comparable companies with similar risk characteristics and market data as the asset, CGU or group of CGUs subject to the test. These estimates and assumptions are susceptible to change from period to period and actual results can and often do differ from the estimates and can have either a positive or negative impact on the estimate of the impairment charge and may be material.
The impairment outcome can also be impacted by the determination of CGUs or groups of CGUs for asset and goodwill impairment testing. The allocation of goodwill is reassessed upon changes in the composition of segments, CGUs or groups of CGUs. In respect of determining CGUs, significant judgment is required to determine what constitutes independent cash flows between power facilities that are connected to the same system. We evaluate the market design, transmission constraints and the contractual profile of each facility, as well as our commodity price risk management plans and practices, in order to inform this determination. With regard to the allocation or reallocation of goodwill, significant judgment is required to evaluate synergies and their impacts. Minimum thresholds also exist with respect to segmentation and internal monitoring activities.
We evaluate synergies with regard to opportunities from combined talent and technology, functional organization and future growth potential and we consider our own performance measurement processes in making this determination. No changes arose in our CGUs in 2023.
PP&E impairment charges can be reversed in future periods if circumstances improve. No assurances can be given if any reversal will occur or the amount or timing of any such reversal.
Asset Impairments
Hydro
During 2023, internal valuations indicated the fair value less costs of disposal for two hydro facilities exceeded the carrying value due to a contract extension and changes in power price assumptions, which favourably impacted estimated future cash flows and resulted in a full recoverability test. As a result of the recoverability test an impairment reversal of $10 million was recognized.
Wind and Solar
During 2023, the Company recorded a net impairment reversal of $4 million as a result of changes in power price assumptions for two wind facilities, which favourably impacted estimated future cash flows and resulted in a full recoverability test.
Valuation of Goodwill
We evaluate goodwill for impairment at least annually, or more frequently if indicators of impairment exist. If the carrying amount of a CGU or group of CGUs, including goodwill, exceeds the unit’s fair value, the excess represents a goodwill impairment loss.
For the purposes of the 2023 goodwill impairment review, the Company determined the recoverable amounts of the Wind and Solar segment by calculating the fair value less costs of disposal using discounted cash flow projections. In 2023, the Company relied on the recoverable amounts determined in 2022 for the Hydro and Energy Marketing segments in performing the 2023 goodwill impairment review. The recoverable amounts are based on the Company’s long-range forecasts for the periods extending to the last planned asset retirement in 2072. The resulting fair value measurement is categorized within Level III of the fair value hierarchy. We have determined there were no goodwill impairments for 2023, 2022 and 2021.
Determining the fair value of the CGUs or group of CGUs is susceptible to changes from period to period as management is required to make assumptions about future cash flows, including estimates of contracted and future market prices based on expected market supply and demand in the region in which the facility operates, anticipated production levels, planned and unplanned outages, changes to regulations and transmission capacity or constraints for the remaining life of the facilities.
Project Development Costs
Project development costs include external, direct and incremental costs that are necessary for completing an acquisition or construction project. The appropriateness of capitalization of these costs is evaluated each reporting period and amounts capitalized for projects no longer probable of occurring are charged to net earnings (loss).
Useful Life of PP&E
Each significant component of an item of PP&E is depreciated over its estimated useful life. A component is a tangible asset that can be separately identified as an asset and is expected to provide a benefit of greater than one year. Estimated useful lives are determined based on current facts and past experience and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological obsolescence and regulations. The useful lives of PP&E and depreciation rates used are reviewed at least annually to ensure they continue to be appropriate.

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Change in Estimate - Useful Lives
During 2023, the Company adjusted the useful lives of certain assets in the Gas segment to reflect changes made based on future operating expectations of the assets. This resulted in a decrease of $92 million in depreciation expense that was recognized in the Consolidated Statement of Earnings (Loss) in 2023.
Leases
In determining whether the Company's contracts contain, or are, leases, management must use judgment to assess whether the contract provides the customer with the right to substantially all of the economic benefits from the use of the asset during the lease term and whether the customer obtains the right to direct the use of the asset during the lease term. For those agreements considered to contain, or be, leases, further judgment is required to determine the lease term by assessing whether termination or extension options are reasonably certain to be exercised. Judgment is also applied in identifying in-substance fixed payments (included) and variable payments that are based on usage or performance factors (excluded) and in identifying lease and non-lease components (services that the supplier performs) of contracts and in allocating contract payments to lease and non-lease components.
For leases where the Company is a lessor, judgment is required to determine if substantially all of the significant risks and rewards of ownership are transferred to the customer or remains with the Company, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant and impact how we classify amounts related to the arrangement as either PP&E or as a finance lease receivable on the Consolidated Statements of Financial Position and therefore the amount of certain items of revenue and expense are dependent upon such classifications.
Income Taxes
Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of the jurisdictions in which we operate. The process also involves making an estimate of taxes currently payable and income taxes expected to be payable or recoverable in future periods, referred to as deferred income taxes. An assessment must also be made to determine the likelihood that our future taxable income will be sufficient to permit the recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be reduced. The reduction of the deferred income tax asset can be reversed if the estimated future taxable income improves. No assurances can be given if any reversal will occur or the amount or timing of any such reversal. Management must exercise judgment in its assessment of continually
changing tax interpretations, regulations and legislation to ensure deferred income tax assets and liabilities are complete and fairly presented. Differing assessments and applications than our estimates could materially impact the amount recognized for deferred income tax assets and liabilities. Our tax filings are subject to audit by taxation authorities. The outcome of some audits may change our tax liability, although we believe that we have adequately provided for income taxes in accordance with IFRS based on all information currently available. The outcome of pending audits is not known nor is the potential impact on the consolidated financial statements determinable.
Employee Future Benefits
We provide selected pension and other post-employment benefits to employees, such as health and dental benefits. The cost of providing these benefits is dependent upon many factors, including actual plan experience and estimates and assumptions about future experience.
The liabilities for pension, other post-employment benefits and associated pension costs included in annual compensation expenses are impacted by employee demographics, including age, compensation levels, employment periods, the level of contributions made to the plans and earnings on plan assets.
Changes to the provisions of the plans may also affect current and future pension costs. Pension costs may also be significantly impacted by changes in key actuarial assumptions, including, for example, the discount rates used in determining the defined benefit obligation and the net interest cost on the net defined benefit liability. The discount rate used to estimate our obligation reflects high-quality corporate fixed income securities currently available and expected to be available during the period to maturity of the pension benefits.
Defined Benefit Obligation
The liability for pension and post-employment benefits and associated costs included in compensation expenses are impacted by estimates related to changes in key actuarial assumptions, including discount rates. The defined benefit obligation has increased by $5 million to $155 million as at Dec. 31, 2023, from $150 million as at Dec. 31, 2022. A one per cent increase in discount rates would have a $40 million impact on the defined benefit obligation.
Decommissioning and Restoration Provisions
We recognize decommissioning and restoration provisions for generating facilities and mine sites in the period in which they are incurred if there is a legal or constructive obligation to remove the facilities and restore the site. The amount recognized as a provision is the best estimate of the expenditures required to settle the provision. Expected

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values are probability weighted to deal with the risks and uncertainties inherent in the timing and amount of settlement of many decommissioning and restoration provisions. Expected values are discounted at the current market-based risk-free interest rate adjusted to reflect the market’s evaluation of our credit standing.
The Company recognizes provisions for decommissioning obligations. Initial decommissioning provisions and subsequent changes thereto, are determined using the Company’s best estimate of the required cash expenditures, adjusted to reflect the risks and uncertainties inherent in the timing and amount of settlement.
During 2023, the decommissioning and restoration provision decreased by $89 million due to revisions in estimated cash flows and timing of cash flows for certain Gas and Energy Transition assets. The timing of cash flows was adjusted to optimize and maximize efficiencies by staging required reclamation work. Operating assets included in PP&E decreased by $34 million and $55 million was recognized as an impairment reversal in net earnings related to retired assets.
During 2023, revisions in discount rates increased the decommissioning and restoration provision by $52 million due to a decrease in discount rates, largely driven by decreases in long-term market benchmark rates. On average, discount rates decreased compared to 2022, with rates ranging from 6.0 to 9.0 per cent as at Dec. 31, 2023. This has resulted in a corresponding increase in PP&E of $31 million on operating assets and the recognition of a $21 million impairment charge in net earnings related to retired assets.
Other Provisions
Where necessary, we recognize provisions arising from ongoing business activities, such as interpretation and application of contract terms, ongoing litigation and force majeure claims. These provisions and subsequent changes thereto, are determined using our best estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially from the amount recognized.
Classification of Joint Arrangements
Upon entering into a joint arrangement, the Company must classify it as either a joint operation or joint venture and the classification affects the accounting for the joint arrangement. In making this classification, the Company exercises judgment in evaluating the terms and conditions of the arrangement to determine whether the parties have rights to the assets and obligations or rights to the net assets. Factors such as the legal structure, contractual arrangements and other facts and circumstances, such as where the purpose of the arrangement is primarily for the provision of the output to the parties and when the parties are substantially the only source of cash flows for the arrangement, must be evaluated to understand the rights of the parties to the arrangement.
Significant Influence
Upon entering into an investment, the Company must classify it as either an investment as an associate or an investment under IFRS 9. In making this classification, the Company exercises judgment in evaluating whether the Company has significant influence over the investee. Significant influence is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control over those policies. If the Company holds 20 per cent or more of the voting rights in the investee, it is presumed that the entity has significant influence, unless it can be clearly demonstrated that this is not the case. Other factors such as representation on the board of directors, participation in policy-making processes, material transactions between the Company and investee, interchange of managerial personnel or providing essential technical information are considered when assessing if the Company has significant influence over an investee.

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Accounting Changes
Current Accounting Changes
Amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction
On May 7, 2021, the International Accounting Standards Board (“IASB”) issued Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction, which amends IAS 12 Income Taxes. The amendments clarify that the initial recognition exemption under IAS 12 does not apply to transactions such as leases and decommissioning obligations. These transactions give rise to equal and offsetting temporary differences in which deferred tax should be recognized.
The amendments are effective for annual periods beginning on or after Jan. 1, 2023, and were adopted by the Company on that date. The Company's accounting aligns with the amendment and no financial impact arose upon adoption.
Amendments to IAS 12 International Tax Reform — Pillar Two Model Rules
The Organization for Economic Co-operation and Development (OECD) published Pillar Two model rules in December 2021 to ensure that large multinational companies would be subject to a minimum 15 per cent tax rate. In May 2023, the IASB issued amendments to IAS 12 Income Taxes to provide companies with immediate temporary relief from accounting for deferred taxes arising from the OECD international tax reform. The amendments clarify that IAS 12 applies to income taxes arising from tax law enacted or substantively enacted to implement the Pillar Two model rules published by the OECD. Pillar Two legislation has not been enacted or substantively enacted
in any jurisdiction in which the Company operates and therefore has not been reflected within our tax provisions at Dec. 31, 2023.
Future Accounting Changes
Amendments to IAS 1 Non-current Liabilities with Covenants and Classification of Liabilities as Current or Non-current
In October 2022, the IASB issued Non-current Liabilities with Covenants, which amends IAS 1 Presentation of Financial Statements, to clarify how conditions with which an entity must comply within 12 months after the reporting period affect the classification of a liability. In January 2020, the IASB issued Classification of Liabilities as Current or Non-current, which amends IAS 1 Presentation of Financial Statements regarding the classification of liabilities as current or non‐current, clarifying that contractual rights and conditions existing at the end of the reporting period are relevant in determining whether the Company has a right to defer settlement of a liability by at least 12 months.
Additionally, the IASB clarified that the classification of a liability is unaffected by the likelihood that an entity will exercise its deferral right. The amendments are effective for annual periods beginning on or after Jan. 1, 2024, and are to be applied retrospectively. On Jan. 1, 2024, the Company will re-classify the Exchangeable Securities from non-current liabilities to current liabilities as the conversion option can be exercised at any time after Jan. 1, 2025, although there is no obligation to deliver cash equivalent resources and the holder cannot call for repayment. This accounting is consistent with the amendment.
Environmental, Social and Governance
Sustainability, or ESG management and performance, is a priority at TransAlta. Sustainability is one of our core values, which means it is part of our corporate culture. We perpetually strive to further integrate sustainability into our governance, decision-making, risk management and day-to-day business processes, while enabling our growth strategy. The ultimate outcome of our sustainability focus is continuous improvement on key, material ESG issues and ensuring our economic value creation is balanced with a value proposition for the environment and our stakeholders.
Our key strategic sustainability pillars build on our corporate strategy and weave through our business. Our track record in these areas illustrates our commitment to
sustainability (including climate change leadership and safety). In other areas, where we have set new goals in recent years (including equity, diversity and inclusion), we believe the focus will only strengthen our corporate strategy and support value creation into the future. Our pillars include:
•Clean, Reliable and Sustainable Electricity Production
•Safe, Healthy, Diverse and Engaged Workplace
•Positive Indigenous, Stakeholder and Customer Relationships
•Progressive Environmental Stewardship
•Technology and Innovation

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Reporting on Our Material Sustainability Factors
TransAlta has been reporting on sustainability since 1994. The Company's ESG reporting content is integrated within this MD&A to provide information on how ESG affects our business (including material focus areas) and is guided by leading ESG reporting frameworks. We adopt guidance from the International Sustainability Standards Board by the International Financial Reporting Standards ("IFRS") Foundation, the International Integrated Reporting Framework, the Global Reporting Initiative ("GRI") and the Sustainability Accounting Standards Board ("SASB") requirements for electric utilities and power generators. We continue to monitor the development of sustainability and climate-related disclosure requirements to assess our future reporting, such as the proposed climate-related disclosure rules by the Canadian Securities Administrators, the US Securities and Exchange Commission and the Australian government.
Since 2007, TransAlta's material sustainability data to be disclosed has received limited assurance from independent third-party providers. Climate-related data to be disclosed is informed by the IFRS S2 Climate-related Disclosures Standard launched in 2023, in alignment with the recommendations of the Task Force on Climate-related Financial Disclosures ("TCFD"). In 2024, TransAlta will continue to focus on our alignment with the IFRS S2 requirements. As a result, we no longer expect to respond to climate change questionnaires from CDP (the global disclosure system for environmental impacts known formerly as the Carbon Disclosure Project). We will continue to monitor its future guidance for the purpose of continuous improvement of our voluntary climate-related disclosures.
In 2023, we reviewed and updated our management response to our 2021 climate-related scenario analysis that enhanced our alignment with both international sustainability frameworks. We also reviewed and updated our Climate Transition Plan and climate-related financial metrics. GHG emissions data for scopes 1 and 2 follow the accounting and reporting standards of the GHG Protocol. We continue to make advancements in our scope 3 accounting for future reporting in alignment with the GHG Protocol. For further information on climate change management and the findings of our scenario analysis, refer to the Decarbonizing Our Energy Mix section of this MD&A.
The disclosure of our most relevant sustainability factors remained in 2023 and is guided by our sustainability materiality assessment. In 2022, we refreshed our materiality assessment by evaluating key sector-specific research on material issues, supported by internal and external engagement on key sustainability issues. Our Enterprise Risk Management ("ERM") program is designed to help the Company focus its efforts on key enterprise risks, within the planning horizon, that could significantly impact the success of our strategy, including our sustainability objectives. We consider a sustainability factor as material if it could substantively affect our ability to create value.
In addition, we reviewed key topics identified within SASB, TCFD, IFRS and the Taskforce on Nature-related Financial Disclosures to inform the identification of our material sustainability factors. We also considered sustainability factors from the electricity sector through Electricity Canada’s 2021 Sustainable Electricity Report and conducted a peer review of material sustainability factors. This work was validated by our executive team and resulted in the identification of 21 material sustainability factors presented in the Sustainability Governance section of this MD&A.
For further guidance on our risk factors, refer to the Governance and Risk Management section of this MD&A.

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Accelerating Our Business Transformation with a Target to Become Net-Zero by 2045
At TransAlta, our mission is to provide safe, low-cost and reliable clean electricity to our customers. As a customer-centred clean electricity leader, we are well positioned to support our customers' ESG and sustainability goals. To achieve this goal, in today's evolving economy and increasingly electrified world, our strategy focuses on renewable electricity growth and a deep commitment to sustainability. We believe that we are uniquely positioned as the world continues to electrify and adopt sustainability practices. For further information, refer to the Description of the Business section of this MD&A.
Our President and Chief Executive Officer, John Kousinioris, speaks about our decarbonization journey below.
What role do you see natural gas generation having in a successful energy transition?
“We believe that there are three factors that must be balanced to ensure a successful energy transition: reliability, decarbonization and affordability. We continue to see a role in natural gas-fired generation enabling the energy transition by ensuring the reliability of the electricity grid. Today, our gas fleet, to be strengthened following closing of the Heartland Generation acquisition, includes peaking and baseload generation, which underpin the reliability needs of our grid, as well as cogeneration facilities, which serve customers critical to the industrial sectors of our three core markets. We also work closely with our industrial customers to support their decarbonization goals. For example, we recently achieved commercial operation for the Northern Goldfield solar and battery storage project for BHP Nickel West in Western Australia that is expected to reduce BHP's scope 2 GHG emissions.”
Following closing of the Heartland Generation acquisition, will TransAlta still be able to achieve its 2026 decarbonization target?
“Our commitment to decarbonization remains unchanged. TransAlta’s target of a 75 per cent scope 1 and 2 GHG emissions reduction by 2026 is estimated to align with the Paris Agreement goal to limit global warming to 1.5°C and is based on our 2015 scope 1 and 2 GHG emissions of 32.2 MT CO 2 e. The acquisition of the Heartland Generation portfolio is aligned with our decarbonization commitment. We will recalculate our 2015 emission baseline to include emissions from Heartland Generation and expect this
transaction will continue to enable us to reduce our emissions in the short term and to be carbon net-zero by 2045.
We remain committed to investing in climate change mitigation solutions to maximize value for our shareholders, customers, local communities and the environment.”
For further information, refer to Climate Change Metrics and Targets in the Decarbonizing Our Energy Mix section of this MD&A.
TransAlta has adopted a 2045 net-zero target. How will the Company achieve this target?
"Our net-zero target is a testament of our growth strategy. We are using the cash flows from our legacy thermal generation assets to fund our transition to a generating fleet focused on renewables and storage by creating electricity solutions for our industrial and commercial customers. In 2023, we revised our Clean Electricity Growth Plan, which targets growing the Company’s generation fleet by an incremental 1.75 GW — with approximately $3.5 billion of capital expenditure — as well as increasing our development pipeline of projects to 10 GW, each to be achieved by 2028. Our investment focus to 2028 will be on renewables and storage assets, responsive and flexible generation to support reliability, and advancing new technological solutions."

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Our 2023 Sustainability Performance
In 2023, TransAlta's strong safety performance was a key accomplishment amongst our social performance metrics. Our Total Safety Report Frequency and Total Recordable Injury Frequency ("TRIF") exceeded our performance targets.
Performance against our 2023 sustainability targets is outlined below. Target year means by Dec. 31 of that year.
ESG Alignment: Environmental

Sustainability goal | Sustainability target | Results | Comments
Reduce GHG emissions | By 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from 2015 base year(1) | On track | Since 2015, we have reduced scope 1 and 2 GHG emissions by 21.3 MT CO 2 e or 66 per cent
By 2045, achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions(2) | On track
By 2024, verify and disclose 80 per cent of TransAlta’s scope 3 emissions(3) | On track | We completed a pre-assessment of 80 per cent of TransAlta’s scope 3 emissions to prepare for limited assurance in 2024
Reduce air emissions | By 2026, achieve a 95 per cent reduction of SO 2 emissions and an 80 per cent reduction of NO x emissions below 2005 levels | Achieved | Our total air emissions in 2023 retained similar performance to 2022 levels. We achieved this target in 2022 through the reduction of our SO 2 emissions by 98 per cent and NO x emissions by 83 per cent from 2005 levels
Reclaim land utilized for mining | By 2040, complete full reclamation of our Centralia coal mine in Washington State | On track | Reclamation work at Centralia is underway and 40 per cent of the coal mine land has been reclaimed
By 2046, complete full reclamation of our Highvale coal mine in Alberta | On track | Our Highvale coal mine in Alberta closed in 2021. Reclamation work is underway and 22 per cent of the coal mine land has been reclaimed
Responsible water management | By 2026, reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m 3 or 40 per cent over a 2015 baseline | Achieved in 2022 | Water consumption increased to 30 million m 3 in 2023 primarily due to an increase in production compared to last year. We achieved this target in 2022 through the reduction of our fleet-wide water consumption by approximately 20 million m 3 or 43 per cent from 2015 levels
Protecting nature and biodiversity | By 2024, assess and disclose nature-related risks and opportunities including TransAlta’s dependencies and impacts on ecosystems, land, water and air | On track | Assessment of nature-related risks and opportunities is underway
Achieve zero biodiversity-related incidents(4) | Achieved | We recorded zero (0) biodiversity-related incidents

(1)TransAlta does not plan to use carbon credits to achieve its 2026 GHG emissions reduction target.
(2)The Company may choose to neutralize residual emissions from gas-fired generation through fuel switching, new technologies or nature-based solutions to achieve its 2045 net-zero target. For further information, refer to Climate Transition Plan in the Decarbonizing Our Energy Mix section of this MD&A.
(3)To calculate TransAlta's scope 3 GHG emissions, we rely on third-party data that is available only after the first quarter of each year. As a result, this target means reporting on 2023 scope 3 GHG emissions data in 2025 following the verification of data by independent third-party providers in 2024.
(4)This means biodiversity-related incidents that affected habitats and species included on the Red List of the International Union for Conservation of Nature and are classified as near-threatened, vulnerable, endangered and critically endangered.

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ESG Alignment: Social

Sustainability goal | Sustainability target | Results | Comments
Reduce safety incidents | Achieve a Total Recordable Injury Frequency rate below 0.32 | Achieved | We achieved a TRIF rate of 0.30 compared to 0.39 in 2022. Our strong safety performance can be attributed to our focus on maturing our safety culture, reducing hazards, assessing and addressing risk tolerance and standardizing safety information and data collection technology
Integrate sustainability into supply chain | By 2024, 80 per cent of our spend will be with suppliers that have a sustainability policy or commitment | On track | On average, 78 per cent of our spend in 2022 and 2023 was with suppliers that have a sustainability policy or commitment
Support prosperous Indigenous communities | Support equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunities | Achieved | Support represented a total value of $453,000, or 14 per cent of TransAlta’s total community investment
Provide Indigenous cultural awareness training to all TransAlta employees by the end of 2023 | Achieved | We provided Indigenous awareness training to all Canadian, Australian and US employees

ESG Alignment: Governance

Sustainability goal | Sustainability target | Results | Comments
Strengthen gender equality | Achieve 50 per cent female representation on the Board by 2030 | On track | As at Dec. 31, 2023, women represented 46 per cent of our Board composition compared to 36 per cent in 2022(1)
Achieve at least 40 per cent female employment among all employees of the Company by 2030 | On track | As at Dec. 31, 2023, women represented 27 per cent of all employees, an increase over 2022 levels (26 per cent)
Maintain equal pay for women in equivalent roles as men | Achieved | We achieved a 97 per cent female/male pay equity ratio. We strive to maintain this ratio within a deviation of plus or minus three per cent
Demonstrate leadership on ESG reporting within financial disclosures | Maintain our position as a leader on integrated ESG disclosure through increased annual alignment with leading sustainability disclosure frameworks | Achieved | TransAlta's MSCI ESG Rating was upgraded to 'AA' from 'A'. The upgrade reflects the Company's strong renewable energy growth compared to peers. We also received an award for best ESG reporting (mid-cap) by the IR Magazine Canada. In 2023, TransAlta demonstrated some of the most comprehensive disclosures among utilities companies assessed in the inaugural Climate Engagement Canada Net Zero Benchmark, which evaluates corporate issuers’ progress towards aligning with the Paris Agreement’s goals

(1)Board composition includes all independent and non-independent directors.

