Contents
2
President’s Message
4
Message from the Chairman of the Board
M1
Management’s Discussion and Analysis
F1
Consolidated Financial Statements
F14
Notes to Consolidated Financial Statements
267
Eleven-Year Financial and Statistical Summary
270
Plant Summary
273
Sustainability Performance Indicators
283 Independent Practitioner’s Assurance Report
287
Shareholder Information
291
Shareholder Highlights
292
Fighting Against Forced Labour and Child Labour in Supply Chains Act
298 Corporate Information
299 Glossary of Key Terms
TransAlta Corporation
2024 Integrated Report
1
Letter from the
President and CEO
John H. Kousinioris
President and Chief Executive Officer
Dear Fellow Shareholders,
2024 was marked by significant change across our sector,
ranging from growing supply chain constraints to rising
demand for power and associated reliability products. As I
look to 2025 and beyond, I am optimistic about the
opportunities for our company. Power markets will
continue to evolve, with momentum driven from the growth
in demand from electrification and data centres, and the
ongoing evolution of the energy mix. While we remain
steadfast in the transition to a cleaner electricity future, we
recognize the paramount importance of providing reliable
generation. All forms of energy will be needed to ensure
an orderly transition. As a highly capable, experienced and
flexible company, we are well-positioned to drive growth
and innovate as we navigate this evolving landscape. We
will focus on reliable life extension opportunities within our
existing portfolio, a technology-agnostic approach to
greenfield development and opportunistic mergers and
acquisitions. And we will continue to be disciplined with
our capital allocation, focused on maximizing shareholder
value, while remaining a trusted partner for our customers.
Sustaining Strong Business Performance
TransAlta was able to achieve another year of strong
performance despite significant headwinds, including
persistent inflation and lower power prices. We delivered
exceptional results, achieving $2.8 billion in revenues and
$1.3 billion in adjusted EBITDA. Our net earnings for
shareholders were also excellent at $177 million.
On a free cash flow basis, we generated $569 million, at
the upper end of our guidance range, or $1.88 per share.
Since 2022, we’ve delivered an impressive $8.65 per share
of free cash flow.
In 2024, we returned $143 million to shareholders through
our enhanced share repurchase program, at an average
price of $10.59 per share. This is part of our capital
allocation strategy, which adapts to market conditions and
the timing of development at our legacy thermal energy
campuses, opportunistic M&A and growth opportunities.
We have a normal course issuer bid in place that we have
actively used year after year to make accretive share buy
backs, with up to $100 million available for share buy backs
in 2025.
We have also increased our annual common share dividend
for 2025 to $0.26 per common share, as another means of
returning free cash flow to our shareholders.
We made significant progress in our growth initiatives in
2024. Our team successfully completed all three Oklahoma
wind facilities including White Rock West, White Rock East
and
Horizon
Hill.
Additionally,
the
Mount
Keith
Transmission Expansion achieved commercial operation
earlier in the year. These additions, along with the fully
rehabilitated Kent Hills facilities, are expected to contribute
over $175 million in EBITDA annually.
Availability was also excellent and reflected a significant
improvement across our facilities, at 91.2 per cent fleet-
wide in 2024.
Strategic Acquisition of Heartland
In the fourth quarter of 2024, we completed the acquisition
of Heartland Generation. The addition of Heartland’s assets
to our portfolio provides us with a further 1.7 GW of
generation capacity in Alberta and British Columbia, adding
flexible and complementary capacity to our fleet, including
contracted cogeneration and peaking generation, legacy
gas-fired thermal generation and transmission capacity.
With the growing demand for reliable power and the
intermittency of renewables, the need for low-cost, highly
flexible and fast-responding generation to support grid
reliability is more critical than ever. The Heartland
acquisition strengthens our position to meet future demand
for reliable electricity with a robust and diversified
portfolio.
2
TransAlta Corporation
2024 Integrated Report
Leading in Carbon Reductions
We are committed to decarbonization, with a target of
reducing scope 1 and 2 greenhouse gas emissions by 75
per cent from 2015 levels by 2026. Since 2018, we have
retired 4,464 MW of coal-fired generation capacity and
converted 1,659 MW of coal-fired capacity to natural-gas.
By the end of 2025, the remaining 670 MW of our coal-
fired generation will be retired, marking an important
milestone for the company’s transition and further reducing
our emissions. Our converted natural gas units have
approximately 57 per cent lower CO2 intensity compared to
coal-fired generation. Since 2015, we have reduced scope
1 and 2 greenhouse gas emissions by 22.7 MT CO2e or 70
per cent, a remarkable achievement considering the size
and diversity of our fleet.
Disciplined Approach to Capital Allocation and Growth
Electrification and growing demand presents significant
opportunities for TransAlta. Our strong balance sheet,
diverse generation portfolio and growth pipeline ensure
that we are well positioned for the years ahead. Given our
skill set, competitive advantages and market positioning,
we are poised to capture opportunities in each of our core
markets of Canada, the United States and Western
Australia.
Long-term shareholder value creation will ultimately drive
our investment and capital allocation decisions. Our
primary goal is to maximize shareholder returns in the
near-term by realizing the value of our legacy thermal
energy
campuses
as
we
pursue
redevelopment
opportunities,
as
well
as
potential
mergers
and
acquisitions. Longer-term, our focus is on greenfield
development.
We remain disciplined in our investment decisions to
ensure that we obtain appropriate risk-adjusted returns for
our shareholders. As we execute our Growth Plan, we
expect our adjusted EBITDA will become increasingly
contracted and more diversified across generation type
and customer base.
Preparing for TransAlta’s Future
Looking ahead to 2025 and beyond, we are prepared to
meet the increasing demand for power that stems from
electrification and the build-out of data centres supporting
the AI revolution. Our legacy fleet ensures that we can
maintain a stable cash flow base, while we continue to
invest in diverse, flexible and responsive generation to
meet future reliability needs.
In 2025, we will be focused on continued safe, reliable
operations
and
executing
our
strategic
priorities.
Specifically, optimizing our Alberta Portfolio, executing our
growth plan, realizing the value of our legacy generating
facilities and maintaining financial strength and capital
allocation discipline.
Our strong free cash flow permits us to return capital to our
shareholders and invest in TransAlta’s future, with a focus
on increasing our contracted cash flows and diversifying
our generation portfolio. We remain focused on identifying
the opportunities and meeting the challenges that will push
our company forward in the second half of the decade and
into the 2030s.
Our achievements in 2024 would not have been possible
without the collective contributions of our employees. I
thank them for their continued commitment to our core
values of safety, innovation, sustainability, respect, and
integrity.
I would also like to express my thanks to our Board of
Directors for the support, guidance and wisdom that they
provide day after day to our company.
To our shareholders, thank you for your trust and
confidence. We greatly value your opinions and put your
interests at the centre of our continued transformation and
the development of our strategy.
Finally, we sincerely appreciate the support of all of
our stakeholders, including our indigenous partners.
I am confident in the future and believe our success will
continue in 2025 and beyond.
John H. Kousinioris
President and Chief Executive Officer
February 19, 2025
TransAlta Corporation
2024 Integrated Report
3
Message from the
Chairman of the Board
John P. Dielwart
Chair of the Board of Directors
Dear Fellow Shareholders,
As we report the financial results for the year ended
December 31, 2024, I am incredibly proud to share in
TransAlta’s accomplishments, which would not have been
possible without the contribution of our exceptional
employees. The company, under direction of the Board,
expanded its renewable portfolio with the commercial
operation of our Horizon Hill and White Rock wind facilities,
achieved strong operational results and enhanced its
Alberta strategy through the completed acquisition of
Heartland Generation.
The company continues to manage its evolution for the
benefit of our shareholders. We have reported another
year of superior results that were within the upper end of
the original expectations we had at the beginning of 2024.
Our management team delivered another year of strong
free cash flow for our shareholders, achieved excellent
safety results, continued to reduce our emissions ahead of
targets and deployed our capital in a disciplined and
prudent way throughout the year. TransAlta has delivered
performance at all levels: safety; financial; operational; and
sustainability.
The company’s evolving strategy continues to provide
strong results and 2024’s share price appreciation reflects
the success of that execution. We continue to transition
the company through our technology-agnostic Growth Plan
and are well-positioned as a credible and sought-after
developer of choice for customers in all of our core
geographies.
Our strategy is directed towards achieving material growth
in our portfolio that will also increase the size of our
contracted fleet by the end of the decade. We will remain
disciplined in the deployment of our capital and we will not
grow for the sake of growth even if it means we do not
achieve our growth plan targets. Creating shareholder
value can happen through growth; however, we have
multiple avenues to deploy our capital to benefit our
shareholders. We will maintain discipline as we consider
our growth aspirations and rates of return for growth
projects. Acquisitions must also meet our target thresholds
for value creation. Long-term shareholder value creation
will drive our investment decisions and we remain
committed to our prudent capital allocation approach. To
the extent we deploy reduced growth capital, we will
pursue enhanced shareholder returns through dividends
and share repurchases.
The Board wishes to extend our heartfelt gratitude to the
employees and leadership team of TransAlta for their
efforts in delivering another outstanding year for the
company. The team has exhibited exceptional adaptability
to the changing market conditions and is committed to
enhancing the value of the company in a disciplined and
prudent manner. They have a keen focus on capital
allocation discipline and creation of shareholder value.
We also thank our shareholders for their unwavering
commitment and confidence in the company. As fellow
shareholders, we look forward to TransAlta’s execution in
2025 and we value your engagement and viewpoints on
our evolving strategy.
The Board of Directors will continuously engage with and
guide the management team to assess new opportunities
that will add value to the company, improve performance
and overall increase shareholder value.
John P. Dielwart
Chair of the Board of Directors
February 19, 2025
4
TransAlta Corporation
2024 Integrated Report
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
M76
Key Non-IFRS Financial Ratios
M4
Description of the Business
M77
2025 Outlook
M6
Highlights
M79
Material Accounting Policies and Critical Accounting
Estimates
M16
Capital Expenditures
M85
Accounting Changes
M17
Significant and Subsequent Events
M86
Sustainability
M19
Segmented Financial Performance and Operating Results
M87
Our 2024 Sustainability Performance
M29
Performance by Segment with Supplemental Geographical
Information
M89
2025+Sustainability Targets
M29
Optimization of the Alberta Portfolio
M92
Transitioning Our Energy Mix
M34
Fourth Quarter Highlights
M98
Key Climate Scenario Findings
M38
Segmented Financial Performance and Operating Results
for the Fourth Quarter
M101
Managing Climate Change Risks and Opportunities
M42
Selected Quarterly Information
M112
Enabling Innovation and Technology Adoption
M43
Strategic Priorities
M114
Managing Environmental Resources
M48
Financial Position
M123
Engaging with Our Stakeholders to Create
Positive Relationships
M50
Financial Capital
M129
Building a Diverse and Inclusive Workforce
M56
Cash Flows
M131
Delivering Reliable and Affordable Energy
M60
Other Consolidated Analysis
M133
Sustainability Governance
M62
Financial Instruments
M134
Governance and Risk Management
M64
Additional IFRS Measures and Non-IFRS Measures
M155
Disclosure Controls and Procedures
This MD&A should be read in conjunction with our 2024 audited annual consolidated financial statements (the consolidated financial statements)
and our 2024 Annual Information Form (AIF), each for the fiscal year ended Dec. 31, 2024. In this MD&A, unless the context otherwise requires,
“we”, “our”, “us”, the “Company” and “TransAlta” refer to TransAlta Corporation and its subsidiaries. The consolidated financial statements have
been prepared in accordance with International Financial Reporting Standards (IFRS) for Canadian publicly accountable enterprises as issued by
the International Accounting Standards Board (IASB) and in effect at Dec. 31, 2024. All tabular amounts in the following discussion are in millions
of Canadian dollars unless otherwise noted, except amounts per share, which are in whole dollars to the nearest two decimals. This MD&A is
dated Feb. 19, 2025. Additional information respecting TransAlta, including our AIF for the year ended Dec. 31, 2024, is available on SEDAR+ at
www.sedarplus.ca, on EDGAR at www.sec.gov and on our website at www.transalta.com. Information on or connected to our website is not
incorporated by reference herein.
TransAlta Corporation
2024 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 U.S. securities laws, including the Private
Securities Litigation Reform Act of 1995 (collectively
referred to herein as "forward-looking statements").
Forward-looking statements are not facts, but only
predictions and generally can be identified by the use of
statements that include phrases such as "may", "will",
"can",
"could",
"would",
"shall",
"believe",
"expect",
"estimate",
"anticipate",
"intend",
"plan",
"forecast",
"foresee",
"potential",
"enable",
"continue"
or
other
comparable terminology. 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 about the following, among other things:
• The strategic objectives of the Company and that the
execution of the Company’s strategy will realize value for
shareholders;
• Our capital allocation and financing strategy;
• Our sustainability goals and targets, including those in
our 2024 Sustainability Report;
• Our 2025 Outlook;
• Our financial and operational performance, including our
hedge position;
• Optimizing and diversifying our existing assets;
• The increasingly contracted nature of our fleet;
• Expectations about strategies for growth and expansion,
including opportunities for Centralia redevelopment, and
data centre opportunities;
• Expected costs and schedules for planned projects;
• Expected regulatory processes and outcomes, including
in relation to the Alberta restructured energy market;
• The power generation industry and the supply and
demand of electricity;
• The cyclicality of our business;
• Expected outcomes with respect to legal proceedings;
• The expected impact of future tax and accounting
changes; and
• Expected industry, market and economic conditions.
The forward-looking statements contained in this MD&A
are based on many assumptions including, but not limited
to, the following:
• No
significant
changes
to
applicable
laws
and
regulations;
• No unexpected delays in obtaining required regulatory
approvals;
• No material adverse impacts to investment and credit
markets;
• No significant changes to power price and hedging
assumptions;
• No
significant
changes
to
gas
commodity
price
assumptions and transport costs;
• No significant changes to interest rates;
• No significant changes to the demand and growth of
renewables generation;
• No significant changes to the integrity and reliability of
our facilities;
• No significant changes to the Company's debt and credit
ratings;
• No unforeseen changes to economic and market
conditions; and
• No significant event occurring outside the ordinary
course of business.
These assumptions are based on information currently
available to TransAlta, including information obtained from
third-party sources. Actual results may differ materially
from those predicted by such assumptions.
Factors that may adversely impact what is expressed or
implied by forward-looking statements contained in this
MD&A include, but are not limited to:
• Fluctuations in power prices;
• Changes in supply and demand for electricity;
• Our ability to contract our electricity generation for prices
that will provide expected returns;
• Our ability to replace contracts as they expire;
• Risks
associated
with
development
projects
and
acquisitions;
• Any difficulty raising needed capital in the future on
reasonable terms or at all;
• Our
ability
to
achieve
our
targets
relating
to
environmental,
social
and
governance
(ESG)
performance;
• Long-term commitments on gas transportation capacity
that may not be fully utilized over time;
• Changes to the legislative, regulatory and political
environments;
• Environmental requirements and changes in, or liabilities
under, these requirements;
• Operational
risks
involving
our
facilities,
including
unplanned outages and equipment failure;
• Disruptions in the transmission and distribution of
electricity;
• Reductions in production;
• Impairments and/or writedowns of assets;
• Adverse impacts on our information technology systems
and our internal control systems, including increased
cybersecurity threats;
• Commodity risk management and energy trading risks;
M2
TransAlta Corporation
2024 Integrated Report
• Reduced labour availability and ability to continue to staff
our operations and facilities;
• Disruptions to our supply chains;
• Climate-change related risks;
• Reductions to our generating units' relative efficiency or
capacity factors;
• General economic risks, including deterioration of equity
markets, increasing interest rates or rising inflation;
• General domestic and international economic and
political developments, including potential trade tariffs;
• Industry risk and competition;
• Counterparty credit risks;
• Inadequacy or unavailability of insurance coverage;
• Increases in the Company's income taxes and any risk of
reassessments;
• Legal,
regulatory
and
contractual
disputes
and
proceedings involving the Company;
• Reliance on key personnel; and
• Labour relations matters.
The foregoing risk factors, among others, are described in
further detail in the Governance and Risk Management
section of this MD&A.
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
2024 Integrated Report
M3
Description of the Business
TransAlta Corporation is one of Canada’s largest publicly
traded power generators, owning and operating a diverse
fleet across Canada, the United States and Western
Australia. Our portfolio includes hydro, wind, solar, battery
storage, natural gas and coal, complemented by our
exceptional asset optimization and energy marketing
capabilities. As one of Canada’s largest producers of wind
and thermal generation and Alberta’s largest producer of
hydro power, TransAlta remains committed to a balanced,
technology-agnostic generation mix. With strong cash
flows underpinned by a high-quality portfolio, TransAlta
strives to deliver sustainable long-term shareholder value
in an evolving energy landscape.
The Company's goal is to deliver solutions to meet our
customers' needs for reliable, sustainable power. With over
a century of experience, TransAlta is a trusted partner
delivering tailored solutions. Our strategic priorities include
optimizing our Alberta Portfolio, executing our growth plan,
realizing the value of our legacy generating facilities,
maintaining financial strength and capital discipline,
defining the next generation of power solutions and
leading in ESG and market policy development. We are
primarily focused on opportunities within our core markets
of Canada, the United States and Western Australia.
Our sustainability goals include our commitment to cease
coal-fired generation at the end of 2025. We remain on
track to achieve our 2026 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 32 million
tonnes (MT) of CO2e or an 77 per cent reduction,
representing approximately 11 per cent of Canada's Paris
Agreement 2030 decarbonization target(1).
Portfolio of Assets
Our asset portfolio is geographically diversified with
operations across our core markets.
Our Hydro, Wind and Solar, Gas and Energy Transition
segments are responsible for operating and maintaining
our 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, transport and storage of natural gas,
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 merchant
assets and high-quality contracted assets. 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 58 per
cent of our capacity is located and 77 per cent of our
Alberta capacity is available to participate in the merchant
market. Our high-quality contracted assets provide stable
long-term cash flow and earnings, balancing our merchant
fleet.
In Alberta, the Company manages merchant exposure by
executing hedging strategies that include a significant
base of commercial and industrial (C&I) customers,
supplemented with financial hedges. A significant portion
of our thermal generation capacity in Alberta is hedged to
provide greater cash flow certainty while also capturing
higher
returns
for
our
shareholders
through
the
optimization of our merchant generation portfolio. Refer to
the 2025 Outlook section and the Optimization of the
Alberta Portfolio of this MD&A for further details.
(1)
In 2005, TransAlta's estimated scope 1 and 2 GHG emissions were 41.9 MT of CO2e, which did not receive independent limited assurance. Canada's
Paris Agreement 2030 decarbonization target assumed 293 MT of CO2e or a 40 per cent reduction from a 2005 baseline of 732 MT of CO2e.
M4
TransAlta Corporation
2024 Integrated Report
The following table provides our consolidated ownership by segment of our facilities across the regions in which we
operate as of Dec. 31, 2024:
Year ended
Dec. 31, 2024
Gross
Installed
Capacity
(MW)
Number of
facilities
Gross
Installed
Capacity
(MW)(1)
Number of
facilities
Gross
Installed
Capacity
(MW)(1)(2)
Number of
facilities(2)
Gross
Installed
Capacity
(MW)
Number of
facilities(3)
Gross
Installed
Capacity
(MW)
Number of
facilities
Alberta
834
17
764
14
3,650
15
—
—
5,248
46
Canada, excluding
Alberta
88
7
751
9
705
4
—
—
1,544
20
U.S.
—
—
1,024
10
29
1
671
2
1,724
13
Western Australia
—
—
48
3
450
6
—
—
498
9
Total
922
24
2,587
36
4,834
26
671
2
9,014
88
Hydro
Wind & Solar
Gas
Energy Transition
Total
(1)
Gross installed capacity for consolidated reporting is based on a proportionate interest held in a facility. Refer to the Plant Summary section for details.
(2) Includes 1,747 MW of capacity attributable to nine facilities acquired from Heartland, which exclude the Planned Divestitures. Refer to the Significant
and Subsequent events section.
(3) Includes the Centralia coal facility and the Skookumchuck hydro facility.
Contracted Capacity
The following table provides our contracted capacity by segment in MW and as a percentage of total gross installed
capacity of our facilities across the regions in which we operate as of Dec. 31, 2024:
As at Dec. 31, 2024
Hydro
Wind &
Solar
Gas(1)
Energy
Transition
Total
Alberta
—
336
887
—
1,223
Canada, excluding Alberta
88
751
705
—
1,544
U.S.
—
1,024
29
381
1,434
Western Australia
—
48
450
—
498
Total contracted capacity (MW)
88
2,159
2,071
381
4,699
Contracted capacity as a % of total capacity (%)
10
83
43
57
52
(1)
Includes contracted capacity of 436 MW from facilities acquired from Heartland: 376 MW in Alberta and 60 MW in Canada, excluding Alberta. The
figures exclude the contracted capacity of Planned Divestitures. Refer to the Significant and Subsequent events section.
Approximately 52 per cent of our total installed capacity is contracted. Contracts are primarily with strong creditworthy
counterparties.
The following table provides the weighted average contract life by segment of our contracted and merchant facilities
across the regions in which we operate as of Dec. 31, 2024:
As at Dec. 31, 2024
Hydro
Wind &
Solar
Gas(1)
Energy
Transition
Total
Alberta
—
7
2
—
3
Canada, excluding Alberta
15
9
7
—
8
U.S.
—
13
1
—
8
Western Australia
—
14
14
—
14
Total weighted average contract life (years)(2)
1
10
4
—
5
(1)
Total weighted average contract life calculation of our gas facilities as at Dec. 31, 2024 includes the contracts added from the acquisition of Heartland
and excludes the contracts pertaining to Planned Divestitures.
(2) The contract life of merchant facilities is included as nil years.
TransAlta Corporation
2024 Integrated Report
M5
Highlights
For the year ended Dec. 31, 2024, the Company
demonstrated
strong
financial
and
operational
performance. The results were within the upper range of
management's expectations due to active management of
the Company's merchant portfolio and hedging strategies.
During 2024, the Company settled a higher volume of
hedges at prices that were significantly above the spot
market in Alberta and achieved commercial operation at
the White Rock and Horizon Hill wind facilities. On Dec. 4,
2024, the Company also completed the acquisition of
Heartland Generation, which added 1,747 MW to gross
installed capacity. IFRS financial results include the Poplar
Hill and Rainbow Lake facilities, (collectively, the Planned
Divestitures), which the Company agreed to divest
pursuant to a consent agreement entered into with the
Commissioner of Competition for Canada. Our non-IFRS
measures and operational KPIs exclude the results of the
Planned
Divestitures.
Refer
to
the
Significant
and
Subsequent Events section of this MD&A for details on the
Heartland acquisition and the Planned Divestitures.
Year ended Dec. 31
2024
2023
2022(4)
Operational information
Availability (%)
91.2
88.8
89.8
Production (GWh)
22,811
22,029
21,258
Select financial information
Revenues
2,845
3,355
2,976
Adjusted EBITDA(1)
1,253
1,632
1,656
Earnings before income taxes
319
880
353
Net earnings attributable to common shareholders
177
644
4
Cash flows
Cash flow from operating activities
796
1,464
877
Funds from operations(1)(2)
810
1,351
1,346
Free cash flow(1)(2)
569
890
961
Per share
Weighted average number of common shares outstanding
302
276
271
Net earnings per share attributable to common shareholders, basic and diluted
0.59
2.33
0.01
Dividends declared per common share
0.24
0.22
0.21
Dividends declared per preferred share
1.36
1.33
0.25
Funds from operations per share(1)(2)
2.68
4.89
4.97
Free cash flow per share(1)(2)
1.88
3.22
3.55
As at Dec. 31
2024
2023
2022
Liquidity and capital resources
Available liquidity(5)
1,616
1,738
2,118
Adjusted net debt to adjusted EBITDA (times)
3.6
2.5
2.1
Total consolidated net debt(1)(3)
3,798
3,453
2,854
Assets and liabilities
Total assets
9,499
8,659
10,741
Total long-term liabilities(6)
5,087
5,253
5,864
Total liabilities(7)
7,656
6,995
8,752
(1)
These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Presenting
these items from period to period provides management and investors with the ability to evaluate earnings (loss) trends more readily in comparison with prior
periods’ results. Refer to the Segmented Financial Performance and Operating Results section of this MD&A for further discussion of these items, including, where
applicable, reconciliations to measures calculated in accordance with IFRS. Also, refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
(2)
Funds from operations (FFO) per share and free cash flow (FCF) per share are calculated using the weighted average number of common shares outstanding during
the period. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for the purpose of these non-IFRS ratios.
(3)
Refer to the table in the Financial Capital section of this MD&A for more details on the composition of total consolidated net debt.
(4) During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the
Company has applied this composition to all previously reported periods. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
(5) Available liquidity is calculated as a sum of total available capacity under the committed credit and term facilities and cash and cash equivalents net of
bank overdraft, less the amounts drawn under the non-committed demand facilities.
(6) Total long-term liabilities correspond to total non-current liabilities in the consolidated statements of financial position under IFRS .
(7)
Total liabilities correspond to a sum of current and non-current liabilities in the consolidated statements of financial position under IFRS.
M6
TransAlta Corporation
2024 Integrated Report
Operating Performance
Availability
The following table provides availability (%) by segment:
Year ended Dec. 31
2024
2023
2022
Hydro
90.7
90.8
96.7
Wind and Solar
93.4
86.9
83.8
Gas
92.2
91.6
94.6
Energy Transition(1)
80.0
79.8
77.2
Availability (%)
91.2
88.8
89.8
(1)
Availability adjusted for dispatch optimization for the year ended 2022 was 79 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 an indicator of the overall
performance of the fleet.
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 operations. In high
price environments, actual outage schedules may change
to accelerate the return to service of the unit.
2024 versus 2023
Availability for the year ended Dec. 31, 2024, was 91.2 per
cent, compared to 88.8 per cent in 2023, consistent with
management's expectations. Higher availability compared
to the prior year was primarily due to:
• The addition of the White Rock and Horizon Hill wind
facilities; and
• The return to service of the Kent Hills wind facilities.
2023 versus 2022
Availability for the year ended Dec. 31, 2023, was 88.8 per
cent, compared to 89.8 per cent in 2022. Lower availability
compared to the prior year 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
The following table provides the long-term average generation (LTA generation) on a consolidated basis for each of our
segments:
2024
2023
2022
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
1,723
2,015
86%
1,769
2,015
88%
1,988
2,015
99%
Wind and Solar
5,949
6,876
87%
4,243
5,127
83%
4,248
4,950
86%
Gas
12,317
11,873
11,448
Energy Transition
2,822
4,144
3,574
Total
22,811
22,029
21,258
TransAlta Corporation
2024 Integrated Report
M7
In addition to availability, the Company uses LTA
generation as another indicator of performance for the
renewable facilities 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
broadly 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.
The LTA generation for Gas and Energy Transition is not
applicable as these facilities are dispatchable and their
production is largely dependent on market conditions and
merchant demand.
2024 versus 2023
Total production for 2024 increased by 782 GWh, or four
per cent, compared to 2023, primarily due to:
• Production from new facilities, including the White Rock
West and East wind facilities commissioned in January
and April 2024, respectively, the Horizon Hill wind facility
commissioned in May 2024, and the Northern Goldfields
solar facilities commissioned in November 2023;
• Production from the facilities acquired with Heartland;
• Favourable market conditions in the Ontario wholesale
power market that enabled higher dispatch at the Sarnia
facility in the Gas segment that resulted in higher
merchant production to the Ontario grid;
• The return to service of the Kent Hills wind facilities in
the first quarter of 2024; and
• Full-year production from the Garden Plain wind facility;
partially offset by
• Increased economic dispatch at the Centralia facility due
to lower market prices compared to the prior year in the
Energy Transition segment; and
• Higher dispatch optimization in Alberta.
2023 versus 2022
Total production for 2023, increased by 771 GWh, or four
per cent, compared to 2022, primarily due to:
• Lower planned and unplanned outages at the Centralia
facility in the Energy Transition segment compared to
prior year, which allowed the Company to increase
dispatch during the periods of higher merchant pricing;
• Higher availability in the Gas segment during periods of
supply tightness, allowing for the Company to operate
during periods of peak pricing;
• Production from new facilities, including the Garden Plain
wind facility, commissioned in August 2023 and the
Northern Goldfields solar facilities in November 2023;
and
• The partial return to service of the Kent Hills wind
facilities in the fourth quarter of 2023, partially offset by
• Lower than average wind and water resources in the
year;
• Lower availability in the Hydro segment due to increased
planned maintenance outages compared to 2022; and
• Relatively mild weather in the fourth quarter of 2023,
compared to the same period in 2022 when markets
experienced tighter supply due to the extreme cold
weather in Alberta.
M8
TransAlta Corporation
2024 Integrated Report
Market Pricing
Year ended Dec. 31, 2024
2024
2023
2022
Alberta spot power price ($/MWh)
63
134
162
Mid-Columbia spot power price (US$/MWh)
56
76
82
Ontario spot power price ($/MWh)
32
28
47
Natural gas price (AECO) per GJ ($)
1.29
2.54
5.08
For the year ended Dec. 31, 2024, spot electricity prices in
Alberta were 53 per cent lower compared to 2023, driven
by lower natural gas prices and the anticipated increased
supply from new renewable and combined-cycle gas
facilities.
Spot electricity prices in the Pacific Northwest were 26 per
cent lower compared to 2023 due to lower natural gas
prices.
AECO natural gas prices for the year ended Dec. 31, 2024,
were 49 per cent lower compared to 2023, mainly due to
higher gas production and higher storage levels in Alberta
and throughout North America.
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
of 2023 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 increased
production
and
storage
levels
in
Alberta
and
North America.
Financial Performance Review of Consolidated Information
Year ended Dec. 31
2024
2023
2022
Revenues
2,845
3,355
2,976
Fuel and purchased power
939
1,060
1,263
Carbon compliance
112
112
78
Operations, maintenance and administration
655
539
521
Depreciation and amortization
531
621
599
Asset impairment charges (reversals)
46
(48)
9
Interest income
30
59
24
Interest expense
324
281
286
Earnings before income taxes
319
880
353
Income tax expense
80
84
192
Net earnings attributable to common shareholders
177
644
4
Net earnings attributable to non-controlling interests
10
101
111
2024 versus 2023
Revenues
totalling
$2,845
million,
decreased
by
$510 million, or 15 per cent, compared to 2023, primarily
due to:
• Lower merchant spot and hedged power prices in the
Alberta market;
• Lower revenue from derivatives and other trading
activities in the Wind and Solar segment driven by higher
unrealized mark-to-market losses on the long-term wind
energy sales related to the Oklahoma facilities, primarily
due to strengthening forecasted wind capture prices
reflected in the year; and
• Lower revenue at Centralia due to higher economic
dispatch driven by lower market prices; partially offset by
• Higher revenue from derivatives and other trading
activities in the Gas segment driven by higher volume of
favourable hedging positions settled, which generated
positive contributions over settled spot prices in Alberta;
TransAlta Corporation
2024 Integrated Report
M9
• Higher environmental and tax attributes revenues from
the Hydro segment and the sale of production tax credits
from the Oklahoma wind facilities to taxable U.S.
counterparties;
• Commercial operation of the White Rock and Horizon Hill
wind facilities, the Northern Goldfields solar facilities, the
Mount Keith 132kV expansion and return to service of the
Kent Hills wind facilities; and
• Higher revenue in the Gas segment with the acquisition
of Heartland.
Fuel and purchased power costs totalling $939 million,
decreased by $121 million, or 11 per cent, compared to
2023, primarily due to:
• Lower purchased power costs driven by lower Mid-
Columbia prices on repurchases of power;
• Lower
fuel
consumption
due
to
higher
dispatch
optimization in the Gas segment in Alberta and higher
economic dispatch in the Energy Transition segment; and
• Lower natural gas prices.
Carbon compliance costs totalling $112 million, were
consistent with 2023, primarily due to:
• Utilization
of
internally
generated
and
externally
purchased emission credits to settle a portion of our
2023 GHG obligation; offset by
• An increase in the carbon price from $65 per tonne in
2023 to $80 per tonne in 2024; and
• Higher production in the Gas segment.
OM&A expenses totalling $655 million, increased by $116
million, or 22 per cent, compared to 2023, primarily due to:
• Penalties assessed by the Alberta Market Surveillance
Administrator for self-reported contraventions pertaining
to hydro ancillary services provided during 2021 and
2022;
• Higher spend to support strategic and growth initiatives;
• The addition of the White Rock and Horizon Hill wind
facilities and the return to service of the Kent Hills wind
facilities;
• The
Heartland
acquisition-related
transaction
and
restructuring costs, mainly comprising severance, legal
and consulting fees; and
• Higher spending related to the planning and design of an
upgrade to our enterprise resource planning (ERP)
system.
Depreciation and amortization totalling $531 million,
decreased by $90 million, or 14 per cent, compared to
2023, primarily due to:
• Revisions to useful lives of certain facilities in prior and
current periods; partially offset by
• Commercial operation of the White Rock and Horizon Hill
wind facilities and return to service of the Kent Hills wind
facilities.
Asset impairment charges totalling $46 million, increased
by $94 million, compared to asset impairment recoveries in
2023, primarily due to:
• An
increase
in
decommissioning
and
restoration
provisions on retired assets driven by a decrease in
discount
rates
and
revisions
in
estimated
decommissioning costs; and
• Impairment charges related to development projects that
are no longer proceeding.
Interest income totalling $30 million, decreased by
$29 million, or 49 per cent, compared to 2023, primarily
due to lower cash balances and lower interest rates.
Interest expense totalling $324 million, increased by 43
million, or 15 per cent, compared to 2023, primary due to
lower capitalized interest resulting from lower construction
activity in 2024 compared to 2023.
Earnings before income taxes totalling $319 million,
decreased by $561 million, or 64 per cent, compared to
2023, due to the above noted items. Refer to the Segment
Financial Performance and Operating Results section for
additional information.
Income tax expense totalling $80 million, decreased by $4
million, or five per cent, compared to 2023, due to:
• Lower earnings before income taxes due to the above
noted items; partially offset by
• A recovery related to the reversal of previously
derecognized Canadian deferred tax assets.
Net earnings attributable to non-controlling interests
totalling $10 million, decreased by $91 million, or 90 per
cent, compared to 2023, primarily due to lower net
earnings for TransAlta Cogeneration, LP (TA Cogen)
resulting from lower merchant pricing in the Alberta market
and the acquisition of TransAlta Renewables Inc. (TransAlta
Renewables) on Oct. 5, 2023.
M10
TransAlta Corporation
2024 Integrated Report
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.
OM&A expenses totalling $539 million, increased by $18
million, or three 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 four per cent, compared to
2022, primarily due to:
• Revisions to useful lives of certain facilities; and
• Commercial operation of new facilities.
Asset
impairment
reversals
totalling
$48
million,
increased by $57 million, 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 U.S.
non-deductible expenses relating to U.S. operations,
partially
offset
by
higher
earnings
from
Canadian operations.
Net earnings attributable to non-controlling interests
totalling $101 million, decreased by $10 million, or nine per
cent, compared to 2022, primarily due to lower net
earnings for TA Cogen.
TransAlta Corporation
2024 Integrated Report
M11
Adjusted EBITDA — 2024 versus 2023
For the year ended Dec. 31, 2024, the Company's adjusted EBITDA was $1,253 million as compared to $1,632 million in
2023, a decrease of $379 million, or 23 per cent. The major factors impacting adjusted EBITDA are summarized in the
following table:
Year ended
Dec. 31
Adjusted EBITDA for the year ended Dec. 31, 2023
1,632
Hydro: Lower primarily due to lower spot power prices and ancillary services prices in the Alberta
market, partially offset by realized premiums above the spot power prices, higher environmental and tax
attributes revenues due to higher sales of emission credits to third parties and intercompany sales to
the Gas segment and higher ancillary service volumes due to increased demand by the Alberta Electric
System Operator (AESO).
(143)
Wind and Solar: Higher primarily due to new sales of production tax credits, the return to service of the
Kent Hills wind facilities, the commercial operation of the White Rock and Horizon Hill wind facilities,
partially offset by lower realized power pricing in the Alberta market and higher OM&A due to the
addition of new wind facilities.
59
Gas: Lower primarily due to lower power prices in the Alberta market and resulting increase in economic
dispatch, an increase in the price of carbon, higher carbon costs and fuel usage related to production
and lower capacity payments, partially offset by a higher volume of favourable hedging positions
settled, the utilization of emission credits to settle a portion of our 2023 GHG obligation and lower
natural gas prices.
(266)
Energy Transition: Lower primarily due to increased economic dispatch driven by lower market prices
which negatively impacted merchant production, partially offset by lower fuel and purchased power
costs.
(31)
Energy Marketing: Higher primarily due to favourable market volatility and the timing of realized settled
trades during the current year in comparison to the prior year and lower OM&A.
22
Corporate: Lower primarily due to higher spend to support strategic and growth initiatives.
(20)
Adjusted EBITDA(1) for the year ended Dec. 31, 2024
1,253
(1)
Adjusted EBITDA is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other
issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A. For a comparison of 2024 and 2023 earnings before
income tax, the most directly comparable IFRS measure, see pages M67-M68
M12
TransAlta Corporation
2024 Integrated Report
Adjusted EBITDA — 2023 versus 2022
For the year ended Dec. 31, 2023, the Company's adjusted EBITDA was $1,632 million compared to $1,656 million in
2022, a decrease of $24 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)
1,656
Hydro: Lower primarily due to lower ancillary services volumes, lower spot power and ancillary services
prices in the Alberta market, lower production due to lower availability and lower than average water
resources, partially offset by realized gains from hedging strategy and sales of environmental attributes.
(90)
Wind and Solar: Lower primarily due to lower environmental attribute revenues, lower realized power
prices in Alberta, lower wind resource across the operating fleet, 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 to 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.
172
Energy Transition: Higher primarily due to higher production from higher availability and 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.
(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(2) for the year ended Dec. 31, 2023
1,632
(1)
During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the
Company has applied this composition to all previously reported periods. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
(2) Adjusted EBITDA is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other
issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A. For a comparison of 2023 and 2022 earnings before
income tax, the most directly comparable IFRS measure, see pages M68-M69.
TransAlta Corporation
2024 Integrated Report
M13
Free Cash Flow — 2024 versus 2023
For the year ended Dec. 31, 2024, the Company's FCF decreased by $321 million, or 36 per cent, compared to 2023, but
was within the upper range of our 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, 2023
890
Lower Adjusted EBITDA due to the items noted above.
(379)
Higher current income tax expense due to the full utilization of Canadian non-capital loss carryforwards
in 2023, partially offset by lower earnings before income taxes in 2024 compared to the prior year.
(93)
Higher net interest expense(1) due to lower capitalized interest resulting from lower construction activity
in 2024 compared to 2023 and lower interest income due to lower cash balances and interest rates in
2024 compared to prior year.
(67)
Lower distributions paid to subsidiaries' non-controlling interests relating to lower TA Cogen net
earnings resulting from lower merchant pricing in the Alberta market and the cessation of distributions
to TransAlta Renewables non-controlling interest. On Oct. 5, 2023, the Company acquired all of the
outstanding common shares of TransAlta Renewables not already owned, directly or indirectly.
183
Higher provisions accrued in the current year compared to the prior year resulting in higher FCF.
11
Lower sustaining capital expenditures due to the receipt of a lease incentive related to the Company's
head office, and lower planned major maintenance at our Alberta and Western Australian gas facilities,
partially offset by higher major maintenance at our Alberta Hydro facilities.
32
Other non-cash items(2)
14
Other(3)
(22)
FCF(4) for the year ended Dec. 31, 2024
569
(1)
Net interest expense includes interest expense less interest income and excludes non-cash items like financing amortization and accretion.
(2) Other non-cash items consists of Alberta market pool incentives, carbon obligation and contract liabilities. Refer to the Reconciliation of Cash Flow from
Operations to FFO and FCF section tables in this MD&A for more details.
(3) Other consists of higher realized foreign exchange loss, higher decommissioning and restoration costs settled, higher dividends paid on preferred
shares, lower principal payments on lease liabilities and lower productivity capital. Refer to the Reconciliation of Cash Flow from Operations to FFO and
FCF section tables in this MD&A for more details.
(4) FCF is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to
the Additional IFRS Measures and Non-IFRS Measures section of this MD&A. For a comparison of 2024 and 2023 cash flow from operations, the most
directly comparable IFRS measure, see page M56.
M14
TransAlta Corporation
2024 Integrated Report
Free Cash Flow — 2023 versus 2022
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 due to the items noted above.
(24)
Higher interest income due to higher cash balances and favourable interest rates.
35
Lower current income tax expense due to previously restricted non-capital loss carryforwards that were
utilized to offset taxable income.
15
Higher sustaining capital expenditures due to higher planned major maintenance costs for the Hydro
and Gas segments, partially offset by lower planned major maintenance in the Wind and Solar and
Energy Transition segments.
(32)
Higher distributions paid to subsidiaries' non-controlling interests related to the timing of distributions
paid to TA Cogen, partially offset by lower distributions paid to TransAlta Renewables.
(36)
Lower provisions being accrued compared to the prior year, with no notable settlements being recorded
in either year.
(26)
Other non-cash items(1)
11
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, the SunHills royalty onerous contract and Brazeau
penalties. 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 and may not be comparable to similar measures presented by other issuers. Refer to
the Additional IFRS Measures and Non-IFRS Measures section of this MD&A. For a comparison of 2023 and 2022 cash flow from operations, the most
directly comparable IFRS measure, see page M57.
TransAlta Corporation
2024 Integrated Report
M15
Capital Expenditures
Sustaining Capital Expenditures
We are in a long-cycle business that requires significant
capital expenditures. Our goal is to undertake sustaining
capital expenditures that ensure our facilities operate
reliably and safely.
The Company's sustaining capital expenditures by segment are summarized in the table below:
Year ended Dec. 31
2024
2023
2022
Hydro
56
41
35
Wind and Solar
20
15
18
Gas
52
76
41
Energy Transition
12
15
19
Corporate
2
27
29
Sustaining capital expenditures
142
174
142
Total sustaining capital expenditures in 2024 were $32
million lower compared to 2023, primarily due to:
• The receipt of a lease incentive related to the Company's
head office, included in the Corporate segment; and
• Lower planned major maintenance at our Alberta and
Western Australian gas facilities; partially offset by
• Higher major maintenance at our Alberta hydro assets;
and
• Higher major maintenance at our Wind and Solar facilities.
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.
M16
TransAlta Corporation
2024 Integrated Report
Growth and Development Expenditures
Growth and development expenditures are impacted by the timing and construction of projects within the development
pipeline. The following table provides our growth and development spending by segment:
Year ended Dec. 31
2024
2023
2022
Hydro
9
6
2
Wind and Solar
64
673
711
Gas
59
60
61
Growth and development expenditures
132
739
774
Growth and development expenditures were lower in 2024
compared to 2023 and 2022, as many of the development
projects achieved commercial operation in the first half of
2024. The White Rock East and Horizon Hill wind facilities
were commissioned in the second quarter of 2024. The
White Rock West wind facility and Mount Keith 132kV
expansion were commissioned in the first quarter of 2024.
Refer to the Strategic Priorities section of this MD&A for
more details.
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 and the Horizon Hill wind projects; and
• The Mount Keith 132kV expansion.
Significant and Subsequent Events
Declared Increase in Common Share
Dividend
The Company’s Board of Directors has approved a $0.02
annualized increase to the common share dividend, or 8
per cent increase, and declared a dividend of $0.065 per
common share to be payable on July 1, 2025 to
shareholders of record at the close of business on June 1,
2025. The quarterly dividend of $0.065 per common share
represents an annualized dividend of $0.26 per common
share.
TransAlta Acquires Heartland Generation
from Energy Capital Partners
On Dec. 4, 2024, the Company closed the acquisition of
Heartland
Generation
Ltd.
and
certain
affiliates
(collectively, Heartland) for a purchase price of $542
million from an affiliate of Energy Capital Partners (ECP),
the parent of Heartland (the Transaction). To meet the
requirements of the federal Competition Bureau, the
Company entered into a consent agreement with the
Commissioner of Competition pursuant to which TransAlta
agreed to divest Heartland's Poplar Hill and Rainbow Lake
assets (the Planned Divestitures) following closing of the
Transaction. In consideration of the Planned Divestitures,
TransAlta and ECP agreed to a reduction of $80 million
from the original purchase price for the Transaction. ECP
will be entitled to receive the proceeds from the sale of
Poplar Hill and Rainbow Lake, net of certain adjustments
following completion of the Planned Divestitures. TransAlta
also received a further $95 million at closing of the
Transaction to reflect the economic benefit of the
Heartland business arising from Oct. 31, 2023 to the
closing date of the Transaction, pursuant to the terms of
the share purchase agreement. The net cash payment for
the Transaction, before working capital adjustments,
totalled
$215
million,
and
was
funded
through
a
combination of cash on hand and draws on TransAlta's
credit facilities.
Excluding the Planned Divestitures, the Transaction adds
1,747 MW (net interest) of complementary capacity from
nine facilities, including contracted cogeneration and
peaking generation, legacy gas-fired thermal generation,
and transmission capacity, all of which will be critical to
support reliability in the Alberta electricity market.
Mothballing of Sundance Unit 6
On Nov. 4, 2024, the Company provided notice to the
AESO that Sundance Unit 6 will be mothballed on April 1,
2025, for a period of up to two years depending on market
conditions. TransAlta maintains the flexibility to return the
mothballed unit to service when market fundamentals
improve or opportunities to contract are secured. The unit
remains available and fully operational for the first quarter
of 2025.
TransAlta Corporation
2024 Integrated Report
M17
Appointment of New Chief Financial
Officer (CFO)
The Board appointed Joel Hunter as Executive Vice
President, Finance and CFO, effective July 1, 2024.
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 and the Horizon Hill
wind facilities.
On June 21, 2024, the Company entered into an additional
10-year transfer agreement with an A+ rated customer for
the sale of the remaining 20 per cent of the expected
PTCs.
The expected average annual EBITDA from the two
agreements is approximately $78 million (US$57 million).
Normal Course Issuer Bid (NCIB)
TransAlta remains committed to enhancing shareholder
returns through appropriate capital allocation such as
share buybacks and its quarterly dividend. In the first
quarter of 2024, the Company announced an enhanced
common share repurchase program for 2024, allocating up
to $150 million, and targeting up to 42 per cent of 2024
FCF guidance, to be returned to shareholders in the form
of share repurchases and dividends.
On May 27, 2024, the Company announced that it had
received approval from the Toronto Stock Exchange to
purchase up to 14 million common shares during the 12-
month period that commenced May 31, 2024, and
terminates May 31, 2025. Any common shares purchased
under the NCIB will be cancelled.
For the year ended Dec. 31, 2024, the Company purchased
and cancelled a total of 13,467,400 common shares, at an
average price of $10.59 per common share, for a total cost
of $143 million, including taxes.
Horizon Hill Wind Facility Achieves
Commercial Operation
On May 21, 2024, the 202 MW Horizon Hill wind facility
achieved commercial operation. The facility is located in
Logan County, Oklahoma and is fully contracted to Meta
Platforms Inc. for the offtake of 100 per cent of the
generation.
White Rock Wind Facilities Achieve
Commercial Operation
On Jan. 1, 2024, the 100 MW White Rock West wind facility
achieved commercial operation. On April 22, 2024, the 202
MW White Rock East wind facility also completed
commissioning. The facilities are located in Caddo County,
Oklahoma and are contracted under two long-term power
purchase agreements (PPAs) with Amazon Energy LLC for
the offtake of 100 per cent of the generation.
Mount Keith 132kV Expansion Complete
The Mount Keith 132kV expansion project was completed
during the first quarter of 2024. The expansion was
developed under the existing PPA with BHP Nickel West
(BHP), which extends until Dec. 31, 2038. The expansion
will facilitate the connection of additional generating
capacity to the transmission network which supports BHP's
operations.
M18
TransAlta Corporation
2024 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
2024
2023
2022(2)
Hydro
316
459
549
Wind and Solar
316
257
311
Gas
535
801
629
Energy Transition
91
122
86
Energy Marketing
131
109
183
Corporate
(136)
(116)
(102)
Total adjusted EBITDA(1)
1,253
1,632
1,656
Earnings before income taxes
319
880
353
(1)
This item is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer
to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(2) During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the
Company has applied this composition to all previously reported periods. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
2024 versus 2023
Earnings before income taxes for the year ended Dec. 31,
2024, decreased by $561 million, or 64 per cent, compared
to 2023, primarily due to:
• The factors causing lower adjusted EBITDA above;
• Higher asset impairment charges related to an increase in
the decommissioning provision on retired assets, driven
by a decrease in discount rates and revisions in
estimated decommissioning costs, and higher impairment
charges related to development projects that are no
longer proceeding;
• Lower unrealized mark-to-market gains and lower
realized gains on closed exchange positions in the
Energy Marketing segment mainly driven by market
volatility across North American power and natural gas
markets;
• Higher unrealized mark-to-market losses recorded in the
Wind and Solar segment primarily related to the long-
term wind energy sales related to the Oklahoma facilities;
• Higher interest expense due to lower capitalized interest
during 2024 resulting from lower construction activity in
2024 compared to 2023;
• Lower capacity payments in 2024 for Southern Cross
Energy in Western Australia due to the scheduled
conclusion on Dec. 31, 2023, of the demand capacity
charge under the customer contract, partially offset by
the commencement in March 2024 of capacity payments
for the Mount Keith 132kV expansion;
• Heartland
acquisition-related
transaction
and
restructuring costs;
• Lower interest income due to lower cash balances and
lower interest rates during 2024;
• Higher spending relating to planning and design work on
a planned upgrade to our ERP system; and
• Penalties assessed by the Alberta Market Surveillance
Administrator for self-reported contraventions pertaining
to Hydro ancillary services provided during 2021 and
2022; partially offset by
• Lower depreciation and amortization compared to 2023
related to revisions of useful lives of certain facilities in
prior and current periods, partially offset by the
commercial operation of new facilities during the year
and the return to service of the Kent Hills wind facilities;
• Higher unrealized mark-to-market gains recorded in the
Energy Transition segment primarily related to the
favourable changes in forward prices; and
• Higher net other operating income mainly due to
Sundance A decommissioning cost reimbursement.
2023 versus 2022
Earnings before income taxes for the year ended Dec. 31,
2023, increased by $527 million, or 149 per cent,
compared to 2022, primarily due to:
TransAlta Corporation
2024 Integrated Report
M19
• Higher unrealized mark-to-market gains in in the Gas
segment primarily related to higher power price hedges;
• Higher unrealized mark-to-market gains in the Wind and
Solar segment primarily related to Garden Plain and Big
Level, partially offset by unrealized mark-to-market
losses related to the Oklahoma facilities;
• Higher
realized
mark-to-market
losses
on
closed
exchange positions in the Energy Marketing segment
mainly driven by market volatility across the North
American power and natural gas markets;
• Higher asset impairment reversals for the Hydro and
Wind and Solar segments due to favourable changes in
power price assumptions and contract extensions,
partially offset by a change in decommissioning and
restoration provisions for retired assets due to a change
in the timing of expected cash outflows and the revisions
in discount rates;
• Higher interest income due to higher cash balances and
favourable interest rates; partially offset by
• Lower adjusted EBITDA (as described above);
• Lower gain on sale of assets in 2023. In 2022 the
Company closed the sale of two hydro facilities and sold
equipment related to its Energy Transition segment; and
• Higher depreciation and amortization due to revisions to
useful lives of certain facilities and commercial operation
of new facilities.
M20
TransAlta Corporation
2024 Integrated Report
Hydro
Year ended Dec. 31
2024
2023
Change
2022(7)
Change
Gross installed capacity (MW)
922
922
—
— %
922
—
— %
LTA generation (GWh)
2,015 2,015
—
— %
2,015
—
— %
Availability (%)
90.7
90.8
(0.1)
— %
96.7
(5.9)
(6) %
Production
Contract production (GWh)
281
277
4
1 %
323
(46)
(14) %
Merchant production (GWh)
1,442 1,492
(50)
(3) %
1,665
(173)
(10) %
Total energy production (GWh)
1,723 1,769
(46)
(3) %
1,988
(219)
(11) %
Ancillary service volumes (GWh)(1)
2,951 2,582
369
14 %
3,124
(542)
(17) %
Alberta Hydro Assets revenues(2)(3)
144
291
(147)
(51) %
328
(37)
(11) %
Other Hydro Assets and other revenues(2)(4)
49
51
(2)
(4) %
42
9
21 %
Alberta Hydro ancillary services revenues
136
173
(37)
(21) %
256
(83)
(32) %
Environmental and tax attributes revenues
61
14
47
336 %
1
13
1300 %
Adjusted revenues(5)
390
529
(139)
(26) %
627
(98)
(16) %
Fuel and purchased power
16
19
(3)
(16) %
22
(3)
(14) %
Adjusted gross margin(6)
374
510
(136)
(27) %
605
(95)
(16) %
Adjusted OM&A(5)
55
48
7
15 %
53
(5)
(9) %
Taxes, other than income taxes
3
3
—
— %
3
—
— %
Adjusted EBITDA(6)
316
459
(143)
(31) %
549
(90)
(16) %
Supplemental Information:
Gross revenues per MWh
Alberta Hydro Assets energy ($/MWh)(2)(3)
100
195
(95)
(49) %
197
(2)
(1) %
Alberta Hydro Assets ancillary ($/MWh)(1)
46
67
(21)
(31) %
76
(9)
(12) %
(1)
Ancillary services as described in the AESO Consolidated Authoritative Document Glossary.
(2) Alberta Hydro Assets include 13 hydro facilities on the Bow and North Saskatchewan river systems. Other Hydro Assets include our hydro facilities in
British Columbia, Ontario and Alberta (other than the Alberta Hydro Assets).
(3) Alberta Hydro Assets revenues include revenues from swaps and forward hedges.
(4) Other revenues includes revenues from our transmission business and other contractual arrangements, including the flood mitigation agreement with
the Government of Alberta and black start services.
(5) For details of the adjustments to revenues and OM&A included in adjusted EBITDA refer to the Additional IFRS and Non-IFRS Measures section of this
MD&A.
(6) Adjusted EBITDA and adjusted gross margin are not defined and have no standardized meaning under IFRS and may not be comparable to similar
measures presented by other issuers. Refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.
(7)
During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the
Company has applied this composition to all previously reported periods. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
TransAlta Corporation
2024 Integrated Report
M21
2024 versus 2023
Adjusted revenues for the year ended Dec. 31, 2024,
decreased compared to 2023, primarily due to:
• Lower spot power prices and ancillary services prices in
the Alberta market; partially offset by
• Realized premiums above spot power prices and positive
contributions from hedging;
• Higher environmental and tax attributes revenues due to
increased sales of emission credits to third parties and
intercompany sales to the Gas segment; and
• Higher ancillary services volumes due to increased
demand by the AESO.
Adjusted EBITDA for the year ended Dec. 31, 2024,
decreased compared to 2023, primarily due to lower
adjusted 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.
2023 versus 2022
Adjusted 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
adjusted revenues as explained by the factors above.
M22
TransAlta Corporation
2024 Integrated Report
Wind and Solar
Year ended Dec. 31
2024
2023
Change
2022
Change
Gross installed capacity (MW)(1)
2,587
2,084
503
24 %
1,906
178
9 %
LTA generation (GWh)
6,876
5,127
1,749
34 %
4,950
177
4 %
Availability (%)
93.4
86.9
6.5
7 %
83.8
3.1
4 %
Production
Contract production (GWh)
4,720
3,095
1,625
53 %
3,182
(87)
(3) %
Merchant production (GWh)
1,229
1,148
81
7 %
1,066
82
8 %
Total production (GWh)
5,949
4,243
1,706
40 %
4,248
(5)
— %
Revenues
372
347
25
7 %
357
(10)
(3) %
Environmental and tax attributes revenues
77
26
51
196 %
50
(24)
(48) %
Adjusted revenues(2)
449
373
76
20 %
407
(34)
(8) %
Fuel and purchased power
30
30
—
— %
31
(1)
(3) %
Carbon compliance
—
—
—
— %
1
(1)
(100) %
Adjusted gross margin(3)
419
343
76
22 %
375
(32)
(9) %
Adjusted OM&A(2)
97
80
17
21 %
68
12
18 %
Taxes, other than income taxes
16
12
4
33 %
12
—
— %
Net other operating income
(10)
(6)
(4)
67 %
(16)
10
(63) %
Adjusted EBITDA(3)
316
257
59
23 %
311
(54)
(17) %
(1)
Gross installed capacity and availability for 2024 include the 100 MW White Rock West and 202 MW White Rock East wind facilities that achieved
commercial operation in January and April 2024, respectively, and the 202 MW Horizon Hill wind facility that achieved commercial operation in May
2024.Tower removal at Sinott in 2025, reduced gross installed capacity by 1 MW. Gross installed capacity and availability for 2024 and 2023 include 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 OM&A included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures
section of this MD&A. The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(3) Adjusted EBITDA and adjusted gross margin are not defined and have no standardized meaning under IFRS and may not be comparable to similar
measures presented by other issuers. Refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.
TransAlta Corporation
2024 Integrated Report
M23
2024 versus 2023
Adjusted revenues for the year ended Dec. 31, 2024,
increased compared to 2023, primarily due to:
• Higher environmental and tax attributes revenues from
the sale of production tax credits from Horizon Hill and
White Rock West and East wind facilities to taxable US
counterparties;
• Higher production from the return to service of the Kent
Hills wind facilities; and
• Commercial operation of the Horizon Hill and White Rock
West and East wind facilities; partially offset by
• Lower realized power prices in the Alberta market.
Adjusted EBITDA for the year ended Dec. 31, 2024,
increased compared to the same period in 2023, primarily
due to:
• Higher adjusted revenues as explained by the factors
above; partially offset by
• Higher OM&A mainly due to the addition of new wind
facilities.
2023 versus 2022
Adjusted 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 realized power prices 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 adjusted 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.
M24
TransAlta Corporation
2024 Integrated Report
Gas
Year ended Dec. 31
2024
2023
Change
2022
Change
Gross installed capacity (MW)(1)
4,834
3,084
1,750
57 %
3,084
—
— %
Availability (%)
92.2
91.6
0.6
1 %
94.6
(3.0)
(3) %
Production
Contract sales volume (GWh)
6,874
4,322
2,552
59 %
3,806
516
14 %
Merchant sales volume (GWh)
6,576
7,889
(1,313)
(17) %
7,927
(38)
— %
Purchased power (GWh)(2)
(1,133)
(338)
(795)
235 %
(285)
(53)
19 %
Total production (GWh)
12,317
11,873
444
4 % 11,448
425
4 %
Adjusted revenues(3)
1,321
1,525
(204)
(13) %
1,521
4
— %
Adjusted fuel and purchased power(3)
470
449
21
5 %
637
(188)
(30) %
Carbon compliance
145
112
33
29 %
83
29
35 %
Adjusted gross margin(4)
706
964
(258)
(27) %
801
163
20 %
OM&A
198
192
6
3 %
195
(3)
(2) %
Taxes, other than income taxes
13
11
2
18 %
15
(4)
(27) %
Net other operating income
(40)
(40)
—
— %
(38)
(2)
5 %
Adjusted EBITDA(4)
535
801
(266)
(33) %
629
172
27 %
(1)
Gross installed capacity and availability for 2024 include the 1,747 MW Heartland gas facilities and exclude the Planned Divestitures. Refer to the
Significant and Subsequent events section. Gross installed capacity for Keephills Unit 3 was adjusted by 3 MW during 2024 due to reduced equipment
load.
(2) Power required to fulfil contractual obligations during planned and unplanned outages is included in purchased power.
(3) 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.
(4) Adjusted EBITDA and adjusted gross margin are not defined and have no standardized meaning under IFRS and may not be comparable to similar
measures presented by other issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
2024 versus 2023
The Gas fleet performance was broadly in line with
management's expectations for the segment.
Adjusted revenues for the year ended Dec. 31, 2024,
decreased compared to 2023, primarily due to:
• Lower power prices in the Alberta market;
• Increased dispatch optimization from Alberta Gas
facilities driven by lower power prices; and
• Lower capacity payments in 2024 for Southern Cross
Energy in Western Australia due to the scheduled
conclusion on Dec. 31, 2023, of the demand capacity
charge under the customer contract, partially offset by
the commencement in March 2024 of capacity payments
for the Mount Keith 132kV expansion; partially offset by
• Higher volume of favourable hedging positions settled,
which generated positive contributions over settled spot
prices in Alberta.
Adjusted EBITDA for the year ended Dec. 31, 2024,
decreased compared to 2023, primarily due to:
• Lower adjusted revenues explained above;
• An increase in the carbon price from $65 to $80
per tonne, impacting gross margin from our Canadian gas
facilities; and
• Higher carbon costs and fuel usage related to
production; partially offset by
• The utilization of emission credits to settle a portion of
our 2023 GHG obligation; and
• Lower natural gas prices.
TransAlta Corporation
2024 Integrated Report
M25
2023 versus 2022
Adjusted 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
facilities; and
• Higher adjusted 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 facilities.
M26
TransAlta Corporation
2024 Integrated Report
Energy Transition
Year ended Dec. 31
2024
2023
Change
2022
Change
Gross installed capacity (MW)
671
671
—
— %
671
—
— %
Availability (%)
80.0
79.8
0.2
— %
77.2
2.6
3 %
Production
Contract sales volume (GWh)
3,338
3,329
9
— %
3,329
—
— %
Merchant sales volume (GWh)
3,201
4,417
(1,216)
(28) %
3,951
466
12 %
Purchased power (GWh)(1)
(3,717)
(3,602)
(115)
3 %
(3,706)
104
(3) %
Total production (GWh)
2,822
4,144
(1,322)
(32) %
3,574
570
16 %
Adjusted revenues(2)
582
746
(164)
(22) %
724
22
3 %
Fuel and purchased power
418
557
(139)
(25) %
566
(9)
(2) %
Carbon compliance
1
—
1
— %
(1)
1
(100) %
Adjusted gross margin(3)
163
189
(26)
(14) %
159
30
19 %
OM&A
69
64
5
8 %
69
(5)
(7) %
Taxes, other than income taxes
3
3
—
— %
4
(1)
(25) %
Adjusted EBITDA(3)
91
122
(31)
(25) %
86
36
42 %
Supplemental information:
Highvale mine reclamation spend
11
15
(4)
(27) %
12
3
25 %
Centralia mine reclamation spend
16
13
3
23 %
16
(3)
(19) %
(1)
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.
(2) For details of the adjustments to revenues included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of
this MD&A.
(3) Adjusted EBITDA and adjusted adjusted gross margin are not defined and have no standardized meaning under IFRS and may not be comparable to
similar measures presented by other issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
2024 versus 2023
Adjusted revenues for the year ended Dec. 31, 2024,
decreased compared to 2023, primarily due to increased
economic dispatch driven by lower market prices which
negatively impacted merchant production.
Adjusted EBITDA for the year ended Dec. 31, 2024,
decreased compared to 2023, primarily due to:
• Lower revenues as explained by the factors above;
partially offset by
• Lower fuel and purchased power costs due to lower Mid-
Columbia prices on purchases of power and lower
production volumes.
Mine reclamation spending for the year ended Dec. 31,
2024, was consistent with 2023.
2023 versus 2022
Adjusted 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 spending for the year ended Dec. 31,
2023, was consistent with 2022.
TransAlta Corporation
2024 Integrated Report
M27
Energy Marketing
Year ended Dec. 31
2024
2023
Change
2022
Change
Adjusted revenues(1)
167
152
15
10 %
218
(66)
(30) %
OM&A
36
43
(7)
(16) %
35
8
23 %
Adjusted EBITDA(2)
131
109
22
20 %
183
(74)
(40) %
(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.
(2) Adjusted EBITDA is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other
issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
2024 versus 2023
Adjusted revenues and Adjusted EBITDA for the year
ended Dec. 31, 2024, increased compared to 2023,
primarily due to favourable market volatility across North
American power and natural gas markets and higher
realized settled trades in 2024 in compared to the prior
year, primarily due to:
• 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; and
• A decrease in OM&A mainly due to lower incentives
related to revenue before adjustments compared to the
prior year.
2023 versus 2022
Adjusted revenues and 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
• An increase in OM&A mainly due to higher incentives
related to revenues before adjustments.
Corporate
Year ended Dec. 31
2024
2023
Change
2022
Change
Adjusted OM&A(1)
135
115
20
17%
101
14
14%
Taxes, other than income taxes
1
1
—
—%
1
—
—%
Adjusted EBITDA(2)
(136)
(116)
(20)
17%
(102)
(14)
14%
(1)
For details of the adjustments to OM&A included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
(2) Adjusted EBITDA is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other
issuers Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
2024 versus 2023
Adjusted EBITDA for the year ended Dec. 31, 2024,
decreased compared to 2023, primarily due to increased
spending to support strategic and growth initiatives related
to early stage growth projects.
2023 versus 2022
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.
M28
TransAlta Corporation
2024 Integrated Report
Performance by Segment with Supplemental
Geographical Information
The following table provides adjusted EBITDA by segment across the regions we operate in:
Year ended Dec. 31, 2024
Hydro
Wind &
Solar
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
Alberta
307
51
340
(10)
131
(136)
683
Canada, excluding Alberta
9
122
91
—
—
—
222
U.S.
—
135
12
101
—
—
248
Western Australia
—
8
92
—
—
—
100
Adjusted EBITDA(1)
316
316
535
91
131
(136)
1,253
Earnings before income taxes
319
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
U.S.
—
84
10
132
—
—
226
Western Australia
—
1
131
—
—
—
132
Adjusted EBITDA(1)
459
257
801
122
109
(116)
1,632
Earnings before income taxes
880
(1)
Adjusted EBITDA is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other
issuers. Refer to the 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 58 per
cent of our capacity is located, 77 per cent of which is
available to participate in the merchant market. Our
portfolio of assets consists of hydro, wind, battery storage
and natural gas generation facilities.
The acquisition of Heartland enhances and further
diversifies TransAlta’s competitive portfolio in the highly
dynamic and shifting electricity landscape in Alberta, by
adding 507 MW of contracted cogeneration capacity, 387
MW of contracted and merchant peaking generation
capacity, 950 MW of natural gas-fired thermal generation
capacity, transmission capacity and a development
pipeline. The fast-ramping nature of certain Heartland
facilities is ideally positioned to respond to expected price
volatility and deliver peaking capacity in periods of higher
demand in the Alberta market. Refer to the Significant and
Subsequent events section.
Generating capacity in Alberta is subject to market forces.
Power from commercial generation is cleared through a
wholesale electricity market. Power is dispatched in
accordance with an economic merit order administered by
the Alberta Electric System Operator (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,
which enables portfolio management. It also provides us
with capacity that can be monetized as either energy
production or ancillary services. A significant portion of the
generation capacity in the portfolio has been hedged to
provide greater cash flow certainty. The Company's
hedging strategy includes maintaining a significant base of
Commercial
and
Industrial
(C&I)
customers
and
is
supplemented with financial hedges.
During periods of low market prices, the Company may
choose not to generate power from the thermal fleet and
monetize its hedged or contract positions. This results in a
change in revenue not correlating with a change in
production. During 2024, there were periods of low market
prices, and the Company opted not to generate production
from the thermal fleet, and as a result, the thermal
generation sold through C&I contracts and financial hedges
exceeded the actual merchant production generated.
TransAlta Corporation
2024 Integrated Report
M29
The Alberta hydro fleet provides ancillary services and grid
reliability products such as black start services, 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 that the Company sells to third
parties and intercompany to the Gas segment.
The following table provides information for the Company's Alberta electricity portfolio:
2024
2023
2022
Year ended Dec.
31
Hydro
Wind &
Solar Gas(4)
Energy
Transition
Total
Hydro
Wind &
Solar
Gas
Energy
Transition
Total
Hydro
Wind &
Solar
Gas
Energy
Transition
Total
Gross
installed capacity
(MW)
834
764
3,650
—
5,248 834
766
1,960
—
3,560
834
636
1,960
—
3,430
Total
production(1)
(GWh)
1,443
1,981
8,385
—
11,809 1,492
1,907
8,360
—
11,759 1,665
1,686
8,106
19
11,476
Contract
production
(GWh)
—
928
2,566
—
3,494
—
774
861
—
1,635
—
620
526
—
1,146
Merchant
production
(GWh)
1,443
1,053
5,819
—
8,315 1,492
1,133
7,499
—
10,124 1,665
1,066
7,580
19
10,330
Purchased
power
(GWh)
—
—
(918)
—
(918)
—
—
(150)
—
(150)
—
—
(197)
—
(197)
Hedged
production
(GWh)
558
136
8,386
9,080 378
221
7,173
—
7,550
—
—
7,228
—
7,228
Production
contracted or
hedged (%)
39%
54%
131%
—%
106%
25%
41%
96%
—%
78%
—%
37%
96%
—%
73%
Hedged
production as a
percentage of
gross installed
capacity (%)
8%
2%
26%
—%
20%
5%
3%
42%
—%
24%
—%
—%
42%
—%
24%
Revenues(2)(3)(5)
($)
370
105
887
5
1,367
509
130
1,083
5
1,727
602
155
989
6
1,752
Fuel ($)
6
11
297
1
315
8
17
307
—
332
10
17
419
5
451
Purchased
power ($)
7
3
60
—
70
9
3
29
—
41
8
4
23
—
35
Carbon
compliance(3) ($)
—
—
125
1
126
—
—
106
—
106
—
1
70
(1)
70
Gross
margin(5) ($)
357
91
405
3
856
492
110
641
5
1,248
584
133
477
2
1,196
(1)
Total production includes contract and merchant production.
(2) 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.
(3) The intercompany sales of emission credits from the Hydro segment to the Gas segment are eliminated on consolidation in the Corporate segment.
Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(4) Gross installed capacity for Alberta facilities in 2024 includes 1,687 MW from the acquisition of Heartland and excludes production from Planned
Divestitures. Refer to the Significant and Subsequent events section.
(5) During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the
Company has applied this composition to all previously reported periods. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
M30
TransAlta Corporation
2024 Integrated Report
2024 versus 2023
Total production for the Alberta portfolio for the year
ended Dec. 31, 2024, was 11,809 GWh, compared to 11,759
GWh in 2023. The increase of 50 GWh, or 0.4 per cent,
was primarily due to:
• Higher production in the Gas segment due to the addition
of gas facilities from the acquisition of Heartland; and
• A full-year of production from the addition of the Garden
Plain wind facility, which was commissioned in August
2023; partially offset by
• Higher dispatch optimization in the Gas segment; and
• Lower production from the Alberta Hydro Assets due to
lower water resources compared to the prior year.
Hedged production for the year ended Dec. 31, 2024,
increased compared to 2023. In anticipation of the risk of
lower prices in 2024, the Company deployed a defensive
strategy to increase financial hedges for the merchant
portfolio at attractive margins. Realized gains and losses on
financial hedges are included in revenues in the table
above.
Gross margin for the Alberta portfolio for the year ended
Dec. 31, 2024, was $856 million, compared to $1,248
million in 2023. The decrease of $392 million, or 31 per
cent, was primarily due to:
• The impact of lower Alberta spot power prices and lower
hydro ancillary services prices;
• Increased dispatch optimization in the Gas segment
driven by lower power prices;
• An increase in the carbon price per tonne from $65 in
2023 to $80 in 2024; partially offset by
• Higher gains realized on financial hedges settled in the
period;
• Higher environmental and tax attributes revenues due to
the increased sales of emission credits to third parties
and intercompany sales from the Hydro segment to the
Gas segment;
• The utilization of emission credits in the Gas segment in
2024 to settle a portion of our 2023 GHG obligation;
• Higher hydro ancillary services volumes due to increased
demand by the AESO; and
• Lower natural gas prices.
2023 versus 2022
Total production for the year ended Dec. 31, 2023, was
11,759 GWh, compared to 11,476 GWh in 2022. The
increase of 283 GWh, or two 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 facilities 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 Alberta portfolio for the year ended
Dec. 31, 2023, was $1,248 million, compared to $1,196
million in 2022. The increase of $52 million, or four 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.
TransAlta Corporation
2024 Integrated Report
M31
The following table provides information for the Company's Alberta electricity portfolio:
Year ended Dec. 31
2024
2023
2022
Alberta Market
Spot power price average per MWh
63
134
162
Natural gas price (AECO) per GJ
1.29
2.54
5.08
Carbon compliance price per tonne
80
65
50
Alberta Portfolio Results
Realized merchant power price per MWh(1)
109
136
126
Hydro energy spot power price per MWh
91
175
197
Hydro ancillary services price per MWh
46
67
76
Wind energy spot power price per MWh
35
73
90
Gas spot power price per MWh
86
162
194
Hedged power price average per MWh(2)
84
111
86
Hedged volume (GWh)
9,080
7,550
7,228
Fuel cost per MWh(3)
38
40
56
Carbon compliance cost per MWh(4)
15
13
9
(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) Hedged power price average per MWh is calculated as the average sales price for all hedges and direct customer sales during the reporting period.
(3) Fuel cost per MWh is calculated on production from carbon-emitting generation in the Gas and Energy Transition segments.
(4) Carbon compliance cost per MWh is calculated on production from carbon-emitting generation, as well as power purchased, in the Gas and Energy
Transition segments.
2024 versus 2023
The average spot power price per MWh for the Alberta
portfolio for the year ended Dec. 31, 2024 decreased from
$134 per MWh in 2023 to $63 per MWh in 2024, primarily
due to:
• Higher generation from the addition of increased supply
of new renewables and combined-cycle gas facilities into
the market compared to the prior period; and
• Lower natural gas prices.
The realized merchant power price per MWh of production
for the Alberta portfolio for the year ended Dec. 31, 2024,
decreased by $27 per MWh, compared to 2023, primarily
due to:
• Lower average spot power prices as explained above;
and
• Lower hedge prices compared to the prior year.
Fuel cost per MWh for the year ended Dec. 31, 2024,
decreased by $2 per MWh, compared to 2023, primarily
due to lower natural gas prices.
Carbon compliance cost per MWh of production for the
year ended Dec. 31, 2024, increased by $2 per MWh,
compared to 2023, primarily due to:
• The increase in carbon pricing from $65 per tonne in
2023 to $80 per tonne in 2024; partially offset by
• The utilization of emission credits to settle a portion of
the 2023 GHG obligation during the year.
2023 versus 2022
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 Alberta portfolio 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.
M32
TransAlta Corporation
2024 Integrated Report
Fuel cost per MWh for the Alberta portfolio for the year
ended Dec. 31, 2023, decreased by $16 per MWh,
compared to 2022, primarily due to lower natural
gas prices.
Carbon compliance cost per MWh of production for the
Alberta portfolio for the year ended Dec. 31, 2023,
increased by $4 per MWh, compared to 2022 primarily due
to:
• The increase in carbon pricing 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 2022 the Company used
emission credits to settle a portion of the carbon
compliance obligation resulting in a lower carbon cost
per MWh.
TransAlta Corporation
2024 Integrated Report
M33
Fourth Quarter Highlights
For the quarter ended Dec. 31, 2024, the Company's
performance was impacted by lower power prices in the
Alberta and Mid-Columbia markets. The results were in line
with
management's
expectations
due
to
active
management of the Company's merchant portfolio and
hedging strategies. During the fourth quarter of 2024, the
Company settled a higher volume of hedges that were
significantly above average spot prices. The acquisition of
Heartland on Dec. 4, 2024 positively contributed to the
production in the Gas segment and further diversifies
TransAlta’s competitive portfolio in the highly dynamic and
shifting electricity landscape in Alberta by adding 1,747
MW to gross installed capacity.
Consolidated Financial Highlights
Three months ended Dec. 31
2024
2023
Operational information
Availability (%)
87.8
86.9
Production (GWh)
6,199
5,783
Select financial information
Revenues
678
624
Adjusted EBITDA(1)
285
289
Loss before income taxes
(51)
(35)
Net loss attributable to common shareholders
(65)
(84)
Cash flows
Cash flow from operating activities
215
310
Funds from operations(1)
137
229
Free cash flow(1)
48
121
Per share
Weighted average number of common shares outstanding
298
308
Free cash flow per share(1)(2)
0.16
0.39
(1)
These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.
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.
M34
TransAlta Corporation
2024 Integrated Report
Operating Performance
Availability
The following table provides availability (%) by segment:
Three months ended Dec. 31
2024
2023
Hydro
85.8
76.6
Wind and Solar
92.2
90.3
Gas(1)
84.1
89.5
Energy Transition
91.7
79.6
Availability (%)
87.8
86.9
(1)
Availability for 2024 includes the facilities acquired from Heartland and excludes the Planned Divestitures. Refer to the Significant and Subsequent
events section.
Availability for the three months ended Dec. 31, 2024, was
87.8 per cent compared to 86.9 per cent for the same
period in 2023, primarily due to:
• The addition of the White Rock and Horizon Hill wind
facilities which operated with high availability;
• The return to service of the Kent Hills wind facilities;
• Higher availability in the Hydro segment due to lower
planned outages;
• Higher availability in the Energy Transition segment due
to lower unplanned outages; and
• Positive contribution from the addition of the gas facilities
acquired with Heartland; partially offset by
• Lower availability for the Gas segment due to planned
outages at Sarnia, Sheerness and Keephills.
Production and Long-Term Average Generation
2024
2023
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
452
447
101%
326
447
73%
Wind and Solar
1,831
2,175
84 %
1,479
1,361
109 %
Gas(1)
2,875
2,892
Energy Transition
1,041
1,086
Total
6,199
5,783
(1)
Gas production for 2024 includes 511 GWh from Heartland, excluding production from the Planned Divestitures. Refer to the Significant and Subsequent
events section.
Production for the three months ended Dec. 31, 2024, was
6,199 GWh compared to 5,783 GWh for the same period in
2023. The increase was primarily due to:
• Higher production in the Wind and Solar segment due to
the addition of the Horizon Hill and the White Rock West
and East wind facilities during 2024;
• Higher production in the Hydro segment compared to the
same period in 2023 due to water conservation in the
fourth quarter of 2023 that resulted in lower production
volumes compared to the current period; partially offset
by
• Lower production in the Energy Transition segment due
to
higher
dispatch
optimization,
which
negatively
affected merchant production; and
• Lower production in the Gas segment driven by lower
availability at the Sarnia facility due to planned outages,
higher
economic
dispatch
in
Alberta
and
lower
production from Western Australia due to lower demand,
partially offset by positive contribution from the
Heartland gas facilities.
TransAlta Corporation
2024 Integrated Report
M35
Financial Performance Review on Consolidated Information
Three months ended Dec. 31
2024
2023
Revenues
678
624
Fuel and purchased power
249
278
Carbon compliance
39
27
Operations, maintenance and administration
234
150
Depreciation and amortization
143
132
Asset impairment charges
20
26
Interest expense
92
66
Foreign exchange gain (loss)
17
(7)
Loss before income taxes
(51)
(35)
Income tax (recovery) expense
(8)
19
Net loss attributable to common shareholders
(65)
(84)
Net (loss) earnings attributable to non-controlling interests
(4)
5
Current
Year
Variance
Analysis
(Fourth
quarter
2024 versus Fourth quarter 2023)
Revenues for the three months ended Dec. 31, 2024,
increased by $54 million, or nine per cent, compared to the
same period in 2023, primarily due to:
• Higher revenue in the Gas segment due to favourable
contribution from hedging and the addition of Heartland
facilities;
• Higher revenues in the Hydro segment due to higher
production in the fourth quarter of 2024 due to water
conservation in the same period of 2023; and
• Revenue from the commercial operation of the White
Rock and Horizon Hill wind facilities in the current period;
partially offset by
• Lower realized power prices and dispatch optimization in
Alberta;
• Lower revenues in the Energy Marketing segment due to
lower market volatility across North American power and
natural gas markets; and
• Lower revenues in the Energy Transition segment due to
increased economic dispatch due to lower market prices.