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ESG Alignment: Environmental and Social

Sustainability goal | Sustainability target | Results | Comments
Coal transition | No further coal generation by the end of 2025 with 100 per cent of our owned net generation capacity to be from renewables and gas | On track | We retired 670 MW of Centralia at Dec. 31, 2020. In 2021, we retired or converted all coal plants in Canada and closed the Highvale coal mine, thus ceasing all coal generation in Canada. Our remaining Centralia plant in the US is set to retire on Dec. 31, 2025
Clean energy solutions for customers | Develop new renewable projects that support customer sustainability goals to achieve both long-term power price affordability and carbon reductions | On track | Since 2021, we have added over 800 MW of new capacity through renewable projects such as Windrise (206 MW), Garden Plain (130 MW), Northern Goldfields Solar (48 MW), White Rock (300 MW) and Horizon Hill (200 MW). We also acquired TransAlta Renewables (1.2 GW) in 2023 and North Carolina Solar (122 MW) in 2021. In 2023, our Clean Electricity Growth Plan was updated to continue our priorities. By 2028, the plan will see the Company execute on an incremental 1.75 GW of renewables growth and a 10 GW growth pipeline

2024+ Sustainability Targets
Our 2024 and longer-term sustainability targets support the success of our business so that the Company will continue to be positioned as an ESG leader in the future. Goals and targets are established to improve our ESG performance and manage current and emerging material sustainability issues in support of the United Nations Sustainable Development Goals ("UN SDGs") and the Future-Fit Business Benchmark, which also defines sustainable goals for businesses. TransAlta is committed to decarbonizing our energy generation and accelerating clean energy growth. We believe that we can make a greater positive impact on UN SDG 7 “Affordable and Clean Energy” and SDG 13 “Climate Action”, while supporting seven other SDGs.
Our 2024 and long-term sustainability targets reflect on incremental change from the sustainability targets set in 2023. Specifically, TransAlta updated two sustainability targets in the areas of safety and Indigenous cultural awareness, while maintaining our climate-related targets to achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions by 2045 and to reduce 75 per cent of our scope 1 and 2 GHG emissions by 2026 from a 2015 base year. This target covers 100 per cent of TransAlta's operating assets and is estimated to align with the electricity sector decarbonization pathway to limit global warming to 1.5°C, as one of the Paris Agreement goals.
In 2024, we will continue to review setting new environmental targets for GHG emissions, air emissions and water consumption consistent with our commitment to continuously improve our environmental performance.
Targets are outlined below. Target year means by Dec. 31 of that year.

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ESG Alignment: Environmental

Sustainability goal | Sustainability target | Alignment with UN SDG Target or Future-Fit Business Benchmark
Reduce GHG emissions | By 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from 2015 base year(1) | UN SDG Target 13.2: "Integrate climate change measures into national policies, strategies and planning"
By 2045, achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions(2)
By 2024, verify and disclose 80 per cent of TransAlta’s scope 3 emissions(3)
Reduce air emissions | By 2026, achieve a 95 per cent reduction of SO 2 emissions and an 80 per cent reduction of NO x emissions below 2005 levels | UN SDG Target 9.4: "By 2030, upgrade infrastructure and retrofit industries to make them sustainable, with increased resource-use efficiency and greater adoption of clean and environmentally sound technologies and industrial processes"
Reclaim land utilized for mining | By 2040, complete full reclamation of our Centralia coal mine in Washington State | Future-Fit Business Benchmark: "Positive Pursuits 13: Ecosystems are restored"
By 2046, complete full reclamation of our Highvale coal mine in Alberta | Future-Fit Business Benchmark: "Positive Pursuits 13: Ecosystems are restored"
Responsible water management | By 2026, reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m 3 or 40 per cent over the 2015 baseline | UN SDG Target 6.4: "By 2030, substantially increase water-use efficiency across all sectors and ensure sustainable withdrawals and supply of freshwater to address water scarcity and substantially reduce the number of people suffering from water scarcity"
Protecting nature and biodiversity | By 2024, assess and disclose nature-related risks and opportunities including TransAlta’s dependencies and impacts on ecosystems, land, water and air | UN SDG Target 15.5: "Take urgent and significant action to reduce the degradation of natural habitats, halt the loss of biodiversity and, by 2020, protect and prevent the extinction of threatened species”
Achieve zero biodiversity-related incidents(4)

(1)TransAlta does not plan to use carbon credits to achieve its 2026 GHG emissions reduction target.
(2)The Company may choose to neutralize residual emissions from gas-fired generation through fuel switching, new technologies or nature-based solutions to achieve its 2045 net-zero target. For further information, refer to Climate Transition Plan in the Decarbonizing Our Energy Mix section of this MD&A.
(3)To calculate TransAlta's scope 3 GHG emissions, we rely on third-party data that is available only after the first quarter of each year. As a result, this target means reporting on 2023 scope 3 GHG emissions data in 2025 following the verification of data by independent third-party providers in 2024.
(4)This means biodiversity-related incidents that affected habitats and species included on the Red List of the International Union for Conservation of Nature and are classified as near-threatened, vulnerable, endangered and critically endangered.

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ESG Alignment: Social

Sustainability goal | Sustainability target | Alignment with UN SDG Target or Future-Fit Business Benchmark
Reduce safety incidents | Achieve a Total Recordable Injury Frequency rate below 0.32 with a goal of 0.00 | UN SDG Target 8.8: "Protect labour rights and promote safe and secure working environments for all workers, including migrant workers, in particular women migrants, and those in precarious employment"
Integrate sustainability into supply chain | By 2024, 80 per cent of our spend will be with suppliers that have a sustainability policy or commitment | UN SDG Target 12.7: “Promote public procurement practices that are sustainable, in accordance with national policies and priorities”
Support prosperous Indigenous communities | Support equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunities | UN SDG Target 4.5: "By 2030, eliminate gender disparities in education and ensure equal access to all levels of education and vocational training for the vulnerable, including persons with disabilities, Indigenous peoples and children in vulnerable situations"
Provide Indigenous cultural awareness training during the onboarding of all new TransAlta employees | UN SDG Target 12.8: "By 2030, ensure that people everywhere have the relevant information and awareness for sustainable development and lifestyles in harmony with nature"

ESG Alignment: Governance

Sustainability goal | Sustainability target | Alignment with UN SDG Target or Future-Fit Business Benchmark
Strengthen gender equality | Achieve 50 per cent female representation on the Board by 2030 | UN SDG Target 5.5: "Ensure women’s full and effective participation and equal opportunities for leadership at all levels of decision making in political, economic and public life"
Achieve at least 40 per cent female employment among all employees of the Company by 2030
Maintain equal pay for women in equivalent roles as men
Demonstrate leadership on ESG reporting within financial disclosures | Maintain our position as a leader on integrated ESG disclosure through increased annual alignment with leading sustainability disclosure frameworks | UN SDG Target 12.6: "Encourage companies, especially large and transnational companies, to adopt sustainable practices and to integrate sustainability information into their reporting cycle"

ESG Alignment: Environmental and Social

Sustainability goal | Sustainability target | Alignment with UN SDG Target or Future-Fit Business Benchmark
Coal transition | No further coal generation by the end of 2025 with 100 per cent of our owned net generation capacity to be from renewables and gas | UN SDG Target 7.1: "By 2030, ensure universal access to affordable, reliable and modern energy services"
Clean energy solutions for customers | Develop new renewable projects that support customer sustainability goals to achieve both long-term power price affordability and carbon reductions | UN SDG Target 7.2: "By 2030, increase substantially the share of renewable energy in the global energy mix"

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Decarbonizing Our Energy Mix
ESG is more than a business strategy at TransAlta; it is a competitive advantage. Sustainability is one of our core values; therefore, we strive to integrate climate change into governance, decision-making, risk management and our day-to-day business operations. The outcome of our climate change focus is continuous improvement on key climate-related issues and ensuring our economic value creation is balanced with a value proposition for the environment and people.
We recognize the impact of climate change on society and our business both today and into the future. Our renewable energy journey began 112 years ago when we built the first hydro assets in Alberta, which still operate today. In 1993, we began operating our first wind facility, which was the first commercial wind facility in Canada; in 2014, acquired our first solar facility; and, in 2020, constructed our first battery storage facility. Today, we operate 57 renewable facilities across Canada, the US and Australia.
Our reporting on climate change management has been guided by the TCFD recommendations since 2018. In 2023, we adopted guidance from IFRS S2, which is based on the TCFD recommendations with industry-specific climate metrics based on the SASB standards. IFRS S2 and TCFD help inform discussion and provide context on how climate change affects our business.
Strategy and Risk Management
Climate Change Strategy
As described in the following sections, our risks and opportunities assessment and climate scenarios analysis support the development and continuous improvement of our climate change strategy. We actively monitor and manage climate-related risks and opportunities as part of our overall business strategy to ensure we remain resilient across scenarios.
TransAlta remains committed to creating a path to resiliency in a decarbonizing world in support of the goals adopted under the Paris Agreement, and the goals adopted during subsequent international climate meetings. Our strategy is focused on the operation of our existing assets (wind, hydro, solar, natural gas, battery storage and transition-coal), the phase-out of coal-fired electricity generation, and the development of renewable energy and storage projects. Our customers are increasingly integrating ESG risk into their business decisions; therefore, we see an advantage in growing our renewable power business to support our customers' sustainability goals. Our investments and growth in renewable energy are highlighted by our portfolio of renewable energy-generating assets. From 2000 to 2023, we grew our nameplate renewables capacity from approximately 900
MW to over 2,900 MW. Today, our diversified renewable fleet makes us one of the largest renewable power producers in North America, one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta.
Another way we contribute to our customers’ sustainability goals is through environmental attributes. The environmental attributes that we generate include carbon offsets, renewable energy credits and emission offsets. Our customers can use environmental attributes to lower compliance costs attributed to carbon policies or renewable portfolio standards. Furthermore, environmental attributes can help achieve voluntary corporate sustainability or carbon reduction goals. To combat the challenges of renewable energy intermittency, we continue to invest in battery storage and evaluate the role of natural gas to provide increased reliability and flexibility.
In 2020, we launched WindCharger, a "first-of-its-kind in Alberta" battery storage project that stores energy produced by our Summerview II wind facility and discharges electricity onto the Alberta grid during system supply shortages, as well as providing critical system support services to the system operator. This project received co-funding from Emissions Reduction Alberta. Further, in 2021, we agreed to provide solar electricity supported with a battery energy storage system to BHP Nickel West through the construction of the Northern Goldfields hybrid solar project in Western Australia. The Northern Goldfields solar and battery storage facilities were commissioned in 2023 and are expected to reduce BHP's scope 2 GHG emissions at its Nickel West operations by 12 per cent. In 2022, TransAlta entered into an agreement for the expansion of the Mount Keith 132kV transmission system. The expansion is underway, with expected completion in the first quarter of 2024. In 2023, TransAlta’s early-stage development pipeline included in excess of 1 GW from four energy storage projects in Canada.
In support of our own path to build resilience to climate change, we have taken significant steps to reduce our carbon footprint over the last several years. In 2021, we adopted a more stringent climate-related target to reduce 75 per cent of our scope 1 and 2 GHG emissions by 2026 from a 2015 base year. This target covers 100 per cent of TransAlta's operating assets and is estimated to align with the electricity sector decarbonization pathway to limit global warming to 1.5°C, as one of the Paris Agreement goals. Furthermore, we adopted a long-term climate-related target to achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions by 2045. This ambitious target aligns us with the Canadian Net-Zero Emissions Accountability Act to achieve net-zero emissions by 2050.

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We are also taking strategic steps to decarbonize the power sector and support the energy transition. In 2021, we set out clear targets under the Clean Electricity Growth Plan. Since 2021, the Company added 800 MW of new capacity and acquired TransAlta Renewables (1.2 GW) and North Carolina Solar (122 MW). In 2023, our Clean Electricity Growth Plan was updated to continue our priorities. By 2028, the plan will see the Company execute on an incremental 1.75 GW of renewables growth and a 10 GW growth pipeline. In 2025, we will retire our single remaining coal unit, located in the US, to complete TransAlta's transition away from coal generation.
To date, we have retired 4,664 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to natural gas. Comparatively, our converted natural gas units' CO2 intensity is approximately 57 per cent less than coal generation. Repurposing the facilities rather than decommissioning them reduces the cost and emissions associated with new construction and aligns with the UN SDGs, specifically "Goal 9: Industry, Innovation and Infrastructure." The completed conversions and the closure of the Highvale coal mine also contribute to the goals of the Powering Past Coal Alliance, which TransAlta joined in 2021 at COP26.
We actively engage policymakers and stakeholders on how to facilitate a transition where the electricity systems we serve can reach net-zero emissions while maintaining reliability. We will continue investing in renewables and assessing the best options to deliver energy storage, including incorporating learnings from our industrial-scale battery into our Company strategy and sharing those learnings with government. At the same time, natural gas will play an essential role in the electricity sector, providing dispatchable generation to support current system demands and a smooth energy transition. We always seek energy-efficiency improvements and opportunities to achieve emissions reductions at competitive costs. Further, we are committed to investing in climate change mitigation solutions to maximize value for our shareholders, customers, local communities and the environment.
Climate Transition Plan
A climate-related transition plan describes how a company aims to minimize climate-related risks and increase opportunities, in alignment with IFRS S2 and TCFD. In 2023, TransAlta reviewed and updated its Climate Transition Plan, which lays out our approach to reducing operational and value chain emissions to deliver net-zero operations by 2045. In addition, our Climate Transition Plan includes sustainable finance and inclusive transition actions reflecting TransAlta's commitment to a successful transition toward a low-carbon economy. For further information, refer to Sustainable Finance in the Decarbonizing Our Energy Mix section of this MD&A and Inclusive Transition in the Engaging with Our Stakeholders to Create Positive Relationships section of this MD&A.
Our Climate Transition Plan defines TransAlta's past, short-term (2024-2025) and medium- to long-term actions (beyond 2026). For each of these actions, we assessed our ability to control ("C") intended outcomes, partner ("P") with stakeholders to drive outcomes or influence ("I") outcomes that will help us achieve our decarbonization targets.
The highest level of climate change oversight, including the actions of our Climate Transition Plan, is at the Board level. For further information, refer to Oversight by the Board of Directors in the Climate Change Governance section of this MD&A. Information on executive compensation linked to climate-related targets is described in ESG-Linked Compensation in the Building a Diverse and Inclusive Workforce section of this MD&A. Metrics and targets supporting our Climate Transition Plan, including climate-related financial metrics, are described in Climate Change Metrics and Targets in the Decarbonizing Our Energy Mix section of this MD&A.

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Delivering Net-Zero Operations by 2045

| Past actions | Short-term actions (2024-2025) | Medium to long-term actions (2026 +)
Hydro | Became the largest producer of hydro power in Alberta (C) | Advance 1500 MW of early-stage wind and solar projects in all jurisdictions (C) Complete development and commence construction on 100 MW wind project in Canada (C) | Deliver an incremental 1.75 GW of clean electricity capacity by 2028 (C) Deploy approximately $3.5 billion of growth capital by 2028 (C) Expand our growth pipeline to 10 GW by 2028 with focus on renewables and storage (C)
Wind and Solar | From 2000 to 2023, we grew our nameplate renewables capacity by approximately 2,000 MW (C)
Battery Storage | First battery storage facility delivered in 2020 (C) In 2023, completed the construction of a 48 MW solar and battery storage system in Australia (C) | Complete development and commence construction on 180 MW battery storage in Canada (C) Evaluate and deploy battery storage alongside renewable facilities where appropriate (C) |
Natural Gas | Completed our coal-to-gas conversions in Canada in 2021 (C) Converted 1,659 MW from coal to natural gas since 2018 (C) | Operate simple-cycle, combined-cycle and cogeneration facilities in Canada, the United States and Australia (C) Assess deployment of nature-based or engineered solutions to neutralize unabated gas-fired generation where appropriate (C) Evaluate use of renewable and low-carbon natural gas (C) | Neutralize residual emissions from gas-fired generation through fuel switching, new technologies or nature-based solutions (C)
Emerging Abatement Technologies and Solutions | Started exploring new technologies such as storage, hydrogen and carbon capture (P) In 2023, continued to support the development of low-cost, low-emissions hydrogen production through $2 million investment in a Canadian-based venture (P) In 2023, started partnership with leading global companies to target early-stage revolutionary technologies through a US$25 million investment in a deep decarbonization fund (P) In 2023, started an electric vehicle pilot project in our hydro operations (C) | Identify the next generation of power solutions and technologies and potential for parallel investments in new complementary sectors by the end of 2025 (P) Assess ways to support customers with broader decarbonization technologies beyond electrification (P) Identify opportunities to partner, pilot and deploy novel, net-zero generation technologies (P) Assess and deploy GHG removal technologies where appropriate (C) Evaluate the electrification of our vehicle fleet (C) | Deploy new net-zero generation technologies and solutions where appropriate (C) Choose materials, products and processes that generate fewer GHG emissions, mainly through energy savings (C) Evaluate the electrification of our vehicle fleet (C)
Energy Transition (Coal) | Retired 4,664 MW of coal-fired generation capacity since 2018 including ending coal generation in Canada in 2021 (C) | Continue to execute reclamation work at our coal mines (C) Contribute to a circular economy through mining waste reuse or by-product sales (C) | Cease coal generation by 2026 (C) Complete full reclamation in Washington State by 2040 and in Alberta by 2046 (C)

Legend: (C) Control intended outcomes, (P) partner with stakeholders to drive outcomes, and (I) influence outcomes that will help us achieve our decarbonization targets.

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Delivering Net-Zero Operations by 2045 (Continued)

| Past actions | Short-term actions (2024-2025) | Medium to long-term actions (2026 +)
Supply Chain | Enhanced supplier management functionality within the corporate procurement system (C) | Develop ESG criteria for supply chain engagement (C) Understand direct suppliers, GHG emissions profile and targets (C) Incorporate ESG data reporting capability in corporate procurement system (C) | Engage with suppliers to explore enhancement of their GHG emissions reduction targets (I) Set direction for engaging suppliers with GHG emissions reduction targets (C)
Value Chain | Disclosed range of scope 3 GHG emissions at company level (C) | Update scope 3 GHG emissions reporting methodology (C) Verify and disclose 80 per cent of our total scope 3 emissions (C) | Consider scope 3 GHG emissions targets (C)
Sustainable Finance | In 2021, converted existing $1.3 billion loan into a Sustainability-Linked Loan aligned with GHG emissions reduction and female employment targets at the company level (C) In 2021, secured $173 million green bond financing for eligible wind project in Alberta (C) In 2022, issued US$400 million Senior Green Bonds for eligible renewable energy and energy-efficiency projects (C) Linked ESG performance to employees’ and executive remuneration (C) | Continue to evaluate the use of sustainable or green financing instruments to fund renewable energy and battery storage projects (C) Link ESG performance to employees’ and executive remuneration (C) | Continue to evaluate the use of sustainable or green financing instruments to grow our renewables and storage capacity (C) Link ESG performance to employees’ and executive remuneration (C)
Inclusive Transition | Developed a five-year Equity, Diversity and Inclusion (ED&I) strategy (C) Conducted ED&I census to help drive a greater sense of belonging for all employees (C) Set employee engagement and ED&I targets as part of ESG-linked compensation (C) In 2023, launched two employee resource groups (C) In 2023, provided Indigenous cultural awareness training to all employees (C) In 2015, announced community investment of US$55 million over 10 years to support energy efficiency, economic and community development and education and retraining initiatives in Washington State (P) In 2016, agreed to invest in the communities impacted by the phase-out of coal generation in Alberta (P) | Expand number of employee resource groups available (C) Adapt workplaces to incorporate structural changes for inclusive work environments (C) Deliver year-round ED&I learning and awareness, and celebration campaigns (C) Continue energy transition investment in Washington State communities of up to US$55 million by 2025 (P) Continue to invest in the communities impacted by the phase-out of coal generation in Alberta (P) Strengthen Indigenous relations focused on community engagement and consultation, community investment and partnership opportunities (P) Promote supplier diversity in our operations (C) | Enhance recruitment and retention of female employees to achieve gender-based targets (C) Maintain succession practices to increase female representation at senior management level (C) Increase female representation in Generation by encouraging women to pursue a career in electricity (C) Enhance opportunities for diverse suppliers in our procurement processes (C) Continue to enhance our Indigenous relations focused on partnership opportunities with local communities (P) Ongoing support to local community organizations aligned with our community investment pillars where we operate and grow communities (P)

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Climate Change Governance
Climate-related risks and opportunities can significantly impact our business, especially regulatory changes and shifting customer preferences toward lower-carbon energy. Therefore, we actively manage risks and opportunities so that we can continue to grow and achieve our goals. Climate-related issues are identified at every level of management, including the Board, executive team, business units and corporate functions (for example, government relations, regulatory, emissions trading, sustainability, commercial, customer relations, investor relations). Ensuring climate-related issues are acknowledged and addressed at the most senior levels of the Company (including at the Board and executive level) has allowed us to establish actionable emissions reduction targets and grow our generation capacity through renewable energy and storage.
Oversight by the Board of Directors
The highest level of climate change oversight is at the Board level, with specific oversight of certain aspects of the Company's response to climate change being delegated to our Governance, Safety and Sustainability Committee (“GSSC”), our Audit, Finance and Risk Committee ("AFRC") and our Investment Performance Committee (“IPC”) of the Board.
Meeting quarterly, the GSSC assists the Board in monitoring and assessing compliance with climate change regulation and reporting. The GSSC receives management reports on changes in climate-related legislation and the potential impact of policy developments on TransAlta's business. The GSSC then supports the Board in assessing and overseeing Company-wide climate change strategies, policies and practices. The GSSC also reviews environmental protection guidelines, including with respect to GHG mitigation, and considers whether our environmental procedures are being effectively implemented.
The AFRC and IPC also play a role in managing TransAlta's climate-related risks and opportunities. The AFRC assists the Board in overseeing the integrity of our consolidated financial statements and considers climate risks and opportunities as it relates to our financial decision-making. Further, the AFRC is responsible for approving our Commodity and Financial Exposure Management policies and reviewing quarterly ERM reporting. The IPC considers and assesses risks related to capital investment projects, including overseeing climate risk assessments and mitigation plans. As a result, climate-related capital expenditures, acquisitions and budgets are reviewed by the AFRC and IPC on a case-by-case basis.
The Board reviews and updates the Company's strategy annually. In 2023, the Board's strategic planning sessions included climate-related issues considering growth
initiatives and strategies, capital allocation, ESG policy development and other matters. Our Board is composed of individuals with a mix of skills, knowledge and experience critical to our strategy success and business growth. In 2023, three of our 13 Board members identified environment/climate change among their top four relevant competencies. Given the breadth of experience and skills of each director, the skills matrix lists only the top four competencies possessed by each director nominee based on the Board’s assessment and each director’s self-evaluation. The criteria used to assess competence of Board members on climate-related issues includes the knowledge of corporate responsibility practices and the constituents involved in sustainable development practices, including as it pertains to climate change.
For further information regarding Board members competence on climate-related issues, refer to TransAlta's Management Proxy Circular.
Role of Senior Management
TransAlta’s President and CEO maintains the highest level of oversight on climate-related issues at the executive level. Senior management of the Company, including our President and CEO, provide the Board with updates on climate-related risks and opportunities to inform business strategy and ensure alignment with TransAlta’s GHG emissions reduction goals.
Our business units and corporate functions work closely together to support the executive team in understanding climate-related risks and opportunities, including legislative developments. Our executive team reviews such risks and opportunities quarterly and reports to the GSSC and AFRC, as applicable.
At the business unit level, climate change risks are identified through our Total Safety Management System, asset management function and systems, energy and trading business, communication with stakeholders, active monitoring and participation in working groups.
Notably, we tie a component of executive compensation to reducing GHG emissions and climate change management. We link our annual incentive plans (short-term incentive and long-term incentives) to our strategic goals. Our strategic goals include growing renewable energy, reducing GHG emissions and supporting our customers' sustainability goals to decarbonize through on-site low carbon energy generation.
For further information on incentives for ESG performance, refer to the discussion on ESG-Linked Compensation in Building a Diverse and Inclusive Workforce section of this MD&A.

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Climate Scenarios
In 2021, we conducted climate scenario analysis to understand risks and opportunities and assess our strategy's resiliency under several potential future climate scenarios. The analysis utilized scenarios from the International Energy Agency’s ("IEA") 2020 World Energy Outlook, a large-scale simulation model designed to replicate how energy markets function. We used three scenarios: Stated Policies (“STEPS”); Sustainable Development (“SDS”); and Net-Zero Emissions by 2050 (“NZE”).
In STEPS, the energy system has no major additional climate and environmental policies enacted by government(s). STEPS assumes that carbon pricing continues in Canada while no carbon price is set in the US or Australia. STEPS also assumes that the power sector reduces emissions by 45 per cent by 2040 while natural gas generation capacity increases. Finally, STEPS is limited to the deployment of commercial-ready technologies, including wind and solar.
In SDS, the goals of the Paris Agreement (2015) are achieved, resulting in net-zero emissions by 2070. The SDS assumes a rapid increase in clean energy policies and investments that position the energy system to also achieve key UN SDGs. In SDS, all current net-zero pledges are achieved and there are extensive efforts to reduce emissions. SDS assumes that carbon pricing continues in Canada and is set in the US and Australia. It also assumes that the power sector reduces emissions by 90 per cent by 2040 while natural gas capacity remains stable into 2030 and declines toward 2040. Finally, SDS assumes that beyond wind and solar, the energy system relies on batteries, storage and some level of carbon capture, utilization and storage (“CCUS”) and hydrogen.
NZE represents a pathway for the global energy sector to achieve net-zero emissions by 2050. This scenario also assumes key energy-related SDGs are achieved through universal energy access by 2030 and major improvements in air quality. NZE is built upon the idea that a global increase in electrification supports the journey to net-zero. It assumes that an aggressive carbon price is set in Canada, the US and Australia. It also assumes the power sector reaches net-zero emissions by 2035 in advanced economies while natural gas capacity is stable to 2030 and declines significantly into 2040. Like the SDS, NZE assumes that beyond wind and solar, the energy system relies on batteries, storage and some level of CCUS and hydrogen.
In 2023, we reviewed the findings from the climate scenario analysis and updated the management response accordingly.

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Key Climate Scenario Findings
Using climate scenarios, we analyzed the resiliency of our business and determined specific risks and opportunities for our individual assets. All three scenarios present opportunities for TransAlta’s growth related to renewables, storage solutions and ancillary services. The scenario
analysis found that our wind and solar assets have the highest prospects for growth, which aligns with our growth strategy. Under all scenarios, hydro remains a valuable asset as it allows for expansion to include storage.
The following sections highlight TransAlta's top risks, opportunities and management response across all scenarios.
Top Identified Climate-Related Risks by Scenario

| Increased competition | Decreased demand of natural gas electricity | Increased operational costs
Description | Subsidies/funds available for clean energy transition increase as governments aim to grow installed capacity of renewables to meet rising electricity demand and compensate for the closure of carbon-intensive power plants. In Canada, it is expected that major grid decarbonization investments will flow into Alberta as most other provincial markets are heavily regulated and/or are already low carbon. This will increase competition in the merchant market, making a large part of the generating fleet frequently bid at zero, driving down the average price of dispatched electricity. Simultaneously the cost of renewables, expected to decline across all scenarios, decreases the capital barrier to entry. These combined factors will increase competition for TransAlta. The IEA scenarios do not provide clear indication of electricity pricing and how it can be affected by increased competition. As such, this remains a point of uncertainty. Some structural market changes may be required to guarantee returns for power generators and successfully decarbonize the grid. | Demand for power from natural gas declines as the market shifts towards cleaner power with gas shifting to a reliability backstop role. An additional decline from Canadian oil and gas customers can occur as oil production levels drop under NZE and SDS. The transition to a lower-carbon world will likely result in volatility and market uncertainty. Natural gas power may be necessary to provide power in the transition if the pace of decarbonization is slower than expected in the scenarios or if grid-scale storage solutions do not develop/commercialize as modelled. In these cases, with coal phased out, natural gas assets will be relied on for baseload generation. This means that natural gas assets may still play a role for a smooth and efficient energy transition. Optimization of natural gas assets is required, and additional investments need to be assessed with caution to consider the pace of decarbonization and consequent risk of decreased demand for natural gas power. | Carbon price increases the cost of natural gas operations. Additional mandated emissions reductions could force remaining plants to invest in technologies like CCUS, increasing the operating costs for natural gas plants further. Natural gas assets in the US and Australia face less risk compared to assets in Alberta as they are contracted and can pass down carbon costs to their clients. Current and anticipated regional carbon pricing monitoring is required to plan and assess increases in operational costs and impacts on new projects and investments.

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| Increased competition | Decreased demand of natural gas electricity | Increased operational costs
NZE | By 2040, renewables are expected to comprise over 85 per cent of the total electricity generation in the regions we operate. This surge in renewables will increase competition and drive electricity pricing down depending on availability and the cost of energy storage. The change in electricity prices and increased market uncertainty are expected to impact our profits. | The share of natural gas electricity generation is expected to decline over 50 per cent in the regions in which we operate by 2040 compared to 2019 levels. This lower demand for natural gas power is expected to impact our natural gas assets if no management responses are implemented. | Higher operational costs driven by an increase in carbon price to US$205/tonne CO2e by 2040 in all our operating regions (advanced economies under IEA scenarios) and lower operational capacity is expected to impact the profits from our natural gas assets.
SDS | Fewer subsidies/funds are expected under this scenario compared to NZE. However, renewable costs will still decline approximately 10 per cent in wind and 55 per cent in solar by 2040 compared to 2019 levels. This decline with some level of subsidy will increase competition and potentially decrease electricity prices, which is expected to impact our profits. | Natural gas electricity generation still falls over 50 per cent in North America while remaining flat in Australia by 2040 when compared to 2019 levels. Demand for natural gas power is expected to decrease at a slower pace than under NZE. This could potentially impact our natural gas assets if no management responses are implemented. | Increase in operational costs would happen at a slower rate compared to NZE but carbon costs are still expected to reach US$140/tonne CO2e by 2040 in all of our operating regions. This could potentially impact the operational capacity and profits from our natural gas assets, depending on the ability to pass carbon prices on through our contracts.
STEPS | While minimal subsidies are expected and the cost of entry will not decline at the same rate as SDS or NZE, renewable costs are still expected to decline approximately 8 per cent in wind and 45 per cent in solar by 2040 compared to 2019 levels. This will still cause an increase in competition that is expected to be offset by additional electricity demand and therefore it is not expected to impact our profits. | Natural gas electricity generation is expected to increase over 15 per cent in the regions in which we operate by 2040 compared to 2019 levels. These changes are not expected to affect our natural gas assets. | Operational costs are not expected to significantly increase under this scenario as only Canada sees a carbon price in 2040.
Management Response | Navigating the uncertainty around market dynamics (structure, pricing and competition), government policies and planning is critical for TransAlta. We use hedging and PPAs to stabilize pricing and are planning on leading clean energy growth in the regions in which we operate. See more details of our strategy and risk management under the Climate Strategy section and the Managing Climate Change Risks and Opportunities section of this MD&A. | Optimize gas assets to maximize value and cash flows to support renewables and storage growth. Our converted natural gas units' CO 2 intensity is approximately 57 per cent less than coal generation. Repurposing the coal facilities rather than decommissioning them reduces the cost and emissions associated with new construction and aligns with the UN SDGs, specifically "Goal 9: Industry, Innovation and Infrastructure." In parallel, we continue growing our renewable fleet; by the end of 2025 we will have achieved a 100 per cent portfolio mix of renewables and natural gas. | We have taken significant steps to reduce our carbon footprint. Since 2015, we have reduced scope 1 and 2 GHG emissions by 66 per cent. By 2026, we have a commitment to reduce scope 1 and 2 GHG emissions by 75 per cent from 2015 base year and plan to achieve net-zero emissions by 2045. Further, our corporate functions apply regionally specific carbon pricing, both current and anticipated, as a mechanism to manage future risks of uncertainty in the carbon market.

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Top Identified Climate-Related Opportunities by Scenario

| Renewables become major energy source | New technology development
Description | Opportunities to grow the renewable fleet exist across all scenarios. Renewable assets (hydro, wind, solar) are expected to become the default form of generation with demand for power from these types of assets increasing. Hydro is likely to grow in value given increased renewables penetration and the need for reliable zero-emitting generation. This can make hydroelectric power a stronger source of baseload electricity in many regions. The decreasing cost of renewables also facilitates the growth of a renewable fleet, especially under NZE and SDS. | Opportunities for development of battery or hydroelectric storage systems and ancillary services exist across all scenarios as renewable energy continues to penetrate the grid. Developments in these areas are required to keep electricity flowing when the renewables in a region are not producing. Storage is especially anticipated to play an important role in the energy transition. Cost-competitive battery storage enables greater adoption of renewables.
NZE | A growth of renewable electricity generation of approximately 950 per cent is expected by 2040 compared to 2019 levels. This results in renewables comprising more than 85 per cent of the electricity generation in the regions in which we operate. The transition of hydro to baseload capacity is expected to create upside for TransAlta. An increase in TransAlta’s renewable capacity and demand are expected to enable growth and higher revenues. | Increased revenues through access to new and emerging markets are expected to enable growth and higher revenues under NZE. With more than 85 per cent of electricity in areas in which we operate made up of renewables, there will be big steps forward in storage and ancillary services technologies. Storage capacity is expected to grow to approximately 250 GW in the US by 2040.
SDS | A growth of renewable electricity generation of approximately 550 per cent is expected by 2040 compared to 2019 levels. This results in renewables comprising more than 75 per cent of the electricity generation in the regions in which we operate. An increase in TransAlta’s renewable capacity and demand are expected to enable growth and higher revenues. | Increased revenues through access to new and emerging markets are expected to enable growth and higher revenues under SDS. A lower share of renewables than in NZE will allow swing production to remain present; however, growth in ancillary and storage capacity will still be needed to support the market. Storage capacity is expected to grow to approximately 110 GW in the US by 2040.
STEPS | STEPS growth is muted relative to the other scenarios but still sees a growth of renewables of 280 per cent by 2040 compared to 2019 levels. This growth will allow approximately 50 per cent of electricity generation to come from renewables in areas in which we operate by 2040. An increase in TransAlta’s renewable capacity and demand are expected to enable growth and higher revenues. | Access to new and emerging markets would be limited under this scenario compared to NZE and SDS. While growth in renewables is expected, the need for new technologies is not a necessity in this market and may not be profitable. Therefore, our revenues are not expected to be affected.
Management Response | Our renewable energy commitment began more than 100 years ago when we built the first hydro assets in Alberta, which still operate today. We now operate 57 renewable facilities across Canada, the US and Australia. By the end of 2028, we expect 70 per cent of our EBITDA to be derived from renewables. Our strategy is focused on the operation of our existing assets (wind, hydro, solar, gas, storage and coal) and the development of renewable energy, storage and responsive and flexible natural gas generation for reliability. Our investments and growth in renewable energy are highlighted by our portfolio of renewable energy-generating assets. From 2000 to 2023, we grew our nameplate renewables capacity from approximately 900 MW to over 2,900 MW. Today, our diversified renewable fleet makes us one of the largest renewable producers in North America, one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta. | To leverage this opportunity and combat the challenges of renewable energy intermittency, we continue to invest in battery storage. In 2020, we launched WindCharger, a "first of its kind in Alberta" battery storage project that stores energy produced by our Summerview II wind facility and discharges electricity onto the Alberta grid during system supply shortages. Further, in 2021, we agreed to provide renewable solar electricity supported with a battery energy storage system to BHP Nickel West through the construction of the Northern Goldfields solar project in Western Australia. This project was completed in November 2023 and will support BHP in meeting its emissions reduction targets and delivering lower-carbon, sustainable nickel to its customers. In 2023, TransAlta’s early-stage development pipeline included four energy storage projects in Canada with a total capacity in excess of 1 GW.

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NZE: The most significant risks include increased competition, decreased demand for natural gas and increased operational costs due to increased carbon pricing and emissions reduction mandates. The most significant opportunities include a shift toward renewables as the default energy source and new technology developments, including battery storage systems and ancillary services. It is worth noting that there are additional risks and opportunities for TransAlta under NZE. For example, changes in how energy market services are offered could positively or negatively impact our business. Further, as carbon credit policies evolve, so will our ability to use credits. Lastly, as renewables become the primary energy source, a rethinking of ancillary services will be necessary but could create significant opportunities for TransAlta.
SDS: The risks and opportunities remain the same under SDS as NZE; however, the impacts are reduced as market changes are slower and less extreme. Renewables still become the primary electricity source and there are new technology opportunities, particularly in batteries. Natural gas electricity demand still declines by 2040. Carbon pricing exists in the US and Australia, but the price is reduced compared to NZE. Lastly, a reevaluation of ancillary services still presents an opportunity for TransAlta.
STEPS: Under STEPS, renewable generation sees significant growth but does not become the predominant energy source. Implementing new technologies is much slower and the demand for batteries is reduced. The demand for natural gas electricity does not decline and there are no large-scale market changes making services, pricing and ancillary services more stable. This removes the risk associated with natural gas electricity demand but eliminates the opportunity for growth in ancillary services. Physical risks become more relevant under this scenario than transitional risks.
To mitigate risks and capitalize on opportunities, we have developed climate signposts to monitor the evolution of future climate scenarios. Signposts are indicators that suggest the likelihood of a particular climate scenario. Examples of signposts include directional change in carbon and oil prices. The findings from the climate scenarios and these signposts work alongside our sustainability metrics and targets to inform the evolution and resiliency of our Company's strategy and financial planning, risk management, opportunity assessment and planning for uncertainty.
Managing Climate Change Risks and Opportunities
We actively monitor and manage climate-related risks through our Company-wide ERM processes. In 2021, we established a formal process to review specific risks using climate scenario analysis. As previously mentioned, climate change risks and opportunities are addressed at each of the Board level, executive and management level, business unit level and through our corporate functions. The business units and corporate functions work closely together and provide information on risks and opportunities to management, the executive team and the Board.
Climate change risks at the asset or business unit level are identified through our Total Safety Management System, asset management function and systems, energy and trading business, communication with stakeholders, active monitoring and participation in working groups. All identified material risks are added to our ERM register and scored based on likelihood and impact. We do not consider risks in isolation and major risks are the focus of management response and mitigation plans. Further discussion can be found in Reporting in the Governance and Risk Management section of this MD&A.
We divide our climate change risks into two major categories as per IFRS S2 and TCFD guidance: (i) risks related to the transition to a lower-carbon economy; and (ii) risks related to the physical impacts of climate change.
Transition Risks to a Lower-Carbon Economy
We actively aim to understand and manage the impact of climate change on our business as the world shifts to a lower-carbon society.
Policy and Legal Risks
Changes in current environmental legislation do have, and will continue to have, an impact upon our operations and our business in Canada, the US and Australia.
For a more detailed assessment of policy and regulatory risks, refer to the Governance and Risk Management section of this MD&A.
Canada
The Government of Canada has set out ambitious objectives for carbon emissions reduction, including achieving a 40 to 45 per cent national emissions reduction over 2005 levels by 2030, a net-zero electricity grid by 2035 and a net-zero national economy by 2050. The Government plans to rely on several policy tools to achieve its emissions objectives, including carbon pricing, emissions performance regulations, funding for industrial energy transition, a Clean Fuel Regulation and incentives for consumers.

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Canada’s provinces have significant jurisdiction over their respective electricity sectors and play an important role in setting carbon pricing policy and emissions performance standards, as well as developing and operating their own funding and incentive programs, subject to the federal government's authority to set national carbon pricing standards. Negotiation to align carbon pricing, funding and regulatory standards will likely require significant effort and create the risk of tension and misalignment between federal and provincial governments.
Risks
•Escalation in carbon prices and emissions performance regulation may impact TransAlta’s natural gas generation fleet in Canada as governments escalate policy stringency to meet 2030, 2035 and 2050 targets.
•Increased government funding for industrial energy transition may create out of market incentives for competing generation.
•Regulatory incentives, including emissions reduction crediting, may create out of market incentives for competing generation.
•Lack of federal/provincial coordination with respect to climate policy and regulation may lead to investment uncertainty.
Opportunities
•Independent estimates suggest that achieving Canada’s climate targets will require a minimum of twice Canada’s current non-emitting generation. This presents strong policy alignment with TransAlta’s Clean Electricity Growth Plan. Further, we continue to see strong private sector demand for contracted zero emissions generation to meet corporate sustainability goals.
•Government funding for innovative technology to reduce emissions from the electricity sector offers TransAlta the potential opportunity to gain project support for uneconomic new technologies, which will enable the Company to grow its ESG and policy-aligned generation and energy storage fleet.
•Government support for industrial electrification and consumer incentives mandates for electrification, such as for the purchase of electric vehicles, will grow the electricity load over time and create new opportunities for contracted clean electricity generation.
Management Response
•TransAlta’s Clean Electricity Growth Plan positions our company to meet the rapidly growing demand for clean electricity generation driven by customers and government policy.
•We are focused on developing and acquiring contracted assets that provide long-term certainty with respect to revenue and eligibility for government incentive programs. TransAlta actively assesses available
government renewable energy tax legislation and programs to maximize, wherever possible, access to project incentives.
•Our clean and contracted growth reduces the proportional Company exposure to potential policy and regulatory decisions that negatively impact natural gas generation.
•Our coal-to-gas facilities fit within government plans to continue providing reliable and competitively priced electricity for consumers and industry.
•Our remaining natural gas facilities (non-coal-to-gas) operate under contract, reducing TransAlta’s exposure to changes in carbon pricing.
•TransAlta actively engages with the federal and provincial governments in Canada to inform and influence policy development to ensure that our generating fleet continues to serve our customers as the country undertakes a broader energy transition.
•We actively work, both directly and through industry associations, to encourage governments to adopt a level playing field within funding and crediting programs so that all new emerging technology projects receive equitable government incentives and funding.
•TransAlta actively engages with all relevant Canadian governments to seek policy alignment across carbon pricing and regulatory and funding programs to create the greatest possible degree of investment certainty.
United States
The US Government has set out ambitious objectives for carbon emissions reduction, including achieving a 50 to 52 per cent national emissions reduction over 2005 levels by 2030, a net-zero electricity grid by 2035 and a net-zero national economy by 2050. The US does not have a national carbon pricing regime but does offer federal incentives for renewable generation and energy storage.
State and regional climate and market policies have a significant impact on the pace of energy transition in the US with many governments operating under renewable portfolio standards and carbon pricing regimes. Similar to Canada, independent estimates suggest that the US will require substantial growth in zero-emissions generation to meet its national climate targets.
Risks
•TransAlta operates two thermal generating facilities in the US that could be subject to short-term climate policy changes, but our exposure to this policy risk is low (refer to Management Response below).
•Significant new federal incentives for clean energy could increase competition in the renewables and energy storage space.

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Opportunities
•Achieving government climate goals and private sector sustainability commitments will require rapid and sustained growth in zero-emissions electricity generation over the coming decades. TransAlta’s Clean Electricity Growth Plan is focused on providing renewable electricity to contracted customers in a manner that aligned with federal, state and private sector goals.
•US tax incentive programs offer significant support for new renewable and energy storage projects, making the US an attractive growth market.
Management Response
•TransAlta’s single coal unit in Washington State is subject to a retirement agreement with the state government that exempts the facility from any carbon regulation prior to its end of life in 2025. TransAlta’s cogeneration unit at Ada operates under a contract that reduces the Company’s exposure to policy risk.
•Our Clean Electricity Growth Plan is focused on developing and acquiring contracted assets that provide long-term certainty with respect to revenue and eligibility for government incentive programs. TransAlta actively assesses available government renewable tax legislation and programs to maximize, wherever possible, access to project incentives.
Australia
The Australian Government has a 43 per cent national emissions reduction target over 2005 levels by 2030 and a goal to achieve a net-zero national economy by 2050. Decarbonization efforts have been centered on funding for clean technologies, upgrading the electricity grid to support more renewables, regulating and reporting of GHG emissions, and incentivizing zero-emissions vehicle adoption. Large GHG emitters are required to reduce their scope 1 emissions under the Australian Government's National Safeguard Mechanism ("SGM"). While the government has made recent changes to the SGM, these changes are not expected to have a material impact on TransAlta's assets. Australian state governments have all adopted net-zero goals and a number of states have interim targets for 2030 and 2040. These state policies are driving demand for zero-emissions electricity and energy storage.
Risks
•TransAlta’s Australian natural gas assets may face policy risk related to changes in government policies but remain well positioned to mitigate those risks (refer to Management Response below).
Opportunities
•Our Clean Electricity Growth Plan is focused on building new, clean electricity generation in Australia and other markets. Government policies and funding programs are generally supportive of the types of projects contemplated within TransAlta’s strategy.
•Strong corporate demand for clean electricity solutions in Australia's natural resource sectors present opportunities for TransAlta to leverage its existing expertise to help customers meet regulatory requirements and reach their decarbonization objectives.
Management Response
•Through our Clean Electricity Growth Plan, TransAlta continues to deliver clean electricity solutions to natural resource customers in Western Australia. Our growing suite of technologies, including renewables and energy storage, positions us to provide contracted solutions to customers focused on the need for reliable and sustainable energy.
•TransAlta also continues to assess opportunities to grow our clean energy generation in alignment with Australia's national and state climate goals.
•TransAlta’s assets are predominantly contracted with an ability to pass through carbon compliance costs and serve remote industrial load. As a result, the Company faces reduced policy risk.
Technology Risks
Technological changes to support the low-carbon transition present both risks and opportunities for TransAlta. We evaluate existing and emerging impacts of technology through our Energy Innovation team and our ERM process. Examples of technology risks and opportunities include infrastructure changes (such as the shift to distributed energy and away from large-scale power generation infrastructure assets and projects) and digitization combined with greater adoption of energy efficiency (less use of our end product). Cost-competitive battery storage will enable greater adoption of renewables and a shift to a distributed power generation model. We continue to evaluate battery storage for its financial viability while monitoring the potential impact battery technology could have on natural gas power generation. In 2020, we completed our first battery storage (10 MW) project at one of our wind facilities in Southern Alberta. In 2023, we delivered a hybrid system of solar with battery storage (48 MW) in Western Australia. We continue to investigate the possibility of battery storage at our other facility locations. Our teams continuously adopt improved technology at each of our new developments, which helps protect our shareholder value and maintain reliable and affordable electricity delivery.
We are well-positioned to take advantage of technological opportunities in storage through hydro and/or battery power. We are also well-positioned to take advantage of advancements in renewable technologies as we build new facilities. We will continue monitoring new technologies such as storage, hydrogen and CCUS for future deployment.
For further information on technology and innovation, refer to the Enabling Innovation and Technology Adoption section of this MD&A.

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Market Risks
Our major market risks are associated with our coal and natural gas assets. Increased costs for natural gas supply due, in part, to carbon pricing changes could impact our operating costs. We actively monitor market risks through our energy marketing and asset optimization teams and our ERM process. We manage the market risks to our coal assets by converting them to natural gas and plan to fully transition off coal by 2025. Further, our corporate functions apply regionally specific carbon pricing, both current and anticipated, as a mechanism to manage future risks of uncertainty in the carbon market. To simultaneously manage our risks and leverage market opportunities, we continue operating our hydro, wind and solar facilities and are investing in expanding our renewable energy fleet.
We currently have over 30 renewable projects that are either under construction or in the development stage. We are committed to growing our clean energy fleet. Further, we established Canadian, US and Australian clean energy growth teams. In 2023, the Company established a pipeline of potential growth projects in renewables that includes 280 MW of advanced-stage development projects along with 4,285 to 5,015 MW of projects in earlier stages of development. Our renewable fleet makes our overall portfolio more resilient to climate risk, provides increased flexibility in generation and creates incremental environmental value through environmental attributes. Lastly, we recognize the opportunity to grow our ancillary services, such as systems support, providing flexibility to the decarbonizing grid.
Reputation Risks
Negative reputational impacts, including revenue loss and reduced customer base, are evaluated through our ERM process. In the past, we experienced negative reputational impacts due to our coal operations, including a negative impact on the market price of our common shares. Our clear transition path away from coal mitigates this reputational risk. As consumer trends move in favour of renewable electricity, we are investing in a diversified mix of renewable generation and optimizing our natural gas fleet. We continue to actively monitor and manage reputational risks by delivering renewable power solutions while maintaining competitive costs and reliability.
Physical Risks of Climate Change
As we learn more about the physical risks associated with climate change, we continue to consider acute and chronic risks that could significantly impact our operations. We continue to investigate the physical impacts of climate change on our operating assets.
Acute Physical Risks
We have operating assets in three countries and varied geographic locations, many of which could be impacted by extreme weather events. We continuously evaluate the potential impact of acute climate change on our business. Our facilities, construction projects and operations are exposed to potential interruption or loss from environmental disasters (e.g., floods, strong winds, wildfires, ice storms, earthquakes, tornados, cyclones). A significant climate change event could disrupt our ability to produce or sell power for an extended period. Therefore, we strive to mitigate future impacts with climate adaptation solutions.
For example, our gas facility at South Hedland, Australia, is built with climate adaptation in mind. We designed the facility to withstand a category 5 cyclone (the highest cyclone rating). We have mitigated the risk of floods that can occur in the area by constructing the facility above normal flood levels. In 2019, a category 4 cyclone hit this facility but did not impact operations. We were able to continue generating electricity through the storm despite widespread flooding and the shutdown of the nearby port. In Canada, since the 2013 floods in Southern Alberta, we have implemented projects that increase the resilience of our hydro facilities to severe climate events. We have also modified operations at several of our facilities as per an agreement with the Government of Alberta. This reduces flood risk in the spring while also recognizing the potential for increased droughts as a result of climate change in the future. TransAlta continues to participate in multi-stakeholder groups developing options for climate resiliency across Southern Alberta.
For further information on weather-related risks, refer to Weather in the Progressive Environmental Stewardship section of this MD&A.
Chronic Physical Risks
We continuously investigate the physical impacts of longer-term shifts in climate patterns on our operating assets and actively integrate climate modelling into our long-term planning. For example, changes to water flow or wind patterns could impact our hydro and wind businesses and associated revenue generation.
Climate Change Metrics and Targets
Metrics and Targets
At TransAlta, climate change management and performance are a top priority. We established our climate-related goals and targets with reference to the UN SDGs. Over time, we have set ourselves apart with actions that demonstrate climate change leadership.