Fuel and purchased power costs for the three months
ended Dec. 31, 2024, decreased by $29 million, or 10 per
cent, compared to the same period in 2023, primarily
due to:
• Lower purchased power costs driven by lower Mid-
Columbia prices on repurchases of power and lower
production in the Energy Transition segment.
Carbon compliance costs for the three months ended
Dec. 31, 2024, increased by $12 million compared to 2023
due to:
• Carbon price increase from $65 to $80 per tonne; and
• Carbon
compliance
costs
attributable
to
facilities
acquired from Heartland.
OM&A expenses for the three months ended Dec. 31,
2024, increased by $84 million, or 56 per cent, compared
to the same period in 2023, primarily due to:
• Penalties assessed by the Alberta Market Surveillance
Administrator for self-reported contraventions pertaining
to hydro ancillary services provided during 2021 and
2022;
• Heartland
acquisition-related
transaction
and
restructuring costs;
• Higher spending in connection with planning and design
work on a planned upgrade to our ERP system;
• Addition of OM&A costs from Heartland;
• Higher maintenance costs at the South Hedland facility;
and
• Higher spend to support strategic and growth initiatives.
Depreciation and amortization for the three months
ended Dec. 31, 2024, increased by $11 million, or eight per
cent, compared to the same period in 2023, primarily
due to:
• Commercial operation of the White Rock and Horizon Hill
wind facilities; partially offset by
• Revisions to the useful lives of certain facilities.
M36
TransAlta Corporation
2024 Integrated Report
Asset impairment charges for the three months ended
Dec. 31, 2024 decreased by $6 million, or 23 per cent,
compared to the same period in 2023, primarily due to:
• Lower decommissioning and restoration provisions on
retired assets driven by lower discount rates in the
current period compared to the same period in 2023;
partially offset by
• Impairment charges related to development projects that
are no longer proceeding.
Interest expense for the three months ended Dec. 31,
2024 increased by $26 million, or 39 per cent, compared to
2023, primarily due to lower capitalized interest in 2024 as
a result of capital projects being completed in the first half
of 2024.
Foreign exchange gains for the three months ended Dec.
31, 2024 increased by $24 million due to favorable
changes in foreign exchange rates.
Loss before income taxes for the three months ended
Dec. 31, 2024 totalling $51 million, increased by $16 million,
or 46 per cent, compared to the same period in 2023, due
to the above noted items.
Income tax recovery for the three months ended Dec. 31,
2024, increased by $27 million, or 142 per cent, compared
to 2023 as a result of a higher loss before income taxes
due to the above noted items; in addition to lower non-
deductible expenses.
Net loss attributable to common shareholders for the
three months ended Dec. 31, 2024 was $65 million
compared to a net loss of $84 million in the same period of
2023, an improvement of $19 million, or 23 per cent,
primarily due to the above noted items.
Net earnings (loss) attributable to non-controlling
interests for the three months ended Dec. 31, 2024,
decreased by $9 million, or 180 per cent, compared to the
same period in 2023, primarily due to lower TA Cogen net
earnings resulting from lower Alberta market merchant
pricing.
TransAlta Corporation
2024 Integrated Report
M37
Segmented Financial Performance and Operating Results for
the Fourth Quarter
A summary of our adjusted EBITDA by segment and loss before income taxes for the three months ended Dec. 31, 2024,
and 2023 is as follows:
Adjusted EBITDA(1)
Three months ended Dec. 31
2024
2023
Hydro
57
56
Wind and Solar
95
82
Gas
116
141
Energy Transition
28
26
Energy Marketing
27
14
Corporate
(38)
(30)
Total adjusted EBITDA(1)
285
289
Loss before income taxes
(51)
(35)
(1)
This item is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer
to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
Loss before income taxes for the three months ended Dec.
31, 2024, increased by $16 million, or 46 per cent,
compared to the same period in 2023, primarily due to:
• Factors causing lower adjusted EBITDA (as described
above);
• Higher interest expense due to lower capitalized interest
in the fourth quarter of 2024 resulting from lower capital
activity in 2024 compared to the same period in 2023;
• Heartland
acquisition-related
transaction
and
restructuring costs in the fourth quarter of 2024;
• Higher ERP upgrade costs related to planning and design
work;
• Penalties assessed by the Alberta Market Surveillance
Administrator for self-reported contraventions pertaining
to Hydro ancillary services provided during 2021 and
2022;
• Higher depreciation and amortization due to the
commercial operation of the White Rock and Horizon Hill
wind facilities during 2024;
• Higher taxes other than income taxes mainly consisting
of property taxes due to the addition of new wind
facilities during 2024; partially offset by
• Higher realized and unrealized foreign exchange gains;
• Lower realized gains on closed exchange positions in
2024 compared to the same period in 2023;
• Higher net other operating income mainly due to
Sundance A decommissioning cost reimbursement; and
• Lower
asset
impairment
charges
related
to
the
decommissioning and restoration provisions on retired
assets driven by lower discount rates in the current
period compared to the same period in 2023, partially
offset by impairment charges related to development
projects that are no longer proceeding.
M38
TransAlta Corporation
2024 Integrated Report
The major factors impacting adjusted EBITDA for the three months ended Dec. 31, 2024, are summarized in the
following table:
Three months
ended Dec. 31
Adjusted EBITDA for the three months ended Dec. 31, 2023
289
Hydro: Higher due to higher merchant revenues driven by higher volumes, partially offset by lower spot
power prices and lower environmental and tax attributes revenues.
1
Wind and Solar: Higher due to environmental and tax attributes revenues from the sale of production
tax credits from Horizon Hill and White Rock West and East wind facilities to taxable US counterparties,
higher revenues driven by increased production from the addition of the White Rock and Horizon Hill
wind facilities and the return to service of the Kent Hills wind facilities, partially offset by unfavourable
merchant power prices in Alberta.
13
Gas: Lower due to lower realized power prices in Alberta, an increase in the carbon price in Canada,
and higher OM&A driven by higher maintenance costs at the South Hedland facility, partially offset by
higher volume of favourable hedging positions settled, positive contribution from the Heartland gas
facilities and lower capacity payments.
(25)
Energy Transition: Higher due to lower fuel and purchased power costs, partially offset by increased
economic dispatch due to lower market prices.
2
Energy Marketing: Higher due to favourable market volatility and the timing of realized settled trades
during 2024 compared to the same period in 2023.
13
Corporate: Lower due to higher spend to support strategic and growth initiatives.
(8)
Adjusted EBITDA(1) for the three months ended Dec. 31, 2024
285
(1)
Adjusted EBITDA is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other
issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
FCF for the three months ended Dec. 31, 2024, decreased by $73 million, or 60 per cent, compared to the same period
in 2023.
Three months
ended Dec. 31
FCF for the three months ended Dec. 31, 2023
121
Lower adjusted EBITDA due to the items noted above.
(4)
Higher net interest expense(1) due to lower capitalized interest as a result of capital projects being
completed in the first half of 2024 and lower interest income due to lower cash balances in 2024.
(23)
Higher current income tax expense due to the full utilization of Canadian non-capital loss carryforwards
in 2023, partially offset by a higher loss before income taxes in the current period compared to the
same period in 2023.
(25)
Lower sustaining capital due to lower planned maintenance at the Alberta gas facilities, partially offset
by higher planned maintenance at the Sarnia cogeneration facility and Alberta hydro facilities.
7
Higher dividends paid on preferred shares.
(1)
Lower distributions paid to subsidiaries' non-controlling interests due to lower TA Cogen net earnings.
13
Higher provisions accrued in the current year compared to the prior year resulting in higher FCF.
3
Higher realized foreign exchange losses compared to realized foreign exchange gains in the
comparative period.
(29)
Other(2)
(14)
FCF(2)(3) for the three months ended Dec. 31, 2024
48
(1)
Net interest expense includes interest expense less interest income and excludes non-cash items like financing amortization and accretion.
(2) Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF section tables in this MD&A for more details.
(3) FCF is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to
the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
TransAlta Corporation
2024 Integrated Report
M39
Alberta Electricity Portfolio
The following table provides information for the Company's Alberta electricity portfolio for the three months ended
Dec. 31:
2024
2023
Three months ended Dec. 31
Hydro
Wind &
Solar
Gas
Energy
Transition
Total
Hydro
Wind &
Solar
Gas
Energy
Transition
Total
Gross installed capacity (MW)
834
764
3,650
—
5,248
834
766
1,960
—
3,560
Total production(1) (GWh)
367
619
2,164
—
3,150
278
745
1,966
—
2,989
Contract production (GWh)
—
257
837
—
1,094
—
353
438
—
791
Merchant production (GWh)
367
362
1,327
—
2,056
278
391
1,528
—
2,197
Purchased power (GWh)
—
—
(286)
—
(286)
—
—
(50)
—
(50)
Hedged production (GWh)
205
44
2,388
2,637
58
82
1,684
—
1,824
Production contracted or hedged (%)
56%
49%
149%
—%
118%
21%
58%
108%
—%
87%
Hedged production as a percentage of gross installed
capacity (%)
11%
3%
30%
—%
23%
3%
5%
39%
—%
23%
Revenues(2) ($)
72
24
235
1
332
71
38
221
1
331
Fuel ($)
1
3
86
1
91
3
5
76
—
84
Purchased power ($)
1
1
14
—
16
2
—
5
—
7
Carbon compliance(3)($)
—
—
34
—
34
—
—
25
—
25
Gross margin(2) ($)
70
20
101
—
191
66
33
115
1
215
(1)
Total production includes contract production and merchant production.
(2) 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. Alberta Hydro revenues for the three months ended Dec. 31, 2024 exclude the impact of Brazeau penalties.
(3) The intercompany sales of emission credits from the Hydro segment to the Gas segment is eliminated on consolidation in the Corporate segment. Refer
to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
Total production for the Alberta portfolio for the three
months ended Dec. 31, 2024, was 3,150 GWh, compared
to 2,989 GWh for the same period in 2023. The increase of
161 GWh, or five per cent, was primarily due to:
• Higher production from the Alberta Gas assets due to the
Heartland acquisition;
• Higher production from the Alberta Hydro Assets due to
significant water conservation during the fourth quarter
of 2023; partially offset by
• Higher economic dispatch for the Alberta gas facilities;
and
• Lower production in the Wind and Solar segment due to
lower wind resource.
Hedged production for the Alberta portfolio for the three
months ended Dec. 31, 2024, increased compared to the
same period in 2023. In anticipation of the risk of lower
prices in 2024, the Company deployed a defensive
strategy to increase financial hedges for the merchant
portfolio at attractive margins. Realized gains and losses on
financial hedges are included in revenues in the table
above.
Gross margin for the Alberta portfolio for the three months
ended Dec. 31, 2024, was $191 million, compared to $215
million in 2023. The decrease of $24 million, or eleven per
cent, was primarily due to:
• Lower Alberta spot power prices;
• Higher carbon compliance costs due to increase in the
carbon price from $65 per tonne in 2023 to $80 per
tonne in 2024; and
• Higher
purchased
power
due
to
the
contractual
requirement to fulfill physical power trades; partially
offset by
• Higher gains realized on financial hedges settled in the
period.
M40
TransAlta Corporation
2024 Integrated Report
The following table provides information for the Company's Alberta electricity portfolio for the three months ended
Dec. 31:
Three months ended Dec. 31
2024
2023
Alberta Market
Spot power price average per MWh
52
82
Natural gas price (AECO) per GJ
1.42
2.19
Carbon compliance price per tonne
80
65
Alberta Portfolio Results
Realized merchant power price per MWh(1)
110
117
Hydro energy spot power price per MWh
78
107
Hydro ancillary services price per MWh
39
37
Wind energy spot power price per MWh
26
49
Gas spot power price per MWh
75
101
Hedged power price average per MWh(2)
80
90
Hedged volume (GWh)
2,637
1,824
Fuel cost per MWh(3)
42
43
Carbon compliance cost per MWh(4)
16
13
(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) Hedged power price average per MWh is calculated as the average sales price for all hedges and direct customer sales during the reporting period.
(3) Fuel cost per MWh is calculated on production from carbon-emitting generation in the Gas and Energy Transition segments.
(4) Carbon compliance cost per MWh is calculated on production from carbon-emitting generation, as well as power purchased, in the Gas and Energy
Transition segments.
The average spot power price per MWh for the Alberta
portfolio for the three months ended Dec. 31, 2024,
decreased from $82 per MWh in 2023 to $52 per MWh in
2024, primarily due to:
• Higher generation from the addition of increased supply
of new renewables and combined-cycle gas facilities into
the market compared to the prior period; and
• Lower natural gas prices.
The realized merchant power price per MWh of production
for the Alberta portfolio for the three months ended Dec.
31, 2024, although significantly higher than average spot
power prices during the year, decreased by $7 per MWh
compared to the same period in 2023, primarily due to:
• Lower average spot power prices as explained above;
and
• Lower hedge prices compared to the prior year.
Fuel cost per MWh for the three months ended Dec. 31,
2024, decreased by $1 per MWh, compared to the same
period in 2023, primarily due to lower natural gas prices.
Carbon compliance cost per MWh of production for the
Alberta portfolio for the three months ended Dec. 31, 2024,
increased by $3 per MWh, compared to 2023, primarily
due to the carbon compliance price increase from $65 per
tonne in 2023 to $80 per tonne in 2024.
TransAlta Corporation
2024 Integrated Report
M41
Selected Quarterly Information
Our results are seasonal due to the nature of the electricity
market and related fuel costs. Higher maintenance costs
are often incurred in the spring and fall when electricity
prices are expected to be lower, and electricity prices
generally increase in the peak winter and summer months
in our main markets due to increased heating and cooling
loads. Margins are also typically impacted in the second
quarter due to the volume of hydro production resulting
from spring runoff and rainfall in the Pacific Northwest,
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.
Q1 2024
Q2 2024
Q3 2024
Q4 2024
Revenues
947
582
638
678
Carbon compliance
40
(8)
41
39
OM&A
134
144
143
234
Depreciation and amortization
124
131
133
143
Earnings (loss) before income taxes
267
94
9
(51)
Net earnings (loss) attributable to common shareholders
222
56
(36)
(65)
Net earnings (loss) per share attributable to common shareholders,
basic and diluted(1)
0.72
0.18
(0.12)
(0.22)
Cash flow from operating activities
244
108
229
215
Q1 2023
Q2 2023
Q3 2023
Q4 2023
Revenues
1,089
625
1,017
624
Carbon compliance
32
25
28
27
OM&A
124
134
131
150
Depreciation and amortization
176
173
140
132
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
(1)
Basic and diluted earnings (loss) per share attributable to common shareholders is calculated in each period using the basic and diluted weighted
average common shares outstanding during the period, respectively. As a result, the sum of the earnings (loss) per share for the four quarters making up
the calendar year may sometimes differ from the annual earnings (loss) per share.
Operating results have been impacted by the following
events:
• Acquisition of Heartland on Dec. 4, 2024. Refer to the
Significant and Subsequent events section of this MD&A
for more details; and
• Commissioning of the Garden Plain wind facility in the
third quarter of 2023, the Northern Goldfields solar
facilities in the fourth quarter of 2023, the White Rock
West wind facility and the Mount Keith 132kV expansion
in the first quarter of 2024 and the White Rock East and
Horizon Hill wind facilities in the second quarter of 2024.
In addition to the items described above, revenues have
been impacted by:
• Higher production in each quarter of 2024, compared to
the same periods in the prior year;
• The effects of unrealized mark-to-market gains and
losses from hedging and derivative positions; and
• Lower realized pricing in each quarter of 2024, compared
to the same periods in the prior years impacted by
additions of new natural gas, wind and solar supply in the
Alberta market in 2024.
Carbon compliance costs have been impacted by:
• Higher costs of carbon per tonne. In 2024, the cost of
carbon was $80 per tonne as compared to $65 per tonne
in 2023; and
• In the second quarter of 2024, carbon compliance costs
were reduced by using internally generated and
externally purchased emission credits to settle a portion
of the 2023 GHG obligation.
M42
TransAlta Corporation
2024 Integrated Report
OM&A has been impacted by:
• Higher costs stemming from planning and design work on
a planned upgrade to our ERP system in all quarters of
2024;
• Higher spend to support strategic and growth initiatives
in all quarters of 2024 compared to same period in prior
year;
• Return to service of Kent Hills wind facilities and the
addition of Horizon Hill and White Rock wind facilities.
• In the fourth quarter of 2024 Heartland acquisition-
related transaction and restructuring costs, mainly
comprising severance, legal and consultant fees; and
• In the fourth quarter of 2024 penalties assessed by the
Alberta Market Surveillance Administrator for self-
reported contraventions pertaining to Hydro ancillary
services provided during 2021 and 2022.
Depreciation has been impacted by:
• Revisions in the useful lives of certain facilities that
occurred in the third quarters of 2023 and 2024, partially
offset by
• An increase in depreciation due to the addition of White
Rock wind facilities in the first quarter of 2024, Horizon
Hill wind facilities in the second quarter of 2024.
Higher asset impairment charges due to:
• Development projects that are no longer proceeding in all
four quarters of 2024;
• Increase in decommissioning provisions for retired assets
due to changes in estimated cash flows in the third
quarter of 2023 and 2024; and
• changes in expected timing of restoration expenditures
occurring, recognized in the third quarter of 2023 and the
third and fourth quarters of 2024.
Earnings (loss) before income taxes has been impacted by
the following:
• The items described above; and
• Higher interest expense due to lower capitalized interest
during 2024 as compared to 2023 resulting from lower
capital activity in 2024 compared to 2023.
Net earnings (loss) attributable to common shareholders
has been impacted by fluctuations in current and deferred
tax expense with earnings before tax across the quarters.
Cash flow from operating activities has been impacted by
the following:
• The items described above;
• Unfavourable changes in non-cash operating working
capital balances in the last four quarters of 2024,
compared to the same periods in the prior year due to
unfavourable changes in accounts payable and accrued
liabilities due to lower capital spend and lower cost
accruals, partially offset by lower collateral provided due
to lower market volatility;
• Higher unrealized foreign exchange gains in the last four
quarters of 2024 compared to the same periods in 2023;
and
• Higher provisions and other non-cash items.
Strategic Priorities
The Company remains focused on investing in electricity
solutions that meet the evolving needs of customers and
communities. We take a balanced, prudent and disciplined
approach to capital allocation, ensuring long-term value
creation
for
shareholders.
Our
strategy
prioritizes
generating meaningful, risk-adjusted returns by optimizing
our legacy thermal assets, operating our diverse fleet of
renewable facilities, our exceptional marketing and trading
capabilities, and expanding our generating portfolio
through the addition of contracted clean energy assets and
selective gas assets. Given our skill set, competitive
advantages and market positioning, we are well-positioned
to capture significant opportunities in our core markets of
Canada, the United States and Western Australia.
The Company continues to make strong progress on key
strategic priorities, ensuring the business remains resilient,
growth-focused and aligned with the evolving energy
landscape.
TransAlta Corporation
2024 Integrated Report
M43
Optimize Alberta Portfolio
In Alberta, the Company continues to proactively deploy
hedging strategies, to mitigate the impact of lower
merchant power prices, along with optimization activities.
The acquisition of Heartland Generation has significantly
strengthened our Alberta portfolio, adding 1,747 MW of
flexible
capacity,
including
contracted
cogeneration,
peaking generation and transmission capacity. Of note, the
acquisition added 290 MW of peaking gas capacity, which
will be optimized within our larger portfolio to address
increasing intermittency in Alberta.
The Company is maximizing the value of its hydro fleet by
enhancing its operational capabilities and flexibility. We are
also advancing initiatives to maximize the value of our
existing thermal assets and meet the growing demand for
affordable and reliable power.
Execute Growth Plan
In 2024, significant progress was made on growth
initiatives. Early in the year we successfully completed our
two Oklahoma wind facilities: the 302 MW White Rock wind
facilities and the 202 MW Horizon Hill wind facility. We also
achieved commercial operations for our Mount Keith
Transmission Expansion project. These additions, along
with the fully rehabilitated Kent Hills facilities are expected
to contribute over $175 million in EBITDA annually.
Our growth plan is guided by a technology-agnostic
approach, focusing on our core operating jurisdictions and
clear target customer segments within them.
Realize the Value of Legacy Generating
Facilities
The Company is seeing considerable opportunities to
support the energy transition with sophisticated, reliable
and affordable power solutions in our core operating
jurisdictions. Particularly, at our legacy thermal sites in
Alberta and Washington State, where we are actively
pursuing
accretive
opportunities
with
existing
and
prospective customers. We believe that these sites hold
significant value and provide unique advantages to
customers.
Maintain Financial Strength and Capital
Discipline
The Company maintains a strong financial position, with
$1.6 billion in liquidity as of Dec. 31, 2024, and a disciplined
approach to capital allocation. The Company balances
investments in growth, debt repayments and returns to
shareholders through share repurchases and dividend
payments. Reflecting confidence in the business, the
annual common share dividend was increased by eight per
cent to $0.26 per share, our sixth consecutive dividend
increase, effective July 1, 2025. The Company also
announced
an
ongoing
commitment
to
its
share
repurchase plan, allowing the Company to repurchase up
to $100 million in common shares. Together, these actions
represent a return of up to 35 per cent of the midpoint of
2025 free cash flow guidance to shareholders.
Define Next Generation of Power Solutions
The Company has been at the forefront of innovation in the
power-generation sector since the early 1900s when we
developed our first hydro assets. We continue to make
progress on our identification of the next generation of
energy solutions that will be needed to power our
customers’ needs in an efficient, reliable and affordable
manner. Refer to the Enabling Innovation and Technology
Adoption section of the MD&A for further discussion.
Lead in ESG and Market Policy Development
The
Company
is
an
active
participant
in
policy
development in all key markets in which we operate. Most
notably, we are actively engaging with the Government of
Alberta and the Alberta Electric System Operator on
Alberta's restructured energy market, which is intended to
deliver the objectives of reliability, affordability, and
decarbonization by 2050 for the province. TransAlta is
committed to actively engaging in the AESO's consultation
process, to support the development of an investable
market
structure
that
can
responsibly
achieve
a
sustainable grid in a manner that ensures reliability and
affordability for Albertans.
M44
TransAlta Corporation
2024 Integrated Report
Growth
Throughout 2024 we refined our development pipeline to
reflect our views on changes in regulation, interconnection
timelines and with a focus on maximizing returns and
meeting the evolving needs of our customers. We also
incorporated additional redevelopment opportunities at our
legacy thermal facilities. We will continue to take a
disciplined approach to evaluating project economics. Our
pipeline includes 280 MW of advanced-stage development
projects along with 3,330 to 5,230 MW of projects in
earlier stages of development. We are focused primarily on
redevelopment opportunities at our legacy sites in addition
to evaluating greenfield and merger and acquisition
prospects in Alberta, Western Australia and the western
United States.
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 do not have final approval
from the Board of Directors at time of reporting.
The following table shows the pipeline of future growth projects in advanced-stage development:
Project
Type
Region
Target investment date
MW
Tempest
Wind
Alberta
On hold
100
WaterCharger
Battery Storage
Alberta
On hold
180
TransAlta Corporation
2024 Integrated Report
M45
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.
The following table shows the pipeline of future growth projects currently under early-stage development:
Project
Type
Region
Potential
investment
date(1)
MW
Canada
New Brunswick Battery
Battery
New Brunswick
2027+
10
SunHills Solar
Solar
Alberta
2027+
170
Tent Mountain Pumped Storage(2)
Hydro
Alberta
2029
192
Provost
Wind
Alberta
2027+
170
Red Rock
Wind
Alberta
2027+
100
Antelope Coulee
Wind
Saskatchewan
2027+
200
Other Canadian Opportunities
Wind
Various
2026+
374
Brazeau Pumped Hydro
Hydro
Alberta
TBD
300-900
Alberta Thermal Redevelopment(3)
Various
Alberta
2027+
400-1200
Total
1,916 - 3,316
United States
Square Top
Solar
Oklahoma
2026
195
Old Town
Wind
Illinois
2026
185
Trapper Valley
Wind
Wyoming
2027+
225
Other U.S. opportunities
Wind
Various
2026+
144
Centralia site redevelopment(3)
Various
Washington
2025+
500-1000
Total
1,249 - 1,749
Australia
Boodarie Solar
Solar
Western Australia
2025
50
Other Australian opportunities
Gas, Solar, Transmission
Western Australia
2025+
115
Total
165
Canada, United States and Australia
Total
3,330 - 5,230
(1)
Potential investment date is to be determined (TBD).
(2) This represents the Company's 60 per cent interest in Tent Mountain Renewable Energy Complex.
(3) The Company is currently evaluating redevelopment opportunities at these brownfield sites.
M46
TransAlta Corporation
2024 Integrated Report
Projects under Construction
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 of our 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:
Total project (millions)
Project
Type
Region
MW
Estimated
spend
Spent to
date
Target
completion
date
PPA
Term
(years)
Average
annual
EBITDA(1)
range
Status
Western Australia
Mount Keith
West
network
upgrade
Transmission
WA
n/a AU$37 —
AU$40
AU$19
Q4 2025
14
AU$6 - AU$7
• Engineering
completed
• Site works
commenced
• On track to be
completed on
schedule
Total(2)
n/a
$34
—
$36
$17
$6 - $7
(1)
This item is not defined and has no standardized meaning under IFRS and is forward-looking. It may not be comparable to similar measures presented
by other issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.
(2) Total expected spending and average annual EBITDA were converted using a Canadian dollar forward exchange rate for 2024. Spend to date was
converted using the period-end closing rate.
TransAlta Corporation
2024 Integrated Report
M47
Financial Position
The following table highlights significant changes in the Consolidated Statements of Financial Position from
Dec. 31, 2023, to Dec. 31, 2024:
Dec. 31, 2024
Dec. 31, 2023
Increase/(decrease)
Assets
Current assets
Cash and cash equivalents
337
348
(11)
Trade and other receivables
767
807
(40)
Risk management assets
318
151
167
Assets held for sale
80
—
80
Other current assets(1)
271
274
(3)
Total current assets
1,773
1,580
193
Non-current assets
Risk management assets
93
52
41
Investments
159
138
21
Property, plant and equipment, net
6,020
5,714
306
Intangible assets, net
281
223
58
Deferred income tax assets
52
21
31
Goodwill
517
464
53
Long-term portion of finance lease receivable
305
171
134
Other non-current assets(2)
299
296
3
Total non-current assets
7,726
7,079
647
Total assets
9,499
8,659
840
Liabilities
Current liabilities
Accounts payable, accrued liabilities and other current liabilities
756
809
(53)
Risk management liabilities
277
314
(37)
Decommissioning and other provisions (current)
83
35
48
Credit facilities, long-term debt and lease liabilities
572
532
40
Exchangeable securities
750
—
750
Contingent consideration payable
81
—
81
Other current liabilities(3)
50
52
(2)
Total current liabilities
2,569
1,742
827
Non-current liabilities
Credit facilities, long-term debt and lease liabilities
3,236
2,934
302
Exchangeable securities
—
744
(744)
Decommissioning and other provisions (long-term)
850
654
196
Risk management liabilities (long-term)
305
274
31
Defined benefit obligation and other long-term liabilities
202
251
(49)
Deferred income tax liabilities
470
386
84
Other non-current liabilities(4)
24
10
14
Total non-current liabilities
5,087
5,253
(166)
Total liabilities
7,656
6,995
661
Equity
Equity attributable to shareholders
1,746
1,537
209
Non-controlling interests
97
127
(30)
Total equity
1,843
1,664
179
Total liabilities and equity
9,499
8,659
840
(1)
Includes restricted cash, inventory and prepaid expenses and other.
(2) Includes right-of-use assets and other assets.
(3) Includes bank overdraft and dividends payable.
(4) Includes contract liabilities.
M48
TransAlta Corporation
2024 Integrated Report
Significant
changes
in
Company's
Consolidated
Statements of Financial Position were as follows:
On Dec. 4, 2024, the Company acquired Heartland. The
Financial Position as at Dec. 31, 2024 includes the assets
and liabilities of Heartland. Refer to note 4 of our
consolidated financial statements for further details.
Working Capital
The deficit of current assets over current liabilities,
including the current portion of long-term debt and lease
liabilities, was $796 million as at Dec. 31, 2024 (Dec. 31,
2023 – deficit of current assets over current liabilities of
$162 million). The deficit increased primarily as a result of
the reclassification of the exchangeable securities to a
current liability. The exchangeable securities are classified
as current as their conversion option can be exercised at
any time after Dec. 31, 2024 at Brookfield's option,
although there is no obligation to deliver cash equivalent
resources and the holder cannot call for repayment. Refer
to the Accounting Changes section of this MD&A for more
details.
Current assets increased by $193 million to $1,773 million
as at Dec. 31, 2024, from $1,580 million as at Dec. 31,
2023, primarily due to:
• Higher risk management assets mainly due to changes in
market pricing across multiple markets as well as higher
price forecasts;
• Addition of assets held for sale for the Planned
Divestitures (refer to Significant and Subsequent events
section); partially offset by
• Lower trade receivables, mainly due to timing of cash
receipts and lower collateral provided in the Energy
Marketing segment due to favourable changes in market
prices, offset by an increase in trade and other
receivables due to Heartland acquisition; and
• Lower cash and cash equivalents mainly due to lower
cash flow from operating activities.
Current liabilities increased by $827 million from $1,742
million as at Dec. 31, 2023, to $2,569 million as at Dec. 31,
2024, mainly due to:
• The exchangeable securities being classified as current
as described above;
• Contingent consideration payable related to the Planned
Divestitures (refer to the Significant and Subsequent
events section); and
• Higher current portion of decommissioning and other
provisions due to the addition of balances from
Heartland;
• Higher current portion of credit facilities, long-term debt
and lease liabilities mainly due to additions of balances
from Heartland; partially offset by
• Lower accounts payable, accrued liabilities and other
current liabilities mainly due to lower cost accruals and
lower capital spend, partially offset by the additions of
accounts payable balances from Heartland acquisition
and higher current income taxes payable; and
• Lower risk management liabilities due to changes in
market pricing across multiple prices and contract
settlements.
Non-Current Assets
Non-current assets as at Dec. 31, 2024, were $7,726
million, an increase of $647 million from $7,079 million as
at Dec. 31, 2023, primarily due to:
• Higher property, plant and equipment (PP&E) resulting
from $413 million of additions from Heartland recognized
at acquisition and capital additions of $311 million mainly
related to the construction of growth projects and
planned major maintenance activities. The increase in
PP&E additions was partially offset by depreciation of
$516 million;
• Higher finance lease receivable related to the additions
from Heartland and the Mount Keith 132kV finance lease
receivable;
• Higher deferred income tax asset due to an increase in
deductible temporary differences arising from the
Heartland acquisition;
• Higher risk management assets due to favourable
changes in market prices across multiple markets and
addition of risk management assets from Heartland;
• Higher goodwill balance due to goodwill arising on
Heartland acquisition;
• Higher intangibles mainly due to the addition of power
sale contracts from Heartland; and
• Higher investments balance resulting from contributions
and equity income from equity-accounted investments.
Non-Current Liabilities
Non-current liabilities as at Dec. 31, 2024 were $5,087
million, a decrease of $166 million from $5,253 million as at
Dec. 31, 2023, mainly due to:
• The exchangeable securities being classified as current
liabilities;
• Lower defined benefit obligations and other long-term
liabilities mainly due to a decrease in retail power
contract liabilities resulting from amortization based on
volumes delivered; partially offset by
• Increase in credit facilities, long-term debt and lease
liabilities due to the addition of Heartland credit facilities
and an increase in the cash drawings under the
syndicated credit facility;
TransAlta Corporation
2024 Integrated Report
M49
• Increase in decommissioning and other provisions due to
additions
of
generating
facilities
from
Heartland
acquisition, revisions in discounts rates and estimated
decommissioning costs and commissioning of Horizon
Hill and White Rock wind facilities;
• Higher deferred income tax liabilities due to an increase
in temporary taxable differences arising from the
Heartland acquisition; and
• Higher risk management liabilities due to forward price
changes and volatility in market pricing across multiple
markets.
Total Equity
As at Dec. 31, 2024, the increase in total equity of $179
million was due to:
• Net earnings of $239 million; and
• Net gains on derivatives from cash flow hedges of $194
million; partially offset by
• Share repurchases under the NCIB of $143 million;
• Dividends declared on common and preferred shares of
$123 million; and
• Distributions to non-controlling interests of $40 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 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 2024, 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 a
stable outlook. In addition, S&P Global Ratings reaffirmed
the Company's senior unsecured debt rating and issuer
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.
M50
TransAlta Corporation
2024 Integrated Report
Capital Structure
Our capital structure consists of the following components as shown below:
2024
2023
2022
$
%
$
%
$
%
Net senior unsecured debt
Recourse debt - CAD debentures
251
4
251
5
251
5
Recourse debt - U.S. senior notes
995
16
911
17
934
18
Credit facilities
543
9
397
7
428
9
Other
—
—
—
—
1
—
Less: cash and cash equivalents(1)
(336)
(6)
(345)
(6) (1,118)
(21)
Less: other cash and liquid assets(2)
(7)
—
5
—
(3)
—
Net senior unsecured debt
1,446
23
1,219
23
493
11
Other debt liabilities
Exchangeable debentures
350
6
344
6
339
6
Non-recourse debt
TAPC Holdings LP bond
75
1
85
1
94
2
Pingston bond
39
1
39
1
45
1
Melancthon Wolfe Wind bond
133
2
168
3
202
4
New Richmond Wind bond
93
2
103
2
112
2
Kent Hills Wind bond
179
3
193
3
206
4
Windrise Wind bond
157
3
164
3
170
3
South Hedland non-recourse debt
675
11
691
13
711
14
Heartland term facility
224
4
—
—
—
—
OCP Bond
192
3
217
4
241
4
OCP LP restricted cash(3)
(17)
—
(17)
—
(17)
—
U.S. tax equity financing
101
1
104
1
123
2
Lease liabilities
151
2
143
3
135
2
Total consolidated net debt(4)(5)(6)
3,798
62
3,453
63 2,854
55
Exchangeable preferred securities(6)
400
7
400
7
400
7
Equity attributable to shareholders
Common shares
3,179
53
3,285
60 2,863
54
Preferred shares
942
16
942
17
942
18
Contributed surplus, deficit and accumulated other
comprehensive loss
(2,375)
(40) (2,690)
(49) (2,695)
(51)
Non-controlling interests
97
2
127
2
879
17
Total capital
6,041
100
5,517
100 5,243
100
(1)
Cash and cash equivalents is net of bank overdraft.
(2) 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) Principal portion of the TransAlta OCP LP restricted cash related to the TransAlta OCP LP bonds as this cash is restricted specifically to repay
outstanding debt.
(4) These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.
Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion, including reconciliations to measures
calculated in accordance with IFRS.
(5) The tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in these amounts.
(6) The total consolidated net debt excludes the exchangeable preferred securities as they are considered equity with dividend payments for credit
purposes.
TransAlta Corporation
2024 Integrated Report
M51
We have enhanced liquidity and shareholder value through the following:
2024
• Renewed the $400 million Term Facility with the maturity
extended by one year to September 2025;
• Extended the $1.9 billion syndicated credit facility and
$240 million bilateral credit facilities by one year to June
2028 and June 2026, respectively;
• Purchased and cancelled 13,467,400 common shares at
an average price of $10.59 per share through our NCIB
program, for a total cost of $143 million; and
• Assumed new credit facilities and letter of credit facilities
as part of the Heartland acquisition.
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.
Credit Facilities
The Company's credit facilities are summarized in the table below:
As at Dec. 31, 2024
Utilized
Credit facilities
Facility
size
Outstanding
letters of
credit(1)
Cash
drawings
Available
capacity
Maturity
date
Committed
Syndicated credit facility
1,950
456
145
1,349
Q2 2028
Bilateral credit facilities
240
161
—
79
Q2 2026
Term Facility
400
—
400
—
Q3 2025
Heartland Credit Facilities
276
14
224
38
Q4 2027
Heartland EDC letter of credit facility
50
14
—
36
Q1 2025
Total Committed
2,916
645
769
1,502
Non-Committed
Demand facilities
400
220
—
180
N/A
Total Non-Committed
400
220
—
180
(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.
M52
TransAlta Corporation
2024 Integrated Report
In the second quarter of 2024, the $400 million Term
Facility was renewed with the maturity extended by one
year to September 2025. The $1,900 syndicated credit
facility and $240 million bilateral credit facilities were also
extended by one year to June 2028 and June 2026,
respectively.
As part of the Heartland acquisition on Dec. 4, 2024, the
Company assumed a $232 million drawn term facility and
$25 million revolving facility with a syndicate of banks,
(collectively Heartland Credit Facilities). At Dec. 31, 2024
the drawn term facility was $224 million. The $25 million
revolving facility is undrawn and available for working
capital and general corporate purposes. The maturity date
for the Heartland Credit Facilities is Dec. 22, 2027. The
Heartland Credit Facilities also include a $27 million debt
service reserve letter of credit facility.
As part of the Heartland acquisition, the Company has
access to a $50 million unsecured letter of credit facility
with two Canadian banks, which is supported by a
performance security guarantee from Export Development
Canada (EDC).
The Heartland Credit Facilities are not subject to any
maintenance or financial covenants but do contain certain
covenants that limit Heartland’s ability to, among other
things, incur additional indebtedness, create or permit liens
to exist, make certain acquisitions or dispositions, make
distributions and enter into certain hedging agreements.
Non-Recourse Debt and Other
The Melancthon Wolfe Wind LP, Pingston Power Inc., TAPC
Holdings LP, New Richmond Wind LP, Kent Hills Wind LP,
TEC Hedland Pty Ltd. and Windrise Wind LP non-recourse
bonds, the TransAlta OCP LP bond, and Heartland Credit
Facilities 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 2024, with the exception of Kent Hills
Wind LP. The funds in the Kent Hills Wind entity 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 2025. At Dec. 31, 2024, $117 million
(Dec. 31, 2023 – $79 million) of cash was subject to these
financial restrictions.
At Dec. 31, 2024, $5 million (AU$6 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 2025 and 2027, the Company has a total of
$1,066 million of scheduled debt repayments, including the
$400 million maturity of the Term Facility, with the balance
of $666 million related to scheduled non-recourse debt
and
tax
equity
repayments.
The
$750
million
of
exchangeable securities are exchangeable after Dec. 31,
2024.
U.S. Tax Equity Financing and Production
Tax Credits
The Company owns equity interests in wind facilities that
are eligible for tax incentives available for renewable
energy facilities in the U.S. Current U.S., tax law allows
qualified wind energy projects to receive production tax
credits (PTCs) that are earned for each MWh of generation
during the first 10 years of the project's operation. To
monetize tax incentives, the Company has partnered with
Tax Equity Investors (TEIs) who invest in these facilities in
exchange for a share of the tax incentives and cash.
TransAlta accounts for the TEIs' interest as long-term debt,
where cash distributions and allocations of tax incentives
to the TEIs primarily reduce the long-term debt balance.
Upon the TEIs achieving an agreed-upon after-tax
investment return, the project flip point occurs (Flip Point).
Prior to achieving the Flip Point, the TEIs are allocated
substantially all of the taxable attributes including PTCs
produced and a proportion of cash. After the Flip Point has
been reached, the Company retains substantially all of the
cash and the taxable income (losses) generated by the
facility.
In 2023, U.S. tax laws were amended to allow entities to
monetize certain clean energy tax credits, including PTCs,
by transferring (selling) them to third-party taxpayers, in
exchange for cash consideration.
TransAlta Corporation
2024 Integrated Report
M53
The following table outlines information regarding the Company's tax equity financing arrangements with PTC eligibility:
Facility
Commercial
operation date
Expected
Flip
Point
Initial TEI
investment
($US)
Expected
annual PTC
($US)
TEI allocation
of cash
distributions
(pre-Flip Point)
Undiscounted(1)
($US)
TEI allocation
of taxable
income and
PTCs
(pre-Flip Point)
Lakeswind
2014
2027
45
—
7
99%
Big Level and
Antrim
2019
2029
126
10
41
99%
Skookumchuck(2)
2020
2030
121
11
17
99%
North Carolina
Solar
2021
2028
64
N/A
7
N/A
(1)
Cumulative expected cash distributions from Dec. 31, 2024 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.
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
2024
2023
2022
Interest income
30
59
24
Interest on debt
197
203
164
Interest on exchangeable debentures
31
29
29
Interest on exchangeable preferred shares
28
28
28
Capitalized interest
(16)
(57)
(16)
Interest on lease liabilities
10
9
7
Credit facility fees, bank charges and other interest
21
21
27
Tax shield on tax equity financing
3
—
(2)
Accretion of provisions
50
48
49
Interest expense
324
281
286
Interest income was lower due to lower average cash
balances and lower interest rates. Interest expense was
higher than in 2023, primarily due to lower capitalized
interest resulting from lower construction activity in 2024
compared to 2023.
M54
TransAlta Corporation
2024 Integrated Report
Share Capital
The following tables outline the common and preferred shares issued and outstanding:
Number of shares (millions)
As at
Feb. 19, 2025
Dec. 31, 2024
Dec. 31, 2023
Common shares issued and outstanding, end of period
297.6
297.5
306.9
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.
As at Dec. 31, 2024, the Company owned 50.01 per cent of
TransAlta Cogeneration, LP (TA Cogen) (Dec. 31, 2023 –
50.01 per cent), which owns, operates or has an interest in
three natural-gas-fired cogeneration facilities (Ottawa,
Windsor and Fort Saskatchewan) and a natural-gas-fired
facility (Sheerness). On Dec. 4, 2024, the Company
acquired the remaining 50 per cent interest in Sheerness
as part of the Heartland acquisition.
As at Dec. 31, 2024, the Company owned 83 per cent of
Kent Hills Wind LP (Dec. 31, 2023 - 83 per cent), which
owns and operates three wind facilities.
Since the Company owns 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. On Oct. 5, 2023, the Company acquired all of the
outstanding common shares of TransAlta Renewables not
already owned, directly or indirectly.
The reported net earnings attributable to non-controlling
interests for the year ended Dec. 31, 2024, decreased by
$91 million, compared to 2023, primarily as a result of
lower TA Cogen net earnings attributable to non-
controlling interests resulting from lower production and
lower merchant pricing in the Alberta market and the
cessation of distributions to TransAlta Renewables non-
controlling interest.
TransAlta Corporation
2024 Integrated Report
M55
Cash Flows
The following table highlights significant changes in the Consolidated Statements of Cash Flows for the year ended Dec.
31, 2024 and Dec. 31, 2023:
Year ended Dec. 31
2024
2023
2022
Cash and cash equivalents, beginning of year
348
1,134
947
Provided by (used in):
Operating activities
796
1,464
877
Investing activities
(520)
(814)
(741)
Financing activities
(291)
(1,432)
45
Translation of foreign currency cash
4
(4)
6
Cash and cash equivalents, end of year
337
348
1,134
Cash Flow from Operating Activities
Cash from operating activities for the year ended Dec. 31, 2024, decreased compared with the same period in 2023,
primarily due to the following:
Year ended
Dec. 31
Cash flow from operating activities for the year ended Dec. 31, 2023
1,464
Lower gross margin due to lower revenues, excluding the effect of unrealized losses from risk
management activities, partially offset by lower fuel and purchased power.
(351)
Higher OM&A due to increased spending on planning and design of an ERP system upgrade, higher
spending on strategic and growth initiatives, penalties assessed by the Alberta Market Surveillance
Administrator for self-reported contraventions and Heartland acquisition-related transaction and
restructuring costs.
(116)
Higher current income tax expense due to the full utilization of Canadian non-capital loss carryforwards
in 2023, offset by lower earnings before income taxes in 2024.
(93)
Lower interest income due to lower cash balances and lower interest rates.
(29)
Higher interest expense on debt primary due to lower capitalized interest resulting from lower
construction activity in 2024 compared to 2023.
(35)
Unfavourable change in non-cash operating working capital balances due to lower accounts payables
and accrued liabilities, partially offset by lower collateral provided as a result of market price volatility.
(86)
Other non-cash items
42
Cash flow from operating activities for the year ended Dec. 31, 2024
796
M56
TransAlta Corporation
2024 Integrated Report
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 due to 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 due to 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 due to previously restricted non-capital loss carryforwards were
utilized to offset taxable income.
15
Higher interest income due to higher cash balances and favourable interest rates.
35
Favourable change in non-cash operating working capital balances due to 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
Cash Flow Used in Investing Activities
Cash used in investing activities for the year ended Dec. 31, 2024, decreased compared with the same period in 2023,
primarily due to the following:
Year ended
Dec. 31
Cash flow used in investing activities for the year ended Dec. 31, 2023
(814)
Cash paid for the acquisition of Heartland.
(217)
Lower additions to PP&E due to larger construction program in 2023 compared to 2024.
564
Lower proceeds on sale of PP&E due to the sale of equipment related to Sundance Unit 5 in 2023.
(25)
Unfavourable change in non-cash investing working capital balances due to lower capital accruals.
(18)
Lower cash receipts under the new Mount Keith 132kV expansion finance lease receivable as compared
to the Southern Cross Energy finance lease receivable.
(34)
Lower cash contributions to equity accounted investments.
8
Other(1)
16
Cash flow used in investing activities for the year ended Dec. 31, 2024
(520)
(1)
Mainly comprised of the lease incentive received, offset by lower realized gains on financial instruments, increase in the restricted cash balance and
other investing items.
TransAlta Corporation
2024 Integrated Report
M57
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 due to 2022 additions 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 due to lower additions of intangibles under development.
18
Lower proceeds on sale of PP&E due to closing the sale of two hydro facilities and equipment related to
Sundance Unit 5 and other equipment in 2022.
(37)
Unfavourable change in non-cash investing working capital balances due to lower capital accruals.
(28)
Other(1)
(69)
Cash flow used in investing activities for the year ended Dec. 31, 2023
(814)
(1)
Mainly comprised of higher spending on project development costs, higher contributions to investments, lower insurance proceeds and lower
settlements in 2023.
Cash Flow Used in Financing Activities
Cash used in financing activities for the year ended Dec. 31, 2024, decreased compared with the same period in 2023,
primarily due to the following:
Year ended
Dec. 31
Cash flow used in financing activities for the year ended Dec. 31, 2023
(1,432)
Acquisition of TransAlta Renewables in 2023.
811
Increase in borrowings under credit facilities during 2024.
189
Lower distributions paid to non-controlling interests.
183
Higher repurchases of common shares under the NCIB.
(56)
Lower repayments of long-term debt in 2024 compared to prior year.
33
No long-term debt issued in 2024.
(39)
Lower realized losses on financial instruments.
34
Other
(14)
Cash flow used in financing activities for the year ended Dec. 31, 2024
(291)
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TransAlta Corporation
2024 Integrated Report
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 due to the repayment of US$400 million senior notes in 2022.
457
Higher share capital issuance due to cash used and shares issued to acquire TransAlta Renewables.
(811)
Lower net increase in borrowings under credit facilities.
(495)
Lower issuance of long-term debt due to the Company issuing US$400 million senior notes in 2022.
(493)
Lower realized gains on financial instruments due to recognizing a gain on the repayment of US$400
million senior notes in 2022.
(72)
Higher distributions paid to non-controlling interests.
(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
2024 Integrated Report
M59
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 36, 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, 2024, we provided
letters of credit totalling $865 million (2023 – $782 million)
and cash collateral of $124 million (2023 – $145 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 increase in
the amount of letters of credit issued during 2024 relates
to higher physical and financial derivative transactions in a
net liability position and additions of new letters of credit
issued from the acquisition of Heartland.
Commitments
Contractual commitments are as follows:
2025
2026
2027
2028
2029
2030 and
thereafter
Total
Natural gas and transportation contracts(1)
75
68
65
66
64
425
763
Transmission(1)
23
23
21
10
8
105
190
Coal supply agreements(1)
75
—
—
—
—
—
75
Long-term service agreements(1)
61
47
50
31
18
151
358
Operating leases(1,2)
4
3
3
2
2
22
36
Long-term debt(3)
566
169
331
309
824
1,493 3,692
Exchangeable securities(4)
—
—
—
—
—
750
750
Principal payments on lease liabilities
4
5
5
5
5
127
151
Interest on long-term debt and lease liabilities(1)(5)
205
178
169
151
136
649 1,488
Interest on exchangeable securities(1,4)
53
53
53
52
12
—
223
Growth(1)
46
3
—
—
—
—
49
Total
1,112
549
697
626 1,069
3,722 7,775
(1)
Not recognized as a financial liability on the Consolidated Statements of Financial Position and excludes the impact of interest rate hedges.
(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) The exchangeable debentures are due May 1, 2039 and the exchangeable preferred shares are perpetual. However, a cash payment could occur after
Dec. 31, 2028, at the Company's option, if the exchangeable securities are not exchanged by Brookfield Renewable Partners or its affiliates (collectively
Brookfield). At Brookfield's option, the exchangeable securities are currently exchangeable into an equity ownership interest in TransAlta’s Alberta Hydro
Assets.
(5) Interest on long-term debt is based on debt currently in place with no assumption as to refinancing on maturity.
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Contingencies
TransAlta is occasionally named as a party in various
claims and legal and regulatory proceedings that arise
during the normal course of its business. TransAlta reviews
each of these claims, including the nature of the claim, the
amount in dispute or claimed and the availability of
insurance coverage. There can be no assurance that any
particular claim will be resolved in the Company’s favour or
that such claims may not have a material adverse effect on
TransAlta. Inquiries from regulatory bodies may also arise
in the normal course of business, to which the Company
responds as required.
The Company conducts internal reviews of its offers and
offer behaviour in both the energy and ancillary services
markets in Alberta on an ongoing basis and will self-report
suspected contraventions or respond to inquiries from
regulatory agencies as required. There currently is no
certainty that any particular matter will be resolved in the
Company’s favour or that such matters may not have a
material adverse effect on TransAlta.
Brazeau Facility — Well Licence Applications
to Consider Hydraulic Fracturing Activities
The Alberta Energy Regulator (AER) issued a subsurface
order on May 27, 2019, which does not permit any
hydraulic fracturing within three kilometres of the Brazeau
facility, but permits hydraulic fracturing in all formations
(except the Duvernay) within three to five kilometres of the
Brazeau facility. Subsequently, two oil and gas operators
submitted applications to the AER for 10 well licences
(which include hydraulic fracturing activities) within three
to five kilometres of the Brazeau facility.
The Company's position, based on independent expert
analysis commissioned by the Government of Alberta, is
that hydraulic fracturing activities within five kilometres of
the Brazeau facility pose an unacceptable risk and that the
applications should be denied. The regulatory hearing to
consider these applications - Proceeding 379 - has been
adjourned to November 2025.
Brazeau Facility - Claim Against the
Government of Alberta
On Sept. 9, 2022, the Company filed a Statement of Claim
against the Government of Alberta in the Alberta Court of
King’s Bench seeking a declaration that: (a) granting
mineral leases within five kilometres of the Brazeau facility
is a breach of a 1960 agreement between the Company
and the Alberta Government; and (b) the Government of
Alberta is required to indemnify the Company for any costs
or damages that result from the risks of hydraulic fracturing
near the Brazeau facility. On Sept. 29, 2022, the
Government of Alberta filed its Statement of Defence,
which asserts, among other things, that the Company: (a)
is trying to usurp the jurisdiction of the AER; and (b) is out
of time under the Limitations Act (Alberta). The trial is
scheduled to be heard in September or October 2025 in
the event the parties are unable to resolve the dispute
prior to such date.
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 $53 million
in damages. The Company disputes this claim in its entirety
and asserts a counterclaim. The parties have initiated the
dispute resolution procedure with an arbitration hearing
scheduled for three weeks starting April 14, 2025.
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
application was heard by Alberta Utilities Commission in
the first quarter of 2024. A decision was rendered on
Dec. 9, 2024, which directed the Balancing Pool to pay
TransAlta
$9
million,
being
the
shortfall
of
decommissioning costs of Sundance A from previously
collected amounts under the Power Purchase Arrangement
Regulation.
Brazeau — Spinning Reserve Self-Report
On Nov. 30, 2022, TransAlta self-reported to the Market
Surveillance Administrator (MSA) a potential violation of the
Independent System Operator rules relating to offers of
active spinning reserves at Brazeau when it was not
properly configured to do so between Aug. 13, 2021, and
Nov. 1, 2022. In 2022 a provision of $20 million was initially
recognized in revenue reflecting a potential disgorgement
of revenue and $2 million for potential penalties and fines.
On Nov. 29, 2024, the MSA issued penalties to TransAlta
for this self-report and TransAlta made a payment of $33
million in January 2025.
TransAlta Corporation
2024 Integrated Report
M61
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 when 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
U.S. dollar 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 on 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 U.S. dollar 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
matching foreign-denominated expenses with revenues,
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2024 Integrated Report
such as offsetting revenues from our U.S. operations with
interest payments on our U.S. dollar denominated 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, 2024, Level III instruments had a net liabilities
carrying value of $234 million (2023 – net liabilities $147
million). The Level III liabilities increased in 2024 primarily
due to market price changes and the addition of
contingent
consideration
related
to
the
Planned
Divestitures from the acquisition of Heartland, offset by
contract settlements in the year. Our risk management
profile and practices have not changed materially from
Dec. 31, 2023.
Refer to the Material Accounting Policies and Critical
Accounting Estimates section of this MD&A for further
details regarding valuation techniques.
TransAlta Corporation
2024 Integrated Report
M63
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, 2024, 2023
and
2022.
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, Adjusted gross margin, total
consolidated net debt and adjusted net debt are non-IFRS
measures that are presented in this MD&A. This section
provides additional information in respect of such non-IFRS
measures, 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. In the fourth
quarter of 2024, our adjusted EBITDA composition was
adjusted to exclude the impact of the Brazeau penalties
assessed,
the
Sundance
A
decommissioning
cost
reimbursement, the ERP integration costs, revenues and
expenses of the Planned Divestitures and Acquisition
related and integration costs associated with the Heartland
acquisition as these transactions are not reflective of
ongoing operations or performance of our operating
assets. Accordingly, the Company has applied this
composition to all previously reported periods. 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 most directly comparable IFRS
measure is earnings before income taxes.
The following are descriptions of the adjustments made.
Adjustments to Revenue
• 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.
• Certain assets that we own in Canada and in Western
Australia are fully contracted and recorded as finance
leases under IFRS. We believe that it is more appropriate
to reflect the payments we receive under the contracts
as a capacity payment in our revenues instead of as
finance lease income and a decrease in finance lease
receivables.
• The Brazeau penalties are issued by the Alberta Market
Surveillance
Administrator
for
self-reported
contraventions pertaining to Hydro ancillary services
provided during 2021 and 2022. The penalties have been
excluded and does not represent ongoing performance.
In 2022 a provision of $20 million was initially recognized
in revenue reflecting a potential disgorgement of revenue
and $2 million for potential penalties and fines. The final
assessment contained no disgorgement of revenue and
penalties of $33 million. This resulted in a reversal of the
original disgorgement provision in revenue in the year
ended Dec. 31, 2024 and recognition of the full amount
of the penalties assessed in OM&A.
• Revenues from the Planned Divestitures are not included
as they do not reflect ongoing business performance.
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.
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2024 Integrated Report
• Fuel and purchased power from the Planned Divestitures
is not included as it does not reflect ongoing business
performance.
Adjustments to OM&A
• Acquisition-related transaction and restructuring costs,
mainly comprising severance, legal and consultant fees,
are not included as these do not reflect ongoing business
performance.
• The Brazeau penalties are issued by the Alberta Market
Surveillance
Administrator
for
self-reported
contraventions pertaining to Hydro ancillary services
provided during 2021 and 2022. The penalties have
been excluded as it does not represent ongoing
performance. The provision was initially recognized in
2022 based on an estimate and revised in 2024 based on
the actual resolution of the matter.
• ERP integration costs representing planning and design
of upgrades to the existing ERP system in 2024 are not
included as they represent project costs that do not
occur on a regular basis and therefore, do not reflect
ongoing performance.
Adjustments to Net Other Operating Income
• The Sundance A decommissioning cost reimbursement in
2024 is not included as it relates to a settlement of a
contingency for a facility that is no longer in operation.
Refer to Note 8 from our consolidated financial
statements for further details.
• Insurance recoveries related to the Kent Hills tower
collapse in 2023 and 2022 are not included as these
relate to investing activities and are not reflective of
ongoing business performance.
• An
onerous
contract
provision
for
future
royalty
payments recognized with the shutdown of the Highvale
mine is excluded in 2022 as these are not part of
operating income.
• Contract termination penalties in 2022 as a result of the
Company's Clean Energy Transition plan are not included.
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.
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 is expected to generate.
Funds From Operations (FFO)
FFO is an important metric as it provides a proxy for cash
generated from operating activities before changes in
working capital and provides the ability to evaluate cash
flow trends in comparison with results from prior periods.
FFO is a non-IFRS measure. For a description of the
adjustments made to Cash Flow from Operations (the most
directly comparable IFRS measure) to calculate FFO, see
the tables on pages M70 and M74.
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.
• Sundance A decommissioning cost reimbursement in
2024 is not included as it relates to a settlement of a
contingency for a facility that is no longer in operation.
• Cash received/paid on closed positions are reflected in
the period that the position is settled.
• We adjust for costs associated with acquisition-related
transactions or restructuring and that are not reflective of
ongoing operations.
• Other
adjustments
include
payments/receipts
for
production tax credits, which are reductions to tax equity
TransAlta Corporation
2024 Integrated Report
M65
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. For a description of
the adjustments made to Cash Flow from Operations (the
most directly comparable IFRS measure) to calculate FCF,
see the tables on pages M70 and M74.
Adjusted Gross Margin
Adjusted gross margin is calculated as adjusted revenues
less adjusted fuel and purchased power and carbon
compliance costs, where adjustments to revenue or fuel
and purchased power were applied as stated above. The
Skookumchuck wind facility has been included on a
proportionate basis in the Wind and Solar segment. The
most directly comparable measure is gross margin in the
consolidated statement of earnings.
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
Sustaining
capital
expenditures
and
growth
and
development expenditures are supplementary financial
measures used to present our spend related to facilitate
safe and reliable operation of our existing facilities and the
construction of projects, respectively. Refer to the Capital
Expenditures
section
of
this
MD&A
for
additional
information.
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
Portfolio
section
of
this
MD&A
for
additional information.
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TransAlta Corporation
2024 Integrated Report
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, 2024:
Hydro
Wind &
Solar(1)
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
Equity-
accounted
investments(1)
Reclass
adjustments
IFRS
financials
Revenues
409
357 1,350
616
168
(34) 2,866
(21)
—
2,845
Reclassifications and adjustments:
Unrealized mark-to-market (gain)
loss
1
84
(60)
(36)
14
—
3
—
(3)
—
Realized gain (loss) on closed
exchange positions
—
—
7
2
(15)
—
(6)
—
6
—
Decrease in finance lease
receivable
—
2
19
—
—
—
21
—
(21)
—
Finance lease income
—
6
8
—
—
—
14
—
(14)
—
Revenues from Planned Divestitures
—
—
(1)
—
—
—
(1)
—
1
—
Brazeau penalties
(20)
—
—
—
—
—
(20)
—
20
—
Unrealized foreign exchange loss
on commodity
—
—
(2)
—
—
—
(2)
—
2
—
Adjusted revenues
390
449 1,321
582
167
(34) 2,875
(21)
(9)
2,845
Fuel and purchased power
16
30
475
418
—
—
939
—
—
939
Reclassifications and adjustments:
Fuel and purchased power related
to Planned Divestitures
—
—
(1)
—
—
—
(1)
—
1
—
Australian interest income
—
—
(4)
—
—
—
(4)
—
4
—
Adjusted fuel and purchased power
16
30
470
418
—
—
934
—
5
939
Carbon compliance
—
—
145
1
—
(34)
112
—
—
112
Gross margin
374
419
706
163
167
— 1,829
(21)
(14)
1,794
OM&A
86
97
198
69
36
173
659
(4)
—
655
Reclassifications and adjustments:
Brazeau penalties
(31)
—
—
—
—
—
(31)
—
31
—
ERP integration costs
—
—
—
—
—
(14)
(14)
—
14
—
Acquisition-related transaction
and restructuring costs
—
—
—
—
—
(24)
(24)
24
—
Adjusted OM&A
55
97
198
69
36
135
590
(4)
69
655
Taxes, other than income taxes
3
16
13
3
—
1
36
—
—
36
Net other operating income
—
(10)
(40)
(9)
—
—
(59)
—
—
(59)
Reclassifications and adjustments:
Sundance A decommissioning
cost reimbursement
—
—
—
9
—
—
9
—
(9)
—
Adjusted net other operating
income
—
(10)
(40)
—
—
—
(50)
—
(9)
(59)
Adjusted EBITDA(2)
316
316
535
91
131
(136) 1,253
Equity income
5
Finance lease income
14
Depreciation and amortization
(531)
Asset impairment charges
(46)
Interest income
30
Interest expense
(324)
Foreign exchange gain
5
Gain on sale of assets and other
4
Earnings before income taxes
319
(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 and may not be comparable to similar measures presented by other
issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
TransAlta Corporation
2024 Integrated Report
M67
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 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 gain
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 gain
(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 and may not be comparable to similar measures presented by other
issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
M68
TransAlta Corporation
2024 Integrated Report
The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for
the year ended Dec. 31, 2022:
Revenues
606
303 1,209
714
160
(2) 2,990
(14)
2,976
Reclassifications and
adjustments:
Unrealized mark-to-market
(gain) 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)
—
Brazeau penalties
20
—
—
—
—
—
20
—
(20)
—
Unrealized foreign exchange
gain on commodity
—
—
—
—
(1)
—
(1)
—
1
—
Adjusted revenues
627
407 1,521
724
218
(2) 3,495
(14)
(505)
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
605
375
801
159
218
— 2,158
(14)
(509)
1,635
OM&A
55
68
195
69
35
101
523
(2)
—
521
Reclassifications and
adjustments:
Brazeau penalties
(2)
—
—
—
—
—
(2)
—
2
—
Adjusted OM&A
53
68
195
69
35
101
521
(2)
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:
Royalty onerous contract and
contract termination
penalties
—
7
—
—
—
—
7
—
(7)
—
Adjusted net other operating
income
—
(16)
(38)
—
—
—
(54)
3
(7)
(58)
Adjusted EBITDA(2)(3)
549
311
629
86
183
(102) 1,656
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
Hydro
Wind &
Solar(1)
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
Equity-
accounted
investments(1)
Reclass
adjustments
IFRS
financials
(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 and may not be comparable to similar measures presented by other issuers.
Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(3) During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the
Company has applied this composition to all previously reported periods. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
TransAlta Corporation
2024 Integrated Report
M69
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:
2024
2023
2022
Cash flow from operating activities(1)
796
1,464
877
Change in non-cash operating working capital balances
(38)
(124)
316
Cash flow from operations before changes in working capital
758
1,340
1,193
Adjustments
Share of adjusted FFO from joint venture(1)
8
8
8
Decrease in finance lease receivable
21
55
46
Clean energy transition provisions and adjustments(2)
—
11
42
Sundance A decommissioning cost reimbursement
(9)
—
—
Realized gain (loss) on closed exchanged positions
(6)
(81)
37
Acquisition-related transaction and restructuring costs
19
—
—
Other(3)
19
18
20
FFO(4)
810
1,351
1,346
Deduct:
Sustaining capital(1)
(142)
(174)
(142)
Productivity capital
(1)
(3)
(4)
Dividends paid on preferred shares
(52)
(51)
(43)
Distributions paid to subsidiaries’ non-controlling interests
(40)
(223)
(187)
Principal payments on lease liabilities
(6)
(10)
(9)
FCF(4)
569
890
961
Weighted average number of common shares outstanding in the period
302
276
271
FFO per share(4)
2.68
4.89
4.97
FCF per share(4)
1.88
3.22
3.55
(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 U.S. 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.
(3) Other consists of production tax credits, which is a reduction to tax equity debt, less distributions from an equity-accounted joint venture.
(4) These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.
Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
M70
TransAlta Corporation
2024 Integrated Report
The table below provides a reconciliation of our adjusted EBITDA to our FFO and FCF:
Year ended Dec. 31
2024
2023
2022(5)
Adjusted EBITDA(1)(4)
1,253
1,632
1,656
Provisions
10
(1)
25
Net interest expense(2)
(231)
(164)
(200)
Current income tax expense
(143)
(50)
(65)
Realized foreign exchange loss
(27)
(4)
—
Decommissioning and restoration costs settled
(41)
(37)
(35)
Other non-cash items
(11)
(25)
(35)
FFO(3)(4)
810
1,351
1,346
Deduct:
Sustaining capital(4)
(142)
(174)
(142)
Productivity capital
(1)
(3)
(4)
Dividends paid on preferred shares
(52)
(51)
(43)
Distributions paid to subsidiaries’ non-controlling interests
(40)
(223)
(187)
Principal payments on lease liabilities
(6)
(10)
(9)
FCF(3)(4)
569
890
961
(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 less interest income and excludes non-cash items like financing amortization and accretion.
(3) These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.
FFO and FCF are defined in the 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.
(5) During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the
Company has applied this composition to all previously reported periods. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
TransAlta Corporation
2024 Integrated Report
M71
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, 2024:
Revenues
93
104
319
155
14
—
685
(7)
—
678
Reclassifications and adjustments:
Unrealized mark-to-market
(gain) loss
4
23
26
(8)
19
—
64
—
(64)
—
Realized gains (losses) on
closed exchange positions
—
—
(1)
2
1
—
2
—
(2)
—
Decrease in finance
lease receivable
—
1
5
—
—
—
6
—
(6)
—
Finance lease income
—
2
3
—
—
—
5
—
(5)
—
Revenues from Planned
Divestitures
—
—
(1)
—
—
—
(1)
—
1
—
Brazeau penalties
(20)
—
—
—
—
—
(20)
—
20
—
Unrealized foreign exchange
gain on commodity
—
—
(1)
—
—
—
(1)
—
1
—
Adjusted revenues
77
130
350
149
34
—
740
(7)
(55)
678
Fuel and purchased power
3
8
136
102
—
—
249
—
—
249
Reclassifications and adjustments:
Fuel and purchased power
related to Planned Divestitures
—
—
(1)
—
—
—
(1)
—
1
—
Australian interest income
—
—
(1)
—
—
—
(1)
—
1
—
Adjusted fuel and
purchased power
3
8
134
102
—
—
247
—
2
249
Carbon compliance
—
—
39
—
—
—
39
—
—
39
Gross margin
74
122
177
47
34
—
454
(7)
(57)
390
OM&A
47
27
67
19
7
68
235
(1)
—
234
Reclassifications and adjustments:
Brazeau penalties
(31)
—
—
—
—
—
(31)
—
31
—
ERP integration costs
—
—
—
—
—
(14)
(14)
—
14
—
Acquisition-related transaction
and restructuring costs
—
—
—
—
—
(16)
(16)
—
16
—
Adjusted OM&A
16
27
67
19
7
38
174
(1)
61
234
Taxes, other than income taxes
1
3
4
—
—
—
8
1
—
9
Net other operating income
—
(3)
(10)
(9)
—
—
(22)
—
—
(22)
Reclassifications and adjustments:
Sundance A decommissioning
cost reimbursement
—
—
—
9
—
—
9
—
(9)
—
Adjusted net other
operating income
—
(3)
(10)
—
—
—
(13)
—
(9)
(22)
Adjusted EBITDA(2)
57
95
116
28
27
(38)
285
Equity income
2
Finance lease income
5
Depreciation and amortization
(143)
Asset impairment charges
(20)
Interest income
11
Interest expense
(92)
Foreign exchange gain
17
Loss before income taxes
(51)
Hydro
Wind &
Solar(1)
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
Equity-
accounted
investments(1)
Reclass
adjustments
IFRS
financials
(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 and may not be comparable to similar measures presented by other issuers.
Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
M72
TransAlta Corporation
2024 Integrated Report
The following table reflects adjusted EBITDA by segment and provides reconciliation to loss 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 charges
(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 and may not be comparable to similar measures presented by other
issuers. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
TransAlta Corporation
2024 Integrated Report
M73
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
2024
2023
Cash flow from operating activities(1)
215
310
Change in non-cash operating working capital balances
(97)
(135)
Cash flow from operations before changes in working capital
118
175
Adjustments
Share of adjusted FFO from joint venture(1)
4
3
Decrease in finance lease receivable
6
15
Clean energy transition provisions and adjustments(2)
—
4
Sundance A decommissioning cost reimbursement
(9)
—
Realized gain on closed exchanged positions
2
27
Acquisition-related transaction and restructuring costs
11
—
Other(3)
5
5
FFO(3)
137
229
Deduct:
Sustaining capital(1)
(67)
(74)
Productivity capital
(1)
(1)
Dividends paid on preferred shares
(13)
(12)
Distributions paid to subsidiaries’ non-controlling interests
(6)
(19)
Principal payments on lease liabilities
(3)
(2)
Other
1
—
FCF(4)
48
121
Weighted average number of common shares outstanding in the period
298
308
FFO per share(4)
0.46
0.74
FCF per share(4)
0.16
0.39
(1)
Includes our share of amounts for Skookumchuck, an equity-accounted joint venture. The amount for the fourth quarter of 2023 was adjusted to
conform to current period presentation.
(2) Includes amounts related to onerous contracts recognized in 2021 and a voluntary contribution to the U.S. 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 and may not be comparable to similar measures presented by other issuers.
Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
M74
TransAlta Corporation
2024 Integrated Report
The table below provides a reconciliation of our adjusted EBITDA to our FFO and FCF for the three months ended
Dec 31. 2024 and 2023:
Three months ended Dec. 31
2024
2023
Adjusted EBITDA(1)(4)
285
289
Provisions
2
(1)
Net interest expense(2)
(64)
(41)
Current income tax (expense) recovery
(20)
5
Realized foreign exchange loss (gain)
(20)
9
Decommissioning and restoration costs settled
(12)
(15)
Other non-cash items
(34)
(17)
FFO(3)(4)
137
229
Deduct:
Sustaining capital(4)
(67)
(74)
Productivity capital
(1)
(1)
Dividends paid on preferred shares
(13)
(12)
Distributions paid to subsidiaries’ non-controlling interests
(6)
(19)
Principal payments on lease liabilities
(3)
(2)
Other
1
—
FCF(3)(4)
48
121
(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 less interest income and excludes non-cash items like financing amortization and accretion.
(3) These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.
FFO and FCF are defined in the 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.
TransAlta Corporation
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M75
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
2024
2023
2022
Credit facilities, long-term debt and lease liabilities(1)
3,808
3,466
3,653
Exchangeable debentures
350
344
339
Less: Cash and cash equivalents(2)
(336)
(345)
(1,118)
Add: 50 per cent of issued preferred shares and exchangeable
preferred shares(3)
671
671
671
Other(4)
(24)
(12)
(20)
Adjusted net debt(5)
4,469
4,124
3,525
Adjusted EBITDA(6)(7)
1,253
1,632
1,656
Adjusted net debt to adjusted EBITDA (times)
3.6
2.5
2.1
(1)
Consists of current and non-current portions of long-term 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 2024, 2023 and 2022) 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 and may not be comparable to similar measures presented by other issuers. Presenting this
item from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’
results. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(6) Last 12 months.
(7)
During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the
Company has applied this composition to all previously reported periods. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this
MD&A.
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, 2024 was
higher compared to Dec. 31, 2023, due to higher adjusted
net debt resulting from the assumption of Heartland debt,
lower cash balances due to cash paid to acquire Heartland
on Dec. 4, 2024 and lower adjusted EBITDA in 2024
compared to 2023.
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TransAlta Corporation
2024 Integrated Report
2025 Outlook
For 2025, the Company expects adjusted EBITDA to be in
the range of $1.15 to $1.25 billion and FCF to be in the
range of $450 to $550 million which is based on
the following:
• Higher contribution from the wind and solar portfolio due
to a full-year impact of new asset additions of the White
Rock and Horizon Hill wind facilities;
• Contribution from assets acquired with Heartland;
• Lower contributions from the legacy merchant hydro,
wind and gas assets in Alberta which are expected to
step down due to lower expected average power prices
in Alberta given baseload gas and renewables supply
additions in late 2024 and 2025;
• Lower current income tax expense in 2025 compared to
2024 actual; and
• Increased net interest expense in 2025 as a result of the
Heartland acquisition and 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 2025 and should be
read in conjunction with the narrative discussion that follows and the Governance and Risk Management section of
this MD&A:
Measure
2025 Target
2024 Target
2024 Actual
Adjusted EBITDA(1)
$1,150 to $1,250 million
$1,150 to $1,300 million
$1,253 million
FCF(1)(2)
$450 to $550 million
$450 to $600 million
$569 million
FCF per share
$1.51 to $1.85
$1.47 to $1.96
$1.88
Dividend per share
$0.26 annualized
$0.24 annualized
$0.24 annualized
(1)
These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.
Refer to the Reconciliation of Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations
to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
The Company's outlook for 2025 may be impacted by a number of factors as detailed further below.
Range of key 2025 power and gas price assumptions
Market
2025 Assumptions
2024 Assumptions
2024 Actual
Alberta spot ($/MWh)
$40 to $60
$75 to $95
$63
Mid-Columbia spot (US$/MWh)
US$50 to US$70
US$85 to US$95
US$76
AECO gas price ($/GJ)
$1.60 to $2.10
$2.50 to $3.00
$1.29
Alberta spot price sensitivity: a +/- $1 per MWh change in spot price is expected to have a +/-$3 million impact on
adjusted EBITDA for 2025.
Other assumptions relevant to the 2025 outlook
Measure
2025 Expectations
2024 Expectations
2024 Actual
Energy Marketing gross margin
$110 to $130 million
$110 to $130 million
$167 million
Sustaining capital
$145 to $165 million
$130 to $150 million
$142 million
Current income tax expense
$95 to $130 million
$95 to $130 million
$143 million
Net interest expense
$255 to $275 million
$240 to $260 million
$231 million
TransAlta Corporation
2024 Integrated Report
M77
Alberta Hedging
Range of hedging assumptions
Q1 2025
Q2 2025
Q3 2025
Q4 2025
2026
Hedged production (GWh)
2,117
1,758
1,942
1,845
4,713
Hedge price ($/MWh)
$72
$70
$70
$70
$75
Hedged gas volumes (GJ)
14 million
6 million
6 million
6 million
18 million
Hedge gas prices ($/GJ)
$2.98
$3.63
$3.77
$3.65
$3.67
Market Pricing
The following graphs include 2025 pricing based on a range of assumptions and are subject to change:
Annual Average Spot Electricity Prices
$63
$56
$50
$60
2024
2025 (Assumption)
AB System Market Price
($/MWh)
Mid-Columbia Price
(US$/MWh)
Annual Average Gas (AECO) Prices
$1.29
$1.85
2024
2025 (Assumption)
Natural gas price (AECO) per GJ
For 2025, spot electricity prices in Alberta are expected to
be lower compared to 2024, driven by normalized weather
expectations and the addition of new natural gas and
cogeneration, and wind and solar supply. Spot electricity
prices in the Pacific Northwest are expected to be
comparable in 2025, but will depend on natural gas prices
and the actual hydrology for the region during the year.
AECO natural gas prices are expected to be higher than in
2024.
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 facilities and also allocated to our
portfolio of hydro facilities rather than a single facility.
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TransAlta Corporation
2024 Integrated Report
Sustaining Capital Expenditures
Our estimate for total sustaining capital is as follows:
Spent in 2024
Expected spend in 2025
Total sustaining capital
$142 million
$145 to $165 million
The Company expects sustaining capital to be in the range
of $145 to $165 million. The midpoint for the range
represents an 11 per cent increase from the midpoint of the
2024 expected sustaining capital range of $130 to $150
million, and a nine per cent increase from 2024 sustaining
capital spend. This is driven by increased Hydro dam
safety spending and the additional capital requirements to
support Heartland gas facilities, offset by lower sustaining
capital expenditures for planned major maintenance
related to our other gas facilities and lower sustaining
capital from our Energy Transition segment as 2025 is our
Centralia plant's final year of coal-fired generation.
Liquidity and Capital Resources
We maintain adequate available liquidity under our
committed credit facilities. As at Dec. 31, 2024, we had
access to $1.6 billion in liquidity, including $336 million in
cash, which exceeds the funds required for committed
growth, sustaining capital and productivity projects.
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:
Tariff
On Feb. 1, 2025, the President of the United States issued
three executive orders directing the United States to
impose new tariffs on imports originating from Canada,
Mexico and China. These orders call for additional 25 per
cent duty on imports into the United States of Canadian-
origin and Mexican-origin products and 10 per cent duty on
Chinese-origin products, except for Canadian energy
resources that are subject to an additional 10 per cent
duty. On Feb. 3, 2025, a 30-day pause on potential tariffs
was implemented. The actual tariffs and their impacts to
the Company remain uncertain. The Company is assessing
the direct and indirect impacts to its business of such
tariffs, retaliatory tariffs or other trade protectionist
measures implemented as this situation develops.
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
TransAlta Corporation
2024 Integrated Report
M79
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 to determine
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.
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 composed 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, 2024, is an estimated total upside of
$200 million (2023 – $194 million) and total downside of
$146 million (2023 – $116 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
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TransAlta Corporation
2024 Integrated Report
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 $30 million (2023 – $25
million) potential impact to the carrying value of nil as at
Dec. 31, 2024 (2023 – 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.
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 2024.
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
During 2024, the Company recorded asset impairment
charges of $24 million related to retired assets due to
changes in discount rates and cash flow revisions. Refer to
Note 24 and 7 in our consolidated financial statements for
further details.
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 2024 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
2024, the Company relied on the recoverable amounts
determined in 2023 for the Hydro and Energy Marketing
segments in performing the 2024 goodwill impairment
review. The recoverable amounts are based on the
TransAlta Corporation
2024 Integrated Report
M81
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 2024, 2023 and 2022.
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.
The significant assumptions impacting the determination of
fair value for the Wind and Solar segment, with a high
degree of subjectivity, are the following:
• Forecasts of sales prices for each facility are determined
by taking into consideration contract prices for facilities
subject to long- or short-term contracts, forward price
curves for merchant plants and regional supply-demand
balances. Where forward price curves are not available for
the duration of the facility’s useful life, prices are
determined by extrapolation techniques using historical
industry and company-specific data. Merchant electricity
prices used in Wind and Solar models ranged between $40
to $225 per MWh during the forecast period (2023 – $35
to $238 per MWh).
• Discount rates used ranged from 6.4 to 7.3 per cent
(2023 – 6.4 to 7.5 per cent).
• The White Rock and Horizon Hill wind facilities are
subject to location specific price basis, sourced from third
party analysis. This analysis is based on models of the
transmission
system,
including
assumptions
around
potential
system
upgrades
as
well
as
forecasted
generation and load in the area.
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). At
the end of each reporting period, we assess whether there
is any indication that capitalized project development costs
are impaired by evaluating the effect of any significant
adverse events on projects, including the evaluation of
whether the criteria for capitalization continues to be
appropriate. During 2024, the Company recognized
impairment of project development costs related to
projects that are no longer proceeding. Refer to note 7 of
our consolidated financial statements.
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.
Change in Estimate — Useful Lives
During 2024 and 2023, the Company adjusted the useful
lives of certain assets in the Gas segment to reflect
changes to the future operating expectations of the assets.
This resulted in a decrease of $112 million (2023 -
$92 million) in depreciation expense that was recognized in
the Consolidated Statement of Earnings in 2024 and 2023,
respectively.