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Progress towards our climate-related targets are presented below. As a result of our Clean Electricity Growth Plan being updated in November 2023, the below performance is assessed against our prior Clean Electricity Growth Plan announced in 2021.

Clean energy growth
Sustainability Target |  | Develop new renewable projects that support our customers' sustainability goals to achieve both long-term power price affordability and carbon reductions.(1) |  | No further coal generation; 100 per cent of our owned net generation capacity from renewables and gas.
Target Year |  | 2025 |  | 2025
Progress |  | Renewables Growth |  | Net Generation Capacity (renewable and gas)
Notes |  | Since 2021, we have added over 800 MW of new capacity through renewable projects such as Windrise (206 MW), Garden Plain (130 MW), Northern Goldfields Solar (48 MW), White Rock (300 MW) and Horizon Hill (200 MW). In November 2023, our Clean Electricity Growth Plan was updated to continue our priorities. By 2028, the plan will see the Company execute on an incremental 1.75 GW of renewables growth and a 10 GW growth pipeline. |  | In 2023, our owned net generation capacity from renewables and gas represented approximately 90 per cent of our total 6,425 MW owned net generation capacity. In 2021, we achieved full phase-out of coal in Canada. In the US, the remaining unit at Centralia is set to retire on Dec. 31, 2025.
UN SDG Alignment |  | Target 7.2: "By 2030, increase substantially the share of renewable energy in the global energy mix" |  | Target 7.1: "By 2030, ensure universal access to affordable, reliable and modern energy services”.

(1)This includes the construction of new renewable projects (hydro, wind and solar) as part of the Company's Clean Electricity Growth Plan. This excludes acquisitions.

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Emissions reduction
Sustainability Target |  | By 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from a 2015 base year. |  | By 2045, achieve net-zero for 100 per cent of TransAlta’s scope 1 and 2 GHG emissions.
Target Year |  | 2026 |  | 2045
Progress |  | GHG Emissions Reduction |  | GHG Emission (million tonnes CO 2 e)
Notes |  | We are well on track to achieve our target of 75 per cent scope 1 and 2 GHG emissions reductions by 2026. Since 2015, we have reduced scope 1 and 2 GHG emissions by 21.3 MT CO2e or 66 per cent. |  | In 2022, we adopted a more ambitious target to be net-zero by 2045. We believe our Clean Electricity Growth Plan supports achieving our net-zero target.
UN SDG Alignment |  | Target 13.2: "Integrate climate change measures into national policies, strategies and planning". |  | Target 13.2: "Integrate climate change measures into national policies, strategies and planning".

TransAlta's target to reduce 75 per cent of our scope 1 and 2 GHG emissions by 2026 from a 2015 base year is estimated to align with the electricity sector decarbonization pathway to limit global warming to 1.5°C, as one of the Paris Agreement goals.
In December 2021, the Company committed to setting a science-based emissions reduction target through the Science Based Target initiative ("SBTi"). In 2022, we started the target validation process of our 2026 scope 1 and 2 emissions reduction target. In 2023, TransAlta did not anticipate that setting a near-term scope 3 target would be a condition to our scope 1 and 2 target being validated by the SBTi. This would mean accelerating the validation of our scope 3 emissions ahead of the Company's intended timelines. As a result, given SBTi's requirement that we establish a near-term scope 3 reduction target, we determined to withdraw from our commitment to the SBTi. TransAlta remains confident that our significant scope 1 and 2 emissions reduction trajectory from 2015 to 2026 is in line with the electricity sector pathway to limit global warming to 1.5°C.
GHG Disclosures
Scope 1 and 2 Emissions
Our scope 1 and 2 GHG emissions are calculated using a number of different methodologies depending on the technologies available at our facilities. Emissions data has been aligned with the “Setting Organizational Boundaries: Operational Control” methodology set out in the GHG Protocol: A Corporate Accounting and Reporting Standard developed by the World Resources Institute and the World Business Council for Sustainable Development. We report emissions on an operation control basis, which means we report 100 per cent of emissions at the facilities that we operate.
The GHG Protocol classifies a company’s scope 1 emissions as the direct emissions from owned or controlled sources. Scope 2 emissions are indirect emissions from the generation of purchased energy.
We compile our corporate GHG inventory using our business segment GHG calculations. As a result, emission factors and global warming potentials used in our GHG calculations can vary due to difference in regional compliance guidance. Applying harmonized global warming potentials across our fleet would result in a minor variance to our overall calculated GHG totals.
Our 2023 GHG data was reported to a number of different regulatory bodies throughout the year for regional compliance and, as a result, may incur minor revisions as we review and report data. Any historical revisions will be captured and reported in future disclosure. As per the

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Kyoto Protocol, GHGs include carbon dioxide, methane, nitrous oxide, sulphur hexafluoride, nitrogen trifluoride, hydrofluorocarbons and perfluorocarbons. Our exposure is limited to carbon dioxide, methane, nitrous oxide and a small amount of sulphur hexafluoride. The majority of our estimated GHG emissions result from carbon dioxide emissions from stationary combustion from coal and
natural-gas-powered generation. Methane emissions from our operations are mainly due to incomplete combustion of natural gas from the natural-gas-powered plants and there are no fugitive methane emissions associated with our operations. In 2023, methane emissions were 0.2 per cent of our total emissions.
The following tables detail our GHG emissions by scope, business segment and country in million tonnes of CO 2 e. Some values do not sum to the indicated total due to rounding of tabulated emissions. Zeros (0.0) indicate truncated values.

Year ended Dec. 31 | 2023 | 2022 | 2021
Scope 1 | 10.9 | 10.2 | 12.4
Scope 2 | 0.0 | 0.1 | 0.1
Total scope 1 and 2 GHG emissions | 10.9 | 10.2 | 12.5

Year ended Dec. 31 | 2023 | 2022 | 2021
Hydro | 0.0 | 0.0 | 0.0
Wind and Solar | 0.0 | 0.0 | 0.0
Gas | 6.4 | 6.3 | 6.5
Energy Transition | 4.5 | 4.0 | 6.0
Corporate and Energy Marketing | 0.0 | 0.0 | 0.0
Total scope 1 and 2 GHG emissions | 10.9 | 10.2 | 12.5

Year ended Dec. 31 | 2023 | 2022 | 2021
Australia | 1.0 | 0.9 | 1.0
Canada | 5.3 | 5.2 | 7.9
US | 4.6 | 4.1 | 3.6
Total scope 1 and 2 GHG emissions | 10.9 | 10.2 | 12.5

In 2023, our GHG emissions (scopes 1 and 2) were 10.9 million tonnes as a result of normal operating activities. Despite the increase in absolute emissions as a result of increased production, our scope 1 and 2 GHG emissions intensity remains similar to the previous year at 0.41 tCO2e/MWh (2022 - 0.40 tCO2e/MWh). TransAlta will cease generation from our single remaining US coal unit by the end of 2025, which will further reduce the Company’s emissions.
TransAlta sells the environmental attributes generated from our renewable energy facilities and does not subtract this amount from our total GHG emissions (scope 1 and 2). However, it should be noted that TransAlta’s customers are reporting GHG emissions reductions using our renewable energy assets, projects and operations.
GHG emissions are verified to a level of reasonable assurance in locations in which we operate within a carbon regulatory framework. Any historical revisions to GHG data will be captured and reported in future disclosure. The majority of our GHG emissions result from carbon dioxide emissions from stationary combustion from coal and natural-gas-powered generation.
The following table highlights our scope 1 and 2 GHG emissions reductions since 2015 and our targeted emissions in 2026. The actual GHG emissions for the Company in 2026 will vary from that presented below depending on, among other things, the growth of the Company, including its on-site generation business.

Year ended Dec. 31 | 2026 (forecast) | 2023 | 2015
Total scope 1 and 2 GHG emissions (million tonnes CO 2 e) | 8.1 | 10.9 | 32.2

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Scope 3 Emissions
Scope 3 emissions are all indirect emissions (not included in scope 1 or 2) that occur in the value chain of the reporting company, including both upstream and downstream emissions. TransAlta's scope 3 emissions are calculated using methodologies consistent with the GHG Protocol Corporate Value Chain (Scope 3) Accounting and Reporting Standard ("Scope 3 Standard") and with reference to the additional guidance provided in the GHG Protocol Technical Guidance for Calculating Scope 3 Emissions ("Scope 3 Guidance") developed by the World Resources Institute and the World Business Council for Sustainable Development.
Our scope 3 emissions include the indirect GHG emissions resulting from activities in our value chain but outside of our operational control. We estimate our scope 3 emissions in 2023 to be approximately four million tonnes of CO 2 e, which is primarily attributed to our non-operated joint venture interests as part of Category 15: Investments. Of the 15 categories described in the GHG Protocol Scope 3 Guidance, four are not relevant to our business and, therefore, are not included in the calculation: Category 8: Upstream leased assets, Category 12: End-of-life treatment of sold products, Category 13: Downstream leased assets, and Category 14: Franchises.
Since 2022, we have focused on enhancing our scope 3 emissions accounting. In 2022, we engaged with an independent third-party consulting company to complete a methodology review of our scope 3 inventory based on the GHG Protocol Scope 3 Guidance. In 2023, we engaged with an independent third-party advisory firm to complete a pre-assessment of material scope 3 emissions so that we can meet our target to verify and disclose 80 per cent of TransAlta’s scope 3 emissions by 2024, with the aim of reporting on 2023 scope 3 emissions as part of our 2024 Integrated Report.
Avoided Emissions
In 2023, production from renewable assets resulted in the avoidance of approximately 2.3 million tonnes of CO 2 e for our customers. TransAlta's avoided emissions are defined as the sum of the displaced emissions by our renewable assets in the jurisdictions where we operate. The value is calculated as the product of the generation of electricity obtained from a renewable source (hydro, wind and solar) and the specific CO 2 emissions intensity from the grid of the jurisdiction in which we operate. Avoided emissions decreased in 2023 compared to 2022 primarily due to the reduction of emission intensity of the grid. As the world decarbonizes over time, the emission intensity of the grid will gradually decrease year over year. The following table highlights our avoided emissions in the reporting year.

Year ended Dec. 31 | 2023 | 2022 | 2021
Total GHG emissions avoided (million tonnes CO 2 e) | 2.3 |  | 2.7 | 2.6

Sustainable Finance
Sustainable finance is the process of taking due account of ESG considerations (e.g., climate change, biodiversity, human rights, etc.) when making investment decisions. Sustainable finance is a key pillar of TransAlta’s Climate Transition Plan. This means we will utilize pools of capital available to sustainable economic activities and projects to finance our energy transition towards net-zero operations.
TransAlta deploys green and sustainable financing to build our renewable energy fleet and advance our clean energy transition. This supports our goal to deliver on our customers’ needs for clean electricity. Since 2020, we have issued $684 million in green bonds and converted our four-year $2.0 billion revolving credit facility into a sustainability-linked loan.
In 2022, TransAlta issued US$400 million ($533 million) in Senior Green Bonds, an amount equal to the net proceeds from the bonds has been allocated to finance or refinance
new and/or existing eligible green projects. The bonds were issued under TransAlta's Green Bond Framework, which aligns with the Green Bond Principles published by the International Capital Market Association. For further information, refer to Green Bond Framework in the Shareholder Information section of the Investor Centre on our website. In 2021, the Company's indirect wholly owned subsidiary, Windrise Wind LP, completed a secured green bond offering by way of private placement for approximately $170 million (face value).
In 2021, TransAlta converted an existing $1.3 billion syndicated revolving credit facility into a sustainability-linked loan. The loan aligns the cost of borrowing to the Company's GHG emissions reductions and gender diversity targets. Sustainability-linked loans are any types of loan instruments and/or contingent facilities (such as bonding lines, guarantee lines or letters of credit) that incentivize the borrower’s achievement of ambitious, predetermined sustainability performance objectives.

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The summary below shows the carrying value of the issued green bonds and the total facility size of our ESG financial operations portfolio.

As at Dec. 31 (in millions of Canadian dollars) | 2023 | 2022 | 2021
Green bonds (1) | 684 | 703 | 171
Sustainability-linked loans | 1,950 | 1,250 | 1,250

(1)Green bonds are related to Senior Green Bonds issued in 2022 and the Windrise Wind green bond issued in 2021.
Climate-Related Financial Metrics
The results of TransAlta’s 2021 climate-related scenario analysis, aligning with a 1.5°C warmer world, have shown that opportunities to grow the renewable fleet exist across all scenarios and locations. Our adjusted revenue from renewable energy generation (hydro, wind and solar) in 2023 was $902 million (2022 – 1,014 million) or 27 per cent of our total adjusted revenue in 2023.
We continue to execute the Clean Electricity Growth Plan updated in 2023 to deliver up to 1.75 GW of incremental renewables capacity and a 10 GW growth pipeline by 2028. In 2023, our growth capital expenditures for renewable energy generation was $630 million (2022 – $666 million). In addition, TransAlta continues to invest in emerging abatement technologies and solutions. In 2023, our investments in low-carbon research and development were $4 million (2022 – $12 million).
As part of our Clean Electricity Growth Plan, our goal is to achieve 70 per cent of adjusted EBITDA from renewables and storage by the end of 2028. In 2023, adjusted EBITDA from renewable energy generation was $716 million (2022 – $838 million) or 44 per cent of our total adjusted EBITDA. Our renewable fleet makes our overall portfolio more resilient to climate-related risks, provides increased flexibility in generation and creates incremental environmental value through environmental attributes. Our revenue in 2023 from environmental attribute sales was $36 million (2022 – $53 million).
The disclosure of TransAlta's financial metrics related to our climate-related risks and opportunities align with the IFRS S2 and TCFD recommendations. A summary of our climate-related financial metrics is presented below.

Year ended Dec. 31 (in millions of Canadian dollars) | 2023 | 2022 | 2021
Growth capital expenditures for renewable energy generation(1) | 630 |  | 666 | 326 |
Renewable energy adjusted EBITDA(2) | 716 |  | 838 | 584 |
Environmental attribute sales revenue(3) | 36 |  | 53 |  | 40 |
Renewable energy adjusted revenue(4) | 902 | 1,014 |  | 731 |
Investments in low-carbon research and development(5) | 4 | 12 |  | — |

(1)Growth capital expenditures include amounts deployed for growth projects and acquisitions related to renewable energy generation. This includes the construction of our Windrise wind facility completed in 2021, the acquisition of North Carolina Solar portfolio in 2021, the construction of the Garden Plain wind project, White Rock wind projects, Horizon Hill wind project and Northern Goldfields solar project as part of our Clean Electricity Growth Plan. This excludes the Mount Keith transmission expansion project.
(2)Adjusted EBITDA from renewable energy generation includes hydro, wind, solar and battery storage facilities. The renewable energy adjusted EBITDA is the total adjusted EBITDA of the Hydro and Wind and Solar segments. These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures and Segmented Financial Performance and Operating Results sections of this MD&A.
(3)Environmental attribute sales revenue indicates the full amount of hydro, wind and solar environmental credits, without any other consolidation impacts.
(4)Adjusted revenue from renewable energy generation includes hydro, wind, solar and battery storage facilities. For details of the adjustments to revenues included in adjusted EBITDA refer to the Additional IFRS and Non-IFRS Measures section of this MD&A
(5)Investments in low-carbon research and development include our equity investment in Ekona Power Inc.'s ("Ekona") Series A funding round and our four-year investment in EIP’s Deep Decarbonization Frontier Fund 1 (the “Frontier Fund”).

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Alignment with Climate-Related Disclosures Frameworks
The table below shows the alignment of our climate change management disclosure with TCFD, IFRS S2 and CDP (2023) recommendations.

TCFD Recommended Disclosures | Other Alignments | Location
Governance |  |
Describe the board’s oversight of climate-related risks and opportunities | IFRS S2: 6; CDP: C1.1 | Oversight by the Board of Directors
Describe management’s role in assessing and managing climate-related risks and opportunities | IFRS S2: 6; CDP: C1.2 | Role of Senior Management
Strategy |  |
Describe the climate-related risks and opportunities the organization has identified over the short, medium and long term | IFRS S2: 8-9; CDP: C2.1 | Key Scenario Findings
Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy and financial planning | IFRS S2: 8-9; CDP: C2.3, C2.4, C3.3, C3.4 | Climate Change Strategy, Key Climate Scenario Findings
Describe the resilience of the organization’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenario | IFRS S2: 22-23; CDP: C3.1, C3.2 | Climate Scenarios, Key Climate Scenario Findings
Risk management |  |
Describe the organization’s processes for identifying and assessing climate-related risks | IFRS S2: 10; CDP: C2.2 | Climate Change Strategy
Describe the organization’s processes for managing climate-related risks | IFRS S2: 24-25; CDP: C2.2 | Managing Climate Change Risks and Opportunities
Describe how processes for identifying, assessing and managing climate-related risks are integrated into the organization’s overall risk management | IFRS S2: 24-25; CDP: C2.2 | Managing Climate Change Risks and Opportunities
Metrics and targets |  |
Disclose the metrics used by the organization to assess climate-related risks and opportunities in line with its strategy and risk management process | IFRS S2: 27-28; CDP: C6.1, C6.3, C6.5, C9.1 | Climate Change Metrics and Targets
Disclose scope 1, scope 2 and, if appropriate, scope 3 greenhouse gas (GHG) emissions and the related risks | IFRS S2: 29-32; CDP: C6.1, C6.3, C6.5 | Climate Change Metrics and Targets
Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets | IFRS S2: 33-36; CDP: C4.1, C4.2 | Climate Change Metrics and Targets

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Enabling Innovation and Technology Adoption
Technology and innovation are an existing and increasing focus at TransAlta. We have long been innovators. TransAlta has been at the forefront of innovation in the power-generation sector since the early 1900s when we developed hydro assets. We have been an early adopter and developer of wind technology in Canada, including the first commercial wind farm in Canada, and are now one of the largest wind generators in the country. In 2015, we made our first investment in solar technology in Massachusetts, in 2020, we installed the first utility-scale battery in Alberta and, in 2023 we completed our first solar microgrid with battery energy storage system in Western Australia. We are now looking to advance a new technology roadmap that aligns with the Clean Electricity Growth Plan. This section covers manufactured and intellectual capital management as per guidance from the International Integrated Reporting Framework.
Our Energy Innovation Team
As part of our Clean Electricity Growth Plan, in 2021, we established an Energy Innovation team to investigate, prioritize and deploy new net-zero electricity generation technologies that address the three main factors of our energy transition: reliability, decarbonization and affordability. As we grow our renewables business, the Energy Innovation team is focused on what we should build next that complements our hydro, wind and solar assets to deliver reliable, affordable and low-carbon electricity to our customers. At the same time, the Energy Innovation team is looking at electrification broadly to investigate where potential new, adjacent business opportunities may exist for TransAlta.
Our Energy Innovation team participates in the Energy Futures Lab, a multi-stakeholder initiative that brings together innovators, influencers, and experts from different sectors and perspectives to address the challenges and opportunities of achieving a net-zero Alberta energy system. In 2023, TransAlta sponsored the Energy Futures Labs Alberta’s Electricity Futures Working Group, which aims to foster collaboration to explore and test new solutions for a reliable, affordable, and low-carbon electricity system in Alberta. We also continue to participate in the energy innovation ecosystem through engagement with various innovation accelerators that 'incubate' and accelerate start-ups by matching new technology solutions with practical problems identified by end-users, like TransAlta.
In 2023, TransAlta launched its Energy Innovation Series. The Series is led by our Energy Innovation Team along with guest speakers from across the Company and aims to empower our workforce through relevant industry knowledge on innovation in the electricity sector. In 2023, we delivered four sessions on a range of relevant topics
including grid reliability during the energy transition, grid energy storage options and decarbonized baseload generation strategies.
For further details on how we invest in our workforce, please refer to Talent and Employee Development in the Building a Diverse and Inclusive Workforce section of this MD&A.
Renewable Energy
In 2023, TransAlta's nameplate capacity was 944 MW from hydro energy, 2,046 MW from wind and battery storage, and 181 MW from solar power. We continue to look for opportunities to develop and operate solar energy.
In August 2023, the Garden Plain wind facility in Alberta was commissioned adding 130 MW to our gross installed capacity. The facility is fully contracted with Pembina Pipeline Corporation (100 MW) and PepsiCo Canada (30 MW), with a weighted average contract life of approximately 17 years.
In November 2023, the 48 MW Northern Goldfields solar and battery storage facilities in Western Australia achieved commercial operation. The facilities consist of the 27 MW Mount Keith solar facility, 11 MW Leinster solar farm and 10 MW/5 MWh Leinster battery energy storage system and interconnecting transmission infrastructure, all of which are now integrated into TransAlta’s 169 MW Southern Cross Energy North remote network. The Northern Goldfields solar facilities are expected to reduce BHP Nickel West’s scope 2 electricity GHG emissions from its Leinster and Mount Keith operations by 12 per cent and is long-term contracted with a globally recognized counterparty for 16 years.
In 2023, the Company continued to advance the 300 MW White Rock wind projects, to be located in Oklahoma. The White Rock wind projects are expected to achieve commercial operation in the first quarter of 2024. In 2021, we entered into two long-term PPAs with Amazon for the offtake of 100 per cent of the generation from these projects.
In 2023, TransAlta advanced the construction of its 200 MW Horizon Hill wind project located in Oklahoma, with a target commercial operation date in the first quarter of 2024. In 2022, the Company executed a long-term renewable energy PPA with a subsidiary of Meta for 100 per cent of the generation from the project. Under this agreement, Meta will receive both renewable electricity and environmental attributes from the Horizon Hill wind project.
TransAlta is actively advancing its development pipeline for renewable energy generation. In 2023, the Company

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established a pipeline of potential growth projects in renewables that includes 280 MW of advanced-stage development projects along with 4,285 to 5,015 MW of projects in earlier stages of development.
Scaling Up Energy Solutions
Battery Storage
We continue to invest in battery energy storage systems and see them as an important element for TransAlta to continue to provide reliability through the energy transition – continuing an important role TransAlta has played for over one hundred years with our hydro units.
In November 2023, the Northern Goldfields solar and battery storage facilities in Western Australia achieved commercial operation and are now supplying reliable electricity to BHP’s remote nickel mining operations in Western Australia. The energy storage consists of the 10 MW/5 MWh Leinster Battery Energy Storage System which will be integrated into TransAlta’s remote network. The network and new generation will support BHP Nickel West to meet its emissions reduction targets and deliver lower-carbon nickel to its customers. TransAlta is continuing to work with BHP Nickel West on the development of other projects to further reduce scope 2 GHG emissions at BHP’s Mt Keith and Leinster operations.
In 2023, TransAlta’s development pipeline included four energy storage projects in Canada: WaterCharger (lithium-ion battery storage, 180 MW), Tent Mountain (pumped hydro storage, 160 MW), Brazeau (pumped hydro storage, 300-900 MW) and New Brunswick Power Battery (battery, 10 MW). These strategically-located units could play various roles on electricity grids including providing reliability services and storing surplus generation for discharge at peak periods.
Electric Mobility
Companies can play an important role in driving the transition to electric vehicles by taking the lead in their own operations. Recognizing this role, TransAlta is exploring the potential of electrifying our service fleet with zero-emission vehicles. In 2023, we launched a pilot project called Project Electrify to test four fully-electric vehicles at different facilities in Canada. We will assess their performance, safety and cost-effectiveness under different conditions and operator needs. The project will run from 2024 to 2025, during which time our operators will gain hands-on experience with the technology and provide feedback on its suitability for wider adoption. Based on the learnings from the project, TransAlta will decide whether to pursue further electrification of our fleet.
Future Solutions
Hydrogen
In 2022, we announced a $2 million equity investment in Ekona's Series A funding round. The investment will help support the commercialization of Ekona’s novel methane pyrolysis technology platform, which produces cleaner and lower-cost turquoise hydrogen. If successful, Ekona’s distributed technology allows for onsite production of hydrogen, hence avoiding the need for costly transportation of hydrogen. Furthermore, its solid carbon byproduct allows for low-cost, low-emissions hydrogen production without the need for carbon sequestration. TransAlta is a member of Ekona’s Strategic Committee and continues to work with Ekona as it develops its pyrolysis technology.
Small Modular Reactors ("SMR")
Small modular reactors have a power capacity of up to 300 MW per unit and differ from traditional nuclear in that they are built to be modular, factory-assembled units that are transported to a location for installation. Additionally, they implement passive or walk-away safety features designed to dramatically reduce the risk of nuclear events. While high costs remain a challenge for all forms of nuclear, SMR developers argue that smaller MW plants made from manufactured components will allow the industry to access steep cost declines as the technology matures and more units are deployed. By providing reliable, emissions-free baseload power, nuclear power may play an important role in clean energy transitions. Today, nuclear power makes a significant contribution to low-carbon electricity generation and has significant potential to contribute to power sector decarbonization. TransAlta continues to monitor developments in SMR.
Nature-based Solutions ("NBS")
Nature-based solutions are actions to protect, sustainably manage and restore natural and modified ecosystems that address societal challenges effectively and adaptively, simultaneously benefiting people and nature. TransAlta is actively evaluating NBS as carbon removals to neutralize any residual emissions that we cannot yet eliminate.
Direct Air Capture ("DAC")
Direct air capture technologies extract CO 2 directly from the atmosphere. The CO 2 can be permanently stored in deep geological formations, thereby achieving permanent CO 2 removal. TransAlta continues to explore the benefits of DAC as a carbon dioxide removal option to support the net-zero transition of our operations and customers.
Carbon Capture, Utilization and Storage ("CCUS")
Our teams continuously explore the use of applied or new technologies such as CCUS to reduce GHG emissions. We

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know that new technologies will emerge over the next number of years as the industry continues to drive towards lower emissions while maintaining a reliable and affordable product for customers.
Disruptive Technologies
In 2022, we entered into a commitment to invest US$25 million over the next four years in Energy Impact Partners' ("EIP") Deep Decarbonization Frontier Fund 1 (the “Frontier Fund”) that invests in early-stage, innovative technology companies that will accelerate the transition to net-zero GHG emissions. TransAlta's investment in the Frontier Fund provides TransAlta with the opportunity to pool funds with some of the largest utilities in the United States and Europe to identify, pilot, commercialize and bring to market technologies that will support its decarbonization goals.
Fusion
Fusion technologies attempt to recreate the fusion reactions in the sun by fusing two hydrogen molecules together. If successful, fusion promises low-cost energy, with far shorter-lived nuclear waste. Fusion achieved some significant development milestones in 2022, including most significantly, Lawrence Livermore National Laboratory achieving net energy gain. This, coupled with unprecedented capital flow into fusion companies, has led to newfound excitement that fusion may be able to leapfrog current generation technologies.
Through EIP, TransAlta has invested in ZAP Energy, a leading fusion start-up. ZAP Energy’s technology stabilizes the hydrogen plasma using sheared flow (driving current through the flow creating the magnetic field confining and compressing the plasma) rather than magnetic fields. In 2022, ZAP announced it will conduct a feasibility study of retrofitting the former TransAlta Big Hanaford gas plant located in Centralia to host its first-of-a-kind Z-pinch fusion pilot plant. ZAP received $1 million from the Centralia Coal Transition Grants Energy Technology Board as part of our energy transition investments to move away from coal in Washington State.
For more information on investments in low-carbon research and development, refer to Climate-Related Financial Metrics section of this MD&A.
Analytics and Automation
Asset Performance
TransAlta's Asset Performance team was founded in 2023 to continue the work initiated by our previous Asset Analytics and Optimization team founded in 2008. This team monitors the Company's generation portfolio across Canada, the US and Australia. A centralized team of engineers and operations specialists remotely monitors our
power facilities for emerging equipment reliability and performance issues. The Asset Performance team also performs production reporting functions for these assets and is actively engaged in projects to improve this reporting.
The Data and Innovation team worked with partners across the company to advance its Asset Performance Management platform, GenOS, to deliver new features that increase the performance and management of our renewable asset fleet. Key process improvements, such as enhanced performance analytics that leverage machine learning, advanced analytics and data science models, provide our operators with deeper insights to help optimize asset performance across the entire fleet. Built in-house, GenOS provides data-driven insights for our wind, solar, gas and hydro fleets
Asset Performance staff are trained in the development and use of specialized equipment monitoring and performance assessment software and they apply their experience to power facility operations. If an issue is detected, the Asset Performance engineer will initially assess and then notify facility operations of their findings to support investigation and remedy of the issue before there is an impact to operations. This support is critical for reliability and performance of our operations. For example, if a wind turbine starts to show very early signs of equipment change compared to others, our operation team is notified and will work to investigate and remedy the issue. The monitoring, analysis and diagnostics completed by the Asset Performance engineer are focused on early identification of equipment issues based on longer-term trend analysis and complements day-to-day facility operations.
Automation and Robotics
TransAlta created the Data and Innovation team in 2019 to modernize its data infrastructure and take advantage of new opportunities in analytics and data science. The Data and Innovation team is cross-functional; composed of data architects, data engineers, data analysts, software developers, integration specialists and engineers. The team focuses on the delivery of value using digital innovation, such as the modernization of data management strategy and platforms, the rapid delivery of data-driven applications, the design and implementation of advanced analytics and machine learning models and the execution of robotic process automation to eliminate manual tasks.
The substantial growth of our Advanced Automation Program has increased the number of manual processes we have automated, allowing our subject matter experts to spend more time on higher-value opportunities. With industry leaders in automation, TransAlta is able to leverage high impact technology to quickly develop custom robotic process automations across the company.

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Drones
In 2022, TransAlta formed the Robotics Inspection Council. The Council's purpose is to coordinate and assess the use of drones for robotic inspections to increase value to the business through improved safety, reduced inspection costs and better communication. In alignment with TransAlta’s core value of safety, the Council defined the corporate requirements on the safe use of remotely piloted aircraft in TransAlta's fleet. In 2023, drone technology was
used in TransAlta's gas and hydro fleets to inspect boiler internal components, canals and cooling ponds, and a “drone in a box” solution was trialed and purchased for improved site security. The Council continues to meet with vendors and industry peers to understand areas of opportunity and how these technologies are being deployed. Robotic inspections were performed in TransAlta’s gas and hydro fleets. The Council is investigating additional applications in our fleet for 2024.
Engaging with Our Stakeholders to Create Positive Relationships
We strive to create shared value for our stakeholders through social and relationship value creation at TransAlta. The most material impacts on our social and relationship performance are fostering positive relationships with Indigenous neighbours, communities, stakeholders, governments, industry and landowners in the areas where we operate, as well as public health and safety. This section covers sustainability factors of social and relationship capital and intellectual capital as per guidance from the International Integrated Reporting Framework.
Inclusive Transition
In support of our energy transition, since 2015, TransAlta has been investing US$55 million over 10 years to support energy efficiency, economic and community development and education and retraining initiatives in Washington State. The investment is part of the TransAlta Energy Transition Bill passed in 2011. This bill was a historic agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State by closing the Centralia facility’s two units, one in 2020 and the other in 2025. Three funding boards were formed to invest the US$55 million: the Weatherization Board (US$10 million), the Economic and Community Development Board (US$20 million), and the Energy Technology Board (US$25 million). To date, the Weatherization Board has invested US$9.5 million, the Economic and Community Development Board US$15 million and the Energy Technology Board US$15 million.
Specific projects that the boards funded in 2023 include: the replacement of a diesel bus with a new electric bus by the Skamania School District; the installation of a 100 kW roof mounted solar system at Palouse High School by the Palouse School District; the installation of a 100kW ground mounted solar system at the Wastewater Treatment Plant owned by the City of Medical Lake; and pre-employment training services for youth in Lewis County by Morningside Services.
Additionally, in 2016, TransAlta announced that we had reached an agreement with the Government of Alberta for the cessation of emissions from coal-fired electricity generation facilities in Alberta (Off-Coal Agreement). As part of the Off-Coal Agreement, TransAlta has invested in programs and initiatives to support the communities surrounding the plants negatively impacted by the phase-out of coal generation during the transition.
Customers
TransAlta serves industrial and commercial customers with power and energy services across its fleet in Canada, the US and Australia. We are focused on customer-centred renewables growth to bring high levels of service quality and reliability for our customers in a low-carbon future. As one of the largest electricity generators in Canada, our team serves businesses with:
•Energy solutions starting from the design phase;
•Energy consumption and cost management solutions;
•Market price risk and volume exposure mitigation; and
•Monitoring of energy market design changes, price signals and applicable and available incentives.
The Customer Solutions team at TransAlta has maintained a large portfolio of customers in Alberta across a broad range of industry segments, including commercial real estate, municipal, manufacturing, industrial, hospitality, finance and oil and gas. Our work has been recognized by our customers through an average retention rate of 89 per cent over the last three years.
Across our business in Canada, the US and Australia, we provide on-site generation for large mining and industrial customers. This requires us to continually engage with these customers, ensuring that current electricity requirements are provided safely, reliably and cost-effectively with the benefit of lower GHG emissions. We continue to explore opportunities to provide 24/7 carbon-free energy to help customers meet their decarbonization goals.

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We continue to develop renewable energy facilities to support customers achieving their sustainability goals and targets, such as 100 per cent renewable power targets and/or GHG emissions reduction targets. Production
from renewable electricity in 2023 resulted in the avoidance of approximately 2.3 million tonnes of CO 2 e for our customers.
Our experience in developing and operating power facilities is highlighted below:

Power generation type | Operating experience (years)
Hydro | 112 |
Natural Gas | 73 |
Wind | 26 |
Solar | 9 |
Battery Energy Storage Systems | 3 |

For further details on how we support our customers' sustainability objectives, please refer to the Enabling Innovation and Technology Adoption section of this MD&A.
Human Rights
TransAlta is committed to honouring domestic and internationally accepted labour standards and supports the protection of human rights of all its employees, contractors, suppliers, partners, Indigenous partners and other stakeholders. We abide by human rights and modern slavery legislation in Canada, the US and Australia. We have a zero tolerance approach to discrimination based on age, disability, gender, race, religion, colour, national origin, political affiliation or veteran’s status or any other prohibited ground as defined by human rights legislation in the jurisdictions in which we operate. We afford equal opportunities for all gender identities, support the right to freedom of association and the right to organize unions and bargain collectively. We do not conduct operational human rights reviews or impact assessments, but we have governance practices in place for the protection of human rights.
Our Human Rights and Discrimination Policy outlines our commitment to human rights in our operations and supply chain to ensure that our personnel policies and practices in our global operations respect fundamental rights. Expected behaviours of all our employees are set out in our Corporate Code of Conduct. We are committed to creating a work environment where all workers feel safe and are valued for the diversity they bring to our business. Our annual mandatory Code of Conduct training is required for employees prior to signing off the Code of Conduct. In 2023, 100 per cent of employees completed the training and acknowledged and signed the Code of Conduct. We also have adopted a Supplier Code of Conduct that defines the principles and standards expected of suppliers, their employees and contractors to meet while providing goods and/or services to TransAlta.
Our Whistleblower Policy provides a mechanism for our employees, officers, directors and contractors to report,
among other things, any actual or suspected ethical or legal violations. We would seek to remedy the impact promptly in order to establish a corrective action plan in collaboration with the relevant individuals and stakeholders.
In Australia, since 2020, we have reported under federal modern slavery legislation. Our Modern Slavery Act Statements demonstrate the actions we have taken to assess and address modern slavery risks within our operations and supply chain. These annual statements are approved by our Board of Directors and are publicly available. In 2024, we will report under Canada’s Fighting Against Forced Labour and Child Labour in Supply Chains Act.
Supply Chain and Sustainable Sourcing
We continue to seek solutions to advance supply chain sustainability. As we explore major projects, we assess vendors both at the evaluation stage and as part of information requests on such elements as safe work practices, environmental practices and Indigenous spend. This means, for example and for select procurement engagements, getting information on:
•Estimated value of services that will be procured though local Indigenous businesses;
•Estimated number of local Indigenous persons that will be employed;
•Understanding overall community spend and engagement; and
•Understanding the state of community relations through interview processes and stakeholder work.
Supply chain is a pillar of our Clean Electricity Growth Plan to deliver net-zero operations. We have enhanced the supplier management functionality within our corporate

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procurement system and are working to incorporate ESG data reporting capability. In the next few years, we will develop ESG criteria for supply chain engagement and work to understand our direct suppliers' GHG emissions profile and targets. Our long-term plan is to engage with suppliers to explore enhancement of their GHG emissions targets and set direction for engaging suppliers with GHG emissions reduction targets.
In 2022, TransAlta approved a new goal to integrate sustainability into supply chain. Our target is "By 2024, 80 per cent of our spend will be with suppliers that have a sustainability policy or commitment". This supports the intent of the UN SDG Target 12.7: “Promote public procurement practices that are sustainable, in accordance with national policies and priorities.” In 2023, we confirmed that on average 78 per cent of our spend in 2022 and 2023 was with suppliers that have a sustainability policy or commitment. TransAlta will continue to consider other targets to help integrate sustainability into supply chain.
Our Supplier Code of Conduct applies to all vendors and suppliers of TransAlta. Under this code, suppliers of goods and services to TransAlta are required to adhere to our core values, including health and safety, ethical business conduct and environmental leadership. The code also allows suppliers to report ethical or legal concerns via TransAlta’s Ethics Helpline.
Indigenous Relationships and Partnerships
At TransAlta, we value relationships and partnerships with our Indigenous neighbours, aspiring to the highest standards in our relationships with Indigenous peoples. Our core values of safety, innovation, sustainability, respect and integrity represent how we do business and engage with Indigenous peoples. Our commitment to Indigenous relations is led by a centralized corporate team who foster a relationship-based approach, involving employees at our facilities and within each business unit. These employees and teams build relationships with the neighbouring Indigenous communities and work to develop respectful, trusting relationships that help TransAlta continually improve its business practices.
Our Indigenous Relations Policy focuses on five key areas: community engagement and consultation, business development, community investment, employment, and training and awareness. We ensure that TransAlta’s principles for engagement are upheld and the Company fulfils its commitments to Indigenous communities. Efforts are focused on building and maintaining solid relationships and strong communication channels that enable TransAlta to: share information regarding operations and growth initiatives; gather feedback to inform project planning; and understand priorities and interests from communities to better address concerns and unlock opportunities.
Methods of engagement include:
•Relationship building through regular communication and meetings with representatives at various levels within Indigenous communities and organizations;
•Hosting company-community activities to share both business information and cultural knowledge;
•Maintaining consistent communications with each community and following appropriate community protocols and procedures;
•Participating in community events such as pow wows and blessing ceremonies; and
•Providing both monetary and in-kind sponsorships for community initiatives.
TransAlta takes a proactive approach in engagement by initiating communication early in project development to allow concerns to be identified and addressed, which has minimized potential project delays. We strive to maintain relationships through the life cycle of our facilities, from project development and construction, through operation, until decommissioning phases are complete. We work with communities to build relationships based on a foundation of ongoing communication and mutual respect. This is recognized in our Indigenous Relations Policy, which was recently updated to include our acknowledgement and understanding of the intent of the recommendations of the United Nations Declaration on the Rights of Indigenous Peoples.
In 2024, TransAlta will continue to ensure that all new employees complete Indigenous cultural awareness training as part of the Company’s onboarding process.
Support for Indigenous Youth, Education and Employment
TransAlta recognizes the importance of investing in Indigenous students and our financial support helps students complete their education, become self-sufficient and move forward to become future leaders in their communities. We are keen to help young Indigenous students reach their full potential and achieve their dreams. We also believe in providing support to Indigenous primary school students, helping to instill a passion for lifelong learning.
In 2023, TransAlta provided more than $453,000 to support Indigenous youth, education and employment programs, representing 14 per cent of TransAlta’s total community investment. Highlights include:
•Mother Earth's Children's Charter School ("MECCS") – Located in Treaty 6 territory, Alberta, MECCS offers education for students from kindergarten to Grade 9 and is cited as Canada’s first and only Indigenous children’s charter school. The student population is diverse and includes Métis, Cree, Nakoda Sioux and Stoney. MECCS is a tuition-free public school integrating Indigenous

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culture, beliefs and perspectives into elementary school experience. The school specializes in working with children suffering from adversity and provides enhanced learning support. MECCS students have a high success rate for completing high school and winning academic awards. In 2023, TransAlta provided $35,000 to support the school’s operations plus a holiday donation to enable a student celebration.
•The Read On Literacy Program ("Read On") – In 2023, TransAlta partnered with Read On to provide elementary students in communities near our operations with in-person and virtual sessions. Read On is an Indigenous literacy program that seeks to mentor young people in First Nation schools to achieve their maximum academic, personal and social development by promoting the core values of education, literacy, taking pride in ones’ culture and making good decisions in one’s life.
•Diamond Willow Youth Lodge – In partnership with the United Way of Calgary and Area, designated funding was provided to the Diamond Willow Youth Lodge, which is a safe place for Calgary Indigenous youth to connect with peers and participate in a variety of programs that promote health and wellness, education and employment preparation.
•Wihnemne School Hot Lunch Program – In 2023, TransAlta partnered with the community school at Paul First Nation in Alberta on a program designed to ensure the Nation’s children receive nutritious meals each day maximizing their scholastic success. This program is cited as a catalyst responsible for strong growth in the school's enrollment.
Indigenous Cultural Awareness Training for TransAlta Employees
In November 2023, TransAlta successfully reached 100 per cent completion of the Indigenous Cultural Awareness Training program across our operating jurisdictions in Canada, the US and Australia. In line with our sustainability target set in 2021, the Company made a deliberate effort to ensure that every employee participated in Indigenous Cultural Awareness training over the past two years. This initiative has been instrumental in providing valuable insights into the rich history, culture and perspectives of Indigenous communities within the jurisdictions where we operate.
Stakeholder Relationships
Fostering positive relationships with our stakeholders is important to TransAlta. Driven by our core values, we see stakeholder transparency as an integral part of our relationships. We take a proactive approach to building relationships and understanding the impacts our business and operations may have on local stakeholders.
Our Stakeholders
To act in the best interests of the Company and optimize the balance between financial, environmental and social values of our stakeholders and TransAlta, we seek to:
•Build relationships through regular engagement with stakeholders regarding our operations, growth prospects and future developments;
•Consider feedback and make changes to project designs and plans to resolve and/or accommodate concerns expressed by our stakeholders; and
•Respond in a timely and professional manner to stakeholder inquiries and concerns and work diligently to resolve issues or complaints.
Our stakeholders are identified through stakeholder mapping exercises and prospective project development or acquisition. Through decades of establishing stakeholder relationships in the areas of our facilities, we have developed a strong knowledge of who our stakeholders are and have gained understanding of our stakeholders' issues and concerns.
Our principal stakeholder groups are listed in the following table.

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TransAlta stakeholders
Non-governmental organizations | Community associations | Transmission facility operators
Regulators | Industry organizations | Communities
Charitable organizations/Non-profit | Standards organizations | Retirees
All levels of government | Media | Residents/Landowners
Suppliers | Business partners | Investor organizations
Contractors | Unions/Labour organizations | Financial institutions
Government agencies | Forest associations/Industry | Mineral rights owners
System operators | Oil and gas associations/Industry | Railroad owners
Customers | Think tanks | Utility owners
Shareholders | Academics | Employees

Stakeholder Engagement
In order to run our business successfully, we maintain open communication channels with our stakeholders. We are committed to timely and professional resolution in our dialogue with stakeholders.
Our stakeholder engagement practices are guided by regulatory requirements, industry best practices, international standards and corporate policies. We work internally and externally with each stakeholder to identify and mitigate further issues.
Examples of our methods of engagement are listed in the following table.

Information and communication | Dialogue and consultation | Relationship building
Open houses, town halls and public information sessions | In-person meetings with local groups and communities | Community advisory bodies
Newsletters, telephone conversations, emails and letters | Meetings with individual stakeholders (e.g., landowners and residents) | Capacity agreements
Websites | Targeted audience sessions | Sponsorships and donations
Social media postings | Tours of our facilities and sites | Hosting and attending events

A key focus of our work is to support business growth through proactive engagement with stakeholders in our geographic operating areas in Canada, the US and Australia to develop and maintain relationships, assess needs and fit and seek out collaborative opportunities. This helps ensure any stakeholder concerns are identified and can be addressed early in the development process, thereby minimizing project delays. We conduct consultation primarily during project development and construction phase and maintain engaged communication throughout operations to decommissioning phase.
Examples of stakeholder engagement in 2023 include: the Pinnacle project 1 and 2 open houses, SunHills Solar project open house, two Riplinger project open houses and ongoing engagement on the Kent Hills rehabilitation plan.
Community Investments
In 2023, TransAlta contributed approximately $3.2 million in donations and sponsorships (2022 – $2.3 million), with a continued focus in three priority areas: youth and
education, environmental leadership and community health and wellness.
One of our significant community investments each year is to United Way campaigns across Canada and the US. This year, TransAlta employees, retirees, contractors and the Company raised over $1.5 million for the United Way.
In 2023, TransAlta made a number of other significant investments, including the following highlights:
•Community Shelters – In 2023, TransAlta donated $40,000 to local shelters near our operating assets in Canada, US and Australia. This initiative recognizes the unprecedented need for employment services, families experiencing poverty and escaping violence and abuse.
•New Operation Support – In 2023, TransAlta donated $50,000 to local communities surrounding our new White Rock, Horizon Hill and Garden Plain operations. These initiatives recognize our commitment to supporting the communities in which we operate. Funding was designated to the local school libraries, school repairs and a local fire station.

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•Centralia Coal Facility – Since 2012, TransAlta has maintained its commitment to invest US$55 million in the state of Washington and made the final annual payment in December 2023. Funds from this investment have been managed by the Centralia Coal Transition Board to support local community sponsorships including investments in the arts, colleges, energy technology, weatherization upgrades and supporting displaced workers with education and retraining opportunities. This completes a significant commitment for the transition of the Centralia coal facility.
Public Health and Safety
We are committed to protecting the public and our assets, as well as the physical, psychological and social well-being of our employees.
We specifically look to minimize the following risks:
•Harm to people;
•Damage to property;
•Operational liability; and
•Loss of organizational reputation and integrity.
We work to prevent incidents and lower our risk by administering security controls such as restricting physical access around and into our operating facilities. The use of security technology such as surveillance cameras and electronic access is utilized to ensure the control of secure areas. Regular audits and security risk assessments are conducted to ensure continuous improvement of the Security Management Program. Our Security Management Program is focused on the protection of people, property, information and reputation.
The Corporate Emergency Management Program prepares employees should an emergency incident occur. The program receives executive sponsorship and includes an emergency management policy and standard, which sets an expectation for employees to continuously prepare for emergencies. It provides the overarching framework for each business unit to provide an Emergency Response Plan and Business Continuity Plan. We implement our Incident Command System, which is a standardized on-scene emergency and incident management system that provides an organizational structure capable of responding to single or multiple incidents. Designed to aid in the management of resources during incidents, it combines facilities, equipment, personnel, procedures and communications operating within a common organizational structure. It is used as part of an all-hazards approach for incident management and is officially recognized for multi-agency response in emergency situations, however complex the incident might be.
We develop strong relationships with local emergency responders. We periodically conduct multi-agency training events at our facilities. This ensures continuous
improvement and familiarity with our assets and builds strong communication channels for emergency response.
Our processes designate how we communicate with stakeholders in the event of a crisis. This is managed by our Crisis Communications Team. The team has the responsibility and goal to provide a unified message on behalf of the Company throughout the response and recovery, ensure all messaging is approved by the Incident Commander, co-ordinate messaging with any applicable external agencies and, if necessary, deploy to an incident site.
Annual training, exercise and drill requirements are adhered to by our employees operating at our facilities. The results are tracked, audited and presented at our annual executive review. The findings and recommendations assist in maintaining an effective program across the organization.
Data and Digital Asset Protection
We work diligently to protect our digital assets, including our corporate data and our digital identities that provide access into line of business applications. Cybersecurity threats that compromise these assets include the manipulation of data integrity, system and network hacking, use of social engineering tactics through email phishing and compromise of operations and infrastructure through the use of ransomware, credential breaches and attacks introduced through unknowing third-party vendors and service providers.
Given the ever-evolving nature of cyberattacks, we are consistently adapting our cybersecurity program to focus on three key pillars: technology, processes and people. Each of these pillars can be reinforced independently to address specific cybersecurity risks and threats through a comprehensive and multi-faceted program. TransAlta continually assesses our cyber threat level, implementing measures and controls to proactively mitigate internal and external cybersecurity risks and threats posed to the organization.
TransAlta’s Cybersecurity Policy defines how we identify and manage cybersecurity risks and threats, as well as how we detect, respond, and recover from cybersecurity incidents. We comply with the North American Electric Reliability Corporation Critical Infrastructure Protection ("NERC CIP") requirements where applicable. The NERC CIP is a set of standards aimed at regulating, enforcing, monitoring and managing the security of the North American power system. These compliance standards apply specifically to address cybersecurity risks.
In 2023, there were no identified cybersecurity breaches to our technology environment. Refer to Cybersecurity Risk in the Governance and Risk Management section of this MD&A for further details.