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.
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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 that 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 depends on 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 decreased by $9 million to $146 million as at
Dec. 31, 2024, from $155 million as at Dec. 31, 2023. A one
per cent increase in discount rates would have a $34
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
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.
On Dec. 4, 2024 as part of the Heartland acquisition, the
Company recognized decommissioning and restoration
provision of $101 million.
During
2024,
the
decommissioning
and
restoration
provision increased by $21 million due to revisions in
estimated cash flows and timing of cash flows for certain
Gas and Hydro assets. The timing of cash flows was
adjusted to optimize and maximize efficiencies by staging
required reclamation work. Operating assets included in
PP&E increased by $14 million and $7 million was
recognized as an impairment charge in net earnings related
to retired assets.
During 2024, revisions in discount rates increased the
decommissioning and restoration provision by $35 million
due to a decrease in discount rates. On average, discount
rates decreased compared to 2023, with rates ranging
from 5.3 to 8.4 per cent as at Dec. 31, 2024. This has
resulted in a corresponding increase in PP&E of $18
million on operating assets and the recognition of a
$17 million impairment charge in net earnings related to
retired assets.
TransAlta Corporation
2024 Integrated Report
M83
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. As part of the acquisition of
Heartland, the Company recognized an onerous contract
provision of $47 million related to certain natural gas
transportation contracts assumed. Payments required
under the contracts continue through the first quarter of
2031.
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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TransAlta Corporation
2024 Integrated Report
Accounting Changes
Current Accounting Changes
Amendments to IAS 1 — Non-current
Liabilities with Covenants and Classification of
Liabilities as Current or Non-current
In October 2022, the IASB issued Non-current Liabilities
with Covenants, which amends IAS 1 Presentation of
Financial Statements, to clarify how conditions with which
an entity must comply within 12 months after the reporting
period affect the classification of a liability. In January
2020, the IASB issued Classification of Liabilities as
Current or Non-current, which amends IAS 1 Presentation
of Financial Statements regarding the classification of
liabilities
as
current
or
non‐current,
clarifying
that
contractual
rights
and
conditions
existing
at
the end of the reporting period are relevant in determining
whether the Company has a right to defer settlement of a
liability by at least 12 months.
Additionally, the IASB clarified that the classification of a
liability is unaffected by the likelihood that an entity will
exercise its deferral right. The amendments are applied
retrospectively, effective for annual periods beginning on
or after Jan. 1, 2024, and were adopted by the Company
on that date.
The Company has an Investment Agreement whereby
Brookfield Renewable Partners or its affiliates (collectively,
Brookfield) invested $750 million in TransAlta through the
purchase
of
exchangeable
securities
(Exchangeable
Securities), which are exchangeable into an equity
ownership interest in TransAlta’s Alberta hydro assets in
the future. On Jan. 1, 2024, the Company reclassified the
Exchangeable Securities from non-current liabilities to
current liabilities as the conversion option can be exercised
at any time after Dec. 31, 2024, although there is no
obligation to deliver cash equivalent resources and the
holder cannot call for repayment. This accounting is
consistent with the amendment.
Future Accounting Changes
Amendments to IFRS 9 and IFRS 7 — Nature-
Dependent Electricity Contracts
On Dec. 18, 2024, the IASB issued amendments to IFRS 9
Financial Instruments and IFRS 7 Financial Instruments:
Disclosure to improve reporting of the financial effects of
nature-dependent
electricity
(e.g.,
wind
and
solar)
contracts, which are often structured as power purchase
agreements. Under these contracts, the amount of
electricity generated can vary based on uncontrollable
factors such as weather conditions. The amendments
clarify the application of own-use requirements, permit
hedge accounting if these contracts are used as hedging
instruments and add new disclosure requirements about
the effect of these contracts on a company's financial
performance and cash flows. The amendments are
effective for annual reporting periods beginning on or after
Jan. 1, 2026. The Company is currently evaluating the
impacts to the financial statements.
Amendments to IFRS 7 and IFRS 9 —
Classification and Measurement of Financial
Instruments
On May 29, 2024, the IASB issued Amendments to the
Classification and Measurement of Financial Instruments
effective Jan. 1, 2026 impacting IFRS 7 and 9. The IASB
amended the requirements related to settling financial
liabilities using an electronic payment system and
assessing contractual cash flow characteristics of financial
assets, including those with ESG-linked features. The
Company is currently evaluating the impacts to the
financial statements.
IFRS 18 — Presentation and Disclosure in
Financial Statements
On April 9, 2024, the IASB issued a new standard, IFRS 18
Presentation and Disclosure in Financial Statements, which
introduced new requirements for improved comparability in
the statement of profit or loss, enhanced transparency of
management-defined performance measures and more
useful grouping of information in the financial statements.
The standard is effective for annual reporting periods
beginning on or after Jan. 1, 2027. The Company is
currently
evaluating
the
impacts
to
the
financial
statements.
TransAlta Corporation
2024 Integrated Report
M85
Sustainability
Sustainability, or environmental, social and governance
(ESG) management and performance, is a core value at
TransAlta. Sustainability is integrated into our governance,
decision-making,
risk
management
and
day-to-day
business processes. Our focus on continuous improvement
on material sustainability factors seeks to mitigate ESG-
related risks and provides long-term value creation to
our stakeholders. TransAlta's sustainability pillars support
our corporate strategy and weave through our business.
Our sustainability pillars were refreshed in 2024 and
include:
• Reliable and Responsible Electricity Production
• Safe, Healthy, Diverse and Engaged Workplace
• Positive Indigenous, Stakeholder, Customer and
Employee Relationships
• Environmental Stewardship
• Technology and Innovation
Reporting on Our Material
Sustainability Factors
TransAlta has been reporting on sustainability since 1994.
The Company's sustainability reporting is integrated within
this MD&A to provide information on how sustainability
factors affect our business and is guided by leading
sustainability reporting frameworks. We partially adopt
guidance from the Canadian Sustainability Standards
Board,
International
Sustainability
Standards
Board,
International
Financial
Reporting
Standards
(IFRS)
Foundation,
Integrated
Reporting
Framework,
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 in the jurisdictions in which we
operate to assess our future reporting obligations.
Since 2007, TransAlta's material sustainability data to be
disclosed has received limited assurance from independent
third-party providers. Climate-related information to be
disclosed is partially informed by the IFRS S2 Climate-
related Disclosures Standard and the recommendations of
the Task Force on Climate-related Financial Disclosures
(TCFD).
In 2024, we reviewed and updated our management
response to our 2021 climate-related scenario analysis. We
also reviewed and updated our Climate Transition Plan and
climate-related financial metrics. GHG emissions data for
scopes 1, 2 and 3 follow the accounting and reporting
standards of the GHG Protocol. For further information on
climate change management and the findings of our
scenario analysis, refer to the Transitioning Our Energy Mix
section of this MD&A.
Disclosure of our most relevant sustainability factors in
2024 remained unchanged from 2022 and is guided by our
most recent materiality assessment. In 2022, we refreshed
our materiality assessment by evaluating key sector-
specific research, supported by internal and external
engagement on key sustainability factors. 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.
Key topics identified within SASB, TCFD, IFRS and the
Taskforce on Nature-related Financial Disclosures (TNFD)
were reviewed 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, validated by our executive team, resulted in the
identification of 21 material sustainability factors, which are
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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TransAlta Corporation
2024 Integrated Report
Our 2024 Sustainability Performance
Performance against our 2024 sustainability targets is outlined below and excludes the acquisition of Heartland
Generation on Dec. 4, 2024 (refer to the Significant and Subsequent Events section of this MD&A). Target year means by
Dec. 31 of that year. For more information on all our sustainability performance indicators, refer to the Sustainability
Performance Indicators section of this report.
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 22.7 MT CO2e or
70 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
Achieved
We received limited assurance on 93 per
cent of TransAlta’s scope 3 emissions in
2024.
Reduce air emissions
By 2026, achieve a 95 per cent
reduction of SO2 emissions and an
80 per cent reduction of NOx
emissions below 2005 levels
Achieved
in 2022
We achieved this target in 2022 through
the reduction of our SO2 emissions by 98
per cent and NOx emissions by 83 per cent
from 2005 levels. In 2024, we retained the
achievement of this target.
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 44 per cent of the coal mine land has
been reclaimed.
By 2046, complete full reclamation
of our Highvale coal mine in Alberta
On track
Our Highvale coal mine in Alberta closed in
2021. Reclamation work is underway and
22 per cent of the coal mine land has
been reclaimed.
Responsible water
management
By 2026, reduce fleet-wide water
consumption (withdrawals minus
discharge) by 20 million m3 or 40
per cent over a 2015 baseline
Achieved
in 2022
We achieved this target in 2022 through
the reduction of our fleet-wide water
consumption by approximately 20 million
m3 or 43 per cent from 2015 levels. In
2024, we retained the achievement of this
target.
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
Achieved
Assessment of nature-related risks and
opportunities was completed in 2024.
Achieve zero biodiversity-related
incidents(3)
Achieved
We
recorded
zero
(0)
biodiversity-
related incidents.
(1)
Gross GHG emissions reduction target, which does not include utilization of internally generated and externally purchased emission credits. TransAlta
does not plan to use carbon credits to achieve its 2026 GHG emissions reduction target.
(2) Target covers 100 per cent of TransAlta's operating assets. 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 the Climate
Transition Plan in the Transitioning Our Energy Mix section of this MD&A.
(3) Biodiversity-related incidents are significant environmental incidents that affect 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.
TransAlta Corporation
2024 Integrated Report
M87
ESG Alignment: Social
Sustainability goal
Sustainability target
Results
Comments
Reduce safety incidents
Achieve a Total Recordable Injury
Frequency (TRIF) rate below 0.32
with a goal of 0.00
Not
Achieved
We recorded a TRIF rate of 0.56
compared to 0.30 in 2023. We recorded
zero serious injuries in 2024. The
identification and control of high-energy
hazards is foundational to our strong
performance
on
serious
injury
prevention.
Integrate sustainability
into supply chain
By 2024, 80 per cent of our spend
will be with suppliers that have a
sustainability policy or commitment
Not
Achieved
On
average,
79
per
cent
of
our
spend in 2022, 2023 and 2024 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
On track
Support represented a total value of
$320,000, or 11 per cent of TransAlta’s
total community investment.
Provide
Indigenous
cultural
awareness
training
during
the
onboarding of all new TransAlta
employees(1)
Achieved
We
provided
Indigenous
awareness
training to 100 per cent of employees in
Canada, the U.S. and Western Australia
onboarded in 2024.
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, 2024, women represented
38 per cent of our Board composition,
compared to 46 per cent in 2023.(2)
Achieve at least 40 per cent female
employment among all employees
of the Company by 2030
On track
As
at
Dec.
31,
2024,
women
represented
28
per
cent
of
all
employees, an increase over 2023
levels (27 per cent).
Maintain equal pay for women in
equivalent roles as men
Achieved
We achieved a 99 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
On track
In 2024, TransAlta received an award for
best ESG reporting (mid-cap) by the IR
Magazine Canada. We also received the
Sustainability, ESG and Purpose Award
from the Governance Professionals of
Canada. This award underscores our
commitment to embedding sustainability
into our governance, strategy and risk
management practices.(3)
(1)
TransAlta employees have 60 days to complete onboarding training; hence, this target refers to employees onboarded from Jan. 1 to Oct. 31, 2024.
(2) Board composition includes all independent directors, and our President and CEO who is not independent. In 2024, we achieved 50 per cent female
representation on the Board, excluding the two nominees from Brookfield.
(3) A description of the specific set of criteria and/or methodology used by the IR Magazine Canada can be found at https://events.irmagazine.com/
canadaawards. The Governance Professionals of Canada 2024 Report of the Judges can be found at https://www.flipsnack.com/gpcanada/2024-gpc-
eg-awards-judges-report/full-view.html.
M88
TransAlta Corporation
2024 Integrated Report
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
coal-fired
generation at Centralia on 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. We plan to cease
coal-fired generation at our Centralia
plant by 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
(302 MW) and Horizon Hill (202 MW). As
a result, our U.S. renewables fleet
represents over 1 GW.
2025+ Sustainability Targets
Our 2025 and longer-term sustainability targets support
the performance of our business. Goals and targets are
established to manage current and emerging material
sustainability factors in support of the United Nations
Sustainable Development Goals (UN SDGs) and the
Future-Fit Business Benchmark, which defines sustainable
goals for businesses.
In 2024, TransAlta updated four sustainability targets in
the areas of air emissions, water resources, safety and
Indigenous relations, while setting a new climate-related
target to achieve a 30 per cent reduction of our scope 1
and 2 GHG emissions intensity by 2030 from a 2023 base
year.
We have maintained our climate-related targets to achieve
net-zero of 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.
Targets are outlined below. Target year means by Dec. 31
of that year.
TransAlta Corporation
2024 Integrated Report
M89
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 2030, achieve a 30 per cent
reduction of scope 1 and 2 GHG
emissions intensity from 2023 base
year
By 2045, achieve net-zero for
scope 1 and 2 GHG emissions(2)
Reduce air emissions
By 2030, achieve a 90 per cent
reduction of SO2 emissions intensity
from 2023 base year
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"
Manage water
resources
By
2030,
maintain
water
consumption
intensity
at
2023
levels
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"
Protect nature and
biodiversity
Achieve zero biodiversity-related
incidents(3)
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”
Transition away from
coal
Cease 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"
(1)
Gross GHG emissions reduction target, which does not include utilization of internally generated and externally purchased emission credits. TransAlta
does not plan to use carbon credits to achieve its 2026 GHG emissions reduction target. The Company may choose to update this target to include the
acquisition of Heartland Generation on Dec. 4, 2024, in alignment with internationally recognized methodologies such as the GHG Protocol.
(2) Target covers 100 per cent of TransAlta's operating assets. 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 the Climate
Transition Plan in the Transitioning Our Energy Mix section of this MD&A.
(3) Biodiversity-related incidents are significant environmental incidents that affect 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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TransAlta Corporation
2024 Integrated Report
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 0.37 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"
Support prosperous
Indigenous
communities
Support access to education and
wellbeing
for
Indigenous
communities
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
TransAlta Corporation
2024 Integrated Report
M91
Transitioning Our Energy Mix
We recognize the impact of climate change on society and
our business both today and into the future. TransAlta's
renewable energy journey began 113 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, we acquired our first solar facility; and, in 2020, we
constructed our first battery storage facility. Today, we
operate 60 renewable power facilities across Canada, the
U.S. and Western Australia.
Our reporting on climate change management has been
guided by the TCFD recommendations since 2018. In
2024, we partially adopted guidance from IFRS S2, which
is based on the TCFD recommendations with industry-
specific climate metrics based on the SASB standards.
Strategy and Risk Management
Climate Change Strategy
As described in the following sections, our risks and
opportunities assessment and scenarios analysis support
the development and continuous improvement of our
climate change strategy. We actively monitor and manage
climate-related risks and opportunities 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 coal),
the phase-out of coal-fired electricity generation, the
development of renewable energy and storage, and the
use of natural gas generation to ensure reliability.
Our customers continue to integrate climate risk into their
business decisions; therefore, we see an advantage in our
renewable power business to support our customers'
sustainability goals. From 2000 to 2024, we increased our
nameplate renewable power capacity from approximately
900 MW to over 3,600 MW. Today, TransAlta is 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 we generate include carbon
offsets, renewable energy credits and emission offsets.
Our customers use environmental attributes to lower
compliance
costs
attributed
to
carbon
policies
or
renewable portfolio standards. Environmental attributes
can also 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 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 into 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. In 2022, TransAlta entered
into an agreement for the expansion of the Mount Keith
132kV transmission system. The expansion was completed
in February 2024.
We have also taken important 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 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 target aligns
with the Canadian Net-Zero Emissions Accountability Act
to achieve net-zero emissions by 2050.
Since 2018, we have retired 4,464 MW of coal-fired
generation capacity, while converting 1,659 MW to natural
gas. Comparatively, our converted natural gas units' CO2
intensity is approximately 57 per cent less than coal-fired
generation. Repurposing these 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." Completed conversions and the closure of
our Highvale coal mine also contribute to the goals of the
Powering Past Coal Alliance, which TransAlta joined in
2021 at COP26. In 2025, we plan to cease coal-fired
operations at our sole remaining coal unit, located in the
U.S., to complete TransAlta's transition away from coal-
fired electricity generation.
We engage with policymakers and stakeholders involved in
the energy transition to ensure that parties understand the
need to maintain reliable, sustainable and affordable
energy as countries move to net-zero electricity systems.
At TransAlta, we plan to continue investing in renewables
and assessing the best options to deliver energy storage.
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At the same time, we believe that natural gas plays an
essential role in the electricity sector, providing critical
reliable, dispatchable generation to support current
systems demands.
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
2024, TransAlta updated its Climate Transition Plan, which
outlines our approach to reducing operational and value
chain emissions with the target to deliver net-zero
operations by 2045. Our Climate Transition Plan includes
sustainable finance and inclusive transition actions that
reflect TransAlta's commitment to a progress toward a
lower-carbon economy. For further information, refer to
Sustainable Finance in the Transitioning 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 (2025-2027) and medium- to long-term actions
(beyond 2028). 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
of Directors (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 Transitioning
Our Energy Mix section of this MD&A.
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Climate Transition Plan
Past actions
Short-term actions
(2025-2027)
Medium to long-term actions
(2028 +)
Hydro
Became the largest producer of
hydro power in Alberta (C)
Evaluate and deploy investments in
renewable
projects,
where
appropriate (C)
Evaluate and deploy investments in
renewable
projects,
where
appropriate (C)
Wind and solar
From 2000 to 2024, we grew our
nameplate renewables capacity
by approximately 2,200 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
Western Australia (C)
Evaluate
and
deploy
battery
storage, where appropriate (C)
Evaluate and deploy battery storage,
where appropriate (C)
Natural gas
Converted 1,659 MW from coal to
natural gas since 2018 (C)
Completed
our
coal-to-gas
conversions
in
Canada
in
2021 (C)
Operate simple-cycle, combined-
cycle and cogeneration facilities in
Canada, the U.S. and Western
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 GHG emissions
(scopes 1 and 2) from gas-fired
generation through fuel switching,
new technologies or nature-based
solutions (C)
Emerging
abatement
technologies
and solutions
In 2023, started partnership 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)
In 2024, started a partnership to
study the deployment of a small
modular nuclear reactor at the
site of an existing coal-to-gas
plant in Alberta (P)
In 2024, continued to support the
development of low-cost, low-
emissions hydrogen production
through a $2 million investment in
a Canadian-based venture (P)
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 4,464 MW of coal-fired
generation capacity since 2018
including ending coal generation
in Canada in 2021 (C)
Ceased coal mining in Canada in
2021 and in the U.S. in 2006 (C)
In 2023, started partnership to
repurpose landfilled fly ash to
advance
low-carbon
concrete
projects in Alberta (P)
Continue to execute reclamation
work at our coal mines (C)
Cease coal-fired generation by the
end of 2025 (C)
Contribute to a circular economy
through mining waste reuse or by-
product sales (C)
Complete
full
reclamation
in
Washington State by 2040 and in
Alberta by 2046 (C)
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Climate Transition Plan (Continued)
Past actions
Short-term actions
(2025-2027)
Medium to long-term actions
(2028 +)
Supply chain
Enhanced
supplier
management
functionality within the corporate
procurement system (C)
From 2022 to 2024, 79 per cent of
our spend was with suppliers that
had
a
sustainability
policy
or
commitment (C)
Develop ESG criteria for supply
chain engagement (C)
Understand direct suppliers, their
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)
Consider setting direction for engaging
suppliers with GHG emissions reduction
targets (C)
Value chain
Updated scope 3 GHG emissions
reporting methodology (C)
In 2024, verified and disclosed 93
per cent of our total scope 3
emissions (C)
Consider scope 3 GHG emissions
targets (C)
Consider
verification
and
disclosure of remaining scope 3
GHG 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 our GHG
emissions reduction and female
employment targets (C)
In 2021, secured $173 million green
bond financing for an 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 an ED&I census to
measure progress (C)
Set employee engagement and
ED&I targets as part of ESG-linked
compensation (C)
Since
2023,
launched
four
employee resource groups (C)
Since 2022, provided Indigenous
cultural awareness training to all
employees (C)
From 2012 to 2023, invested
US$55 million to support energy
efficiency,
economic
and
community
development
and
education and retraining initiatives
in Washington State (P)
Since
2016,
invested
in
the
communities
impacted
by
the
phase-out of coal generation in
Alberta (P)
Empower
employees
through
culture champions to foster a
culture of allyship, inclusion and
belonging (C)
Adapt workplaces to incorporate
structural changes for inclusive
work environments (C)
Embed
ED&I
into
our
culture
strategy and daily work activities
(C)
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)
Advance recruitment and retention of
female employees to progress towards
gender-based targets (C)
Maintain
succession
practices
to
increase diverse representation at the
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)
Provide
ongoing
support
to
local
community organizations aligned with
our community investment pillars where
we operate and grow (P)
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M95
Climate Change Governance
Climate-related risks and opportunities can significantly
impact our business. We therefore actively manage such
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.
Oversight by the Board of Directors
The highest level of climate change oversight is at the
Board level. Specific oversight of certain aspects of the
Company's response to climate change is delegated to the
Board,
its
Governance,
Safety
and
Sustainability
Committee (GSSC), Audit, Finance and Risk Committee
(AFRC), and Investment Performance Committee (IPC).
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 also supports the Board in 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
implemented effectively.
The AFRC and IPC also play an important 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 related to our financial decision-
making. The AFRC is also 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.
The Board reviews and updates the Company's strategy
annually. In 2024, the Board's strategic planning sessions
included
climate-related
issues
considering
growth
initiatives
and
strategies,
capital
allocation,
policy
development and other matters. Our Board is comprised of
individuals with a mix of skills, knowledge and experience
critical to our strategy success and business growth. In
2024, three of our 12 Board members identified
environment/climate change among their top four relevant
competencies. Given the breadth of experience and skills
of each director, the Board skills matrix lists only the top
four competencies of each director nominee, based on the
Board’s assessment and each director’s self-evaluation.
Criteria used to assess competence on climate-related
issues include the director's knowledge of corporate
responsibility practices and sustainable development
practices, including as they pertain 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, mitigate risk, 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
and regulatory 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 link our annual incentive plans (short-term
incentive and long-term incentives) to our strategic goals.
In 2024, our strategic goals included growing renewable
energy and supporting our customers' sustainability goals
to
decarbonize
through
on-site
renewable
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.
Climate Scenarios
In 2021, TransAlta conducted climate scenario analysis to
understand risks and opportunities and assess our
strategy's resiliency under several potential future climate
scenarios.
The
analysis
used
scenarios
from
the
International Energy Agency’s (IEA) World Energy Outlook
2020, 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 U.S.
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.
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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 U.S. 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 U.S.
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 2024, we reviewed the findings from the climate
scenario
analysis
and
updated
the
management
response accordingly.
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M97
Key Climate Scenario Findings
In 2021, TransAlta used climate scenarios from the IEA
World Energy Outlook 2020 to analyze the resiliency of our
business and determine 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. Our scenario
analysis at that time determined that our wind and solar
assets had the highest prospects for growth. Under all
scenarios, hydro remains a valuable asset as it allows for
expansion to include storage.
Findings outlined below may not reflect currently available
climate scenarios or policy frameworks. We continue to
monitor climate-related risks and opportunities that may
impact our business over time. For further information,
refer to the Managing Climate Change Risks and
Opportunities section in this MD&A.
The following sections highlight TransAlta's top risks, opportunities and management response across all scenarios.
Top Identified Climate-Related Risks by Scenario (2021)
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
wholesale
electricity 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 facilities will
be
relied
on
for
baseload
generation. This means that natural
gas facilities may still play a role for
a smooth and efficient energy
transition. Optimization of natural
gas
facilities
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,
further
increasing the operating costs for
natural
gas
plants.
Natural
gas
facilities in the U.S. and Western
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.
Increased clean energy
competition
Decreased demand of
natural gas electricity
Increased operational costs
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NZE
By 2040, renewables are expected
to comprise over 85 per cent of the
total electricity generation in the
regions where 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
facilities
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 facilities.
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
Western
Australia
by
2040
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 facilities 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 facilities, 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
eight 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 facilities.
Operational costs are not expected to
significantly
increase
under
this
scenario as only Canada is expected
to adopt a carbon price in 2040.
Management
response
Navigating
uncertainty
around
market dynamics (structure, pricing
and
competition),
government
policies and planning is critical for
TransAlta. We use hedging and
PPAs
to
reduce
pricing-related
risks. 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.
As
concerns
regarding
grid
reliability and demand increase, we
have
increased
our
focus
on
optimizing our gas facilities to
maximize value and cash flows and
to support future renewables and
storage
growth.
Our
converted
natural gas units' CO2 intensity is
approximately 57 per cent less than
coal generation. Repurposing the
coal
facilities
rather
than
decommissioning them reduces the
cost and emissions associated with
new construction and aligns with
the UN SDGs, specifically "Goal 9:
Industry,
Innovation
and
Infrastructure." In parallel, we plan
to achieve a 100 per cent portfolio
mix of renewables and natural gas
by the end of 2025.
We have taken significant steps to
reduce our carbon footprint. Since
2015, we have reduced scope 1 and 2
GHG emissions by 70 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 have a target to achieve net-zero
emissions by 2045.
Increased clean energy
competition
Decreased demand of
natural gas electricity
Increased operational costs
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Top Identified Climate-Related Opportunities by Scenario (2021)
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
the
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 anticipated to
play an especially 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 U.S.
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 U.S.
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 60
renewable facilities across Canada, the U.S. and
Western Australia. Our strategy is focused on the
operation and/or repurposing of our existing assets
(wind, hydro, solar, gas, storage and coal) and the
development of renewable energy, storage and natural
gas generation for reliability. From 2000 to 2024, we
increased our nameplate renewables capacity from
approximately 900 MW to over 3,600 MW. Today,
TransAlta is one of the largest producers of wind power
in Canada and the largest producer of hydro power
in Alberta.
To address and mitigate 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 into the Alberta grid during system
supply shortages. Further, in 2023, we completed the
Northern Goldfields solar project in Western Australia,
which provides solar electricity supported with a battery
energy storage system and will support BHP Nickel West
in meeting its emissions reduction targets. In 2024,
TransAlta
launched
a
project
with
Atlas
Power
Technologies Inc. for a hybrid hydro supercapacitor
energy storage system, expected to be the first of its kind
in North America. The project is complementary to an
existing hydro facility that augments the power plant’s
response time and the capability to address frequency
response needs.
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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 U.S. 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.
The findings from the climate scenarios 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
used a climate scenario analysis to review specific risks. As
previously
mentioned,
climate
change
risks
and
opportunities are addressed at each of the Board,
executive and management, business unit levels 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. In 2024, we updated the
transition risks outlined below.
Policy and Legal Risks
Changes in current environmental legislation have a
potentially significant impact upon our business and
operations in Canada, the U.S. 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 objectives for carbon
emissions reductions, including a 45 to 50 per cent
national emissions reduction over 2005 levels by 2035, a
net-zero electricity grid by 2035 and a net-zero national
economy by 2050. The current government plans to rely
on several policy tools to achieve its emissions objectives,
including but not limited to carbon pricing, emissions
performance regulations, funding for industrial energy
transition, and incentives for consumers.
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Canada’s provinces have jurisdiction over their respective
electricity sectors and play an important role in setting
carbon
pricing
policy
and
emissions
performance
standards, subject to the federal government's authority to
set national carbon pricing standards. Jurisdictional
responsibilities
between
the
federal
and
provincial
governments enable both levels of government to
implement policies that impact our sector. Leadership
changes at either level of government can influence policy
direction.
Risks
• Changes in carbon pricing and emissions performance
regulations may impact TransAlta’s generation fleet in
Canada as governments may change policy stringency in
conjunction with climate targets.
• 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
current climate targets will require a minimum of twice
Canada’s current non-emitting generation. Further, we
continue to see strong private sector demand for
contracted renewable electricity generation to meet
corporate sustainability goals.
• Government funding to support the development of
innovative technology to reduce emissions from the
electricity
sector
offers
TransAlta
the
potential
opportunity to gain project support to grow its energy
storage fleet.
• Government support for industrial electrification will grow
the
electricity
load
over
time
and
create
new
opportunities for electricity generation.
Management Response
• We believe that TransAlta’s corporate strategy positions
our Company to meet the demand for renewable and
dispatchable 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
as applicable. TransAlta actively assesses available
government renewable energy tax legislation and
programs to maximize, wherever possible, access to
project incentives.
• Our diversified portfolio 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.
• We engage 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.
• 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.
• We engage 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
President Trump was elected on Nov. 4, 2024. It is
expected that the U.S. Government will reduce carbon
emission reduction objectives in 2025 following the
inauguration. Currently, the Inflation Reduction Act of 2022
remains in force and aims to reduce U.S. carbon emissions
by 40 per cent by 2030 from 2005 levels. The U.S. does
not have a national carbon pricing regime but does offer
federal incentives for renewable generation and energy
storage.
State and regional renewable and climate policies have a
significant impact on the pace of energy transition in the
country, with several jurisdictions maintaining renewable
portfolio standards and/or carbon pricing regimes. Similar
to Canada, independent estimates suggest that the U.S.
will
require
substantial
growth
in
zero-emissions
generation to meet its national, state and regional climate
targets.
Risks
• TransAlta operates two thermal generating facilities in
the U.S. that could be subject to policy changes, but we
believe that our risk exposure is low due to existing
agreements and contracts associated with these facilities
(refer to Management Response below).
• Potential changes to federal wind permitting could pose
risks for new wind development projects.
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2024 Integrated Report
• Federal incentives for clean energy that are available
today
are
expected
to
maintain
competition
in
renewables and energy storage.
Opportunities
• Achieving government and private sector sustainability
commitments will require sustained growth in zero-
emissions
electricity
generation
over
the
coming
decades. TransAlta remains focused on providing
renewable electricity as a core component of a balanced
energy portfolio to contracted customers in a manner
that is aligned with federal, state and private sector
goals.
• Strong customer demand to meet low-carbon energy and
reliability needs present opportunities for TransAlta.
• U.S. tax incentive programs offer significant support for
new renewable and energy storage projects, making the
U.S. 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
before 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.
• The Company remains focused on developing and
acquiring contracted assets that provide long-term
certainty with respect to revenue.
• TransAlta will continue to assess government policy
changes related to our business under the new U.S.
administration.
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
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 Western Australian natural gas facilities may
face policy risk related to changes in government policies
but we believe that we remain well positioned to mitigate
those risks (refer to Management Response below).
Opportunities
• The Company remains focused on maintaining renewable
and dispatchable electricity generation in Western
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 renewable 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
• 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.
• The Company continues to deliver renewable 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 renewable energy generation in alignment with
Australia's national and state climate goals.
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
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 shareholder value and maintain reliable and
affordable electricity delivery.
We believe that we are well-positioned to take advantage
of technological opportunities in storage through hydro
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2024 Integrated Report
M103
and/or battery power, as well as advancements in
renewable technologies. 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.
Market Risks
Our major market risks are associated with our natural gas
facilities and specifically carbon pricing which could impact
our operating costs. We actively monitor market risks
through our energy marketing and asset optimization
teams and our ERM process. 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 evaluating fleet growth opportunities.
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 and reliability to the grid.
Reputation Risks
Negative reputational impacts, including revenue loss and
a reduced customer base, are evaluated through our ERM
process. In the past, we experienced negative reputational
impacts due to our coal operations. We believe that our
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 existing natural
gas fleet. We believe that natural-gas-fired generation
enables the energy transition by ensuring the reliability of
the electricity grid. We continue to actively monitor and
manage reputational risks by delivering reliable and
responsible power solutions.
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. These 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.
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.
We continuously evaluate the potential impact of acute
climate change on our business. For example, our gas
facility at the 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 and 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.
Chronic Physical Risks
Chronic physical risks refer to longer-term shifts in climate
patterns that may cause sea level rise, chronic heat waves,
changes in precipitation patterns and extreme variability in
weather patterns.
These variations in weather could have an impact on our
generating assets. Ice can accumulate on wind turbine
blades in the winter months. The accumulation of ice on
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2024 Integrated Report
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 water flow or wind patterns that could impact
our hydro and wind businesses and associated revenue
generation.
Climate Change Metrics and Targets
Metrics and Targets
TransAlta has established climate-related goals and targets with reference to the UN SDGs. Performance against our
2024 climate-related targets is outlined below and excludes the acquisition of Heartland Generation on Dec. 4, 2024.
Target year means by Dec. 31 of that year.
Renewable 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
2024
2025
Progress
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
(302 MW) and Horizon Hill (202 MW).
In 2024, 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 U.S., we plan
to cease coal-fired generation at our Centralia
plant by 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).
GHG 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
We are 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
22.7
MT
CO2e
or
70 per cent.
Since 2005, we have reduced our scope 1 and 2
GHG emissions by 32 million tonnes (MT) of CO2e
or a 77 per cent reduction, proudly representing
approximately 11 per cent of Canada's Paris
Agreement 2030 decarbonization target(1). We
believe that our corporate strategy 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".
(1)
In 2005, TransAlta's estimated scope 1 and 2 GHG emissions were 41.9 MT of CO2e, which did not receive independent limited assurance. Canada's
Paris Agreement 2030 decarbonization target assumed 293 MT of CO2e or a 40 per cent reduction from a 2005 baseline of 732 MT of CO2e.
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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.
GHG Disclosures
Scope 1 and 2 Emissions
Scope 1 emissions are the direct emissions from owned or
controlled sources. Scope 2 emissions are indirect
emissions from the generation of purchased energy.
TransAlta's scope 1 and 2 GHG emissions are calculated
using
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
Greenhouse Gas 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.
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 GHG data is 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 annually. Any historical revisions
will be captured and reported in future disclosure. As per
the 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 natural-gas-powered plants and there are
no fugitive methane emissions associated with our
operations. In 2024, methane emissions were 0.5 per cent
of our total emissions.
The following tables detail our GHG emissions by scope, business segment and country in million tonnes of CO2e. Some
values do not sum to the indicated total due to rounding of tabulated emissions. Zeros (0.0) indicate truncated values.
Year ended Dec. 31
2024
2023
2022
Scope 1
9.5
10.9
10.2
Scope 2
0.1
0.1
0.1
Total scope 1 and 2 GHG emissions
9.6
10.9
10.3
Year ended Dec. 31
2024
2023
2022
Hydro
0.0
0.0
0.0
Wind and Solar
0.0
0.0
0.0
Gas
6.3
6.4
6.3
Energy Transition
3.2
4.5
4.0
Corporate and Energy Marketing
0.0
0.0
0.0
Total scope 1 and 2 GHG emissions
9.6
10.9
10.3
Year ended Dec. 31
2024
2023
2022
Australia
0.9
1.0
0.9
Canada
5.4
5.3
5.2
United States
3.3
4.6
4.1
Total scope 1 and 2 GHG emissions
9.6
10.9
10.3
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In 2024, our GHG emissions (scope 1 and 2) were 9.6
million tonnes as a result of normal operating activities.
This represents a 12 per cent decrease from 2023. As a
result, in 2024 our scope 1 and 2 GHG emissions intensity
decreased to 0.35 tCO2e/MWh from 0.41 tCO2e/MWh in
2023. TransAlta plans to cease generation from our single
remaining 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-fired generation.
The following table highlights our scope 1 and 2 GHG emissions reductions since 2015 and our targeted emissions in 2026
in million tonnes of CO2e. 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)
2024
2015
Total scope 1 and 2 GHG emissions
8.1
9.6
32.2
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.
TransAlta's scope 3 emissions include the indirect GHG
emissions resulting from activities in our value chain but
outside of our operational control. 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.
In 2024, we achieved our target to verify and disclose 80
per cent of TransAlta’s scope 3 emissions by 2024. Of the
15 categories described in the GHG Protocol Scope 3
Guidance, five are the most relevant to our business and
together they accounted for 93 per cent of our total scope
3 emissions of approximately 3.7 million tonnes of CO2e in
2024. They include Category 1: Purchased goods and
services, Category 2: Capital goods, Category 3: Fuel and
energy-related activities, Category 11: Use of sold
products, and Category 15: Investments. These emissions
received limited assurance by a third-party provider.
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The following table details our total scope 3 GHG emissions in million tonnes of CO2e. Some values do not sum to the
indicated total due to rounding of tabulated emissions. Zeros (0.0) indicate truncated values.
Year ended Dec. 31
2024
2023
2022
Category 1: Purchased goods and services(1)
0.0
0.0
0.0
Category 2: Capital goods(2)
0.0
0.1
0.1
Category 3: Fuel and energy-related activities(3)
1.0
1.0
1.0
Category 11: Use of sold products(4)
0.6
0.7
0.6
Category 15: Investments(5)
1.8
1.7
1.8
Other relevant categories(6)
0.2
0.3
0.3
Total scope 3 GHG emissions
3.7
3.7
3.8
(1)
Category 1: Purchased goods and services includes emissions associated with the purchase of goods and services described as operating expenses.
(2) Category 2: Capital goods includes emissions associated with the purchase of capital goods and services described as capital expenditures.
(3) Category 3: Fuel and energy-related activities includes emissions associated with the extraction, production of all fuels consumed and midstream
transportation of natural gas (pipeline). Excludes the emissions associated with electricity purchased from the grid as they have been accounted for in
our scope 2 GHG emissions, but accounting for the transmission and distribution losses.
(4) Category 11: Use of sold products includes emissions associated with natural gas combustion during electricity production where the sales and delivery
of physical natural gas occur.
(5) Category 15: Investments includes scope 1 and 2 GHG emissions (on an equity basis) from our assets that are owned (as a joint venture or other
ownership structure) but not operated by TransAlta.
(6) Other relevant categories include Category 4: Upstream transportation and distribution, Category 5: Waste generated in operations, Category 6:
Business travel, Category 7: Employee commuting, Category 9: Downstream transportation and distribution, and Category 10: Processing of sold
products. These emissions were estimated based on best available information and did not receive limited assurance by a third-party provider.
Avoided Emissions
In 2024, production from renewable assets resulted in the
avoidance of approximately 2.8 million tonnes of CO2e for
our customers. TransAlta's avoided emissions are defined
as the sum of the displaced emissions by our renewable
assets in the jurisdictions where we operate.
The value is calculated as the product of the generation of
electricity obtained from a renewable source (hydro, wind
and solar) and the specific CO2 emissions intensity from
the grid of the jurisdiction in which we operate. Avoided
emissions increased in 2024 compared to 2023 primarily
due to an increase in renewable fleet generation.
The following table highlights our avoided emissions in million tonnes of CO2e.
Year ended Dec. 31
2024
2023
2022
Total GHG emissions avoided
2.8
2.3
2.7
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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 that we may choose to utilize
pools of capital available to sustainable economic activities
and projects to finance our energy transition.
TransAlta deploys green and sustainable financing to build
our renewable energy fleet. This supports our goal to
deliver on our customers’ needs for renewable electricity.
Since 2020, we have issued $726 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, and 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, 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.
The summary below shows the carrying value of the issued green bonds and the total committed facility size of our ESG
financial operations portfolio.
As at Dec. 31 (in millions of Canadian dollars)
2024
2023
2022
Green bonds (1)
726
684
703
Sustainability-linked loans
1,950
1,950
1,250
(1)
Green bonds are related to the Senior Green Bonds issued in 2022.
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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 revenue from renewable
energy generation (hydro, wind and solar) in 2024 was
$839 million (2023 – $902 million).
In 2024, our growth capital expenditures for renewable
energy generation were $61 million (2023 – $630 million).
In addition, TransAlta continues to invest in emerging
abatement technologies and solutions. In 2024, our
investments in low-carbon research and development
were $8 million (2023 – $4 million).
In 2024, adjusted EBITDA from renewable energy
generation was $632 million (2023 – $716 million). 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 2024
from environmental attribute sales was $79 million (2023 –
$36 million).
The disclosure of TransAlta's financial metrics related to
our climate-related risks and opportunities partially aligns
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)
2024
2023
2022
Growth capital expenditures for renewable energy generation(1)
61
630
666
Renewable energy adjusted EBITDA(2)
632
716
860
Environmental and tax attributes revenue(3)
79
36
53
Renewable energy revenue(4)
839
902
1,014
Investments in low-carbon research and development(5)
8
4
12
(1)
Growth capital expenditures include amounts deployed for growth projects and acquisitions related to renewable energy generation. This includes the
Garden Plain wind project and the Northern Goldfields solar project, both completed in 2023, and the White Rock and Horizon Hill wind projects, both
completed in 2024. This excludes the Mount Keith transmission expansion and Mount Keith west network upgrade projects.
(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 and
may not be comparable to similar measures presented by other issuers. During 2024 our adjusted EBITDA composition was amended to exclude the
impact of Brazeau penalties and related provisions. Therefore, the Company has applied this composition to all previously reported periods. Refer to the
Additional IFRS Measures and Non-IFRS Measures and Segmented Financial Performance and Operating Results sections of this MD&A.
(3) Environmental and tax attributes revenue represents a full amount of hydro, wind and solar environmental credit sales, including intercompany sales.
(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 partial alignment of our climate change management disclosure with TCFD and IFRS S2
recommendations.
TCFD Recommended Disclosures
Other Alignments
Location
Governance
Describe the board’s oversight of
climate-related risks and opportunities
IFRS S2: 6
Oversight
by
the
Board
of Directors
Describe management’s role in assessing
and managing climate-related risks
and opportunities
IFRS S2: 6
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
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
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
Climate Scenarios, Key Climate
Scenario Findings
Risk management
Describe the organization’s processes for
identifying and assessing climate-related risks
IFRS S2: 10
Climate Change Strategy
Describe the organization’s processes for
managing climate-related risks
IFRS S2: 24-25
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
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
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
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
Climate
Change
Metrics
and
Targets
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Enabling Innovation and Technology Adoption
TransAlta has been at the forefront of innovation in the
power-generation sector since the early 1900s when we
developed our first hydro facilities. We have been an early
adopter and developer of wind technology, including the
first commercial wind facility 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, completed our first solar
microgrid with battery energy storage system in Western
Australia.
This
section
covers
manufactured
and
intellectual capital management partially in alignment with
guidance from the IFRS's Integrated Reporting Framework.
Our Energy Innovation Team
In 2021, we established an Energy Innovation team to
investigate, prioritize and deploy new net-zero electricity
generation
technologies
that
address
reliability,
decarbonization and affordability. The Energy Innovation
team is focused on identifying projects that complement
our hydro, wind and solar assets to deliver reliable and
low-carbon electricity to customers. The Energy Innovation
team is also looking at electrification more broadly to
investigate potential new, adjacent business opportunities
for TransAlta.
Our Energy Innovation team participates in the Low Carbon
Peer Group, a discussion forum made up of TransAlta’s
peers in the electricity sector in the U.S. and Canada. 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 or our customers.
Renewable Energy
In 2024, TransAlta's nameplate capacity was 2,406 MW
from wind and battery storage, 944 MW from hydro
energy, and 181 MW from solar power. In 2024, our U.S.
renewables fleet represented over 1 GW.
In April 2024, the Company achieved commercial operation
of our 302 MW White Rock wind facilities, located in
Oklahoma. The facilities are fully contracted to Amazon
Energy LLC and currently supply clean and affordable
electricity to our customer.
In May 2024, TransAlta achieved commercial operation of
our 202 MW Horizon Hill wind facility, located in Oklahoma.
The facility is fully contracted to Meta Platforms Inc., which
is receiving both clean electricity and environmental
attributes from the facility.
In 2023, the Garden Plain wind facility in Alberta was
commissioned adding 130 MW to our gross installed
capacity. The facility is fully contracted with Pembina
Pipeline Corporation (100 MW) and PepsiCo Canada (30
MW). In addition, in 2023, the 48 MW Northern Goldfields
solar and battery storage facilities in Western Australia
achieved commercial operation.
Scaling Up Energy Solutions
Battery Storage
We continue to invest in battery energy storage systems
as an important element to provide reliability through the
energy transition – continuing an important role TransAlta
has played for over 100 years with our hydro facilities.
In 2024, TransAlta’s development pipeline included four
energy storage projects in Canada: WaterCharger (project
is on hold, 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 projects could play
various roles on electricity grids including providing
reliability services and storing surplus generation for
discharge at peak periods.
In 2023, the Northern Goldfields solar and battery storage
facilities
in
Western
Australia
achieved
commercial
operation. The energy storage consists of the 10 MW/5
MWh Leinster Battery Energy Storage System which is
integrated into TransAlta’s remote network. The network
and new generation supports BHP Nickel West to meet its
emissions reduction targets and deliver lower-carbon
nickel to its customers.
Electric Mobility
Companies can play an important role in reducing
emissions by exploring the use of electric vehicles in their
own operations. TransAlta is currently 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. The project will run from 2024 to 2025,
during which time operators will gain hands-on experience
with the technology and provide feedback on 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
on-site
hydrogen
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production,
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
modular, factory-assembled units 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.
In 2024, TransAlta announced a partnership with X-Energy
Reactor Company, LLC to study the deployment of X-
Energy’s Xe-100 advanced small modular nuclear reactors
in Alberta. With support from a grant from Emissions
Reduction Alberta, the study will examine the feasibility of
deploying X-Energy’s advanced high-temperature gas-
cooled small modular nuclear reactor at an existing coal-
to-gas plant in Alberta.
TransAlta continues to monitor developments in SMR and
explore the benefits of carbon dioxide removal options to
support the net-zero transition of our operations, such as
nature-based solutions, direct air capture, carbon capture,
utilization and storage, and other technologies.
Hybrid Hydro Supercapacitor Energy Storage
In 2024, TransAlta launched a project with Atlas Power
Technologies Inc. for a hybrid hydro supercapacitor energy
storage system, which is expected to be the first of its kind
in North America. With support from a grant from Emissions
Reduction Alberta, the project is complementary to an
existing hydroelectric generating station that augments the
power plant’s response time and capability to address
frequency response needs.
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 seek to 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 U.S. and Europe to identify, pilot, commercialize and
bring to market technologies that will support its
decarbonization goals. In total, the Company invested
US$12 million to this fund as at Dec. 31, 2024.
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.
Through EIP, TransAlta has invested in ZAP Energy, a
leading fusion startup. 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 our retired Big Hanaford gas plant located in
Centralia to host its first-of-a-kind Z-pinch fusion pilot
plant. In 2024, ZAP received a second grant in the same
amount of US$1 million from the Centralia Coal Transition
Grants Energy Technology Board as part of energy
transition investments to move away from coal in
Washington State.
For more information on our investments in low-carbon
research and development, refer to the Climate-Related
Financial Metrics section of this MD&A.
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Managing Environmental Resources
We continue to increase financial value from natural or
environmental capital-related business activities, while
striving to minimize our environmental footprint and
potential risk factors related to environmental impacts. This
section covers natural capital management partially in
alignment with guidance from the IFRS's Integrated
Reporting Framework.
Environmental Strategy
All energy sources used to generate electricity impact 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. In 2026, we expect that our generation mix will be
made up of natural gas and renewable energy only.
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, waste management and biodiversity.
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, licences, 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.
Nature-Related Risks and Opportunities
Nature-related risks may exist based on a Company’s
dependencies on and impacts to biodiversity, ecosystems
and ecosystem services (BEES) and could result in nature-
related events. These events could impact resource
availability and sustainability, disrupt the supply chain
necessary for successful operations, have negative
regulatory compliance implications and cause reputational
damage. Nature-related opportunities might exist when
supporting or enhancing BEES, to the benefit of business
operations. These opportunities can include accessing
healthy, natural resources (i.e., soil and water), supporting
a resilient ecosystem that is less prone to fluctuations (e.g.,
drought, flooding and erosion) and enhancing tourism and
recreational opportunities.
Overseeing Nature-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 Nature-Related Dependencies and Impacts
In 2024, TransAlta conducted our first nature-related risks
and
opportunities
assessment,
achieving
our
2022
sustainability target to "assess and disclose nature-related
risks and opportunities including TransAlta’s dependencies
and impacts on ecosystems, land, water and air" by 2024.
We chose to follow the TNFD recommendations where
possible, as a commitment to using internationally
recognized methodologies. The analysis utilized the TNFD
guidance on assessing nature-related issues—the Locate,
Evaluate, Assess, Prepare (LEAP) approach—in conjunction
with the TNFD Additional Sector Guidance – Electric
Utilities and Power Generators (June 2024).
Methods applied include the review of environmental
evaluations, permits and monitoring reports, the collection
of environmental and geospatial data, the use of the TNFD
data tools and the review of findings by internal and
external subject matter experts. In addition, we adopted a
TNFD scenario that projects moderate nature-related risks
to business operations over the next 20 years, driven by
gradual ecosystem degradation, climate change and
shifting customer and shareholder expectations. This
analysis excluded projections of physical risks related to
climate change.
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Given the large number of TransAlta's assets, a subset of
facilities was selected and included over 3,100 MW of
nameplate capacity from hydro, wind, solar, natural gas
and coal facilities in Canada, the U.S. and Western
Australia.
The
following
sections
highlight
TransAlta's
top
dependencies, impacts, risks, opportunities and mitigation
measures related to nature.
Material Dependencies
We identified where and how the Company's operations
may interface with nature and determined whether those
interfaces are material. This means that our goal was not to
understand or evaluate every potential issue, but rather
focus on ecosystem services considered material to the
operation of our selected facilities.
Our most material dependencies are associated with the
regulation of the climate and climatic events, the use of
water in production cycles, mainly in gas- and coal-fired
power generation and the regulation of the water cycle,
which enables the operation of hydroelectric facilities.
For further information on climate change, refer to the
section Managing Climate Change Risks and Opportunities.
of this MD&A.
TransAlta's nature-related dependencies found to be
material are summarized in the table below.
Material Dependencies by Generation Type
Ecosystem service(1)
Hydro
Wind
Solar
Gas and coal
Groundwater
M
NA
VL
M
Surface water
VH
NA
VL
VH
Water supply
VH
VL
M
H
Water flow regulation
VH
NA
NA
M
Climate regulation(2)
VH
VH
VH
VL
Flood and storm protection
H
M
M
M
Soil stabilization and erosion control
H
M
M
L
Legend: (VL) Very Low, (L) Low, (M) Medium, (H) High, (VH) Very High and (NA) Not Applicable, as defined by the TNFD Additional Sector Guidance -
Electric Utilities and Power Generators (June 2024).
(1)
The use of renewable resources (wind and solar radiation) and mineral resources (natural gas and coal), water flow regulation, flood and storm
protection, and soil stabilization and erosion control are material to our operations but were excluded from this analysis because associated metrics
were not available at an international scale. Facilities have locally mandated controls to manage risks, including engineering solutions built into the
design phase.
(2) Climate regulation services are the ecosystem contributions to the regulation of ambient atmospheric conditions and were excluded from this analysis
because they are discussed in the section Managing Climate Change Risks and Opportunities.
Material Impact Drivers
Impact drivers are a measurable quantity of a natural
resource that is used as an input to production (e.g., the
volume of water consumed) or a measurable non-product
output of a business activity (e.g., a kilogram of NOx
emissions released into the atmosphere).
The analysis of TransAlta's material impact drivers included
the assessment of 26 metrics related to land use, water, air
emissions, GHG emissions, waste, species at risk, invasive
alien species and enforcement actions or fines.
Our material nature-related impact drivers are associated
with GHG emissions and the use of water as summarized in
the table below.
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Material Impact Drivers by Generation Type
Impact driver(1)
Hydro
Wind
Solar
Gas and coal
Land use change
VH
H
VH
NA
Freshwater use change
VH
M
NA
H
Water use
VH
NA
NA
VH
GHG emissions
L
NA
NA
VH
Non-GHG emissions
NA
NA
NA
VH
Water/soil pollutants
H
L
L
M
Solid waste
L
L
L
H
Area of land use
M
H
L
M
Area of freshwater use
H
NA
NA
M
Biological alterations(2)
H
NA
NA
NA
Legend: (L) Low, (M) Medium, (H) High, (VH) Very High and (NA) Not Applicable, as defined by the TNFD Additional Sector Guidance - Electric Utilities and
Power Generators (June 2024).
(1)
Noise and light disturbances are material to our operations but were excluded from this analysis because mitigations are built into project design and
monitored during operations, in accordance with applicable regulatory requirements in the jurisdictions in which we operate. The state of nature (e.g.,
species extinction risk, direct mortality, fisheries risk and incidents related to birds, bats, fish and others) is material to our operations but was not
included in this table because the TNFD has not provided the associated materiality ratings. Metrics related to the state of nature were included in our
analysis and are summarized under the Biodiversity heading in the Environmental Performance section of this MD&A.
(2) Biological alterations or interferences include the impact from activities that directly introduce nonnative invasive species into areas of operation.
Potential Risks, Opportunities and Mitigation Measures
Nature-related risks are the potential threats posed to an
organization linked to its dependencies on nature and its
impacts on nature. These can derive from physical and
transition risks.
The analysis of TransAlta's nature-related risks and
opportunities was conducted with a focus on physical
risks. These risks were evaluated to help us understand
how our operations result in changes in the state of nature
and how this affects ecosystem service provision.
Transition risks such as regulatory and policy, reputation,
market and technology risks related to the Company are
discussed in the Governance and Risk Management
section of this MD&A. Transition risks related to climate
change are disclosed in the Managing Climate Change
Risks and Opportunities section of this MD&A.
Nature-related opportunities are activities that create
positive outcomes for organizations and nature by avoiding
or reducing impact on nature, or contributing to its
restoration.
The metrics we use to assess and manage material nature-
related dependencies and impacts as well as risks and
opportunities in line with its strategy and risk management
process can be found in the Environmental Performance
section of this MD&A. Current and future nature-related
targets can be found in the Our 2024 Sustainability
Performance and 2025+ Sustainability Targets sections of
this MD&A.
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TransAlta's nature-related risks and opportunities and their mitigation measures are summarized in the following table.
Identified Potential Risks and Opportunities and Mitigation Measures
Potential risks
Mitigation measures and opportunities
Hydro
Substantial alteration of natural water flow regimes is
typical, leading to major changes in water levels, flow
timing and velocity.
Two facilities are located within 35 km of a World
Heritage site as defined by the United Nations
Educational,
Scientific
and
Cultural
Organization
(UNESCO). These facilities are not within 35 km of Key
Biodiversity Areas.
Minimal impact related to land pollution, including spills,
may occur.
Facilities are located in areas with very low to low water
stress, as determined by the Aqueduct Water Risk Atlas.
Some facilities are located within critical habitat for
species at risk. While there is potential for fish mortality,
species extinction risk and mortality risk related to
species
listed
by
the
International
Union
for
Conservation of Nature (IUCN) are minimal.
Typically, there is minimal impact from the emissions of
GHG, SO2, NOx, particulate matter and mercury.
Most facilities maintain minimum or riparian flows to help
support fish habitats despite the fluctuations in natural
water flows. These measures aim to moderate the effects
of dam operations on local water systems and wildlife.
Our Cascade (36 MW) and Spray (112 MW) facilities are
located within the Canadian Rocky Mountain Parks
(UNESCO World Heritage Site). Cascade is located in and
Spray is adjacent to Banff National Park. These facilities
are Ecologo certified. This means that their energy
products or services have undergone third-party testing
for reduced impacts on aquatic, riparian and terrestrial
ecosystems.
In 2021, we renewed our previous agreement with the
Government of Alberta for another five years to manage
water flow 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 2024, TransAlta signed onto a voluntary water-sharing
memorandum of understanding with over 30 other water
licence holders in the Bow River Basin in Alberta. Due to
its role managing water storage and water flows in the
Bow River system for power generation, drought
prevention and flood control, the Company collaborates
with other downstream water licence holders to manage
water flows.
Wind
No measurable impact on water natural flow regimes.
Facilities are located in areas with very low to moderate
water stress.
Some facilities are located within a Key Biodiversity
Area, but not within 35 km of UNESCO World Heritage
sites. Minimal impact related to land pollution, including
spills, may occur. While there is potential for wildlife
mortality, species extinction risk and mortality risk
related to IUCN-listed species are minimal to low.
Typically, there is minimal impact from the emissions
associated with wind facilities.
Wind facilities can be associated with bird and bat
mortalities. Given this, our wind facilities are required to
complete post-construction mortality monitoring for a set
number of years after the start of operations. If mortality
exceeds acceptable levels, additional monitoring and
mitigation
measures
are
usually
required
(e.g.,
curtailment).
Further information on mortality of species at risk can be
found under the Biodiversity heading in the Environmental
Performance section of this MD&A.
Solar
No measurable impact on water natural flow regimes.
Facilities are located in areas with moderate water
stress. Minimal impact related to land pollution,
including spills, may occur.
Some facilities are located within a Key Biodiversity
Area, but not within 35 km of UNESCO World Heritage
sites. While there is potential for wildlife mortality,
species extinction risk is minimal. Mortality risk related
to IUCN-listed species is moderate.
Typically, there is minimal impact from the emissions
associated with solar facilities.
Facilities are located in areas with moderate water
stress. However, their water use is minimal.
Typically, solar facilities can have high impacts on land
use and land use change. These impacts could be
reduced if facilities are small in size. This is the case with
our North Carolina solar facility (122 MW), which is
composed of 20 small sites throughout the state.
Further information on mortality of species at risk can be
found under the Biodiversity heading in the Environmental
Performance section of this MD&A.
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Identified Potential Risks and Opportunities and Mitigation Measures (Continued)
Potential risks
Mitigation measures and opportunities
Natural gas
Some modification of water flow, affecting specific local
stretches of water bodies is typical. Seasonal or
operational impacts on flow may exist but are limited in
scope and duration. Most facilities are located in areas
with low water stress, but our Western Australian
operations are located in areas with very high water
stress.
Facilities are not located within 35 km of Key
Biodiversity Areas or UNESCO World Heritage sites.
Minimal impact related to land pollution, including spills,
may occur. Facilities are not located within critical
habitat for species at risk. Species extinction risk and
mortality risk related to IUCN-listed species are minimal
to moderate.
High to major impacts from the emissions of GHG, NOx
and particulate matter are typical, with minimal impact
from SO2 and mercury.
Water for gas operations is withdrawn primarily from rivers
where we hold permits and must therefore adhere to
regulations on the quality of discharged water.
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.
In
2024,
we
returned
approximately 97 per cent of the water withdrawn from
the adjacent St. Clair River to support our Sarnia
operations.
Our facilities in Western Australia have been designed to
minimize water consumption. Water supply at these
facilities is provided at no cost under PPAs with our
mining customers, hence our risk is significantly mitigated.
Water used in our operations is returned to our customers,
who repurpose this water for vegetation and dust
suppression in their mining operations. 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.
In 2022, we met our 2026 targets to achieve a 95 per
cent reduction of SO2 emissions and an 80 per cent
reduction of NOx emissions below 2005 levels and we
retained the achievement over 2023 and 2024.
We continue to progress towards our 2026 target to
reduce scope 1 and 2 GHG emissions by 75 per cent from
2015 levels. Since 2015, we have reduced scope 1 and 2
GHG emissions by 22.7 MT CO2e or 70 per cent.
Coal
TransAlta’s sole remaining coal-fired generation facility,
Centralia, is located in an area with very low water
stress. Some modification of water flow, affecting
specific local stretches of water bodies is typical.
Seasonal or operational impacts on flow may exist but
are limited in scope and duration.
Centralia is not located within 35 km of Key Biodiversity
Areas or UNESCO World Heritage sites. Minimal impact
related to land pollution, including spills, may occur.
Centralia is not located within critical habitat for species
at risk. Species extinction risk and mortality risk related
to IUCN-listed species are minimal.
Typically, there is major impact from the emissions of
GHG, SO2, NOx, particulate matter and mercury.
TransAlta historically operated three coal mines. The
Whitewood mine in Alberta is completely reclaimed and
the land was donated to the community. Further
information can be found in the Case Study: TransAlta's
Donation to the Alberta Conservation Association in the
Community Investments section of this MD&A.
The Highvale mine in Alberta closed in 2021 and the
Centralia mine in Washington State closed in 2006. Both
Highvale and Centralia are actively reducing their footprint
through site reclamation, with targeted completion by
2046 and 2040 respectively.
In 2021, we retired or converted all coal plants in Canada
to natural-gas-fired generation. We plan to cease coal-
fired generation at our Centralia plant in the U.S. by
Dec. 31, 2025.
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Environmental Performance
Our performance on managing environmental aspects is
presented in the following sections and excludes the
acquisition of Heartland Generation on Dec. 4, 2024.
Energy Use
TransAlta uses energy in a number of different ways. We
burn natural gas, diesel and coal to generate electricity. We
plan to cease coal-fired generation at Centralia by the end
of 2025. 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 table captures our energy use (petajoules). Energy use decreased by 11 per cent in 2024 over 2023. Some
values do not sum to the indicated total due to rounding. Zeros (0) indicate truncated values.
Year ended Dec. 31
2024
2023
2022
Hydro
0
0
0
Wind and Solar
0
0
0
Gas
122
123
130
Energy Transition
52
73
64
Corporate and Energy Marketing
0
0
0
Total energy use (petajoules)
175
197
195
Air Emissions
Our one remaining coal-fired 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 include NOx, SO2, particulate matter and mercury.
We continue reducing air emissions in our existing facilities
through our conversion and retirement of coal units in
Alberta (completed in 2021) and Washington State
(planned completion by the end of 2025).
In 2022, we achieved our 2026 target of 95 per cent SO2
and 80 per cent NOx emissions reductions over 2005
levels. In 2025, TransAlta set a new target "By 2030,
achieve a 90 per cent reduction of SO2 emissions intensity
from 2023 base year".
As per guidance from SASB, detailed air emissions
disclosure is required when a facility is located within 49
kilometres of an area with a population greater than 50,000
persons.
Many of our gas facilities are located in very remote and
unpopulated regions, away from dense urban areas.
However, our Sarnia, Windsor, Ottawa, Fort Saskatchewan
and Ada gas facilities and Centralia coal facility are located
within 49 kilometres of dense or urban environments. In
2024, these facilities accounted for 41 per cent of total
NOx, 99 per cent of total SO2, 31 per cent of total
particulate matter and 56 per cent of total mercury.
Our total air emissions in 2024 show a decrease of 18 per
cent for SO2 and 18 per cent for NOx from 2023 levels.
This is primarily due to the decrease in production from our
coal facility.
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The following table represents our material air emissions. Figures have been rounded for SO2 (to the nearest one
hundred), NOx (to the nearest one thousand), particulate matter (to the nearest ten, when possible) and mercury (to the
nearest whole number).
Year ended Dec. 31
2024
2023
2022
SO2 (tonnes)
870
1,100
1,200
NOx (tonnes)
8,700
11,000
11,000
Particulate matter (tonnes)
320
460
360
Mercury (kilograms)
16
21
21
Water
Our principal water use is for cooling and steam generation
in our coal and gas facilities, but our hydro operations also
require water flow for operations. Water for coal and gas
operations is withdrawn primarily from rivers where we
hold permits and must therefore adhere to regulations on
the quality of discharged water. The difference between
withdrawal and discharge, representing consumption, is
due to several factors, which include evaporation loss and
steam production for customers, which we are unable
to recover.
In 2022, we achieved our water consumption reduction
target
to
reduce
fleet-wide
water
consumption
(withdrawals minus discharge) by 20 million m3 or 40 per
cent in 2026 over the 2015 baseline. Water consumption in
2015 was 45 million m3. This target is in line with the UN
SDGs, specifically "Goal 6: Clean Water and Sanitation." In
2024, we retained the achievement of this target. In 2025,
TransAlta set a new target "By 2030, maintain water
consumption intensity at 2023 levels".
In 2024, we withdrew approximately 237 million m3 (2023 –
273 million m3) and returned approximately 212 million m3
(2023 – 239 million m3) or 90 per cent. Overall, water
consumption was approximately 25 million m3 (2023 – 34
million m3).
The following table represents our water withdrawal, water discharge and total water consumption (million m3). Some
values do not sum to the indicated total due to rounding. Figures below have been rounded to the nearest million m3.
Year ended Dec. 31
2024
2023
2022
Water withdrawal
237
273
233
Water discharge
212
239
207
Total water consumption (million m3)
25
34
26
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
other national and international programs. Our monitoring
programs include:
• Regular operations and engineering inspections;
• Testing 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. In
2022, we started decommissioning the Keephills Ash
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Lagoon, a facility that is no longer needed for ash storage
following the coal-to-gas conversion of Keephills Unit 2.
This project will reshape the existing lagoon so that it is
stable for the long term and is the first step towards
decommissioning the structure. Similar work is underway
to remove the coal combustion waste storage ponds at the
Centralia facility in Washington State.
TransAlta is proud of its reputation in dam safety. We
participate in many industry associations including 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 2024, our operations generated approximately 384,000
tonnes equivalent of waste (2023 – 479,000 tonnes). Of
the total waste generated, 98 per cent was non-hazardous
waste and zero per cent was directed to landfill (2023 –
0.2 per cent). Since its retirement, we have been selling
ash from our Highvale and Centralia Mine, which accounts
for 97 per cent of the total waste generated.
The following table represents our total waste generation (tonnes equivalent). Figures have been rounded to the nearest
one thousand.
Year ended Dec. 31
2024
2023
2022
Waste to landfill (tonne eq.)
1,000
1,000
2,000
Waste recycled (tonne eq.)
12,000
19,000
22,000
Waste reuse (tonne eq.)
372,000
457,000
453,000
Total waste generation (tonnes equivalent)
384,000
479,000
506,000
Percentage of total waste to landfill
0.3
0.2
0.4
Percentage of total waste: hazardous
2.4
3.5
5.0
Percentage of hazardous waste to landfill
0.0
0.0
0.0
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 U.S. In 2023,
Lafarge Canada and TransAlta entered into an agreement
designed to advance low-carbon concrete projects in
Alberta. The project repurposes landfilled fly ash, a waste
product from TransAlta’s Highvale mine, which ceased
operations in 2021. The ash is used to replace cement in
concrete manufacturing. Turning the recovered product
into something marketable, reduces the amount of cement
produced and consequent emissions while offering new
job and economic growth opportunities. This innovative
technology contributes to reducing waste and is expected
to reduce reclamation liabilities for TransAlta.
Land Use
Our largest land use had been associated with land
disturbed by surface mining of coal, which we ceased to
do 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, when we discontinued coal-fired power generation in
Canada. 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
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for the reclaimed land. In 2024, we continued contouring
disturbed areas, re-establishing drainage, replacing topsoil
and subsoil, and advancing re-vegetation and land
management.
Our land use practices regarding previous mining activities
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
5,000 hectares, which is equivalent to 40 per cent of land
disturbed (12,500 hectares).
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 IUCN from near
threatened to critically endangered.
The following table represents our biodiversity incidents in accordance with the IUCN Red List classification.
Year ended Dec. 31
2024
2023
2022
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
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 2024, no regulatory non-compliance environmental
incidents were recorded (2023 – no incidents). No fines or
environmental enforcement actions occurred.
The following table represents our regulatory non-compliance environmental incidents.
Year ended Dec. 31
2024
2023
2022
Regulatory non-compliance environmental incidents
0
0
1
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 2024 was zero (0) m3 (2023 – 0 m3).
The following table represents our significant environmental incidents.
Year ended Dec. 31
2024
2023
2022
Significant environmental incidents
0
0
0
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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 partially in
alignment with guidance from the IFRS's Integrated
Reporting
Framework.
Performance
outlined
below
excludes the acquisition of Heartland Generation on Dec.
4, 2024.
Inclusive Transition
In support of our energy transition, from 2012 to 2023,
TransAlta invested US$55 million 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 ceasing Centralia's coal-fired generation by the
end of 2025.
Three funding boards were formed to invest the US$55
million starting in 2015: the Weatherization Board (US$10
million), the Economic and Community Development Board
(US$20 million), and the Energy Technology Board (US$25
million). These boards are independent from TransAlta and
provide grants to local businesses, non-profit organizations
and local governments to improve energy efficiency,
educate and retrain workers for the next generation of jobs
and fund energy technology projects. To date, the
Weatherization Board has invested US$10 million, the
Economic and Community Development Board US$18.9
million and the Energy Technology Board US$15.5 million.
Further information on Centralia Coal Transition Grants can
be found on the website https://cctgrants.com/.
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 and
continues to invest 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
U.S. and Western Australia. We are focused on customer-
centred growth to bring high levels of service quality and
reliability for our customers. 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 92 per
cent over the last three years.
Across our business in Canada, the U.S. and Western
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. We continue to explore opportunities 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
2024 resulted in the avoidance of approximately 2.8 million
tonnes of CO2e for our customers.
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Our experience in developing and operating power facilities is highlighted below.
Power generation type
Operating experience (years)
Hydro
113
Natural Gas
74
Wind
27
Solar
10
Battery Energy Storage Systems
4
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 U.S. 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
2024, 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.
TransAlta files annual reports under Canada's Fighting
Against Forced Labour and Child Labour in Supply Chains
Act and Australia's Modern Slavery Act 2018. Such reports
set forth the actions that we have taken to assess and
address modern slavery risks within our operations and
supply chain.
Supply Chain
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.
In the coming years, we plan to 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 collaborate with suppliers to explore
enhancement of their GHG emissions targets and to
consider setting direction for engaging suppliers with GHG
emissions reduction targets.
In 2022, TransAlta approved a new goal to integrate
sustainability into our 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 2024, we confirmed
that, on average, 79 per cent of our spend since 2022 was
with suppliers that have a sustainability policy or
commitment. Even though our target to achieve 80 per
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2024 Integrated Report
cent of our spend with suppliers that have a sustainability
policy or commitment by 2024 was not achieved, all
vendors and suppliers of TransAlta are required to adhere
to our Supplier Code of Conduct. 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.
TransAlta will continue to consider other targets to help
integrate sustainability into supply chain.
Indigenous Relationships and Partnerships
At TransAlta, we use our core values—safety, innovation,
sustainability, respect and integrity—to guide our business
practices and our engagement with stakeholders and
Indigenous communities. We seek to build and nurture
relationships and work to listen and understand the
impacts our operations may have on local communities. We
maintain open communication channels and are dedicated
to resolving issues promptly and professionally through
dialogue.
In addition to the Company's core values, engagement
practices are guided by industry best practices and
standards, corporate policies and regulatory requirements.
Our commitment to Indigenous relations is spearheaded by
a centralized corporate team that fosters a relationship-
based approach, involving employees at our facilities and
within each business unit.
TransAlta's Indigenous Relations Policy focuses on five key
areas: awareness, community engagement, community
investment, business development, employment and
training. 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 strives to maintain relationships through the life
cycle of our facilities, from project development and
construction, through operation, until decommissioning
phases are complete. This is recognized in our Indigenous
Relations Policy, which includes acknowledgement and
understanding of the intent of the recommendations of the
United Nations Declaration on the Rights of Indigenous
Peoples.
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.
In 2024, TransAlta provided more than $320,000 to
support Indigenous youth, education and employment
programs, representing 11 per cent of TransAlta’s total
community investment. Highlights include:
• The Read On Literacy Program (Read On) – In 2024,
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 one’s culture
and making good decisions in one’s life.
• In the Spirit of Planting Seeds – In 2024, TransAlta
donated to the Growbox Project, an initiative by the
Piikani Nation Lands Department aimed at addressing
food security and promoting environmental stewardship.
The project, titled "Sūṗii ṗo’omaaksin" or "in the spirit of
planting
seeds,"
involves
the
development
of
a
comprehensive greenhouse program that integrates
renewable energy technologies and Blackfoot cultural
teachings. The program includes a hydroponic farm for
year-round food production, educational opportunities for
students, and efforts to promote food sustainability and
sovereignty within the Piikani Nation community.
Indigenous Cultural Awareness Training
In line with our sustainability target set in 2023, the
Company made a deliberate effort to ensure that every
new
employee
participated
in
Indigenous
Cultural
Awareness training. In 2024, TransAlta successfully
reached 100 per cent completion of the Indigenous Cultural
Awareness Training program during the onboarding of all
new employees across our operating jurisdictions in
Canada, the U.S. and Western Australia. 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.
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Case Study: Diamond Willow Youth Lodge
To meet the unique needs of Calgary’s Indigenous youth,
TransAlta has invested over $1 million since 2018 in the
Diamond Willow Youth Lodge. Named after the species of
willow tree used to build sacred sweat lodges, the diamond
willow is known for its strength and flexibility making it
ideal for creating the framework of the lodge.
This accessible and safe space provides a broad spectrum
of support for the culture, identity, housing, mentorship
and well-being needs of Indigenous youth aged 12 to 29. In
2023, 292 youth were supported by the lodge during 829
visits. The number of attendees has been increasing
steadily year-over-year since inception. Over 165 events,
workshops and activities were hosted including traditional
cooking, drumming groups, hide and circle camps, tipi pole
harvesting and tea ceremonies.
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
business success. We work to build relationships and
understand the importance of early and regular dialogue to
determine what opportunities or impacts our activities 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. In many of our operating areas, we
have decades of established relationships and work to
maintain a consistent level of communication and trust. In
newer areas, we spend time and effort on site listening and
learning to ensure we consider all perspectives.
Our principal stakeholder groups are listed in the following table.
TransAlta Stakeholders
Non-governmental organizations
Community associations
Transmission facility operators
Regulators
Industry associations
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
Resource industry associations
Mineral rights owners
System operators
Think tanks
Railroad owners
Customers
Academics
Utility owners
Shareholders
Employees
Creditors
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Stakeholder Engagement
Our stakeholder engagement practices are guided by industry best practices, international standards, corporate policies
and regulatory requirements. 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 U.S. and
Western 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 during project development and
construction phase and maintain engaged communication
throughout operations to decommissioning phase.
In 2024, TransAlta was active in many communities in the
jurisdictions where we operate. We delivered open houses,
hosted
community
barbecues,
conducted
ongoing
engagement with environmental, recreation and civil
society groups and made numerous visits and interacted
with non-profit organizations.
Community Investments
In 2024, TransAlta contributed approximately $2.9 million
in donations and sponsorships (2023 – $3.2 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. This year, TransAlta employees,
retirees, contractors and the Company raised over $1.3
million for the United Way of Calgary and Area.
In 2024, TransAlta made a number of other significant
investments, including the following highlights:
• Community Health and Wellness – In 2024, TransAlta
donated to the Goldfields Women's Refuge Finlayson
House in Australia, which offers a safe haven for women
and children escaping domestic violence, providing them
with shelter, support, and the tools to rebuild their lives.
• Environmental Leadership – In 2024, TransAlta donated
to the Day on the Creek event as part of our commitment
to supporting youth education and environmental
stewardship in the Waterton Biosphere Region in Alberta.
Our contribution helps provide valuable educational
opportunities for students and the community, fostering a
deeper understanding of watershed stewardship and the
importance of preserving our natural environment.
• Youth and Education – In 2012, students from a
kindergarten class were awarded a $2,500 college
scholarship by TransAlta after winning a regional eco-
challenge competition. In 2024, 19 students of the
kindergarten class reached their high school graduation.
As of their graduation date, the initial principal of the
scholarship more than doubled. A celebration for the
students and their families was held at the Centralia
facility.
Case Study: TransAlta's Donation to the
Alberta Conservation Association
In
2024,
TransAlta
and
the
Alberta
Conservation
Association (ACA) celebrated a significant milestone at the
Whitewood Mine location. Through our partnership,
TransAlta completed a donation of 1,274 acres to the ACA.
This donation will ensure that the land remains preserved
in its natural state, contributing to biodiversity and
conservation efforts.
The Whitewood Mine, formerly a coal mine in Parkland
County, Alberta required reclamation and conservation
efforts to transform it into a sustainable natural habitat.
The challenge was to preserve the land's diverse natural
landscapes and ensure its long-term protection.
TransAlta's donation to the ACA is part of a larger effort to
create the Whitewood Mine Conservation Site, which will
encompass a total of 2,167 acres, combining past and
present sales and donations. This makes it the largest
continuous conservation property owned by the ACA in
Alberta. The site features diverse natural landscapes,
including a 100-acre lake, small water bodies and various
natural habitats.
The transformation of the Whitewood Mine into a
conservation area showcases the Company's commitment
to environmental stewardship, reclamation and community
engagement.
Upon
receiving
its
final
reclamation
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certificate, the ACA plans to open the site to the public,
providing a valuable recreational and educational resource
for the community.
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 an 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 them 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
continuously 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 and risk levels
through independent auditing and simulated cyber-attacks
(i.e., penetration testing). Results from these assessments
and exercises guide our cybersecurity strategy and
practices,
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 all relevant legal, regulatory,
industry standards and compliance requirements such as
the North American Electric Reliability Corporation Critical
Infrastructure Protection (NERC CIP), the Australian
Security of Critical Infrastructure Act and the U.S. Sarbanes
Oxley Act, where applicable. The NERC CIP and Australian
Security of Critical Infrastructure rules are a set of
standards aimed at regulating, enforcing, monitoring and
managing the security of the North American and
Australian power system. These compliance standards
apply specifically to address cybersecurity risks.
In 2024, 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 2024, we enhanced our
ESG performance through our efforts to promote an
equitable, diverse and inclusive workforce. This section
covers sustainability factors of human capital partially in
alignment with guidance from the IFRS's Integrated
Reporting
Framework.
Performance
outlined
below
excludes the acquisition of Heartland Generation on Dec.
4, 2024.
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 that 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, deliver company results and positively impact
the communities that we live in.
In 2024, TransAlta executed the fourth 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. In 2024, women made up 32
per cent of our executive team and 38 per cent of our
Board.
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 28 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 2024, we continued with the Women in Trades
Scholarship that provides eligible students enrolled in post-
secondary trade programs with financial support. In 2024,
we also continued with the gender diversity program in our
Generation business to strategically target the recruitment
of women. The program seeks to break down barriers and
create opportunities for women to thrive in fields with
historically lower female representation.
Workforce Health and Safety
At TransAlta, safety is a core value and is the foundation of
how we operate. While generating affordable and reliable
electricity for our customers is important, nothing is more
important than the health and safety of our people and the
communities we serve. We are committed to fostering a
culture where we work and learn together to keep each
other safe. Our focus on Operational Excellence puts into
action our mission to safely do the right work at the right
time to power and empower our communities.
Our management systems underpin the delivery of safe,
reliable and competitive electricity to our customers and
partners. The Company's Total Safety Management
System is a combination of recognized best practices in
process safety, risk management, asset management,
occupational
health,
safety
and
environmental
management.
At TransAlta, safety is a core part of everyone’s role and a
shared responsibility. As our safety culture maturity
progresses, we are focused on cultivating a positive safety
experience for everyone. We believe that the overall safety
experience depends on the interaction between three
elements: the physical work environment, the social
environment and the individual environment. We made
significant progress on our safety culture transformation
journey through training and initiatives that support the
three elements of positive safety. This training provides the
tools and strategies to increase employees' ability to
identify and control high energy hazards, enhance
psychological safety and support mental health. At
TransAlta, a positive safety culture is not only the absence
of harm but the presence of protective factors that
increase well-being.
In 2024, our strong safety performance was supported by
our strategic areas of focus: maturing our safety culture,
understanding risk and standardizing 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
human and organizational performance principles, serious
injury and fatality prevention and psychological safety,
leaders held over 100 sessions across the fleet.
One of our safety indicators is TRIF, which tracks the
number of injury incidents that require treatment beyond
first aid, relative to total exposure hours worked. Our TRIF
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result for 2024 was 0.56 compared to 0.30 in 2023. We
recorded zero serious injuries in 2024. The identification
and control of high energy hazards is foundational to our
strong performance on serious injury prevention.
The following table represents our corporate safety performance and includes employees and contractors.