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Building a Diverse and Inclusive Workforce
Engaging our workforce, developing our employees, creating an equitable, diverse and inclusive work environment and minimizing safety incidents are the keys to human capital value creation at TransAlta and our most material areas for management. In 2023, we enhanced our ESG performance through our efforts to promote an equitable, diverse and inclusive workforce. This section covers sustainability factors of human capital as per guidance from the International Integrated Reporting Framework.
Equity, Diversity and Inclusion
TransAlta’s commitment and focus on excellence in equity, diversity and inclusion ("ED&I") is found in our workplace and among our co-workers who advocate for the values of equity and inclusion at all working levels. This commitment is outlined in our Board and Workforce Diversity Policy and Diversity and Inclusion Pledge. We believe a strong focus on ED&I will create a culture of belonging, allowing our employees to bring their authentic selves to work where they can thrive, innovate, improve service to our customers and positively impact the communities that we live in.
In 2023, TransAlta executed the third year of our five-year ED&I strategy to achieve the goals and aspirations defined in our ED&I Pledge.
Gender Diversity
A number of case studies have highlighted the link between gender diversity and additional business value. TransAlta is an active supporter of gender diversity as a driver for value, but also as an ethical business practice. Our commitment to gender diversity in our business is evidenced by our female participation rates on both our executive team and Board. As of Dec. 31, 2023, women made up 26 per cent of our executive team and 46 per cent of our Board. These percentages are higher than the Canadian corporate averages of board seats held by women (29 per cent) and women on executive teams (21 per cent), according to data from all disclosing Canadian TSX-listed companies in Canada.
To further support female advancement, we have set targets to: (i) maintain equal pay for women in equivalent roles, (ii) achieve 50 per cent representation of women on our Board by 2030 and (iii) achieve 40 per cent representation of women among all employees by 2030. Currently, women employees represent 27 per cent of all employees. Though the majority of our operational roles are currently held by male employees, we remain committed to achieving the 40 per cent goal in this time period.
In 2023, we continued with the Women in Trades Scholarship that provides eligible students enrolled in post-secondary trade programs with financial support. In 2023, we also continued with a female apprenticeship program in
our Generation business to strategically target the recruitment of female students and train them to gain valuable experiential learning in the trades.
Workforce Health and Safety
The safety of our people, communities and the environment is one of our core values. Our focus on Operational Excellence puts into action TransAlta’s value of enabling a safe environment for our people and our communities. Operational Excellence is about powering and empowering our communities in a safe, environmentally-friendly and sustainable manner by ensuring our assets operate reliably and efficiently.
TransAlta's management systems underpin the delivery of safe, reliable and competitive electricity to our customers and partners. Our Total Safety Management System is a combination of recognized best practices in process safety, risk management, asset management, occupational health, safety and environmental management. Since expanding our Occupational Health and Safety program in 2015 to encompass Total Safety, we have transitioned from the development and implementation of this framework into continuous improvement, always striving to achieve our Target Zero vision to operate our business with zero unexpected asset failures and zero environmental, health and safety incidents.
We made significant progress on our safety culture transformation journey. Training and development initiatives were a top priority in which we completed behaviour-based safety training for all employees.
This training provides the tools and strategies to allow employees to influence their individual behaviours and encourage personal ownership over safety outcomes. It helps create a psychologically safe environment in our workplace as it encourages personal accountability towards safety.
In 2023, our strong safety performance has been supported by our strategic areas of focus: maturing our safety culture, understanding risk tolerance and standardization of safety information and systems. To support our safety cultural growth, new employees and leaders completed training modules designed to gain tools to understand their role in setting, building, and maintaining our safety culture. Through peer board sessions designed to embed an understanding of risk perception, risk tolerance and psychological safety, leaders held over 100 sessions across the fleet.
One of our key safety indicator is the TRIF, which tracks the number of injury incidents that require treatment beyond first aid, relative to total exposure hours worked. Our TRIF result for 2023 was 0.30 compared to 0.39 in 2022.

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The following represents our corporate safety performance and includes employees and contractors:

Year ended Dec. 31 | 2023 | 2022 | 2021
Lost-time injuries | 1 | 0 |  | 3 |
Medical aids | 4 | 6 |  | 9 |
Restricted work injuries | 0 | 0 |  | 5 |
Exposure hours | 3,362,000 | 3,058,000 |  | 4,134,000 |
Total Recordable Injury Frequency (TRIF) | 0.30 | 0.39 |  | 0.82 |

We focus on leading indicators and participation through Total Safety Reports (hazard, near miss, positive observations, and cybersecurity reports). Total Safety Report Frequency demonstrates the proactive activities, per worker per year, we are taking to identify and prevent an injury or loss from occurring. We also report and recognize positive behaviours in the workplace to enhance psychological safety. This allows us to not only respond to incidents if they occur but find opportunities to strengthen barriers and layers of protection to mitigate potential incidents. In 2023, we recorded 12.5 reports per worker, which is above our target of 12. Evidence of the positive impacts associated with strong engagement and a maturing safety culture is apparent in TransAlta's overall safety performance. In 2023, TransAlta was selected by Canada’s Safest Employers to receive a Utilities and Electrical Employer Excellence Award. TransAlta was also recognized as the employer with the Best Wellness Program across all industries, excelling in the promotion and protection of employee overall wellness.
Organizational Culture and Structure
Our employees are central to value creation. Our corporate culture has evolved and adapted throughout our 112-year history. Our values are safety, innovation, sustainability, respect and integrity. These five values help provide clarity for our employees and guide our behaviour and decision-making. They also provide a foundation for leadership, collaboration, community support, personal growth and work-life balance. Through corporate initiatives and support throughout all levels of leadership, we encourage our employees to maximize their potential.
Culture Transformation
In 2022, we embarked on our culture transformation journey with the goal of becoming a culture of results, purpose and learning. We developed a three-year culture strategy, Culture Charter and Culture Roadmap that defines milestones. For alignment and transparency, all of these documents are available to our employees. Part of our culture transformation involves improving employee psychological safety in order to increase employees to speak up with a view to increase innovation, creativity and ultimately, results.
We conduct annual Employee Engagement Surveys to gauge the employee experience, and based on survey results, leaders created action plans to drive improvement and increase engagement at the business unit and team level.
Finally, we are focused on improving employee health and well-being. To increase awareness, we have launched education sessions on a variety of topics such as mental health, women’s health, men’s health, nutrition, resiliency, etc.
Organizational Structure
As of Dec. 31, 2023, we had 1,257 (2022 – 1,222) active employees. This number increased by one per cent from 2022 levels. With approximately 30 per cent of our employees being unionized, we strive to maintain open and positive relationships with union representatives and regularly meet to exchange information, listen to concerns and share ideas that further our mutual objectives. Collective bargaining is conducted in good faith and we respect the rights of employees to participate in collective bargaining.
Our organizational structure changed in 2023. Our business continues to operate four generating segments, with Gas, Wind and Solar, Hydro and Energy Transition, with support from our Corporate and Growth Business Units. Our operations portfolio is run by a single leadership team, which provides operational and financial synergies, thus enhancing our competitiveness.

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Employee Retention and Recognition
ESG-Linked Compensation
At TransAlta, we have linked our ESG performance to our employees’ compensation including that of our executive leadership team. Our annual and long-term incentive pay for performance plans are linked to TransAlta achieving various ESG goals, where the targets and metrics are reviewed and approved annually by our Board of Directors and further outlined in our annual compensation plans.
In 2023, 20 per cent of our annual incentive plan was linked to achieving specific ESG targets: 10 per cent referred to our organizational culture improvements and 10 per cent was linked to safety. Further, 30 per cent of our annual incentive plan was tied to growth, which is focused on expanding TransAlta’s portfolio of renewable generation and will help reduce the Company’s overall GHG emissions intensity. Our long-term incentive plans include strategic goals related to our focus on clean electricity, strong renewables growth, leading in ESG policy development, delivering on our culture plan and our ED&I strategy. Refer to the Management Proxy Circular for additional details on our ESG related compensation.
Employee Performance and Recognition
Coaching, feedback and management are fundamental to our performance philosophy, with leaders and employees being asked to participate in regular meetings to discuss work progress, professional and career development throughout the year.
We strive to be an employer of choice through our HR and total rewards programs, which include pay-for performance incentive plans, as reviewed and approved by the Board of Directors. TransAlta’s annual and long-term incentive plans are designed to measure and recognize employees’ contributions towards metrics and targets. In order to motivate and engage employees in a timely manner, we continue to utilize employee recognition programs, including a quarterly recognition program and a peer-to-peer recognition program.
Talent Development
TransAlta places significant focus on talent development and retention of its employees. Annually, employees complete a combination of optional, mandatory and customized training as part of their roles. All employees have access to learning sessions from speakers who are experts on topics as varied as psychological safety, ED&I, mental and physical health, culture, financial wellness, core skills and leadership development.

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Progressive Environmental Stewardship
We continue to increase financial value from natural or environmental capital-related business activities, while minimizing our environmental footprint and potential risk factors related to environmental impacts. This section covers natural capital management as per guidance from the International Integrated Reporting Framework.
Environmental Strategy
All energy sources used to generate electricity have impact on the environment. While we are pursuing a business strategy that includes investing in renewable energy resources such as wind, hydro and solar, we also believe that natural gas will continue to play an important role in meeting energy needs during our clean electricity transition. Our environmental management processes support our corporate strategy of ceasing GHG-intensive coal operations. In 2026, our generation mix will be made up of natural gas and renewable energy only.
Reducing the environmental impact of our activities benefits not only our operations and financial results, but also the communities in which we operate. We have a proactive approach to minimizing environmental risks and we anticipate this strategy will benefit our competitive position as stakeholders and society at large place an increasing emphasis on successful environmental management. Our Environmental Policy defines how we are integrating the protection of nature and the environment within TransAlta’s strategy, our Total Safety Management System, as well as the principles of conduct for the management of natural resources.
Environmental Management System
At TransAlta, we operate our facilities in line with best practices related to environmental management standards. Our environmental management processes are verified annually to ensure we continuously improve our environmental performance. Our knowledge of environmental management systems ("EMS") has matured since we aligned our processes in accordance with the internationally recognized ISO 14001 EMS standard. Currently, the most material natural or environmental
capital impacts to our business are GHG emissions, air emissions (i.e., pollutants) and energy use. Other material impacts that we manage and track performance on via our environmental management practices include land use, water use and waste management.
In addition to our environmental management practices, we are subject to environmental laws and regulations that affect aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of waste and hazardous substances. The Company’s activities have the potential to damage natural habitat, impact vegetation and wildlife, or cause contamination to land or water that may require remediation under applicable laws and regulations. These laws and regulations require us to obtain and comply with a variety of environmental registrations, licenses, permits and other approvals. The environmental regulations in the jurisdictions in which we operate are robust. Both public officials and private individuals may seek to enforce environmental laws and regulations against the Company. We interact with a number of regulators on an ongoing basis.
Environmental Performance
Our performance on managing environmental aspects, reducing our environmental impact and capitalizing on environmental initiatives includes the following:
Biodiversity
The importance of environmental protection and biodiversity is outlined in our Environmental Policy as a corporate responsibility for TransAlta and a responsibility of each employee and contractor working on TransAlta's behalf. In 2022, the Company adopted the target to "achieve zero biodiversity-related incidents". This means zero biodiversity-related incidents that affected habitats and species included on the Red List of the International Union for Conservation of Nature ("IUCN") from near-threatened to critically endangered.
The following represents our biodiversity incidents in accordance with the IUCN Red List classification:

Year ended Dec. 31 | 2023 | 2022 | 2021
Critically Endangered | 0 |  | 0 |  | 0 |
Endangered | 0 |  | 0 |  | 0 |
Vulnerable | 0 |  | 0 |  | 0 |
Near threatened | 0 |  | 0 |  | 0 |
Total biodiversity-related incidents | 0 |  | 0 |  | 0 |

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Overseeing Biodiversity-Related Issues
TransAlta's GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Company’s monitoring of environmental regulations, public policy changes and the development of strategies, policies and practices for the environment. For further information, refer to the Sustainability Governance section of this MD&A.
Assessing Biodiversity Impacts of Our Value Chain
We consider the biodiversity impact at all of our existing operations and the biodiversity impacts of all new growth projects are evaluated in line with regulatory compliance and with respect to TransAlta's focus on biodiversity health. Details on how we assess biodiversity impacts of our value chain are presented in the sections below.
Growth
Each new TransAlta development project must complete an in-depth environmental assessment (as prescribed by the local regulation and in line with our own assessment practices) describing baseline environmental conditions, identifying potential effects and developing mitigation strategies for identified environmental sensitivities prior to construction and operation. These assessments have been specifically designed to meet the environmental information requirements of the respective regions in which we operate while identifying alignment with the intent of the standards and/or regulations applicable to these jurisdictions. Typically, our renewable projects are greenfield development projects that require a higher level of evaluation compared to our gas projects, which primarily integrate into existing industrial facilities.
In addition, each greenfield development project has a detailed community engagement plan designed to ensure all potentially impacted host landowners, stakeholders, agencies, businesses, non-governmental organizations ("NGOs"), environmental NGOs and Indigenous communities understand the nature of the projects, have multiple and varied opportunities for engagement and feedback and are able to engage in meaningful dialogue and discussion with TransAlta and its representatives. The ultimate goal is addressing, resolving and mitigating stakeholder or Indigenous community concerns before filing major permit applications for all of our projects.
Day-to-day Operations
At our Alberta operations, in 2023, we continued with our Wildlife Monitoring Program designed to monitor wildlife abundance and species diversity in the study area over time. Based on these surveys, TransAlta has seen primarily stable or increasing biodiversity in the area, with various new bird species being detected over the years and incidents of vehicle collisions decreasing due to lower speed limit restrictions. Some animal population sizes fluctuate in the area based on weather conditions and available ground cover.
Our natural gas operations have a relatively limited impact on biodiversity. The facilities are frequently constructed adjacent to existing industrial operations and TransAlta may not always be the holder of the environmental permits. The land area these facilities occupy is also generally relatively small. One exception is our Sarnia cogeneration facility. This facility is made up of 260 acres of brownfield industrial land, some of which contains areas with tall grasses and potential wildlife. Care will be taken at the time of redevelopment of this land to minimize impact to species-at-risk through the completion of species-at-risk surveys as well as performing certain construction activities outside of nesting periods. For all sites that are under our environmental scope, we adhere to all relevant environmental compliance permits.
At our hydro facilities, a major focus is on reducing the impact on fish and its habitat. We adhere to provincial and federal regulations and operate in accordance with facility approvals. We continue to work toward operational improvement and regularly review our Environmental Operational Management Plans to ensure our operating parameters are met.
At our wind and solar operations, an Operational Environmental Management Plan has been developed for each asset to ensure that our facilities use environmentally-sound and responsible practices that are based on a philosophy of continuous improvement of environmental protection. Examples of environmental initiatives to support our biodiversity focus include our bird and bat protection practices (installation of covers to protect birds from possible electrocution), a bird and bat mortality database (records all injuries and mortalities), environmentally-sensitive resource monitoring (monitoring sensitive wildlife features in and around our operating wind facilities), and long-term dataset collections (e.g., wildlife studies pre-construction and post-construction). In addition, we continue to collaborate with industry and the scientific community to address environmental concerns and impacts pertaining to biodiversity.
At our Centralia operations, in 2023, we completed a riparian reforestation plan for under-forested areas along the Skookumchuck River within our Skookumchuck Wildlife Habitat Management Area. We planted 15,620 trees along both sides of the river to maintain the river banks and decrease erosion, and we completed a vigorous weed control program to control the proliferation of invasive species; thus, improving overall habitat health. Additionally, we harvested approximately 97,300 board feet of timber consisting of diseased Red Alder and Douglas Fir to allow for the growth of healthy trees as part of our overall wildlife habit management program.
Energy Use
TransAlta uses energy in a number of different ways. We burn natural gas, diesel and coal (to the end of 2025 at

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Centralia) to generate electricity. We harness the kinetic energy of water and wind to generate electricity. We also generate electricity from the sun. In addition to combustion of fuel sources, we also track combustion of gasoline and diesel in our vehicles and the electricity use and fuel use for heating (such as natural gas) in the buildings we
occupy. Knowledge of how much energy we use allows us to optimize and create energy efficiencies. As an electricity generator, we continually and consistently look for ways to optimize and create efficiencies related to the use of energy.
The following captures our energy use (million gigajoules). Energy use increased by one (1) per cent in 2023 over 2022. Some values do not sum to the indicated total due to rounding. Zeros (0) indicate truncated values:

Year ended Dec. 31 | 2023 | 2022 | 2021
Hydro | 0 | 0 |  | 0 |
Wind and Solar | 0 | 0 |  | 0 |
Gas | 123 | 130 |  | 118 |
Energy Transition | 73 | 64 |  | 86 |
Corporate and Energy Marketing | 0 | 0 |  | 0 |
Total energy use (million gigajoules) | 197 | 195 |  | 204 |

Air Emissions
Our one remaining coal facility emits air emissions that we track, analyze and report to regulatory bodies. We also work on mitigation solutions depending on the type of air emission. We report our major air emissions from coal, which includes NO x, SO 2, particulate matter and mercury. We continue reducing air emissions in our existing facilities through our conversion and retirement of coal units in Alberta (completed in 2021) and Washington State (planned completion by the end of 2025).
In 2022, we achieved our 2026 target of 95 per cent SO 2 and 80 per cent NO x emissions reductions over 2005 levels. Since 2005, we have reduced SO 2 emissions by 98 per cent and NO x by 83 per cent. In 2024, we will continue to review setting new environmental targets for air emissions.
None of our previous Alberta coal facilities are located within 50 kilometres of dense or urban populations and they all have been retired or converted to gas as of 2021. Our Centralia thermal facility in Washington State is located 40 kilometres from a dense or urban population. As per guidance from SASB, “a facility is considered to be located near an area of dense population if it is located within 49 kilometres of an area of dense population” (being deemed to be a "minimum population of 50,000 persons"). In 2023, the Centralia thermal facility accounted for 35 per cent of total NO x, 99 per cent of total SO 2, 30 per cent of total
particulate matter and 76 per cent of total mercury. The facility has two units and we retired one unit in 2020 and will retire the additional unit by the end of 2025, at which time air emissions from our coal facilities will be eliminated.
Our gas facilities emit sufficient levels of NO x that trigger reporting obligations to national regulatory bodies. These gas facilities also produce trace amounts of SO 2 and particulate matter, but at levels that are deemed negligible and do not trigger any reporting requirements or compliance issues. Many of our gas facilities are located in very remote and unpopulated regions, away from dense urban areas. Our Sarnia, Windsor, Ottawa, Fort Saskatchewan and Ada gas facilities are our facilities with air emissions within 49 kilometres of dense or urban environments.
Our total air emissions in 2023 retained similar performance to 2022 levels. This is due to the completion of coal-to-gas conversions in previous years, which resulted in higher operational efficiency and reduction in air emissions. The slight increase of particulate matter is due to increased production of Centralia, which is the only remaining coal plant within our portfolio.
The following represents our material air emissions. Figures have been rounded for SO 2 (to the nearest one hundred), NO x (to the nearest one thousand), particulate matter (to the nearest ten, when possible) and mercury (to the nearest whole number):

Year ended Dec. 31 | 2023 | 2022 | 2021
SO 2 (tonnes) | 1,100 | 1,200 | 7,300
NO x (tonnes) | 11,000 | 11,000 | 15,000
Particulate matter (tonnes) | 460 | 360 | 2,200
Mercury (kilograms) | 18 |  | 21 | 41

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Water
Our principal water use is for cooling and steam generation in our coal and gas facilities, but our hydro operations also require water flow for operations. Water for coal and gas operations is withdrawn primarily from rivers where we hold permits and must therefore adhere to regulations on the quality of discharged water. The difference between withdrawal and discharge, representing consumption, is due to several factors, which include evaporation loss and steam production for customers, which we are unable to recover.
In 2022, we achieved our water consumption reduction target to reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m 3 or 40 per cent in 2026 over the 2015 baseline. Water consumption in 2015 was 45 million m 3. This target is in line with the UN
SDGs, specifically "Goal 6: Clean Water and Sanitation." In 2024, we will continue to review setting new environmental targets for water consumption.
In 2023, we withdrew approximately 273 million m 3 (2022 – 233 million m 3) and returned approximately 239 million m 3 (2022 – 207 million m 3) or 88 per cent. Overall, water consumption was approximately 34 million m 3 (2022 – 26 million m 3). Water consumption increased primarily due to an increase in production compared to last year. This is particularly observed in Centralia, our last transition-coal plant with the highest water consumption intensity.
The following represents our total water consumption (million m 3) over the last three years. Some values do not sum to the indicated total due to rounding. Figures below have been rounded to the nearest million m 3:

Year ended Dec. 31 | 2023 | 2022 | 2021
Water withdrawal | 273 |  | 233 |  | 241 |
Water discharge | 239 |  | 207 |  | 209 |
Total water consumption (million m 3) | 34 |  | 26 |  | 32 |

Water Security
Our largest water withdrawal and discharge occurs at our Sarnia gas cogeneration facility (which produces both electricity and steam for our customers). The facility operates as a once-through, non-contact cooling system for our steam turbines. Despite large withdrawals from the adjacent St. Clair River to support our Sarnia operations, we return approximately 97 per cent of the water withdrawn. Water from this source is currently at low risk as per analysis from the SASB-endorsed Aqueduct Water Risk Atlas tool.
The Aqueduct Water Risk Atlas tool highlights that water risk is high at our interior and southern Western Australia facilities due to high interannual variability in the region. Interannual variability refers to wider variations in regional water supply from year to year. Our water supply at these facilities is provided at no cost under PPAs with our mining customers, hence our risk is significantly mitigated. In addition, our customers have developed conservation and re-use strategies aimed at recycling water for mining operational needs. All water used in the region is sourced from scheme water. With respect to gas and diesel turbine water use, water wash techniques and frequency of activities are continually modified to minimize consumption and environmental impact. Water used in our operations is returned to our customers, who repurpose this water for vegetation and dust suppression in their mining operations.
At the South Hedland facility in Western Australia, water risk is also high due to the risk of flooding in the region. The South Hedland facility was built above normal flood levels to mitigate potential risk from flooding. During a
category 4 cyclone event in the area and associated flooding in the region in 2019, the South Hedland facility continued to generate power for the region. In addition, the South Hedland facility has developed a Water Efficiency Management Plan with Water Corporation WA, the principal supplier of water, wastewater and drainage services in Western Australia. Initiatives are aimed at reducing water consumption and costs through innovative technology and efficiencies identified through facility management.
Dam Safety
Our dam safety programs include all hydroelectric developments, constructed ponds and fluid retaining structures such as ash lagoons and canals, as well as associated equipment and structures and the personnel required to operate, maintain and inspect these items. They are governed through our Dam Safety Policy and Dam Safety Management System, which includes requirements on design, modification and decommissioning, operation, maintenance and surveillance, public safety, emergency management and risk management.
TransAlta’s Board and its President and CEO oversee the effectiveness of our dam safety programs and receive regular updates. In 2022, a member of the Board was designated as the Company's Dam Safety Advisor to assist the Board in fulfilling its oversight role in regard to the Company's dam safety practices given the unique and technical aspects of dam safety. In addition, TransAlta engages an external Dam Safety Review Panel to provide external review of the program and its management, including overall assessment and benchmarking against

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other national and international programs. Our monitoring programs include:
•Regular operations and engineering inspections;
•Testing of critical equipment;
•Numerous instruments in the dams monitoring water level, temperature, movement, earthquake detection;
•Use of drones and satellite remote movement monitoring;
•Emergency plans and exercises with internal and external stakeholders; and
•Regular third-party reviews that are shared with the regulators.
We work closely with local stakeholders including conservation authorities and public agencies on watershed management, emergency planning and flood response. For example, in Southern Alberta, our hydroelectric facilities have played an increasingly important water management role following the flood of 2013. In 2021, we renewed our previous agreement with the Government of Alberta for another five years to manage water on the Bow River at our Ghost Reservoir facility to aid in potential flood mitigation efforts, as well as at our Kananaskis River System (which includes the Interlakes, Pocaterra and Barrier hydroelectric plants) for drought mitigation efforts. In 2022, we started decommissioning the Keephills Ash Lagoon, a facility that is no longer needed for ash storage following the coal-to-gas conversion of Keephills Unit 2. This three-year project will reshape the existing lagoon so that it is stable for the long term and is the first step towards delicensing the structure.
TransAlta is proud of its reputation in dam safety. We participate in the Canadian Dam Association, Dam Safety Interest Group of the Centre for Energy Advancement through Technological Innovation, United States Society on Dams, Canadian Geotechnical Society, Dam Safety Advisory Committee of the Alberta Chamber of Resources and Association of State Dam Safety Officials.
For information on our corporate emergency management program, refer to Public Health and Safety in the Engaging with Our Stakeholders to Create Positive Relationships section of this MD&A.
Waste
The importance of environmental protection and waste management is outlined in our Environmental Policy as a corporate responsibility for TransAlta and its employees, and contractors working on TransAlta's behalf. Our waste data is reported annually to a number of different regulatory bodies.
In 2023, our operations generated approximately 479,000 tonnes equivalent of waste (2022 – 204,000 tonnes). Of the total waste generated, 97 per cent was non-hazardous waste and 0.2 per cent was directed to landfill (2022 – 0.9 per cent). The main reason for the increase in total waste is due to the waste reuse. Since its retirement, we have been selling ash from our Highvale and Centralia Mine, which accounts for 95 per cent of the total waste generated.
The following represents our total waste production over the last three years. Figures have been rounded to the nearest one thousand:

Year ended Dec. 31 | 2023 | 2022 | 2021
Total waste generation (tonnes equivalent) | 479,000 | 204,000 | 514,000
Waste to landfill (tonne eq.) | 1,000 | 1,900 | 1,000
Waste recycled (tonne eq.) | 19,000 | 22,000 | 31,000
Waste reuse (tonne eq.) | 457,000 | 151,000 | 176,000
% of total waste to landfill | 0.2 | 0.9 | 0.2 |
% of total waste: hazardous | 3 |  | 9 | 5 |
% hazardous waste to landfill | 0.0 | 0.6 |  | 1.0 |

Our reuse waste or byproduct waste is generally sold to third parties. Our operating teams are diligent at not only minimizing waste, but also maximizing recoverable value from waste. We have invested in equipment to capture byproducts from the combustion of coal, such as fly ash, bottom ash, gypsum and cenospheres, for subsequent sale. These non-hazardous materials add value to products like cement and asphalt, wallboard, paints and plastics.
Coal Ash Management
Given our transition off coal, we ceased producing fly ash waste in Canada at the end of 2021 and will no longer produce it past the end of 2025 in the US. In 2023, Lafarge
Canada and TransAlta entered into an agreement that will advance low-carbon concrete projects in Alberta. The project will repurpose landfilled fly ash, a waste product from TransAlta’s Highvale mine, which ceased operations in 2021. The ash will be used to replace cement in concrete manufacturing. By turning the recovered product into something marketable, it will continue to aid in reducing the amount of cement produced and consequent emissions while offering new job and economic growth opportunities. This innovative technology contributes to a circular economy and will reduce reclamation liabilities for TransAlta.

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Land Use
Our largest land use had been associated with land disturbed by surface mining of coal, which ceased operations in 2021. Of the three mines we operated, the Whitewood mine in Alberta is completely reclaimed and the land certification process is ongoing. Our Centralia mine in Washington State is currently in the reclamation phase and we have adopted a target to fully reclaim this mine by 2040.
Our Highvale mine in Alberta ceased operations on Dec. 31, 2021, as part of our target to discontinue coal-fired power generation in Canada at the end of 2021. The mine reclamation of Highvale has been progressively executed as part of our regulatory approvals and our target is to have it fully reclaimed by 2046. In 2022, our reclamation team submitted our final reclamation plans. The updated plans align with community priorities for the reclaimed land. Our reclamation plans at Highvale are set out on a life-cycle basis and include contouring disturbed areas, re-establishing drainage, replacing topsoil and subsoil, re-vegetation and land management.
Our mining practices incorporate progressive reclamation where the final end use of the land is considered at all
stages of planning and development. To date, we have reclaimed approximately 4,900 hectares, which is approximately 39 per cent of land disturbed (12,600 hectares).
Environmental Incidents and Spills
Protecting the environment supports healthy ecosystems and mitigates our environmental compliance risk and reputational risk. We maintain corporate incident management procedures, as part of our Total Safety Management System, for response, investigation and lessons learned to minimize environmental incidents. With respect to biodiversity management (management of ecosystems, natural habitats and life in the areas we operate), we seek to establish robust environmental research and data collection to establish scientifically sound baselines of the natural environment around our facilities to ensure we can accurately evaluate the level of significance to biodiversity following an incident. We closely monitor the air, land, water and wildlife in these areas to identify and curtail potential impacts.
In 2023, no regulatory non-compliance environmental incidents were recorded (2022 – one incident). No fines or environmental enforcement actions occurred.
Regulatory non-compliance environmental incidents follow:

Year ended Dec. 31 | 2023 | 2022 | 2021
Regulatory non-compliance environmental incidents | 0 | 1 | 2

Regarding spills and releases, efforts are placed on providing immediate response to all environmental spills to ensure assessment, containment and recovery of spilled materials result in minimal impact to the environment.
The volume of spills in 2023 was zero (0) m 3 (2022 – 246 m 3).
Significant environmental incidents follow:

Year ended Dec. 31 | 2023 | 2022 | 2021
Significant environmental incidents | 0 | 0 | 0

There is a potential that ash ponds associated with our retired coal mines could fail. The probability of this occurring is low, but the impact could be significant. We follow applicable environmental regulations with respect to our ash ponds and satisfy ourselves that management is adequate given our approach to dam safety and the robust regulations in the jurisdictions where we operate. Management includes periodic inspections and appropriate mitigation if issues are uncovered.
Weather
Abnormal weather events can impact our operations and give rise to risks. Due to the nature of our business, our earnings are sensitive to seasonal weather variations. Variations in winter weather affect the demand for electrical heating requirements while variations in summer weather affect the demand for electrical cooling requirements. These variations in demand translate into
spot market price volatility. Variations in precipitation also affect water supplies, which in turn affect our hydroelectric assets. Also, variations in sunlight conditions can have an effect on energy production levels from our solar facilities. Variations in weather may be impacted by climate change resulting in sustained higher temperatures and rising sea levels, which could have an impact on our generating assets. Ice can accumulate on wind turbine blades in the winter months. The accumulation of ice on wind turbine blades depends on a number of factors, including temperature and ambient humidity. Accumulated ice can have a significant impact on energy yields and could result in the wind turbine experiencing more downtime. Extreme cold temperatures can also impact the ability of wind turbines to operate effectively and this could result in more downtime and reduced production. In addition, climate change could result in increased variability to our water and wind resources.

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Our generation facilities and their operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g., floods, strong winds, wildfires, earthquakes, tornados and cyclones), equipment failures and other events beyond our control. Climate change can increase the frequency and severity of these extreme weather events. The occurrence of a significant event that disrupts the operation or ability of the generation facilities to produce or sell power for an extended period, including events that preclude existing
customers from purchasing electricity, could have a material adverse effect. In certain cases, there is the potential that some events may not excuse us from performing our obligations pursuant to agreements with third parties. The fact that several of our generation facilities are located in remote areas may make access for repair of damage difficult. Refer to the Governance and Risk Management section of this MD&A for further discussion on weather-related risks.
Delivering Reliable and Affordable Energy
TransAlta’s goal is to be a leading customer-centred clean electricity company, one that is committed to a sustainable future. Our strategy is focused on meeting our customers' need for clean, low-cost and reliable electricity, operational excellence and continual improvement in everything that we do. This section covers manufactured, intellectual and social and relationship capital management as per guidance from the International Integrated Reporting Framework.
Energy Affordability
TransAlta focuses on assisting commercial and industrial customers in managing their cost of energy. TransAlta has a full suite of procurement strategies and products with various terms available to our customers to assist in understanding and reducing their energy costs.
For customers interested in making a long-term commitment to obtain predictable costs, TransAlta has the experience to develop renewable energy facilities, battery energy storage systems and hybrid solutions, or long-term offtake agreements from its existing and future renewable and gas-fired facilities.
End-Use Efficiency and Demand
TransAlta’s commercial and industrial customers have access to an extensive set of monthly reports providing detailed tracking of customer usage, allowing for corrective action as required, as well as cost-saving recommendations.
Our Power Factor Report advises customers if their sites are operating at less than a 90 per cent power factor so they can consider installing energy-efficient equipment. By reducing the customer’s power system demand charge through power factor correction, the customer’s site puts less strain on the electricity grid and reduces its carbon footprint. TransAlta’s Site Health Report advises customers of a site whose peak demand has been permanently reduced for a variety of reasons from its initial in-service date. The customer may be paying a higher demand charge each month to the distribution company based on
the original peak demand expected at the site. TransAlta collaborates with the customer and determines the new peak demand based on the customer’s operation. The customer, working with the distribution company, may find it economic to buy down the distribution contract to reduce the monthly distribution costs going forward.
Grid Resiliency
As a large electricity generator, TransAlta works diligently to ensure the power we provide our customers is reliable, affordable and has low environmental impact. We provide decentralized and customized power solutions to industrial customers. In 2023, TransAlta completed the Northern Goldfields solar facilities in Western Australia to provide renewable solar electricity supported with a battery energy storage system to the Goldfields-based operations of BHP. We also supply power to centralized power systems and own and operate transmission grid infrastructure in Alberta that addresses system reliability needs.
In all jurisdictions where we operate, we work closely with the system operators to ensure overall supply adequacy and reliability of the grid. We consider a myriad of factors in our planning and operation decisions that could put grid resiliency at risk, including renewable energy intermittency, cyberattacks, extreme weather events and natural disasters. We are also committed to ensuring strong compliance with North American Electric Reliability Corporation standards and Alberta Reliability Standards for the power plant and transmission infrastructure that we own and operate.
As a Company, we are keenly focused on deploying clean power generation and new technology solutions to meet the emerging and future needs of the electric system that we operate in. For example, in Alberta, we brought online the first battery storage project, called WindCharger, in 2020 that is co-located with our Summerview II wind facility to create an emissions-free, peaking resource. This resource participates in the AESO’s fast frequency response ancillary services market to support intertie operations. Beyond the fast frequency response, WindCharger introduces a resource with a response time

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that can be operated with a high level of reliability to support the growing need for primary frequency response and system frequency support and resiliency to support a decarbonized grid with a supply mix made up of intermittent renewable resources.
For more information on technologies to support grid resiliency, refer to the Enabling Innovation and Technology Adoption section of this MD&A. For more information on extreme weather events and natural disasters, refer to Weather in the Progressive Environmental Stewardship section of this MD&A.
Sustainability Governance
In order for an organization to truly integrate sustainability, it requires accountability at the Board and executive level. It requires an understanding of ESG issues and associated corporate actions to address these issues, while continuing to balance operations and growth.
Sustainability is overseen by TransAlta's GSSC of the Board. The GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Company’s monitoring of climate change, environmental, health and safety regulations, public policy changes and the development of strategies, policies and practices for climate change, environment, health and safety and social well-being, including human rights, working conditions and responsible sourcing.
The following policies help govern sustainability at TransAlta and are publicly available in the Governance section of the Investor Centre on our website:
•Corporate Code of Conduct
•Supplier Code of Conduct
•Whistleblower Policy
•Total Safety Management Policy
•Human Rights and Discrimination Policy
•Indigenous Relations Policy
•Board and Workforce Diversity Policy and Diversity and Inclusion Pledge
•Environmental Policy
In 2023, our sustainability memberships included key sustainability organizations and working groups such as the EXCEL Partnership, the Canadian Business for Social Responsibility and the Electricity Canada Sustainable Electricity Steering Committee, which all provide validation and support of our sustainability strategy and practices.
In 2022, we refreshed our material sustainability factors. They are presented below in alphabetical order.
•Air quality and emissions
•Asset integrity and grid resiliency
•Biodiversity and land management
•Climate change and greenhouse gas emissions
•Dam safety
•Energy use and conservation
•Equity, diversity and inclusion
•Ethics and business conduct
•Health, safety and well-being
•Human rights and labour practices
•Indigenous relationships and partnerships
•Information asset protection and cybersecurity
•Renewable energy and innovative technologies
•Security and emergency preparedness and response
•Stakeholder engagement and community investment
•Supply chain and sustainable sourcing
•Sustainability governance
•Sustainable finance
•Talent attraction, retention and development
•Waste management
•Water management
For additional details on governance, refer to the Governance and Risk Management section of this MD&A.

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Governance and Risk Management
Our business activities expose us to a variety of risks and opportunities including, but not limited to, regulatory changes, rapidly changing market dynamics and increased volatility in our key commodity markets. Our goal is to manage these risks and opportunities so that we are in a position to develop our business and achieve our goals while remaining reasonably protected from an unacceptable level of risk or financial exposure. We use a multilevel risk management oversight structure to manage the risks and opportunities arising from our business activities, the markets in which we operate and the political environments and structures with which we interact.
Governance
The key elements of our governance practices are:
•Employees, management and the Board are committed to ethical business conduct, integrity and honesty;
•We have established key policies and standards to provide a framework for how we conduct our business;
•The Chair of our Board and all directors, other than our President and CEO, are independent within the meaning of National Instrument 58-101 — Disclosure of Corporate Governance Practices;
•The Board is comprised of individuals with a mix of skills, knowledge and experience that are critical for our business and our strategy;
•The effectiveness of the Board is achieved through robust annual evaluations and continuing education of our directors; and
•Our management and the Board facilitate and foster an open dialogue with shareholders and community stakeholders.
Commitment to ethical conduct is the foundation of our corporate governance model. We have adopted the following codes of conduct to guide our business decisions and everyday business activities:
•Corporate Code of Conduct, which applies to all employees and officers of TransAlta and its subsidiaries;
•Directors’ Code of Conduct;
•Supplier's Code of Conduct;
•Finance Code of Ethics, which applies to all financial employees of the Company; and
•Energy Trading Code of Conduct, which applies to all of our employees engaged in energy marketing.
Our Corporate Code of Conduct outlines the standards and expectations we have for our employees, officers, directors, consultants and suppliers with respect to, among other things, the protection and proper use of our assets. The codes also provide guidelines with respect to securing
our assets, avoiding conflicts of interest, respect in the workplace, social responsibility, privacy, compliance with laws, insider trading, environment, health and safety and our commitment to ethical and honest conduct. Our Corporate Code of Conduct and Directors' Code of Conduct each goes beyond the laws, rules and regulations that govern our business in the jurisdictions in which we operate; they outline the principal business practices with which all employees and directors must comply.
Our employees, officers and directors are reminded annually about the importance of ethics and professionalism in their daily work and must certify annually that they have reviewed and understand their responsibilities as set forth in the respective codes of conduct. This certification also requires our employees, officers and directors to acknowledge that they have complied with the standards set out in the respective code during the last calendar year.
The Board provides stewardship of the Company and ensures that the Company establishes key policies and procedures for the identification, assessment and management of principal risks and strategic plans. The Board monitors and assesses the performance and progress of the Company’s goals through candid and timely reports from the CEO and the senior management team. We have also established an annual evaluation process whereby our directors are provided with an opportunity to evaluate the Board, Board committees, individual directors and the Chair of the Board’s performance.
In order to allow the Board to establish and manage the financial, environmental and social elements of our governance practices, the Board has delegated certain responsibilities to the AFRC, GSSC, the Human Resources Committee (the “HRC”) and the Investment Performance Committee ("IPC").
The AFRC, consisting of independent members of the Board, provides assistance to the Board in fulfilling its oversight responsibility relating to the integrity of our consolidated financial statements and the financial reporting process; the systems of internal accounting and financial controls; the internal audit function; the external auditors’ qualifications and terms and conditions of appointment, including remuneration, independence, performance and reports; and the legal and risk compliance programs as established by management and the Board. The AFRC approves our Commodity and Financial Exposure Management policies and reviews quarterly ERM reporting.
The GSSC is responsible for developing and recommending to the Board a set of corporate governance principles applicable to the Company and for monitoring

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compliance with these principles. The GSSC is also responsible for Board recruitment, succession planning and for the nomination of directors to the Board and its committees. In addition, the GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Company’s monitoring of climate change, environmental, health and safety regulations, public policy changes and the development of strategies, policies and practices for climate change, environmental, health and safety and social well-being, including human rights, working conditions and responsible sourcing. The GSSC also receives an annual report on the annual codes of conduct certification process. For further information on the Board's oversight of climate-related factors, refer to the Climate Change Governance in the ESG section of this MD&A.
In regards to overseeing and seeking to ensure that the Company consistently achieves strong environment, health and safety (“EH&S”) performance, the GSSC undertakes a number of actions that include: (i) receiving regular reports from management regarding environmental compliance, trends and TransAlta’s responses; (ii) receiving reports and briefings on management’s initiatives with respect to changes in climate change legislation, policy developments as well as other draft initiatives and the potential impact such initiatives may have on our operations; (iii) assessing the impact of the GHG policies implementation and other legislative initiatives on the Company’s business; (iv) reviewing with management the EH&S policies of the Company; (v) reviewing with management the health and safety practices implemented within the Company, as well as the evaluation and training processes put in place to address problem areas; (vi) discussing with management ways to improve the EH&S processes and practices; (vii) considering and recommending our sustainability targets to the Board and evaluating our performance against such targets; and (viii) reviewing the effectiveness of our response to EH&S issues and any new initiatives put in place to further improve the Company’s EH&S culture.
The HRC is empowered by the Board to review and approve key compensation and human resources policies of the Company that are intended to attract, recruit, retain and motivate employees of the Company. The HRC also makes recommendations to the Board regarding the compensation of the CEO, including the review and adoption of equity-based incentive compensation plans, the adoption of human resources policies that support human rights and ethical conduct and the review and approval of executive management succession and development plans.
The IPC is empowered by the Board to oversee management's investment conclusions and the execution of major, Board-approved capital expenditure projects that further the Company's strategic plans. The IPC provides assistance to the Board in fulfilling its oversight responsibilities with respect to broadly reviewing and
monitoring project management and control processes, financial profile, capital costs, procurement practices and project schedules in a more in-depth manner than time permits during regularly scheduled Board meetings.
The responsibilities of other stakeholders within our risk management oversight structure are described below:
The CEO and executive management review and report on key risks quarterly. Specific Trading Risk Management reviews are held monthly by the Commodity Risk and Compliance Committee and weekly by the commodity risk team, the commercial managers in Trading and Marketing and the Executive Vice-President, Finance and Chief Financial Officer.
The Investment Committee is a management committee chaired by our Senior Vice-President, M&A, Strategy and Treasurer and comprises the President and Chief Executive Officer; Executive Vice-President, Finance and Chief Financial Officer; Executive Vice-President, Generation; Executive Vice-President, Commercial and Customer Relations; and Vice-President, Strategic Finance and Investor Relations. It reviews and approves all major capital expenditures including growth, productivity, life extensions and major coal outages. Projects that are approved by the Investment Committee will then be put forward for approval by the Board, if required.
The Commodity Risk & Compliance Committee is chaired by our Executive Vice-President, Finance and Chief Financial Officer and comprises at least three members of senior management. It oversees the risk and compliance program in trading and ensures that this program is adequately resourced to monitor trading operations from a risk and compliance perspective. It also ensures the existence of appropriate controls, processes, systems and procedures to monitor adherence to policy.
The Hydro Operating Committee consists of two members who are Brookfield employees with expertise in hydro facility management and two TransAlta members. This committee was formed in 2019 for the purpose of collaborating on matters in connection with the operation and maximization of the value of TransAlta's Alberta Hydro Assets. It is delivering on its objectives by reviewing the operating, maintenance, safety and environmental aspects of TransAlta's Alberta Hydro Assets and, following that review, providing expert advice and recommendations to TransAlta’s hydro operational team. The Hydro Operating Committee has an initial term of six years, which can be extended for an additional two years.
TransAlta is listed on the Toronto Stock Exchange and the New York Stock Exchange and is subject to the governance regulations, rules and standards applicable under both exchanges. Our corporate governance practices meet the following governance rules and guidelines of the TSX and Canadian Securities Administrators: (i) Multilateral Instrument 52-109 —

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Certification of Disclosure in Issuers’ Annual and Interim Filings; (ii) National Instrument 52-110 — Audit Committees; (iii) National Policy 58-201 — Corporate Governance Guidelines; and (iv) National Instrument 58-101 — Disclosure of Corporate Governance Practices. As a “foreign private issuer” under US securities laws, we are generally permitted to comply with Canadian corporate governance requirements. Additional information regarding our governance practices can be found in our most recent management information circular.
Risk Controls
Our risk controls have several key components:
Enterprise Tone
We strive to foster beliefs and actions that are true to and respectful of, our many stakeholders. We do this by investing in communities where we live and work, operating and growing sustainably, putting safety first and being responsible to the many groups and individuals with whom we work.
Policies
We maintain a comprehensive set of enterprise-wide policies. These policies establish delegated authorities and limits for business transactions, as well as allow for an exception approval process. Periodic reviews and audits are performed to ensure compliance with these policies. All employees and directors are required to sign a Corporate Code of Conduct on an annual basis.
Reporting
On a regular basis, residual risk exposures are reported to key decision-makers including the Board, the AFRC, senior management and/or the Commodity Risk & Compliance Committee, as applicable. Reporting to this latter committee includes analysis of new risks, monitoring of status to risk limits, review of events that can affect these risks and discussion and review of the status of actions to minimize risks. This monthly reporting provides for effective and timely risk management and oversight.
Whistleblower System
We have a process in place where employees, contractors, shareholders or other stakeholders may confidentially or anonymously report any potential legal or ethical concerns, including concerns relating to accounting, internal control accounting, auditing or financial matters or relating to alleged violations of any laws or our Corporate Code of Conduct. These concerns can be submitted confidentially and anonymously, either directly to the AFRC or through TransAlta’s toll-free telephone or online Ethics Helpline. The AFRC Chair is immediately notified of any material complaints and, otherwise, the AFRC receives a report at every quarterly committee meeting on all findings related to any material complaints or complaints relating to accounting or financial reporting or alleged breaches in internal controls over financial reporting.
Value at Risk and Trading Positions
Value at risk (“VaR”) is one of the primary measures used to manage our exposure to market risk resulting from commodity risk management activities. VaR is calculated and reported on a daily basis. This metric describes the potential change in the value of our trading portfolio over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations.
VaR is a commonly used metric that is employed by industry to track the risk in commodity risk management positions and portfolios. Two common methodologies for estimating VaR are the historical variance/covariance and scenario analysis approaches. We estimate VaR using the historical variance/covariance approach. An inherent limitation of historical variance/covariance VaR is that historical information used in the estimate may not be indicative of future market risk. Stress tests are performed periodically to measure the financial impact to the trading portfolio resulting from potential market events, including fluctuations in market prices, volatilities of those prices and the relationships between those prices. We also employ additional risk mitigation measures. VaR at Dec. 31, 2023, associated with our proprietary commodity risk management activities was $4 million (2022 – $4 million). Refer to the Risk Factors – Commodity Price Risk section of this MD&A below for further discussion.
Risk Factors
Risk is an inherent factor of doing business. The following section addresses some, but not all, risk factors that could affect our future plans, performance, results or outcomes and our activities in mitigating those risks. These risks do not occur in isolation, but must be considered in conjunction with each other. Further information on the Company's risk factors can be found in the Risk Factors section of the AIF, which risk factors are hereby incorporated by reference and available on our website at www.transalta.com and under our profile on SEDAR+ at www.sedarplus.ca and on EDGAR at www.edgar.gov.
A reference herein to a material adverse effect on the Company means such an effect on the Company or its business, operations, financial condition, results of operations and/or its cash flows, as the context requires.
For some risk factors, we show the after-tax effect on net earnings (loss) of changes in certain key variables. The analysis is based on business conditions and production volumes in 2023. Each item in the sensitivity analysis assumes all other potential variables are held constant. While these sensitivities are applicable to the period and the magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or for a greater magnitude of changes. The changes in rates should also not be assumed to be proportionate to earnings in all instances.