Year ended Dec. 31
2024
2023
2022
Lost-time injuries
0
1
0
Medical aids
6
4
6
Restricted work injuries
2
0
0
Exposure hours
2,844,000
3,362,000
3,058,000
Total Recordable Injury Frequency (TRIF)
0.56
0.30
0.39
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 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 2024, we recorded 16.3 reports per worker,
which is above our exceptional performance target of 15.
Evidence of the positive impacts associated with strong
engagement and a maturing safety culture is apparent in
TransAlta's overall safety performance. In 2024, TransAlta
was recognized by the Alberta Mine Safety Association
with the Trail Blazer Business Leader Award. This award
recognizes executive leaders and senior managers for
exemplary and inspiring leadership with a high commitment
to health and safety.
Organizational Culture and Structure
Our employees are central to value creation. Our corporate
culture has evolved and adapted throughout our 113-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 to encourage 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
In 2024, we had 1,205 (2023 – 1,257) active employees.
With approximately 29 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 2024. Our
business continues to operate four generating segments,
with Gas, Wind and Solar, Hydro and Energy Transition,
with support from our Corporate and Energy Marketing
segments. Our operations portfolio is run by a single
leadership team, which provides operational and financial
synergies, thus enhancing our competitiveness.
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
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2024 Integrated Report
for performance plans are linked to TransAlta achieving
various sustainability 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 2024, 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. Our long-term incentive
plans include strategic goals related to leading in ESG
policy development and progress towards our ESG targets.
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. 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 retaining 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.
Delivering Reliable and Affordable Energy
TransAlta’s goal is to be a leading customer-centred
electricity company, one that is committed to a sustainable
future. Our strategy is focused on meeting our customers'
need for affordable and reliable electricity, operational
excellence and continual improvement. This section covers
manufactured, intellectual and social and relationship
capital management partially in alignment with guidance
from the IFRS's Integrated Reporting Framework.
Energy Affordability
TransAlta helps commercial and industrial customers
manage their cost of energy. TransAlta has a full suite of
procurement strategies and products with various terms
available to our customers to assist them 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
and affordable. We provide decentralized and customized
power solutions to industrial customers. 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
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disasters. We are also committed to ensuring strong
compliance
with
North
American
Electric
Reliability
Corporation standards, Alberta Reliability Standards and
the Power System Security and Reliability standards in the
Western Electricity Market in Australia for the power plant
and transmission infrastructure that we own and operate.
As a Company, we are keenly focused on deploying
renewable and gas-fired power generation and new
technology solutions to meet the emerging and future
needs of the electric system that we operate in.
In 2020, WindCharger was the first battery energy storage
asset ever developed in Alberta and was a leading
participant in the Alberta Electric System Operator’s pilot
fast frequency response project. Fast frequency response
is a novel and critical new fast-acting transmission
reliability service that helps meet the needs of a more
renewable-based grid by augmenting the electricity
systems ability to recover from the sudden loss of
generation or interties. WindCharger continues to provide
of system reliability service.
In 2024, TransAlta launched a project with Atlas Power
Technologies Inc. for a hybrid hydro supercapacitor energy
storage system, which is expected to be the first of its kind
in North America. With support from a grant from Emissions
Reduction Alberta, the project is complementary to an
existing hydroelectric generating station that augments the
power plant’s response time and capability to address
frequency response needs.
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 Managing Environmental Resources section
of this MD&A.
Asset Management
TransAlta's asset management program is designed to
deliver operational excellence by optimizing the total
lifecycle value from physical assets across the Company's
generation portfolio in Canada, the U.S. and Western
Australia. The program involves a centralized team of
engineers and specialists who collaborate with plant
engineers
and
operators.
They
remotely
monitor
generation facilities for emerging equipment reliability and
performance issues.
If an issue arises, the asset management engineer will
assess and then notify facility operations of the findings to
support investigation and remedy the issue to minimize the
impact to operations. For example, if a wind turbine starts
to show early signs of performance deviation compared to
others, the operations team is notified and they will
investigate and remedy the issue.
The monitoring, analysis and diagnostics completed by the
asset management engineer enable early identification of
equipment issues based on longer-term trend analysis and
complements day-to-day facility operations. Anticipating
risks and asset faults early allows for planned and
scheduled repairs to be optimized and facility availability to
be maximized.
Advanced Analytics
TransAlta has a dedicated data and analytics team that
collaborates with the asset management and operations
teams to leverage data science models, modernized
technology platforms, and advanced analytics. Through
this collaboration, solutions for specific use-cases are
developed, enabling valuable insights that are actioned.
Examples of these use-cases include data science models
for detecting performance anomalies for wind turbines and
models for detecting frequency excursions for compliance
with the market rules.
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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 sustainability factors 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 2024, our sustainability memberships included key
sustainability organizations and working groups such as
the IFRS Sustainability Alliance, the Trellis Network
(formerly GreenBiz) and the Electricity Canada Sustainable
Electricity Steering Committee and Climate Change
Adaptation Committee, which all provide validation and
support of our sustainability strategy and practices.
In 2024, our material sustainability factors remained
unchanged from 2022. 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
multi-level risk management oversight structure to manage
the risks and opportunities arising from our business
activities, the markets in which we operate and the political
environments and structures with which we interact.
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 includes 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 informed
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.
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
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2024 Integrated Report
principles applicable to the Company and for monitoring
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 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; (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; and (IX)
reviewing our safety performance.
The HRC is empowered by the Board to review and
approve the Company's key compensation and human
resources policies that are intended to attract, recruit,
retain and motivate employees. 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 helps 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 Executive Vice-President, Finance and Chief
Financial Officer and comprises the President and Chief
Executive Officer; Executive Vice-President, Generation;
Executive Vice-President, Commercial and Customer
Relations; and Vice-President, Corporate Strategy. 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 to collaborate 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 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
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2024 Integrated Report
M135
Administrators: (i) Multilateral Instrument 52-109 —
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 U.S. 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, and they 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 the 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, the review of events that can affect
these risks and discussion and the 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, 2024,
associated
with
our
proprietary
commodity
risk
management activities was $3 million (2023 – $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.
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 2024. 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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Equipment failure and the operation and
maintenance of our facilities involve risks that
may materially and adversely affect our
business.
There is a risk of equipment failure or underperformance to
our operations due to wear and tear, latent defect, design
error or operator error, among other things, which could
have a material adverse effect on our business. Although
our generation facilities have generally operated in
accordance with expectations, there can be no assurance
that they will continue to do so. Our facilities are exposed
to operational risks that can lead to outages and increased
production risk which could have a material adverse effect
on our business. Further, some of our generation facilities
were constructed many years ago and may require
significant capital expenditures to maintain peak reliability
or operations. Newer facilities also require various levels of
capital expenditures to maintain peak reliability or
operations.
There
can
be
no
assurance
that
our
maintenance program will be able to detect potential
failures in our facilities before they occur or eliminate all
adverse consequences in the event of failure.
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.
Further, if a manufacturer is unable or unwilling to provide
satisfactory
maintenance
or
warranty
support
on
reasonable terms, we may have to enter into alternative
arrangements with other providers or perform the services
ourselves. These arrangements could be more expensive
to us than our current arrangements and if we are unable
to enter into satisfactory alternative arrangements, our
inability to access technical expertise or parts could have a
material adverse effect on us. TransAlta manages this risk
with our capital spares policy.
While we maintain an inventory of, or otherwise make
arrangements to obtain, spare parts to replace critical
equipment and maintain insurance for property damage
and business interruption to protect against certain
operating risks, these protections may not be adequate to
cover lost revenues or increased expenses and penalties
that could result if we were unable to operate our
generation facilities at a level necessary to comply with our
contracts. In addition, circumstances could arise in the
future whereby the Company may be obligated to produce
power at a cost that exceeds the revenues being derived
therefrom.
There can be no assurance that any applicable insurance
coverage would be adequate to protect our business from
material adverse effects. In addition, there can be no
assurance that we will be able to restore equipment or
assets that have reached the end of their useful lives.
We manage our generation equipment and technology risk
by:
• Operating our facilities within defined industry standards
that optimize 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
• Implementing long-term asset management strategies
that optimize the life cycles of our existing facilities and/
or identify replacement requirements for generating
assets.
Unexpected changes in the cost of
maintenance or in the cost and durability of
components for the Company's facilities may
adversely affect the results of our operations.
Inflation or other increases in the Company's cost structure
that are beyond the control of the Company could
materially adversely impact our financial performance.
Examples of such costs include, but are not limited to,
unexpected increases in the cost of procuring materials
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2024 Integrated Report
M137
and services required for maintenance activities, and
unexpected replacement or repair costs associated with
equipment underperformance or lower-than-anticipated
durability.
Changes in the price of electricity may
materially adversely affect our business.
A portion of our revenues are tied, either directly or
indirectly, to the market price for electricity in the markets
in which we operate, and in particular in the Alberta
electricity market. Market electricity prices are impacted by
a number of factors, including the strength of the
economy, the available transmission capacity, the price of
fuel that is used to generate electricity (and, accordingly,
certain of the factors that affect the price of fuel described
below), the management of generation, the amount of
excess generating capacity relative to load in a particular
market, the cost of controlling emissions and cost of
carbon, the structure of the particular market, the
availability
of
transmission
(including
from
other
jurisdictions), increased adoption of energy-efficiency and
conservation initiatives, and weather conditions that
impact electrical load. As a result, we cannot precisely
predict future electricity prices and electricity price
volatility (particularly lower Alberta electricity prices) that
could have a material and adverse effect on us. Further,
the Alberta market is the only fully deregulated electricity
market in Canada and this market structure permits
corporate offtakers to invest in new renewable generation
in the province solely for ESG reasons (i.e., to align with
decarbonization goals) that may not align with supply and
demand fundamentals. This could potentially result in an
oversupply of intermittent electricity in the Alberta
electricity market and could put downward pressure on
electricity prices and contribute to significant price
volatility in the near term.
Our facilities and construction projects have structured
agreements in their contracts around force majeure events
that are beyond our control, but positions the organization
to industry standards for insurance or contract claw back
in costs. Such events could result in material adverse
effects.
Our facilities, construction projects and operations are
exposed to potential interruption and damage, or partial or
full loss resulting from environmental disasters (e.g., floods,
high winds, fires, ice storms, earthquakes and public health
crises, such as pandemics and epidemics), other seismic
activity and equipment failures. Climate change can also
increase the frequency and severity of these extreme
weather events. There can be no assurance that in the
event of an earthquake, flood, cyclone, hurricane, tornado,
tsunami, terrorist attack, act of war or other natural, man-
made or technical catastrophe, all or some parts of our
generation facilities and infrastructure systems will not be
disrupted. The occurrence of a significant event that
disrupts the ability of our power generation assets to
produce power for an extended period, including events
that preclude existing customers under PPAs from
purchasing electricity, could have a material negative
impact on our business. Our facilities, construction projects
and operations could be exposed to the effects of severe
weather conditions, natural and man-made disasters and
other potentially catastrophic events. The occurrence of
such an event may not release us from performing our
obligations pursuant to PPAs or other agreements with
third parties. In addition, many of our generation facilities
are located in remote areas, which can make repair of
damage costly or difficult to access. Catastrophic events,
including public health crises, could result in volatility and
disruption to global supply chains, disruption to global
financial markets, trade and market sentiment, risks to
employee health and safety, a slowdown or temporary
suspension
of
operations
in
impacted
locations,
postponements in the initiation and/or completion of the
Company's development or construction projects, and
delays in the completion of services, any of which may
result in the Company incurring penalties under contracts,
additional costs or the cancellation of contracts.
Risks relating to TransAlta's development and
growth projects and acquisitions may
materially and adversely affect us.
Development and growth projects and acquisitions that we
undertake may be subject to execution and capital cost
risks, including, but not limited to, risks relating to
regulatory
approvals,
third-party
opposition,
cost
escalations, securing land rights, construction delays,
shortages of raw materials, supply chain constraints, or
skilled labour and capital constraints. The occurrences of
these risks could have a material and adverse impact on
us, our financial condition, our ability to operate and our
cash flows.
Expansion of our business through development projects
and acquisitions may place increased demands on our
management, operating systems, internal controls and
financial and physical resources. In addition, the process of
integrating acquired businesses or development projects
may involve unforeseen difficulties. Failure to successfully
manage
or
integrate
any
acquired
businesses
or
development projects could have a material adverse
impact on us, our financial condition, our ability to operate
and our cash flows. Further, we cannot make assurances
that we will be successful in integrating any acquisition or
that the commercial opportunities or operational synergies
of any acquisition will be realized as expected.
We may pursue acquisitions in new markets that are
subject to regulation by various foreign governments and
regulatory authorities and to the application of foreign
laws. Such foreign laws or regulations may not provide for
the same type of legal certainty and rights, in connection
with our contractual relationships in such countries, as are
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2024 Integrated Report
afforded to us currently, which may adversely affect our
ability to receive revenues or enforce our rights in
connection with any such foreign operations. In addition,
the laws and regulations of some countries may limit our
ability to hold a majority interest in some of the projects
that we may acquire, thus limiting our ability to control the
operation of such projects. Any existing or new operations
may also be subject to significant political, economic and
financial risks, which vary by country, and may include: (a)
changes in government policies or personnel; (b) changes
in general economic conditions; (c) restrictions on currency
transfer or convertibility; (d) changes in labour relations; (e)
political instability and civil unrest; (f) regulatory or other
changes in the local electricity market; and (g) breach or
repudiation of important contractual undertakings by
governmental entities and expropriation and confiscation
of assets and facilities for less than fair market value.
With respect to acquisitions, we cannot make assurances
that we will identify suitable transactions or that we will
have access to sufficient resources, through our credit
facilities, the capital markets or otherwise, to pursue and
complete any identified acquisition opportunities on a
timely basis and at a reasonable cost. Any acquisition that
we propose or complete would be subject to regulatory
approvals and other normal commercial risks that could
result in the transaction not being completed on the terms
anticipated, on time, or at all. In the event we are unable to
close a transaction that we've entered into, we may be
subject to termination fees that could become payable to
the vendor. An unavoidable level of risk remains regarding
potential undisclosed or unknown liabilities relating to any
acquisition. The existence of such undisclosed liabilities
may have a material adverse impact on our business,
financial condition, results of operations and cash flows.
There can be no assurance that the Company will realize
the anticipated benefits in respect of the Heartland
Generation acquisition.
The acquisition of Heartland Generation may not deliver
the anticipated benefits expected to arise from such
transaction, including as it pertains to accretion to free
cash flow, the remaining life of the Heartland Generation
assets and the ability for such assets to generate sufficient
average
annual
EBITDA
to
meet
the
Company's
expectations. Furthermore, as with all development
projects, there are risks related to the development of the
400 MW Battle River Carbon Hub Project held by Heartland
Generation,
including
risk
relating
to
the
project’s
continued development, the ability to obtain regulatory
approval and the economic outlook required to support a
final investment decision.
We could suffer lost revenues or increased
expenses and penalties if we are unable to
operate our generation facilities at a level
necessary to comply with our PPAs.
The ability of our facilities to generate the maximum
amount of power or steam that can be sold under PPAs is
an important determinant of our revenues. Under certain
PPAs, if the facility is not capable of generating electricity
or steam for the required availability in a given contract
year, penalty payments may be payable to the relevant
purchaser by us and could give rise to termination rights.
The payment of any such penalties or the termination of
such PPAs could adversely affect our revenues and
profitability.
We are dependent on access to parts and
equipment from certain key suppliers and we
may be adversely affected if these
relationships are not maintained.
Our ability to compete and expand depends on having
access, at a reasonable cost, to equipment, parts and
components that are technologically and economically
competitive with those used by our competitors. Although
we have individual framework agreements with various
suppliers, there can be no assurance that these
relationships with suppliers will be maintained or not
adversely affected. If they are not maintained, or are
adversely affected, our ability to compete may be impaired
due to lack of access or significant delays to the supply of
equipment, parts or components.
We depend on certain joint venture, strategic
and other partners that may have interests or
objectives that conflict with our objectives and
such differences could have a negative impact
on us.
We
have
entered
into
various
arrangements
with
communities or joint venture, strategic or other partners in
connection with the operation of our facilities and assets.
Certain of these partners may have or develop interests or
objectives that are different from, or in conflict with, our
objectives. Any such differences could have a negative
impact on the Company's ability to realize the anticipated
benefits of, or the anticipated increase in the value of
facilities or assets subject to, these arrangements. We are
sometimes required through the permitting and approval
processes to notify and consult with various stakeholder
groups, including landowners, Indigenous groups and
municipalities. Any unforeseen delays in this process may
negatively impact our ability to complete any given facility
on time or at all and could result in write-offs or give rise to
reputational harm.
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Dam and dyke failures may result in lost
generating capacity, increased maintenance
and repair costs and other liabilities.
A natural or man-made disaster, and certain other events,
including natural or induced seismic activity, could
potentially cause dam failures at our hydroelectric facilities
and various dam sites. The occurrence of dam or dyke
failures at any of our facilities could result in a loss of
generating capacity, damage to the environment or
damages and harm to third parties or the public, and such
failures could require us to incur significant expenditures of
capital and other resources or expose us to significant
liabilities for damages. There can be no assurance that our
dam safety program will be able to detect potential dam
failures prior to their occurrence or eliminate all adverse
consequences in the event of failure. Other safety
regulations could change from time to time, potentially
impacting our costs and operations. Reinforcing all dams or
dykes to enable them to withstand more severe events
could require us to incur significant expenditures of capital
and other resources. The consequences of dam or dyke
failures could have a material adverse effect on us. This
includes any increased risk of dam failure due to induced
seismic activity triggered by fracking near our hydroelectric
facilities, which could increase the risk of dam failure or
require the Company to incur potentially significant capital
investments to mitigate such risk and that would not
otherwise be required.
The power generation industry has certain
inherent risks related to worker health and
safety, and the environment, that could cause
us to suffer unanticipated expenditures or to
incur fines, penalties or other consequences
material to our business and operations.
The ownership and operation of our power generation
assets carry an inherent risk of liability and reputational
harm related to worker health and safety, and the
environment, including the risk of government-imposed
orders to remedy unsafe conditions and/or to remediate or
otherwise address environmental contamination, potential
penalties
for
contravention
of
health,
safety
and
environmental laws, licences, permits and other approvals,
and potential civil liability. Compliance with (and any future
changes to) health, safety and environmental laws and the
requirements of licences, permits and other approvals are
expected to remain material to our business. The
occurrence of any of these events or any changes,
additions to, or more rigorous enforcement of health,
safety and environmental laws, licences, permits or other
approvals could have a significant impact on our
operations and/or result in additional material expenditures.
As a consequence, no assurances can be given that
additional environmental and workers' health and safety
issues relating to presently known or unknown matters will
not require unanticipated expenditures, or result in fines,
penalties or other consequences (including changes to
operations) material to our business and operations.
Climate change and other variations in
weather can affect demand for electricity and
our ability to generate electricity.
Due to the nature of our business, our earnings are
sensitive to weather variations from period to period, as
well as long-term changes due to climate change.
Variations in winter weather affect the demand for
electrical heating requirements. Variations in summer
weather
affect
the
demand
for
electrical
cooling
requirements. These variations in demand can translate
into electricity market price volatility. Variations in
precipitation also affect water supplies, which in turn affect
our hydroelectric assets. Also, variations in sunlight and
wind conditions can have an effect on energy production
levels from our solar and wind facilities. Typically, when
winters are warmer or summers are cooler, demand for
energy is lower than expected, resulting in less electricity
consumption than forecasted and often resulting in lower
than expected market prices for electricity. Conversely,
when winters are colder or summers are warmer, market
prices for natural gas or electricity tend to be higher;
however, in these circumstances, if we have entered into
hedges and are unable to produce or consume the amount
of natural gas or electricity that we have hedged we could
be required to purchase additional volumes at higher prices
to cover our hedge position.
Our generation facilities and their operations are exposed
to potential damage and partial or complete loss resulting
from environmental disasters (e.g., floods, strong winds,
wildfires, earthquakes, tornados and cyclones), equipment
failures and other events beyond our control, which could
make it difficult for the Company to continue to generate
electricity during such periods, and such circumstances
could pose threats to the Company's equipment and
personnel.
The accumulation of ice on wind turbine blades depends
on a number of factors including temperature and ambient
humidity, and can have a significant impact on energy
yields and could result in the wind turbine experiencing
more downtime. Extreme cold temperatures can also
impact the ability of wind turbines to operate effectively,
and this could result in more downtime and reduced
production. Sudden temperature changes can create an
increased risk of ice crystals that can pose a number of
constraints on our hydro operations.
Climate change is expected to change the volume and
timing of precipitation which may impact the ability of
hydro facilities to maximize the generation from available
water. These changes in flow may result in additional
operational costs to manage water through the hydro
plants. Variations in weather may be impacted by climate
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change resulting in sustained higher temperatures, rising
sea levels and altered precipitation patterns that could
have an impact on our generating assets. Furthermore,
climate change could result in increased variability or
sustained long-term changes to our water and wind
resources impacting hydroelectric and wind electricity
generation, which could adversely affect our revenues and
profitability.
Variation in wind levels may negatively impact
the amount of electricity generated at our
wind facilities.
Given that wind is variable, the amount of electricity
produced from our wind facilities is also variable. In
addition, the strength and consistency of the wind
resource at our wind facilities may vary from what we
anticipate due to a number of factors, including the extent
to which our site-specific historic wind data and wind
forecasts accurately reflect actual long-term wind speeds,
strength and consistency, the potential impact of climatic
factors, the accuracy of our assumptions relating to,
among other things, weather, icing, degradation, site
access, wake and wind shear line losses and wind shear,
and the potential impact of topographical variations and
the potential for electricity losses to occur before delivery.
A reduced amount of wind at the location of one or more of
our wind facilities over an extended period may reduce the
production
from
such
facilities,
as
well
as
any
environmental attributes that accrue to us related to that
production and reduce our revenues and profitability.
There can be no assurance that we will
achieve or be able to adhere to our
sustainability targets and any failure to do so
may present adverse consequences to our
business.
The Company annually establishes sustainability targets to,
among things, manage current and emerging material
sustainability issues, which include targets relating to
decarbonization (refer to the 2025+ Sustainability Targets
section of this MD&A for details). The Board of Directors
has the discretion to determine the sustainability targets
being adopted by the Company and may modify or cancel
any previously established sustainability target at any time.
The Board of Director's determination to establish, alter or
cancel any sustainability target will depend on, among
other things: the United Nations Sustainable Development
Goals; results of operations; technological considerations;
financial condition; market opportunities; legal, regulatory
and contractual considerations; and other relevant factors.
Further, there is no certainty that the Company will be
successful in achieving any particular sustainability target
within the stated time frame, or at all. If we are not able to
achieve, or adhere to, our sustainability targets, we may
not
satisfy
our
stakeholders'
current
and
future
expectations, which could negatively impact our reputation
and could result in certain investors being unable to hold
our common shares.
Many of our activities and properties are
subject to environmental regulations, and any
liabilities arising under these requirements
may materially adversely affect our business.
Our operations are subject to federal, provincial, state and
local environmental laws, regulations and guidelines
relating to the generation and transmission of electrical
and thermal energy and surface mine reclamation
(collectively,
environmental
regulations).
These
environmental regulations pertain to pollution and the
protection of the environment, health and safety, and
govern, among other things, air emissions, water usage
and discharges, storage, treatment and disposal of waste
and other materials, and remediation of sites and
responsible land use. These laws and regulations can
impose liability and obligations for costs to investigate and
remediate contamination without regard to fault, and under
certain circumstances liability may be joint and several,
resulting in one responsible party being held responsible
for the entire obligation. Environmental regulations can also
impose, among other things, restrictions, liabilities and
obligations in connection with the generation, handling,
use, storage, transport, treatment and disposal of
hazardous substances and waste, and can impose
cleanup, disclosure or other responsibilities with respect to
spills, releases and emissions of various substances to the
environment. Environmental regulations can also require
that facilities and other properties associated with our
operations be operated, maintained, abandoned and
reclaimed to the satisfaction of applicable regulatory
authorities.
In
addition,
the
relative
stringency
of
environmental regulations can reduce or decline based on
political direction, resulting in potentially unstable policy
environments at national, state/province and regional
levels in Canada, the U.S. and Western Australia, which
may
impose
different
compliance
requirements
or
standards on our business. These various compliance
standards may impact costs and/or our ability to operate
our facilities.
Changes in standards, new or amended regulation,
increased enforcement by regulatory authorities, more
extensive permitting requirements, an increase in the
number and types of assets operated by the Company
subject
to
environmental
regulation
and
the
implementation or change to regional, provincial, state and
national environmental regulations may impose varying
obligations on us in the jurisdictions in which we operate,
and could increase our expenditures. To the extent these
expenditures cannot be passed through to our customers
under our PPAs or otherwise, our costs could be material.
In addition, compliance with environmental regulation may
result in restrictions on some of our operations. It is
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anticipated that compliance costs are at risk of change due
to increased political and public attention.
If we do not comply with environmental regulations,
regulatory agencies could seek to impose statutory,
administrative and/or criminal liabilities on us, curtail our
operations,
or
require
significant
expenditures
on
compliance, new equipment or technology, reporting
obligations and research and development.
With Bill C-59 we anticipate continued and growing
scrutiny by lawyers and other stakeholders relating to
sustainability performance. We could face civil liability in
the event that private parties seek to impose liability on us
for property damage, personal injury or other costs and
losses.
We
cannot
guarantee
that
lawsuits
or
administrative or investigative actions will not be started
against us and otherwise affect our operations and assets.
If an action is filed against us or may otherwise affect our
operations and assets, we could be required to make
substantial expenditures to defend against, or provide
evidence of our activities or to bring our Company, our
operations and assets into compliance, which could have a
material adverse effect on our business.
The estimated reclamation costs applicable to the
Company's operations may be inaccurate and could require
greater financial resources than currently anticipated. As
an owner of mines that were previously in operation, we
maintain permits from the applicable regulatory body
providing for the authorization of certain mining operations
that result in a disturbance of the surface. These
requirements sought to limit the adverse impacts of coal
mining with more restrictive requirements potentially being
adopted from time to time. As an owner of mines that were
previously in operation, we may also be required to submit
a bond or otherwise secure payment of certain long-term
obligations including mine closure or reclamation costs.
Surety bond costs have increased in recent years and the
market terms of such bonds have generally become more
unfavourable. In addition, the number of companies willing
to issue surety bonds has decreased. We could be required
to self-fund these obligations should we be unable to
renew or secure the required surety bonds for our mining
operations or if it becomes more economical to do so.
We manage environmental compliance risk by:
• Seeking
continuous
improvement
in
numerous
performance metrics such as emissions, safety, land and
water impacts and environmental incidents;
• Staffing projects during construction and maintenance
activities with expert environmental firms to help assure
compliance during the project execution process and
long term operations of the asset;
• 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, Western Australia and the U.S.
to advocate that regulatory changes are well-designed
and cost-effective;
• Developing compliance plans that address how to meet
or surpass emission standards for GHG, mercury, SO2
and NOx, which will be adjusted as regulations are
finalized;
• Purchasing carbon emissions reduction offsets or credits;
• Investing in renewable energy projects, such as wind,
solar and hydro generation and storage technologies;
and
• Incorporating change-in-law provisions in contracts that
allow recovery of certain compliance costs from our
customers.
We are committed to remaining in compliance with all
environmental regulations relating to operations and
facilities. Compliance with both regulatory requirements
and management system standards is regularly audited
through our performance assurance policy and results are
reported to the GSSC.
The laws and regulations in the various
markets in which we operate are subject to
change, which may materially adversely affect
us.
Most of the markets in which we operate and intend to
operate are subject to significant regulatory oversight and
control. We are not able to predict whether there will be
any further changes in the regulatory environment,
including potential carbon and other environmental
regulations, changes in market structure or market design,
or changes in other laws and regulations. Existing market
rules, regulations and reliability standards are often
dynamic and may be revised or re-interpreted, and new
laws and regulations may be adopted or become
applicable to us or our facilities, which could have a
material adverse effect on us. Many of our projects must
also comply with reliability standards, including those
established by the North American Electric Reliability
Corporation and Alberta Reliability Standards. Failure to
comply with these mandatory reliability standards could
result
in
sanctions,
including
substantial
monetary
penalties. We manage these risks systematically through a
regulatory and compliance program designed to reduce
any potential negative impact on us. However, we cannot
guarantee that we will be able to adapt our business in a
timely manner in response to any changes in the regulatory
regimes in which we operate, and such failure to adapt
could have a material adverse effect on our business.
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Regulatory authorities may also from time to time audit or
investigate our activities in the markets in which we
operate or pursue trading. Such audits or investigations
may result in sanctions or penalties that may materially
affect our future activities, reputation or financial status.
Our facilities are also subject to various licensing and
permitting requirements in the jurisdictions in which we
operate. Many of these licences and permits need to be
renewed from time to time. If we are unsuccessful in
obtaining or renewing such licences or permits, or the
terms of such licences or permits are changed in a manner
that is adverse to our business, we could be materially
adversely affected.
Any changes in the rules and regulations of provincial or
state public utility commissions or other regulatory bodies
in the other markets in which we compete, or may compete
in the future, may materially adversely affect us.The laws
and regulations in the various markets in which we operate
are subject to change, which may materially adversely
affect us.
The reduction, elimination or expiration of
government subsidies and economic
incentives could adversely affect our
prospects for growth.
We seek to take full advantage of government policies that
promote renewable power generation and enhance the
economic
feasibility
of
renewable
power
projects.
Renewable power generation sources currently benefit
from various incentives in the form of feed-in tariffs,
rebates, tax credits, renewable portfolio standards (such
as the U.S. government policy mechanism that supports
the adoption of renewable power by setting a targeted
percentage of a jurisdiction's total electricity procurement
from renewable power) and other incentives throughout
the markets in which we participate or intend to
participate. If incentives are removed, we would expect to
see some reduction in development opportunities, but
given that all generators would be in the same boat, the
impact may be muted.
We may be adversely affected if our supply of
water is materially reduced.
Our hydroelectric and natural gas facilities and our coal-
fired facility require continuous water flow for their
operation.
Shifts
in
weather
or
climate
patterns,
seasonable precipitation, the timing and rate of melting,
run-off and other factors beyond our control may reduce
the water flow to our facilities. Any material reduction in
the water flow to our facilities would limit our ability to
produce and market electricity from these facilities and
could have a material adverse effect on us. There is an
increasing level of regulation respecting the use, treatment
and discharge of water, and respecting the licensing of
water rights in jurisdictions where we operate. Any such
change in regulations could have a material adverse effect
on us.
Availability or disruption of fuel supply to our
thermal plants could have an adverse impact
on the operation of our facilities and our
financial condition.
Our gas facilities rely on having adequate supplies of
natural gas and our Centralia facility requires adequate
supplies of coal to run the facility reliably and at full
capacity. As a result, we face the risk of not having
adequate fuel supplies available due to insufficient natural
gas transportation service, disruptions in fuel supplies due
to weather, strikes, lockouts, or breakdowns of equipment,
the timing of receiving regulatory approvals or we could be
materially adversely affected if the cost of fuel that we
must buy to generate electricity increases to a greater
degree than the price that we can obtain for the electricity
that we sell. Several factors affect the price of fuel, many
of which are beyond our control, including:
• Prevailing market prices for fuel;
• Global demand for energy products;
• The cost of carbon and other environmental concerns;
• Weather-related disruptions affecting the ability to
deliver fuels or near-term demand for fuels;
• Increases in the supply of energy products in the
wholesale power markets;
• Political instability, including the war in Ukraine;
• The extent of fuel transportation capacity, cost of fuel
transportation service into our markets or potential rail
strikes; and
• The cost of mining or extraction that, in turn, depends on
various factors such as labour market pressures,
equipment replacement costs and permitting.
Changes in any of these factors may increase our cost of
producing power or decrease the amount of revenue
received from the sale of power, which could have a
material adverse effect on us.
In the event the Company secures more natural gas than
required to operate its facilities, the Company may have
difficulty reselling such natural gas and it could be exposed
to the market price for natural gas in respect of any such
resales. There is no certainty that the Company will be
successful in reselling or recovering its costs in respect of
such resales of natural gas.
As well, the coal used to fuel the Centralia facility is
sourced from the Powder River Basin in Montana and
Wyoming through contracts to purchase and transport
such coal to our Centralia facility. The loss of our suppliers
or inability to receive coal at Centralia under our existing
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coal contracts at sufficient quantities, or at all, could also
significantly affect our ability to serve our customers and
have an adverse impact on our financial condition and
results of operations. We could face the risk of inadequate
supply service due to our reliance on the Pioneer Pipeline
and on the ATCO Pipeline as a significant provider of
natural gas for our Sundance and Keephills units.
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.
We manage coal supply and price 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.
In managing gas supply risk the company will enter into
long term transportation service agreements to ensure that
facilities have adequate gas supply. This also could result
in the additional risk of of being in a surplus position where
some of the transportation capacity may not be needed,
and the Company is still required to pay for the unused
transportation. To manage this risk the Company will
remarket excess natural gas transport capacity in the
short-term
while
seeking
long-term
or
permanent
assignments.
Our facilities rely on national and regional
transmission systems and related facilities that
are owned and operated by third parties and
have both regulatory and physical constraints
that could impede access to electricity
markets.
Our power generation facilities depend on electric
transmission systems and related facilities owned and
operated primarily by third parties to deliver the electricity
that we generate to delivery points where ownership
changes and we are paid. The risks associated with the
aging transmission infrastructure in the markets where we
operate are increasing because new connections to the
transmission system are consuming capacity faster than it
is being added by new transmission developments.
Further, transmission systems operate with both regulatory
and physical constraints that in certain circumstances may
impede access to electricity markets. There may be
instances in system emergencies in which our power
generation facilities are physically disconnected from the
power grid, or our production curtailed for periods of time.
Most of our electricity sales contracts do not provide for
payments to be made if electricity is not delivered.
Our power generation facilities may also be subject to
changes
in
regulations
governing
the
cost
and
characteristics of use of the transmission and distribution
systems to which our power generation facilities are
connected. Our power generation facilities in the future
may not be able to secure access to this interconnection or
transmission capacity at reasonable prices, in a timely
fashion or at all, which could then cause delays and
additional costs in attempting to negotiate or renegotiate
PPAs or to construct new projects. In addition, we may not
benefit from preferential arrangements in the future. Any
such increased costs and delays could delay the
commercial operation dates of any new projects and
negatively impact our revenues and financial condition.
Cyberattacks may cause disruptions to our
operations and could have a material adverse
effect on our business.
We rely on our information technology to process, transmit
and store electronic information and data used for the safe
operation of our assets. Over the past few years,
geopolitical tensions and the pandemic have significantly
impacted the cybersecurity ecosystem, increasing the
frequency and diversity of cyberattacks, including threats
of war-driven cyberattacks (i.e., terrorism) against critical
infrastructure and threat actors taking advantage of the
pandemic (e.g., charity scams) and hybrid working
environments. In the continuously evolving cybersecurity
threat landscape, any attacks or breaches of network or
information systems may disrupt our business operations
or compromise the proprietary, confidential or personal
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information of the Company, its customers, partners or
others
with
whom
the
Company
has
dealings.
Cyberattackers may use a range of techniques, from
exploiting vulnerabilities within our user base (social
engineering attacks), to using sophisticated malicious code
on a single or distributed basis to try to breach our network
security controls. We anticipate that the cyber threat
landscape will continue to evolve, with increasing threats
of ransomware, compromised insider threats, supply chain
attacks,
advanced
targeted
phishing
and
artificial
intelligence. Cyber threats originate from various sources
and vectors, from nation states, organized hacking groups
or malware/ransomware. The cyber threat landscape
continues to evolve, as we see cyber threats shift their
focus from traditional attacks against perimeter information
technology systems, to more effective attacks, such as
phishing and ransomware. A successful cyberattack may
allow for the unauthorized interception, destruction, use or
dissemination of proprietary, confidential or personal
information and may cause disruptions to our operations.
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.
We are subject to regulatory, legislative and business
requirements (e.g., North American Electric Reliability
Corporation Critical Infrastructure Protection, SOX, Privacy)
and
also
adopt
industry
endorsed
standards
and
frameworks (e.g., National Institute of Standards and
Technology, Critical Infrastructure Projection/Reliability
Standards) as they pertain to our cybersecurity program
and the implementation of our cybersecurity controls and
processes.
While we have cyber insurance, as well as systems,
policies,
procedures,
practices,
hardware,
software
applications and data backups designed to prevent or limit
the effect of security breaches of our network and
infrastructure, there can be no assurance that these
measures will be sufficient and that such security breaches
will not occur or, if they do occur, that they will be
adequately addressed in a timely manner.
TransAlta has established a comprehensive cybersecurity
program to manage cybersecurity risks through effective
security practices and structured and tailored plans.
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, and has 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 processes 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, we believe that
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.
Our technology and systems for
communication and monitoring may be
vulnerable to security breaches or
interruptions, which could result in increased
operating expenses and other liabilities.
We rely on technology, mainly on computer, telephone,
satellite, cellular and related networks and infrastructure,
to conduct our business and monitor the production of our
generation facilities. These systems and infrastructure
could be vulnerable to unforeseen problems including, but
not limited to, cyberattacks, breaches, vandalism and theft.
Our operations are dependent upon our ability to protect
our information and operating technology against damage
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from fire, power loss, telecommunications failure or a
similar catastrophic event. While we have dedicated
resources
for
maintaining
appropriate
levels
of
cybersecurity and we use third-party technology to help
protect us against security breaches and cyber incidents,
our measures may not be effective and our information
technology and infrastructure may be vulnerable to attacks
by
hackers
or
breached
due
to
employee
error,
malfeasance or other disruptions. Any such security
breaches and cyber incidents or other disruptions could
jeopardize the security of information stored in and
transmitted
through
our
systems
and
network
infrastructure, and could result in significant setbacks and
potential liabilities and deter future customers. Additionally,
we must be able to protect our generation facility
infrastructure against physical damage and any service
disruptions.
Any damage or failure that causes an interruption in
operations could have an adverse effect on our customers.
While we have systems, policies, hardware, practices and
procedures designed to prevent or limit the effect of failure
or
interruptions
of
our
generation
facilities
and
infrastructure, there can be no assurance that these
measures will be sufficient and that any such failures or
interruptions will not occur or, if they do occur, that they
will be adequately addressed in a timely manner.
We operate in a highly competitive
environment and may not be able to compete
successfully.
We operate in a number of Canadian provinces, as well as
in the U.S. and Western Australia. These areas of operation
are affected by competition ranging from large utilities to
small independent power producers, as well as private
equity,
pension
funds,
international
conglomerates,
traditional energy companies and technology firms. In
addition, potential customers may look to deploy their own
capital to self-supply their own electricity needs. Some
competitors have significantly greater financial and other
resources than we do. Such competition could have a
material adverse effect on our business. Emerging
technology affecting the demand, generation, distribution
or storage of electricity may also significantly impact our
business and ability to compete. Climate change and
regulatory incentives are expected to drive innovation and
transformation of the power generation sector, including
energy production and consumption, and there can be no
certainty that the Company will benefit from such
innovation or transformation. Furthermore, older facilities
may over time be unable to compete with newer more
efficient facilities utilizing improvements to existing power
technologies
and
cost-efficient
new
technologies,
including gas turbines with lower heat rates. In Alberta,
certain industrial customers rely on behind-the-fence
generation; these customers are not being supplied
electricity from the grid, which reduces the competitive
load in the province and puts downward pressure on pool
prices. Further, certain large industrial companies in Alberta
operate significant cogeneration facilities, which generate
steam required for their operations and often results in
large amounts of excess generation being offered to the
wholesale electricity market. These cogeneration facilities
offer their energy into the market at low prices to ensure it
is dispatched, which results in the facility realizing an
achieved price close to the average pool price, which
potentially puts downward pressure on the pool price and
could result in certain of the Company's facilities not being
dispatched.
Changes in general economic and market
conditions may have a material adverse effect
on us.
Adverse changes in general economic and market
conditions could negatively impact demand for electricity
as well as our 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 which could cause us to suffer a material
adverse effect.
We may be unsuccessful in legal actions.
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 that our liabilities with
respect to such claims will not have a material adverse
effect on us. Refer to the Other Consolidated Analysis
section of this MD&A for further details.
We may have difficulty raising needed capital
in the future, which could significantly harm
our business.
To the extent that our sources of cash and cash flow from
operations are insufficient to fund our activities or we are
unable to divest assets to generate capital, we may need
to raise additional funds. Additional financing may not be
available when needed, and if such financing is available, it
may not be available on terms that are favourable to our
business.
Recovery of the capital investment in power projects
generally occurs over a long period of time. As a result, we
must obtain funds from equity or debt financings, including
tax equity transactions, or from government grants, to help
finance the acquisition and development of projects and to
support the general and administrative costs of operating
our business. Our ability to arrange financing, either at the
corporate level or at the subsidiary level (including non-
M146
TransAlta Corporation
2024 Integrated Report
recourse project debt or tax equity), and the costs of such
capital are dependent on numerous factors, including: (a)
general economic and capital market conditions; (b) credit
availability from banks and other financial institutions; (c)
investor confidence and the markets in which we conduct
operations; (d) our financial performance and/or the
expected financial performance of certain assets; (e) our
level of indebtedness and compliance with covenants in
our debt agreements; (f) our cash flow and/or the expected
cash flow of certain assets; and (g) our credit ratings. We
are subject to certain financial covenants under our credit
facility that could limit the amount of additional debt that
the Company could raise in certain circumstances. An
inability to raise project debt or tax equity financing could
reduce the number of projects that we are able to finance.
If we are unable to raise additional funds when needed, we
could be required to delay the acquisition and construction
of growth projects, reduce the scope of projects, abandon
or sell some of our projects or generation facilities, or
default on our contractual commitments in the future, any
of which could adversely affect our business, financial
condition and results of operations.
TransAlta's debt securities will be structurally
subordinated to any debt of our subsidiaries
that is currently outstanding or may be
incurred in the future.
We operate our business through, and a majority of our
assets are held by, our subsidiaries, including partnerships.
Our
results
of
operations
and
ability
to
service
indebtedness
are
dependent
upon
the
results
of
operations of our subsidiaries and the payment of funds by
these subsidiaries to TransAlta in the form of loans,
dividends or otherwise. Our subsidiaries may be restricted
in their ability to pay amounts due, or make any funds
available to TransAlta, whether by dividends, interest
payments, loans, advances or other payments. In addition,
the payment of dividends and the making of loans,
advances and other payments to us by our subsidiaries
may be subject to statutory or contractual restrictions or
tax withholding amounts. In the event of the liquidation of
any subsidiary, the assets of the subsidiary would be used
first to repay the indebtedness of the subsidiary, including
trade payables or obligations under any guarantees, before
being used to pay TransAlta's indebtedness, including any
debt securities issued by TransAlta. Such indebtedness
and any other future indebtedness of such subsidiaries
would be structurally senior for such subsidiary to any debt
securities issued by TransAlta.
Our subsidiaries have financed some investments using
non-recourse project financing. Each non-recourse project
loan is structured to be repaid out of cash flow provided by
the project. In the event of a default under a financing
agreement that is not secured, the lenders would generally
have rights to the related assets. In the event of
foreclosure after a default, our subsidiary may lose its
equity in the asset or may not be entitled to any cash that
the asset may generate.
A downgrade of our credit ratings could
materially and adversely affect us.
Rating agencies regularly evaluate us, basing their ratings
of our long and short-term debt, along with our issuer
rating, on a number of factors. There can be no assurance
that one or more of our credit ratings and the
corresponding outlooks will not be changed. Our borrowing
costs and ability to raise funds are directly impacted by our
credit ratings. Credit ratings may be important to suppliers
or counterparties when they seek to engage in certain
transactions with us. A credit rating downgrade could
potentially impair our ability to enter into arrangements
with suppliers or counterparties, to engage in certain
transactions, and could limit our access to private and
public credit markets and increase the costs of borrowing
under our existing credit facilities. See Note 15 of our
audited consolidated financial statements for the year
ended Dec. 31, 2024, which financial statements are
incorporated by reference herein.
Changes to our reputation may have a material
adverse effect on us.
Reputation risk relates to the risk associated with our
business because of changes in opinion from the general
public, private stakeholders, governments, financiers and
other entities. Our reputation is one of our most valued
assets. The potential for harming our reputation exists in
every business decision and all risks can have an impact on
reputation, which in turn can negatively impact our
business and securities. Reputational risk cannot be
managed in isolation from other forms of risk. Negative
impacts from a compromised reputation could include
revenue loss, reduction in our customer base and the
decreased value of our securities.
We 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;
• Pursuing sustainable development as a longer-term
corporate strategy;
TransAlta Corporation
2024 Integrated Report
M147
• 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.
We may fail to meet financial expectations.
Our quarterly revenue, earnings, cash flows and results of
operations are difficult to predict and fluctuate from
quarter to quarter. Our quarterly results of operations are
influenced by a number of factors, including the risks
described in this MD&A, many of which are outside of our
control and that may cause such results to fall below
market expectations. Although we base our planned
operating expenses in part on our expectations of future
revenue, a significant portion of our expenses are relatively
fixed in the short-term. If revenue for a particular quarter is
lower than expected, we will likely be unable to
proportionately reduce our operating expenses for that
quarter, which will adversely affect our results of
operations for that quarter.
Our cash dividend payments are not
guaranteed.
The payment of dividends is not guaranteed and could
fluctuate. The Board of Directors has the discretion to
determine the amount and timing of any dividends to be
declared and paid to our shareholders. In addition, the
payment of dividends on common shares is, in all cases,
subject to prior satisfaction of preferential dividends
applicable to each series of our first preferred shares. We
may alter our dividend on common shares at any time. The
Board of Directors' determination to declare dividends will
depend on, among other things: results of operations;
financial condition; current and expected future levels of
earnings; operating cash flow; liquidity requirements;
market opportunities; income taxes; maintenance and
growth capital expenditures; debt repayments; legal,
regulatory and contractual constraints; working capital
requirements; taxes payable; and other relevant factors.
Our short- and long-term borrowings may prohibit us from
paying dividends at any time at which a default or event of
default would exist under such debt, or if a default or event
of default would exist as a result of paying the dividend.
Over time, our capital and other cash needs may change
significantly from our current needs, which could affect
whether we pay dividends and the amount of any
dividends we may pay in the future. If we continue to pay
dividends at the current level, we may not retain a
sufficient amount of cash to finance growth opportunities,
meet any large unanticipated liquidity requirements or fund
our operations in the event of a significant business
downturn. The Board of Directors, subject to the
requirements of our bylaws and other governance
documents, may amend, revoke or suspend our dividends
at any time. A decline in the market price or liquidity, or
both, of our common shares could result if the Board of
Directors reduces or eliminates the payment of dividends.
We are dependent on the operations of our facilities for our
cash availability. The actual amount of cash available for
dividends to holders of our common shares will depend
upon numerous factors relating to each of our generation
facilities
including:
operating
performance
of
our
generation facilities; profitability; changes in gross margin;
fluctuations in working capital; capital expenditure levels;
applicable laws; tax position; financing; compliance with
contracts; and contractual restrictions contained in the
instruments governing any indebtedness. Any reduction in
the amount of cash available for distribution from our
generation facilities will reduce the amount of cash
available to pay dividends to holders of our common
shares.
The market price for our common shares may
be volatile.
The market price for our common shares may be volatile
and subject to wide fluctuations in response to numerous
factors, many of which are beyond our control, including:
(a) actual or anticipated fluctuations in our results of
operations; (b) recommendations by securities research
analysts; (c) changes in the economic performance or
market valuations of other companies that investors deem
comparable; (d) the loss or resignation of executive
officers and other key personnel; (e) sales or perceived
sales
of
additional
common
shares;
(f)
significant
acquisitions
or
business
combinations,
strategic
partnerships, joint ventures or capital commitments by or
involving us or our competitors; and (g) trends, concerns,
technological or competitive developments, regulatory
changes and other related issues in the power generation
industry or our target markets.
Financial markets have experienced significant price and
volume fluctuations that have particularly affected the
market prices of equity securities of companies and such
fluctuations have, in many cases, been unrelated to the
operating
performance,
underlying
asset
values
or
prospects of such companies. Accordingly, the market
price of our common shares may decline even if our
operating results, underlying asset values or prospects
have not changed. Additionally, these factors, as well as
other related factors, may cause decreases in asset values
that may result in impairment losses. Certain institutional
investors may base their investment decisions on
consideration of our environmental, governance and social
practices and performance against such institutions'
respective investment guidelines and criteria, and failure to
meet such criteria may result in limited or no investment in
our common shares by those institutions, which could
adversely affect the trading price of our common shares.
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2024 Integrated Report
We may not be able to extend, renew or
replace expiring or terminated PPAs, or other
customer contracts at favourable rates or on a
long-term basis.
Our ability to extend, renew or replace our existing PPAs or
other customer contracts depends on a number of factors
beyond our control, including, but not limited to: whether
the PPA counterparty has a continued need for energy at
the time of the agreement’s expiration; the presence or
absence of governmental incentives or mandates which
prevails market prices; the availability of other electricity
sources; the satisfactory performance of our obligations
under such PPAs; the regulatory environment applicable to
our contractual counterparties at the time; macroeconomic
factors present at the time, such as population, business
trends, international trade laws, regulations, agreements,
treaties, policies or other countries and related energy
demand; and the effects of regulation on the contracting
practices of our contractual counterparties.
If we are not able to extend, renew or replace on
acceptable terms existing PPAs before contract expiration,
or if such agreements are otherwise terminated prior to
their expiration, we may not have any ability to sell
electricity to the market or to other customers. If we are
able to sell electricity on an uncontracted basis, we would
sell electricity at prevailing market prices that could be
materially lower than under the applicable contract. This
could result in us having less stable cash flows. If there is
no satisfactory market for a project’s uncontracted energy,
we may decommission the project before the end of its
useful life. Any failure to extend, renew or replace a
significant portion of our existing PPAs, or other customer
contracts, or extending, renewing or replacing them at
lower prices or with other unfavourable terms, or the
decommissioning of a project, could have a material
adverse effect on our business, financial condition, results
of operations and ability to pay dividends to our
shareholders.
We may fail to fully or effectively hedge our
supply and price risk exposure.
We closely monitor the risks associated with changes in
electricity and input fuel prices on our future operations
and, where we consider it appropriate, use various physical
and financial instruments to hedge our assets and
operations from such price risks. The efficacy of our risk
management and hedging program may be adversely
impacted by unanticipated events and costs that we are
not able to effectively mitigate, including unanticipated
events that impact supply and demand, such as extreme
weather and unplanned outages. We may also be
adversely impacted if we make incorrect assumptions that
were relied upon in establishing our hedges. We are
exposed to changes in electricity prices and natural gas
prices on purchases of electricity or natural gas from the
market to fulfil our supply obligations under these short-
and long-term hedge contracts. If we are unable to
produce or consume the amount of natural gas or
electricity that we have hedged, we could incur losses as
we could be required to purchase additional volumes in the
market at higher prices in order to cover our hedge
position. Comparably, if the market price for electricity is
higher than the hedged price we would be subject to the
opportunity cost associated with not realizing the higher
market price.
We are also exposed to basis risk as certain of our
generating facilities receives the "node" price for the
electricity it delivers to the grid while the financial PPA for
such generating facility settles at the "hub" price. The
differences between the "node" price and "hub" price can
be significant from time to time.
Trading risks may have a material adverse effect on our
business.
Our trading and marketing business frequently involves
establishing trading positions in the wholesale energy
markets on both a medium-term and short-term basis, and
on both an asset and proprietary basis. To the extent that
we have long positions in the energy markets, a downturn
in market prices will result in losses from a decline in the
value of such long positions. Conversely, to the extent that
we enter into forward sales contracts to deliver energy that
we do not own, or take short positions in the energy
markets, an upturn in market prices will expose us to losses
as we attempt to cover any short positions by acquiring
energy in a rising market.
In addition, from time to time, we may have a trading
strategy consisting of simultaneously holding a long
position and a short position, from which we expect to earn
a profit based on changes in the relative value of the two
positions. If, however, the relative value of the two
positions changes in a direction or manner that we did not
anticipate, we would realize losses from such a paired
position.
If the strategy that we use to hedge our exposures to
these various risks is not effective, we could incur
significant losses. Our trading positions can be impacted
by volatility in the energy markets that, in turn, depend on
various factors, including weather in various geographical
areas and short-term supply and demand imbalances,
which cannot be predicted with any certainty. A shift in the
energy markets could adversely affect our positions, which
could also have a material adverse effect on our business.
We use a number of risk management controls conducted
by our risk management group to limit our exposure to risks
arising from our trading activities. These controls include
risk capital limits, Value at Risk, Gross Margin at Risk, tail
risk scenarios, position limits, concentration limits, credit
limits and approved product controls. We cannot guarantee
TransAlta Corporation
2024 Integrated Report
M149
that losses will not occur and such losses may be outside
the parameters of our risk controls.
Certain of the contracts to which we are a
party require that we provide collateral against
our obligations.
We are exposed to risk under certain arrangements,
including financial derivative contracts and electricity and
natural gas purchase and sale contracts entered into for
the purposes of hedging and proprietary trading. The terms
and conditions of these contracts may require us to
provide collateral when the fair value of these contracts is
in excess of any credit limits granted by our counterparties
and the contract obliges that we provide the collateral. The
change in fair value of these contracts often occurs due to
changes in commodity prices. These contracts include: (a)
financial derivative contracts when forward commodity
prices are more or less than contracted prices, depending
on the transactions; (b) purchase agreements, when
forward commodity prices are less than contracted prices;
and (c) sales agreements, when forward commodity prices
exceed
contracted
prices.
Downgrades
in
our
creditworthiness by certain credit rating agencies may
decrease the credit limits granted by our counterparties
and, accordingly, increase the amount of collateral that we
may have to provide. Any increase in the amount of
collateral provided by the Company could reduce our
liquidity and materially adversely affect us.
If counterparties to our contracts are unable
to meet their obligations, we may be
materially and adversely affected.
If purchasers of our electricity and steam or other
contractual counterparties default on their obligations, we
may be materially and adversely affected. While we have
procedures and controls in place to manage counterparty
credit risk before entering into contracts, all contracts
inherently contain default risk. Moreover, while we seek to
monitor trading activities to ensure that the credit limits for
counterparties are not exceeded, we cannot guarantee
that a party will not default. If counterparties to our
contracts are unable to meet their obligations, we could
suffer a reduction in revenue that could have a material
adverse effect on our business.
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 restrictions on 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, 2023. We had no material
counterparty losses in 2024. 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.
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2024 Integrated Report
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, 2024:
Investment
grade
(per cent)
Non-investment
grade
(per cent)
Total
(per cent)
Total
amount
($)
Trade and other receivables(1,2)
87
13
100
767
Long-term finance lease receivables
100
—
100
305
Risk management assets(1)
58
42
100
411
Loan receivable(2)
—
100
100
25
Total
1,508
(1)
Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.
(2) Includes $25 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 $77
million (2023 – $23 million).
Because of our multinational operations, we
are subject to currency rate risk, tax,
regulatory and political risk.
We have exposure to various currencies as a result of our
investments and operations in foreign jurisdictions, the
earnings from those operations, the acquisition of
equipment
and
services
and
foreign-denominated
commodities from foreign suppliers, and our U.S. and
Australian dollar-denominated debt. Our exposures are
primarily to the U.S. and Australian currencies, and
changes in the values of these currencies relative to the
Canadian dollar could negatively impact our operating cash
flows or the value of our foreign investments. While we
attempt to manage this risk by using hedging instruments,
including cross-currency interest rate swaps, forward
exchange contracts and matching revenues and expenses
by currency at the corporate level, there can be no
assurance that these risk management efforts will be
effective, and fluctuations in these exchange rates may
have a material adverse effect on our business.
In addition to currency rate risk, our foreign operations may
be subject to tax, regulatory and political risk. Any change
to the regulations governing power generation or the
political climate in the countries where we have operations
could impose additional costs and have a material adverse
effect on us.
We manage our currency rate risk by establishing and
adhering to policies that include:
• Hedging our net investments in U.S. operations using
U.S. dollar denominated debt;
• Entering into forward foreign exchange contracts to
hedge
future
foreign-denominated
expenditures
including our U.S. dollar 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 U.S. and
Australian exposure, net of debt service and sustaining
capital expenditures, is managed with forward foreign
exchange contracts.
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M151
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 U.S. 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
$20
We are not able to insure against all potential
risks and may become subject to higher
insurance premiums.
Our business is exposed to the risks inherent in the
construction and operation of electricity generation
facilities, such as breakdowns, manufacturing defects,
natural disasters, injury, damage to third parties, theft,
terrorist attacks, cyberattacks and sabotage. We are also
exposed to environmental risks. We maintain insurance
policies, covering usual and customary risks associated
with our business, with creditworthy insurance carriers. Our
insurance policies, however, may not cover losses, or may
be subject to limitations in coverage as a result of force
majeure, natural disasters, terrorist or cyberattacks or
sabotage, armed hostilities, or other perils. Our insurance
policies may be subject to increase resulting from climate
change, for example due to increased storm severity and
frequency. In addition, we generally do not maintain
insurance for certain environmental risks, such as
environmental contamination. Our insurance policies are
subject to annual review by the respective insurers and
may not be renewed at all or on similar or favourable terms.
A significant uninsured loss or a loss significantly
exceeding the limits of our insurance policies or the failure
to renew such insurance policies on similar or favourable
terms could have a material adverse effect on our
business, financial condition and results of operations.
Our insurance coverage may not be available in the future
on commercially reasonable terms or adequate insurance
limits may not be available in the market. In addition, the
insurance proceeds received for loss or damage to any of
our generation facilities may not be sufficient to permit us
to continue to make payments on our debt.
Provision for income taxes may not be
sufficient.
Our operations are complex and located in several
countries, and the computation of the provision for income
taxes
involves
tax
interpretations,
regulations
and
legislation that are continually changing. In addition, our tax
filings are subject to audit by taxation authorities. While we
believe that our tax filings have been made in material
compliance
with
all
applicable
tax
interpretations,
regulations and legislation, we cannot guarantee that we
will not have disagreements with taxation authorities with
respect to our tax filings that could have a material adverse
effect on our business.
The Company and its subsidiaries are subject to changing
laws, treaties and regulations in and between countries.
Various tax proposals in the countries we operate in could
result in changes to the basis on which deferred taxes are
calculated or could result in changes to income or non-
income tax expense. There has recently been an increased
focus on issues related to the taxation of multinational
corporations. A change in tax laws, treaties or regulations,
or in the interpretation thereof, could result in a materially
higher income or non-income tax expense that could have
a material adverse impact on us.
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
$3
If we fail to attract and retain key personnel,
we could be materially adversely affected.
The loss of any of our key personnel or our inability to
attract, train, retain and motivate additional qualified
management and other personnel could have a material
adverse effect on our business. Competition for these
personnel is intense and there can be no assurance that
we will be successful in this regard. If we are unable to
successfully
negotiate
new
collective
bargaining
agreements with our unionized workforce, as required, we
will be adversely affected.
While we believe we have a satisfactory relationship with
our unionized employees, we cannot guarantee that we will
be able to successfully negotiate or renegotiate our
collective bargaining agreements on terms agreeable to
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TransAlta. In 2024 we successfully renegotiated one
collective bargaining agreement.
We expect to renegotiate four collective bargaining
agreements in 2025. Any hurdles in negotiating these
collective bargaining agreements could lead to higher
employee costs and a work stoppage or strike, which could
have a material adverse effect on us.
We 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 for non-union roles 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.
We are subject to risks associated with our
ownership interests in projects that are under
construction, which could result in our inability
to complete construction projects on time or
at all, and make projects too expensive to
complete or cause the return on an investment
to be less than expected.
TransAlta has interests in certain projects that have not yet
started operations or are under construction. There may be
delays or unexpected developments in completing any
future construction projects, which could cause the
construction costs of these projects to exceed our
expectations, result in substantial delays or prevent the
project from commencing commercial operations. Various
factors could contribute to construction-cost overruns,
construction halts or delays or the failure to commence
commercial operations, including: delays in obtaining, or
the inability to obtain, necessary land rights, permits and
licences; delays and increased costs related to the
interconnection of new projects to the transmission
system; the inability to acquire or maintain land use and
access rights; the failure to receive contracted third-party
services; interruptions to dispatch at the projects; supply
chain disruptions, including as a result of changes in
international trade laws, regulations, agreements, treaties,
taxes, tariffs, duties or policies of Canada, the U.S. or other
countries in which the Company's suppliers are located;
work stoppages; labour disputes; weather interferences;
unforeseen engineering, environmental and geological
problems, including, but not limited to, discoveries of
contamination, protected plant or animal species or
habitat, archaeological or cultural resources or other
environment-related factors; unanticipated cost overruns
in excess of budgeted contingencies; and failure of
contracting parties to perform under contracts.
In addition, if we or one of our subsidiaries has an
agreement for a third party to complete construction of any
project,
TransAlta
is
subject
to
the
viability
and
performance of the third party. Our inability to find a
replacement contracting party, if the original contracting
party
has
failed
to
perform,
could
result
in
the
abandonment of the construction of such project, while we
could remain obligated under other agreements associated
with the project, including, but not limited to, offtake PPA's.
We 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.
TransAlta Corporation
2024 Integrated Report
M153
New technology and artificial intelligence may
present emerging risks that could have a
material adverse effect on the Company.
We are introducing artificial intelligence and robotics at
some of our facilities. The use of artificial intelligence and
robotics at our facilities may not yield materially better
results, higher outputs or increased productivity and there
is no certainty that we will realize benefits from
investments in these technologies. Additionally, the use of
artificial intelligence is subject to the risk that privacy
concerns relating to such technology could deter current
and potential customers.
The global energy transition may have an
adverse effect on the Company.
The decarbonization of the global energy system in order
to achieve net-zero emissions and minimize a global
temperature rise poses several risks to TransAlta's
business, including but not limited to, changing regulations
and policies, market risks from the volatility of and
uncertainty of the energy supply and demand, and
operational risks from new technologies.
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
$17
Changes in interest rates can impact our borrowing costs and affect our 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.
At Dec. 31, 2024, approximately 18 per cent (2023 – 14 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.
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.
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
$3
M154
TransAlta Corporation
2024 Integrated Report
Disclosure Controls and Procedures
Management
is
responsible
for
establishing
and
maintaining adequate internal control over financial
reporting (ICFR) and disclosure controls and procedures
(DC&P). For the year ended Dec. 31, 2024, the majority of
our workforce supporting and executing our ICFR and
DC&P continue to work on a hybrid basis. The Company
has implemented appropriate controls and oversight for
both in-office and remote work. There has been minimal
impact to the design and performance of our internal
controls.
ICFR is a framework designed to provide reasonable
assurance regarding the reliability of financial reporting and
the preparation of the consolidated financial statements for
external purposes in accordance with IFRS. Management
has used the Internal Control – Integrated Framework
issued by the Committee of Sponsoring Organizations of
the Treadway Commission (2013 framework) to assess the
effectiveness of the Company’s ICFR.
DC&P refer to controls and other procedures designed to
ensure that information required to be disclosed in the
reports we file or submit under securities legislation is
recorded, processed, summarized and reported within the
time frame specified in applicable securities legislation.
DC&P include, without limitation, controls and procedures
designed to ensure that information required to be
disclosed by us in our reports that we file or submit under
applicable securities legislation is accumulated and
communicated to management, including our Chief
Executive
Officer
and
Chief
Financial
Officer,
as
appropriate to allow timely decisions regarding our
required disclosure.
Together, the ICFR and DC&P frameworks provide internal
control over financial reporting and disclosure. In designing
and
evaluating
our
ICFR
and
DC&P,
management
recognizes that any controls and procedures, no matter
how well designed and operated, can provide only
reasonable assurance of achieving the desired control
objectives and as such may not prevent or detect all
misstatements and management is required to apply its
judgment in evaluating and implementing possible controls
and procedures. Further, the effectiveness of ICFR is
subject to the risk that controls may become inadequate
because of changes in conditions or that the degree of
compliance with policies or procedures may change.
In accordance with the provisions of NI 52-109 and
consistent with U.S. Securities and Exchange Commission
guidance, the scope of the evaluation did not include
internal controls over financial reporting of Heartland,
which the Company acquired on Dec. 4, 2024. Heartland
was excluded from management's evaluation of the
effectiveness of the Company's internal control over
financial reporting as at Dec. 31, 2024, due to the proximity
of the acquisition to year-end. Further details related to the
acquisition are disclosed in Note 4 to the Company's
Consolidated Financial Statements for the year ended Dec.
31, 2024. Included in the 2024 Consolidated Financial
Statements of TransAlta for Heartland are eight per cent
per cent and 20 per cent of the Company's total and net
assets, respectively, as at Dec. 31, 2024 and one per cent
and (5) per cent of the Company's revenues and net
earnings, respectively, for the year ended Dec. 31, 2024.
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, 2024, the end
of the period covered by this MD&A, our ICFR and DC&P
were effective.
TransAlta Corporation
2024 Integrated Report
M155
Consolidated Financial Statements
Management's Report
To the Shareholders of TransAlta Corporation
The Consolidated Financial Statements and other financial
information included in this annual report have been
prepared
by
management.
It
is
management’s
responsibility to ensure that sound judgment, appropriate
accounting principles and methods, and reasonable
estimates have been used to prepare this information.
They
also
ensure
that
all
information
presented
is consistent.
Management is also responsible for establishing and
maintaining internal controls and procedures over the
financial reporting process. The internal control system
includes an internal audit function and an established
business conduct policy that applies to all employees. In
addition,
TransAlta
Corporation
(TransAlta
or
the
Company) has a Corporate Code of Conduct that applies
to all employees and is signed annually and can be viewed
on
the
Company's
website
(www.transalta.com).
Management believes the system of internal controls,
review procedures and established policies provides
reasonable assurance as to the reliability and relevance of
financial
reports.
Management
also
believes
that
TransAlta’s operations are conducted in conformity with
the law and with a high standard of business conduct.
The Board of Directors (the Board) is responsible for
ensuring that management fulfils its responsibilities for
financial reporting and internal controls. The Board carries
out its responsibilities principally through its Audit, Finance
and Risk Committee (the Committee). The Committee,
which consists solely of independent directors, reviews
the
financial
statements
and
annual
report
and
recommends them to the Board for approval. The
Committee meets with management and internal and
external auditors to discuss internal controls, auditing
matters and financial reporting issues. Internal and
external auditors have full and unrestricted access to the
Committee. The Committee also recommends the firm of
external auditors to be appointed by shareholders.
John Kousinioris
Joel Hunter
President and Chief Executive Officer
Executive Vice President, Finance and
Chief Financial Officer
February 19, 2025
F1
TransAlta Corporation
2024 Integrated Report
Management’s Annual Report on Internal Control Over
Financial Reporting
To the Shareholders of TransAlta Corporation
The following report is provided by management in
respect of TransAlta Corporation’s (TransAlta or the
Company) internal control over financial reporting (as
defined in Rules 13a-15f and 15d-15f under the United
States Securities Exchange Act of 1934 and National
Instrument 52-109 Certification of Disclosure in Issuers'
Annual and Interim Filings (NI 51-109)).
TransAlta’s management is responsible for establishing
and maintaining adequate internal control over financial
reporting for the Company.
Management
uses
the
Committee
of
Sponsoring
Organizations of the Treadway Commission (COSO) 2013
framework to evaluate the effectiveness of TransAlta’s
internal control over financial reporting. Management
believes that the COSO 2013 framework is appropriate for
its evaluation of TransAlta’s internal control over financial
reporting because it is free from bias, permits reasonably
consistent qualitative and quantitative measurements of
internal controls, is sufficiently complete so any relevant
factors
that
would
alter
a
conclusion
about
the
effectiveness of the Company’s internal controls are not
omitted, and is relevant to an evaluation of internal control
over financial reporting.
Internal control over financial reporting cannot provide
absolute assurance of achieving financial reporting
objectives due to its inherent limitations. Internal control
over financial reporting are processes that involve human
diligence and compliance that are subject to lapses in
judgment and breakdowns resulting from human failures.
Internal control over financial reporting can also be
circumvented by collusion or improper overrides. As a
result of such limitations, there is a risk that material
misstatements may not be prevented or detected on a
timely basis. These inherent limitations are known features
of the financial reporting process and it is possible to
design safeguards into the process to reduce, though not
eliminate, this risk.
In accordance with the provisions of NI 52-109 and
consistent with U.S. Securities and Exchange Commission
guidance, the scope of the evaluation did not include
internal control over financial reporting of Heartland
Generation Ltd. and Alberta Power (2000) Ltd. (collectively
Heartland), which the Company acquired on Dec. 4, 2024.
Heartland was excluded from management's evaluation of
the effectiveness of the Company's internal control over
financial reporting as at Dec. 31, 2024, due to the
proximity of the acquisition to year-end. Further details
related to the acquisition are disclosed in Note 4 to the
Company's Consolidated Financial Statements for the year
ended Dec. 31, 2024. Included in the 2024 Consolidated
Financial Statements of TransAlta for Heartland are eight
per cent and 20 per cent of the Company's total and net
assets, respectively, as at Dec. 31, 2024 and one per cent
and (5) per cent of the Company's revenues and net
earnings, respectively, for the year ended Dec. 31, 2024.
TransAlta equity accounts for our investment in SP
Skookumchuck
Investment,
LLC
(Skookumchuck)
in
accordance
with
International
Financial
Reporting
Standards. Management does not have the contractual
ability to assess the internal controls of this equity
investment. Once the financial information is obtained
from Skookumchuck, it falls within the scope of TransAlta’s
internal controls framework. Management’s conclusion
regarding the effectiveness of internal controls does not
extend to the internal controls at the transactional level of
this associate.
Included in the 2024 Consolidated Financial Statements of
TransAlta for equity-accounted investments are one per
cent and six per cent of the Company's total and net
assets, respectively, as at Dec. 31, 2024, and zero per
cent and three per cent of the Company's revenues and
net earnings, respectively, for the year ended Dec. 31,
2024.
TransAlta Corporation
2024 Integrated Report
F2
Changes in Internal Control over Financial Reporting
The Company's internal controls over financial reporting
commencing Dec. 4, 2024, include controls designed to
result in the complete and accurate consolidation of
results attributable to Heartland. There has been no
change in the Company's internal control over financial
reporting that occurred during the year covered by this
Annual Report that has materially affected, or is
reasonably likely to materially affect, the Company's
internal control over financial reporting.
Management
has
assessed
the
effectiveness
of
TransAlta’s internal control over financial reporting as at
Dec. 31, 2024, and has concluded that such internal
control over financial reporting was effective.
Ernst & Young LLP, who has audited the Consolidated
Financial Statements of TransAlta for the year ended Dec.
31, 2024, has also issued a report on internal control over
financial
reporting
under
the
standards
of
the
Public Company Accounting Oversight Board. This report
is located on the following page of this Annual Report.
John Kousinioris
Joel Hunter
President and Chief Executive Officer
Executive Vice President, Finance and
Chief Financial Officer
February 19, 2025
F3
TransAlta Corporation
2024 Integrated Report
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of TransAlta Corporation
Opinion on Internal Control Over Financial Reporting
We have audited TransAlta Corporation’s internal control over financial reporting as of December 31, 2024, based on
criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (2013 framework) (the “COSO criteria”). In our opinion, TransAlta Corporation (the “Company”)
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on
the COSO criteria.
As indicated in the accompanying Management’s Annual Report on Internal Control over Financial Reporting,
management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not
include the internal controls of Heartland Generation Ltd. and Alberta Power (2000) Ltd. which are included in the 2024
consolidated financial statements of the Company and constituted 8% and 20% of total and net assets, respectively, as
of December 31, 2024, and 1% and (5)% of revenues and net earnings, respectively, for the year then ended, and the
equity accounted joint venture of SP Skookumchuck Investment, LLC which are included in the 2024 consolidated
financial statements of the Company and constituted 1% and 6% of total and net assets, respectively, as of December
31, 2024, and 0% and 3% of revenues and net earnings, respectively, for the year then ended. Our audit of internal
control over financial reporting of the Company also did not include an evaluation of the internal control over financial
reporting of Heartland Generation Ltd. and Alberta Power (2000) Ltd. and the equity accounted joint venture of SP
Skookumchuck Investment, LLC.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the consolidated statements of financial position of TransAlta Corporation as of December 31, 2024
and 2023, the related consolidated statements of earnings, comprehensive income (loss), changes in equity and cash
flows for each of the three years in the period ended December 31, 2024, and the related notes and our report dated
February 19, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s
Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s
internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that
our audit provides a reasonable basis for our opinion.
TransAlta Corporation
2024 Integrated Report
F4
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies
and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on
the consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
/s/Ernst & Young LLP
Chartered Professional Accountants
Calgary, Canada
February 19, 2025
F5
TransAlta Corporation
2024 Integrated Report
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of TransAlta Corporation
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated statements of financial position of TransAlta Corporation (the
“Company”) as of December 31, 2024 and 2023, the related consolidated statements of earnings, comprehensive
income (loss), changes in equity and cash flows, for each of the three years in the period ended December 31, 2024, and
the related notes (collectively referred to as the “consolidated financial statements“). In our opinion, the consolidated
financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2024
and 2023, and the financial performance and its cash flows for each of the three years in the period ended December 31,
2024, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards
Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria
established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission (“COSO”), and our report dated February 19, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company‘s management. Our responsibility is to
express an opinion on the Company‘s consolidated financial statements based on our audits. We are a public accounting
firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the
U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of
material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of
material misstatement of the consolidated financial statements, whether due to error or fraud, and performing
procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the
amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the
consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
TransAlta Corporation
2024 Integrated Report
F6
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial
statements that were communicated or required to be communicated to the audit committee and that: (1) relate to
accounts or disclosures that are material to the financial statements and (2) involved our especially challenging,
subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on
the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters
below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Acquisition of Heartland Generation
Description of
the Matter
As disclosed in notes 2(Q)(XV) and 4 of the consolidated financial statements, the Company completed the acquisition
of Heartland Generation Ltd. and Alberta Power (2000) Ltd. (collectively “Heartland”) for an aggregate purchase price
of $542 million. The acquisition has been accounted for as a business combination under IFRS 3 using the acquisition
method and the results of operations have been included in the consolidated financial statements since the date of
acquisition. The preliminary purchase price allocation is based on management’s best estimates of the assets acquired
and liabilities assumed. The fair values of the long-lived assets acquired as at the acquisition date of December 4, 2024
was $412 million.
Auditing the fair value of the long-lived assets as part of the preliminary purchase price allocation was identified as a
critical audit matter due to the significant estimation uncertainty and judgment applied by management in determining
those fair values, primarily due to the sensitivity of the significant assumptions to the future cash flows and the effect
that changes in these assumptions would have on the fair values. The estimates with a high degree of subjectivity
include market prices, capacity, and determining the appropriate discount rate.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding of management’s process for determining the fair value of long-lived assets acquired.
We evaluated the design and tested the operating effectiveness of controls over management’s review of the long-
lived assets acquired, including controls related to the review and approval of the significant estimates used in the
determination of the fair value of the long-lived assets. Our audit procedures to test the fair values for a sample of
facilities included, among others, comparing the significant assumptions used to estimate cash flows to current
contracts with external parties and historical trends and obtaining historical electricity generation data to evaluate
future electricity generation capacity forecasts. We evaluated the Company’s determination of future sales prices by
comparing them to externally available third-party future electricity price estimates. We also involved our internal
valuation specialist to assist in our evaluation of the discount rates, which involved benchmarking the inputs against
available market data.
Valuation of Long-Lived Assets related to certain cash generating units ("CGU"s) and Goodwill related to the Wind & Solar
segment
Description of
the Matter
As disclosed in notes 2(G), 2(H), 2(Q)(II), 7, and 22 of the consolidated financial statements, the Company owns
significant Wind & Solar generation assets and has recognized goodwill from historical acquisitions which must be
tested for impairment at least annually or when indicators of impairment are present. The carrying value of Goodwill
related to the Wind & Solar segment as at December 31, 2024 was $178 million and the recoverable amount of long-
lived assets in the Wind & Solar segment that had indicators of impairment or impairment reversal during the year was
$540 million.
Determining the recoverable amounts for the Wind & Solar segment for the purposes of the goodwill impairment test
and of certain CGUs in the Wind & Solar segment with indicators of impairment or impairment reversal (“Wind & Solar
CGUs”) for the asset impairment test was identified as a critical audit matter due to the significant estimation
uncertainty and judgment applied by management in determining the recoverable amount, primarily due to the
sensitivity of the significant assumptions to the future cash flows and the effect that changes in these assumptions
would have on the recoverable amount. The estimates with a high degree of subjectivity include electricity production,
sales prices, cost inputs, and determining the appropriate discount rate.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding of management’s process for estimating the recoverable amount of the Wind & Solar
segment and the Wind & Solar CGUs. We evaluated the design and tested the operating effectiveness of controls over
the Company’s processes to determine the recoverable amount. Our audit procedures to test the Company’s
recoverable amount of the Wind & Solar segment and the Wind & Solar CGUs with indicators of impairment or
impairment reversal included, among others, comparing the significant assumptions used to estimate cash flows to
current contracts with external parties and historical trends and obtaining historical electricity generation data to
evaluate future electricity production forecasts. We assessed the historical accuracy of management’s forecasts by
comparing them with actual results and performed a sensitivity analysis to evaluate the assumptions that were most
significant to the determination of the recoverable amount. We evaluated the Company’s determination of future sales
prices by comparing them to externally available third-party future electricity price estimates. We also involved our
internal valuation specialist to assist in our evaluation of the discount rates, which involved benchmarking the inputs
against available market data.
F7
TransAlta Corporation
2024 Integrated Report
Valuation of Level III Derivative Instruments
Description of
the Matter
As disclosed in notes 2(B), 2(Q)(V) and 14 of the consolidated financial statements, the Company enters into
transactions that are accounted for as derivative financial instruments and are recorded at fair value. The valuation of
derivative instruments classified as level III are determined using assumptions that are not readily observable. As at
December 31, 2024 the fair value of the Company’s derivative financial instruments classified as level III was a $153
million net risk management liability.
Auditing the determination of fair value of level III derivative instruments that rely on significant unobservable inputs
can be complex and relies on judgments and estimates concerning future prices, discount rates, credit value
adjustments, liquidity and delivery volumes, and can fluctuate significantly depending on market conditions. Therefore,
such determination of fair value was identified as a critical audit matter.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding of the Company’s processes and we evaluated and tested the design and operating
effectiveness of internal controls addressing the determination and review of inputs used in establishing level III fair
values. Our audit procedures included, among others, testing a sample of level III derivative instrument internal models
used by management and evaluating the significant assumptions utilized. We also compared management's future
pricing assumptions, credit value adjustments, and liquidity assumptions to third-party data as well as comparing terms
such as delivery volumes and timing to executed commodity contracts. We compared the delivery volume assumptions
to historical information. We performed a sensitivity analysis to evaluate assumptions including future commodity
prices, delivery volumes and discount rates. For a sample of level III derivative instruments, we involved our internal
valuation specialist to assist in our evaluation of the appropriateness of the fair value by evaluating the key
assumptions and methodologies.
/s/Ernst & Young LLP
Chartered Professional Accountants
We have served as auditors of TransAlta Corporation and its predecessor entities since 1947.
Calgary, Canada
February 19, 2025
TransAlta Corporation
2024 Integrated Report
F8
Consolidated Statements of Earnings
(in millions of Canadian dollars except where noted)
Year ended Dec. 31
2024
2023
2022
Revenues (Note 5)
2,845
3,355
2,976
Fuel and purchased power (Note 6)
939
1,060
1,263
Carbon compliance (Note 16)
112
112
78
Gross margin
1,794
2,183
1,635
Operations, maintenance and administration (Note 6)
655
539
521
Depreciation and amortization (Note 19, 20, 21 and 27)
531
621
599
Asset impairment charges (reversals) (Note 7)
46
(48)
9
Taxes, other than income taxes
36
29
33
Net other operating income (Note 8)
(59)
(47)
(58)
Operating income
585
1,089
531
Equity income (Note 9)
5
4
9
Finance lease income
14
12
19
Interest income
30
59
24
Interest expense (Note 10)
(324)
(281)
(286)
Foreign exchange gain (loss)
5
(7)
4
Gain on sale of assets and other
4
4
52
Earnings before income taxes
319
880
353
Income tax expense (Note 11)
80
84
192
Net earnings
239
796
161
Net earnings attributable to:
TransAlta shareholders
229
695
50
Non-controlling interests (Note 12)
10
101
111
239
796
161
Net earnings attributable to TransAlta shareholders
229
695
50
Preferred share dividends (Note 29)
52
51
46
Net earnings attributable to common shareholders
177
644
4
Weighted average number of common shares outstanding in the year
(millions)
302
276
271
Net earnings per share attributable to common shareholders, basic
and diluted (Note 28)
0.59
2.33
0.01
See accompanying notes.
F9
TransAlta Corporation
2024 Integrated Report
Consolidated Statements of Comprehensive Income (Loss)
(in millions of Canadian dollars)
Year ended Dec. 31
2024
2023
2022
Net earnings
239
796
161
Other comprehensive income (loss)
Net actuarial gains (losses) on defined benefit plans, net of tax(1)
9
(5)
37
Fair value loss on third-party investments, net of tax
—
—
(1)
Total items that will not be reclassified subsequently to net earnings
9
(5)
36
Gains (losses) on translating net assets of foreign operations, net of tax
30
(6)
21
(Losses) gains on financial instruments designated as hedges of foreign
operations, net of tax(2)
(28)
9
(25)
Gains (losses) on derivatives designated as cash flow hedges, net of tax(3)
213
41
(556)
Reclassification of (gains) losses on derivatives designated as cash flow
hedges to net earnings, net of tax(4)
(19)
58
100
Total items that will be reclassified subsequently to net earnings
196
102
(460)
Other comprehensive income (loss)
205
97
(424)
Total comprehensive income (loss)
444
893
(263)
Total comprehensive income (loss) attributable to:
TransAlta shareholders
434
817
(318)
Non-controlling interests (Note 12)
10
76
55
444
893
(263)
(1)
Net of income tax expense of $3 million for the year ended Dec. 31, 2024 (2023 — $1 million recovery, 2022 — $12 million expense).
(2) Net of income tax recovery of $4 million for the year ended Dec. 31, 2024 (2023 — $1 million expense, 2022 — $3 million recovery).
(3) Net of income tax expense of $57 million for the year ended Dec. 31, 2024 (2023 — $10 million expense, 2022 — $138 million recovery).
(4) Net of reclassification of income tax recovery of $4 million for the year ended Dec. 31, 2024 (2023 — $17 million expense, 2022 — $26 million
expense).
See accompanying notes.
TransAlta Corporation
2024 Integrated Report
F10
Consolidated Statements of Financial Position
(in millions of Canadian dollars)
As at Dec. 31
2024
2023
Current assets
Cash and cash equivalents
337
348
Restricted cash (Note 25)
69
69
Trade and other receivables (Note 13)
767
807
Prepaid expenses and other
68
48
Risk management assets (Note 14 and 15)
318
151
Inventory (Note 16)
134
157
Assets held for sale (Note 4 and 18)
80
—
1,773
1,580
Non-current assets
Investments (Note 9)
159
138
Long-term portion of finance lease receivables (Note 17)
305
171
Risk management assets (Note 14 and 15)
93
52
Property, plant and equipment (Note 19)
6,020
5,714
Right-of-use assets (Note 20)
120
117
Intangible assets (Note 21)
281
223
Goodwill (Note 22)
517
464
Deferred income tax assets (Note 11)
52
21
Other assets (Note 23)
179
179
Total assets
9,499
8,659
Current liabilities
Bank overdraft
1
3
Accounts payable, accrued liabilities and other current liabilities (Note 13)
756
809
Current portion of decommissioning and other provisions (Note 24)
83
35
Risk management liabilities (Note 14 and 15)
277
314
Dividends payable (Note 28 and 29)
49
49
Exchangeable securities (Note 3 and 26)
750
—
Contingent consideration payable (Note 4)
81
—
Current portion of long-term debt and lease liabilities (Note 25)
572
532
2,569
1,742
Non-current liabilities
Credit facilities, long-term debt and lease liabilities (Note 25)
3,236
2,934
Exchangeable securities (Note 3 and 26)
—
744
Decommissioning and other provisions (Note 24)
850
654
Deferred income tax liabilities (Note 11)
470
386
Risk management liabilities (Note 14 and 15)
305
274
Contract liabilities (Note 5)
24
10
Defined benefit obligation and other long-term liabilities (Note 27)
202
251
Equity
Common shares (Note 28)
3,179
3,285
Preferred shares (Note 29)
942
942
Contributed surplus
42
41
Deficit
(2,458)
(2,567)
Accumulated other comprehensive income (loss) (Note 30)
41
(164)
Equity attributable to shareholders
1,746
1,537
Non-controlling interests (Note 12)
97
127
Total equity
1,843
1,664
Total liabilities and equity
9,499
8,659
Commitments and contingencies (Note 37)
See accompanying notes.
On behalf of the Board:
John P. Dielwart
Director
Thomas M. O'Flynn
Chair of Audit, Finance and Risk Committee
F11
TransAlta Corporation
2024 Integrated Report
Consolidated Statements of Changes in Equity
(in millions of Canadian dollars)
Common
shares
Preferred
shares
Contributed
surplus
Deficit
Accumulated other
comprehensive
income (loss)(1)
Attributable to
shareholders
Attributable
to non-
controlling
interests
Total
Balance, Dec. 31, 2022
2,863
942
41 (2,514)
(222)
1,110
879 1,989
Net earnings
—
—
—
695
—
695
101
796
Other comprehensive income (loss):
Net gains on translating net assets of foreign
operations, net of hedges and of tax
—
—
—
—
3
3
—
3
Net gains on derivatives designated as cash flow
hedges, net of tax
—
—
—
—
99
99
—
99
Net actuarial losses on defined benefits plans, net
of tax
—
—
—
—
(5)
(5)
—
(5)
Intercompany and third-party FVTOCI investments
—
—
—
—
25
25
(25)
—
Total comprehensive income
—
—
—
695
122
817
76
893
Common share dividends (Note 28)
—
—
—
(65)
—
(65)
—
(65)
Preferred share dividends (Note 29)
—
—
—
(51)
—
(51)
—
(51)
Shares purchased under normal course issuer bid
(NCIB) (Note 28)
(80)
—
—
(7)
—
(87)
—
(87)
Changes in non-controlling interests in TransAlta
Renewables (Note 4)
510
—
—
(625)
(64)
(179)
(630) (809)
Provision for repurchase of shares under the
automatic share purchase plan (Note 28)
(19)
—
—
—
—
(19)
—
(19)
Share-based payment plans and stock options
exercised (Note 31)
11
—
—
—
—
11
—
11
Distributions declared to non-controlling interests
(Note 12)
—
—
—
—
—
—
(198) (198)
Balance, Dec. 31, 2023
3,285
942
41 (2,567)
(164)
1,537
127 1,664
Net earnings
—
—
—
229
—
229
10
239
Other comprehensive income:
Net gains on translating net assets of foreign
operations, net of hedges and tax
—
—
—
—
2
2
—
2
Net gains on derivatives designated as cash flow
hedges, net of tax
—
—
—
—
194
194
—
194
Net actuarial gains on defined benefits plans, net
of tax
—
—
—
—
9
9
—
9
Total comprehensive income
—
—
—
229
205
434
10 444
Common share dividends (Note 28)
—
—
—
(71)
—
(71)
—
(71)
Preferred share dividends (Note 29)
—
—
—
(52)
—
(52)
—
(52)
Shares purchased NCIB (Note 28)
(146)
—
—
3
—
(143)
— (143)
Reversal of provision for repurchase of shares under
the automatic share purchase plan (Note 28)
19
—
—
—
—
19
—
19
Share-based payment plans and stock options
exercised (Note 31)
21
—
1
—
—
22
—
22
Distributions declared to non-controlling interests
(Note 12)
—
—
—
—
—
—
(40)
(40)
Balance, Dec. 31, 2024
3,179
942
42 (2,458)
41
1,746
97 1,843
(1)
Refer to Note 30 for details on components of and changes in, accumulated other comprehensive income (loss).
See accompanying notes.
TransAlta Corporation
2024 Integrated Report
F12
Consolidated Statements of Cash Flows
(in millions of Canadian dollars)
Year ended Dec. 31
2024
2023
2022
Operating activities
Net earnings
239
796
161
Depreciation and amortization (Note 19, 20, 21 and 27)
531
621
599
Gain on sale of assets and other
(1)
(3)
(32)
Accretion of provisions (Note 10 and 24)
50
48
49
Decommissioning and restoration costs settled (Note 24)
(41)
(37)
(35)
Deferred income tax (recovery) expense (Note 11)
(63)
34
127
Unrealized loss (gain) from risk management activities
2
(36)
385
Unrealized foreign exchange gain
(29)
(9)
(82)
Provisions and contract liabilities
23
(1)
19
Asset impairment charges (reversals) (Note 7)
46
(48)
9
Equity loss (income), net of distributions from investments (Note 9)
—
2
(4)
Other non-cash items
1
(27)
(3)
Cash flow from operations before changes in working capital
758
1,340
1,193
Change in non-cash operating working capital balances (Note 34)
38
124
(316)
Cash flow from operating activities
796
1,464
877
Investing activities
Additions to property, plant and equipment (Note 4, 19 and 38)
(311)
(875)
(918)
Additions to intangible assets (Note 21 and 38)
(10)
(13)
(31)
Restricted cash (Note 25)
(1)
1
—
(Advances) repayment from loan receivable (Note 23)
(1)
11
18
Acquisitions, net of cash acquired (Note 4)
(217)
—
(10)
Investments (Note 9)
(5)
(13)
(10)
Proceeds on sale of property, plant and equipment
4
29
66
Realized gain on financial instruments
1
18
27
Decrease in finance lease receivable
21
55
46
Other
19
(25)
45
Change in non-cash investing working capital balances
(20)
(2)
26
Cash flow used in investing activities
(520)
(814)
(741)
Financing activities
Net increase (decrease) in borrowings under credit facilities (Note 25 and 34)
143
(46)
449
Repayment of long-term debt (Note 25 and 34)
(131)
(164)
(621)
Issuance of long-term debt (Note 25 and 34)
—
39
532
Dividends paid on common shares (Note 28)
(71)
(58)
(54)
Dividends paid on preferred shares (Note 29)
(52)
(51)
(43)
Repurchase of common shares under NCIB (Note 28)
(143)
(87)
(52)
Proceeds on issuance of common shares
12
5
3
Realized gain (loss) on financial instruments
4
(30)
42
Acquisition of TransAlta Renewables (Note 4)
—
(811)
—
Distributions paid to subsidiaries' non-controlling interests (Note 12)
(40)
(223)
(187)
Decrease in lease liabilities (Note 25 and 34)
(6)
(10)
(9)
Financing fees and other
(1)
1
(13)
Change in non-cash financing working capital balances
(6)
3
(2)
Cash flow (used in) from financing activities
(291)
(1,432)
45
Cash flow (used in) from operating, investing and financing activities
(15)
(782)
181
Effect of translation on foreign currency cash
4
(4)
6
(Decrease) increase in cash and cash equivalents
(11)
(786)
187
Cash and cash equivalents, beginning of year
348
1,134
947
Cash and cash equivalents, end of year
337
348
1,134
Cash taxes paid
104
94
67
Cash interest paid
269
277
229
Cash interest received
30
54
20
See accompanying notes.
F13
TransAlta Corporation
2024 Integrated Report
Notes to the Consolidated
Financial Statements
(Tabular amounts in millions of Canadian dollars, except as otherwise noted)
1. Corporate Information
A. Description of the Business
TransAlta Corporation (TransAlta or the Company) was
incorporated under the Canada Business Corporations Act
in March 1985 and became a public company in
December 1992. The Company's head office is located in
Calgary, Alberta.
Operating Segments
Generation Segments
The Company is comprised of four generation segments:
Hydro, Wind and Solar, Gas, and Energy Transition. The
Company directly or indirectly owns and operates hydro,
wind and solar and, natural gas-fired facilities, along with a
coal-fired facility and natural gas pipeline operations in
Canada, the United States (U.S.) and Western Australia.
Transmission in Canada and Western Australia is included
within the Hydro and Gas segments in Canada and
Western Australia, respectively. The Wind and Solar
segment includes the financial results, on a proportionate
basis, of our investment in SP Skookumchuck Investment,
LLC (Skookumchuck). Segment revenues are derived from
the availability and production of electricity and steam as
well as ancillary services.
Energy Marketing Segment
The Energy Marketing segment derives revenue and
earnings from the trading of electricity, natural gas and
environmental products across a variety of North
American markets, excluding Alberta.
The Energy Marketing segment also performs services on
behalf of certain assets outside of Alberta for the
marketing of available generating capacity as well as the
procurement of the fuel and transmission needs for the
fleet. Contracts of various durations for the forward sales
of electricity and for the purchase of natural gas and
transmission capacity are utilized. The results of these
activities are included in the gross margin of the related
generation segment. The Energy Marketing segment
allocates charges to recognize the performance of these
activities to the applicable generation segments.
Corporate Segment
The Corporate segment includes the Company’s central
finance, legal, administrative, corporate development, and
investor relations functions. Activities and charges directly
or
reasonably
attributable
to
other
segments
are
allocated to it.
B. Basis of Preparation
These Consolidated Financial Statements have been
prepared by management in compliance with International
Financial Reporting Standards (IFRS) as issued by the
International Accounting Standards Board (IASB).
The
Consolidated
Financial
Statements
have
been
prepared on a historical cost basis except for financial
instruments, which are measured at fair value, as
explained in the following accounting policies.
These Consolidated Financial Statements were authorized
for issue by TransAlta's Board of Directors (the Board) on
Feb. 19, 2025.
C. Basis of Consolidation
The Consolidated Financial Statements include the
accounts of the Company and the subsidiaries that it
controls. Control exists when the Company is exposed, or
has rights, to variable returns from its involvement with the
subsidiary and has the ability to affect the returns through
its power over the subsidiary. The financial statements of
the subsidiaries are prepared for the same reporting
period and apply consistent accounting policies as the
parent company.
TransAlta Corporation
2024 Integrated Report
F14
2. Material Accounting Policies
The Company has reviewed its material accounting
policies. The definition of material that management has
used to judgmentally determine disclosure is that
information is deemed material if omitting or misstating it
could influence decisions users make on the basis of
financial information.
A. Revenue Recognition
I. Revenue from Contracts with Customers
The majority of the Company’s revenues from contracts
with customers are derived from the sale of generation
capacity,
electricity,
thermal
energy,
environmental
attributes and byproducts of power generation. The
Company evaluates whether the contracts it enters into
meet the definition of a contract with a customer at the
inception of the contract and on an ongoing basis if there
is an indication of significant changes in facts and
circumstances. Contract modifications are accounted for
as separate contracts when the consideration for the
additional promised goods reflects a stand-alone selling
price. Otherwise, contract modifications are accounted for
as part of the existing contract. If the additional goods are
not considered distinct the transaction price can be
affected and adjustments to previously recognized
revenue can occur. If the additional goods are distinct, the
existing and modified contracts are treated together as a
new contract, with impacts reflected prospectively from
the modification date, which can include the blending of
contract prices. Revenue is measured based on the
transaction price specified in a contract with a customer.
Revenue is recognized when the control of the goods or
services is transferred to the customer. For certain
contracts, revenue may be recognized at the invoiced
amount,
as
permitted
using
the
invoice
practical
expedient, if such amount corresponds directly with the
Company’s performance to date. The Company excludes
amounts collected on behalf of third parties from revenue.
Performance Obligations
Each promised good or service is accounted for
separately as a performance obligation if it is distinct.
The Company’s contracts may contain more than one
performance obligation.
Transaction Price
The Company allocates the transaction price in the
contract to each performance obligation. The transaction
price allocated to performance obligations may include
variable consideration. Variable consideration is included
in the transaction price for each performance obligation
when it is highly probable that a significant reversal of the
cumulative variable revenue will not occur. Variable
consideration that has previously been constrained is
assessed at each reporting period to determine whether
the constraint is lifted. The consideration contained in
some of the Company's contracts with customers is
primarily variable and may include both variability in
quantity and pricing, such as: revenues can be dependent
upon future production volumes that are driven by
customer or market demand or by the operational ability of
a plant; revenues can be dependent upon the variable cost
of producing energy; revenues can be dependent upon
market prices; and revenues can be subject to various
indices and escalators.
When multiple performance obligations are present in a
contract, the transaction price is allocated to each
performance obligation in an amount that depicts the
consideration the Company expects to be entitled to in
exchange for transferring the good or service. The
Company estimates the amount of the transaction price to
allocate to individual performance obligations based on
their relative stand-alone selling prices, which is primarily
estimated based on the amounts that would be charged to
customers under similar market conditions.
F15
TransAlta Corporation
2024 Integrated Report
Recognition
The nature, timing of recognition of satisfied performance obligations and payment terms for the Company’s goods and
services are described below:
Good or service
Description
Capacity
Capacity refers to the availability of an asset to deliver goods or services. Customers typically
pay for capacity for each defined time period (e.g., monthly) in an amount representative of the
availability of the asset for the defined time period. Obligations to deliver capacity are satisfied
over time and revenue is recognized using a time-based measure. Contracts for capacity are
typically long-term in nature and payments are typically received on a monthly basis.
Contract power
The sale of contract power refers to the delivery of units of electricity to a customer under the
terms of a contract. Customers pay a contractually specified price for the output at the end of
predefined contractual periods (e.g., monthly). Obligations to deliver electricity are satisfied
over time and revenue is recognized using a units-based output measure (i.e., megawatt
hours). Contracts for power are typically long-term in nature and payments are typically
received on a monthly basis.
Thermal energy
Thermal energy refers to the delivery of units of steam to a customer under the terms of a
contract. Customers pay a contractually specified price for the output at the end of predefined
contractual periods (e.g., monthly). Obligations to deliver steam are satisfied over time and
revenue is recognized using a units-based output measure (i.e., gigajoules). Contracts for
thermal energy are typically long-term in nature and payments are typically received on a
monthly basis.
Environmental
attributes
Environmental attributes refers to the delivery of renewable energy certificates, green
attributes and other similar items. Customers may contract for environmental attributes in
conjunction with the purchase of power, in which case the customer pays for the attributes in
the month subsequent to the delivery of the power. Alternatively, customers pay upon delivery
of the environmental attributes. Obligations to deliver environmental attributes are satisfied at
a point in time, generally upon delivery of the item.
Generation
byproducts
Generation byproducts refers to the sale of byproducts from the use of coal in the Company’s
current U.S. and previous Canadian coal operations. Obligations to deliver byproducts are
satisfied at a point in time, generally upon delivery of the item. Payments are received upon
satisfaction of delivery of the byproducts.
A contract liability is recorded when the Company receives
consideration before the performance obligations have
been satisfied. A contract asset is recorded when the
Company has rights to consideration for the completion of
a performance obligation before it has invoiced the
customer. The Company recognizes unconditional rights
to consideration separately as a receivable. Contract
assets and receivables are evaluated at each reporting
period to determine whether there is any objective
evidence that they are impaired.
II. Revenue from Other Sources
Merchant Revenue
Revenues from non-contracted capacity (i.e., merchant)
include energy payments, at market price, for each MWh
produced and are recognized upon delivery.
Lease Revenue
In certain situations, a long-term electricity or thermal
sales contract may contain, or be considered, a lease.
Revenues
associated
with
non-lease
elements
are
recognized as goods or services revenues as outlined
above. Where the terms and conditions of the contract
result in the customer assuming the principal risks and
rewards of ownership of the underlying asset, the
contractual arrangement is considered a finance lease,
which results in the recognition of finance lease income.
Where the Company retains the principal risks and
rewards, the contractual arrangement is an operating
lease. Rental income, including contingent rents where
applicable, is recognized over the term of the contract.
TransAlta Corporation
2024 Integrated Report
F16
Revenue from Derivatives
Commodity risk management activities involve the use of
derivatives such as physical and financial swaps, forward
sales contracts, futures contracts and options, which are
used to earn revenues and gain market information. The
Company also enters into contracts for differences and
Virtual Power Purchase Agreements (VPPA). Contracts for
differences are financial contracts whereby the Company
receives a fixed price per MWh and pays the prevailing
real-time energy market price per MWh. With a VPPA, the
Company receives the difference between the fixed
contract price per MWh and the settled market price.
These arrangements meet the definition of a derivative
and judgment is applied to determine if the contract meets
the "own use" exemption or if derivative treatment
is required.
These derivatives are accounted for using fair value
accounting. The initial recognition and subsequent
changes in fair value affect reported net earnings in the
period the change occurs and are presented on a net
basis in revenue. The fair values of instruments that
remain open at the end of the reporting period represent
unrealized gains or losses and are presented on the
Consolidated Statements of Financial Position as risk
management assets or liabilities. Some of the derivatives
used by the Company in trading activities are not traded
on an active exchange or have terms that extend beyond
the time period for which exchange-based quotes are
available. The fair values of these derivatives are
determined using internal valuation techniques or models.
B. Financial Instruments and Hedges
I. Financial Instruments
Classification and Measurement
IFRS 9 introduced the requirement to classify and measure
financial assets based on their contractual cash flow
characteristics and the Company’s business model for the
financial asset. All financial assets and liabilities, including
derivatives,
are
recognized
at
fair
value
on
the
Consolidated Statements of Financial Position when the
Company becomes party to the contractual provisions of a
financial instrument or non-financial derivative contract.
Financial assets must be classified and measured at either
amortized cost, at fair value through profit or loss (FVTPL),
or at fair value through other comprehensive income (loss)
(FVTOCI).
Financial assets with contractual cash flows arising on
specified dates, consisting solely of principal and interest,
and that are held within a business model whose objective
is to collect the contractual cash flows, are subsequently
measured at amortized cost. Financial assets measured at
FVTOCI are those that have contractual cash flows, arising
on specific dates, consisting solely of principal and
interest, and that are held within a business model whose
objective is to collect the contractual cash flows and to
sell the financial asset and investments in equity
instruments. All other financial assets are subsequently
measured at FVTPL.
Financial liabilities are classified as FVTPL when the
financial liability is held for trading. All other financial
liabilities are subsequently measured at amortized cost.
Funds received under tax equity investment arrangements
are classified as long-term debt. These arrangements are
used in the U.S. where project investors acquire an equity
investment in a project entity, and in return for their
investment, are allocated substantially all of the earnings,
cash flows and tax benefits (such as production tax
credits,
investment
tax
credits,
accelerated
tax
depreciation, as applicable) until they have achieved the
agreed upon target rate of return. Once achieved, the
arrangements flip, with the Company then receiving the
majority of earnings, cash flows and tax benefits. At that
time, the tax equity investor's investment is subsequently
considered residual equity ownership, with distributions
classified as non-controlling interest. In applying the
effective interest method to tax equity financings, the
Company has made an accounting policy choice to
recognize the impacts of the tax attributes in net
interest expense.
The Company enters into a variety of derivative financial
instruments to manage its exposure to commodity price
risk, interest rate risk and foreign currency exchange risk,
including fixed price financial swaps, long-term physical
power sale contracts, foreign exchange forward contracts,
interest rate swap contracts, and designating foreign
currency debt as a hedge of net investments in foreign
operations.
Derivatives are initially recognized at fair value at the date
the derivative contracts are entered into and are
subsequently remeasured to their fair value at the end of
each reporting period. The resulting gain or loss is
recognized in net earnings immediately, unless the
derivative is designated and effective as a hedging
instrument, in which case the timing of the recognition in
net earnings is dependent on the nature of the
hedging relationship.
Derivatives embedded in non-derivative host contracts
that are not financial assets within the scope of IFRS 9
(e.g.,
financial
liabilities)
are
treated
as
separate
derivatives when they meet the definition of a derivative,
their risks and characteristics are not closely related to
those of the host contracts and the host contracts are not
measured at FVTPL. Derivatives embedded in hybrid
contracts that contain financial asset hosts within the
scope of IFRS 9 are not separated, and the entire contract
is measured at either FVTPL or amortized cost, as
appropriate.
Financial assets are derecognized when the contractual
rights to receive cash flows expire. Financial liabilities are
F17
TransAlta Corporation
2024 Integrated Report
derecognized when the obligation is discharged, cancelled
or expired.
Financial assets are also derecognized when the Company
has transferred its rights to receive cash flows from the
asset or has assumed an obligation to pay the received
cash flows to a third party under a "pass-through"
arrangement and either transferred substantially all the
risks and rewards of the asset, or transferred control of
the asset. TransAlta will continue to recognize the asset
and any associated liability if it retains substantially all of
the risks and rewards of the asset, or retains control of the
asset. Continuing involvement that takes the form of a
guarantee over the transferred asset is measured at the
lower of the original carrying amount of the asset and the
maximum amount of consideration that TransAlta could be
required to repay.
Financial assets and liabilities are offset and the net
amount is reported in the Consolidated Statements of
Financial Position if there is a currently enforceable legal
right to offset the recognized amounts and there is an
intention to settle on a net basis or realize the assets and
settle the liabilities simultaneously.
Transaction costs are expensed as incurred for financial
instruments classified or designated as FVTPL. For other
financial
instruments,
such
as
debt
instruments,
transaction costs are recognized as part of the carrying
amount of the financial instrument. The Company uses the
effective
interest
method
of
amortization
for
any
transaction costs or fees, premiums or discounts earned or
incurred
for
financial
instruments
measured
at
amortized cost.
Impairment of Financial Assets
TransAlta recognizes an allowance for expected credit
losses for financial assets measured at amortized cost as
well as certain other instruments. The loss allowance for a
financial asset is measured at an amount equal to the
lifetime expected credit loss if its credit risk has increased
significantly since initial recognition or if the financial asset
is a purchased or originated credit-impaired financial
asset. If the credit risk on a financial asset has not
increased significantly since initial recognition, its loss
allowance is measured at an amount equal to the 12-
month expected credit loss.
For trade receivables, lease receivables and contract
assets recognized under IFRS 15, TransAlta applies a
simplified approach for measuring the loss allowance.
Therefore, the Company does not track changes in credit
risk but instead recognizes a loss allowance at an amount
equal to the lifetime expected credit losses at each
reporting date.
The assessment of the expected credit loss is based on
historical
data
and
adjusted
by
forward-looking
information that includes third-party default rates over
time, dependent on credit ratings.
II. Hedges
Where hedge accounting can be applied and the Company
chooses to seek hedge accounting treatment, a hedge
relationship is designated as a fair value hedge, a cash
flow hedge or a hedge of foreign currency exposures of a
net investment in a foreign operation.
A relationship qualifies for hedge accounting if, at
inception, it is formally designated and documented as a
hedge and the hedging instrument and the hedged item
have values that generally move in opposite direction
because of the hedged risk. The documentation includes
identification of the hedging instrument and hedged item
or transaction, the nature of the risk being hedged, the
Company’s risk management objectives and strategy for
undertaking the hedge and how hedge effectiveness will
be assessed. The process of hedge accounting includes
linking derivatives to specific recognized assets and
liabilities or to specific firm commitments or highly
probable anticipated transactions.
The Company formally assesses, both at the hedge’s
inception and on an ongoing basis, whether the
derivatives used are highly effective in offsetting changes
in fair values or cash flows of hedged items. If hedge
criteria are not met or the Company does not apply hedge
accounting, the derivative is recognized at fair value on
the Consolidated Statements of Financial Position, with
subsequent changes in fair value recorded in net earnings
in the period of change.
Fair Value Hedges
In a fair value hedging relationship, the carrying amount of
the hedged item is adjusted for changes in fair value
attributable to the hedged risk, with the changes being
recognized in net earnings. Changes in the fair value of
the hedged item, to the extent that the hedging
relationship is effective, are offset by changes in the fair
value of the hedging derivative, which is also recorded in
net earnings.
For fair value hedges relating to items carried at amortized
cost, any adjustment to carrying value is amortized
through profit or loss over the remaining term of the hedge
using the effective interest rate (EIR) method. The EIR
amortization may begin as soon as an adjustment exists
and no later than when the hedged item ceases to be
adjusted for changes in its fair value attributable to the risk
being hedged.
If the hedged item is derecognized, the unamortized fair
value is recognized immediately in net earnings.
Cash Flow Hedges
In a cash flow hedging relationship, the effective portion of
the change in the fair value of the hedging derivative is
recognized in other comprehensive income (loss) (OCI)
while any ineffective portion is recognized in net earnings.
The cash flow hedge reserve is adjusted to the lower of
TransAlta Corporation
2024 Integrated Report
F18
the cumulative gain or loss on the hedging instrument and
the cumulative change in fair value of the hedged item.
If cash flow hedge accounting is discontinued, the
amounts previously recognized in accumulated other
comprehensive income (loss) (AOCI) must remain in AOCI
if the hedged future cash flows are still expected to occur.
Otherwise, the amount will be immediately reclassified to
net earnings as a reclassification adjustment. After
discontinuation, once the hedged cash flow occurs, any
amount remaining in AOCI must be accounted for
depending on the nature of the underlying transaction.
Hedges of Foreign Currency Exposures of a Net
Investment in a Foreign Operation
When hedging the foreign currency exposure of a net
investment in a foreign operation, the effective portion of
foreign exchange gains and losses on the hedging
instrument is recognized in OCI and the ineffective portion
is recognized in net earnings. The related fair values are
recorded in risk management assets or liabilities, as
appropriate. The amounts previously recognized in AOCI
are recognized in net earnings when there is a reduction in
the hedged net investment as a result of a disposal, partial
disposal or loss of control.
C. Cash and Cash Equivalents
Cash and cash equivalents comprises cash and highly
liquid investments with original maturities of three months
or less.
D. Inventory
I. Fuel
The Company’s inventory balance is composed of coal and
natural gas used as fuel, which is measured at the lower of
weighted average cost and net realizable value. The cost
of natural gas and purchased coal inventory includes all
applicable expenditures and charges incurred in bringing
the inventory to its existing condition and location.
II. Energy Marketing
Commodity inventories held in the Energy Marketing
segment for trading purposes are measured at fair value
less costs to sell. Changes in fair value less costs to sell
are recognized in net earnings in the period of change.
III. Parts, Materials and Supplies
Parts, materials and supplies are recorded at the lower of
cost and measured at moving average costs and net
realizable value.
IV. Emission Credits and Allowances
Emission credits and allowances are recorded as inventory
at cost. Those purchased for use by the Company are
recorded at cost and are carried at the lower of weighted
average cost and net realizable value. For emission credits
that are not ordinarily interchangeable, the Company
records the credits using the specific identification
method. Credits granted to or internally generated by,
TransAlta are recorded at nil. Emission liabilities are
recorded at the estimated compliance cost required by the
Company to settle its obligation in excess of government-
established caps and targets. Compliance costs that are
recoverable under the terms of the contracts with third
parties are recognized as revenue from contracts
with customers.
Emission credits and allowances that are held for trading
and that meet the definition of a derivative are accounted
for using the fair value method of accounting. Emission
credits and allowances that do not satisfy the criteria of a
derivative are accounted for using the accrual method.
E. Property, Plant and Equipment
The Company’s investment in property, plant and
equipment (PP&E) is initially measured at the original cost
of each component at the time of construction, purchase
or acquisition. A component is a tangible portion of an
asset that can be separately identified and depreciated
over its own expected useful life and is expected to
provide a benefit for a period in excess of one year.
Original cost includes items such as materials, labour,
borrowing costs and other directly attributable costs,
including
the
initial
estimate
of
the
cost
of
decommissioning and restoration. Costs are recognized as
PP&E if it is probable that future economic benefits will be
realized and the cost of the item can be measured reliably.
The cost of major spare parts is capitalized and classified
as PP&E, as these items can only be used in connection
with an item of PP&E.
Planned maintenance is performed at regular intervals.
Planned major maintenance includes inspection, repair and
maintenance of existing components and the replacement
of existing components. Costs incurred for planned major
maintenance activities are capitalized in the period
maintenance activities occur and are amortized on a
straight-line basis over the term until the next major
maintenance
event.
Expenditures
incurred
for
the
replacement of components during major maintenance are
capitalized and amortized over the estimated useful life of
such components.
The cost of routine repairs and maintenance and the
replacement of minor parts is charged to net earnings as
incurred.
Subsequent
to
initial
recognition
and
measurement at cost, all classes of PP&E continue to be
measured using the cost model and are reported at cost
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TransAlta Corporation
2024 Integrated Report
less accumulated depreciation and impairment losses,
if any. An item of PP&E or a component is derecognized
upon disposal or when no future economic benefits are
expected from its use or disposal. Any gain or loss arising
on derecognition is included in net earnings when the
asset is derecognized. The estimate of the useful life of
each component of PP&E is based on current facts and
past experience and takes into consideration existing
long-term sales agreements and contracts, current and
forecasted demand and the potential for technological
obsolescence. The useful life is used to estimate the rate
at which the component of PP&E is depreciated. PP&E
assets are subject to depreciation when the asset is
considered to be available for use, which is typically at the
start of commercial operations. Insurance spares that are
designated as critical for uninterrupted operation in a
particular facility are depreciated over the life of that
facility, even if the item is not in service. Capital spares
begin to be depreciated when the item is put into service.
Each significant component of an item of PP&E is
depreciated to its residual value over its estimated useful
life, generally using straight-line or unit-of-production
methods. Estimated useful lives, residual values and
depreciation methods are reviewed annually and are
subject to revision based on new or additional information.
The effect of a change in useful life, residual value or
depreciation method is accounted for prospectively.
Estimated remaining useful lives of the components of
depreciable assets, categorized by asset class, are
as follows:
Hydro generation
1-48 years
Wind and Solar generation
1-30 years
Gas generation
1-33 years
Energy Transition
1-9 years
Capital spares and other
1-48 years
TransAlta capitalizes borrowing costs on capital invested
in projects under construction. Upon commencement of
commercial operations, capitalized borrowing costs, as a
portion of the total cost of the asset, are depreciated over
the estimated useful life of the related asset.
F. Intangible Assets
Intangible assets acquired in a business combination are
recognized separately from goodwill at their fair value at
the date of acquisition. Intangible assets acquired
separately are recognized at cost. Internally generated
intangible assets arising from development projects are
recognized when certain criteria related to the feasibility
of internal use or sale and probable future economic
benefits of the intangible asset, are demonstrated.
Intangible assets are initially recognized at cost, which is
composed of all directly attributable costs necessary to
create, produce and prepare the intangible asset to be
capable
of
operating
in
the
manner
intended
by management.
Software-as-a-service, such as cloud based software, that
do not meet the criteria of an intangible asset are
expensed as incurred, including implementation costs.
Subsequent
to
initial
recognition,
intangible
assets
continue to be measured using the cost model and are
reported at cost less accumulated amortization and
impairment losses, if any. Amortization is included in
depreciation
and
amortization
in
the
Consolidated
Statements of Earnings.
Amortization commences when the intangible asset is
available for use and is computed on a straight-line basis
over the intangible asset’s estimated useful life. Estimated
useful lives of intangible assets may be determined, for
example, with reference to the term of the related contract
or licence agreement. The estimated useful lives and
amortization methods are reviewed annually with the
effect of any changes being accounted for prospectively.
Intangible assets consist of power sale contracts with
fixed prices higher than market prices at the date of
acquisition, software and intangibles under development.
Estimated remaining useful lives of intangible assets are as
follows:
Software
1-7 years
Power sale contracts
1-17 years
G. Impairment of Tangible and Intangible
Assets Excluding Goodwill
At the end of each reporting period, the Company
assesses whether there is any indication that PP&E and
finite life intangible assets are impaired.
Factors that could indicate that an impairment exists
include: significant underperformance relative to historical
or projected operating results; significant changes in the
manner in which an asset is used, or in the Company’s
overall business strategy; or significant negative industry
or economic trends. In some cases, these events are clear.
However, in many cases, a clearly identifiable event
indicating possible impairment does not occur. Instead, a
series of individually insignificant events occur over a
period of time leading to an indication that an asset may
be impaired. This can be further complicated in situations
where the Company is not the operator of the facility.
Events can occur in these situations that may not be
known until a date subsequent to their occurrence.
The Company’s operations, the market and business
environment are routinely monitored and judgments and
assessments are made to determine whether an event has
occurred that indicates a possible impairment. If such an
event has occurred, an estimate is made of the
recoverable amount of the asset or cash-generating unit
TransAlta Corporation
2024 Integrated Report
F20
(CGU) to which the asset belongs. The recoverable
amount is the higher of an asset’s fair value less costs of
disposal and its value in use. Fair value is the price that
would be received if the asset was sold in an orderly
transaction
between
market
participants
at
the
measurement date. In determining
fair
value,
recent
market
transactions
are taken into account. If no such
transactions can be identified, an appropriate valuation
model such as discounted cash flow is used. Value in use
is the present value of the estimated future cash flows
expected to be derived from the asset from its continued
use and ultimate disposal by the Company. If the
recoverable amount is less than the carrying amount of
the asset or CGU, an asset impairment charge is
recognized in net earnings and the asset’s carrying
amount is reduced to its recoverable amount.
At each reporting date, an assessment is made whether
there is any indication that an impairment charge
previously recognized may no longer exist or may have
decreased. If such indication exists, the recoverable
amount of the asset or CGU to which the asset belongs is
estimated and, if there has been an increase in the
recoverable amount, the impairment charge previously
recognized is reversed. If an impairment charge is
subsequently reversed, the carrying amount of the asset is
increased to the lesser of the revised estimate of its
recoverable amount or the carrying amount that would
have been determined (net of depreciation) had no
impairment charge been recognized previously. A reversal
of an impairment charge is recognized in net earnings.
H. Goodwill
Goodwill arising in a business combination is recognized
as an asset at the date control is acquired. Goodwill is
measured as the cost of an acquisition plus the amount of
any non-controlling interest in the acquiree (if applicable)
less the fair value of the related identifiable assets
acquired and liabilities assumed.
Goodwill is not subject to amortization, but is tested for
impairment at least annually, or more frequently, if an
analysis of events and circumstances indicates that a
possible impairment may exist. These events could include
a significant change in financial position of the CGUs or
groups of CGUs to which the goodwill relates or significant
negative industry or economic trends. For impairment
purposes, goodwill is allocated to each of the Company’s
CGUs or groups of CGUs that are expected to benefit
from the synergies of the business combination in which
the goodwill arose. Accordingly, the Company performs its
test for impairment, where the recoverable amount of the
CGUs or groups of CGUs to which the goodwill relates is
compared to its carrying amount for each operating
segment. If the recoverable amount is less than the
carrying amount, an impairment charge is immediately
recognized in net earnings, by first reducing the carrying
amount of the goodwill and then by reducing the carrying
amount of the other assets in the unit. An impairment
charge recognized for goodwill is not reversed in
subsequent periods.
I. Income Taxes
The Company uses the liability method of accounting for
income taxes. Under the liability method, deferred income
tax assets and liabilities are recognized on the differences
between the carrying amounts of assets and liabilities and
their respective income tax basis (temporary differences).
A deferred income tax asset may also be recognized for
the benefit expected from unused tax credits and losses
available for carryforward, to the extent that it is probable
that future taxable earnings will be available against which
the tax credits and losses can be applied. Deferred income
tax assets and liabilities are measured based on income
tax rates and tax laws that are enacted or substantively
enacted by the end of the reporting period and that are
expected to apply in the years in which temporary
differences are expected to be realized or settled.
Deferred income tax is charged or credited to net
earnings, except when related to items charged or
credited to either OCI or directly to equity. The carrying
amount of deferred income tax assets is evaluated at the
end of each reporting period and is reduced to the extent
that it is no longer probable that sufficient taxable income
will be available to allow all or part of the asset to be
realized. Unrecognized deferred tax assets are reassessed
at each reporting date and are recognized to the extent
that it has become probable that future taxable income will
allow the deferred income tax asset to be recovered.
Deferred income tax liabilities are recognized for taxable
temporary
differences
arising
on
investments
in
subsidiaries, except where the Company is able to control
the reversal of the temporary difference and it is probable
that the temporary difference will not reverse in the
foreseeable future.
Cash
taxes
paid
disclosed
on
the
Consolidated
Statements of Cash Flows includes income taxes and
taxes paid related to the Part VI.1 tax in Canada for the
period.
J. Employee Future Benefits
The Company has defined benefit pension and other post-
employment benefit plans. The current service cost of
providing benefits under the defined benefit plans is
determined using the projected unit credit method
prorated based on service. The net interest cost is
determined by applying the discount rate to the net
defined benefit liability. The discount rate used to
determine the present value of the defined benefit
obligation and the net interest cost, is determined by
reference to market yields at the end of the reporting
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TransAlta Corporation
2024 Integrated Report
period on high-quality corporate bonds with terms and
currencies that match the estimated terms and currencies
of the benefit obligations. Remeasurements, which include
actuarial gains and losses and the return on plan assets
(excluding net interest), are recognized through OCI in the
period in which they occur. Actuarial gains and losses
arise from experience adjustments and changes in
actuarial
assumptions.
Remeasurements
are
not
reclassified to profit or loss, from OCI, in subsequent
periods.
Gains or losses arising from either a curtailment or
settlement of a defined benefit plan are recognized when
the
curtailment
or
settlement
occurs.
When
the
restructuring of a benefit plan gives rise to a curtailment
and a settlement of obligations, the curtailment is
accounted for before the settlement.
In determining whether statutory minimum funding
requirements of the Company’s defined benefit pension
plans give rise to recording an additional liability, letters of
credit provided by the Company as security are
considered to alleviate the funding requirements. No
additional liability results in these circumstances.
Contributions payable under defined contribution pension
plans are recognized as a liability and an expense in the
period in which the services are rendered.
K. Provisions
Provisions are recognized when the Company has a
present obligation (legal or constructive) as a result of a
past event, it is probable that the Company will be
required to settle the obligation and a reliable estimate can
be made of the amount of the obligation. A legal obligation
can arise through a contract, legislation or other operation
of law. A constructive obligation arises from an entity’s
actions whereby through an established pattern of past
practice, published policies or a sufficiently specific
current statement, the entity has indicated it will accept
certain responsibilities and has thus created a valid
expectation that it will discharge those responsibilities.
The amount recognized as a provision is the best
estimate,
remeasured
at
each
period-end,
of
the
expenditures required to settle the present obligation,
considering the risks and uncertainties associated with the
obligation. Where expenditures are expected to be
incurred in the future, the obligation is measured at its
present value using a current market-based, risk-adjusted
discount rate.
The Company records a decommissioning and restoration
provision for all generating facilities and mine sites for
which it is legally or constructively required to remove the
facilities at the end of their useful lives and restore the
plant or mine sites. For some hydro facilities, the Company
is required to remove the generating equipment, but is not
required to remove the structures.
Initial decommissioning provisions are recognized at their
present value when incurred. Each reporting date, the
Company determines the present value of the provision
using the current discount rates that reflect the time value
of money and associated risks. The Company recognizes
the initial decommissioning and restoration provisions, as
well as changes resulting from revisions to cost estimates
and period-end revisions to the market-based, risk-
adjusted discount rate, as a cost of the related PP&E (see
Note 2(E)) to the extent the related PP&E asset is still in
use. Where the related PP&E asset has reached the end of
its useful life, changes in the decommissioning and
restoration provision are recognized in net earnings.
Where the Company expects to receive reimbursement
from a third party for a portion of future decommissioning
costs, the reimbursement is recognized as a separate
asset when it is virtually certain that the reimbursement
will be received.
Changes in other provisions resulting from revisions to
estimates of expenditures required to settle the obligation
or period-end revisions to the market-based, risk-adjusted
discount rate are recognized in net earnings.
The accretion of the net present value discount for both
the decommissioning and restoration provision and other
provisions are charged to net earnings each period and is
included in net interest expense.
L. Leases
Under IFRS 16, a contract contains a lease when the
customer obtains the right to control the use of an
identified asset for a period of time in exchange
for consideration.
I. Lessee
The Company enters into lease arrangements with respect
to land, building and office space, vehicles and site
machinery and equipment. For all contracts that meet the
definition of a lease under IFRS 16 in which the Company
is the lessee and which are not exempt as short-term or
low-value leases, the Company:
• Recognizes right-of-use assets and lease liabilities in the
Consolidated Statements of Financial Position;
• Recognizes depreciation of the right-of-use assets and
interest expense on lease liabilities in the Consolidated
Statements of Earnings; and
• Recognizes the principal repayments on lease liabilities
as financing activities and interest payments on lease
liabilities as operating activities in the Consolidated
Statements of Cash Flows.
For short-term and low-value leases, the Company
recognizes the lease payments as operating expenses.
Variable lease payments that do not depend on an index
or a rate are not included in the measurement of the lease
TransAlta Corporation
2024 Integrated Report
F22
liability and the right-of-use asset and are recognized as
an expense in the period in which the event or condition
that triggers the payments occurs.
Right-of-use assets are initially measured at an amount
equal to the lease liability and adjusted for any payments
made at or before the commencement date, plus any
initial direct costs incurred and an estimate of costs to
dismantle and remove the underlying asset, or to restore
the underlying asset or the site on which it is located, less
any lease incentives received.
Lease liabilities are initially measured at the present value
of the lease payments that are not paid at commencement
and
discounted
using
the
Company's
incremental
borrowing rate or the rate implicit in the lease. The lease
liability is remeasured when there is a change in future
lease payments arising from a change in an index or rate,
or if there is a change in the Company’s estimate or
assessment of whether it will exercise an extension,
termination
or
purchase
option.
A
corresponding
adjustment is made to the carrying amount of the right-of-
use asset, or is recorded in profit or loss if the carrying
amount of the right-of-use asset has been reduced
to zero.
The lease term includes periods covered by an option to
extend if the Company is reasonably certain to exercise
that option and periods covered by an option to terminate
if the Company is reasonably certain not to exercise
that option.
Right-of-use assets are depreciated over the shorter
period of either the lease term or the useful life of the
underlying asset. If a lease transfers ownership of the
underlying asset or the cost of the right-of-use asset
reflects that the Company expects to exercise the
purchase option, the related right-of-use asset is
depreciated over the useful life of the underlying asset.
The Company has elected to apply the practical expedient
that permits a lessee not to separate non-lease
components and instead account for any lease and
associated
non-lease
components
as
a
single arrangement.
II. Lessor
Power Purchase Agreements (PPAs) and other long-term
contracts may contain, or may be considered, leases
where the fulfillment of the arrangement is dependent on
the use of a specific asset (e.g., a generating unit) and the
arrangement conveys to the customer the right to control
the use of that asset.
If the Company determines that the contractual provisions
of a contract contain, or are, a lease and result in the
customer assuming the principal risks and rewards of
ownership of the asset, the arrangement is a finance
lease. Assets subject to finance leases are not reflected as
PP&E and the net investment in the lease, represented by
the present value of the amounts due from the lessee, is
recorded in the Consolidated Statements of Financial
Position as a financial asset, classified as a finance lease
receivable. The payments considered to be part of the
leasing arrangement are apportioned between a reduction
in the lease receivable and finance lease income. The
finance lease income element of the payments is
recognized using a method that results in a constant rate
of return on the net investment in each period and is
reflected in finance lease income on the Consolidated
Statements of Earnings.
Where the Company determines that the contractual
provisions of a contract contain, or are, a lease and result
in the Company retaining the principal risks and rewards of
ownership of the asset, the arrangement is an operating
lease. For operating leases, the asset is, or continues to
be, capitalized as PP&E and depreciated over its useful
life.
M. Non-Controlling Interests
Non-controlling
interests
arise
from
business
combinations in which the Company acquires less than a
100 per cent interest. Non-controlling interests are initially
measured at either fair value or at the non-controlling
interest’s proportionate share of the acquiree’s identifiable
net assets. The Company determines which measurement
is used on a transaction-by-transaction basis. Non-
controlling interests also arise from other contractual
arrangements between the Company and other parties,
whereby the other party has acquired an equity interest in
a subsidiary and the Company retains control.
Subsequent to acquisition, the carrying amount of non-
controlling interests is increased or decreased by the non-
controlling interest’s share of subsequent changes in
equity and payments to the non-controlling interest. Total
comprehensive income (loss) is attributed to the non-
controlling interests even if this results in the non-
controlling interests having a negative balance.
When the proportion of the equity held by non-controlling
interests changes, the carrying amounts of the controlling
and non-controlling interests are adjusted to reflect the
changes in their relative interests in the subsidiary. Any
difference between the amount by which the non-
controlling interests are adjusted and the fair value of the
consideration paid or received, is recognized directly in
equity and attributed to shareholders.
N. Joint Arrangements
A joint arrangement is a contractual arrangement that
establishes the terms by which two or more parties agree
to undertake and jointly control an economic activity. The
Company's joint arrangements are generally classified as
two types: joint operations and joint ventures.
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2024 Integrated Report
A joint operation arises when the parties that have joint
control have rights to the assets and obligations for the
liabilities relating to the arrangement. Generally, each
party takes a share of the output from the asset and each
bears an agreed upon share of the costs incurred in
respect of the joint operation. The Company reports its
interests in joint operations in its Consolidated Financial
Statements using the proportionate consolidation method
by recognizing its share of the assets, liabilities, revenues
and expenses in respect of its interest in the joint
operation.
In a joint venture, the venturers do not have rights to
individual assets or obligations of the venture. Rather,
each venturer has rights to the net assets of the
arrangement. The Company reports its interests in joint
ventures using the equity method. Under the equity
method, the investment is initially recognized at cost and
the carrying amount is increased or decreased to
recognize the Company’s share of the joint venture’s net
earnings or loss after the date of acquisition. The impact
of transactions between the Company and joint ventures
is eliminated based on the Company’s ownership interest.
Distributions received from joint ventures reduce the
carrying amount of the investment. Any excess of the cost
of an acquisition less the fair value of the recognized
identifiable assets, liabilities and contingent liabilities of an
acquired joint venture is recognized as goodwill and is
included in the carrying amount of the investment and is
assessed for impairment as part of the investment.
Investments in joint ventures are evaluated for impairment
at each reporting date by first assessing whether there is
objective evidence that the investment is impaired. If such
objective evidence is present, an impairment charge is
recognized if the investment’s recoverable amount is less
than its carrying amount. The investment’s recoverable
amount is determined as the higher of value in use and fair
value less costs of disposal.
O. Assets Held for Sale
Assets and disposal groups (assets and liabilities disposed
of together) are classified as held for sale if their carrying
amount will be recovered primarily through a sale as
opposed to continued use by the Corporation. Assets and
disposal groups classified as held for sale are measured at
the lower of their carrying amount and fair value less costs
of disposal. Any impairment is recognized in net earnings.
Depreciation and equity accounting ceases when an asset
or equity investment, respectively, is classified as held for
sale. Assets and disposal groups classified as held for sale
are reported as current assets and current liabilities in the
Consolidated Statements of Financial Position.
P. Business Combinations
Transactions in which the acquisition constitutes a
business are accounted for using the acquisition method.
Identifiable assets acquired and liabilities assumed,
including contingent consideration, are measured at their
acquisition date fair values. A business consists of inputs
and processes applied to those inputs that have the ability
to contribute to the creation of outputs. Goodwill is
measured as the excess of the fair value of consideration
transferred less the fair value of the net assets acquired.
Acquisition-related
costs
to
effect
the
business
combination, with the exception of costs to issue debt or
equity
securities,
are
recognized
in
net
earnings
as incurred.
The optional fair value concentration test is applied on a
transaction-by-transaction basis to permit a simplified
assessment of whether an acquired set of activities and
assets is not a business. Where substantially all of the fair
value of the gross assets acquired is concentrated in a
single identifiable asset or group of similar identifiable
assets, the Company may elect to treat the acquisition as
an asset acquisition and not as a business combination.
Q. Significant Accounting Judgments and
Key Sources of Estimation Uncertainty
The
preparation
of
financial
statements
requires
management
to
make
judgments,
estimates
and
assumptions that could affect the reported amounts of
assets, liabilities, revenues, expenses and disclosures of
contingent assets and liabilities during the period. These
estimates are subject to uncertainty. Actual results could
differ from those estimates due to factors such as
fluctuations in interest rates, foreign exchange rates,
inflation and commodity prices and changes in economic
conditions, legislation and regulations.
In the process of applying the Company’s accounting
policies, management has to make judgments and
estimates about matters that are highly uncertain at the
time the estimate is made and that could significantly
affect the amounts recognized in the Consolidated
Financial Statements. Different estimates with respect to
key variables used in the calculations, or changes to
estimates, could potentially have a material impact on the
Company’s financial position or performance. The key
judgments and sources of estimation uncertainty are
described below:
I. Tariff
On Feb. 1, 2025, the President of the United States issued
three executive orders directing the United States to
impose new tariffs on imports originating from Canada,
Mexico and China. These orders call for additional 25 per
cent duty on imports into the United States of Canadian-
origin and Mexican-origin products and 10 per cent duty
TransAlta Corporation
2024 Integrated Report
F24
on Chinese-origin products, except for Canadian energy
resources that are subject to an additional 10 per cent
duty. On Feb. 3, 2025, a 30-day pause on potential tariffs
was implemented. The actual tariffs and their impacts to
the Company remain uncertain. The Company is assessing
the direct and indirect impacts to its business of such
tariffs, retaliatory tariffs or other trade protectionist
measures implemented as this situation develops.
II. Impairment of PP&E and Goodwill
Impairment exists when the carrying amount of an asset,
CGU or group of CGUs to which goodwill relates exceeds
its recoverable amount, which is the higher of its fair value
less costs of disposal and its value in use. An assessment
is made at each reporting date as to whether there is any
indication that an impairment charge may exist or that a
previously recognized impairment charge may no longer
exist or may have decreased. In determining fair value less
costs
of
disposal,
information
about
third-party
transactions for similar assets is used and if none is
available, other valuation techniques, such as discounted
cash flows, are used. Value in use is computed using the
present value of management’s best estimates of future
cash flows based on the current use and present condition
of the asset.
In estimating either fair value less costs of disposal or
value in use using discounted cash flow methods,
estimates and assumptions must be made about sales
prices, cost of sales, production, fuel consumed, capital
expenditures, retirement costs and other related cash
inflows and outflows over the life of the facilities. In
developing
these
assumptions,
management
uses
estimates of contracted and future market prices based on
expected market supply and demand in the region in
which the plant operates, anticipated production levels,
planned and unplanned outages, changes to regulations
and transmission capacity or constraints for the remaining
life of the facilities.
Discount rates are determined by employing a weighted
average cost of capital methodology that is based on
capital structure, cost of equity and cost of debt
assumptions based on comparable companies with similar
risk characteristics and market data as the asset, CGU or
group of CGUs subject to the test. These estimates and
assumptions are susceptible to change from period to
period and actual results can and often do, differ from the
estimates and can have either a positive or negative
impact on the estimate of the impairment charge and may
be material.
The impairment outcome can also be impacted by the
determination of CGUs or groups of CGUs for asset and
goodwill impairment testing. A CGU is the smallest
identifiable group of assets that generates cash inflows
that are largely independent of the cash inflows from other
assets or groups of assets and goodwill is allocated to
each CGU or group of CGUs that is expected to benefit
from the synergies of the acquisition from which the
goodwill arose. The allocation of goodwill is reassessed
upon changes in the composition of segments, CGUs or
groups of CGUs. To determine CGUs, significant judgment
is required to determine what constitutes independent
cash flows between power plants that are connected to
the same system. The Company evaluates the market
design, transmission constraints and the contractual
profile of each facility, as well as the Company’s own
commodity price risk management plans and practices, in
order to inform this determination.
With regard to the allocation or reallocation of goodwill,
significant judgment is required to evaluate synergies and
their impacts. The Company evaluates synergies with
regard to opportunities from combined talent and
technology, functional organization and future growth
potential and considers its own performance measurement
processes
to
make
this
determination.
Information
regarding significant judgments and estimates in respect
of impairment during 2022 to 2024 is disclosed in Notes 7,
19 and 22.
III. Leases
To determine whether the Company’s contracts contain,
or are, leases, management must use judgment in
assessing whether the contract provides the customer
with the right to substantially all of the economic benefits
from the use of the asset during the lease term and
whether the customer obtains the right to direct the use of
the asset during the lease term. For those agreements
considered to contain, or be, leases, further judgment is
required to determine the lease term by assessing
whether termination or extension options are reasonably
certain to be exercised. Judgment is also applied in
identifying in-substance fixed payments (included) and
variable
payments
that
are
based
on
usage
or
performance factors (excluded) and in identifying lease
and non-lease components (services that the supplier
performs) of contracts and in allocating contract payments
to lease and non-lease components.
For leases where the Company is a lessor, judgment is
required to determine if substantially all of the significant
risks and rewards of ownership are transferred to the
customer or remain with the Company to appropriately
account for the agreement as either a finance or operating
lease. These judgments can be significant and impact how
the
Company
classifies
amounts
related
to
the
arrangement as either PP&E or as a finance lease
receivable on the Consolidated Statements of Financial
Position and therefore the amount of certain items of
revenue
and
expense
is
dependent
upon
such classifications. In 2024 and 2023, finance lease
receivables were recognized, where it was determined
that the significant risks and rewards of ownership of the
facilities were transferred to the customer. Information
regarding finance leases is disclosed in Note 17.
F25
TransAlta Corporation
2024 Integrated Report
IV. Income Taxes
Preparation of the Consolidated Financial Statements
involves determining an estimate of, or provision for,
income taxes in each of the jurisdictions in which the
Company operates. The process also involves making an
estimate of income taxes currently payable and income
taxes expected to be payable or recoverable in future
periods, referred to as deferred income taxes. Deferred
income taxes result from the effects of temporary
differences due to items that are treated differently for tax
and accounting purposes. The tax effects of these
differences are reflected in the Consolidated Statements
of Financial Position as deferred income tax assets and
liabilities. An assessment must also be made to determine
the likelihood that the Company’s future taxable income
will be sufficient to permit the recovery of deferred income
tax assets. To the extent that such recovery is not
probable, deferred income tax assets must be reduced.
Management uses the Company’s long-range forecasts as
a basis for evaluation of recovery of deferred income tax
assets. Management must exercise judgment in its
assessment of continually changing tax interpretations,
regulations and legislation to ensure deferred income tax
assets and liabilities are complete and fairly presented.
Differing
assessments
and
applications
than
the
Company’s estimates could materially impact the amounts
recognized for deferred income tax assets and liabilities.
Information regarding the impacts of the Company’s tax
policies is disclosed in Note 11.
V. Financial Instruments and Derivatives
The Company’s financial instruments and derivatives are
accounted for at fair value, with the initial and subsequent
changes in fair value affecting earnings in the period the
change occurs. The fair values of financial instruments and
derivatives are classified within three levels, with Level III
fair values determined using inputs for the asset or liability
that are not readily observable. Transfers between levels
of the fair value hierarchy are deemed to have occurred at
the end of the reporting period in which the event or
change in circumstances that caused the transfer
occurred. These fair value levels are outlined and
discussed in more detail in Note 14. Some of the
Company’s fair values are included in Level III because
they are not traded on an active exchange or have terms
that extend beyond the time period for which exchange-
based quotes are available and require the use of internal
valuation techniques or models to determine fair value.
The determination of the fair value of these contracts and
derivative instruments can be complex and relies on
judgments and estimates concerning future prices,
volatility and liquidity, among other factors. These fair
value estimates may not necessarily be indicative of the
amounts that could be realized or settled and changes in
these assumptions could affect the reported fair value of
financial instruments. Fair values can fluctuate significantly
and can be favourable or unfavourable depending on
current market conditions. Judgment is also used in
determining
whether
a
highly
probable
forecasted
transaction designated in a cash flow hedge is expected
to occur based on the Company’s estimates of pricing and
production to allow the future transaction to be fulfilled.
When the Company enters into contracts to buy or sell
non-financial items, such as certain commodities, and the
contracts can be settled net in cash, the Company must
use judgment to evaluate whether such contracts were
entered into and continue to be held for the purposes of
the receipt or delivery of the commodity in accordance
with the Company's expected purchase, sale or usage
requirements (i.e., normal purchase and sale). If this
assertion cannot be supported, initially at contract
inception and on an ongoing basis, the contracts must be
accounted for as derivatives and measured at fair value,
with changes in fair value recognized in net earnings. In
supporting the normal purchase and sale assertion, the
Company considers the nature of the contracts, the
forecasted demand and supply requirements to which the
contracts relate and its past practice of net settling other
similar contracts, which may taint the normal purchase and
sale assertion. The Company also enters into PPAs and
contracts for differences and judgment is applied to
determine if the contract meets the "own use" exemption
or if derivative treatment is required.
VI. Project Development Costs
Project development costs are recognized in operating
expenses until construction of a facility or acquisition of an
investment is likely to occur, there is reason to believe that
future costs are recoverable and that efforts will result in
future value to the Company, at which time the costs
incurred subsequently are included in PP&E or other
assets. The appropriateness of capitalization of these
costs is evaluated each reporting period and amounts
capitalized for projects no longer probable of occurring or
when there is uncertainty of timing of when the projects
will proceed are charged to net earnings. Management is
required to use judgment to determine if there is reason to
believe that future costs are recoverable and that efforts
will result in future value to the Company when
determining the amount to be capitalized. Information
regarding project development costs is disclosed in
Note 23 and information on the write-off of project
development costs is disclosed in Note 7.
VII. Provisions for Decommissioning and
Restoration Activities
TransAlta recognizes provisions for decommissioning and
restoration obligations as outlined in Note 2(K). Initial
decommissioning provisions and subsequent changes
thereto are determined using the Company’s best estimate
of the required cash expenditures, adjusted to reflect the
risks and uncertainties inherent in the timing and amount
of settlement. The estimated cash expenditures are
present valued using a current, risk-adjusted, market-
TransAlta Corporation
2024 Integrated Report
F26
based, pre-tax discount rate. A change in estimated cash
flows, market interest rates or timing could have a material
impact on the carrying amount of the provision.
Information regarding significant judgments and estimates
made during 2022 to 2024 in respect of decommissioning
and restoration provisions is disclosed in Notes 7, 19 and
24.
VIII. Useful Life of PP&E
Each significant component of an item of PP&E is
depreciated over its estimated useful life. Estimated useful
lives are determined based on current facts and past
experience and take into consideration the anticipated
physical life of the asset, existing long-term sales
agreements and contracts, current and forecasted
demand, the potential for technological obsolescence and
regulations. The useful lives of PP&E are reviewed at least
annually to ensure they continue to be appropriate.
Information on changes in useful lives of facilities is
disclosed in Note 19.
IX. Employee Future Benefits
The
Company
provides
pension
and
other
post-
employment benefits, such as health and dental benefits,
to employees. The cost of providing these benefits is
dependent upon many factors, including actual plan
experience
and
estimates
and
assumptions
about
future experience.
The liability for pension and post-employment benefits
and associated costs included in annual compensation
expenses are impacted by estimates related to:
• Employee demographics, including age, compensation
levels, employment periods, the level of contributions
made to the plans and earnings on plan assets;
• The effects of changes to the provisions of the
plans; and
• Changes in key actuarial assumptions, including rates of
compensation and health-care cost increases and
discount rates.
Due to the complexity of the valuation of pension and
post-employment benefits, a change in the estimate of
any one of these factors could have a material effect on
the carrying amount of the liability for pension and other
post-employment benefits or the related expense. These
assumptions are reviewed annually to ensure they
continue to be appropriate. Disclosures on employee
future benefits are disclosed in Note 32.
X. Other Provisions
Where necessary, the Company recognizes provisions
arising
from
ongoing
business
activities,
such
as
interpretation and application of contract terms, ongoing
litigation and force majeure claims. These provisions and
subsequent changes thereto, are determined using the
Company’s best estimate of the outcome of the underlying
event and can also be impacted by determinations made
by
third
parties,
in
compliance
with
contractual
requirements. The actual amount of the provisions that
may be required could differ materially from the amount
recognized. More information is disclosed in Notes 8 and
24 with respect to other provisions.
XI. Revenue from Contracts with Customers
Where contracts contain multiple promises for goods or
services, management exercises judgment in determining
whether goods or services constitute distinct goods or
services or a series of distinct goods that are substantially
the same and that have the same pattern of transfer to the
customer. The determination of a performance obligation
affects whether the transaction price is recognized at a
point in time or over time. Management considers both the
mechanics of the contract and the economic and
operating environment of the contract to determine
whether the goods or services in a contract are distinct.
In determining the transaction price and estimates of
variable consideration, management considers the past
history of customer usage in estimating the goods and
services to be provided to the customer. The Company
also considers the historical production levels and
operating conditions for its variable generating assets. The
Company’s contracts generally outline a specific amount
to be invoiced to a customer associated with each
performance obligation in the contract. Where contracts
do not specify amounts for individual performance
obligations, the Company estimates the amount of the
transaction price to allocate to individual performance
obligations based on their stand-alone selling price, which
is primarily estimated based on the amounts that would be
charged to customers under similar market conditions.
The satisfaction of performance obligations requires
management to make judgments as to when control of the
underlying good or service transfers to the customer.
Determining when a performance obligation is satisfied
affects
the
timing
of
revenue
recognition.
Management considers both customer acceptance of the
good or service and the impact of laws and regulations
such as certification requirements, to determine when this
transfer occurs.
When contracts are modified, management must exercise
judgment to determine, depending upon the facts and
circumstances of the changes to the contract, whether the
modification is accounted for as a new contract or as part
of the existing contract. If it is required to be accounted
for as part of the existing contract the transaction price
can be affected and adjustments to previously recognized
revenue can occur, or the impacts can be reflected
prospectively from the modification date.
Management
also
applies
judgment
in
determining
whether
the
invoice
practical
expedient
permits
recognition of revenue at the invoiced amount if that
invoiced amount corresponds directly with the entity's
performance to date.
F27
TransAlta Corporation
2024 Integrated Report
XII. Classification of Joint Arrangements
Upon entering into, or acquiring an interest in, a joint
arrangement, the Company must classify it as either a joint
operation or joint venture, and this classification affects
the accounting for the joint arrangement. In making this
classification,
the
Company
exercises
judgment
in
evaluating the terms and conditions of the arrangement to
determine whether the parties have rights to the assets
and obligations or rights to the net assets. Factors such as
the legal structure, contractual arrangements and other
facts and circumstances, such as where the purpose of
the arrangement is primarily for the provision of the output
to the parties and when the parties are substantially the
only source of cash flows for the arrangement, must be
evaluated to understand the rights of the parties to the
arrangement.
XIII. Significant Influence
Upon entering into an investment, the Company must
classify it as either an investment in an associate or an
investment under IFRS 9. In making this classification, the
Company exercises judgment in evaluating whether the
Company has significant influence over the investee.
Significant influence is the power to participate in the
financial and operating policy decisions of the investee,
but is not control or joint control over those policies. If the
Company holds 20 per cent or more of the voting rights in
the investee, it is presumed that the entity has significant
influence, unless it can be clearly demonstrated that this is
not the case. Other factors such as representation on the
Board, participation in policy-making processes, material
transactions
between
the
Company
and
investee,
interchange of managerial personnel or providing essential
technical information are considered when assessing if the
Company has significant influence over an investee.
XIV. Change in Estimates
During the year ended Dec. 31, 2024, there were changes
in estimates relating to asset impairment charges
(reversals) (Note 7), asset useful lives and depreciation
(Note 19), decommissioning and other provisions (Note
24) and defined benefit obligation (Note 27). During the
year ended Dec. 31, 2023, there were changes in
estimates relating to asset impairment charges (reversals)
(Note 7), useful lives (Note 19), decommissioning and
other provisions (Note 24) and defined benefit obligation
(Note 27).
XV. Fair Value of Assets Acquired and
Liabilities Assumed in Business Combination
The fair value of assets acquired and liabilities assumed,
including contingent consideration, is estimated based on
information available at the date of acquisition. While
Management uses best estimates and assumptions to
accurately value assets acquired and liabilities assumed at
the date of acquisition, as well as any contingent
consideration, estimates are inherently uncertain and
subject to refinement.
Accounting for business combinations requires significant
judgement, estimates and assumptions at the acquisition
date. In developing estimates of fair values at the
acquisition date, Management utilize a variety of factors
including market data, market prices, capacity, historical
and future expected cash flows, growth rates and
discount
rates.
Information
regarding
business
combinations has been included in Note 4.
TransAlta Corporation
2024 Integrated Report
F28
3. Accounting Changes
A. Current Accounting Changes
Amendments
to
IAS
1
—
Non-current
Liabilities with Covenants and Classification of
Liabilities as Current or Non-current
In October 2022, the IASB issued Non-current Liabilities
with Covenants, which amends IAS 1 Presentation of
Financial Statements, to clarify how conditions with which
an entity must comply within 12 months after the reporting
period affect the classification of a liability. In January
2020, the IASB issued Classification of Liabilities as
Current or Non-current, which amends IAS 1 Presentation
of Financial Statements regarding the classification of
liabilities
as
current
or
non‐current,
clarifying
that
contractual
rights
and
conditions
existing
at
the end of the reporting period are relevant in determining
whether the Company has a right to defer settlement of a
liability by at least 12 months.
Additionally, the IASB clarified that the classification of a
liability is unaffected by the likelihood that an entity will
exercise its deferral right. The amendments are applied
retrospectively, effective for annual periods beginning on
or after Jan. 1, 2024, and were adopted by the Company
on that date.
The Company has an Investment Agreement whereby
Brookfield Renewable Partners or its affiliates (collectively,
Brookfield) invested $750 million in TransAlta through the
purchase of exchangeable securities (Exchangeable
Securities), which are exchangeable into an equity
ownership interest in TransAlta’s Alberta hydro assets in
the future. On Jan. 1, 2024, the Company reclassified the
Exchangeable Securities from non-current liabilities to
current liabilities as the conversion option can be
exercised at any time after Dec. 31, 2024, although there
is no obligation to deliver cash equivalent resources and
the holder cannot call for repayment. This accounting is
consistent with the amendment.
B. Future Accounting Changes
The Company closely monitors both new accounting
standards and amendments to existing accounting
standards issued by the IASB. The following standards
have been issued but are not yet in effect.
Amendments to IFRS 9 and IFRS 7 — Nature-
Dependent Electricity Contracts
On Dec. 18, 2024, the IASB issued amendments to IFRS 9
Financial Instruments and IFRS 7 Financial Instruments:
Disclosure to improve reporting of the financial effects of
nature-dependent
electricity
(e.g.,
wind
and
solar)
contracts, which are often structured as power purchase
agreements. Under these contracts, the amount of
electricity generated can vary based on uncontrollable
factors such as weather conditions. The amendments
clarify the application of own-use requirements, permit
hedge accounting if these contracts are used as hedging
instruments and add new disclosure requirements about
the effect of these contracts on a company's financial
performance and cash flows. The amendments are
effective for annual reporting periods beginning on or after
Jan. 1, 2026. The Company is currently evaluating the
impacts to the financial statements.
Amendments to IFRS 7 and IFRS 9 —
Classification and Measurement of Financial
Instruments
On May 29, 2024, the IASB issued Amendments to the
Classification and Measurement of Financial Instruments
effective Jan. 1, 2026 impacting IFRS 7 and 9. The IASB
amended the requirements related to settling financial
liabilities using an electronic payment system and
assessing contractual cash flow characteristics of financial
assets, including those with ESG-linked features. The
Company is currently evaluating the impacts to the
financial statements.
IFRS 18 — Presentation and Disclosure in
Financial Statements
On April 9, 2024, the IASB issued a new standard, IFRS 18
Presentation and Disclosure in Financial Statements,
which
introduced
new
requirements
for
improved
comparability in the statement of profit or loss, enhanced
transparency
of
management-defined
performance
measures and more useful grouping of information in the
financial statements. The standard is effective for annual
reporting periods beginning on or after Jan. 1, 2027. The
Company is currently evaluating the impacts to the
financial statements.
C. Comparative Figures
Certain comparative figures have been reclassified to
conform to the current period’s presentation. These
reclassifications did not impact previously reported
net earnings.
F29
TransAlta Corporation
2024 Integrated Report
4. Business Acquisitions
Acquisition of Heartland Generation
On Dec. 4, 2024 (Acquisition Date), the Company acquired
all issued and outstanding common shares of Heartland
Generation
Ltd.
and
Alberta
Power
(2000)
Ltd.
(collectively, Heartland) from Energy Capital Partners
(ECP) (the Acquisition). The Acquisition, which includes
Heartland’s entire business operations in Alberta and
British Columbia, was completed for an aggregate
purchase price of $542 million. This amount was adjusted
for the reduction of $95 million to reflect the economic
benefit of the Heartland business arising since Oct. 31,
2023 and a working capital adjustment of $2 million. The
Acquisition included the assumption of long-term debt at
the Acquisition Date of $232 million and Heartland's cash
and cash equivalents of $276 million, resulting in a
purchase price of $493 million. The Acquisition was
funded through a combination of cash on hand and draws
on the Company's credit facilities.
Heartland owns and operates generation assets consisting
of 507 MW of cogeneration, 387 MW of contracted and
merchant peaking generation, 950 MW of natural gas-fired
thermal
generation,
transmission
capacity
and
a
development pipeline that includes the 400 MW Battle
River Carbon Hub.
In order to meet the requirements of the federal
Competition Bureau, TransAlta entered into a consent
agreement
with
the
Commissioner
of
Competition
pursuant to which TransAlta agreed to divest Heartland’s
Poplar Hill and Rainbow Lake assets with combined gross
installed capacity of 97 MW following closing (the Planned
Divestiture). ECP will be entitled to receive the proceeds
from the Planned Divestiture and net cash flows of these
assets arising from Nov. 13, 2024 to the date of the sale.
The sales process for these assets is in progress. The
Company has no residual financial risk on the sale.
The acquired tangible and intangible assets and assumed
liabilities are recorded at their estimated fair values at the
date of the Acquisition. The total consideration was
allocated to the tangible and intangible assets acquired
and liabilities assumed, with any excess recorded as
goodwill.
The
preliminary
purchase
price
allocation
reflects
management’s best estimate of the fair value of the
acquired assets and liabilities based on the analysis of
information obtained to date. Management is continuing to
obtain specific information to support the valuation of the
environmental compliance liabilities, decommissioning
provision, property, plant and equipment, and deferred
taxes. Any adjustments to the purchase price allocation
will be made as soon as practicable but no later than one
year from the date of acquisition.
TransAlta Corporation
2024 Integrated Report
F30
The following table summarizes the preliminary fair values that were assigned to the net assets acquired as at the
Acquisition Date.
Dec. 4, 2024
Current Assets and Non-Current Assets
Cash and cash equivalents
276
Trade and other receivables
126
Risk management assets current
7
Prepaid expenses and other
104
Assets held for sale (Note 18)
80
Long-term portion of finance lease receivables (Note 17)
107
Risk management assets non-current
9
Property, plant and equipment and Right-of-use assets (Note 19 and 20)
413
Intangible assets (Note 21)
57
Other assets
2
Deferred income tax assets (Note 11)
41
Current Liabilities and Non-Current Liabilities
Accounts payable and accrued liabilities
193
Risk management liabilities current
3
Current portion of decommissioning (Note 24)
4
Current portion of other provisions (Note 24)
15
Current portion of contract liabilities (Note 5)
3
Current portion of long-term debt and lease liabilities (Note 25)
28
Credit facilities, long-term debt and lease liabilities (Note 25)
204
Decommissioning non-current portion (Note 24)
97
Other provisions non-current (Note 24)
40
Deferred income tax liabilities (Note 11)
108
Risk management liabilities non-current
1
Contract liabilities non-current (Note 5)
3
Total identifiable net assets at fair value
523
Goodwill arising on acquisition (Note 22)
51
Net assets acquired
574
Cash consideration
493
Contingent consideration payable
81
Total purchase consideration transferred
574
F31
TransAlta Corporation
2024 Integrated Report
As discussed above, the Company has agreed to pay
contingent consideration to ECP for the proceeds from the
Planned Divestiture and net cash flows of these assets
arising from Nov. 13, 2024, to the date of the sale. The $81
million of contingent consideration recognized in the
purchase price represents the fair value of contingent
consideration at the date of acquisition. The fair value was
determined based on expected sale proceeds and net
cash flows from operations. The Planned Divestiture is
classified and recorded as assets and liabilities held for
sale.
Goodwill of $51 million recognized on the transaction is a
result of deferred tax liabilities recognized on the
transaction, which are recorded at the Company's
effective tax rate without discounting, and from value
attributed to the existence of an assembled workforce.
None of the goodwill is expected to be deductible for tax
purposes.
Acquisition-related expenses incurred were approximately
$24 million for the year ended Dec. 31, 2024 and are
included in operating, maintenance and administrative
expenses recognized in the Consolidated Statements of
Earnings.
Revenue generated by the Acquisition for the period Dec.
4, 2024 to Dec. 31, 2024 was $34 million. Net loss before
taxes for the same period was $11 million. Had Heartland
been acquired at the beginning of the year, the assets
would have contributed an estimated $598 million to
revenues and $66 million to net earnings before taxes.
Acquisition of TransAlta Renewables
On Oct. 5, 2023, the Company completed the acquisition
of
the
outstanding
common
shares
of
TransAlta
Renewables not already owned, directly or indirectly, by
the Company. The consideration paid totalled $1.3 billion,
comprising $800 million of cash and 46 million common
shares of the Company valued at $514 million, based on
an $11.06 closing price of the Company’s shares on the
Toronto Stock Exchange on Oct. 4, 2023.
Transaction costs of $11 million incurred to effect the
acquisition have been charged, net of income tax, against
common shares ($4 million) and deficit ($7 million) on
closing of the acquisition.
Since the Company retained control of TransAlta
Renewables, the acquisition was accounted for as an
equity transaction. On closing of the transaction, non-
controlling interests was reduced by $630 million and
accumulated other comprehensive loss increased by
$64 million to eliminate the balances previously attributed
to
non-controlling
interest
holders
of
TransAlta
Renewables. The difference between consideration paid
and these amounts was recognized in deficit.
The Company's syndicated credit facilities were amended
to effectively consolidate the TransAlta Renewables
syndicated credit facility and non-committed demand
facility into the TransAlta credit facilities. The cash
drawings on the TransAlta Renewables' syndicated credit
facility were repaid and the outstanding letters of credit
were transferred to the TransAlta non-committed demand
facility. The TransAlta Renewables' credit facilities were
then terminated. This resulted in the TransAlta syndicated
credit facility increasing by $700 million to approximately
$2.0 billion. Refer to Note 25.
TransAlta Corporation
2024 Integrated Report
F32
5. Revenue
A. Disaggregation of Revenue
The majority of the Company's revenues are derived from
the sale of power, capacity and environmental and tax
attributes, leasing of power facilities and from asset
optimization activities, which the Company disaggregates
into the following groups for the purpose of determining
how economic factors affect the recognition of revenue.