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Volume Risk
Volume risk relates to the variances from our expected production. The financial performance of our hydro, wind and solar operations is highly dependent upon the availability of their input resources in a given year. Shifts in weather or climate patterns, seasonal precipitation and the timing and rate of melting and runoff may impact the water flow to our facilities. The strength and consistency of the wind resource at our facilities impacts production. The operation of thermal facilities can also be impacted by ambient temperatures and the availability of water and fuel. Where we are unable to produce sufficient quantities of output in relation to contractually specified volumes, we may be required to pay penalties or purchase replacement power in the market.
We manage volume risk by:
•Actively managing our assets and their condition to be proactive in facility maintenance so that our facilities are available to produce when required;
•Monitoring water resources throughout Alberta to the best of our ability and optimizing this resource against real-time electricity market opportunities;
•Placing our facilities in locations we believe to have adequate resources to generate electricity to meet the requirements of our contracts. However, we cannot guarantee that these resources will be available when we need them or in the quantities that we require; and
•Diversifying our fuels and geography to mitigate regional or fuel-specific events.
The sensitivity of volumes to our net earnings is shown below:

Factor | Increase or decrease (per cent) | Approximate impact on net earnings (millions)
Availability/production | 1 |  | $20

Generation Equipment and Technology Risk
There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse effect on the Company. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. Our facilities are exposed to operational risks such as failures due to cyclic, thermal and corrosion damage in boilers, generators and turbines, as well as other issues that can lead to outages and increased production risk. If facilities do not meet availability or production targets specified in their PPA or other long-term contracts, we may be required to compensate the purchaser for the loss in the availability of production or record reduced energy or capacity payments. For merchant facilities, an outage can result in lost merchant opportunities. Therefore, an extended outage could have a material adverse effect on our business, financial condition, results of operations or our cash flows.
As well, we are exposed to procurement risk for specialized parts that may have long lead times. If we are unable to procure these parts when they are needed for maintenance activities, we could face an extended period where our equipment is unavailable to produce electricity.
We manage our generation equipment and technology risk by:
•Operating our facilities within defined industry standards that optimizes availability over their commercial operating life;
•Performing preventive maintenance in accordance with applicable industry practices, major equipment supplier recommendations and our operating experience;
•Adhering to comprehensive maintenance programs and regular turnaround schedules;
•Adjusting maintenance plans by facility to reflect equipment type, age and commercial risk;
•Having adequate business interruption insurance in place to cover extended forced outages;
•Having clauses in our PPAs and other long-term contracts that allow us to declare force majeure in the event of an unforeseen failure;
•Selecting and applying proven technology in our generating facilities, where practical;
•Where technology is newer, ensuring service agreements with equipment suppliers include appropriate availability and performance guarantees;
•Monitoring our fleet against industry performance to identify issues or advancements that may impact performance and adjusting our maintenance and investment programs accordingly;
•Negotiating strategic supply agreements with selected vendors to ensure key components are readily available in the event of a significant outage;
•Monitoring the condition of our assets and performing predictive analytics, and adjusting our maintenance programs to maintain availability;
•Entering into long-term arrangements with our strategic supply partners to ensure availability of critical spare parts; and

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•Implementing long-term asset management strategies that optimize the life cycles of our existing facilities and/or identify replacement requirements for generating assets.
Commodity Price Risk
We have exposure to movements in certain commodity prices, including the market price of electricity and fuels used to produce electricity in both our electricity generation and proprietary trading businesses.
We manage the financial exposure associated with fluctuations in electricity price risk by:
•Entering into long-term contracts that specify the price at which electricity, steam and other services are provided;
•Maintaining a portfolio of short-, medium- and long-term contracts to mitigate our exposure to short-term fluctuations in commodity prices;
•Purchasing natural gas coincident with production for merchant facilities so spot market spark spreads are adequate to produce and sell electricity at a profit; and
•Ensuring limits and controls are in place for our proprietary trading activities.
In 2023, we had approximately 84 per cent (2022 – 83 per cent) of total production under short-term and long-term contracts and hedges. In the event of a planned or unplanned outage or other similar event, however, we are exposed to changes in electricity prices on purchases of electricity from the market to fulfil our supply obligations under these short- and long-term contracts.
We manage the financial exposure to fluctuations in the cost of fuels used in production by:
•Entering into long-term contracts that specify the price at which fuel is to be supplied to our facilities;
•Hedging emissions costs by entering into various emission trading arrangements; and
•Selectively using hedges, where available, to set prices for fuel.
In 2023, 86 per cent (2022 – 82 per cent) of our gas consumption used in generating electricity was contractually fixed or passed through to our customers and 100 per cent (2022 – 100 per cent) of our purchased coal was contractually fixed.
Actual variations in net earnings (loss) can vary from calculated sensitivities and may not be linear due to optimization opportunities, co-dependencies and cost mitigations, production, availability and other factors.
Natural Gas Supply and Price Risk
Having sufficient natural gas and natural gas transportation services available at our gas facilities is essential to maintaining the reliability and availability of those facilities.
Ensuring adequate pipeline transportation service and natural gas supply for our gas units may be impacted by, among other things, the timing of receiving regulatory and other approvals for firm transportation commitments, weather-related events, work stoppages, system maintenance, variability in pipeline hydraulics pressure and flows and impacts due to other naturally caused events. Pricing of natural gas is driven by market supply and demand fundamentals for natural gas in North America and globally. We are exposed to changes in natural gas prices, which may impact the profitability of our facilities and how the facilities are dispatched into the market.
We manage gas supply and price risk by:
•Working to ensure that we have at least two pipelines supplying the gas used in electrical generation in Alberta;
•Contracting for firm gas delivery and supply;
•Monitoring the financial viability of gas producers and pipelines;
•Hedging gas price exposure; and
•Monitoring pipeline maintenance schedules and transportation availability.
Environmental Compliance Risk
Environmental compliance risks are risks to our business associated with existing and/or changes in environmental regulations. New emission reduction objectives for the power sector are being established by governments in Canada, Australia and the US. We anticipate continued and growing scrutiny by investors and other stakeholders relating to sustainability performance. These changes to regulations may affect our earnings by reducing the operating life of generating facilities and imposing additional costs on the generation of electricity through such measures as emission caps or taxes, requiring additional capital investments in emission abatement technology or requiring us to invest in offset credits. It is anticipated that these compliance costs will increase due to increased political and public attention to environmental concerns.
We manage environmental compliance risk by:
•Seeking continuous improvement in numerous performance metrics such as emissions, safety, land and water impacts and environmental incidents;
•Conducting environmental health and safety management system audits to assess conformance to our Total Safety Management System, which is designed to continuously improve performance;
•Committing significant experienced resources to work with regulators in Canada, Australia and the US to advocate that regulatory changes are well-designed and cost-effective;

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•Developing compliance plans that address how to meet or surpass emission standards for GHG, mercury, SO 2 and NO x, which will be adjusted as regulations are finalized;
•Purchasing carbon emissions reduction offsets or credits;
•Investing in renewable energy projects, such as wind, solar and hydro generation and storage technologies; and
•Incorporating change-in-law provisions in contracts that allow recovery of certain compliance costs from our customers.
We are committed to remaining in compliance with all environmental regulations relating to operations and facilities. Compliance with both regulatory requirements and management system standards is regularly audited through our performance assurance policy and results are reported to the GSSC.
Credit Risk
Credit risk is the risk to our business associated with changes in the creditworthiness of entities with which we have commercial exposures. This risk results from the ability of a counterparty to either fulfil its financial or performance obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect cash due to us or to receive products or services may have an adverse impact upon our net earnings (loss) and cash flows.
We manage our exposure to credit risk by:
•Establishing and adhering to policies that define credit limits based on the creditworthiness of counterparties;
•contract term limits and the credit concentration with any specific counterparty;
•Requiring formal sign-off on contracts that include commercial, financial, legal and operational reviews;
•Requiring security instruments, such as parental guarantees, letters of credit and cash collateral or third-party credit insurance if a counterparty goes over its limits. Such security instruments can be collected if a counterparty fails to fulfil its obligation; and
•Reporting our exposure using a variety of methods that allow key decision-makers to assess credit exposure by counterparty. This reporting allows us to assess credit limits for counterparties and the mix of counterparties based on their credit ratings.
If established credit exposure limits are exceeded, we take steps to reduce this exposure, such as by requesting collateral, if applicable, or by halting commercial activities with the affected counterparty. However, there can be no assurances that we will be successful in avoiding losses as a result of a contract counterparty not meeting its obligations.
As needed, additional risk mitigation tactics will be taken to reduce the risk to TransAlta. These risk mitigation tactics may include, but are not limited to, immediate follow-up on overdue amounts, adjusting payment terms to ensure a portion of funds are received sooner, requiring additional collateral, reducing transaction terms and working closely with impacted counterparties on negotiated solutions.
Our credit risk management profile and practices have not changed materially from Dec. 31, 2022. We had no material counterparty losses in 2023. We continue to keep a close watch on changes and trends in the market and the impact these changes could have on our energy trading business and hedging activities and will take appropriate actions as required, although no assurance can be given that we will always be successful.
The following table outlines our maximum exposure to credit risk without taking into account collateral held or right of set-off, including the distribution of credit ratings, as at Dec. 31, 2023:

| Investment grade (per cent) | Non-investment grade (per cent) | Total (per cent) | Total amount ($)
Trade and other receivables(1,2) | 95 |  | 5 |  | 100 |  | 807 |
Long-term finance lease receivables | 100 |  | — |  | 100 |  | 171 |
Risk management assets(1) | 75 |  | 25 |  | 100 |  | 203 |
Loan receivable(2) | — |  | 100 |  | 100 |  | 26 |
Total |  |  |  | 1,207 |

(1)Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.
(2)Includes $26 million loan receivable included within other assets with a counterparty that has no external credit rating.
The maximum credit exposure to any one customer for commodity trading operations, including the fair value of open trading positions net of any collateral held, is $23 million (2022 – $64 million).
Counterparties enter into certain electricity and natural gas purchase and sale contracts for the purposes of asset-backed sales and proprietary trading. The terms and conditions of these contracts require the counterparties to

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provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may impact our ability to enter into these contracts or any ordinary course contract, decrease the credit limits granted and increase the amount of collateral that may have to be provided. Certain existing contracts contain credit rating contingent clauses, that, when triggered, automatically increase costs under the contract or require additional collateral to be posted. Where the contingency is based on the lowest single rating, a one-level downgrade from a credit rating agency with an originally higher rating may not, however, trigger additional direct adverse impact.
Currency Rate Risk
We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the earnings from those operations, the acquisition of equipment and services and foreign-denominated commodities from foreign suppliers, and our US and Australian dollar-denominated debt. Our exposures are primarily to the US and Australian currencies. Changes in
the values of these currencies in relation to the Canadian dollar may affect our earnings, cash flows or the value of our foreign investments to the extent that these positions or cash flows are not hedged or the hedges are ineffective.
We manage our currency rate risk by establishing and adhering to policies that include:
•Hedging our net investments in US operations using US-denominated debt;
•Entering into forward foreign exchange contracts to hedge future foreign-denominated expenditures including our US-denominated senior debt that is outside the net investment portfolio; and
•Hedging our expected foreign operating cash flows. Our target is to hedge a minimum of 60 per cent of our forecasted foreign operating cash flows over a four-year period, with a minimum of 90 per cent in the current year, 70 per cent in the next year, 50 per cent in the third year and 30 per cent in the fourth year. The US and Australian exposure, net of debt service and sustaining capital expenditures, is managed with forward foreign exchange contracts.
The sensitivity of our net earnings to changes in foreign exchange rates has been prepared using management’s assessment that an average $0.03 increase or decrease in the US or Australian currencies relative to the Canadian dollar is a reasonable potential change over the next quarter and is shown below:

Factor | Increase or decrease | Approximate impact on net earnings (millions)
Exchange rate | $0.03 | $14

Liquidity Risk
Liquidity risk relates to our ability to access capital to be used to fund capital projects, refinance debt and pay liabilities, engage in trading and hedging activities and general corporate purposes. Credit ratings facilitate these activities and changes in credit ratings may affect our ability and/or the cost of accessing capital markets, or establishing normal course derivative or hedging transactions, including those undertaken by our Energy Marketing segment.
We continue to focus on maintaining our financial position and flexibility. Credit ratings issued for TransAlta, as well as the corresponding rating agency outlooks, are set out in the Financial Capital section of this MD&A. Credit ratings are subject to revision or withdrawal at any time by the rating organization and there can be no assurance that TransAlta’s credit ratings and the corresponding outlook will not be changed, resulting in the adverse possible impacts identified above.
As at Dec. 31, 2023, we had liquidity of $1.7 billion comprising undrawn amounts under our committed credit facilities and cash on hand net of bank overdraft.
We manage liquidity risk by:
•Preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital;
•Reporting liquidity risk exposure and risk management activities on a regular basis to the Commodity Risk & Compliance Committee, senior management and the AFRC;
•Maintaining a strong balance sheet;
•Maintaining sufficient undrawn committed credit lines to support potential liquidity requirements; and
•Monitoring trading positions.

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Interest Rate Risk
Changes in interest rates can impact our borrowing costs. Changes in our cost of capital may also affect the feasibility of new growth initiatives.
We manage interest rate risk by establishing and adhering to policies that include:
•Employing a combination of fixed and floating rate debt instruments;
•Monitoring the mixture of floating and fixed rate debt and adjusting to ensure efficiency; and
•Opportunistically hedging probable debt issuances and outstanding variable rate borrowings using interest rate swaps.
At Dec. 31, 2023, approximately 14 per cent (2022 – nine per cent) of our total long-term debt was subject to changes in floating interest rates through a combination of floating rate debt and interest rate swaps.
The sensitivity of changes in interest rates upon our net earnings is shown below:

Factor | Increase or decrease (per cent) | Approximate impact on net earnings (millions)
Interest rate | 50 bps | $2 |

London Interbank Offered Rate reform could impact interest rate risk with respect to the Company's Canadian dollar credit facilities and the Poplar Creek non-recourse bond held by a TransAlta subsidiary. The facilities reference the Canadian Dollar Offer Rate ("CDOR") for Canadian-dollar drawings, but include appropriate fallback language to replace this benchmark rate in the event of a benchmark transition. In addition, the non-recourse bond references the three-month CDOR. Cessation of the three-month CDOR will occur on June 28, 2024, which will impact the facilities and the non-recourse bond.
Coal Supply Risk
Having sufficient fuel available when required for generation is essential to maintaining our ability to produce electricity under contracts and for merchant sale opportunities. At Centralia, interruptions at our supplier’s mine, the availability of trains to deliver coal and the financial viability of our coal suppliers could affect our ability to generate electricity.
We manage coal supply risk by:
•Sourcing the coal used at Centralia from different mine sources to ensure sufficient coal is available at a competitive cost;
•Contracting sufficient trains to deliver the coal requirements at Centralia;
•Ensuring coal inventories on hand at Centralia are at appropriate levels for usage requirements;
•Ensuring efficient coal handling and storage facilities are in place so that the coal being delivered can be processed in a timely and efficient manner;
•Monitoring and maintaining coal specifications and carefully matching the specifications mined with the requirements of our facilities;
•Monitoring the financial viability of Centralia suppliers; and
•Hedging diesel exposure in mining and transportation costs.
Project Management Risk
On capital projects, we face risks associated with cost overruns, delays and performance.
We manage project risks by:
•Ensuring all projects follow established corporate processes and policies;
•Identifying key risks during every stage of project development and ensuring mitigation plans are factored into capital estimates and contingencies;
•Reviewing project plans, key assumptions and returns with senior management prior to Board of Director approvals;
•Consistently applying project management methodologies and processes;
•Determining contracting strategies that are consistent with the project scope and scale to ensure key risks, such as labour and technology, are managed by contractors and equipment suppliers;
•Ensuring contracts for construction and major equipment include key terms for performance, delays and quality backed by appropriate levels of liquidated damages;
•Reviewing projects after achieving commercial operation to ensure learnings are incorporated into the next project;
•Negotiating contracts for construction and major equipment to lock in key terms such as price, availability of long lead equipment, foreign currency rates and warranties as much as is economically feasible before proceeding with the project; and
•Entering into labour agreements to provide security around labour cost, supply and productivity.

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Human Resource Risk
Human resource risk relates to the potential impact upon our business as a result of changes in the workplace. Human resource risk can occur in several ways:
•Potential disruption as a result of labour action at our generating facilities;
•Reduced productivity due to turnover in positions;
•Inability to complete critical work due to vacant positions;
•Failure to maintain fair compensation with respect to market rate changes; and
•Reduced competencies due to insufficient training, failure to transfer knowledge from existing employees or insufficient expertise within current employees.
We manage this risk by:
•Possessing a labour relations strategy;
•Applying a human-centric approach that emphasizes the employee experience, including actively improving our workplace culture, focusing on ED&I strategies and offering health and wellness programming and initiatives;
•Focusing on employee learning and development;
•Monitoring industry compensation and aligning salaries with those benchmarks;
•Using incentive pay to align employee goals with corporate goals;
•Monitoring and managing target levels of employee turnover; and
•Ensuring employees have the appropriate training and qualifications to perform their jobs.
In 2023, approximately 30 per cent (2022 – 31 per cent) of our labour force was covered by 11 collective bargaining agreements (2022 – 11). In 2023, we successfully renegotiated three (2022 – six) collective bargaining agreements. Of these three agreements, one agreement is for a three-year duration, one agreement is for a two-year duration and one agreement is a one-year duration. We expect to renegotiate five collective bargaining agreements in 2024. Any problems in negotiating these collective bargaining agreements could lead to higher employee costs and a work stoppage or strike, which could have a material adverse effect on us.
Regulatory and Political Risk
Regulatory and political risk is the risk to our business associated with potential changes to the existing regulatory structures and the political influence upon those structures within each of the jurisdictions in which we operate. This risk can come from market regulation and re-regulation, increased oversight and control, structural or design changes in markets, or other unforeseen influences. Market rules are often dynamic and we are not able to predict whether there will be any material changes in the
regulatory environment or the ultimate effect of changes in the regulatory environment on our business. This risk includes, among other things, uncertainties associated with the development of carbon pricing policies and funding.
We manage these risks systematically through our legal and regulatory groups and our compliance program, which is reviewed periodically to ensure its effectiveness. We also work with governments, regulators, electricity system operators and other stakeholders to resolve issues as they arise. We are actively monitoring changes to market rules and market design and we engage in industry and government-agency-led stakeholder engagement processes. Through these and other avenues, we engage in advocacy and policy discussions at a variety of levels. These stakeholder consultations have allowed us to engage in proactive discussions with governments and regulatory agencies over the longer term.
International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the respective country and such country’s regulatory regime. We mitigate this risk through the use of non-recourse financing and insurance.
Transmission Risk
Access to transmission lines and transmission capacity for existing and new generation is key to our ability to deliver energy produced at our power facilities to our customers. The risks associated with the aging transmission infrastructure in the markets where we operate are increasing because new connections to the power system are consuming transmission capacity faster than it is being added by new transmission developments.
Reputation Risk
Our reputation is one of our most valued assets. Reputation risk relates to the risk associated with our business because of changes in opinion from the general public, private stakeholders, governments, financiers and other entities.
We manage reputation risk by:
•Striving as a neighbour and business partner, in the regions where we operate, to build viable relationships based on mutual understanding leading to workable solutions with our neighbours and other community stakeholders;
•Clearly communicating our business objectives and priorities to a variety of stakeholders on a routine and transparent basis;
•Applying innovative technologies to improve our operations, work environment and environmental footprint;
•Maintaining positive relationships with various levels of government;

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•Pursuing sustainable development as a longer-term corporate strategy;
•Ensuring that each business decision is made with integrity and in line with our corporate values;
•Communicating the impact and rationale of business decisions to stakeholders in a timely manner; and
•Maintaining strong corporate values that support reputation risk management initiatives, including the annual Code of Conduct sign-off.
Corporate Structure Risk
We conduct a significant amount of business through subsidiaries and partnerships. Our ability to meet and service debt obligations is dependent upon the results of operations of our subsidiaries and partnerships and the payment of funds by our subsidiaries and partnerships in the form of distributions, loans, dividends or otherwise. In addition, our subsidiaries and partnerships may be subject to statutory or contractual restrictions that limit their ability to distribute cash to us.
Cybersecurity Risk
We rely on our information technology to process, transmit and store electronic information and data used for the safe operation of our assets. Over the past few years, geopolitical tensions and the pandemic have significantly impacted the cybersecurity ecosystem, increasing the frequency and diversity of cyberattacks, including threats of war driven cyberattacks (i.e., terrorism) against critical infrastructure and threat actors taking advantage of the pandemic (e.g., charity scams) and hybrid working environments. We anticipate that the cyber threat landscape will continue to evolve, with increasing threats of ransomware, compromised insider threats, supply chain attacks, advanced targeted phishing and artificial intelligence.
Cyber threats originate from various sources and vectors, from nation states, organized hacking groups or malware/ransomware. The cyber threat landscape continues to evolve, as we see cyber threats shift their focus from traditional attacks against perimeter information technology systems, to more effective attacks, such as phishing and ransomware.
TransAlta has established a comprehensive cybersecurity program to manage cybersecurity risks through effective security practices and structured and tailored plans. As information technology /operation technology systems are integral to TransAlta’s business operations, the risk of a cybersecurity incident threatens the safety of the public, TransAlta personnel and/or business functions, service delivery, reputation and profitability.
TransAlta maintains compliance to regulatory, legislative, and business requirements (e.g., NERC CIP, SOX, Privacy) by adopting industry endorsed standards and frameworks
(e.g., National Institute of Standards and Technology (“NIST”), CIP/Reliability Standards) to implement a pragmatic fit-for-purpose cybersecurity program, implementing cybersecurity controls and processes under the following domains:
•Identify: TransAlta conducts comprehensive risk assessments to identify and document the organization's assets, systems and data, as well as potential risks and vulnerabilities.
•Protect: TransAlta implements security controls, policies and procedures to safeguard the organization's assets, systems and data from unauthorized access, use, disclosure, disruption, modification or destruction. This includes implementing access controls, encryption, firewalls and intrusion detection/prevention systems to protect the organization's networks and systems.
•Detect: TransAlta implements incident detection and response capabilities to detect and respond to cyber incidents. This includes monitoring systems, networks and data for suspicious activity.
•Respond: TransAlta has developed incident response plans, procedures and teams, as well as provided training and conducted exercises to ensure that these plans and procedures are operating effectively.
•Recover: TransAlta has developed disaster recovery and business continuity plans, and it conducts test exercises of these plans to ensure their effectiveness. This includes identifying critical systems, data and process to ensure the continuity of business operations, as well as implementing backup and recovery solutions to ensure that the organization's data can be restored in the event of a disaster.
Although complete cyber risk elimination is not achievable given the evolving cyber threat landscape, the security controls implemented to detect, prevent and respond to a cyber incident significantly reduce TransAlta’s cyber risk and potential incident impact to acceptable levels. In addition, cyber insurance is utilized to further manage and transfer residual cyber risk to TransAlta’s business. We continue to improve our overall security maturity and defense capabilities against cyber threats and align cybersecurity practices to industry standards, business objectives and regulatory compliance requirements.
General Economic Conditions
Changes in general economic conditions impact product demand, revenue, operating costs, the timing and extent of capital expenditures, the net recoverable value of PP&E, financing costs, credit and liquidity risk and counterparty risk.

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Growth Risk
Our business plan includes targets for the growth of our fleet of generating assets through suitable acquisitions or contracting new build opportunities. There can be no assurance that we will be able to identify attractive growth opportunities in the future, that we will be able to complete growth opportunities that increase the amount of cash available for distribution, or that growth opportunities will be successfully integrated into our existing operations. The successful execution of the growth strategy requires careful timing and business judgment, as well as the resources to complete the due diligence and evaluation of such opportunities and to acquire and successfully integrate those assets into our business.
Income Taxes
Our operations are complex and located in several countries. The computation of the provision for income taxes involves tax interpretations, regulations and
legislation that are constantly evolving. Our tax filings are subject to audit by taxation authorities. Management believes that it has adequately provided for income taxes as required by the Income Tax Act and IFRS, based on all information currently available.
The Company and its subsidiaries are subject to changing laws, treaties and regulations in and between countries.
Various tax proposals in the countries we operate in could result in changes to the basis on which deferred taxes are calculated or could result in changes to income or non-income tax expense. There has recently been an increased focus on issues related to the taxation of multinational corporations. A change in tax laws, treaties or regulations, or in the interpretation thereof, could result in a materially higher income or non-income tax expense that could have a material adverse impact on the Company.
The sensitivity of changes in income tax rates upon our net earnings is shown below:

Factor | Increase or decrease (per cent) | Approximate impact on net earnings (millions)
Tax rate | 1 |  | $9 |

Legal Contingencies
We are occasionally named as a party in various disputes, claims and legal or regulatory proceedings that arise during the normal course of our business. We review each of these claims, including the nature and merits of the claim, the amount in dispute or the remedy claimed and the availability of insurance coverage. There can be no assurance that any particular dispute, claim or proceeding will be resolved in our favour or our liabilities with respect to such claims will not have a material adverse effect on us or our business, operations or financial results. Refer to the Other Consolidated Analysis section of this MD&A for further details.
Other Contingencies
We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our insurance coverage during renewal of the insurance policies on Dec. 31, 2023. Our insurance coverage may not be available in the future on commercially reasonable terms. There can be no assurance that our insurance coverage will be fully adequate to compensate for potential losses incurred. In the event of a significant economic event, the insurers may not be capable of fully paying all claims. All insurance policies are subject to standard exclusions.

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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 year ended Dec. 31, 2023, the majority of our workforce supporting and executing our ICFR and DC&P continue to work on a hybrid basis. The Company has implemented appropriate controls and oversight for both in-office and remote work. There has been minimal impact to the design and performance of our internal controls.
ICFR is a framework designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements for external purposes in accordance with IFRS. Management has used the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) in order to assess the effectiveness of the Company’s ICFR.
DC&P refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under securities legislation is recorded, processed, summarized and reported within the time frame specified in applicable securities legislation. DC&P include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under applicable securities legislation is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure.
Together, the ICFR and DC&P frameworks provide internal control over financial reporting and disclosure. In designing and evaluating our ICFR and DC&P, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and as such may not prevent or detect all misstatements and management is required to apply its judgment in evaluating and implementing possible controls and procedures. Further, the effectiveness of ICFR is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may change.
Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our ICFR and DC&P as of the end of the period covered by this MD&A. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as at Dec. 31, 2023, the end of the period covered by this MD&A, our ICFR and DC&P were effective.

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