Year ended Dec. 31, 2024
Hydro
Wind and
Solar
Gas
Energy
Transition
Energy
Marketing Corporate(1)
Total
Revenues from contracts with customers
Power and other
36
242
494
12
—
—
784
Environmental and tax attributes(2)
61
77
2
—
—
(34)
106
Revenue from contracts with customers
97
319
496
12
—
(34)
890
Revenue from derivatives and other
trading activities(3)
16
(69)
282
311
168
—
708
Revenue from merchant sales
287
71
546
291
—
— 1,195
Other(4)
9
15
26
2
—
—
52
Total revenue
409
336 1,350
616
168
(34) 2,845
Revenues from contracts with customers
Timing of revenue recognition
At a point in time
61
28
—
12
—
(34)
67
Over time
36
291
496
—
—
—
823
Total revenue from contracts
with customers
97
319
496
12
—
(34)
890
(1)
The elimination of intercompany sales is reflected in the Corporate segment.
(2) The environmental and tax attributes represent environmental attributes and production tax transfer sales not bundled with power and other sales.
(3) Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary
significantly from period to period and impact movements in derivative positions.
(4) Other revenue includes production tax credits related to U.S. wind facilities subject to tax equity financing arrangements, total lease income from long-
term contracts that meet the criteria of operating leases and other miscellaneous revenues.
F33
TransAlta Corporation
2024 Integrated Report
Year ended Dec. 31, 2023
Hydro
Wind and
Solar
Gas
Energy
Transition
Energy
Marketing Corporate
Total
Revenues from contracts with customers
Power and other(1)
30
204
400
12
—
—
646
Environmental and tax attributes(2)
14
26
—
—
—
—
40
Revenue from contracts with customers
44
230
400
12
—
—
686
Revenue from derivatives and other
trading activities(1)(3)
44
(16)
(172)
251
220
—
327
Revenue from merchant sales
434
104 1,247
488
—
— 2,273
Other(4)
11
18
39
—
—
1
69
Total revenue
533
336 1,514
751
220
1 3,355
Revenues from contracts with customers
Timing of revenue recognition
At a point in time
14
26
—
12
—
—
52
Over time
30
204
400
—
—
—
634
Total revenue from contracts with
customers
44
230
400
12
—
—
686
(1)
In the Wind and Solar segment, $14 million of mark-to-market losses were reclassified from revenue from contracts with customers to revenue from
derivatives and other trading activities to conform to the current period presentation.
(2) The environmental and tax attributes represent environmental attributes and production tax transfer sales not bundled with power and other sales.
(3) Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary
significantly from period to period and impact movements in derivative positions.
(4) Other revenue includes production tax credits related to U.S. wind facilities subject to tax equity financing arrangements, total lease income from long-
term contracts that meet the criteria of operating leases and other miscellaneous revenues.
TransAlta Corporation
2024 Integrated Report
F34
Year ended Dec. 31, 2022
Hydro
Wind and
Solar
Gas
Energy
Transition
Energy
Marketing Corporate
Total
Revenues from contracts with customers
Power and other
33
220 462
10
—
—
725
Environmental and tax attributes(1)
1
50
—
—
—
—
51
Revenue from contracts with customers
34
270 462
10
—
—
776
Revenue from derivatives and other
trading activities(2)
—
(121) (821)
243
160
(2)
(541)
Revenue from merchant sales
564
119 1,529
461
—
—
2,673
Other(3)
8
21
39
—
—
—
68
Total revenue
606
289 1,209
714
160
(2)
2,976
Revenues from contracts with customers
Timing of revenue recognition
At a point in time
1
50
—
12
—
—
63
Over time
33
220 462
(2)
—
—
713
Total revenue from contracts with
customers
34
270 462
10
—
—
776
(1)
The environmental and tax attributes represent environmental attributes and production tax transfer sales not bundled with power and other sales.
(2) Represents realized and unrealized gains or losses from hedging and derivative positions. Volatility and pricing in commodity markets can vary
significantly from period to period and impact movements in derivative positions.
(3) Other revenue includes production tax credits related to U.S. wind facilities subject to tax equity financing arrangements, total lease income from long-
term contracts that meet the criteria of operating leases and other miscellaneous revenues.
B. Performance Obligations
The performance obligations in the Company's contracts
with its customers include the provision of electricity and
steam capacity; the delivery of electricity, thermal energy
and environmental attributes; the provision of operation
and maintenance services and water management
services;
and
the
supply
of
byproducts
from
coal generation.
The aggregate amount of transaction prices allocated to
remaining performance obligations (contract revenues that
have not yet been recognized) as at Dec. 31, 2024, is
approximately
$2,336
million,
with
approximately
$455 million expected to be recognized during the period
2025-2027; $391 million for the period of 2028-2030;
$668 million for the period of 2031-2035; and $822 million
for 2036 and thereafter.
These amounts exclude revenues related to contracts that
qualify for the invoice practical expedient and future
revenues that are related to constrained variable
consideration. In many of the Company’s contracts,
elements
of
the
transaction
price
are
considered
constrained, such as for variable revenues dependent
upon future production volumes that are driven by
customer or market demand or market prices that are
subject to factors outside the Company’s influence. As a
result, the amounts of future revenues disclosed above
represent only a portion of future revenues that are
expected to be realized by the Company from its
contractual portfolio.
Contract liabilities of $36 million as at Dec. 31, 2024
represent the consideration received from customers in
advance of satisfying the related performance obligation
by supplying the related goods. Revenue is recognized
when the performance obligation is satisfied. $6 million of
contract liabilities were acquired from Heartland (refer to
Note 4).
F35
TransAlta Corporation
2024 Integrated Report
6. Expenses by Nature
Fuel, Purchased Power and Operations, Maintenance and Administration (OM&A)
Fuel and purchased power and OM&A expenses classified by nature are as follows:
Year ended Dec. 31
2024
2023(1)
2022
Fuel and
purchased
power
OM&A
Fuel and
purchased
power
OM&A
Fuel and
purchased
power
OM&A
Gas fuel costs
369
—
384
—
578
—
Coal fuel costs
123
—
177
—
146
—
Royalty, land lease, other direct costs
28
—
25
—
25
—
Purchased power
419
—
474
—
514
—
Salaries and benefits
—
296
—
254
—
263
Other operating expenses(1)
—
359
—
285
—
258
Total
939
655
1,060
539
1,263
521
(1)
Included in OM&A costs for 2023 was $14 million related to the write-down of parts and material inventory related to our natural-gas-fired facilities.
Brazeau — Spinning Reserve Self-Report
In 2022 a provision of $20 million was initially recognized
in revenue reflecting a potential disgorgement of revenue
and $2 million for potential penalties and fines. The final
assessment contained no disgorgement of revenue and
penalties of $33 million. This resulted in a reversal of the
original disgorgement provision in revenue in the year
ended Dec. 31, 2024 and recognition of the full amount of
the penalties assessed in OM&A. Refer to Note 37 for
details.
Acquisition-related transaction and
restructuring costs
During the year ended Dec. 31, 2024, the Company
recognized $24 million in acquisition-related transaction
and restructuring costs in OM&A costs as part of other
operating expenses related to the acquisition of Heartland,
mainly comprising severance, legal and consulting fees.
TransAlta Corporation
2024 Integrated Report
F36
7. Asset Impairment Charges (Reversals)
As part of the Company’s monitoring controls, long-range
forecasts are prepared for each CGU. The long-range
forecast estimates are used to assess the significance of
potential indicators of impairment and provide criteria to
evaluate adverse changes in operations. The Company
also considers the relationship between its market
capitalization and its book value, among other factors,
when reviewing for indicators of impairment. When
indicators of impairment are present, the Company
estimates a recoverable amount (the higher of value in use
or fair value less costs of disposal) for the affected CGUs
using discounted cash flow projections. The valuations are
subject to measurement uncertainty from assumptions
and inputs to the discount rates, power price forecasts,
useful lives of the assets (extending to the last planned
asset retirement in 2072) and long-range forecasts, which
include changes to production, fuel costs, operating costs
and capital expenditures. The Company recognized the
following asset impairment charges (reversals):
Year ended Dec. 31
2024
2023
2022
Segments:
Hydro
—
(10)
21
Wind and Solar
—
(4)
43
Corporate
—
—
(2)
Changes in decommissioning and restoration provisions on retired assets(1)
24
(34)
(53)
Project development costs
22
—
—
Asset impairment charges (reversals)
46
(48)
9
(1)
Changes relate to changes in discount rates and revisions in estimated decommissioning costs on retired assets in 2024, 2023 and 2022. Refer to
Note 24 for further details.
During 2024, the Company recognized impairment of
project development costs related to projects that are no
longer proceeding.
Hydro
During 2023, internal valuations indicated the fair value
less costs of disposal for two hydro facilities exceeded the
carrying value due to a contract extension and changes in
power price assumptions, which favourably impacted
estimated
future
cash
flows
and
resulted
in
a
recoverability test. As a result of the recoverability test, an
impairment reversal of $10 million was recognized. The
recoverable amounts of $70 million in total were estimated
based on fair value less costs of disposal utilizing a
discounted cash flow approach and are categorized as a
Level III fair value measurement.
During 2022, the Company recorded net impairment
charges of $21 million on four hydro facilities as a result of
changes in key assumptions, that included significant
increases in discount rates, changes in pricing and
changes in estimated future cash flows. The total
recoverable amounts of $89 million for these four assets
was estimated based on fair value less costs of disposal
using a discounted cash flow approach and is categorized
as a Level III fair value measurement.
Wind and Solar
During 2023, the Company recorded net impairment
reversals of $4 million. Internal valuations indicated the fair
value less costs of disposal for three wind facilities
exceeded the carrying value due to changes in power
price assumptions, which favourably impacted estimated
future cash flows and resulted in impairment reversals of
$17 million. The total recoverable amounts of $540 million
was estimated based on fair value less costs of disposal
using a discounted cash flow approach and is categorized
as a Level III fair value measurement.
Also in 2023, two wind facilities were impaired, primarily
due to unfavourable power price assumptions and
changes in estimated future cash flows, resulting in a
$13 million impairment charge. The recoverable amounts
of $130 million for these two assets were estimated based
on fair value less costs of disposal using a discounted
cash flow approach and are categorized as a Level III fair
value measurement.
During 2022, the Company recorded net impairment
charges of $43 million on five wind facilities and one solar
facility as a result of changes in key assumptions, that
included significant increases in discount rates, changes in
pricing and changes in estimated future cash flows. The
recoverable amounts of $754 million for these six assets
were estimated based on fair value less costs of disposal
using a discounted cash flow approach and categorized as
a Level III fair value measurement.
F37
TransAlta Corporation
2024 Integrated Report
8. Net Other Operating Income
Net other operating income includes the following:
Year ended Dec. 31
2024
2023
2022
Alberta Off-Coal Agreements
(40)
(40)
(40)
Liquidated damages recoverable
(10)
(6)
(12)
Other
(9)
(1)
(6)
Net other operating income
(59)
(47)
(58)
Alberta Off-Coal Agreements (OCA)
The Company receives payments from the Government of
Alberta for the cessation of coal-fired emissions on or
before Dec. 31, 2030. Under the terms of the agreements,
including
those
acquired
in
the
recent
Heartland
acquisition, the Company will receive annual cash
payments on or before July 31 of approximately $44
million. These payments will continue until the termination
of the agreements at the end of 2030. The Company
recognizes the off-coal payments evenly throughout the
year. Receipt of the payments is subject to certain terms
and conditions, including the cessation of all coal-fired
emissions on or before Dec. 31, 2030, which has been
achieved. The affected plants are not, however, precluded
from generating electricity at any time by any other
method, after Dec. 31, 2030.
Liquidated Damages Recoverable
The Company receives liquidated damages related to
requirements to be met by the contractor on turbine
availability guarantees at our Wind sites.
Sundance A Decommissioning
On Dec. 9, 2024, the Company received the decision by
the Alberta Utilities Commission related to Sundance A
Reclamation awarding TransAlta a reimbursement of
$9 million from the Balancing Pool for TransAlta’s
decommissioning costs for Sundance A, including its
proportionate share of the Highvale mine. The amount,
included in other for 2024, represents a shortfall of
decommissioning costs of Sundance A. Refer to Note 37
for more details.
TransAlta Corporation
2024 Integrated Report
F38
9. Investments
The change in investments is as follows:
EMG Skookumchuck
Tent
Mountain
EIP
Ekona
Total
Classification
Equity-
accounted
Equity-
accounted
Equity-
accounted
FVTPL
FVTOCI
Balance, Dec. 31, 2022
12
105
—
11
1
129
Investment
—
—
10
4
—
14
Equity (loss) income
(4)
8
—
—
—
4
Distributions received
—
(6)
—
—
—
(6)
Changes in foreign
exchange rates
—
(3)
—
—
—
(3)
Balance, Dec. 31, 2023
8
104
10
15
1
138
Investment
—
—
3
5
—
8
Equity (loss) income
(4)
10
(1)
—
—
5
Distributions received
—
(5)
—
—
—
(5)
Changes in foreign
exchange rates
2
9
—
—
—
11
Net change in fair value
recognized in earnings
—
—
—
2
—
2
Balance, Dec. 31, 2024
6
118
12
22
1
159
Equity-accounted Investments
The Company’s investments in joint ventures and
associates that are accounted for using the equity method
consist of its investments in Skookumchuck, EMG
International, LLC (EMG) and Tent Mountain Renewable
Energy Complex (Tent Mountain).
EMG International, LLC
TransAlta holds a 30 per cent interest in EMG, a
wastewater treatment processing company. Earnings are
derived from the design and construction of wastewater
treatment facilities.
Skookumchuck Wind Project
TransAlta holds a 49 per cent membership interest in SP
Skookumchuck Investment, LLC. Skookumchuck is a 136.8
MW wind project located in Lewis and Thurston counties
near Centralia in Washington state. The project has a 20-
year PPA with Puget Sound Energy.
Tent Mountain Pumped Hydro
Development Project
On April 24, 2023, the Company acquired a 50 per cent
interest in Tent Mountain, an early-stage 320 MW pumped
hydro energy storage development project, located in
southwest Alberta, from Evolve Power Ltd., formerly
known as Montem Resources Limited. The acquisition
included land rights, fixed assets and intellectual property
associated with the pumped hydro development project.
The Company paid Evolve $8 million on closing and made
additional investments of $2 million during the balance of
2023. On Oct. 8, 2024, the Company increased its interest
from 50 to 60 per cent by converting an outstanding loan
receivable balance into an additional interest in the
partnership. Additional contingent payments of up to
$17 million may become payable to Evolve based on the
achievement of specific development and commercial
milestones. The Company and Evolve jointly control Tent
Mountain, with the result that the Company accounts for
its interest in the joint venture as an investment using the
equity method.
F39
TransAlta Corporation
2024 Integrated Report
Summarized financial information on the results of operations relating to the Company’s pro-rata interests in
Skookumchuck, EMG and Tent Mountain, is as follows:
Year ended Dec. 31
2024
2023
2022
Results of operations
Revenues and other operating income
28
22
24
Expenses
(23)
(18)
(15)
Proportionate share of net earnings
5
4
9
Other Investments
Energy Impact Partners
On May 6, 2022, the Company entered into a commitment
to invest US$25 million over the next four years in Energy
Impact Partners (EIP) Deep Decarbonization Frontier Fund
1 (the Frontier Fund). The investment in the Frontier Fund
provides the Company with a portfolio approach to
investing in emerging technologies and the opportunity to
identify, pilot, commercialize and bring to market emerging
technologies that will facilitate the transition to net-zero
emissions. The investment is accounted for at FVTPL.
Ekona Power Inc.
On Feb. 1, 2022, the Company made an equity investment
of $2 million in Ekona's Class B Preferred Shares. The
investment supports the commercialization of Ekona’s
novel methane pyrolysis technology platform, which is
being developed to produce cleaner and lower-cost
turquoise hydrogen. The Company has irrevocably elected
to measure its investment in Ekona at FVTOCI.
10. Interest Expense
The components of interest expense are as follows:
2024
2023
2022
Interest on debt
197
203
164
Interest on exchangeable debentures (Note 26)
31
29
29
Interest on exchangeable preferred shares (Note 26)
28
28
28
Capitalized interest (Note 19)
(16)
(57)
(16)
Interest on lease liabilities
10
9
7
Credit facility fees, bank charges and other interest
21
21
27
Tax shield on tax equity financing (Note 25)
3
—
(2)
Accretion of provisions (Note 24)
50
48
49
Interest expense
324
281
286
TransAlta Corporation
2024 Integrated Report
F40
11. Income Taxes
Consolidated Statements of Earnings
I. Rate Reconciliation
Year ended Dec. 31
2024
2023
2022
Earnings before income taxes
319
880
353
Net earnings attributable to non-controlling interests not subject to tax
(10)
(80)
(94)
Adjusted earnings before income taxes
309
800
259
Statutory Canadian federal and provincial income tax rate (%)
23.3%
23.4%
23.4%
Expected income tax expense
72
187
61
(Decrease) increase in income taxes resulting from:
Differences in effective foreign tax rates
(6)
9
(1)
Non-deductible expense(1)
46
58
130
Non-taxable income
(10)
—
—
Taxable capital loss (gain)
1
(2)
18
Deferred income tax recovery related to temporary difference on investment
in subsidiaries
(5)
(3)
(2)
Reversal of unrecognized deferred income tax assets
(13)
(178)
(24)
Statutory and other rate differences
(1)
1
(3)
Adjustments in respect of deferred income tax of previous years
(11)
1
6
Other
7
11
7
Income tax expense
80
84
192
Effective tax rate (%)
26%
11%
74%
(1)
This amount is related to current tax adjustments in the U.S. to mitigate cash tax relating to the Base Erosion and Anti-Abuse Tax, Canadian non-
deductible penalties, and a tax adjustment relating to dividends on preferred shares, treated as interest for accounting purposes.
Global Minimum Tax Act
In response to the OECD Pillar Two Model rules, Canada
enacted the Global Minimum Tax Act (GMTA) on June 19,
2024. The GMTA provides for a minimum tax of 15 per
cent to be applied on a jurisdictional basis. The adoption
of the GMTA did not have a material impact on the
Company’s tax expense. IAS 12 contains a mandatory
temporary exception to recognizing and disclosing
information about deferred taxes related to Pillar Two.
The Company has applied this exception.
F41
TransAlta Corporation
2024 Integrated Report
II. Components of Income Tax Expense
The components of income tax expense are as follows:
Year ended Dec. 31
2024
2023
2022
Current income tax expense
143
50
65
Deferred income tax (recovery) expense related to the origination and
reversal of temporary differences
(45)
215
153
Deferred income tax recovery related to temporary difference on investment
in subsidiaries
(5)
(3)
(2)
Reversal of unrecognized deferred income tax assets(1)
(13)
(178)
(24)
Income tax expense
80
84
192
Current income tax expense
143
50
65
Deferred income tax (recovery) expense
(63)
34
127
Income tax expense
80
84
192
(1)
During the year ended Dec. 31, 2024, the Company recognized deferred tax assets of $13 million (2023 — $178 million, 2022 — $24 million). The
deferred income tax assets mainly relate to the tax benefits associated with tax losses related to the Company's directly owned U.S. operations and
other deductible differences. The Company has not recognized $152 million (2023 — $157 million) of deferred tax assets on the basis that it is not
probable that sufficient future taxable income would be available to utilize these tax assets.
Consolidated Statements of Changes in Equity
The aggregate current and deferred income tax related to items charged or credited to equity are as follows:
Year ended Dec. 31
2024
2023
2022
Income tax expense (recovery) related to:
Net impact related to cash flow hedges
53
27
(112)
Net impact related to hedges of foreign operations
(4)
1
(3)
Net impact related to net actuarial gains (losses)
3
(1)
12
Transaction costs for the acquisition of TransAlta Renewables
—
(2)
—
Income tax expense (recovery) reported in equity
52
25
(103)
TransAlta Corporation
2024 Integrated Report
F42
Consolidated Statements of Financial Position
Significant components of the Company’s deferred income tax assets (liabilities) are as follows:
As at Dec. 31
2024
2023(2)
Non-capital losses(1)
149
88
Future decommissioning and restoration costs
184
140
Property, plant and equipment
(646)
(528)
Investment in subsidiaries(2)
(60)
(63)
Risk management assets and liabilities, net
40
99
Employee future benefits and compensation plans
52
50
Foreign exchange differences
16
12
Other taxable temporary differences
(1)
(6)
Net deferred income tax liabilities, before unrecognized deferred income tax assets
(266)
(208)
Unrecognized deferred income tax assets
(152)
(157)
Net deferred income tax liabilities
(418)
(365)
(1)
Non-capital losses expire between 2031 and 2044. Net operating losses from U.S. operations have no expiration.
(2) Classification for the 2023 comparative figures has been conformed to the current period's presentation.
The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows:
As at Dec. 31
2024
2023
Deferred income tax assets(1)
52
21
Deferred income tax liabilities
(470)
(386)
Net deferred income tax liabilities
(418)
(365)
(1)
The deferred income tax assets presented on the Consolidated Statements of Financial Position are recoverable based on estimated future earnings
and tax planning strategies. The assumptions used in the estimate of future earnings are based on the Company’s long-range forecasts.
Contingencies
As of Dec. 31, 2024, the Company had recognized a net
liability of nil (2023 — nil) related to uncertain tax
positions.
F43
TransAlta Corporation
2024 Integrated Report
12. Non-Controlling Interests
The Company’s subsidiaries and operations that have non-controlling interests are as follows:
Subsidiary/Operation
Non-controlling interest owner
Non-controlling interest
as at Dec. 31, 2024
Non-controlling interest
as at Dec. 31, 2023
TransAlta
Cogeneration LP
Canadian Power Holdings Inc.
49.99%
49.99%
Kent Hills Wind LP
Natural Forces Technologies Inc.
17%
17%
TransAlta Renewables Inc.
Public shareholders
nil
nil(1)
(1)
Non-controlling interest from Jan. 1, 2023 to Oct. 4, 2023 was 39.9%.
TransAlta Cogeneration, LP (TA Cogen) operates a
portfolio of cogeneration facilities in Canada and owns 50
per cent of Sheerness, a dual-fuel generating facility.
Kent Hills Wind LP, a subsidiary, owns and operates the
167 MW Kent Hills (1, 2 and 3) wind facilities located in
New Brunswick.
TransAlta Renewables Inc. (TransAlta Renewables) was
previously a non-wholly owned publicly traded entity that
operated a portfolio of gas and renewable power
generation facilities and owned economic interests in
various other gas and renewable facilities of the Company.
On Oct. 5, 2023, the Company acquired all of the
outstanding common shares of TransAlta Renewables not
already owned, directly or indirectly, by TransAlta and
certain of its affiliates.
Summarized financial information relating to subsidiaries
with significant non-controlling interests is as follows:
TA Cogen
Year ended Dec. 31
2024
2023
2022
Revenues
167
290
347
Net earnings and total comprehensive income
9
121
143
Amounts attributable to the non-controlling interest:
Net earnings
9
80
91
Total comprehensive income
9
80
91
Distributions paid to Canadian Power Holdings Inc.
40
148
87
As at Dec. 31
2024
2023
Current assets
47
43
Long-term assets
130
193
Current liabilities
(48)
(41)
Long-term liabilities
(32)
(34)
Total equity
(97)
(161)
Equity attributable to Canadian Power Holdings Inc.
(46)
(79)
Non-controlling interest share (per cent)
49.99
49.99
TransAlta Corporation
2024 Integrated Report
F44
Kent Hills Wind LP
Prior to Oct. 5, 2023, financial information related to the 17 per cent non-controlling interest in Kent Hills Wind LP was
included in the financial information disclosed in TransAlta Renewables in this note.
Year ended Dec. 31
2024
2023(1)
Revenues
34
7
Net earnings and total comprehensive income
7
2
Amounts attributable to the non-controlling interest:
Net earnings and total comprehensive income
1
—
(1)
This represents financial information from Oct. 5, 2023 to Dec. 31, 2023. The net earnings attributable to non-controlling interest in Kent Hills Wind LP
prior to Oct. 5, 2023, is included in the disclosures for TransAlta Renewables.
As at Dec. 31
2024
2023
Current assets
33
35
Long-term assets
463
481
Current liabilities
(26)
(42)
Long-term liabilities
(174)
(188)
Total equity
(296)
(285)
Equity attributable to non-controlling interests
(51)
(48)
Non-controlling interest share (per cent)
17
17
TransAlta Renewables
The financial information disclosed below includes the 17 per cent non-controlling interest in Kent Hills Wind LP until
Oct. 5, 2023. TransAlta Renewables at Dec. 31, 2024, and Dec. 31, 2023, is a wholly owned subsidiary of the Company.
Refer to Note 4 for more details.
Year ended Dec. 31
2023(1)
2022
Revenues
303
560
Net earnings
56
74
Total comprehensive loss
(7)
(67)
Amounts attributable to the non-controlling interests:
Net earnings
21
20
Total comprehensive loss
(4)
(36)
Distributions paid to non-controlling interests(2)
75
100
(1)
Non-controlling interest share before the close of the transaction on Oct. 5, 2023. This represents financial information from Jan. 1, 2023 to Oct. 4,
2023.
(2) Distributions paid in the year ended Dec. 31, 2023 include $25 million of dividends declared in the fourth quarter of 2022.
F45
TransAlta Corporation
2024 Integrated Report
13. Trade and Other Receivables and Accounts Payable,
accrued liabilities and other current liabilities
As at Dec. 31
2024
2023
Trade accounts receivable
570
600
Collateral provided (Note 15)
124
145
Current portion of finance lease receivables (Note 17)
30
19
Current portion of loan receivable (Note 23)
1
1
Income taxes receivable
42
42
Trade and other receivables
767
807
As at Dec. 31
2024
2023
Accounts payable and accrued liabilities
694
772
Income taxes payable
23
9
Interest payable
17
16
Current portion of contract liabilities (Note 5)
12
3
Liabilities Held for Sale
1
—
Collateral held (Note 15)
9
9
Accounts payable, accrued liabilities and other current liabilities
756
809
TransAlta Corporation
2024 Integrated Report
F46
14. Financial Instruments
A. Financial Assets and Liabilities — Classification and Measurement
Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost.
Carrying value as at Dec. 31, 2024
Derivatives
used for
hedging
Derivatives
held for
trading
(FVTPL)
Amortized
cost
Other
financial
assets
and
liabilities
(FVTPL)
Other
financial
assets
(FVOCI)
Total
Financial assets
Cash and cash equivalents(1)
—
—
337
—
—
337
Restricted cash
—
—
69
—
—
69
Trade and other receivables(2)
—
—
725
—
—
725
Long-term portion of finance lease
receivables
—
—
305
—
—
305
Long-term portion of loan receivable(3)
—
—
24
—
—
24
Other investments(4)
—
—
—
22
1
23
Risk management assets
Current
45
273
—
—
—
318
Long-term
—
93
—
—
—
93
Financial liabilities
Bank overdraft
—
—
1
—
—
1
Accounts payable, accrued liabilities and
other current liabilities(5)
—
—
720
—
—
720
Contingent consideration
—
—
—
81
—
81
Dividends payable
—
—
49
—
—
49
Risk management liabilities
Current
—
277
—
—
—
277
Long-term
—
305
—
—
—
305
Credit facilities, long-term debt and lease
liabilities(6)
—
—
3,808
—
— 3,808
Exchangeable securities
—
—
750
—
—
750
(1)
Includes cash equivalents of nil.
(2) Excludes income taxes receivable.
(3) Included in other assets. Refer to Note 23.
(4) Included in investments. Refer to Note 9.
(5) Excludes the current portion of contract liabilities, current income taxes payable and liabilities held for sale.
(6) Includes current portion.
F47
TransAlta Corporation
2024 Integrated Report
Carrying value as at Dec. 31, 2023
Derivatives
used for
hedging
Derivatives
held for
trading
(FVTPL)
Amortized
cost
Other
financial
assets
(FVTPL)
Other
financial
assets
(FVTOCI)
Total
Financial assets
Cash and cash equivalents(1)
—
—
348
—
—
348
Restricted cash
—
—
69
—
—
69
Trade and other receivables(2)
—
—
765
—
—
765
Long-term portion of finance lease
receivables
—
—
171
—
—
171
Long-term portion of loan receivable(3)
—
—
25
—
—
25
Other investments(4)
—
—
—
15
1
16
Risk management assets
Current
—
151
—
—
—
151
Long-term
—
52
—
—
—
52
Financial liabilities
Bank overdraft
—
—
3
—
—
3
Accounts payable, accrued liabilities and
other current liabilities(5)
—
—
797
—
—
797
Dividends payable
—
—
49
—
—
49
Risk management liabilities
Current
125
189
—
—
—
314
Long-term
80
194
—
—
—
274
Credit facilities, long-term debt and
lease liabilities(6)
—
—
3,466
—
— 3,466
Exchangeable securities
—
—
744
—
—
744
(1)
Includes cash equivalents of nil.
(2) Excludes income taxes receivable.
(3) Included in other assets. Refer to Note 23.
(4) Included in investments. Refer to Note 9.
(5) Excludes the current portion of contract liabilities, current income taxes payable and liabilities held for sale.
(6) Includes current portion.
B. Fair Value of Financial Instruments
The fair value of a financial instrument is the price that
would be received when selling the asset or paid to
transfer the associated liability in an orderly transaction
between market participants at the measurement date.
Fair values can be determined by observing quoted prices
for the instrument in active markets to which the Company
has access. In the absence of an active market, the
Company determines fair values based on valuation
models or by reference to other similar products in active
markets. Fair values determined using valuation models
require the use of assumptions. In determining those
assumptions, the Company looks primarily to external
readily observable market inputs. However, if these are
not available, the Company uses inputs that are not based
on observable market data.
TransAlta Corporation
2024 Integrated Report
F48
I. Level I, II and III Fair Value Measurements
The Level I, II and III classifications in the fair value
hierarchy used by the Company are defined below. The
fair value measurement of a financial instrument is
included in only one of the three levels, the determination
of which is based on the lowest level input that is
significant to the derivation of the fair value. The Level III
classification is the lowest level classification in the fair
value hierarchy.
a. Level I
Fair values are determined using inputs that are quoted
prices (unadjusted) in active markets for identical assets
or liabilities that the Company has the ability to access at
the measurement date. In determining Level I fair values,
the Company uses quoted prices for identically traded
commodities obtained from active exchanges such as the
New York Mercantile Exchange.
b. Level II
Fair values are determined, directly or indirectly, using
inputs that are observable for the asset or liability.
Fair values falling within the Level II category are
determined through the use of quoted prices in active
markets, which in some cases are adjusted for factors
specific to the asset or liability, such as basis, credit
valuation and location differentials.
The Company’s commodity risk management Level II
financial instruments include over-the-counter derivatives
with values based on observable commodity futures
curves and derivatives with inputs validated by broker
quotes or other publicly available market data providers.
Level II fair values are also determined using valuation
techniques,
such
as
option
pricing
models
and
interpolation
formulas,
where
the
inputs
are
readily observable.
In determining Level II fair values of other risk
management assets and liabilities, the Company uses
observable inputs other than unadjusted quoted prices
that are observable for the asset or liability, such as
interest rate yield curves and currency rates. For certain
financial instruments where insufficient trading volume or
lack of recent trades exists, the Company relies on similar
interest or currency rate inputs and other third-party
information such as credit spreads.
c. Level III
Fair values are determined using inputs for the assets or
liabilities that are not readily observable.
The Company may enter into commodity transactions for
which market-observable data is not available. In these
cases, Level III fair values are determined using valuation
techniques such as mark-to-forecast and mark-to-model.
For mark-to-model valuations, derivative pricing models,
regression-based models and scenario analysis simulation
models may be employed. The model inputs may be based
on historical data such as unit availability, transmission
congestion, demand profiles for individual non-standard
deals and structured products and/or volatility and
correlations between products derived from historical
price relationships. For assets and liabilities that are
recognized at fair value on a recurring basis, the Company
determines whether transfers have occurred between
levels in the hierarchy by re-assessing categorization
(based on the lowest level input that is significant to the
fair value measurement as a whole) at the end of each
reporting period.
The Company also has various commodity contracts with
terms that extend beyond a liquid trading period. As
forward market prices are not available for the full period
of these contracts, the value of these contracts is derived
by reference to a forecast that is based on a combination
of external and internal fundamental modelling, including
discounting. As a result, these contracts are classified
in Level III.
II. Commodity Risk Management Assets
and Liabilities
Commodity risk management assets and liabilities include
risk management assets and liabilities that are used in the
energy marketing and generation segments in relation to
trading activities and certain contracting activities. To the
extent applicable, changes in net risk management assets
and liabilities for non-hedge positions are reflected within
earnings of these businesses.
Commodity
risk
management
assets
and
liabilities
classified by fair value levels as at Dec. 31, 2024, are as
follows: Level I – $12 million net liability (Dec. 31, 2023 –
$13 million net liability), Level II – $2 million net liability
(Dec. 31, 2023 – $244 million net liability) and Level III –
$153 million net liability (Dec. 31, 2023 – $147 million
net liability).
Significant changes in commodity net risk management
assets (liabilities) during the year ended Dec. 31, 2024, are
primarily attributable to contract settlements and volatility
in market prices across multiple markets on both existing
contracts and new contracts.
F49
TransAlta Corporation
2024 Integrated Report
The following table summarizes the key factors impacting the fair value of the Level III commodity risk management
assets and liabilities by classification during the years ended Dec. 31, 2024 and 2023, respectively:
Year ended Dec. 31, 2024
Year ended Dec. 31, 2023
Hedge
Non-hedge
Total
Hedge
Non-hedge
Total
Opening balance
—
(147) (147)
(347)
(435) (782)
Changes attributable to:
New contracts added(1)
—
3
3
—
—
—
Market price changes on existing contracts
—
(49)
(49)
(123)
(6)
(129)
Market price changes on new contracts
—
27
27
—
18
18
Contracts settled
—
23
23
256
269
525
Change in foreign exchange rates
—
(10)
(10)
9
7
16
Transfers out of Level III(2)
—
—
—
205
—
205
Net risk management assets (liabilities) at end of year
—
(153) (153)
—
(147)
(147)
Additional Level III information:
Losses recognized in other comprehensive loss
—
—
—
(114)
—
(114)
Total (losses) gains included in earnings before income
taxes
—
(32)
(32)
(256)
19 (237)
Unrealized (losses) gains included in earnings before
income taxes relating to net assets (liabilities) held at
year end
—
(9)
(9)
—
288
288
(1)
New contracts added in 2024 represent the contracts acquired from Heartland.
(2) The Company has a long-term fixed price power sale contract in the U.S. for delivery of power. The fair value was transferred out of Level III to Level II
as at Dec. 31, 2023 as the forward price curve was based on observable market prices for the remaining duration of the contract.
The Company has a Commodity Exposure Management
Policy that governs both the commodity transactions
undertaken in its proprietary trading business and those
undertaken to manage commodity price exposures in its
generation business. This Policy defines and specifies the
controls and management responsibilities associated with
commodity trading activities, as well as the nature and
frequency of required reporting of such activities.
The Company's risk management department determines
methodologies and procedures regarding commodity risk
management Level III fair value measurements. Level III
fair values are primarily calculated within the Company’s
energy trading risk management processes. These
calculations are based on underlying contractual data as
well
as
observable
and
non-observable
inputs.
Development of non-observable inputs requires the use of
judgment. To ensure reasonability, the Level III fair value
measurements are reviewed and validated by the risk
management and finance departments. Review occurs
formally on a quarterly basis or more frequently if daily
review and monitoring procedures identify unexpected
changes to fair value or changes to key parameters.
As at Dec. 31, 2024, the total Level III risk management
asset balance was $110 million (Dec. 31, 2023 – $56
million) and the Level III risk management liability balance
was $263 million (Dec. 31, 2023 – $203 million). The net
risk management liabilities increased mainly due to market
price changes offset by settled contracts. The information
on risk management contracts or groups of risk
management contracts that are included in Level III
measurements and the related unobservable inputs and
sensitivities are outlined in the following table. These
include the effects on fair value of discounting, liquidity
and credit value adjustments; however, the potential
offsetting effects of Level II positions are not considered.
Sensitivity ranges for the base fair values are determined
using reasonably possible alternative assumptions for the
key unobservable inputs, which may include forward
commodity prices, volatility in commodity prices and
correlations, delivery volumes, escalation rates and cost of
supply.
TransAlta Corporation
2024 Integrated Report
F50
As at
Dec. 31, 2024
Description
Valuation
technique
Unobservable input
Reasonably possible change
Sensitivity(1)
Coal
transportation
–
U.S.
Numerical
derivative valuation
Volatility
80% to 120%
+1
Rail rate escalation
0% to 10%
-1
Long-term wind energy
sale — Eastern U.S.
Long-term price
forecast
Illiquid future power prices
(per MWh)
Price decrease
or increase of US$6
+42
Illiquid future REC(2) prices
(per unit)
Price decrease of US$12
or increase of US$8
Wind discounts
0% decrease or 6% increase
-30
Long-term wind energy
sale — Canada
Long-term price
forecast
Illiquid future power prices
(per MWh)
Price decrease of $57
or increase of $10
+53
Wind discounts
15% decrease or 5% increase
-17
Long-term wind energy
sale — Central U.S.
Long-term price
forecast
Illiquid future power prices
(per MWh)
Price decrease of US$4
or increase of US$3
+84
Wind discounts
2% decrease or 2% increase
-77
(1)
Sensitivity represents the total increase or decrease in recognized fair value that could arise from the use of the reasonably possible changes of all
unobservable inputs.
(2) Renewable energy credits
As at
Dec. 31, 2023
Description
Valuation
technique
Unobservable input
Reasonably possible change
Sensitivity(1)
Coal transportation —
U.S.
Numerical derivative
valuation
Volatility
80% to 120%
+6
Rail rate escalation
0% to 10%
-4
Long-term wind energy
sale — Eastern U.S.
Long-term price
forecast
Illiquid future power prices
(per MWh)
Price decrease
or increase of US$6
+24
Illiquid future REC prices
(per unit)
Price decrease of US$12
or increase of US$8
Wind discounts
0% decrease or 9% increase
-28
Long-term wind energy
sale — Canada
Long-term price
forecast
Illiquid future power prices
(per MWh)
Price decrease of $81
or increase of $5
+65
Wind discounts
16% decrease or 5% increase
-23
Long-term wind energy
sale — Central U.S.
Long-term price
forecast
Illiquid future power prices
(per MWh)
Price decrease of US$1
or increase of US$2
+81
Wind discounts
5% decrease or 2% increase
-36
(1)
Sensitivity represents the total increase or decrease in recognized fair value that would arise from the use of the reasonably possible changes of all
unobservable inputs.
a. Coal Transportation – U.S.
The Company has a coal rail transport agreement that
includes an upside sharing mechanism until Dec. 31, 2025.
Option pricing techniques have been utilized to value the
obligation
associated
with
this
component
of
the agreement.
The key unobservable inputs used in the valuation include
option volatility and rail rate escalation. Option volatility
and rail rate escalation ranges have been determined
based on historical data and professional judgment.
b. Long-Term Wind Energy Sale – Eastern U.S.
The Company is party to a long-term contract for
differences (CFD) for the offtake of 100 per cent of the
F51
TransAlta Corporation
2024 Integrated Report
generation from its 90 MW Big Level wind facility. The
CFD, together with the sale of electricity generated into
the PJM Interconnection at the prevailing real-time energy
market price, achieve the fixed contract price per MWh on
proxy generation. Under the CFD, if the market price is
lower than the fixed contract price, the customer pays the
Company the difference and if the market price is higher
than the fixed contract price, the Company refunds the
difference to the customer. The customer is also entitled
to the physical delivery of environmental attributes. The
contract matures in December 2034. The contract is
accounted for as a derivative with changes in fair value
presented in revenue.
The key unobservable inputs used in the valuation of the
contract are expected proxy generation volumes and non-
liquid forward prices for power, RECs and wind discounts.
c. Long-Term Wind Energy Sale – Canada
The Company is party to two Virtual Power Purchase
Agreements (VPPAs) for the offtake of 100 per cent of the
generation from its 130 MW Garden Plain wind facility. The
VPPAs, together with the sale of electricity generated into
the Alberta power market at the pool price, achieve the
fixed contract prices per MWh. Under the VPPAs, if the
pool price is lower than the fixed contract price, the
customer pays the Company the difference and if the pool
price is higher than the fixed contract price, the Company
refunds the difference to the customer. Customers are
also entitled to the physical delivery of environmental
attributes. Both VPPAs commenced on commercial
operation of the facility in August 2023, and extend for a
weighted average period of approximately 17 years.
The energy components of these contracts are accounted
for as derivatives, with changes in fair value presented
in revenue.
The key unobservable inputs used in the valuations of the
contracts are the non-liquid forward prices for power and
monthly wind discounts.
d. Long-Term Wind Energy Sale – Central U.S.
The Company is party to two long-term VPPAs for the
offtake of 100 per cent of the generation from its 302 MW
White Rock East and White Rock West wind power
facilities. The VPPAs, together with the sale of electricity
generated into the U.S. Southwest Power Pool (SPP)
market at the relevant price nodes, achieve the fixed
contract prices per MWh. Under the VPPAs, if the SPP
pricing is lower than the fixed contract price the customer
pays the Company the difference, and if the SPP pricing is
higher than the fixed contract price, the Company refunds
the difference to the customer. The customer is also
entitled to the physical delivery of environmental
attributes.
The
VPPAs
commenced
on
commercial
operation of the facilities in the first quarter of 2024.
The Company is also party to a VPPA for the offtake of 100
per cent of the generation from its 202 MW Horizon Hill
wind power project. The VPPA, together with the sale of
electricity generated into the SPP market at the relevant
price node, achieve the fixed contract price per MWh.
Under the VPPA, if the SPP pricing is lower than the fixed
contract price, the customer pays the Company the
difference and if the SPP pricing is higher than the fixed
contract price, the Company refunds the difference to the
customer. The customer is also entitled to the physical
delivery
of
environmental
attributes.
The
VPPA
commenced on commercial operation of the facility in the
second quarter of 2024.
The energy components of these contracts are accounted
for as derivatives, with changes in fair value presented in
revenue.
The key unobservable inputs used in the valuation of the
contracts are the non-liquid forward prices for power and
wind discounts.
III. Other Risk Management Assets
and Liabilities
Other risk management assets and liabilities primarily
include risk management assets and liabilities that are
used to manage exposures on non-energy marketing
transactions such as interest rates, the net investment in
foreign operations and other foreign currency risks. Hedge
accounting is not always applied.
Other risk management assets and liabilities with a total
net liability fair value of $4 million as at Dec. 31, 2024
(Dec. 31, 2023 – $19 million net asset) are classified as
Level II fair value measurements. The changes in other net
risk management assets and liabilities during the year
ended Dec. 31, 2024, are attributable to contracts
acquired through the Heartland acquisition (Note 4), offset
by
unfavorable
market
price
changes
on
existing
contracts, unfavorable foreign exchange rates on new
contracts entered into during 2024, and contracts settled
during 2024.
TransAlta Corporation
2024 Integrated Report
F52
IV. Other Financial Assets and Liabilities
The fair value of financial assets and liabilities measured at other than fair value is as follows:
Fair value(1)
Total
carrying
value(1)
Level I
Level II
Level III
Total
Exchangeable securities — Dec. 31, 2024
—
739
—
739
750
Long-term debt — Dec. 31, 2024
—
3,447
— 3,447
3,657
Loan receivable — Dec. 31, 2024
—
25
—
25
25
Exchangeable securities — Dec. 31, 2023
—
718
—
718
744
Long-term debt — Long-term debt — Dec. 31, 2023
—
3,104
—
3,104
3,323
Loan receivable — Dec. 31, 2023
—
26
—
26
26
(1)
Includes current portion.
The fair values of the Company’s debentures, senior notes
and exchangeable securities are determined using prices
observed in secondary markets. Non-recourse and other
long-term debt fair values are determined by calculating
an implied price based on a current assessment of the
yield to maturity.
The carrying amount of other short-term financial assets
and liabilities (cash and cash equivalents, restricted cash,
trade accounts receivable, collateral provided, bank
overdraft, accounts payable and accrued liabilities,
collateral held and dividends payable) approximates fair
value due to the liquid nature of the asset or liability. The
fair values of the finance lease receivables approximate
the carrying amounts as the amounts receivable represent
cash flows from repayments of principal and interest.
F53
TransAlta Corporation
2024 Integrated Report
C. Inception Gains and Losses
The majority of derivatives traded by the Company are
based on adjusted quoted prices on an active exchange or
extend beyond the time period for which exchange-based
quotes are available. The fair values of these derivatives
are determined using inputs that are not readily
observable. Refer to section B of this Note 14 above for
fair value Level III valuation techniques used. In some
instances, a difference may arise between the fair value of
a financial instrument at initial recognition (the transaction
price) and the amount calculated through a valuation
model. This unrealized gain or loss at inception is
recognized in net earnings (loss) only if the fair value of
the instrument is evidenced by a quoted market price in an
active market, observable current market transactions that
are substantially the same, or a valuation technique that
uses observable market inputs. Where these criteria are
not met, the difference is deferred on the Consolidated
Statements of Financial Position in risk management
assets or liabilities and is recognized in net earnings (loss)
over the term of the related contract.
The difference between the transaction price and the fair value determined using a valuation model, yet to be
recognized in net earnings (loss) and a reconciliation of changes is as follows:
As at Dec. 31
2024
2023
2022
Unamortized net gain (loss) at beginning of year
3
(213)
(131)
New inception gains (losses)(1)
31
47
(37)
Change resulting from amended contract(2)
—
190
—
Change in foreign exchange rates
(3)
6
(10)
Amortization recorded in net earnings during the year
(20)
(27)
(35)
Unamortized net gain (loss) at end of year
11
3
(213)
(1)
During 2024 and 2023, the Company entered into long-term fixed price power sale contracts with certain of its U.S. customers that resulted in new
inception losses due to the difference between the fixed PPA price and future estimated market prices. There are other key factors, such as project
economics and incentives, that influence the long-term power price for renewable projects outside of the power price curve, which is not liquid for the
majority of the duration of the PPA.
(2) During 2023, the Company entered into certain contract amendments related to the Horizon Hill and White Rock wind projects. These amendments
were mainly specific to obtaining price increases over the contract term. Accordingly, certain inception loss calibration adjustments were recognized
within the risk management liability.
TransAlta Corporation
2024 Integrated Report
F54
15. Risk Management Activities
A. Risk Management Strategy
The Company is exposed to market risk from changes in
commodity prices, foreign exchange rates, interest rates,
credit risk and liquidity risk. These risks affect the
Company’s earnings and the value of associated financial
instruments that the Company holds. In certain cases, the
Company seeks to minimize the effects of these risks by
using derivatives to hedge its risk exposures. The
Company’s risk management strategy, policies and
controls are designed to ensure that the risks it assumes
comply with the Company’s internal objectives and
risk tolerance.
The
Company
has
two
primary
streams
of
risk
management activities: (i) financial exposure management;
and (ii) commodity exposure management. Within these
activities,
risks
identified
for
management
include
commodity risk, interest rate risk, liquidity risk, equity price
risk and foreign currency risk.
The Company seeks to minimize the effects of commodity
risk, interest rate risk and foreign currency risk by using
derivative financial instruments to hedge risk exposures.
Of these derivatives, the Company may apply hedge
accounting to those hedging commodity price risk, interest
rate risk and foreign currency risk.
The use of financial derivatives is governed by the
Company’s policies approved by the Board, which provide
written principles on commodity risk, interest rate risk,
liquidity risk, equity price risk and foreign currency risk, as
well as the use of financial derivatives and non-derivative
financial instruments.
Liquidity risk, credit risk and equity price risk are managed
through
means
other
than
derivatives
or
hedge
accounting.
The Company enters into various derivative transactions
as well as other contracting activities that do not qualify
for hedge accounting or where a choice was made not to
apply hedge accounting. As a result, the related assets
and liabilities are classified as derivatives at fair value
through profit and loss. The net realized and unrealized
gains or losses from changes in the fair value of these
derivatives are reported in net earnings in the period the
change occurs.
The Company designates certain derivatives as hedging
instruments to hedge commodity price risk, foreign
currency exchange risk in cash flow hedges and hedges of
net investments in foreign operations. Hedges of foreign
exchange risk on firm commitments are accounted for as
cash flow hedges.
At the inception of the hedge relationship, the Company
documents
the
relationship
between
the
hedging
instrument and the hedged item, along with its risk
management objectives and its strategy for undertaking
various hedge transactions. At the inception of the hedge
and on an ongoing basis, the Company also documents
whether the hedging instrument is effective in offsetting
changes in fair values or cash flows of the hedged item
attributable to the hedged risk, which is when the hedging
relationships
meet
all
of
the
following
hedge
effectiveness requirements:
• There is an economic relationship between the hedged
item and the hedging instrument;
• The effect of credit risk does not dominate the value
changes that result from that economic relationship; and
• The hedge ratio of the hedging relationship is the same
as that resulting from the quantity of the hedged item
that the Company actually hedges and the quantity of
the hedging instrument that the entity actually uses to
hedge that quantity of hedged item.
If a hedging relationship ceases to meet the hedge
effectiveness requirement relating to the hedge ratio, but
the risk management objective for that designated
hedging relationship remains the same, the Company
adjusts the hedge ratio of the hedging relationship so that
it continues to meet the qualifying criteria.
F55
TransAlta Corporation
2024 Integrated Report
B. Net Risk Management Assets and Liabilities
Aggregate net risk management assets (liabilities) are as follows:
As at Dec. 31, 2024
Cash flow
hedges
Not
designated
as a hedge
Total
Commodity risk management
Current
45
8
53
Long-term
—
(220)
(220)
Net commodity risk management assets (liabilities)
45
(212)
(167)
Other
Current
—
(12)
(12)
Long-term
—
8
8
Net other risk management liabilities
—
(4)
(4)
Total net risk management assets (liabilities)
45
(216)
(171)
As at Dec. 31, 2023
Cash flow
hedges
Not
designated
as a hedge
Total
Commodity risk management
Current
(125)
(53)
(178)
Long-term
(80)
(146)
(226)
Net commodity risk management liabilities
(205)
(199)
(404)
Other
Current
—
15
15
Long-term
—
4
4
Net other risk management liabilities
—
19
19
Total net risk management liabilities
(205)
(180)
(385)
TransAlta Corporation
2024 Integrated Report
F56
Netting Arrangements
Information about the Company’s financial assets and liabilities that are subject to enforceable master netting
arrangements or similar agreements is as follows:
As at Dec. 31, 2024
Gross amounts
of recognized
financial assets
(liabilities)
Amounts
set off
Net amounts
included on
the statement
of financial
position
Master netting
arrangements(1)
Net amount
Current risk management assets
686
(421)
265
(18)
247
Long-term risk management assets
153
(59)
94
(1)
93
Current risk management liabilities
(662)
421
(241)
18
(223)
Long-term risk management liabilities
(128)
59
(69)
1
(68)
Trade and other receivables(2)
1,519
(1,273)
246
(7)
239
Accounts payable and accrued
liabilities(2)
(1,470)
1,273
(197)
7
(190)
As at Dec. 31, 2023
Gross amounts
of recognized
financial assets
(liabilities)
Amounts
set off
Net amounts
included on
the statement
of financial
position
Master netting
arrangements(1)
Net amount
Current risk management assets
528
(355)
173
(7)
166
Long-term risk management assets
161
(91)
70
(2)
68
Current risk management liabilities
(504)
355
(149)
7
(142)
Long-term risk management liabilities
(145)
91
(54)
2
(52)
Trade and other receivables(2)
789
(646)
143
(11)
132
Accounts payable and accrued
liabilities(2)
(760)
646
(114)
11
(103)
(1)
Amounts not set off in the Consolidated Statements of Financial Position.
(2) The trade and other receivables and accounts payable and accrued liabilities include amounts related to collateral provided and held. Refer to
Note 15(F) below for further details.
F57
TransAlta Corporation
2024 Integrated Report
C. Nature and Extent of Risks Arising from
Financial Instruments
I. Market Risk
a. Commodity Price Risk Management
The Company has exposure to movements in certain
commodity prices in both its electricity generation and
proprietary trading businesses, including the market price
of electricity and fuels used to produce electricity. Most of
the Company’s electricity generation and related fuel
supply contracts are considered to be contracts for
delivery or receipt of a non-financial item in accordance
with the Company’s expected own use requirements and
are not considered to be financial instruments. As such,
the discussion related to commodity price risk is limited to
the Company’s proprietary trading business, VPPAs and
other long-term contracts that are derivatives and
commodity derivatives used in hedging relationships
associated
with
the
Company’s
electricity
generating activities.
To mitigate the risk of adverse commodity price changes,
the Company uses three tools:
• A framework of risk controls;
• A predefined hedging plan, including fixed price financial
power swaps and long-term physical power sale
contracts to hedge commodity price for electricity
generation; and
• A committee dedicated to overseeing the risk and
compliance program in trading and ensuring the
existence of appropriate controls, processes, systems
and procedures to monitor adherence to the program.
The Company has executed commodity price hedges for
its Centralia thermal facility, including a long-term physical
power sale contract, and may, at times, execute hedges
for its electricity price exposure in Alberta using fixed price
financial swaps or other similar instruments. Both hedging
strategies fall under the Company’s risk management
strategy used to hedge commodity price risk.
Market risk exposures are measured using Value at Risk
(VaR) supplemented by sensitivity analysis. There has
been no change to the Company’s exposure to market
risks or the manner in which these risks are managed or
measured. Position sizes and trade strategies were
adjusted to remain within the Company's risk framework.
i. Commodity Price Risk Management – Proprietary Trading
The Company’s Energy Marketing segment conducts
proprietary trading activities and uses a variety of
instruments to manage risk, earn trading revenue and gain
market information.
In compliance with the Company's Commodity Exposure
Management Policy, proprietary trading activities are
subject to limits and controls, including VaR limits. The
Board approves the limit for total VaR from proprietary
trading activities. VaR is the most commonly used metric
employed to track and manage the market risk associated
with trading positions.
A VaR measure gives, for a specific confidence level, an
estimated maximum pre-tax loss that could be incurred
over a specified period of time. VaR is used to determine
the potential change in value of the Company’s proprietary
trading portfolio, over a three-day period within a 95 per
cent confidence level, resulting from normal market
fluctuations. VaR is estimated using the historical variance/
covariance
approach.
This
measure
has
inherent
limitations. VaR relies on historical data, assuming that
past price movements will reflect future market risks.
Consequently, it may only be meaningful under normal
market conditions and does not account for extreme
market events. In addition, the use of a three-day
measurement period implies that positions can be
unwound or hedged within three days, although this may
not be possible if the market becomes illiquid.
Changes in market prices associated with proprietary
trading activities affect net earnings in the period that the
price changes occur. VaR at Dec. 31, 2024, associated
with the Company’s proprietary trading activities was $3
million (2023 — $4 million, 2022 — $4 million).
ii. Commodity Price Risk – Generation
The generation segments utilize various commodity
contracts to manage the commodity price risk associated
with electricity generation, fuel purchases, emissions and
byproducts, as considered appropriate. A Commodity
Exposure Management Policy is prepared and approved
annually, which outlines the intended hedging strategies
associated with the Company’s generation assets and
related commodity price risks. Controls also include
restrictions on authorized instruments, management
reviews on individual portfolios and approval of asset
transactions that could add potential volatility to the
Company’s reported net earnings.
TransAlta Corporation
2024 Integrated Report
F58
VaR at Dec. 31, 2024, associated with the Company’s
commodity derivative instruments used in generation
hedging activities was $8 million (2023 — $23 million,
2022 — $97 million). For positions and economic hedges
that do not meet hedge accounting requirements or for
short-term optimization transactions such as buybacks
entered into to offset existing hedge positions, these
transactions are marked to the market value with changes
in market prices associated with these transactions
affecting net earnings in the period in which the price
change occurs. VaR at Dec. 31, 2024, associated with
these transactions was $13 million (2023 — $16 million,
2022 — $45 million).
For the market risk related to long-term power sale and
long-term wind energy sales contracts, refer to the Level
III measurements table and the related unobservable
inputs and sensitivities in Note 14(B)(II).
iii. Commodity Price Risk Management – Hedges
At Dec. 31, 2024, the Company had no outstanding
commodity derivative instruments designated as hedging
instruments, except for the long-term power sale - U.S.
contract.
iv. Commodity Price Risk Management – Non-Hedges
The Company’s outstanding commodity derivative instruments not designated as hedging instruments are as follows:
As at Dec. 31
2024
2023
Type
(thousands)
Notional
amount
sold
Notional
amount
purchased
Notional
amount
sold
Notional
amount
purchased
Electricity (MWh)
47,593
8,416
54,043
12,628
Natural gas (GJ)
2,122
79,194
50,949
209,348
Transmission (MWh)
—
292
—
856
Emissions (MWh)
167
370
212
804
Emissions (tonnes)
1,850
150
4,450
5,125
Coal (tonnes)
—
1,728
—
5,172
F59
TransAlta Corporation
2024 Integrated Report
b. Interest Rate Risk Management
Changes in interest rates can impact the Company’s
borrowing costs and cost of capital. Changes in the cost
of capital could affect the feasibility of new growth
initiatives. Interest rate risk also arises as the fair value of
future cash flows from a financial instrument fluctuates
due to changes in market interest rates.
The Company's syndicated credit facility, Term Facility,
Heartland Term Facility and the Poplar Creek non-
recourse bond are subject to floating interest rates, which
represent 23 per cent of the Company’s total long-term
debt as at Dec. 31, 2024 (2023 — 14 per cent). Interest
rate risk is managed with the use of derivatives.
In 2024, the Company had interest rate swap agreements
in place with a notional amount of $190 million, which are
not designated as hedges, whereby the Company receives
a variable rate of interest equal to the three-month CORRA
rate plus a 0.321 per cent premium, and pays interest at a
fixed rate equal to a weighted average of 1.64 per cent on
the notional amount.
The term and credit facilities with $545 million outstanding
(2023 — $400 million) reference Canadian Overnight Repo
Rate Average (CORRA) for Canadian-dollar drawings,
which replaced the Canadian Dollar Offered Rate (CDOR)
on July 1, 2024 as part of Interbank Offered Rate reform.
The Poplar Creek non-recourse bond with a face value as
at Dec. 31, 2024 of $76 million (2023 — $86 million) pays
interest based upon the three-month CORRA.
c. Currency Rate Risk
The Company has exposure to various currencies, such as
the U.S. dollar and the Australian dollar, as a result of
investments and operations in foreign jurisdictions, the net
earnings from those operations and the acquisition of
equipment and services from foreign suppliers.
The Company may enter into the following hedging
strategies to mitigate currency rate risk, including:
• Foreign exchange forward contracts to mitigate adverse
changes in foreign exchange rates on project-related
expenditures
and
distributions
received
in
foreign currencies;
• Foreign exchange forward contracts and cross-currency
swaps to manage foreign exchange exposure on foreign-
denominated debt not designated as a net investment
hedge; and
• Designating foreign currency debt as a hedge of the net
investment in foreign operations to mitigate the risk due
to fluctuating exchange rates related to certain
foreign subsidiaries.
The Company's target is to hedge a minimum of 60 per
cent of our forecasted foreign operating cash flows over a
four-year period. The U.S. exposure is managed with a
combination of interest expense on our U.S. dollar
denominated
debt
and
forward
foreign
exchange
contracts and the Australian exposure is managed with a
combination of interest expense on Australian-dollar
denominated
debt
and
forward
foreign
exchange
contracts.
i. Net Investment Hedges
When designating foreign currency debt as a hedge of the
Company’s net investment in foreign subsidiaries, the
Company has determined that the hedge is effective if the
foreign currency of the net investment is the same as the
currency of the hedge and therefore an economic
relationship is present.
The Company’s hedges of its net investment in foreign
operations were comprised of U.S.-dollar-denominated
long-term debt with a face value of US$300 million (2023
— US$370 million).
ii. Non-Hedges
The Company also uses foreign currency contracts to
manage its expected foreign operating cash flows and
foreign exchange forward contracts to manage foreign
exchange exposure on foreign-denominated debt not
designated as a net investment hedge. Hedge accounting
is not applied to these foreign currency contracts.
TransAlta Corporation
2024 Integrated Report
F60
As at Dec. 31
2024
2023
Notional
amount
sold
Notional
amount
purchased
Fair value
(liability)
asset
Maturity
Notional
amount
sold
Notional
amount
purchased
Fair value
(liability)
asset
Maturity
Foreign exchange forward contracts – foreign-denominated receipts/expenditures
AUD14
CAD10
(1)
2025-2028
AUD125
CAD113
(1)
2024-2027
USD419
CAD585
(13)
2025-2028
USD828
CAD1,113
19
2024-2027
USD101
AUD153
(9)
2025
USD100
AUD152
5
2024
Foreign exchange forward contracts – foreign-denominated debt
CAD192
USD140
8
2025
CAD190
USD140
(4)
2024
iii. Impacts of Currency Rate Risk
The possible effect on net earnings and OCI, due to
changes in foreign exchange rates associated with
financial instruments denominated in currencies other than
the Company’s functional currency, is outlined below.
The
sensitivity
analysis
has
been
prepared
using
management’s assessment that an average three cents
(2023 — three cents, 2022 — three cents) increase or
decrease in these currencies relative to the Canadian
dollar is a reasonable potential change over the
next quarter.
Year ended Dec. 31
2024
2023
2022
Currency
Net earnings
decrease(1)
OCI gain(1)(2)
Net earnings
decrease(1)
OCI gain(1)(2)
Net earnings
decrease(1)
OCI gain(1)(2)
USD
(17)
—
(11)
—
(12)
—
AUD
(3)
—
(3)
—
(2)
—
Total
(20)
—
(14)
—
(14)
—
(1)
These calculations assume an increase in the value of these currencies relative to the Canadian dollar. A decrease would have the opposite effect.
(2) The foreign exchange impact related to financial instruments designated as hedging instruments in net investment hedges has been excluded.
II. Credit Risk
Credit risk is the risk that customers or counterparties will
cause a financial loss for the Company by failing to
discharge their obligations and the risk to the Company
associated with changes in creditworthiness of entities
with which commercial exposures exist. The Company
actively manages its exposure to credit risk by assessing
the ability of counterparties to fulfil their obligations under
the related contracts before entering into such contracts.
The Company makes detailed assessments of the credit
quality of all counterparties and, where appropriate,
obtains corporate guarantees, cash collateral, third-party
credit insurance and/or letters of credit to support the
ultimate collection of these receivables. For commodity
trading and origination, the Company sets strict credit
limits for each counterparty and monitors exposures on a
daily basis. TransAlta uses standard agreements that allow
for the netting of exposures and often include margining
provisions. If credit limits are exceeded, TransAlta will
request collateral from the counterparty or halt trading
activities with the counterparty.
The Company uses external credit ratings, as well as
internal ratings in circumstances where external ratings
are not available, to establish credit limits for customers
and counterparties. The following table outlines the
Company’s maximum exposure to credit risk without
taking
into
account
collateral
held,
including
the
distribution of credit ratings, as at Dec. 31, 2024:
F61
TransAlta Corporation
2024 Integrated Report
Investment grade
(per cent)
Non-investment grade
(per cent)
Total
(per cent)
Total
amount
Trade and other receivables(1)
87
13
100
767
Long-term finance lease receivable
100
—
100
305
Risk management assets(1)
58
42
100
411
Loans receivable(2)
—
100
100
25
Total
1,508
(1)
Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.
(2) Includes $25 million loans receivable included within other assets with counterparties that have no external credit rating.
An impairment analysis is performed at each reporting
date using a provision matrix to measure expected credit
losses. The provision rates are based on segment
historical rates of default of trade receivables as well as
incorporating
forward-looking
credit
ratings
and
forecasted default rates. In addition to the calculation of
expected credit losses, TransAlta monitors key forward-
looking information as potential indicators that historical
bad debt percentages, forward-looking S&P credit ratings
and
forecasted default rates would no longer be
representative of future expected credit losses. The
calculation reflects the probability-weighted outcome, the
time value of money and reasonable and supportable
information that is available at the reporting date about
past events, current conditions and forecasts of future
economic conditions.
TransAlta evaluates the concentration of risk with respect
to trade receivables as low, as its customers are located in
several jurisdictions and industries. The Company did not
have material expected credit losses as at Dec. 31, 2024.
The Company’s maximum exposure to credit risk at Dec.
31, 2024, without taking into account collateral held or
right of set-off, is represented by the current carrying
amounts of receivables and risk management assets as
per the Consolidated Statements of Financial Position.
Letters of credit and cash are the primary types of
collateral held as security related to these amounts. The
maximum credit exposure to any one customer for
commodity trading operations and hedging, including the
fair value of open trading, net of any collateral held, at
Dec. 31, 2024, was $77 million (Dec. 31, 2023 – $23
million).
TransAlta Corporation
2024 Integrated Report
F62
III. Liquidity Risk
Liquidity risk relates to the Company’s ability to access
capital to be used for capital projects, debt refinancing,
proprietary trading activities, commodity hedging and
general corporate purposes. As at Dec. 31, 2024,
TransAlta maintains an investment grade rating from one
credit rating agency and one notch below investment
grade ratings from two credit rating agencies. Between
2025 and 2027, the Company has $400 million of debt
maturing, and an additional $666 million of scheduled non-
recourse debt and tax equity principal payments.
Collateral is posted based on negotiated terms with
counterparties, which can include the Company’s senior
unsecured credit rating as determined by certain major
credit rating agencies. Some of the Company’s derivative
instruments contain financial assurance provisions that
require collateral to be posted only if a material adverse
credit-related event occurs.
TransAlta manages liquidity risk by monitoring liquidity on
trading positions; preparing and revising longer-term
financing plans to reflect changes in business plans and
the market availability of capital; reporting liquidity risk
exposure for proprietary trading activities on a regular
basis to the Risk Management Committee, senior
management and the Audit, Finance and Risk Committee
(on behalf of the Board); and maintaining sufficient
undrawn committed credit lines to support potential
liquidity requirements. The Company does not use
derivatives or hedge accounting to manage liquidity risk. A
maturity analysis of the Company's financial liabilities is
as follows:
2025
2026
2027
2028
2029
2030 and
thereafter
Total
Bank overdraft
1
—
—
—
—
—
1
Accounts payable, accrued liabilities and other
current liabilities
756
—
—
—
—
—
756
Long-term debt(1)
Credit facilities(1)
400
—
—
145
—
—
545
Debentures
—
—
—
—
110
141
251
Senior notes
—
—
—
—
575
431
1,006
Non-recourse – Hydro
—
—
—
—
—
39
39
Non-recourse – Wind & Solar
69
68
69
74
42
248
570
Non-recourse and other – Gas
58
61
65
66
74
628
952
Non-recourse Heartland term facility
24
24
176
—
—
—
224
Tax equity financing
15
16
21
24
23
6
105
Exchangeable securities(2)
—
—
—
—
—
750
750
Commodity risk management (assets)
liabilities(3)
(55)
14
13
12
6
177
167
Other risk management (assets) liabilities
11
(1)
—
(1)
(1)
(4)
4
Lease liabilities
4
5
5
5
5
127
151
Interest on long-term debt and lease
liabilities(4)
205
178
169
151
136
649
1,488
Interest on exchangeable securities(2)(4)
53
53
53
52
12
—
223
Dividends payable
49
—
—
—
—
—
49
Total
1,590
418
571
528
982
3,192
7,281
(1)
Excludes impact of hedge accounting and derivatives.
(2) The exchangeable debentures are due May 1, 2039 and the exchangeable preferred shares are perpetual. However, a cash payment could occur after
Dec. 31, 2028, at the Company's option, if the exchangeable securities are not exchanged by Brookfield Renewable Partners or its affiliates
(collectively Brookfield). At Brookfield's option, the exchangeable securities are currently exchangeable into an equity ownership interest in TransAlta’s
Alberta Hydro Assets. (Note 26).
(3) Negative amount represents a receivable position or cash inflow.
(4) Not recognized as a financial liability on the Consolidated Statements of Financial Position and excludes the impact of interest rate swaps.
F63
TransAlta Corporation
2024 Integrated Report
IV. Equity Price Risk
Total Return Swaps
The Company has certain compensation, deferred and
restricted share unit programs, the values of which
depend on the common share price of the Company. The
Company has fixed a portion of the settlement cost of
these programs by entering into a total return swap for
which hedge accounting has not been applied. The total
return swap is cash settled every quarter based upon the
difference between the fixed price and the market price of
the Company’s common shares at the end of each quarter.
D. Hedging Instruments – Uncertainty of Future Cash Flows
The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount,
timing and uncertainty of future cash flows:
Maturity
2025
2026
2027
2028
2029
2030
Cash flow hedges
Commodity derivative instruments
Electricity
Notional amount (thousands of MWh)
2,628
—
—
—
—
—
Average price ($ per MWh)
86.25
—
—
—
—
—
E. Effects of Hedge Accounting on Financial Position and Performance
I. Effect of Hedges
The impact of the hedging instruments on the statement of financial position is as follows:
As at Dec. 31, 2024
Notional
amount
Carrying
amount
Line item in the statement
of financial position
Change in fair value
used for measuring
ineffectiveness
Commodity price risk
Cash flow hedges
Physical power sales(1)
2,628
45
Risk management assets
114
Foreign currency risk
Net investment hedges
Foreign-denominated debt
USD300
CAD431
Credit facilities, long-term
debt and lease liabilities
—
(1)
In thousands of MWh.
TransAlta Corporation
2024 Integrated Report
F64
As at Dec. 31, 2023
Notional
amount
Carrying
amount
Line item in the statement
of financial position
Change in fair value
used for measuring
ineffectiveness
Commodity price risk
Cash flow hedges
Physical power sales(1)
5,966
(205)
Risk management liabilities
(114)
Foreign currency risk
Net investment hedges
Foreign-denominated debt
USD370
CAD489
Credit facilities, long-term
debt and lease liabilities
—
(1)
In thousands of MWh.
The impact of the hedged items on the statement of financial position is as follows:
As at Dec. 31
2024
2023
Change in fair value
used for measuring
ineffectiveness
Cash flow
hedge
reserve(1)
Change in fair value
used for measuring
ineffectiveness
Cash flow
hedge
reserve(1)
Commodity price risk
Cash flow hedges
Power forecast sales – Centralia
114
65
(114)
(129)
Change in fair value
used for measuring
ineffectiveness
Foreign
currency
translation
reserve(1)
Change in fair value
used for measuring
ineffectiveness
Foreign
currency
translation
reserve(1)
Foreign currency risk
Net investment hedges
Net investment in foreign
subsidiaries
—
(34)
—
(36)
(1)
Net of tax. Included in AOCI.
The hedging gain or loss recognized in OCI before tax is equal to the change in fair value used for measuring
effectiveness for the net investment hedge. Ineffectiveness of $4 million in after-tax losses was reclassified from OCI to
net earnings during the year ended Dec. 31, 2024.
The impact of designated cash flow hedges on OCI and net earnings is:
Year ended Dec. 31, 2024
Effective portion
Ineffective portion
Derivatives in cash flow
hedging relationships
Pre-tax
gain
recognized
in OCI
Location of gain
reclassified from OCI
Pre-tax
(gain) loss
reclassified
from OCI
Location of (gain) loss
reclassified from OCI
Pre-tax
(gain) loss
recognized
in earnings
Commodity contracts
270
Revenue
(15)
Revenue
—
Forward starting interest
rate swaps
—
Interest expense
(8)
Interest expense
—
OCI impact
270
OCI impact
(23)
Net earnings impact
—
F65
TransAlta Corporation
2024 Integrated Report
Over the next 12 months, the Company estimates that
approximately $28 million of after-tax losses will be
reclassified from AOCI to net earnings. These estimates
assume constant natural gas and power prices, interest
rates and exchange rates over time; however, the actual
amounts that will be reclassified may vary based on
changes in these factors.
Year ended Dec. 31, 2023
Effective portion
Ineffective portion
Derivatives in cash flow
hedging relationships
Pre-tax
gain (loss)
recognized
in OCI
Location of (gain)
loss reclassified
from OCI
Pre-tax
(gain) loss
reclassified
from OCI
Location of (gain) loss
reclassified from OCI
Pre-tax
(gain) loss
recognized
in earnings
Commodity contracts
51 Revenue
83
Revenue
—
Forward starting interest
rate swaps
— Interest expense
(8) Interest expense
—
OCI impact
51 OCI impact
75
Net earnings impact
—
Year ended Dec. 31, 2022
Effective portion
Ineffective portion
Derivatives in cash flow
hedging relationships
Pre-tax
gain (loss)
recognized
in OCI
Location of (gain)
loss reclassified
from OCI
Pre-tax
(gain) loss
reclassified
from OCI
Location of (gain) loss
reclassified from OCI
Pre-tax
(gain) loss
recognized
in earnings
Commodity contracts
(747) Revenue
124
Revenue
—
Forward starting interest
rate swaps
53
Interest expense
2
Interest expense
—
OCI impact
(694) OCI impact
126
Net earnings impact
—
II. Effect of Non-Hedges
For the year ended Dec. 31, 2024, the Company
recognized a net unrealized loss of $7 million (2023 —
loss of $44 million, 2022 — loss of $384 million) related to
commodity derivatives.
For the year ended Dec. 31, 2024, a loss of $63 million
(2023 — gain of $11 million, 2022 — gain of $20 million)
related to foreign exchange and other derivatives was
recognized, which consists of net unrealized losses of
$36 million (2023 — gain of $27 million, 2022 — loss of
$11 million) and net realized losses of $27 million (2023 —
loss
of
$16
million,
2022
—
gains
of
$31 million), respectively.
TransAlta Corporation
2024 Integrated Report
F66
F. Collateral
I. Financial Assets Provided as Collateral
At Dec. 31, 2024, the Company provided $124 million
(Dec. 31, 2023 — $145 million) in cash and cash
equivalents as collateral to regulated clearing agents as
security for commodity trading activities. These funds are
held in segregated accounts by the clearing agents.
Collateral provided is included within trade and other
receivables in the Consolidated Statements of Financial
Position. At Dec. 31, 2024, the Company provided $21
million (Dec. 31, 2023 — $19 million) in surety bonds as
security for commodity trading activities.
II. Financial Assets Held as Collateral
At Dec. 31, 2024, the Company held $9 million (Dec. 31,
2023 — $9 million) in cash collateral associated with
counterparty
obligations.
Under
the
terms
of
the
contracts, the Company may be obligated to pay interest
on the outstanding balances and to return the principal
when the counterparties have met their contractual
obligations or when the amount of the obligation declines
as a result of changes in market value. Interest payable to
the counterparties on the collateral received is calculated
in accordance with each contract. Collateral held is related
to physical and financial derivative transactions in a net
asset position and is included in accounts payable and
accrued liabilities in the Consolidated Statements of
Financial Position.
III. Contingent Features in Derivative
Instruments
Collateral is posted in the normal course of business
based on the Company’s senior unsecured credit rating as
determined by certain major credit rating agencies. Certain
of the Company’s derivative instruments contain financial
assurance provisions that require collateral to be posted
only if a material adverse credit-related event occurs.
At Dec. 31, 2024, the Company had posted collateral of
$424 million (Dec. 31, 2023 — $392 million) in the form of
letters of credit on physical and financial derivative
transactions in a net liability position. Certain derivative
agreements contain credit-risk-contingent features, which
if triggered could result in the Company having to post an
additional $128 million (Dec. 31, 2023 — $154 million) of
collateral to its counterparties.
16. Inventory
The components of inventory are as follows:
As at Dec. 31
2024
2023
Parts, materials and supplies
85
72
Coal
27
38
Emission credits
18
45
Natural gas
4
2
Total
134
157
No inventory was pledged as security for liabilities.
As at Dec. 31, 2024, the Company holds 460,585 emission
credits in inventory that were purchased externally with a
recorded book value of $18 million (Dec. 31, 2023 —
962,548 emission credits with a recorded book value of
$45 million). The Company also has 2,109,491 (Dec. 31,
2023 — 3,121,837) of internally generated eligible
emission credits from the Company's Wind and Solar and
Hydro segments that have no recorded book value.
Emission credits can be sold externally or can be used to
offset future emission obligations from our gas facilities
located in Alberta, where the compliance price of carbon is
expected to increase, resulting in a reduced cash cost for
carbon compliance in the year of settlement.
During the second quarter of 2024, the Company used
978,894 emission credits with a carrying value of $22
million to settle a portion of the 2023 carbon compliance
obligation. This resulted in the Company recognizing a
reduction of $42 million in carbon compliance costs. The
compliance price of carbon for the 2023 obligation settled
was $65 per tonne. It increased to $80 per tonne in 2024.
During the second quarter of 2023, the Company settled
the 2022 carbon compliance obligation in cash. The
compliance price of carbon for the 2022 obligation settled
was $50 per tonne.
F67
TransAlta Corporation
2024 Integrated Report
17. Finance Lease Receivables
Amounts receivable under the Company’s finance leases include the Mount Keith 132kV expansion (2024), Northern
Goldfields solar facilities (2024 and 2023), the Poplar Creek cogeneration facility (2024 and 2023), the Muskeg River
and the Primrose cogeneration plants (2024) and are as follows:
As at Dec. 31
2024
2023
Minimum
lease
receipts
Present value
of minimum
lease
receipts
Minimum
lease
receipts
Present value
of minimum
lease
receipts
Within one year
48
47
28
28
Second to fifth years inclusive
185
159
112
98
More than five years
247
129
117
64
480
335
257
190
Less: unearned finance lease income
146
—
67
—
Add: unguaranteed residual value
1
—
—
—
Total finance lease receivables
335
335
190
190
Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease receivables (Note 13)
30
19
Long-term portion of finance lease receivables
305
171
Total finance lease receivables
335
190
During the first quarter of 2024, the Mount Keith 132kV
expansion was completed. As a result, the Company
derecognized
assets
under
construction
and
recognized a finance lease receivable of $48 million. On
Dec. 4, 2024, as part of the Heartland acquisition, the
Company recognized current and non-current finance
lease receivables of $8 million and $107 million,
respectively (refer to Note 4 for details).
18. Assets Held for Sale
The change in assets held for sale is as follows:
2024
2023
As at Jan. 1
—
—
Additions from acquisition of Heartland on Dec. 4, 2024 (Note 4)
80
—
Balance, Dec. 31
80
—
TransAlta Corporation
2024 Integrated Report
F68
19. Property, Plant and Equipment
A reconciliation of the changes in the carrying amount of PP&E is as follows:
Assets under
construction
Land
Hydro
Wind and
Solar
Gas
generation
Energy
Transition
Capital spares
and other(1)
Total
Cost
As at Dec. 31, 2022
963
93
840
3,233
4,530
3,974
379 14,012
Additions(2)
869
—
—
—
—
—
6
875
Disposals
—
(3)
—
—
—
(30)
—
(33)
Impairment reversals (Note 7)
—
—
10
4
—
—
—
14
Changes to decommissioning and restoration
costs
—
—
3
14
(22)
3
(1)
(3)
Retirement of assets
—
—
(7)
(18)
(124)
(7)
(108)
(264)
Change in foreign exchange rates
(26)
—
—
(18)
(7)
(42)
(1)
(94)
Transfers of assets(3)
(572)
—
38
439
50
16
31
2
Transfers to finance lease receivable
—
—
—
(61)
(4)
—
—
(65)
As at Dec. 31, 2023
1,234
90
884
3,593
4,423
3,914
306 14,444
Additions(2)
279
—
—
—
10
—
22
311
Acquisitions (Note 4)
11
—
—
—
401
—
—
412
Disposals
—
(2)
—
—
(1)
(3)
—
(6)
Changes to decommissioning and restoration
costs (Note 24)
—
—
16
9
13
—
—
38
Retirement of assets
—
—
(10)
(12)
(16)
—
—
(38)
Change in foreign exchange rates
28
2
—
124
—
146
2
302
Transfer to intangible assets (Note 21)
—
—
—
—
(163)
—
—
(163)
Transfers of assets(3)
(1,432)
—
43
1,205
163
14
7
—
Transfers to finance lease receivable (Note 17)
—
—
—
—
(48)
—
—
(48)
As at Dec. 31, 2024
120
90
933
4,919
4,782
4,071
337 15,252
Accumulated depreciation
As at Dec. 31, 2022
—
—
478
1,228
2,812
3,744
194 8,456
Depreciation
—
—
25
129
342
73
16
585
Retirement of assets
—
—
(4)
(15)
(101)
(7)
(108)
(235)
Disposals
—
—
—
—
—
(30)
—
(30)
Change in foreign exchange rates
—
—
—
(5)
(3)
(39)
—
(47)
Transfers of assets(3)
—
—
—
—
(1)
2
—
1
As at Dec. 31, 2023
—
—
499
1,337
3,049
3,743
102 8,730
Depreciation
—
—
37
170
221
62
28
518
Retirement of assets
—
—
(9)
(9)
(15)
—
—
(33)
Disposals
—
—
—
—
—
(2)
—
(2)
Change in foreign exchange rates
—
—
—
23
1
138
—
162
Transfer to intangible assets (Note 21)
—
—
—
—
(143)
—
—
(143)
As at Dec. 31, 2024
—
—
527
1,521
3,113
3,941
130 9,232
Carrying amount
As at Dec. 31, 2022
963
93
362
2,005
1,718
230
185 5,556
As at Dec. 31, 2023
1,234
90
385
2,256
1,374
171
204 5,714
As at Dec. 31, 2024
120
90
406
3,398
1,669
130
207 6,020
(1)
Includes major spare parts and standby equipment available, but not in service.
(2) In 2024, the Company capitalized $16 million (2023 — $57 million) of interest to PP&E at a weighted average rate of 6.52 per cent (2023 — 6.3 per
cent).
(3) Includes transfers of assets upon commissioning to assets in service and other movements.
F69
TransAlta Corporation
2024 Integrated Report
Assets under Construction
During the year, the Company achieved commercial
operations at the White Rock and Horizon Hill wind
facilities. Costs were transferred from assets under
construction to the Wind and Solar segment. As outlined in
Note 17, $48 million related to the Mount Keith 132kV
expansion
was
derecognized
from
assets
under
construction and recognized as a finance lease receivable
in the first quarter of 2024.
Change in Estimate — Useful Lives
During 2024 and 2023, the Company adjusted the useful
lives of certain assets in the Gas segment to reflect
changes to the future operating expectations of the
assets. The adjustment to the useful lives resulted in a
decrease of $112 million (2023 — $92 million) in
depreciation expense that was recognized in the
Consolidated Statement of Earnings.
Mothballing of Sundance Unit 6
During 2024, the Company announced it will temporarily
mothball Sundance Unit 6 on April 1, 2025 for a period of
up to two years depending on market conditions. The
Company maintains the flexibility to return the mothballed
unit to service when market fundamentals improve or
opportunities to contract are secured. The unit remains
available and fully operational for the first quarter of 2025.
20. Right-of-Use Assets
The Company leases various properties and types of
equipment. Lease contracts are typically made for fixed
periods. Leases are negotiated on an individual basis and
contain a wide range of terms and conditions.
The lease agreements do not impose covenants, but
leased assets may not be used as security for
borrowing purposes.
A reconciliation of the changes in the carrying amount of the right-of-use assets is as follows:
Land
Buildings
Vehicles
Equipment
Total
As at Dec. 31, 2022
102
15
2
7
126
Additions
2
2
1
—
5
Depreciation
(5)
(5)
—
(2)
(12)
Change in foreign exchange rates
(2)
—
—
—
(2)
As at Dec. 31, 2023
97
12
3
5
117
Additions(1)
1
3
1
—
5
Depreciation
(5)
(1)
(1)
(1)
(8)
Change in foreign exchange rates
6
—
—
—
6
As at Dec. 31, 2024
99
14
3
4
120
(1)
Additions to buildings include right-of-use assets of $1 million acquired from Heartland.
For the year ended Dec. 31, 2024, TransAlta paid
$16 million (2023 — $19 million) related to recognized
lease liabilities, consisting of $6 million (2023 — $10
million) of principal repayments and $10 million (2023 —
$9 million) of interest expense.
Short-term leases (term of less than 12 months) and
leases with total lease payments below the Company's
capitalization threshold (low value leases) do not require
recognition as lease liabilities and right-of-use assets. For
the year ended Dec. 31, 2024, the Company expensed
$1 million (2023 — $1 million and 2022 — $2 million)
related to short-term and low value leases.
Some of the Company's land leases that met the definition
of a lease were not recognized as they require variable
payments based on production or revenue.
Additionally, certain land leases require payments to be
made on the basis of the greater of the minimum fixed
payments and variable payments based on production or
revenue. For these leases, lease liabilities have been
recognized on the basis of the minimum fixed payments.
For the year ended Dec. 31, 2024, the Company expensed
$9 million (2023 — $8 million and 2022 — $8 million) in
variable land lease payments for these leases.
TransAlta Corporation
2024 Integrated Report
F70
21. Intangible Assets
A reconciliation of the changes in the carrying amount of intangible assets is as follows:
Power sale
and other
contracts
Software
and other
Intangibles under
development
Coal rights
Total
Cost
As at Dec. 31, 2022
272
437
27
132
868
Additions
—
—
13
—
13
Asset impairment charges (Note 7)
—
(1)
—
—
(1)
Change in foreign exchange rates
(2)
(2)
(1)
—
(5)
Transfers
—
12
(12)
—
—
As at Dec. 31, 2023
270
446
27
132
875
Additions
—
—
10
—
10
Acquisitions (Note 4)
57
—
—
—
57
Change in foreign exchange rates
5
7
1
—
13
Transfers
20
35
(33)
—
22
As at Dec. 31, 2024
352
488
5
132
977
Accumulated amortization
As at Dec. 31, 2022
158
326
—
132
616
Amortization
17
21
—
—
38
Change in foreign exchange rates
(1)
(1)
—
—
(2)
As at Dec. 31, 2023
174
346
—
132
652
Amortization
19
19
—
—
38
Change in foreign exchange rates
4
3
—
—
7
Transfers
—
(1)
—
—
(1)
As at Dec. 31, 2024
197
367
—
132
696
Carrying amount
As at Dec. 31, 2022
114
111
27
—
252
As at Dec. 31, 2023
96
100
27
—
223
As at Dec. 31, 2024
155
121
5
—
281
F71
TransAlta Corporation
2024 Integrated Report
22. Goodwill
Goodwill acquired through business combinations has been allocated to groups of CGUs that are expected to benefit
from the synergies of the acquisitions. Goodwill by segments is as follows:
As at Dec. 31
2024
2023
Hydro
258
258
Wind and Solar
178
176
Gas (Note 4)
51
—
Energy Marketing
30
30
Total goodwill
517
464
Addition to goodwill in the Gas segment in 2024
represents the excess of the purchase price over the
estimated fair value of the net assets acquired in the
business acquisition of Heartland. Refer to Note 4 for more
details.
For the purposes of the 2024 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 2024, the Company relied on the recoverable amounts
determined in 2022 for the Hydro and Energy Marketing
segments in performing the 2024 goodwill impairment
review. The recoverable amounts are based on the
Company's long-range forecasts for the periods extending
to the last planned asset retirement in 2072. The resulting
fair value measurements are categorized within Level III of
the fair value hierarchy. No impairment of goodwill arose
for any segment.
The significant assumptions impacting the determination
of fair value for the Wind and Solar segment, with a high
degree of subjectivity, are the following:
• Forecasts of sales prices for each facility are determined
by taking into consideration contract prices for facilities
subject to long- or short-term contracts, forward price
curves for merchant plants and regional supply-demand
balances. Where forward price curves are not available
for the duration of the facility’s useful life, prices are
determined by extrapolation techniques using historical
industry
and
Company-specific
data.
Merchant
electricity prices used in Wind and Solar models ranged
between $40 to $225 per MWh during the forecast
period (2023 — $35 to $238 per MWh).
• Discount rates used ranged from 6.4 per cent to 7.3 per
cent (2023 — 6.4 per cent to 7.5 per cent). A 0.5 per
cent increase in the discount rate would not impact the
results of the impairments tests performed.
• The White Rock and the Horizon Hill wind facilities are
subject to location-specific price basis, sourced from
third-party analysis. This analysis is based on models of
the transmission system, including assumptions around
potential system upgrades as well as forecasted
generation and load in the area.
TransAlta Corporation
2024 Integrated Report
F72
23. Other Assets
The components of other assets are as follows:
As at Dec. 31
2024
2023
South Hedland prepaid transmission access and distribution costs
58
60
TransAlta Energy Transition Bill commitment
30
32
Long-term prepaids and other assets
35
9
Project development costs
15
35
Loans receivable
25
26
Transmission infrastructure
17
18
Total other assets
180
180
Included in the Consolidated Statements of Financial Position as:
Total current other assets (Note 13)
1
1
Total long-term other assets
179
179
Total other assets
180
180
South
Hedland
prepaid
transmission
access
and
distribution costs are costs that are amortized on a
straight-line
basis
over
the
South
Hedland
PPA
contract life.
As part of the TransAlta Energy Transition Bill signed into
law in the State of Washington and the subsequent
Memorandum
of
Agreement
(MOA),
the
Company
committed to fund US$55 million in total over the
remaining life of the Centralia coal plant to support
economic and community development, promote energy
efficiency and develop energy technologies related to the
improvement of the environment. The MOA contains
certain provisions for termination and in the event of
termination and in certain circumstances, this funding or
portion thereof would no longer be required. As at Dec. 31,
2023, the Company has fully funded the commitment. The
outstanding balance will be expensed to net earnings
when
the
funds
are
granted
and
disbursed
to
organizations.
Long-term prepaids and other assets include contractually
required
prepayments
and
deposits,
including
the
balances acquired from Heartland. Refer to Note 4 for
more details.
Project
development
costs
primarily
include
the
pre-construction project costs, which met the criteria for
capitalization.
At Dec. 31, 2024, $25 million of the loans receivable (2023
— $26 million) is an unsecured loan related to an
advancement by the Company's subsidiary, Kent Hills
Wind LP, of the net financing proceeds of the Kent Hills
Wind Bond (KH Bonds), to its 17 per cent partner. The loan
bears interest at 4.55 per cent, with interest payable
quarterly. No scheduled principal repayments are required
until the maturity date of October 2027. During 2024, no
repayments were required as part of the waiver and
amendment made to the KH Bonds (2023 — repayments
of $12 million).
Transmission infrastructure was constructed by the
Company and then transferred to a transmission provider
upon completion. The balance relates to the Garden Plain
and Windrise wind facilities and will be amortized to net
earnings over the useful life of the facilities.
F73
TransAlta Corporation
2024 Integrated Report
24. Decommissioning and Other Provisions
The change in decommissioning and other provision balances is as follows:
Decommissioning and
restoration
Other provisions
Total
Dec. 31, 2022
688
41
729
Liabilities incurred
1
4
5
Liabilities settled
(37)
(13)
(50)
Accretion
47
1
48
Revisions in estimated cash flows
(89)
—
(89)
Revisions in discount rates
52
—
52
Change in foreign exchange rates
(6)
—
(6)
Balance, Dec. 31, 2023
656
33
689
Liabilities acquired (Note 4)
101
55
156
Liabilities incurred
6
12
18
Liabilities settled
(41)
(4)
(45)
Accretion (Note 10)
50
—
50
Transfer to accounts payable
—
(31)
(31)
Transfer to assets held for sale (Note 18)
(1)
—
(1)
Revisions in estimated cash flows
21
20
41
Revisions in discount rates
35
—
35
Change in foreign exchange rates
21
—
21
Balance, Dec. 31, 2024
848
85
933
Included in the Consolidated Statements of Financial Position as:
As at
Dec. 31, 2024
Dec. 31, 2023
Current portion
83
35
Non-current portion
850
654
Total decommissioning and other provisions
933
689
TransAlta Corporation
2024 Integrated Report
F74
A. Decommissioning and Restoration
A provision has been recognized for all generating
facilities and mines for which TransAlta is legally, or
constructively, required to remove the facilities at the end
of their useful lives and restore the sites to their original
condition. TransAlta estimates that the undiscounted
amount of cash flow required to settle these obligations is
approximately $1.8 billion, which will be incurred between
2025 and 2072. The majority of the costs will be incurred
between 2025 and 2050.
On Dec. 4, 2024 as part of the Heartland acquisition, the
Company recognized decommissioning and restoration
provision of $101 million and other provisions of $55 million
(refer to Note 4 for details).
During 2024, the decommissioning and restoration
provision increased by $21 million due to revisions in
estimated cash flows and timing of cash flows for certain
Gas and Hydro assets. The timing of cash flows was
adjusted to optimize and maximize efficiencies by staging
required reclamation work. Operating assets included in
PP&E increased by $14 million and $7 million was
recognized as an impairment charge in net earnings
related to retired assets.
During 2024, revisions in discount rates increased the
decommissioning and restoration provision by $35 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 2023,
with rates ranging from 5.3 to 8.4 per cent as at Dec. 31,
2024. This has resulted in a corresponding increase in
PP&E of $18 million on operating assets and the
recognition of a $17 million impairment charge in net
earnings related to retired assets.
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.
At Dec. 31, 2024, the Company has provided a surety
bond in the amount of US$147 million (2023 —
US$147 million) in support of future decommissioning
obligations at the Centralia coal mine. At Dec. 31, 2024,
the Company had provided a surety bond and letters of
credit in the amount of $194 million (2023 — $188 million)
in support of future decommissioning obligations at the
Highvale mine.
B. Other Provisions
Other provisions include provisions arising from ongoing
business activities, amounts related to commercial
disputes between the Company and customers or
suppliers and onerous contract provisions. Information
about the expected timing of settlement and uncertainties
that could impact the amount or timing of settlement has
not been provided as this may impact the Company’s
ability
to
settle
the
provisions
in
the
most
favourable manner.
As part of the acquisition of Heartland, the Company
recognized an onerous contract provision of $47 million
related to certain natural gas transportation contracts
assumed. Payments required under the contracts continue
through the first quarter of 2031.
F75
TransAlta Corporation
2024 Integrated Report
25. Credit Facilities, Long-Term Debt and Lease Liabilities
A. Amounts Outstanding
The amounts outstanding are as follows:
As at Dec. 31
2024
2023
Segment
Maturity
Currency
Carrying
value
Face
value
Interest(1)
Carrying
value
Face
value
Interest
Credit facilities
Committed syndicated bank facility(2)
Corporate
2028
CAD
143
145
5.3%
—
—
—%
Term Facility
Corporate
2025
CAD
400
400
5.6%
397
400
7.4%
Debentures
7.3% Medium term notes
Corporate
2029
CAD
110
110
7.3%
110
110
7.3%
6.9% Medium term notes
Corporate
2030
CAD
141
141
6.9%
141
141
6.9%
Senior notes(3)
7.8% Senior notes(4)
Corporate
2029
USD
569
575
7.8%
520
528
7.8%
6.5% Senior notes
Corporate
2040
USD
426
431
6.5%
391
396
6.5%
Non-recourse
Melancthon Wolfe Wind LP bond
Wind & Solar
2028
CAD
133
134
3.8%
168
169
3.8%
New Richmond Wind LP bond
Wind & Solar
2032
CAD
93
94
4.0%
103
104
4.0%
Kent Hills Wind LP bond
Wind & Solar
2033
CAD
179
182
4.5%
193
196
4.5%
Windrise Wind LP bond
Wind & Solar
2041
CAD
157
160
3.4%
164
167
3.4%
Pingston bond
Hydro
2043
CAD
39
39
6.2%
39
39
6.2%
TAPC Holdings LP bond (Poplar Creek)
Gas
2030
CAD
75
76
8.3%
85
86
9.4%
TEC Hedland PTY Ltd bond(5)
Gas
2042
AUD
675
683
4.1%
691
699
4.1%
Heartland term facility
Corporate
2027
CAD
224
224
6.6%
—
—
—%
Recourse
TransAlta OCP LP bond
Gas
2030
CAD
192
193
4.5%
217
218
4.5%
Tax equity financing
Big Level & Antrim(6)
Wind & Solar
2029
USD
90
94
6.6%
91
97
6.6%
Lakeswind(7)
Wind & Solar
2027
USD
7
7
10.5%
10
10
10.5%
North Carolina Solar(8)
Wind & Solar
2028
USD
4
4
7.3%
3
3
7.3%
Total long-term debt
3,657 3,692
3,323
3,363
Lease liabilities
151
143
Total long-term debt and lease liabilities
3,808
3,466
Less: current portion of long-term debt
(567)
(526)
Less: current portion of lease liabilities
(5)
(6)
Total current long-term debt and lease liabilities
(572)
(532)
Total non-current credit facilities, long-term debt and lease liabilities
3,236
2,934
(1)
Interest rate reflects the stipulated rate or the average rate weighted by principal amounts outstanding and is before the effect of hedging.
(2) Composed of swing line loans and other commercial borrowings under long-term committed credit facilities.
(3) U.S. face value at Dec. 31, 2024, is US$700 million (2023 — US$700 million).
(4) The effective interest rate for the Senior Notes is 5.98 per cent after the effects of gains realized on settled interest rate hedging instruments.
(5) AU face value at Dec. 31, 2024, is AU$761 million (2023 — AU$773 million).
(6) U.S. face value at Dec. 31, 2024, is US$65 million (2023 — US$73 million).
(7)
U.S. face value at Dec. 31, 2024, is US$5 million (2023 — US$8 million).
(8) U.S. face value at Dec. 31, 2024, is US$3 million (2023 — US$2 million).
TransAlta Corporation
2024 Integrated Report
F76
The Company's credit facilities are summarized in the table below:
As at Dec. 31, 2024
Utilized
Credit facilities
Facility
size
Outstanding
letters of
credit(1)
Cash
drawings
Available
capacity
Maturity
date
Committed
Syndicated credit facility
1,950
456
145
1,349
Q2 2028
Bilateral credit facilities
240
161
—
79
Q2 2026
Term Facility
400
—
400
—
Q3 2025
Heartland Credit Facilities
276
14
224
38
Q4 2027
Heartland EDC letter of credit facility
50
14
—
36
Q1 2025
Total committed
2,916
645
769
1,502
Non-committed
Demand facilities
400
220
—
180
N/A
Total Non-committed
400
220
—
180
(1)
TransAlta has obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential
environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase
obligations. Letters of credit drawn against the non-committed facilities reduce the available capacity under the committed syndicated credit facilities.
At Dec. 31, 2024, TransAlta provided cash collateral of $124 million.
In the second quarter of 2024, the Term Facility of $400
million was renewed with the maturity extended by one
year to September 2025. The syndicated credit facility
and bilateral credit facilities were also extended by one
year to June 2028 and June 2026, respectively.
The credit facilities are the primary source of short-term
liquidity after the cash flow generated from the
Company's business.
Heartland Credit Facilities
As part of the Heartland acquisition on Dec. 4, 2024, the
Company assumed a $232 million drawn term facility and
a $25 million revolving facility with a syndicate of banks,
(collectively Heartland Credit Facilities). At Dec. 31, 2024
the drawn term facility was $224 million. The $25 million
revolving facility is undrawn and available for working
capital and general corporate purposes. The maturity date
for the Heartland Credit Facilities is Dec. 22, 2027. The
Heartland Credit Facilities also include a $27 million debt
service reserve letter of credit facility. As at Dec. 31, 2024
$14 million in letters of credit have been issued under this
facility.
Heartland EDC Letter of Credit Facility
As part of the Heartland acquisition, the Company has
access to a $50 million unsecured letter of credit facility
with two Canadian banks, which is supported by a
performance security guarantee from Export Development
Canada (EDC). As at Dec. 31, 2024, $14 million in letters
of credit have been issued under this facility. The facility is
effective until March 31, 2025.
Senior Notes
A total of US$300 million (2023 — US$370 million) of the
senior notes have been designated as a hedge of the
Company’s net investment in U.S. operations.
Non-Recourse Debt
On May 8, 2023, the Pingston Power Inc. non-recourse
bond matured with a total aggregate repayment of
$46 million, consisting of accrued interest and principal.
On Sept. 14, 2023, the Company closed a non-recourse
bond financing for approximately $39 million (Pingston
Bond) as a replacement for the non-recourse bond that
matured on May 8, 2023. The Pingston Bond is secured by
a first ranking charge over all the respective assets of the
Company's subsidiaries that issued the bonds, amortizes
and bears interest at a rate of 6.145 per cent per annum,
payable semi-annually, and matures on May 8, 2043. The
Pingston
Bond
is
subject
to
customary
financing
conditions and covenants that may restrict the Company's
ability to access funds generated by the facility's
operations.
Tax Equity
Tax equity financings are typically represented by the
initial equity investments made by the project investors at
each project (net of financing costs incurred), except for
the Lakeswind and North Carolina Solar acquired tax
equity financings, which were initially recognized at their
fair values. Tax equity financing balances are reduced by
the value of tax benefits (production tax credits, tax
depreciation and investment tax credits) allocated to the
investor and by cash distributions paid to the investor for
F77
TransAlta Corporation
2024 Integrated Report
their share of net earnings and cash flow generated at
each project. Tax equity financing balances are increased
by interest recognized at the implicit interest rate. The
maturity dates of each financing are subject to change
and are primarily dependent upon when the project
investor achieves the agreed upon targeted rate of return.
The Company anticipates the maturity dates of the tax
equity financings will be: Lakeswind in June 2027; North
Carolina Solar in December 2028; and Big Level and
Antrim in December 2029.
Other
TransAlta’s short and long-term debt has terms and
conditions,
including
financial
covenants,
that
are
considered normal and customary. As at Dec. 31, 2024,
the Company was in compliance with all debt covenants.
The Heartland Credit Facilities are not subject to any
maintenance or financial covenants but do contain certain
covenants that limit Heartland’s ability to, among other
things, incur additional indebtedness, create or permit
liens to exist, make certain acquisitions or dispositions,
make distributions and enter into certain hedging
agreements.
The Company is in compliance with its terms of the credit
facilities and all undrawn amounts are fully available.
Letters of credit in the amount of $220 million were issued
from non-committed demand facilities as at Dec. 31, 2024.
In addition to the net $1.5 billion of committed capacity
available under the credit facilities, the Company had
$336 million of available cash and cash equivalents as at
Dec. 31, 2024.
B. Restrictions Related to Non-Recourse
Debt and Other Debt
The Melancthon Wolfe Wind LP, Pingston Power Inc.,
TAPC Holdings LP, New Richmond Wind LP, Kent Hills
Wind LP, TEC Hedland Pty Ltd. and Windrise Wind LP non-
recourse bonds, the TransAlta OCP LP bond, and
Heartland Credit Facilities, with a total carrying value of
$1.8 billion as at Dec. 31, 2024 (2023 — $1.7 billion), are
subject to customary financing conditions and covenants
that may restrict the Company’s ability to access funds
generated by the facilities’ operations. Upon meeting
certain distribution tests, typically performed once per
quarter, the funds can be distributed by the subsidiary
entities to their respective parent entity. These conditions
include meeting a debt service coverage ratio prior to
distribution, which was met by these entities in the fourth
quarter of 2024 with the exception of Kent Hills Wind LP.
The funds in the entities will remain there until the next
debt service coverage ratio can be performed in the first
quarter of 2025. At Dec. 31, 2024, $117 million (2023 —
$79 million) of cash was subject to these financial
restrictions.
At Dec. 31, 2024, $5 million (AU$6 million) of funds held by
TEC Hedland Pty Ltd. cannot be accessed by other
corporate entities as the funds must be solely used by the
project entities, for the purpose of paying major
maintenance costs. Additionally, certain non-recourse
bonds
require
that
certain
reserve
accounts
be
established and funded through cash held on deposit and/
or by providing letters of credit.
C. Security
Non-recourse debt totalling $1.5 billion as at Dec. 31, 2024
(2023 — $1.4 billion) is secured by a first ranking charge
over all of the respective assets of the Company’s
subsidiaries that issued the debt, which include PP&E with
total carrying amounts of $1.75 billion at Dec. 31, 2024
(2023 — $1.5 billion) and intangible assets with total
carrying amounts of $84 million (2023 — $61 million). At
Dec. 31, 2024, non-recourse debt of approximately $75
million (2023 — $85 million) was secured by a first ranking
charge over the equity interests of the issuer that issued
the non-recourse debt.
The TransAlta OCP bonds have a carrying value of $192
million (2023 — $217 million) and are secured by the
assets of TransAlta OCP, including the right to annual
capital contributions and OCA payments from the
Government of Alberta related to TransAlta's legacy coal
facilities (the TransAlta OCA). Under the TransAlta OCA,
the Company receives annual cash payments on or before
July 31 of approximately $40 million (approximately $37
million, net to the Company), commencing on Jan. 1, 2017,
and terminating at the end of 2030. These payments do
not include the OCA payments Heartland is entitled to
under its OCA.
TransAlta Corporation
2024 Integrated Report
F78
D. Principal Repayments
2025
2026
2027
2028
2029
2030 and
thereafter
Total
Principal repayments(1)
566
169
331
309
824
1,493 3,692
Lease liabilities
4
5
5
5
5
127
151
(1)
Excludes impact of hedge accounting and derivatives.
E. Restricted Cash
As at Dec. 31, 2024, the Company had $17 million (2023 —
$17 million) of restricted cash related to the TransAlta OCP
bonds, which is required to be held in a debt service
reserve
account
to
fund
scheduled
future
debt
repayments. The Company also had $52 million (2023 —
$52 million) of restricted cash related to the TEC Hedland
Pty Ltd. bond. These cash reserves are required to be held
under commercial arrangements and for debt service,
which may be replaced by letters of credit in the future.
F. Letters of Credit
Letters of credit are issued to counterparties as required
by various contractual arrangements with the Company
and certain subsidiaries of the Company. If the Company
or its subsidiary does not perform under such contracts,
the counterparty may present its claim for payment to the
financial institution through which the letter of credit was
issued. All letters of credit expire within one year and are
expected to be renewed, as needed, in the normal course
of business. The total outstanding letters of credit as at
Dec. 31, 2024, was $865 million (2023 — $782 million)
with nil (2023 — nil) amounts exercised by third parties
under these arrangements.
G. Currency Impacts
The strengthening of the U.S. dollar has increased the U.S.
dollar denominated long-term debt balances, mainly the
senior notes and tax equity financings, by $90 million as at
Dec. 31, 2024 (2023 — decreased $27 million due to the
weakening of the U.S. dollar). Almost all of the U.S.
dollar denominated debt is hedged either through financial
contracts or net investments in U.S. operations.
Additionally, the weakening of the Australian dollar has
decreased
the
Australian
dollar-denominated
non-
recourse senior secured notes balance by approximately
$5 million as at Dec. 31, 2024 (2023 — $9 million). As this
debt is issued by an Australian subsidiary, the foreign
currency translation impacts are recognized within other
comprehensive income (loss).
F79
TransAlta Corporation
2024 Integrated Report
26. Exchangeable Securities
On March 22, 2019, the Company entered into an
Investment Agreement whereby Brookfield Renewable
Partners or its affiliates (collectively Brookfield) agreed to
invest $750 million in TransAlta through the purchase of
exchangeable securities, which are exchangeable into an
equity ownership interest in TransAlta’s Alberta Hydro
Assets in the future at a value based on a multiple of the
Alberta Hydro Assets’ future-adjusted EBITDA (Option
to Exchange).
A. $750 Million Exchangeable Securities
As at
Dec. 31, 2024
Dec. 31, 2023
Carrying
value
Face
value
Interest
Carrying
value
Face
value
Interest
Exchangeable debentures – due May 1, 2039(1)
350
350
7%
344
350
7%
Exchangeable preferred shares(2)
400
400
7%
400
400
7%
Total exchangeable securities
750
750
744
750
(1)
Seven per cent unsecured subordinated debentures due May 1, 2039.
(2) Redeemable, retractable first preferred shares (Series I). Exchangeable preferred share dividends are reported as interest expense.
On Dec. 9, 2024, the Company declared a dividend of $7
million, in aggregate, for the Exchangeable Preferred
Shares at the fixed rate of 1.760 per cent, per share,
payable on Feb. 28, 2025. The Exchangeable Preferred
Shares are considered debt for accounting purposes and,
as such, dividends are reported as interest expense (Note
10).
B. Option to Exchange
As at
Dec. 31, 2024
Dec. 31, 2023
Description
Base fair value
Sensitivity
Base fair value
Sensitivity
Option to exchange – embedded derivative
—
+nil
-30
—
+nil
-25
The Investment Agreement allows Brookfield the option to
exchange all of the outstanding exchangeable securities
after Dec. 31, 2024, into an equity ownership interest of up
to a maximum 49 per cent in an entity that has been
formed to hold the Alberta Hydro Assets. The fair value of
the option to exchange is considered a Level III fair value
measurement as there is no available market-observable
data. It is therefore valued using a mark-to-forecast model
with inputs that are based on historical data and changes
in underlying discount rates only when it represents a
long-term change in the value of the option to exchange.
Sensitivity ranges for the base fair value are determined
using reasonably possible alternative assumptions for key
unobservable inputs, which is mainly the change in the
implied discount rate of future cash flows. The sensitivity
analysis has been prepared using the Company’s
assessment that a change in the implied discount rate of
10.5 per cent (2023 — 11.8 per cent) of future cash flows
of one per cent is a reasonably possible change.
The maximum equity interest Brookfield can own with
respect to the Alberta Hydro Assets is 49 per cent. If
Brookfield’s ownership interest is less than 49 per cent at
conversion, Brookfield has a one-time option payable in
cash to increase its ownership to up to 49 per cent,
exercisable up until Dec. 31, 2028, provided Brookfield
holds at least 8.5 per cent of TransAlta’s common shares.
Under this top-up option, Brookfield will be able to acquire
an additional 10 per cent interest in the entity holding the
Alberta Hydro Assets, provided the 20-day volume-
weighted average price (VWAP) of TransAlta’s common
shares is not less than $14 per share prior to the exercise
of the option, and up to the full 49 per cent if the 20-day
VWAP of TransAlta’s common shares at that time is not
less than $17 per share. To the extent the value of the
investment would exceed a 49 per cent equity interest,
Brookfield will be entitled to receive the balance of the
redemption price in cash.
In connection with the Investment Agreement, Brookfield
is entitled to nominate two directors for election to the
Board.
TransAlta Corporation
2024 Integrated Report
F80
27. Defined Benefit Obligation and Other Long-Term Liabilities
The components of defined benefit obligation and other long-term liabilities are as follows:
As at Dec. 31
2024
2023
Defined benefit obligation (Note 32)
146
155
Retail power contract liability
45
83
Other
11
13
Total
202
251
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 decreased by $9 million to
$146 million as at Dec. 31, 2024, from $155 million as at
Dec. 31, 2023.
The Company's U.S. Defined Benefit Pension Plan was
terminated effective June 30, 2024 and annuitized with
the TransAlta Retirement Pension Plan Trust in October
2024. Plan assets and liabilities both totalling $23 million
(US$17 million) were transferred to a new provider. The
participant payments with a new provider commenced on
Jan. 1, 2025.
During 2023, the Company made a voluntary contribution
of $4 million (US$3 million) to further improve the funded
status of U.S. Defined Benefit Pension Plan for the
Centralia thermal facility.
A one per cent increase in discount rates would result in a
$34 million decrease in the defined benefit obligation.
Refer to Note 32 for additional sensitivities impacting the
defined benefit obligation.
The retail power contract liability represents an obligation
arising from the purchase and sale agreement for
customer retail contracts to deliver power, gas and power
and gas financial swaps. The retail power contracts
represent certain off-market customer contracts, where
the value of the contract is based on the differential
between the contractual and market rates on the closing
date. The retail contract liability is amortized to
depreciation over the remaining term of the contracts
based on volumes that will be delivered each month.
F81
TransAlta Corporation
2024 Integrated Report
28. Common Shares
A. Issued and Outstanding
TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.
As at Dec. 31
2024
2023
Common
shares
(millions)
Amount
Common
shares
(millions)
Amount
Issued and outstanding, beginning of period
306.9
3,285
268.1
2,863
Reversal of provision for repurchase of common shares under
ASPP
1.7
19
—
—
Purchased and cancelled under the NCIB(1)(2)
(13.5)
(146)
(7.5)
(80)
Share-based payment plans
0.8
9
0.8
6
Stock options exercised
1.6
12
0.7
5
Issued for acquisition of TransAlta Renewables(3) (Note 4)
—
—
46.5
510
Issued and outstanding, end of year, prior to ASPP
297.5
3,179
308.6
3,304
Provision for repurchase of common shares under ASPP
—
—
(1.7)
(19)
Issued and outstanding, end of year
297.5
3,179
306.9
3,285
(1)
2024 includes $2 million of tax on share buybacks (2023 — nil) on the fair value of the shares repurchased.
(2) Shares purchased by the Company under the NCIB (as defined below) are recognized as a reduction to share capital equal to the average carrying
value of the common shares. Any difference between the aggregate purchase price and the average carrying value of the common shares is recorded
in retained earnings (deficit).
(3) Net of $4 million of transaction costs.
B. Normal Course Issuer Bid (NCIB) Program
The effects of the Company's purchase and cancellation of common shares during the period are as follows:
For the year ended Dec. 31
2024
2023
Total shares purchased
13,467,400
7,537,500
Average purchase price per share
10.59
11.49
Total cost (millions)
143
87
Book value of shares cancelled
146
80
Amount recorded in deficit
3
(7)
2024
On May 27, 2024, the Company announced that it
received approval from the Toronto Stock Exchange (TSX)
to repurchase up to a maximum of 14 million common
shares during the 12-month period that commenced May
31, 2024, and terminates May 30, 2025. Any common
shares purchased under the NCIB will be cancelled.
2023
On May 26, 2023, the TSX accepted the notice filed by
the Company to renew its NCIB for a portion of its
common shares.
On Dec. 19, 2023, the Company entered into an Automatic
Share Purchase Plan (ASPP) that permits an independent
broker to repurchase shares under the NCIB during the
first quarter blackout period through to the end of the
ASPP. As at Dec. 31, 2023, the Company recognized a
TransAlta Corporation
2024 Integrated Report
F82
provision of $19 million for the repurchase of common
shares under the ASPP within accounts payables and
accrued liabilities as an estimate of the maximum number
of shares that could be repurchased during the
blackout period. The provision was settled during 2024.
C. Shareholder Rights Plan
The Company initially adopted the Shareholder Rights Plan
in 1992, which was amended and restated on April 28,
2022. As required, the Shareholder Rights Plan must be
put before the Company’s shareholders every three years
for approval. It was last approved on April 28, 2022, and
will need to be approved at the annual meeting of
shareholders in 2025. The primary objective of the
Shareholder Rights Plan is to encourage a potential
acquirer to meet certain minimum standards designed to
promote the fair and equal treatment of all common
shareholders. When an acquiring shareholder acquires 20
per cent or more of the Company’s common shares,
except in limited circumstances including by way of a
“permitted bid” or a "competing permitted bid" (as defined
in the Shareholder Rights Plan), the rights granted under
the Shareholder Rights Plan become exercisable by all
shareholders
except
those
held
by
the
acquiring
shareholder. Each right will entitle a shareholder, other
than the acquiring shareholder, to purchase additional
common shares at a significant discount to market, thus
exposing the person acquiring 20 per cent or more of the
shares to substantial dilution of their holdings.
D. Earnings per Share
Year ended Dec. 31
2024
2023
2022
Net earnings attributable to common shareholders
177
644
4
Basic and diluted weighted average number of common shares
outstanding (millions)
302
276
271
Net earnings per share attributable to common shareholders, basic
and diluted
0.59
2.33
0.01
E. Dividends
On Dec. 9, 2024, the Company declared a quarterly
dividend of $0.06 per common share, payable on April
1, 2025.
On Feb. 19, 2025, the Company declared a quarterly
dividend of $0.065 per common share, payable on July
1, 2025.
There have been no transactions involving common
shares between the reporting date and the date of
completion of these Consolidated Financial Statements.
F83
TransAlta Corporation
2024 Integrated Report
29. Preferred Shares
A. Issued and Outstanding
All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first
preferred shares.
As at Dec. 31
2024
2023
Series(1)
Number
of shares
(millions)
Amount
Number
of shares
(millions)
Amount
Series A
9.6
235
9.6
235
Series B
2.4
58
2.4
58
Series C
10.0
243
10.0
243
Series D
1.0
26
1.0
26
Series E
9.0
219
9.0
219
Series G
6.6
161
6.6
161
Issued and outstanding, end of period
38.6
942
38.6
942
(1)
The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 26.
Series G Cumulative Redeemable Rate Reset
Preferred Shares
During the third quarter of 2024, after taking into account
all election notices received for the conversion of the
Cumulative Redeemable Rate Reset Preferred Shares,
Series G (Series G shares), 20,607 Series G shares out of
6.6 million outstanding, were tendered for conversion,
which is less than the 1 million shares required to give
effect to conversion into Series H shares. As a result, none
of the Series G Shares were converted into Series H
Shares on Sept. 30, 2024 and the next conversion date
was reset to Sept. 30, 2029.
Preferred Share Series Information
The holders are entitled to receive cumulative fixed
quarterly cash dividends at specified rates, as approved
by the Board. After an initial period of approximately five
years from issuance and every five years thereafter (Rate
Reset Date), the fixed rate resets to the sum of the five-
year Government of Canada bond yield (the fixed rate
Benchmark) plus a specified spread. Upon each Rate
Reset Date, the shares are also:
• Redeemable at the option of the Company, in whole or in
part, for $25.00 per share, plus all declared and unpaid
dividends at the time of redemption.
• Convertible at the holder’s option into a specified series
of non-voting cumulative redeemable floating rate first
preferred shares that pay cumulative floating rate
quarterly cash dividends, as approved by the Board,
based on the sum of the Government of Canada 90-day
Treasury Bill rate (the floating rate Benchmark) plus a
specified spread. The cumulative floating rate first
preferred shares are also redeemable at the option of
the Company and convertible back into each original
cumulative fixed rate first preferred share series, at each
subsequent Rate Reset Date, on the same terms as
noted above.
TransAlta Corporation
2024 Integrated Report
F84
Characteristics specific to each first preferred share series as at Dec. 31, 2024, are as follows:
Series(1)
Rate during
term
Annual dividend
rate per share
($)(2)
Next conversion
date
Rate spread
over benchmark
(per cent)
Convertible
to Series
A
Fixed
0.71924
March 31, 2026
2.03
B
B
Floating
1.60106
March 31, 2026
2.03
A
C
Fixed
1.46352
June 30, 2027
3.10
D
D
Floating
1.86801
June 30, 2027
3.10
C
E
Fixed
1.72352
Sept. 30, 2027
3.65
F
G
Fixed
1.47012
Sept. 30, 2029
3.80
H
(1)
The Series I Preferred Shares are accounted for as long-term debt. Refer to Note 26.
(2) The annual dividend rate per share represents dividends declared in 2024.
B. Dividends
The following table summarizes the preferred share dividends declared in 2024 and 2023:
Total dividends declared
Series
2024
2023
A
7
7
B(1)
4
4
C
15
15
D(2)
2
2
E
15
15
G
9
8
Total for the year
52
51
(1)
Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.03 per cent.
(2) Series D Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 3.10 per cent.
On Dec. 9, 2024, the Company declared a quarterly dividend of $0.17981 per share on the Series A preferred shares,
$0.33972 per share on the Series B preferred shares, $0.36588 per share on the Series C preferred shares, $0.40568
per share on the Series D preferred shares, $0.43088 per share on the Series E preferred shares and $0.42331 per share
on the Series G preferred shares, payable on March 31, 2025.
F85
TransAlta Corporation
2024 Integrated Report
30. Accumulated Other Comprehensive Income (Loss)
The components of and changes in, accumulated other comprehensive loss are as follows:
2024
2023
Currency translation adjustment
Opening balance, Jan. 1
(36)
(39)
Gains (losses) on translating net assets of foreign operations, net of reclassifications to net
earnings, net of tax
30
(6)
(Losses) gains on financial instruments designated as hedges of foreign operations, net of
reclassifications to net earnings, net of tax(1)
(28)
9
Balance, Dec. 31
(34)
(36)
Cash flow hedges
Opening balance, Jan. 1
(129)
(228)
Gains on derivatives designated as cash flow hedges, net of reclassifications to net
earnings and to non-financial assets, net of tax(2)
194
99
Balance, Dec. 31
65
(129)
Employee future benefits
Opening balance, Jan. 1
3
8
Net actuarial gains (losses) on defined benefit plans, net of tax(3)
9
(5)
Balance, Dec. 31
12
3
Other
Opening balance, Jan. 1
(2)
37
Change in ownership of TransAlta Renewables
—
(64)
Intercompany and third-party investments at FVTOCI
—
25
Balance, Dec. 31
(2)
(2)
Accumulated other comprehensive income (loss)
41
(164)
(1)
Net of income tax recovery of $4 million for the year ended Dec. 31, 2024 (Dec. 31, 2023 – $1 million expense).
(2) Net of income tax expense of $53 million for the year ended Dec. 31, 2024 (Dec. 31, 2023 – $27 million).
(3) Net of income tax expense of $3 million for the year ended Dec. 31, 2024 (Dec. 31, 2023 – $1 million recovery).
31. Share-Based Payment Plans
The Company has the following share-based payment plans:
A. Performance Share Unit (PSU) and
Restricted Share Unit (RSU) Plan
Under the Share Unit Plan, grants of PSUs and RSUs may
be made annually, but are measured and assessed over a
three-year performance period. Grants are determined as
a percentage of participants’ base pay and are converted
to PSUs or RSUs on the basis of the Company’s common
share price at the time of grant. Vesting of PSUs is subject
to achievement over a three-year period of specific
performance measures that are established at the time of
each grant. RSUs are subject to a three-year cliff-vesting
requirement. RSUs and PSUs track the Company’s share
price over the three-year period and accrue dividends as
additional units at the same rate as dividends paid on the
Company’s common shares.
The pre-tax compensation expense related to PSUs and
RSUs in 2024 was $23 million (2023 — $21 million, 2022
— $20 million), which is included in OM&A in the
Consolidated Statements of Earnings.
TransAlta Corporation
2024 Integrated Report
F86
B. Deferred Share Unit (DSU) Plan
Under the Share Unit Plan, members of the Board and
executives may, at their option, purchase DSUs using
certain components of their fees or pay. A DSU is a
notional share that has the same value as one common
share of the Company and fluctuates based on the
changes in the value of the Company’s common shares in
the marketplace. DSUs accrue dividends as additional
DSUs at the same rate as dividends are paid on the
Company’s common shares. DSUs are redeemable in cash
and may not be redeemed until the termination or
retirement of the director or executive from the Company.
The Company accrues a liability and expense for the
appreciation in the common share value in excess of the
DSU’s purchase price and for dividend equivalents earned.
The pre-tax compensation expense related to the DSUs
was $8 million in 2024 (2023 — $1 million, 2022 — nil).
C. Stock Option Plan
In 2024, the Company granted executive officers of the
Company a total of 0.7 million stock options with a
weighted average exercise price of $10.88 that vest over a
three-year period and expire seven years after issuance
(2023 — 0.4 million stock options at $12.02; 2022 — 0.3
million stock options at $12.66). The expense recognized
relating to these grants during 2024 was approximately $1
million (2023 — approximately $1 million, 2022 —
approximately $1 million).
The total options outstanding and exercisable under the Stock Option Plan at Dec. 31, 2024, are outlined below:
Options outstanding
Range of exercise prices
($ per share)
Number of options
(millions)(1) Weighted average remaining
contractual life (years)
Weighted average exercise price
($ per share)
9.28-12.67
1.6
4.67
10.97
(1)
Includes 0.7 million options exercisable as at Dec. 31, 2024.
32. Employee Future Benefits
A. Description
The Company sponsors registered pension plans in
Canada and the U.S. covering substantially all employees
of the Company in both countries and specific named
employees working internationally. These plans have
defined benefit and defined contribution options and in
Canada there is an additional non-registered supplemental
plan for eligible employees whose annual earnings exceed
the Canadian income tax limit. Except for the Highvale
pension plan acquired in 2013, the Canadian and U.S.
defined benefit pension plans are closed to new entrants.
The U.S. defined benefit pension plan was frozen effective
Dec. 31, 2010, resulting in no future benefits being earned.
The supplemental pension plan was closed as of Dec. 31,
2015, and a new defined contribution supplemental
pension plan commenced for executive members effective
Jan. 1, 2016. Current executives as of Dec. 31, 2015, were
grandfathered into the old supplemental plan.
The Company's U.S. defined benefit pension plan was
terminated effective June 30, 2024 and annuitized in
October 2024.
The latest actuarial valuation for accounting purposes of
the U.S. defined benefit pension plan was at Jan. 1, 2023.
The latest actuarial valuation for accounting purposes of
the Highvale pension plan was at Dec. 31, 2022. The latest
actuarial valuation for accounting purposes of the
Registered Supplemental, and Other Canadian pension
plans were at Dec. 31, 2021, Dec. 31, 2022 and Dec. 31,
2023, respectively. The measurement date used for all
plans to determine the fair value of plan assets and the
present value of the defined benefit obligation was Dec.
31, 2024.
Funding of the registered pension plans complies with
applicable regulations that require actuarial valuations of
the pension funds at least once every three years in
Canada, or more, depending on funding status and every
year in the U.S.. The supplemental pension plan is solely
the obligation of the Company. The Company is not
obligated to fund the supplemental plan but is obligated to
pay benefits under the terms of the plan as they come
due. The Company posted a letter of credit in March 2024
in the amount of $90 million, and provided $62 million in
surety bonds, to secure the obligations under the
supplemental plan and the Canadian defined benefit
plan, respectively.
The Company provides other health and dental benefits to
certain eligible employees to the age of 65 for both
disabled members and retired members through its other
post-employment benefits plans. The measurement date
used to determine the present value obligation for both
plans was Dec. 31, 2024.
F87
TransAlta Corporation
2024 Integrated Report
The Company provides several defined contribution plans,
including the acquired Heartland plan, an Australian
superannuation plan and a U.S. 401(k) savings plan, that
provide for company contributions from five to 11.5 per
cent, depending on the plan.
Optional employee contributions are allowed for all the
defined contribution plans.
B. Costs Recognized
The costs recognized in net earnings during the year on the defined benefit, defined contribution and other post-
employment benefits plans are as follows:
Year ended Dec. 31, 2024
Registered
Supplemental
Other
Total
Current service cost
1
1
1
3
Administration expenses
1
—
—
1
Interest cost on defined benefit obligation
14
4
1
19
Interest on plan assets
(12)
(1)
—
(13)
Defined benefit expense
4
4
2
10
Defined contribution expense
12
—
—
12
Net expense
16
4
2
22
Year ended Dec. 31, 2023
Registered
Supplemental
Other
Total
Current service cost
1
1
—
2
Administration expenses
1
—
—
1
Interest cost on defined benefit obligation
16
4
1
21
Interest on plan assets
(13)
(1)
—
(14)
Defined benefit expense
5
4
1
10
Defined contribution expense
11
—
—
11
Net expense
16
4
1
21
Year ended Dec. 31, 2022
Registered
Supplemental
Other
Total
Current service cost
1
1
—
2
Administration expenses
1
—
—
1
Interest cost on defined benefit obligation
13
3
—
16
Interest on plan assets
(9)
—
—
(9)
Defined benefit expense
6
4
—
10
Defined contribution expense
11
—
—
11
Net expense
17
4
—
21
TransAlta Corporation
2024 Integrated Report
F88
C. Status of Plans
The status of the defined benefit pension and other post-employment benefit plans is as follows:
Year ended Dec. 31, 2024
Registered
Supplemental
Other
Total
Fair value of plan assets
241
16
—
257
Present value of defined benefit obligation
(303)
(90)
(18)
(411)
Funded status – plan deficit
(62)
(74)
(18)
(154)
Amount recognized in the Consolidated Financial Statements:
Accrued current liabilities
(1)
(6)
(1)
(8)
Other long-term liabilities
(61)
(68)
(17)
(146)
Total amount recognized
(62)
(74)
(18)
(154)
Year ended Dec. 31, 2023
Registered
Supplemental
Other
Total
Fair value of plan assets
269
15
—
284
Present value of defined benefit obligation
(340)
(89)
(17)
(446)
Funded status – plan deficit
(71)
(74)
(17)
(162)
Amount recognized in the Consolidated Financial Statements:
Accrued current liabilities
(1)
(5)
(1)
(7)
Other long-term liabilities
(70)
(69)
(16)
(155)
Total amount recognized
(71)
(74)
(17)
(162)
F89
TransAlta Corporation
2024 Integrated Report
D. Plan Assets
The fair value of the plan assets of the defined benefit pension and other post-employment benefit plans is as follows:
Registered
Supplemental
Other
Total
As at Dec. 31, 2022
274
15
—
289
Interest on plan assets
13
1
—
14
Net return on plan assets
15
(1)
—
14
Contributions(1)
5
6
2
13
Benefits paid
(36)
(6)
(2)
(44)
Administration expenses
(1)
—
—
(1)
Change in foreign exchange rates
(1)
—
—
(1)
As at Dec. 31, 2023
269
15
—
284
Interest on plan assets
12
1
—
13
Net return on plan assets
13
(1)
—
12
Contributions
1
6
1
8
Benefits paid
(31)
(5)
(1)
(37)
Administration expenses
(1)
—
—
(1)
Effect of settlement from annuitization of the U.S. defined
benefit plan (Note 27)
(23)
—
—
(23)
Change in foreign exchange rates
1
—
—
1
As at Dec. 31, 2024
241
16
—
257
(1)
The Company made a voluntary contribution of nil (2023 — $4 million) to further improve the funded status of the U.S. defined benefit pension plan for
the Centralia thermal facility.
TransAlta Corporation
2024 Integrated Report
F90
The fair value of the Company’s defined benefit plan assets by major category is as follows:
As at Dec. 31, 2024
Level I
Level II
Level III
Total
Equity securities
Canadian
—
12
—
12
International
—
53
—
53
Private
—
—
1
1
Bonds
A - AAA
—
18
81
99
BBB
—
1
16
17
Below BBB
—
—
5
5
Loans(1)
—
1
—
1
Other
Alternative funds(2)
—
—
46
46
Money market and cash and cash equivalents
2
19
2
23
Total
2
104
151
257
(1)
Includes A credit rating loans of $1 million.
(2) Alternative funds include investments in infrastructure and real estate funds.
As at Dec. 31, 2023
Level I
Level II
Level III
Total
Equity securities
Canadian
—
12
—
12
U.S.
—
6
—
6
International
—
86
—
86
Private
—
—
1
1
Bonds
A - AAA
—
30
62
92
BBB
1
5
10
16
Below BBB
—
—
4
4
Loans(1)
—
2
—
2
Other
Alternative funds(2)
—
—
44
44
Money market and cash and cash equivalents
2
19
—
21
Total
3
160
121
284
(1)
Includes A credit rating loans of $1 million.
(2) Alternative funds include investments in infrastructure and real estate funds.
Plan assets do not include any common shares of the Company at Dec. 31, 2024 and Dec. 31, 2023.
F91
TransAlta Corporation
2024 Integrated Report
E. Defined Benefit Obligation
The present value of the obligation for the defined benefit pension and other post-employment benefit plans is as
follows:
Registered
Supplemental
Other
Total
Present value of defined benefit obligation as at Dec. 31, 2022
345
85
17
447
Current service cost
1
1
—
2
Interest cost
16
4
1
21
Benefits paid
(36)
(6)
(2)
(44)
Actuarial gain arising from demographic assumptions
1
—
—
1
Actuarial gain arising from financial assumptions
12
4
1
17
Actuarial gain arising from experience adjustments
2
1
—
3
Change in foreign exchange rates
(1)
—
—
(1)
Present value of defined benefit obligation as at Dec. 31, 2023
340
89
17
446
Current service cost
1
—
1
2
Interest cost
14
4
1
19
Benefits paid
(31)
(5)
(1)
(37)
Actuarial gain arising from financial assumptions
1
1
—
2
Actuarial gain arising from experience adjustments
—
1
—
1
Effect of settlement from the termination of the U.S. defined
benefit plan (Note 27)
(23)
—
—
(23)
Change in foreign exchange rates
1
—
—
1
Present value of defined benefit obligation as at Dec. 31, 2024(1)
303
90
18
411
(1)
The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2024, is 9.8 years.
F. Contributions
The expected employer contributions for 2025 for the defined benefit pension and other post-employment benefit plans
are as follows:
Registered
Supplemental
Other
Total
Expected employer contributions
1
6
1
8
TransAlta Corporation
2024 Integrated Report
F92
G. Assumptions
The significant actuarial assumptions used in measuring the Company’s defined benefit obligation for the defined benefit
pension and other post-employment benefit plans are as follows:
2024
2023
As at Dec. 31 (per cent)
Registered
Supplemental
Other
Registered
Supplemental Other
Accrued benefit obligation
Discount rate
4.5
4.5
4.8
4.6
4.6
4.7
Rate of compensation increase
2.9
3.0
—
2.9
3.0
—
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)
—
—
6.7
—
—
6.8
Dental-care cost escalation
—
—
4.1
—
—
4.2
Benefit cost for the year
Discount rate
4.6
4.6
4.7
5.0
5.0
5.0
Rate of compensation increase
2.9
3.0
—
2.7
3.0
—
Assumed health-care cost trend rate
Health-care cost escalation(2)(4)
—
—
6.7
—
—
7.1
Dental-care cost escalation
—
—
4.6
—
—
4.7
(1)
2024 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2034 and remaining at that level thereafter for the U.S. and decreasing gradually
by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.
(2) 2024 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2033 and remaining at that level thereafter for the U.S. and decreasing gradually
by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.
(3) 2023 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2033 and remaining at that level thereafter for the U.S. and decreasing gradually
by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.
(4) 2023 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2032 and remaining at that level thereafter for the U.S. and decreasing gradually
by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.
H. Sensitivity Analysis
The following table outlines the estimated increase in the net defined benefit obligation assuming certain changes in
key assumptions:
Canadian plans
U.S. plans
As at Dec. 31, 2024
Registered
Supplemental
Other
Pension
1% decrease in the discount rate
28
10
1
—
1% increase in the salary scale
1
—
—
—
1% increase in the health-care cost trend rate
—
—
2
—
10% improvement in mortality rates
14
3
—
—
F93
TransAlta Corporation
2024 Integrated Report
33. Joint Arrangements
Joint arrangements at Dec. 31, 2024, included the following:
Joint operations
Segment
Ownership
(per cent)
Description
Goldfields Power
Gas
50
Gas-fired facility in Western Australia operated by
TransAlta
Fort Saskatchewan
Gas
60
Cogeneration facility in Alberta, of which TA Cogen has a
60 per cent interest, operated by TransAlta
Fortescue River Gas
Pipeline
Gas
43
Natural gas pipeline in Western Australia, operated by
DBP Development Group
McBride Lake
Wind and Solar
50
Wind generation facility in Alberta operated by TransAlta
Soderglen
Wind and Solar
50
Wind generation facility in Alberta operated by TransAlta
Pingston
Hydro
50
Hydro facility in British Columbia operated by TransAlta
Joffre(1)
Gas
40
Cogeneration plant in Alberta operated by TransAlta
McMahon(1)
Gas
50
Cogeneration plant in British Columbia operated by
TransAlta
Primrose(1)
Gas
50
Cogeneration plant in Alberta operated by TransAlta
Rainbow Lake(1)(2)
Gas
50
Cogeneration plant in Alberta operated by TransAlta
(1)The Company holds interest through its acquisition of Heartland. Refer to Note 4.
(2)The Company agreed to divest its interest in the Rainbow Lake facility to meet the requirements of the federal Competition Bureau, following the closing
of the acquisition. As at Dec. 31, 2024 the Rainbow Lake facility is classified as part of a disposal group held for sale. Refer to Note 18.
Joint venture
Segment
Ownership
(per cent)
Description
Skookumchuck
Wind and Solar
49
Wind generation facility in Washington operated by
Southern Power
Tent Mountain
Hydro
60
Pumped hydro energy storage development project in
Alberta
On Dec. 4, 2024, the Company acquired Heartland's 50
per cent interest in Sheerness, a natural-gas-fired
facility in Alberta, previously operated by Heartland.
Refer to Note 4 for details. On Oct. 8, 2024, the
Company increased its interest by an additional 10 per
cent interest in Tent Mountain. Refer to Note 9 for
details.
TransAlta Corporation
2024 Integrated Report
F94
34. Cash Flow Information
A. Change in Non-Cash Operating Working Capital
Year ended Dec. 31
2024
2023
2022
Source (use):
Accounts receivable
155
715
(869)
Prepaid expenses
85
—
—
Income taxes receivable
22
27
(61)
Inventory
34
(2)
6
Accounts payable, accrued liabilities and provisions
(273)
(550)
548
Income taxes payable
15
(66)
60
Change in non-cash operating working capital
38
124
(316)
B. Changes in Liabilities from Financing Activities
Balance
Dec. 31,
2023
Debt
assumed
Repayments
and dividends
paid(1)
New
leases
Dividends
declared
Foreign
exchange
impact
Other
Balance
Dec. 31,
2024
Long-term debt and
lease liabilities(2)
3,469
232
6
5
—
86
11
3,809
Exchangeable securities
744
—
—
—
—
—
6
750
Dividends payable
(common and preferred)
49
—
(123)
—
123
—
—
49
Total liabilities from
financing activities
4,262
232
(117)
5
123
86
17
4,608
(1)
Includes a decrease of $131 million related to the repayment of long-term debt, a $143 million net decrease in borrowings under credit facilities and a
decrease in finance lease obligations of $6 million.
(2) Includes bank overdraft of $1 million and new debt assumed of $232 million as part of the Heartland acquisition. Refer to Note 4.
Balance
Dec. 31,
2022
Cash
issuances
Repayments
and dividends
paid(1)
New
leases
Dividends
declared
Foreign
exchange
impact
Other
Balance
Dec. 31,
2023
Long-term debt and
lease liabilities(2)
3,669
39
(220)
5
—
(36)
12
3,469
Exchangeable securities
739
—
—
—
—
—
5
744
Dividends payable
(common and preferred)(3)
68
—
(109)
—
116
—
(26)
49
Total liabilities from
financing activities
4,476
39
(329)
5
116
(36)
(9)
4,262
(1)
Includes a decrease of $164 million related to the repayment of long-term debt, a $46 million net decrease in borrowings under credit facilities and a
decrease in finance lease obligations of $10 million.
(2) Includes bank overdraft of $3 million.
(3) Other dividends payable related to payment of TransAlta Renewables' non-controlling interest dividend reflected within distributions paid to
subsidiaries of non-controlling interests in the Consolidated Statements of Cash Flows.
F95
TransAlta Corporation
2024 Integrated Report
35. Capital
TransAlta’s capital is comprised of the following:
As at Dec. 31
2024
2023
Increase/
(decrease)
Long-term debt(1)
3,808
3,466
342
Exchangeable securities
750
744
6
Bank overdraft
1
3
(2)
Equity
Common shares
3,179
3,285
(106)
Preferred shares
942
942
—
Contributed surplus
42
41
1
Deficit
(2,458)
(2,567)
109
Accumulated other comprehensive income (loss)
41
(164)
205
Non-controlling interests
97
127
(30)
Less: Available cash and cash equivalents(2)
(337)
(348)
11
Less: Principal portion of restricted cash on TransAlta OCP bonds(3)
(17)
(17)
—
Less: Fair value (asset) liability of hedging instruments on long-term debt(4)
(7)
5
(12)
Total capital
6,041
5,517
524
(1)
Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities, current portion of long-term debt and new debt assumed as
part of the Heartland acquisition. Refer to Note 4.
(2) The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed using a net debt
position. These funds may be available and used to facilitate repayment of debt.
(3) The Company includes the principal portion of restricted cash on TransAlta OCP bonds as this cash is restricted specifically to repay outstanding debt.
(4) The Company includes the fair value of economic and designated hedging instruments on debt in an asset, or liability, position as a reduction, or
increase, in the calculation of capital, as the carrying value of the related debt has either increased, or decreased, due to changes in foreign
exchange rates.
TransAlta Corporation
2024 Integrated Report
F96
The Company’s overall capital management strategy and
its objectives in managing capital are as follows:
A. Maintain a Strong Financial Position
The
Company
operates
in
a
long-cycle
and
capital-intensive commodity business and it is therefore a
priority to maintain a strong financial position that enables
the Company to access capital markets at reasonable
interest rates. Maintaining a strong balance sheet also
allows our commercial team to contract the Company’s
portfolio with a variety of counterparties on terms and
prices that are favourable to the Company’s financial
results and provides the Company with better access to
capital markets through commodity and credit cycles. The
Company has an investment grade credit rating from
Morningstar DBRS. In 2024, 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 outlooks, and S&P Global Ratings
reaffirmed the Company's senior unsecured debt rating
and issuer credit rating of BB+ with a stable outlook. The
Company remains focused on maintaining a strong
financial position and cash flow coverage ratios. Credit
ratings provide information relating to the Company's
financing costs, liquidity and operations and affect the
Company's ability to obtain short and long-term financing
and/or the cost of such financing. Management routinely
monitors forecasted net earnings, cash flows, capital
expenditures and scheduled repayment of debt with a
goal of maintaining its credit ratings and to meet dividend
and PP&E expenditure requirements.
B. Liquidity
The Company manages variations in working capital using
existing liquidity under credit facilities to ensure sufficient
cash and credit are available to fund operations, pay
dividends, distribute payments to subsidiaries' non-
controlling interests and invest in PP&E.
For the years ended Dec. 31, 2024 and 2023, cash inflows and outflows are summarized below.
Year ended Dec. 31
2024
2023
Increase
(decrease)
Cash flow from operating activities
796
1,464
(668)
Change in non-cash working capital
(38)
(124)
86
Cash flow from operations before changes in working capital
758
1,340
(582)
Dividends paid on common shares
(71)
(58)
(13)
Dividends paid on preferred shares
(52)
(51)
(1)
Distributions paid to subsidiaries’ non-controlling interests
(40)
(223)
183
Property, plant and equipment expenditures
(311)
(875)
564
Inflow
284
133
151
TransAlta
maintains
sufficient
cash
balances
and
committed credit facilities to fund periodic net cash
outflows related to its business. At Dec. 31, 2024, $1.5
billion (2023 — $1.4 billion) of the Company’s credit
facilities were fully available.
From time to time, TransAlta accesses capital markets, as
required, to help fund some of these periodic net cash
outflows to maintain its available liquidity and maintain its
capital structure and credit metrics within targeted ranges.
F97
TransAlta Corporation
2024 Integrated Report
36. Related-Party Transactions
Details of the Company’s principal operating subsidiaries at Dec. 31, 2024, are as follows:
Subsidiary
Country
Ownership
(per cent)
Principal activity
TransAlta Generation Partnership
Canada
100
Generation and sale of electricity
TransAlta Cogeneration, L.P.
Canada
50.01
Generation and sale of electricity
TransAlta Centralia Generation, LLC
U.S.
100
Generation and sale of electricity
TransAlta Energy Marketing Corp.
Canada
100
Energy marketing
TransAlta Energy Marketing (U.S.), Inc.
U.S.
100
Energy marketing
TransAlta Energy (Australia), Pty Ltd.
Australia
100
Generation and sale of electricity
TransAlta Renewables Inc.
Canada
100
Generation and sale of electricity
Heartland Generation Ltd.
Canada
100(1)
Generation and sale of electricity
Alberta Power (2000) Ltd.
Canada
100(1)
Generation and sale of electricity
Associate or joint venture
Country
Ownership
(per cent)
Principal activity
SP Skookumchuck Investment, LLC
U.S.
49
Generation and sale of electricity
(1)
On Dec. 4, 2024, the Company completed the acquisition of Heartland. Refer to Note 4 for more details.
Transactions between the Company and its subsidiaries
have been eliminated on consolidation and are not
disclosed.
Associates and joint ventures have been equity
accounted for by the Company.
TransAlta Corporation
2024 Integrated Report
F98
A. Transactions with Key Management Personnel
TransAlta’s key management personnel include the President and Chief Executive Officer (CEO), members of the senior
management team that report directly to the President and CEO and the members of the Board. Key management
personnel compensation is as follows:
Year ended Dec. 31
2024
2023
2022
Total compensation
36
21
23
Comprising:
Short-term employee benefits
13
11
11
Post-employment benefits
1
1
1
Termination benefits
4
1
—
Share-based payments
18
8
11
B. Transactions with Associates
In connection with the exchangeable securities issued to
Brookfield, the Investment Agreement entitles Brookfield
to nominate two directors to the TransAlta Board. This
allows Brookfield to participate in the financial and
operating policy decisions of the Company, and as such,
they are considered associates of the Company.
In addition to the exchangeable securities disclosed in
Note 26, the Company may, in the normal course of
operations, enter into transactions on market terms with
associates that have been measured at exchange value
and recognized in the Consolidated Financial Statements,
including power purchase and sale agreements, derivative
contracts and asset management fees. Transactions and
balances between the Company and associates do
not eliminate.
Transactions with Brookfield include the following:
Year ended Dec. 31
2024
2023
2022
Power sales
58
135
127
Purchased power
4
2
12
Asset management fees paid
—
1
2
F99
TransAlta Corporation
2024 Integrated Report
37. Commitments and Contingencies
In addition to the commitments disclosed elsewhere in
the financial statements, the Company has incurred the
following contractual commitments, either directly or
through its interests in joint operations and joint
ventures.
Approximate future payments under these agreements are as follows:
2025
2026
2027
2028
2029
2030 and
thereafter
Total
Natural gas, transportation and
other contracts
75
68
65
66
64
425
763
Transmission
23
23
21
10
8
105
190
Coal supply agreements
75
—
—
—
—
—
75
Long-term service agreements
61
47
50
31
18
151
358
Operating leases
4
3
3
2
2
22
36
Growth
46
3
—
—
—
—
49
Total
284
144
139
109
92
703
1,471
Commitments
Natural Gas, Transportation and
Other Contracts
The Company has natural gas transportation contracts, for
a total of up to 400 terajoules (TJ) per day on a firm basis,
related to the Sundance and Keephills facilities, ending in
2036 to 2038. In addition, the Company has natural gas
transportation agreements for approximately 150 TJ per
day for Sheerness. The Company currently expects to use
approximately 160TJ per day on average and up to
approximately 450TJ per day during peak periods, while
remarketing excess capacity.
Transmission
The Company has several agreements to purchase
transmission network capacity in the Pacific Northwest.
Provided certain conditions for delivering the service are
met, the Company is committed to the transmission at the
supplier’s tariff rate whether it is awarded immediately or
delivered in the future after additional facilities are
constructed.
Transmission commitments also include multi-year U.S.
dollar denominated contracts to secure transmission
capacity. The majority of the transmission capacity
supports a dedicated revenue capacity agreement, held
with a counterparty in the U.S., for similar duration as the
associated transmission capacity.
Coal Supply Agreements
Various coal supply and associated rail transport contracts
are in place to provide coal for use in production at the
Centralia thermal facility. The coal supply agreements
allow TransAlta to take delivery of coal at fixed volumes
with dates extending through 2025.
Long-Term Service Agreements
TransAlta has various service agreements in place,
primarily for inspections, repairs and maintenance that
may be required on natural gas facilities, equipment for
gas and turbines at various wind facilities.
Operating Leases
Operating
leases
include
lease
commitments
not
recognized under IFRS 16 and lease commitments that
have not yet commenced, mainly related to buildings,
vehicles and land.
Growth
Commitments for growth include design and engineering
work, long lead equipment purchases, water treatment
construction and network upgrades.
TransAlta Corporation
2024 Integrated Report
F100
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 - has been
adjourned to November 2025.
Brazeau Facility — Claim against the
Government of Alberta
On Sept. 9, 2022, the Company filed a Statement of Claim
against the Government of Alberta in the Alberta Court of
King’s Bench seeking a declaration that: (a) granting
mineral leases within five kilometres of the Brazeau facility
is a breach of a 1960 agreement between the Company
and the Alberta Government; and (b) the Government of
Alberta is required to indemnify the Company for any
costs or damages that result from the risks of hydraulic
fracturing near the Brazeau facility. On Sept. 29, 2022, the
Government of Alberta filed its Statement of Defence,
which asserts, among other things, that the Company: (a)
is trying to usurp the jurisdiction of the AER; and (b) is out
of time under the Limitations Act (Alberta). The trial is
scheduled to be heard in September or October 2025 in
the event the parties are unable to resolve the dispute
prior to such date.
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 $53
million in damages. The Company disputes this claim in its
entirety and asserts a counterclaim. The parties have
initiated the dispute resolution procedure with an
arbitration hearing scheduled for three weeks starting April
14, 2025.
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
application was heard by Alberta Utilities Commission in
the first quarter of 2024. A decision was rendered on
Dec. 9, 2024, which directed the Balancing Pool to pay
TransAlta
$9
million,
being
the
shortfall
of
decommissioning costs of Sundance A from previously
collected
amounts
under
the
Power
Purchase
Arrangement Regulation.
Brazeau — Spinning Reserve Self-Report
On Nov. 30, 2022, TransAlta self-reported to the Market
Surveillance Administrator (MSA) a potential violation of
the Independent System Operator rules relating to offers
of active spinning reserves at Brazeau when it was not
properly configured to do so between Aug. 13, 2021, and
Nov. 1, 2022. In 2022 a provision of $20 million was
initially recognized in revenue reflecting a potential
disgorgement of revenue and $2 million for potential
penalties and fines. On Nov. 29, 2024, the MSA issued
penalties to TransAlta for this self-report and TransAlta
made a payment of $33 million in January 2025.
F101
TransAlta Corporation
2024 Integrated Report
38. Segment Disclosures
A. Description of Reportable Segments
The Company has six reportable segments as described
in Note 1. The Gas reportable segment includes Heartland,
which was acquired on Dec. 4, 2024. The Company has
aggregated Heartland within the Gas operating segment
as they are similar in the nature of the product and
process
and
are
subject
to
similar
environmental
regulations. Refer to Note 4 for more details.
The following tables provides each segment's results in
the format that the TransAlta’s President and Chief
Executive Officer (the chief operating decision maker)
(CODM) reviews the Company's segments to make
operating decisions and assess performance. The CODM
assesses the performance of the operating segments
based
on
a
measure
of
adjusted
EBITDA.
This
measurement basis represents earnings before income
taxes, adjusted for the effects of: depreciation of property,
plant and equipment and amortization of intangibles,
depreciation of right‐of‐use assets, finance lease income,
unrealized mark-to-market gains or losses, gains and
losses related to closed positions effectively settled by
offsetting positions with exchanges recorded in the year
the positions are settled, unrealized foreign exchange
gains or losses on commodity transactions, interest
income recorded on the prepaid funds, Brazeau penalties,
acquisition-related transaction and restructuring costs,
ERP integration costs, revenues and fuel and purchased
power related to the Planned Divestitures, 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,
Sundance A decommissioning costs reimbursement,
impairment charges, share of (profit) loss of joint venture
and other costs or income adjustments.
For internal reporting purpose, the earnings information
from the Company's investment in Skookumchuck has
been presented in the Wind and Solar segment on a
proportionate basis. Information on a proportionate basis
reflects
the
Company's
share
of
Skookumchuck's
statement
of
earnings
on
a
line-by-line
basis.
Proportionate financial information is not and is not
intended to be, presented in accordance with IFRS. Under
IFRS,
the
investment
in
Skookumchuck
has
been
accounted for as a joint venture using the equity method.
The tables below show the reconciliation of the total
segmented results and adjusted EBITDA to the statement
of earnings reported under IFRS.
TransAlta Corporation
2024 Integrated Report
F102
B. Reported Adjusted Segment Earnings and Segment Assets
I. Reconciliation of Adjusted EBITDA to Earnings before Income Tax
Year ended Dec. 31, 2024
Hydro
Wind &
Solar(1)
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
Equity-
accounted
investments(1)
Reclass
adjustments
IFRS
financials
Revenues
409
357
1,350
616
168
(34) 2,866
(21)
—
2,845
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss
1
84
(60)
(36)
14
—
3
—
(3)
—
Realized gain (loss) on closed
exchange positions
—
—
7
2
(15)
—
(6)
—
6
—
Decrease in finance lease receivable
—
2
19
—
—
—
21
—
(21)
—
Finance lease income
—
6
8
—
—
—
14
—
(14)
—
Revenues from Planned Divestitures
—
—
(1)
—
—
—
(1)
—
1
—
Brazeau penalties
(20)
—
—
—
—
—
(20)
—
20
—
Unrealized foreign exchange gain on
commodity
—
—
(2)
—
—
—
(2)
—
2
—
Adjusted revenues
390
449
1,321
582
167
(34) 2,875
(21)
(9)
2,845
Fuel and purchased power
16
30
475
418
—
—
939
—
—
939
Reclassifications and adjustments:
Fuel and purchased power related to
Planned Divestitures
—
—
(1)
—
—
—
(1)
—
1
—
Australian interest income
—
—
(4)
—
—
—
(4)
—
4
—
Adjusted fuel and purchased power
16
30
470
418
—
—
934
—
5
939
Carbon compliance
—
—
145
1
—
(34)
112
—
—
112
Gross margin
374
419
706
163
167
—
1,829
(21)
(14)
1,794
OM&A
86
97
198
69
36
173
659
(4)
—
655
Reclassifications and adjustments:
Brazeau penalties
(31)
—
—
—
—
—
(31)
—
31
—
ERP integration costs
—
—
—
—
—
(14)
(14)
—
14
—
Acquisition-related transaction and
restructuring costs
—
—
—
—
—
(24)
(24)
24
—
Adjusted OM&A
55
97
198
69
36
135
590
(4)
69
655
Taxes, other than income taxes
3
16
13
3
—
1
36
—
—
36
Net other operating income
—
(10) (40)
(9)
—
—
(59)
—
—
(59)
Reclassifications and adjustments:
Sundance A decommissioning cost
i
b
t
—
—
—
9
—
—
9
—
(9)
—
Adjusted net other operating income
—
(10) (40)
—
—
—
(50)
—
(9)
(59)
Adjusted EBITDA(2)
316
316
535
91
131
(136) 1,253
Equity income
5
Finance lease income
14
Depreciation and amortization
(531)
Asset impairment charges
(46)
Interest income
30
Interest expense
(324)
Foreign exchange gain
5
Gain on sale of assets and other
4
Earnings before income taxes
319
(1)
The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2) Adjusted EBITDA are not defined and have no standardized meaning under IFRS.
F103
TransAlta Corporation
2024 Integrated Report
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 gain
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 charges
48
Interest income
59
Interest expense
(281)
Foreign exchange gain
(7)
Gain on sale of assets and other
4
Earnings before income taxes
880
(1)
The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.
TransAlta Corporation
2024 Integrated Report
F104
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
(gain) 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)
—
Brazeau penalties
20
—
—
—
—
—
20
—
(20)
—
Unrealized foreign exchange
gain on commodity
—
—
—
—
(1)
—
(1)
—
1
—
Adjusted revenues
627
407
1,521
724
218
(2) 3,495
(14)
(505)
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
605
375
801
159
218
—
2,158
(14)
(509)
1,635
OM&A
55
68
195
69
35
101
523
(2)
—
521
Reclassifications and adjustments:
Brazeau penalties
(2)
—
—
—
—
—
(2)
—
2
—
Adjusted OM&A
53
68
195
69
35
101
521
(2)
2
521
Taxes, other than income taxes
3
12
15
4
—
1
35
(2)
—
33
Net other operating loss (income)
—
(23) (38)
—
—
—
(61)
3
—
(58)
Reclassifications and adjustments:
Royalty onerous contract and
contract termination penalties
—
7
—
—
—
—
7
—
(7)
—
Adjusted net other operating
loss (income)
—
(16) (38)
—
—
—
(54)
3
(7)
(58)
Adjusted EBITDA(2)
549
311
629
86
183
(102) 1,656
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.
F105
TransAlta Corporation
2024 Integrated Report
II. Selected Consolidated Statements of Financial Position Information
As at Dec. 31, 2024
Hydro
Wind and
Solar
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
PP&E
501
3,428 1,805
206
—
80 6,020
Right-of-use assets
7
96
6
—
—
11
120
Intangible assets
3
133
108
4
3
30
281
Goodwill
258
178
51
—
30
—
517
As at Dec. 31, 2023
Hydro
Wind and
Solar
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
PP&E
462
3,360 1,543
251
—
98
5,714
Right-of-use assets
7
94
5
—
—
11
117
Intangible assets
2
141
40
4
5
31
223
Goodwill
258
176
—
—
30
—
464
III. Selected Consolidated Statements of Cash Flows Information
Additions to non-current assets are as follows:
Year ended Dec. 31, 2024
Hydro
Wind and
Solar
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
Additions to non-current assets:
PP&E(1)
64
97
100
13
—
37
311
Intangible assets(1)
—
—
—
—
—
10
10
(1)Excludes additions attributable to the Heartland acquisition on Dec. 4, 2024
Year ended Dec. 31, 2023
Hydro
Wind and
Solar
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
Additions to non-current assets:
PP&E
42
674
89
16
—
54
875
Intangible assets
—
—
—
—
—
13
13
Year ended Dec. 31, 2022
Hydro
Wind and
Solar
Gas
Energy
Transition
Energy
Marketing
Corporate
Total
Additions to non-current assets:
PP&E
36
745
43
19
—
75
918
Intangible assets
—
19
—
—
3
9
31
TransAlta Corporation
2024 Integrated Report
F106
C. Geographic Information
I. Revenues
Year ended Dec. 31
2024
2023
2022
Canada
2,009
2,218
1,905
U.S.
676
987
940
Western Australia
160
150
131
Total revenue
2,845
3,355
2,976
II. Non-Current Assets
Property, plant and
equipment
Right-of-use
assets
Intangible assets
Other assets
As at Dec. 31
2024
2023
2024
2023
2024
2023
2024
2023
Canada
3,828
3,578
41
43
170
108
85
68
U.S.
1,852
1,749
74
71
86
88
36
42
Western Australia
340
387
5
3
25
27
58
69
Total
6,020
5,714
120
117
281
223
179
179
D. Significant Customer
For the year ended Dec. 31, 2024, sales to the Alberta
Electric System Operator represented 24 per cent of
the Company’s total revenue (2023 — 46 per cent of
the Company’s total revenue). There were no other
companies that accounted for more than 10 per cent of
the Company's total revenue.
F107
TransAlta Corporation
2024 Integrated Report
Eleven-Year Financial and Statistical Summary
(in millions of Canadian dollars, except where noted)
Year ended Dec. 31
2024
2023
2022
Financial Summary
STATEMENT OF EARNINGS
Revenues
2,845
3,355
2,976
Operating income (loss)
585
1089
531
Earnings (loss) before income taxes
319
880
353
Net earnings (loss) attributable to common shareholders
177
644
4
STATEMENT OF FINANCIAL POSITION
Total assets
9,499
8,659
10,741
Current portion of long-term debt, net of cash and cash equivalents
235
184
(940)
Credit facilities, long-term debt and finance lease obligations
3,236
2,934
3,475
Exchangeable securities
750
744
739
Non-controlling interests
97
127
879
Preferred shares
942
942
942
Equity attributable to common shareholders(1)
804
595
168
Principal portion of restricted cash on TransAlta OCP and fair value (asset)
liability of hedging instruments on debt(1)
(24)
(12)
(20)
Total capital(3)
6,041
5,517
5,243
CASH FLOWS
Cash flow from operating activities
796
1,464
877
Cash flow used in investing activities
(520)
(814)
(741)
COMMON SHARE INFORMATION (per share)
Net earnings
0.59
2.33
0.01
Comparable earnings(1)
n/a
n/a
n/a
Dividends declared on common share
0.24
0.22
0.21
Book value per common share (at year-end)(1)
2.66
2.16
0.62
Market price:
High
20.55
13.97
15.28
Low
8.35
10.02
10.52
Close (Toronto Stock Exchange at Dec. 31)
20.33
11.02
12.11
RATIOS (percentage except where noted)
Adjusted net debt to adjusted EBITDA(1,2,4,5) (times)
3.6
2.5
2.1
Return on equity attributable to common shareholders(1)
23.2
84.8
1.0
Comparable return on equity attributable to common shareholders(1)
n/a
n/a
n/a
Return on capital employed(1)
10.0
17.6
9.2
Comparable return on capital employed(1)
n/a
n/a
n/a
Earnings coverage (times)(1)
2.2
4.3
2.2
Dividend payout ratio based on FFO(1,5)
9.2
4.4
4.1
Adjusted EBITDA(1,2,4,5) (in millions of Canadian dollars)
1,253
1,632
1,656
Dividend coverage(1,5) (times)
11.2
24.6
18.3
Dividend yield(1)
1.1
2.0
1.7
Weighted average common shares for the year (in millions)
302
276
271
Common shares outstanding at Dec. 31 (in millions)
298
307
268
STATISTICAL SUMMARY
Number of employees
1,205
1,257
1,282
GROSS INSTALLED CAPACITY (MW)(6)
Energy Transition(8)
671
671
671
Gas(7,9)
4,834
3,084
3,084
Renewables (wind, solar and hydro)
3,509
3,006
2,828
Equity investments
67
67
67
Total generating capacity
9,081
6,828
6,650
Total production (GWh)
22,811
22,029
21,258
Financial data presented is based on IFRS. Prior year figures that appear within the MD&A have been restated to conform with the current year’s
presentation. All other prior year figures have not been restated.
(1)
These items are not defined and have no standardized meaning under IFRS. Periods for which the non-IFRS measure was not previously disclosed
have not been calculated. After 2016, comparable earnings measures are no longer being calculated or reported on.
TransAlta Corporation
2024 Integrated Report
267
2021
2020
2019
2018
2017
2016
2015
2014
2,721
2,101
2,347
2,249
2,307
2,397
2,267
2,623
(239)
(99)
335
160
138
478
148
442
(380)
(303)
193
(96)
(54)
314
221
239
(576)
(336)
52
(248)
(190)
117
(24)
141
9,226
9,747
9,508
9,428
10,304
10,996
10,947
9,833
(103)
(598)
102
59
433
334
33
708
2,423
3,256
2,699
3,119
2,960
3,722
4,408
3,305
735
730
326
—
—
—
—
—
1,011
1,084
1,101
1,137
1,059
1,152
1,029
594
942
942
942
942
942
942
942
942
640
1,410
2,019
2,055
2,384
2,569
2,419
2,342
(19)
(13)
(17)
(10)
(30)
(163)
(190)
(96)
5,629
6,811
7,172
7,275
7,748
8,556
8,641
7,795
1001
702
849
820
626
744
432
796
(472)
(687)
(512)
(394)
87
(327)
(573)
(292)
(2.13)
(1.22)
0.18
(0.86)
(0.66)
0.41
(0.09)
0.52
n/a
n/a
n/a
n/a
n/a
0.13
(0.17)
0.25
0.19
0.22
0.12
0.2
0.16
0.3
0.72
0.83
2.37
5.13
7.14
7.16
8.28
8.92
8.52
8.52
14.61
11.23
10.14
7.90
8.50
7.54
12.34
14.94
9.57
5.32
5.50
5.44
6.88
3.76
4.13
9.81
14.05
9.67
9.28
5.59
7.45
7.43
4.91
10.52
2.2
4.0
3.9
3.6
3.6
3.8
5.4
4.2
(116.6)
(30.3)
3.3
(15.8)
(10.0)
5.4
(1.2)
6.3
n/a
n/a
n/a
n/a
n/a
1.7
(2.3)
3.0
(4.5)
(1.5)
4.1
0.7
2.1
5.3
4.6
5.8
n/a
n/a
n/a
n/a
n/a
4.4
3.0
5.1
(1.0)
(0.5)
1.5
0.2
0.6
1.7
1.5
1.7
5.1
7.0
6.6
6.1
4.3
8.1
30.0
26.4
1,286
917
984
1,123
1,062
1,144
867
1,036
23.0
15.6
18.6
18.3
14.1
11.1
3.3
5.7
1.3
1.7
1.7
2.9
2.1
4.0
14.7
7.9
271
275
283
287
288
288
280
273
271
270
277
285
288
288
284
275
1,282
1,476
1,543
1,883
2,228
2,341
2,380
2,786
1,472
2,548
2,915
3,147
3,707
3,707
3,708
3,693
3,084
3,082
3,049
2,819
2,827
2,906
2,823
2,949
2,694
2,498
2,421
2,308
2,289
2,334
2,350
2,204
—
67
—
—
—
—
—
—
7,387
8,265
8,385
8,273
8,823
8,947
8,881
8,846
22,105
24,980
29,071
28,409
36,900
38,157
40,673
45,002
(2)
During 2024 our adjusted EBITDA composition was amended to exclude the impact of Brazeau penalties and related provisions. Therefore, the Company has
applied this composition to all previously reported periods.
(3)
Total capital for 2014 has been revised to align with the 2015 calculation methodology.
(4)
In 2022, the adjusted EBITDA composition was amended to include the impact of closed exchange positions that are effectively settled by offsetting positions with
the same counterparty to reflect the performance of the assets and the Energy Marketing segment in the period in which the transactions occur. Therefore, the
Company has applied this composition to 2022, 2021 and 2020 only. In 2019 and onwards adjusted EBITDA was adjusted to exclude the impact of unrealized
mark-to-market gains or losses. 2018 and 2017 amounts were revised.
(5)
2016 and 2015 amounts were revised due to other revisions to EBITDA or FFO measures in the MD&A.
(6)
2014 to 2020 are gross installed capacity, which reflects the basis of underlying results. Prior year figures are as previously reported.
(7)
Includes finance lease receivables.
(8)
In 2021, Gas was adjusted to include the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment
previously known as Alberta Thermal. Prior year figures were revised.
(9)
In 2021, Energy Transition was adjusted to include the segments previously known as Centralia and the coal generation assets from the segment previously known
as Alberta Thermal. Prior year figures were revised.
268
TransAlta Corporation
2024 Integrated Report
Ratio Formulas
Adjusted net debt to Adjusted EBITDA = long-term debt
and
lease
liabilities
including
current
portion
+
exchangeable securities + fair value (asset) liability of
hedging instruments on debt + 50 per cent issued
preferred shares and exchangeable preferred shares -
cash and cash equivalents - principal portion of TransAlta
OCP
restricted
cash
/
Adjusted
EBITDA
-
PPA
termination payments
Return on equity attributable to common shareholders =
net earnings (loss) attributable to common shareholders
excluding gain on discontinued operations or earnings on a
comparable basis / equity attributable to common
shareholders excluding AOCI
Return on capital employed = earnings (loss) before
income taxes + net interest expense - net earnings
(loss) attributable to non-controlling interests / total
capital - AOCI
Earnings coverage = earnings (loss) before income taxes
+ net interest expense / 50 per cent dividends paid on
preferred shares + interest on debt - interest income
Dividend payout ratio based on FFO = common share
dividends paid / FFO - 50 per cent dividends paid on
preferred shares
Dividend coverage = FFO - cash dividends paid on
preferred shares + change in non-cash operating working
capital balances / cash dividends paid on common shares
Dividend yield = dividends paid per common share /
current year’s closing price
TransAlta Corporation
2024 Integrated Report
269
Plant Summary
Hydro
Barrier, AB
13
100 %
13
100 %
13
Western Canada
Merchant
—
24 facilities
Bearspaw, AB
17
100 %
17
100 %
17
Western Canada
Merchant
—
Belly River, AB
3
100 %
3
100 %
3
Western Canada
Merchant
—
Bighorn, AB
120
100 %
120
100 %
120
Western Canada
Merchant
—
Brazeau, AB
355
100 %
355
100 %
355
Western Canada
Merchant
—
Cascade, AB
36
100 %
36
100 %
36
Western Canada
Merchant
—
Ghost, AB
54
100 %
54
100 %
54
Western Canada
Merchant
—
Horseshoe, AB
14
100 %
14
100 %
14
Western Canada
Merchant
—
Interlakes, AB
5
100 %
5
100 %
5
Western Canada
Merchant
—
Kananaskis, AB
19
100 %
19
100 %
19
Western Canada
Merchant
—
Pocaterra, AB
15
100 %
15
100 %
15
Western Canada
Merchant
—
Rundle, AB
50
100 %
50
100 %
50
Western Canada
Merchant
—
Spray, AB
112
100 %
112
100 %
112
Western Canada
Merchant
—
St. Mary, AB
2
100 %
2
100 %
2
Western Canada
Merchant
—
Taylor, AB
13
100 %
13
100 %
13
Western Canada
Merchant
—
Three Sisters, AB
3
100 %
3
100 %
3
Western Canada
Merchant
—
Waterton, AB
3
100 %
3
100 %
3
Western Canada
Merchant
—
Akolkolex, BC
10
100 %
10
100 %
10
Western Canada
LTC(2)
2046
Bone Creek, BC
19
100 %
19
100 %
19
Western Canada
LTC
2031
Pingston, BC
45
50 %
23
100 %
23
Western Canada
LTC
2043
Upper Mamquam, BC
25
100 %
25
100 %
25
Western Canada
LTC
2045
Misema, ON
3
100 %
3
100 %
3
Eastern Canada
LTC
2027
Moose Rapids, ON
1
100 %
1
100 %
1
Eastern Canada
LTC
2030
Ragged Chute, ON
7
100 %
7
100 %
7
Eastern Canada
LTC
2029
Total Hydro
944
922
922
Wind &
Ardenville, AB
69
100 %
69
100 %
69
Western Canada
Merchant
—
Battery Storage
Blue Trail and Macleod
Flats, AB
69
100 %
69
100 %
69
Western Canada
Merchant
—
32 facilities
Castle River, AB(3)
44
100 %
44
100 %
44
Western Canada
Merchant
—
Cowley North, AB
20
100 %
20
100 %
20
Western Canada
Merchant
—
Garden Plain, AB
130
100 %
130
100 %
130
Western Canada
LTC
2034-2041
McBride Lake, AB
75
50 %
38
100 %
38
Western Canada
Merchant
Oldman, AB
4
100 %
4
100 %
4
Western Canada
Merchant
—
Sinnott, AB
5
100 %
5
100 %
5
Western Canada
Merchant
—
Soderglen, AB
71
50 %
36
100 %
36
Western Canada
Merchant
—
Summerview 1, AB
68
100 %
68
100 %
68
Western Canada
Merchant
—
Summerview 2, AB
66
100 %
66
100 %
66
Western Canada
Merchant
—
WindCharger battery
storage, AB
10
100 %
10
100 %
10
Western Canada
Merchant
—
Windrise, AB
206
100 %
206
100 %
206
Western Canada
LTC
2041
Kent Breeze, ON
20
100 %
20
100 %
20
Eastern Canada
LTC
2031
Melancthon, ON(4)
200
100 %
200
100 %
200
Eastern Canada
LTC
2028-2031
As at Dec. 31, 2024
Facility
Nameplate
capacity
(MW)(1)
Consolidated
interest
Gross
installed
capacity(1)
Ownership
(%)
Net capacity
ownership
interest
(MW)(1)
Region
Revenue
source
Contract
expiry date
270
TransAlta Corporation
2024 Integrated Report
Wolfe Island, ON
198
100 %
198
100 %
198
Eastern Canada
LTC
2029
Kent Hills, NB(5)
167
100 %
167
83 %
139
Eastern Canada
LTC
2045
Le Nordais, QC
98
100 %
98
100 %
98
Eastern Canada
LTC
2033
New Richmond, QC
68
100 %
68
100 %
68
Eastern Canada
LTC
2033
Antrim, NH
29
100 %
29
100 %
29
United States
LTC
2039
Big Level, PA
90
100 %
90
100 %
90
United States
LTC
2034
Horizon Hill, OK
202
100 %
202
100 %
202
United States
LTC13
—
Lakeswind, MN
50
100 %
50
100 %
50
United States
LTC
2034
White Rock East, OK
202
100 %
202
100 %
202
United States
LTC13
—
White Rock West, OK
100
100 %
100
100 %
100
United States
LTC13
—
Wyoming Wind, WY
140
100 %
140
100 %
140
United States
LTC
2028
Skookumchuck, WA
137
49 %
67
100 %
67
United States
LTC
2040
Northern Goldfields
Battery, WA(8)
10
100 %
10
100 %
10
Australia
LTC
2038
Total Wind
2548
2,406
2,378
Solar
Mass Solar, MA(6)
21
100 %
21
100 %
21
United States
LTC
2032-2045
4 facilities
North Carolina Solar,
NC(7)
122
100 %
122
100 %
122
United States
LTC
2033
Northern Goldfields,
WA(8)
38
100 %
38
100 %
38
Australia
LTC
2038
Total Solar
181
181
181
As at Dec. 31, 2024
Facility
Nameplate
capacity
(MW)(1)
Consolidated
interest
Gross
installed
capacity(1)
Ownership
(%)
Net capacity
ownership
interest
(MW)(1)
Region
Revenue
source
Contract
expiry date
TransAlta Corporation
2024 Integrated Report
271
As at Dec. 31, 2024
Facility
Nameplate
capacity
(MW)(1)
Consolidated
interest
Gross
installed
capacity(1)
Ownership
(%)
Net capacity
ownership
interest
(MW)(1)
Region
Revenue
source
Contract
expiry date
Gas
McMahon, BC
120
50 %
60
100 %
60
Western Canada
LTC
2029
26 facilities
Battle River 4, AB
155
100 %
155
100 %
155
Western Canada
Merchant
—
Battle River 5, AB
395
100 %
395
100 %
395
Western Canada
Merchant
—
Fort Saskatchewan, AB
118
60 %
71
50 %
35
Western Canada
LTC/Merchant
2029
Joffre, AB
474
40 %
190
100 %
190
Western Canada
LTC/Merchant
2041
Keephills 2, AB
395
100 %
395
100 %
395
Western Canada
Merchant
—
Keephills 3, AB
466
100 %
466
100 %
466
Western Canada
Merchant
—
Muskeg River, AB
202
100 %
202
100 %
202
Western Canada
LTC
2042
Poplar Creek, AB(9)
230
100 %
230
100 %
230
Western Canada
LTC
2030
Primrose, AB
100
50 %
50
100 %
50
Western Canada
LTC
2028
Scotford, AB
195
100 %
195
100 %
195
Western Canada
LTC/Merchant
2043
Sheerness, AB(4)
800
100 %
800
75 %
600
Western Canada
Merchant
—
Sundance 6, AB
401
100 %
401
100 %
401
Western Canada
Merchant
—
Valleyview 1, AB
50
100 %
50
100 %
50
Western Canada
Merchant
—
Valleyview 2, AB
50
100 %
50
100 %
50
Western Canada
Merchant
—
Ottawa, ON
74
100 %
74
50 %
37
Eastern Canada
LTC/ Merchant
2033
Sarnia, ON
499
100 %
499
100 %
499
Eastern Canada
LTC
2031
Windsor, ON
72
100 %
72
50 %
36
Eastern Canada
LTC/ Merchant
2031
Ada, MI
29
100 %
29
100 %
29
United States
LTC
2026
Fortescue River Gas
Pipeline, WA
N/A
100 %
N/A
100 %
N/A
Australia
LTC
2035
Parkeston, WA(10)
110
50 %
55
100 %
55
Australia
LTC/Merchant
2026
Southern Cross, WA(11)
245
100 %
245
100 %
245
Australia
LTC
2038
South Hedland, WA(12)
150
100 %
150
100 %
150
Australia
LTC
2042
Total Gas
5330
4834
4525
Energy Transition
Centralia, WA
670
100 %
670
100 %
670
United States
LTC/ Merchant
2025(14)
2 facilities
Skookumchuck, WA
1
100 %
1
100 %
1
United States
LTC
2025
Total Energy Transition
671
671
671
Total
9,674
9,014
8,677
(1)
MW are rounded to the nearest whole number; columns may not add due to rounding. The gross installed capacity reflects the basis of consolidation of
underlying assets owned, net capacity ownership interest deducts capacity attributable to non-controlling interest in these assets and is calculated
after consolidation of underlying assets.
(2)
Long-term contract.
(3)
Includes seven individual turbines at other locations.
(4)
Comprised of two facilities.
(5)
Comprised of three facilities.
(6)
Comprised of four ground-mounted sites and four roof-top sites.
(7)
Comprised of 20 sites.
(8)
Comprises multiple facilities.
(9)
The Poplar Creek plant is operated by Suncor and ownership of the facility will transfer to Suncor in 2030.
(10)
The Parkeston facility is contracted to October 2023 with early termination options that begin in 2021.
(11)
Comprised of four facilities. Does not include Northern Goldfields facilities that are in the Wind and Solar segment.
(12)
The South Hedland facility is contracted with Fortescue Metals Group Ltd. ("FMG") and Horizon Power.
(13)
The PPA term is confidential for the Horizon Hill and White Rock wind facilities.
(14)
Contract is in place until 2025; however, Centralia Unit 1 was retired from service effective Dec. 31, 2020, and capacity decreased to 670 MW on
Jan. 1, 2021.
272
TransAlta Corporation
2024 Integrated Report
Sustainability Performance
Indicators
Performance below excludes the acquisition of Heartland Generation on Dec. 4, 2024. Refer to "Discussion and Notes on
Numbers" for footnote explanations. √ 2024 data has been assured to a limited assurance level by Ernst & Young LLP. √√
indicates data for 2024, 2023 and 2022 has been assured to a limited assurance level by Ernst & Young LLP.
Environment, Health and Safety (EHS) Management Systems(2)
2024
2023(1)
2022(1)
EHS management system audits
5
5
4
Health and Safety compliance audits
11
3
9
Total EHS audits
16
8
13
Environmental Performance(3)
2024
2023(1)
2022(1)
Resource or energy use(4)
Coal combustion (tonnes)
1,772,000
2,492,000
2,181,000
Diesel combustion (L)
6,479,000
6,920,000
6,685,000
Gasoline combustion (L)
18,000
3,000
3,000
Natural gas combustion (GJ)
121,916,000
123,067,000
130,023,000
Oil combustion (L)
20,000
26,000
15,000
Propane combustion (L)
1,000
2,000
3,000
Biodiesel consumption: vehicle (L)
8,000
10,000
14,000
Diesel consumption: vehicle (L)
2,262,000
2,315,000
3,261,000
Ethanol consumption: vehicle (L)
11,000
7,000
9,000
Gasoline consumption: vehicle (L)
696,000
608,000
605,000
Propane consumption: vehicle (L)
8,000
8,000
7,000
Electricity: building operations (MWh)
162,000
126,000
152,000
Kerosene: building operations (L)
0
0
3,000
Natural gas: building operations (GJ)
148,000
94,000
42,000
Propane: building operations (L)
93,000
110,000
169,000
Total resource or energy use (GJ)
174,953,000
197,357,000
186,393,000
Greenhouse gas (GHG) emissions
Scope 1 and 2 GHG emissions(5)
Carbon dioxide (tonnes CO2e)
9,463,000
10,862,000
10,185,000
Methane (tonnes CO2e)
49,000
26,000
24,000
Nitrous oxide (tonnes CO2e)
52,000
36,000
40,000
Sulphur hexafluoride (tonnes CO2e)
230
80
150
Total scope 1 and 2 GHG emissions (tonnes CO2e)(6) √
9,564,000
10,924,000
10,249,000
GHG emission intensity (tonnes CO2e/MWh)(7) √
0.35
0.41
0.40
Scope 1 emissions (tonnes CO2e)
9,497,000
10,871,000
10,179,000
Scope 1 emissions (percentage of total GHG emissions)
99
100
99
Scope 1 emissions reported to national regulatory bodies (percentage)
100
100
100
Scope 2 emissions (tonnes CO2e)(5)
67,000
53,000
70,000
Scope 2 emissions (percentage of total GHG emissions)
1
0
1
Total GHG emissions avoided (tonnes CO2e)(8)
2,818,000
2,280,000
2,744,000
Scope 3 GHG emissions(9)
Upstream scope 3 emissions
Category 1: Purchased goods and services(10) √√
30,000
32,000
28,000
Category 2: Capital goods(11) √√
24,000
86,000
140,000
TransAlta Corporation
2024 Integrated Report
273
Environmental Performance (continued)
2024
2023(1)
2022(1)
Category 3: Fuel and energy related activities(12) √√
950,000
954,000
963,000
Downstream scope 3 emissions
Category 11: Use of sold products(13) √√
583,000
716,000
556,000
Category 15: Investments(14) √√
1,834,000
1,651,000
1,846,000
Other relevant categories(15)
242,000
308,000
283,000
Total scope 3 GHG emissions (tonnes CO2e)
3,664,000
3,747,000
3,816,000
Air emissions(16)
Total sulphur dioxide emissions (tonnes) √
870
1,100
1,200
Sulphur dioxide emission intensity (kg/MWh) √
0.03
0.04
0.05
Total nitrogen oxide emissions (tonnes) √
8,700
11,000
11,000
Nitrogen oxide emission intensity (kg/MWh) √
0.32
0.40
0.43
Total particulate matter emissions (tonnes) √
320
460
360
Particulate matter emission intensity (kg/MWh) √
0.01
0.02
0.02
Total mercury emissions (kilograms)(16) √
16
21
21
Mercury emission intensity (mg/MWh)(16) √
0.61
0.80
0.83
Water management (17)
Water withdrawal – other sources (million m3)
1
1
1
Water withdrawal – surface water (million m3)
236
272
232
Water withdrawn – all sources (million m3) √
237
273
233
Water discharge – to other sources (million m3)
2
1
0
Water discharge – surface water (million m3)
209
238
207
Water discharge – all sources (million m3) √
212
239
207
Water consumption (million m3) √
25
34
26
Water consumption intensity (m3/MWh)(18) √
0.92
1.25
1.03
Waste management(19)
Diverted from disposal - Non-hazardous(20)
Solid recycled (tonnes)
2,000
2,600
1,600
Liquid recycled (tonne eq.)
210
120
1,800
Reuse (tonnes)(20)
372,000
457,000
453,000
Storage (tonnes)(21)
6
1,400
26,000
Compost (tonnes)
0
1
0
Total non-hazardous waste diverted from disposal (tonnes)
374,000
461,000
485,000
Diverted from disposal - Hazardous
Solid recycled (tonnes)
2,600
10
0
Liquid recycled (tonne eq.)
6,700
17,000
18,000
Total hazardous waste diverted from disposal (tonnes)
9,300
17,000
18,000
Total waste diverted from disposal (tonnes) √
383,000
478,000
503,000
Directed to disposal - Non-hazardous(22)
Solid landfill (tonnes)
780
1,300
1,800
Liquid landfill (tonne eq.)
34
39
67
Ash disposal – mine (tonnes)(23)
0
0
2,900
Ash disposal – lagoon (tonnes)(24)
0
0
0
Total non-hazardous waste directed to disposal (tonnes)
820
1,300
4,800
Directed to disposal - Hazardous
Solid landfill (tonnes)
29
0
81
Liquid landfill (tonne eq.)
29
10
46
Total hazardous waste directed to disposal (tonnes)
58
10
130
Total waste directed to disposal (tonnes) √
880
1,300
4,900
274
TransAlta Corporation
2024 Integrated Report
Environmental Performance (continued)
2024
2023(1)
2022(1)
Land use and reclamation(25)
Land used in mining activities – disturbed (cumulative hectares)(25) √
12,500
12,500
12,500
Land used in mining activities – reclaimed (cumulative hectares)(25) √
5,000
5,000
4,800
Reclamation of land used in mining activities (percentage of land disturbed)(25) √
40
40
39
Land used in mining activities: disturbed minus reclaimed (hectares)(25) √
7,500
7,500
7,700
Land used by facilities, offices and equipment (hectares)(25) √
4,000
4,000
4,000
Total land use (cumulative hectares)(25) √
11,500
11,500
11,600
Environmental incidents(26)
Significant environmental incidents
0
0
0
Regulatory non-compliance environmental incidents
0
0
1
Total environmental incidents √
0
0
1
Environmental enforcement actions(27)
0
0
2
Environmental fines ($ thousands)
0
0
35
Environmental spills(28)
Volume of significant environmental spills (m3)
0
0
246
Biodiversity-related incidents(29)
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
Social Performance
2024
2023
2022
Workplace practices
`
Employees
1,205
1,257
1,222
Number of full-time employees
1,165
1,173
1,150
Number of part-time employees
9
11
14
Number of contingent employees
31
73
58
Employees represented by independent trade union organizations (percentage)(30)
29
30
31
Voluntary employee turnover rate (percentage)(31)
18
5
9
Health and safety
Health and safety enforcement actions(32)
0
0
0
Health and safety fines ($ thousands)
0
0
0
Employee and contractor fatalities √
0
0
0
Lost-time injury (LTI) incidents (absence from work)(33) √
0
1
0
Medical aid (MA) incidents (no absence from work)(34) √
6
4
6
Restricted work injury (RWI) incidents (no absence from work)(35) √
2
0
0
Total recordable injuries to employees and contractors √
8
5
6
Exposure hours(36)
2,844,000
3,362,000
3,058,000
Total Recordable Injury Frequency (TRIF) (employees and contractors)(37)√
0.56
0.30
0.39
Community relations
Community investments ($ millions)(38)
2.9
3.2
2.3
Governance Performance
2024
2023
2022
Diversity
Women in workforce (percentage of all employees)
28
27
26
Women in senior management (percentage)
32
26
30
Women on Board of Directors (percentage)
38
46
36
TransAlta Corporation
2024 Integrated Report
275
Alignment of Sustainability Performance Indicators with Best
Practice Sustainability Reporting Frameworks
The following outlines our sustainability or ESG performance indicator alignment with key criteria of GRI and SASB.
Internally developed criteria are described in the footnotes to the Sustainability Performance Indicators.
Environment, Health and Safety (EHS) Management Systems
Criteria
EHS management system audits
Internally developed criteria(2)
Health and Safety compliance audits
Internally developed criteria(2)
Total EHS audits
Environmental Performance
Criteria
Resource or energy use
GRI 302-1
Coal combustion (tonnes)
GRI 302-1
Natural gas combustion (GJ)
GRI 302-1
Diesel combustion (L)
GRI 302-1
Gasoline consumption: vehicle (L)
GRI 302-1
Diesel consumption: vehicle (L)
GRI 302-1
Propane consumption: vehicle (L)
GRI 302-1
Electricity: building operations (MWh)
GRI 302-1
Natural gas: building operations (GJ)
GRI 302-1
Propane: building operations (L)
GRI 302-1
Kerosene: building operations (L)
GRI 302-1
Total resource or energy use (GJ)
GRI 302-1
Greenhouse gas (GHG) emissions
Carbon dioxide (tonnes CO2e)
SASB IF-EU-110a.1
Methane (tonnes CO2e)
SASB IF-EU-110a.1
Nitrous oxide (tonnes CO2e)
SASB IF-EU-110a.1
Sulphur hexafluoride (tonnes CO2e)
SASB IF-EU-110a.1
Total scope 1 and 2 GHG emissions (tonnes CO2e)
Internally developed criteria(5)(6)
GHG emission intensity (tonnes CO2e/MWh)
GRI 305-4
Scope 1 emissions (tonnes CO2e)
SASB IF-EU-110a.1
Scope 1 emissions (percentage of total GHG emissions)
SASB IF-EU-110a.1
Scope 1 emissions reported to national regulatory bodies (percentage)
SASB IF-EU-110a.1
Scope 2 emissions (tonnes CO2e)
GRI 305-2
Scope 2 emissions (percentage of total GHG emissions)
GRI 305-2
Total GHG emissions avoided (tonnes CO2e)
Internally developed criteria(8)
Scope 3 GHG emissions
Upstream scope 3 emissions
Category 1: Purchased goods and services
GHG Protocol
Category 2: Capital goods
GHG Protocol
Category 3: Fuel and energy related activities
GHG Protocol
Downstream scope 3 emissions
Category 11: Use of sold product
GHG Protocol
Category 15: Investments
GHG Protocol
Other relevant categories
GHG Protocol
Total scope 3 GHG emissions (tonnes CO2e)
GHG Protocol
276
TransAlta Corporation
2024 Integrated Report
Environmental Performance (continued)
Criteria
Air emissions
Total sulphur dioxide emissions (tonnes)
SASB IF-EU-120a.1
Sulphur dioxide emission intensity (kg/MWh)
Internally developed criteria(16)
Total nitrogen oxide emissions (tonnes)
SASB IF-EU-120a.1
Nitrogen oxide emission intensity (kg/MWh)
Internally developed criteria(16)
Total particulate matter emissions (tonnes)
SASB IF-EU-120a.1
Particulate matter emission intensity (kg/MWh)
Internally developed criteria(16)
Total mercury emissions (kilograms)
SASB IF-EU-120a.1
Mercury emission intensity (mg/MWh)
Internally developed criteria(16)
Water management
Water withdrawal – water utility/municipality/customer (million m3)
SASB IF-EU-140a.1
Water withdrawal – surface water (million m3)
SASB IF-EU-140a.1
Water withdrawn – all sources (million m3)
SASB IF-EU-140a.1
Water discharge – all sources (million m3)
Internally developed criteria(17)
Water consumption (million m3)
SASB IF-EU-140a.1
Water consumption intensity (m3/MWh)
Internally developed criteria(18)
Waste management
Diverted from disposal - Non-hazardous
Recycled (tonnes)
GRI 306-4
Recycled (L)
GRI 306-4
Reuse (tonnes)
GRI 306-4
Storage (tonnes)
GRI 306-4
Total non-hazardous waste diverted from disposal (tonnes)
GRI 306-4
Diverted from disposal - Hazardous
Recycled (tonnes)
GRI 306-4
Recycled (L)
GRI 306-4
Total hazardous waste diverted from disposal (tonnes)
GRI 306-4
Total waste diverted from disposal (tonnes)
GRI 306-4
Directed to disposal - Non-hazardous
Landfill (tonnes)
GRI 306-5
Landfill (L)
GRI 306-5
Ash disposal – mine (tonnes)
GRI 306-5
Ash disposal – lagoon (tonnes)
GRI 306-5
Compostable (tonnes)
GRI 306-5
Total non-hazardous waste directed to disposal (tonnes)
GRI 306-5
Directed to disposal - Hazardous
Landfill (tonnes)
GRI 306-5
Landfill (L)
GRI 306-5
Total hazardous waste directed to disposal (tonnes)
GRI 306-5
Total waste directed to disposal (tonnes)
GRI 306-5
Land use and reclamation
Land used in mining activities – disturbed (cumulative hectares)
Internally developed criteria(25)
Land used in mining activities – reclaimed (cumulative hectares)
Internally developed criteria(25)
Reclamation of land used in mining activities (percentage of land disturbed)
Internally developed criteria(25)
Land used in mining activities: disturbed minus reclaimed (hectares)
Internally developed criteria(25)
Land used by plants, offices and equipment (hectares)
Internally developed criteria(25)
Total land use (cumulative hectares)
Internally developed criteria(25)
TransAlta Corporation
2024 Integrated Report
277
Environmental Performance (continued)
Criteria
Environmental incidents
Significant environmental incidents
Internally developed criteria(26)
Regulatory non-compliance environmental incidents
GRI 2-27
Total environmental incidents
Internally developed criteria(26)
Environmental enforcement actions
GRI 2-27
Environmental fines ($ thousands)
GRI 2-27
Environmental spills
Volume of significant spills (m3)
GRI 306-3
Biodiversity-related incidents
Critically Endangered
Internally developed criteria(29)
Endangered
Internally developed criteria(29)
Vulnerable
Internally developed criteria(29)
Near threatened
Internally developed criteria(29)
Total biodiversity-related incidents
Internally developed criteria(29)
Social Performance
Criteria
Workplace practices
Employees
GRI 102-7
Number of full-time employees
Internally developed criteria
Number of part-time employees
Internally developed criteria
Number of contingent employees
Internally developed criteria
Employees represented by independent trade union organizations (percentage)
GRI 102-41
Voluntary employee turnover rate (percentage)
GRI 401-1
Health and safety
Health and safety enforcement actions
Internally developed criteria(32)
Health and safety fines ($ thousands)
Internally developed criteria(32)
Employee and contractor fatalities
SASB IF-EU-320a.1
Lost-time injury (LTI) incidents (absence from work)
SASB IF-EU-320a.1
Medical aid (MA) incidents (no absence from work)
SASB IF-EU-320a.1
Restricted work injury (RWI) incidents (no absence from work)
SASB IF-EU-320a.1
Total injuries to employees and contractors
SASB IF-EU-320a.1
Exposure hours
SASB IF-EU-320a.1
Total Recordable Injury Frequency (TRIF) (employees and contractors)
SASB IF-EU-320a.1
Community relations
Community investments ($ millions)
GRI 203-1
Governance Performance
Criteria
Diversity
Women in workforce (percentage of all employees)
GRI 405-1
Women in senior management (percentage)
GRI 405-1
Women on Board of Directors (percentage)
GRI 405-1
278
TransAlta Corporation
2024 Integrated Report
Discussion and Notes on Numbers
TransAlta strives to improve the accuracy and scope of our
sustainability performance data. We continually review our
processes and controls relating to the measurement and
calculation of key sustainability data annually. Several
footnotes appear throughout the statistical summary and
are intended to provide clarity on specific boundary
conditions, changes in methodology and definitions. For
questions or clarity on any key performance indicators,
please contact us at sustainability@transalta.com.
1.
Some of the values related to 2022 and 2023 have
been restated to reflect better available data or
correction of errors regardless of magnitude to be
reported with complete accuracy. Refer to end notes
associated with individual performance indicators
which identify and explain nature of restatement from
previously reported values.
2.
EHS management system audits are conducted
annually
to
assesses
conformance
to
our
environmental,
health
and
safety
management systems. Health and Safety compliance
audits are conducted to verify compliance to internal
health and safety standards and procedures and
defined occupational health and safety regulatory
requirements.
3.
Environmental performance figures have been rounded
based
on
the
following
methodology:
i)
All
environmental data between 0-100 are rounded to the
nearest whole number, 100-1,000 to the nearest 10,
1,000-10,000 to the nearest hundred, and above
10,000 to the nearest thousand; ii) Water data is
rounded to the nearest million; iii) Land use data,
which is smaller in magnitude compared with other
environmental indicators, is rounded to the nearest 100
to represent a more accurate picture of management
and progress. Some values may not sum to the
indicated total due to rounding.
4.
Energy use is calculated and reported from TransAlta-
operated facilities, following the same approach we
use for GHG emissions reporting, which is the
application of an ‘Operational Control’ boundary as per
guidance from the GHG Protocol: A Corporate
Accounting and Reporting Standard. The energy use
data for years 2022 and 2023 differ from previous
years as the categories of fuel/energy have been
expanded to better reflect our activity consumption.
5.
Scope 1 and 2 GHG emissions are calculated and
reported from TransAlta-operated facilities in line with
carbon compliance regulations from the geographic
jurisdiction where the facility is located. For GHG
emissions that are not calculated using jurisdictional
carbon compliance guidance, we follow guidance from
the GHG Protocol: A Corporate Accounting and
Reporting Standard (specifically ‘Setting Organizational
Boundaries: Operational Control’ methodology). As per
the operational control methodology, TransAlta reports
100 per cent of GHG emissions from facilities at which
we are the operator. GHG emissions include emissions
from
stationary
combustion,
transportation
use,
building use and fugitive emissions. If we were to use a
financial boundary, there would be no material impact.
We report both scope 1 and 2 emissions. We compile
our corporate GHG inventory using our business
segment GHG calculations. All of our scope 1
emissions (100 per cent) are reported to national
regulatory bodies in the country in which we operate.
This includes: Australia (National Greenhouse and
Energy Reporting), Canada (Greenhouse Gas Reporting
Program, National Pollutant Release Inventory) and the
U.S. (EPA). Our scope 1 and 2 emissions use global
warming potentials and emissions factors that vary
with respect to regional compliance guidance and
include IPCC Fifth Assessment Report, Canada's GHG
Inventory 1990-2022, U.S. Emission Factors for
Greenhouse Gas Inventories 2024, U.S. EPA eGRID
Summary Tables 2022 and Australia Greenhouse
Account Factors 2024. Scope 2 for years 2022 and
2023 have been restated due to calculation error.
6.
'Total scope 1 and 2 GHG emissions' is the sum of the
reported 'scope 1 emissions' which have been reported
in accordance with SASB IF-EU-110a.1 and the
reported 'scope 2 emissions' which have been
reported in accordance with GRI 305-2. Total scope 1
and 2 GHG emissions is the sum of applicable gases
which include carbon dioxide, methane, nitrous oxide
and sulphur hexafluoride (SF6).
7.
GHG emission intensity is calculated by dividing total
scope 1 and scope 2 emissions by 100 per cent of
production (MWh) from operated facilities, irrespective
of financial ownership.
8.
Avoided emissions are defined as the emissions that
are displaced from the power grid through renewables
generation instead of standard consumption via the
grid. This is calculated by multiplying the total
renewable production with the grid carbon intensity of
the jurisdiction it operates in.
9.
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
TransAlta Corporation
2024 Integrated Report
279
the GHG Protocol Corporate Value Chain (Scope 3)
Accounting and Reporting Standard and with reference
to the additional guidance provided in the GHG
Protocol Technical Guidance for Calculating Scope 3
Emissions. Upstream scope 3 emissions are the
indirect emissions related to TransAlta’s suppliers.
Downstream scope 3 emissions are the emissions
related to TransAlta's customers. 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. Our scope 3
emissions use global warming potentials sourced from
IPCC Fourth Assessment Report for 2022 and IPCC
Fifth Assessment Report for 2023 and 2024.
10. Category 1: Purchased goods and services includes
emissions associated with purchased of goods and
services described as operating expenses less labour,
wages and other related costs. The accounting
approach includes all upstream (cradle to gate) GHG
emissions
from
the
extraction,
production,
and
transportation of goods and services purchased or
acquired by the Company in the reporting year, where
not otherwise included in Categories 2 to 8. The
methodology utilizes the spend-based approach and
emissions are calculated from the operating expense
of purchases of goods and services and the emission
factors from U.S. EPA Environmentally-Extended Input-
Output (EEIO) models.
11. Category
2:
Capital
goods
includes
emissions
associated with purchased of capital goods and
services described as capital expenditures. The
accounting approach includes all upstream (cradle to
gate) GHG emissions from the production of capital
goods or services purchased or acquired by the
Company in the reporting year, where not otherwise
included in Categories 1 and from 3 to 8. The
methodology utilizes the spend-based approach and
emissions are calculated from the capital expense of
purchases of capital goods and the emission factors
from U.S. EPA Environmentally-Extended Input-Output
(EEIO) models.
12. Category 3: Fuel and energy related activities includes
emissions associated with the extraction, production
and midstream transportation of natural gas (pipeline).
Excludes the emissions associated with electricity
consumption as they have been accounted for in our
scope 2 GHG emissions but accounting for the
transmission and distribution losses. The activities
applicable are a) upstream emissions of purchased
fuels and c) transmission and distribution losses of
purchased electricity. The methodology utilizes the
average-data approach and emissions are calculated
from the resource or energy use and the emission
factors from Canada's GHG Inventory, U.S. Emission
Factors for Greenhouse Gas Inventories and Australia
Greenhouse Account Factors.
13. Category 11: Use of sold products includes emissions
associated
with
natural
gas
combustion
during
electricity production where the sales and delivery of
physical natural gas occur. TransAlta is considered an
intermediary between the natural gas producer whom
we purchased it from to the client, for sole purpose of
combustion for electricity production. As such, we
account for the direct use-phase emissions associated
with the combustion of natural gas, categorized under
fuels and feedstocks. The methodology utilizes the
amount of fuel sold in Alberta and British Columbia in
Canada multiplying it with representative emission
factors from Canada's GHG Inventory 1990-2022.
14. Category 15: Investments includes emissions from our
assets that are owned (as a joint venture or other
ownership structure) but not operated by TransAlta.
The joint venture assets utilize an equity-based
investment on the asset's scope 1 and 2 GHG
emissions.
15. In 2024, relevant scope 3 categories that did not
receive limited assurance by a third-party provider
include Category 4: Upstream transportation and
distribution,
Category
5:
Waste
generated
in
operations, Category 6: Business travel, Category 7:
Employee
commuting,
Category
9:
Downstream
transportation and distribution, and Category 10:
Processing of sold products.
16. Air emissions which are applicable to TransAlta's
operations are NOx, SO2, particulate matter (PM2.5
and PM10) and mercury. The applicable air emissions
are calculated and reported from TransAlta-operated
facilities, following the same approach we use for GHG
emissions reporting, which is the application of an
‘Operational Control’ boundary as per guidance from
the GHG Protocol: A Corporate Accounting and
Reporting Standard. Air emissions are expressed in
tonnes, except for mercury emissions, which are
represented in kilograms. Particulate matter emissions
include both PM2.5 and PM10. Air emission intensities
are calculated by dividing total emissions by 100 per
cent of production (MWh) from operated facilities,
irrespective of financial ownership. In 2024, PM
emissions factor utilized for certain facilities was
updated to a more applicable source, contributing to a
31 per cent decrease from 2023, as the prior year
amounts have not been restated to reflect this
updated emission factor. We have restated our 2023
mercury emissions and mercury emissions intensity
following the discovery of an error related to
conversion. The restatement increases the original
280
TransAlta Corporation
2024 Integrated Report
2023 mercury by 3 kg and the mercury intensity by
0.13 mg/MWh.
17. Water use is calculated and reported from TransAlta-
operated facilities, following the same approach we
use for GHG emissions reporting, which is the
application of an ‘Operational Control’ boundary as per
guidance from the GHG Protocol: A Corporate
Accounting and Reporting Standard. Total water
consumed is measured by total water withdrawal
minus water discharge, where water withdrawal are
sourced from surface water, groundwater, third-party,
or non-freshwater, and water discharge refers to the
volume of freshwater leaving the organization's
boundary and released to surface water, groundwater,
or to third parties. Water is used primarily for cooling
by our thermal power plants. Evaporative losses from
cooling ponds and cooling towers account for the
majority of consumptive loss. The water lost to
evaporation is not returned directly to the water body,
but the water remains in the hydrologic cycle.
18. Water
intensity
is
calculated
by
dividing
total
operational water consumption (m3) by 100 per cent of
production (MWh) from operated facilities, irrespective
of financial ownership.
19. Waste is categorized as either non-hazardous or
hazardous waste. Non-hazardous waste includes, but
is not limited to, water treatment chemicals, coal
refuse (including ash byproducts), metals, paper,
cardboard and building materials. Hazardous wastes
can be harmful to people, plants, animals or the
environment, either in the short or the long term, and
TransAlta is required in all of its operating jurisdictions
to follow proper procedures for landfill/recycling of
these materials. We measure and report the total
weight of all types of waste generated and use several
methods for calculation, including direct measurement
of quantity onsite, by transporters at the point of
shipping or loading (consistent with shipping papers),
by waste disposal contractor at the point of waste
disposal or by transporters, at the point of shipping or
loading,
and
engineering
estimates
or
process
knowledge. The unit measurement for all types of
waste is reported as metric ton. Unless specified that
it is on-site, all waste generated are disposed off-site
from our facilities.
20. Waste diverted from disposal refers to the recycling or
reuse of waste that would otherwise end up in the
landfill. We have restated our 2022 waste – reuse
following the discovery of an error related to data
aggregation error. The restatement increases the
original 2022 data by 302,000 tonnes.
21. Storage waste is ash product from coal production,
which is stored on-site for treatment prior to sales for
cement production.
22. Waste directed to disposal refers to waste that ends
up in the landfill.
23. Ash disposal – mine is fly ash and bottom ash from
coal production, which is treated and then returned to
its original source, the mine, for landfill/disposal. In
2024, we reported zero as we have ceased coal
operations in Canada; therefore, we have no ash waste
to dispose of.
24. Ash disposal – lagoon is fly ash and bottom ash from
Keephills coal production, which is treated and then
sent to ash lagoons for disposal. In 2024, we reported
zero as we have ceased coal operations in Canada;
therefore, we have no ash waste to dispose of.
25. Land used in mining activities – disturbed refers to the
total active footprint of our mining operations, which
includes the cumulative hectares for land cleared of
vegetation, soil disturbed, ready for reclamation, soils
placed, and permanently reclaimed: (i) Disturbed
means soil has been disturbed; (ii) Cleared means
vegetation has been removed and soils are intact; (iii)
Reclamation means the restoration of disturbed lands
to
similar
pre-development
condition,
other
economically productive use, or natural or semi-natural
habitat. Land reclamation refers to the ratio between
the land that has been permanently or temporarily
reclaimed and the total active footprint of our mining
operations. Reclamation is presented as a cumulative
number; therefore, the total number of hectares
reported from year to year may increase depending on
whether reclamation has occurred or whether re-
disturbance
of
previously
reclaimed
areas
was
required. Total land use refers to the total active
footprint of all our operations or the sum of the land
used in mining activities plus land used by plants,
offices and equipment. We have restated our 2022
and 2023 land use for mining activities (disturbed and
reclaimed) following an update to historical estimation
and this is done in line with internal policy to update
for most recent information even if it is not considered
material. We have restated our 2022 and 2023 land
use for facilities, offices and equipment following the
discovery of an error related to conversion. The
restatement decreases our original 2022 and 2023
data by 1000 hectares.
26. Environmental incidents are separated into two
categories:
significant
environmental
incidents
(internally defined) and regulatory non-compliance
environmental incidents (aligned to GRI 2-27). We
define significant environmental incidents as an
incident that is internally classified as moderate,
significant, major or extreme, that resulted in an impact
to the ecosystem that is reversible or irreversible.
Factors
that
impact
this
classification
include
mortalities of greater than 0.01 per cent of a given
species when compared to the overall population, as
TransAlta Corporation
2024 Integrated Report
281
well as other relevant qualitative factors. We define
regulatory non-compliance environmental incidents as
violations
or
non-compliance
to
regulations
or
exceedance of limits in company operating approvals
that result in enforcement action including fines or
stop work orders that suspend overall facility or site
operations, but did not have an impact on the
environment. For example, a technical issue with a
computer system for gathering real-time data could
cause us to be out of compliance with local regulation
or our EMS, but there is no direct consequence for the
physical environment.
27. Environmental enforcement actions are a violation or
non-compliance to regulations or exceedance of limits
in company operating approvals that result in an
impact on the environment and enforcement action
including stop work orders, fines or suspension of
operating approvals.
28. Environmental
spills
generally
happen
in
low
environmental impact areas and are almost always
contained and fully recovered. It is extremely rare that
we experience large spills, which could adversely
impact the environment and the Company.
29. Biodiversity incidents are the number of total
biodiversity-related incidents that are classified as a
significant environmental incident and that affect
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.
30. In 2024, TransAlta employed approximately 351
unionized workers working primarily in our operational
business units.
31. Voluntary turnover is aligned with our Human
Resources voluntary turnover reporting methodology.
As per this methodology, voluntary turnover is any full-
time, part-time or contingent employee initiated exit,
excluding retirement. Summer students and temporary
workers are not considered within voluntary turnover.
32. Health and safety enforcement actions are a violation
of or non-compliance with regulations or exceedance
of limits in company operating approvals that result in
enforcement action including stop work orders, fines
or suspension of operating approvals.
33. Lost-time injuries (LTI) are injuries that resulted in the
worker being away from work beyond the day of the
injury.
34. Medical aids (MA) are injuries that resulted in medical
treatment beyond first aid.
35. Restricted work injuries (RWI) are injuries that resulted
in the worker being unable to perform all normally
scheduled and assigned work activities.
36. Exposure hours are total hours worked by all TransAlta
employees and contractors, and include full-time, part-
time, direct, contract, executive, labour, salary, hourly
and seasonal employees in all locations, but exclude
prime contractors. Prime contractor is the person
responsible for legislative compliance for safety in
multiple employer work site situations under applicable
law in the jurisdictions where we operate. Exposure
hours from prime contractors are excluded as we do
not direct their work. Exposure hours have been
rounded to the nearest thousand.
37. Total Recordable Injury Frequency (TRIF) measures
restricted work, medical aid and lost-time injuries per
200,000 hours worked. It does not include near miss
as per the SASB IF EU 320a.1 criteria.
38. Cumulative of donations and sponsorship totals in the
respective calendar year. This investment figure does
not include donations from our employees.
282
TransAlta Corporation
2024 Integrated Report
Independent Practitioner’s
Assurance Report
To Management of TransAlta Corporation
Scope
We have been engaged by TransAlta Corporation (“TransAlta”) to perform a ‘limited assurance engagement,’ as defined
by International Standards on Assurance Engagements, hereafter referred to as the engagement, to report on select
performance indicators detailed in the accompanying schedule (the “Subject Matter”) and contained in TransAlta’s 2024
Annual Integrated Report (the “Report”).
Other than as described in the preceding paragraph, which sets out the scope of our engagement, this engagement did
not include performing assurance procedures on the remaining information included in the Report, and accordingly, we do
not express a conclusion on this information.
Criteria applied by TransAlta
In preparing the Subject Matter, TransAlta applied relevant guidance contained within the Sustainability Accounting
Standards Board (“SASB”) Standards, Global Reporting Initiative (“GRI”) Sustainability Reporting Standards, the
Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard ("GHG Protocol") and internally developed
criteria, as detailed in the accompanying Schedule, collectively referred to herein as (the “Criteria”). The internally
developed criteria were specifically designed for the preparation of the Report. As a result, the Subject Matter may not be
suitable for another purpose.
TransAlta’s responsibilities
TransAlta’s management is responsible for selecting the Criteria, and for presenting the Subject Matter in accordance with
that Criteria, in all material respects. This responsibility includes establishing and maintaining internal controls, maintaining
adequate records and making estimates that are relevant to the preparation of the Subject Matter, such that it is free from
material misstatement, whether due to fraud or error.
EY’s responsibilities
Our responsibility is to express a conclusion on the presentation of the Subject Matter based on the evidence we
have obtained.
We conducted our engagement in accordance with the International Standard for Assurance Engagements (“ISAE”) 3000,
Assurance Engagements Other than Audits or Reviews of Historical Financial Information (“ISAE 3000”) and ISAE 3410,
Assurance Engagements on Greenhouse Gas Statements (“ISAE 3410”). These standards require that we plan and
perform our engagement to obtain limited assurance about whether, in all material respects, the Subject Matter is
presented in accordance with the Criteria, and to issue a report. The nature, timing and extent of the procedures selected
depend on our judgment, including an assessment of the risk of material misstatement, whether due to fraud or error.
We believe that the evidence obtained is sufficient and appropriate to provide a basis for our limited
assurance conclusion.
Our independence and quality management
We have complied with the relevant rules of professional conduct / code of ethics applicable to the practice of public
accounting and related to assurance engagements, issued by various professional accounting bodies, which are founded
on fundamental principles of integrity, objectivity, professional competence and due care, confidentiality and
professional behaviour.
TransAlta Corporation
2023 Integrated Report
283
Our firm applies Canadian Standard on Quality Management 1, Quality Management for Firms that Perform Audits or
Reviews of Financial Statements, or Other Assurance or Related Services Engagements, which requires us to design,
implement and operate a system of quality management including policies or procedures regarding compliance with
ethical requirements, professional standards and applicable legal and regulatory requirements.
Description of procedures performed
Procedures performed in a limited assurance engagement vary in nature and timing from, and are less in extent than for, a
reasonable assurance engagement. Consequently, the level of assurance obtained in a limited assurance engagement is
substantially lower than the assurance that would have been obtained had a reasonable assurance engagement been
performed. Our procedures were designed to obtain a limited level of assurance on which to base our conclusion and do
not provide all the evidence that would be required to provide a reasonable level of assurance.
Although we considered the effectiveness of management’s internal controls when determining the nature and extent of
our procedures, our assurance engagement was not designed to provide assurance on internal controls. Our procedures
did not include testing controls or performing procedures relating to checking aggregation or calculation of data within
IT systems.
A limited assurance engagement consists of making enquiries, primarily of persons responsible for preparing the Subject
Matter and related information, and applying analytical and other appropriate procedures.
Our procedures included:
• Conducting interviews with relevant personnel to obtain an understanding of the reporting processes;
• Inquiries of relevant personnel who are responsible for the Subject Matter including, where relevant, observing and
inspecting systems and processes for data aggregation and reporting in accordance with the Criteria;
• Assessing the accuracy of data, through analytical procedures and limited reperformance of calculations, where
applicable, and tested, on a limited sample basis, underlying source information to support completeness and accuracy
of the Subject Matter; and
• Checking presentation and disclosure of the Subject Matter in the Report.
We also performed such other procedures as we considered necessary in the circumstances.
Inherent limitations
The Greenhouse Gas ("GHG") quantification process is subject to scientific uncertainty, which arises because of
incomplete scientific knowledge about the measurement of GHGs. Additionally, GHG procedures are subject to estimation
(or measurement) uncertainty resulting from the measurement and calculation processes used to quantify emissions
within the bounds of existing scientific knowledge.
Non-financial information, such as the Subject Matter, is subject to more inherent limitations than financial information,
given the more qualitative characteristics of the subject matter and the methods used for determining such information.
The absence of a significant body of established practice on which to draw allows for the selection of different but
acceptable evaluation techniques which can result in materially different evaluation and can impact comparability
between entities and over time.
Conclusion
Based on our procedures and the evidence obtained, nothing has come to our attention that causes us to believe that the
Subject Matter for the reporting periods outlined in the accompanying schedule and the Report, are not prepared, in all
material respects, in accordance with the Criteria.
Calgary, Canada
February 19, 2025
284
TransAlta Corporation
2024 Integrated Report
Schedule
Our limited assurance engagement was performed on the following Subject Matter:
Greenhouse Gas Emissions
Scope 1 and 2 emissions
Internally developed criteria(2)
9,564,000
Tonnes CO2e
Greenhouse gas emission
intensity
GRI 305-4
0.35 Tonnes CO2e /MWh
Air Emissions
Total sulphur dioxide emissions
SASB IF-EU-120a.1
870
Tonnes
Sulphur dioxide emission
intensity
Internally developed criteria(3)
0.03
kg/MWh
Total nitrogen oxide emissions
SASB IF-EU-120a.1
8,700
Tonnes
Nitrogen oxide emission
intensity
Internally developed criteria(3)
0.32
kg/MWh
Total particulate matter
emissions
SASB IF-EU-120a.1
320
Tonnes
Particulate matter emission
intensity
Internally developed criteria(3)
0.01
kg/MWh
Total mercury emissions
SASB IF-EU-120a.1
16
kg
Mercury emission intensity
Internally developed criteria(3)
0.61
mg/MWh
Water Management
Water withdrawn – all sources
SASB IF-EU-140a.1
237
Million m3
Water discharge – all sources
Internally developed criteria(4)
212
Million m3
Water consumption
SASB IF-EU-140a.1
25
Million m3
Water consumption intensity
Internally developed criteria(5)
0.92
m3/MWh
Waste Management
Total waste diverted from
disposal
GRI 306-4
383,000
Tonnes
Total waste directed to disposal GRI 306-5
880
Tonnes
Land Use and Reclamation
Land used in mining activities –
disturbed
Internally developed criteria(6)
12,500
Cumulative
hectares
Land used in mining activities –
reclaimed
Internally developed criteria(6)
5,000
Cumulative
hectares
Reclamation of land used in
mining activities
Internally developed criteria(6)
40
% of land disturbed
Land used in mining activities:
disturbed minus reclaimed
Internally developed criteria(6)
7,500
Hectares
Performance Indicator
Criteria
Reported
Value for the
year
ended
December
31, 2024(1)
Unit of Measure
TransAlta Corporation
2024 Integrated Report
285
Land used by facilities, offices
and equipment
Internally developed criteria(6)
4,000
Hectares
Total land use
Internally developed criteria(6)
11,500
Cumulative
hectares
Environmental Incidents
Total environmental incidents
Internally developed criteria(7)
0
Number
Health and Safety
Employee and contractor
fatalities
SASB IF-EU-320a.1(8)
0
Number
Lost-time injury (LTI) incidents
SASB IF-EU-320a.1(8)
0
Number
Medical aid (MA) incidents
SASB IF-EU-320a.1(8)
6
Number
Restricted work injury
(RWI) incidents
SASB IF-EU-320a.1(8)
2
Number
Total recordable injuries to
employees and contractors
SASB IF-EU-320a.1(8)
8
Number
Total Recordable Injury
Frequency (TRIF) (employees
and contractors)
SASB IF-EU-320a.1(8)
0.56
Rate
Performance Indicator
Criteria
Reported
Value for the
year
ended
December
31, 2024(1)
Unit of Measure
Performance Indicator
Criteria
Reported
Value for the
year
ended
December
31, 2024(1)
Reported
Value for the
year
ended
December
31, 2023(1)
Reported
Value for the
year
ended
December
31, 2022(1)
Unit of Measure
Greenhouse Gas Emissions
Scope 3 Category 1 emissions
GHG Protocol(9)
30,000
32,000
28,000
Tonnes CO2e
Scope 3 Category 2 emissions
GHG Protocol(9)
24,000
86,000
140,000
Tonnes CO2e
Scope 3 Category 3 emissions
GHG Protocol(9)
950,000
954,000
963,000
Tonnes CO2e
Scope 3 Category 11 emissions
GHG Protocol(9)
583,000
716,000
556,000
Tonnes CO2e
Scope 3 Category 15 emissions
GHG Protocol(9)
1,834,000
1,651,000
1,846,000
Tonnes CO2e
(1)
All figures have been rounded in accordance with footnote 3 in the Sustainability Performance Indicators section of the Report.
(2)
As described in the footnote 6 in the Sustainability Performance Indicators section of the Report.
(3)
As described in the footnote 16 in the Sustainability Performance Indicators section of the Report.
(4)
As described in the footnote 17 in the Sustainability Performance Indicators section of the Report.
(5)
As described in the footnote 18 in the Sustainability Performance Indicators section of the Report.
(6)
As described in the footnote 25 in the Sustainability Performance Indicators section of the Report.
(7)
As described in the footnote 26 in the Sustainability Performance Indicators section of the Report.
(8)
Other criteria included in SASB Disclosure IF-EU-320a.1 (3), near miss frequency rate (NMFR), is excluded from the scope of our limited assurance
engagement
(9)
Reported Scope 3 emissions are calculated in accordance with the methodologies in the GHG Protocol Technical Guidance for Calculating Scope 3
Emissions
286
TransAlta Corporation
2024 Integrated Report
Shareholder Information
Special Services for Registered Shareholders
Service
Description
Direct deposit for dividend payments
Automatically have dividend payments deposited to your bank account
Account consolidations
Eliminate costly duplicate mailings by consolidating account registrations
Address changes and share transfers
Receive tax splits and dividends without the delays resulting from address
and ownership changes
Stock Splits and Share Consolidations
Date
Events
May 8, 1980
Stock split
February 1, 1988
Stock split(1)
December 31, 1992
Reorganization — TransAlta Utilities shares exchanged for TransAlta Corporation shares(2) 1:1
The valuation date value of common shares owned on December 31, 1971, adjusted for stock splits, is $4.54 per share.
(1)
The adjusted cost base for shares held on January 31, 1988, was reduced by $0.75 per share following the February 1, 1988, share split.
(2)
TransAlta Utilities Corporation became a wholly owned subsidiary of TransAlta Corporation as a result of this reorganization.
Dividend Declaration for Common Shares
Dividends are paid quarterly as determined by the Board. Dividends on our common shares are at the discretion of the
Board. In determining the payment and level of future dividends, the Board considers our financial performance, results of
operations, cash flow and needs with respect to financing our ongoing operations and growth, balanced against returning
capital to shareholders. The Board continues to focus on building sustainable earnings and cash flow growth.
Common Share Dividends Declared in 2024
Payment Date
Record Date
Ex-Dividend Date
Dividend
April 1, 2024
March 1, 2024
Feb. 28, 2024
$0.060
July 1, 2024
June 1, 2024
May 31, 2024
$0.060
Oct. 1, 2024
Sept. 1,2024
Aug. 31, 2024
$0.060
Jan. 1, 2025
Dec. 1, 2024
Nov. 30, 2024
$0.060
TransAlta Corporation
2024 Integrated Report
287
Submission of Concerns Regarding Accounting or
Auditing Matters
TransAlta has adopted a procedure for employees,
shareholders or others to report concerns or complaints
regarding accounting or other matters on an anonymous,
confidential basis to the Audit, Finance and Risk Committee
of the Board of Directors. Such submissions may be
directed to the Audit, Finance and Risk Committee c/o the
Chief Officer, Legal, Regulatory and External Affairs, of
the Company.
Dividend Declaration for Preferred Shares
Series A: Fixed cumulative preferential cash dividends are
paid quarterly when declared by the Board at the annual
rate of $0.71924 per share from and including March 31,
2021, to, but excluding, March 31, 2026.
Series B: Floating cumulative preferential cash dividends
are paid quarterly when declared by the Board from
and including March 31, 2021, to, but excluding,
March 31, 2026.
Series C: Fixed cumulative preferential cash dividends are
paid quarterly when declared by the Board at the annual
rate of $1.46352 per share from and including June 30,
2022, to, but excluding, June 30, 2027.
Series D: Floating cumulative preferential cash dividends
are paid quarterly when declared by the Board from and
including June 30, 2022, to, but excluding, June 30, 2027.
Series E: Fixed cumulative preferential cash dividends are
paid quarterly when declared by the Board at the annual
rate of $1.72352 per share from and including September
30, 2022, to, but excluding, September 30, 2027.
Series G: Fixed cumulative preferential cash dividends are
paid quarterly when declared by the Board at the annual
rate of $1.47012 per share from and including September
30, 2024, to, but excluding, September 30, 2029.
288
TransAlta Corporation
2024 Integrated Report
Preferred Share Dividends Declared in 2024
Series A
Payment Date
Record Date
Ex-Dividend Date
Dividend
March 31, 2024
March 1, 2024
Feb. 28, 2024
$0.17981
June 30, 2024
June 1, 2024
May 31, 2024
$0.17981
Sept. 30, 2024
Sept. 1, 2024
Aug. 31, 2024
$0.17981
Dec. 31, 2024
Dec. 1, 2024
Nov. 30, 2024
$0.17981
March 31, 2025
March 1, 2025
Feb. 28, 2025
$0.17981
Series B
Payment Date
Record Date
Ex-Dividend Date
Dividend
March 31, 2024
March 1, 2024
Feb. 28, 2024
$0.43958
June 30, 2024
June 1, 2024
May 31, 2024
$0.43579
Sept. 30, 2024
Sept. 1, 2024
Aug. 31, 2024
$0.43371
Dec. 31, 2024
Dec. 1, 2024
Nov. 30, 2024
$0.39182
March 31, 2025
March 1, 2025
Feb. 28, 2025
$0.33972
Series C
Payment Date
Record Date
Ex-Dividend Date
Dividend
March 31, 2024
March 1, 2024
Feb. 28, 2024
$0.36588
June 30, 2024
June 1, 2024
May 31, 2024
$0.36588
Sept. 30, 2024
Sept. 1, 2024
Aug. 31, 2024
$0.36588
Dec. 31, 2024
Dec. 1, 2024
Nov. 30, 2024
$0.36588
March 31, 2025
March 1, 2025
Feb. 28, 2025
$0.36588
Series D
Payment Date
Record Date
Ex-Dividend Date
Dividend
March 31, 2024
March 1, 2024
Feb. 28, 2024
$0.50609
June 30, 2024
June 1, 2024
May 31, 2024
$0.50230
Sept. 30, 2024
Sept. 1, 2024
Aug. 31, 2024
$0.50097
Dec. 31, 2024
Dec. 1, 2024
Nov. 30, 2024
$0.45906
March 31, 2025
March 1, 2025
Feb. 28, 2025
$0.40568
Series E
Payment Date
Record Date
Ex-Dividend Date
Dividend
March 31, 2024
March 1, 2024
Feb. 28, 2024
$0.43088
June 30, 2024
June 1, 2024
May 31, 2024
$0.43088
Sept. 30, 2024
Sept. 1, 2024
Aug. 31, 2024
$0.43088
Dec. 31, 2024
Dec. 1, 2024
Nov. 30, 2024
$0.43088
March 31, 2025
March 1, 2025
Feb. 28, 2025
$0.43088
Series G
Payment Date
Record Date
Ex-Dividend Date
Dividend
March 31, 2024
March 1, 2024
Feb. 28, 2024
$0.31175
June 30, 2024
June 1, 2024
May 31, 2024
$0.31175
Sept. 30, 2024
Sept. 1, 2024
Aug. 31, 2024
$0.31175
Dec. 31, 2024
Dec. 1, 2024
Nov. 30, 2024
$0.42331
March 31, 2025
March 1, 2025
Feb. 28, 2025
$0.42331
Dividends are paid on the last day of the month in March, June, September and December. When a dividend payment
date falls on a weekend or holiday, the payment is made on the following business day. Only dividend payments that have
been approved by the Board of Directors are included in this table. The Board of Directors has also declared dividends on
the Series I Preferred Shares, which are held by an affiliate of Brookfield Renewable Partners.
TransAlta Corporation
2024 Integrated Report
289
Voting Rights
Common shareholders receive one vote for each common share held.
Transfer Agent
Phone
Fax
Odyssey Trust Company
Trader's Bank Building,
702 - 67 Yonge Street,
Toronto, Ontario, M5E 1J8
Attention: Proxy Department
North America:
1-888-290-1175 toll-free
Outside North America:
1-587-885-0960
1-800-517-4553
Website:
www.odysseytrust.com
Exchanges
Ticker Symbols
Toronto Stock Exchange (TSX)
New York Stock Exchange (NYSE)
TransAlta Corporation common shares: TSX: TA, NYSE: TAC
TransAlta Corporation preferred shares: TSX: TA.PR.D, TA.PR.E,
TA.PR.F, TA.PR.G, TA.PR.H, TA.PR.J
Additional Information
Requests can be directed to:
Investor Relations
TransAlta Corporation
Phone
Email
TransAlta Place
Suite 1400, 1100 1 St SE
Calgary, Alberta T2G 1B1
North America:
1.800.387.3598 toll-free
Calgary/outside North America:
403.267.2520
investor_relations@transalta.com
Website:
www.transalta.com
290
TransAlta Corporation
2024 Integrated Report
Shareholder Highlights
Ten-Year Total Shareholder Return vs. S&P/TSX
Composite Index
Year ended Dec. 31 ($)
15
16
17
18
19
20
21
22
23
24
TransAlta
100
155
159
122
206
219
323
283
262
495
S&P/TSX
100
118
125
110
131
134
163
149
161
190
This chart compares what $100 invested in TransAlta and the S&P/TSX Composite Index at the end of 2015 would be worth today, assuming the
reinvestment of all dividends.
Source: FactSet
Ten-Year Market Value vs. Book Value
Year ended Dec. 31
($ per share)
15
16
17
18
19
20
21
22
23
24
Market value
4.91
7.43
7.45
5.59
9.28
9.67
14.05
12.11
11.02
20.33
Book value
8.52
8.92
8.28
7.16
7.14
5.13
2.37
0.62
2.16
2.66
Data is from 2014 onwards.
Source: FactSet and TransAlta
Monthly Volume and Market Prices
2024
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Volume (millions)
16
14
26
23
22
21
21
23
29
23
28
41
TSX closing price ($ per share)
9.74
9.31
8.69
9.13
9.79
9.70
10.40
11.87
14.02
14.56
15.87 20.33
Source: FactSet
Return on Common Shareholders' Equity
(%)
15
16
17
18
19
20
21
22
23
24
ROE
(1.2)
5.4 (10.0) (15.8) 0.03 (30.3) (116.6)
1.0 84.8 23.2
Source: TransAlta
TransAlta Corporation
2024 Integrated Report
291
Fighting Against Forced Labour and
Child Labour in Supply Chains Act
2024 Annual Report
A. INTRODUCTION
TransAlta Corporation (“TransAlta”) is subject to legal
requirements in section 11 of the Canadian federal Fighting
Against Forced Labour and Child Labour in Supply Chains
Act (the “Act”). This Report is made pursuant to the Act for
the financial year ending December 31, 2024 (“Reporting
Period”) and was approved by the TransAlta Board of
Directors on February 18, 2025.
The Report is filed by TransAlta on behalf of itself and the
following subsidiaries licensed to import goods into
Canada: TransAlta Generation Partnership; TransAlta
Energy Marking Corp.; TransAlta Cogeneration L.P.;
Keephills 3 Limited Partnership; TransAlta (SC) L.P.;
Melancthon Wolfe Wind L.P.; TA Alberta Hydro LP; and
Garden Plain I LP. The terms the “Company”, “TransAlta”,
“we”, “our”, or “us” refer to TransAlta Corporation and
extend to all entities listed in this report.
The Report sets out the steps taken to prevent and reduce
the risk that forced labour or child labour is used at any
step of the production of goods in Canada or elsewhere by
TransAlta or of goods imported into Canada by TransAlta.
On December 4, 2024, TransAlta successfully completed
the acquisition of 100 percent of the shares in Heartland
Generation
Ltd.
and
Alberta
Power
(2000)
Ltd.
(collectively, “Heartland”) and commenced integration of
Heartland’s operations into our business.
Unless otherwise stated, the operational and supply chain
data and content presented in the main body of the report
does not include former Heartland entities. However, we
have presented specific data and content for former
Heartland entities in section 3 of this Report.
B. OVERVIEW
1. Steps to Prevent and Reduce Risks of Forced and
Child Labour
TransAlta took significant steps during the Reporting
Period to prevent and reduce the risk of forced labour or
child labour in its business and supply chains, described
below.
(a) Enhanced Supplier Risk Management
Throughout the Reporting Period, we prioritized actions to
deepen our understanding of modern slavery risks within
our
operations
and
supply
chains,
enhancing
the
effectiveness of measures to address these risks. We
proactively examined the upstream sourcing of materials,
equipment and services from our key vendor partners to
support both growth and operational needs.
(b) Expanded ESG Data Collection from Suppliers
We also implemented a modern slavery questionnaire for
new suppliers to gather information on their policies and
practices to mitigate modern slavery risks within their
workplaces and supply chains. For existing suppliers, we
distributed a modern slavery survey to collect insights on
their operations, supply chains, and environmental and
social impacts, with a specific focus on risks of modern
slavery. This initiative was conducted across TransAlta.
(c) Employee Training Initiatives
We provided annual mandatory Code of Conduct training
for all employees as well as specialized training on
Canada’s
modern
slavery
legislation
for
employees
involved in the procurement of goods and services. This
training was designed to enhance awareness and
understanding
of
responsible
procurement
practices
among our teams.
These actions were applied broadly across TransAlta,
except as otherwise noted.
C. TRANSALTA’S STRUCTURE, ACTIVITIES AND
SUPPLY CHAINS
1.
TransAlta Overview
TransAlta is the sole parent company of the entities
covered in this Report and is headquartered in Calgary,
Alberta. We have been engaged in the development,
production, and sale of electric energy since 1911. We are
one of Canada’s largest independent power generators and
among
Canada’s
largest
non-regulated
electricity
generation and energy marketing companies, with 9,014
megawatts (“MW”) of gross installed capacity.
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TransAlta Corporation
2024 Integrated Report
We own, operate, and manage a highly contracted and
geographically diversified portfolio of assets using a broad
range of technologies and fuels, including water, wind,
solar, natural gas, energy storage, and coal. We are
focused on generating and marketing electricity in Canada,
the United States, and Western Australia through our
diversified portfolio of facilities. Our mission is to provide
safe, low-cost, and reliable clean electricity.
2.
TransAlta’s Supply Chains
During the Reporting Period, we procured goods and
services globally from a network of approximately 2,000
suppliers and contractors across North America, Australia,
Asia and Europe. Our suppliers range from major, Fortune
500 international companies to small, local businesses.
Our supply network largely reflects our operational
footprint, meaning most of our direct spend during the
Reporting Period continued to be in the countries where
we have operated assets. Approximately 52 percent of our
suppliers were based in Canada, 26 percent were located
in the United States, 21 percent in Australia and
approximately 1 percent in Europe or Asia. We appreciate,
however, that some of these suppliers are supplying goods
that originated from other jurisdictions. Our Supply Chain
team endeavors to understand our vendors’ partners
upstream providers where possible.
Our suppliers cover a wide range of disciplines, including
construction, engineering, and professional services.
Approximately 80 percent of our 2024 spend was allocated
to the procurement of fuel, professional services, local
operations and maintenance services, as well as the local
operations of wind turbines, conducted in both Canada and
the United States.
We have a centralized Supply Chain Management (“SCM”)
function that serves the entire Company, including our
Canadian, United States and Australian operations. This
function is responsible for all aspects of SCM, including
strategic sourcing, contract management, and supply chain
and commercial risk management, all with the goal of
creating
maximum
value
for
TransAlta
and
our
shareholders while upholding the principles and standards
set out in our Supplier Code.
3.
Heartland’s Supply Chains
On December 4, 2024, we completed the acquisition of
Heartland and began integrating its operations and
functions into our business - a process that will continue
over time.
The former Heartland operations are generation assets in
Alberta and British Columbia, Canada, consisting of 507
MW of cogeneration, 387 MW of contracted and merchant
peaking generation, 950 MW of gas-fired thermal
generation, transmission capacity.
Prior to acquisition, Heartland implemented a Code of
Business Conduct and Ethics, including Code Policies (the
“Heartland Code”), a Modern Slavery Policy, a Supply
Chain Management Policy and Sourcing Practice, and an
Ethics
and
Compliance
Helpline
(collectively,
the
“Policies”). Each employee was required to read and
acknowledge the Heartland Code, which also references
the Policies. Additionally, all third-party suppliers and
contractors were obligated to adhere to these Policies as
part of Heartland’s standard supply chain contract terms.
During the Reporting Period, we were advised that
Heartland conducted a risk analysis of its supply chains to
assess potential forced labour and child labour risks. As
part of this analysis, we understand that Heartland’s key
material suppliers and contractors were reviewed and sent
a questionnaire requesting detailed information about their
exposure to forced labour and child labour, as well as the
actions they are taking to prevent and mitigate these risks.
The results of the risk analysis and questionnaires were
analyzed for any potential exposure, and no instances of
forced labour or child labour were identified.
4.
TransAlta’s Policies and Due Diligence Processes
TransAlta recognizes that forced labour, child labour, and
other forms of modern slavery are critical issues, and we
stand strongly against this exploitation. TransAlta has
accordingly developed internal governance documents
that take into consideration supply chain and human rights
compliance risks. Our supply chain processes are designed
to procure goods and services that meet our standards for
environmental stewardship, social responsibility, and
ethical practices. We attain this objective by incorporating
ESG factors into our supplier lifecycle management
framework,
encompassing
supplier
selection
and
relationship management through various means, including
pre-qualification,
requests
for
proposals,
proposal
evaluations, and contracts.
5.
TransAlta Policies Addressing Forced and Child
Labour
(a) Corporate Code of Conduct (the “Code”)
TransAlta’s Code sets out the expected behavior of all
employees, including independent third-party contractors
such as consultants, agents or independent contractors
retained to do work or represent TransAlta’s interests.
We are committed to creating a work environment where
all employees feel safe and are valued for the diversity
they bring to our business. We have continued to require
employees to complete annual mandatory Code training.
This training is reviewed and updated approximately each
TransAlta Corporation
2024 Integrated Report
293
year and is required to be completed by employees before
completing the required annual Code acknowledgment and
sign-off. In 2024, 100 percent of employees completed
this training and acknowledged and signed-off on the
Code. We do not tolerate discrimination or harassment
and
are
committed
to
honoring
domestic
and
internationally accepted labour standards and support the
protection of human rights.
(b) Supplier Code of Conduct (“Supplier Code”)
TransAlta expects suppliers to know and uphold the human
rights of all workers, whether temporary or contract
employees, and to treat all their workforce members with
dignity and respect, providing them with safe working
conditions. The Supplier Code specifically addresses the
prohibition of human rights abuses, including all forms of
forced labour and child labour.
We expect all our suppliers to adhere to and implement the
principles and practices expressed in the Supplier Code. In
addition, we expect suppliers to cascade these principles
and requirements down to their own respective suppliers.
TransAlta encourages all suppliers, workers, and other
stakeholders, through the provisions of the Supplier Code,
to speak up about any issues, concerns, and suspected
violations of TransAlta’s policies. All ethical or legal
concerns related to the Supplier Code can be reported to
TransAlta’s Ethics Help Line, which is set out in more detail
below.
(c) Human Rights and Discrimination Policy
TransAlta’s Human Rights and Discrimination Policy is a
global policy that communicates our commitment to human
rights
in
our
operations
and
supply
chains.
This
commitment includes that TransAlta will strive to ensure
our operations do not negatively impact human rights of
local communities, which is done through meaningful and
transparent consultations with stakeholders who are or will
be potentially affected by our operations. TransAlta
employees will not be complicit in human rights abuses.
The policy states that TransAlta’s personnel policies and
practices in our operations around the world will respect
the following fundamental rights:
• the right to a healthy and safe workplace;
• the right to non-discrimination in the workplace;
• the right to be free from cruel and unusual disciplinary
practices;
• the prohibition of exploitative child labour; and
• the prohibition of forced labour and the avoidance of
products produced by such labour.
(d) Procurement Policy
TransAlta is committed to upholding our Procurement
Policy, which aims to maintain workplaces that strictly
prohibit all forms of forced labour.
(e) Whistleblower Policy and Ethics Helpline
Our Whistleblower Policy offers a reporting mechanism for
our employees, officers, directors, and contractors to
report ethical or legal violations, among other concerns.
Stakeholders may make a report to identify individuals
within TransAlta or through the Company’s third-party
Ethics Helpline. The Ethics Helpline is a confidential and
anonymous platform, which can be accessed 24 hours a
day, 356 days a year by phone, mail, or electronically.
Upon receipt of a report, TransAlta will review the facts,
and determine whether sufficient facts are present to
initiate
an
investigation.
Upon
completion
of
an
investigation, we seek to address potential impropriety
promptly and/or establish a corrective action plan in
collaboration with relevant stakeholders. Our Whistleblower
Policy prohibits retribution against any individual who
reports an ethical complaint.
(f) Due Diligence Processes
We developed a multi-year roadmap to further integrate
additional ESG considerations and opportunities, including
the promotion and protection of human rights, into our
SCM strategies and programs. This includes thorough pre-
screening, self-assessment questionnaires, on-site and
desktop evaluations, and ongoing performance monitoring,
each of which is set out in more detail below.
(g) Pre-screening and Self-Assessment
We engage internal subject-matter experts, including
sustainability and legal, to provide input into supplier pre-
qualification and the monitoring phases of the supplier
lifecycle, as well as to offer guidance on emerging issues.
Our aim is to ensure that our standards regarding safety,
human rights, sustainability, and environmental practices
are upheld throughout our supply chains, and that
suppliers follow the high standards set forth in the Supplier
Code.
(h) Requests for Proposals (“RFPs”) and Proposal
Evaluations
Following a risk-based assessment of our supplier base,
we may include in our RFPs specific questions regarding
goods and services associated with medium or high levels
of risk. These questions address the origins of critical
materials and components, supplier location, ownership,
scope of business, etc. In certain instances, we may seek
explicit assurances concerning specific risk areas and
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TransAlta Corporation
2024 Integrated Report
require proponents to affirm their commitment to specific
contractual terms addressing these concerns.
(i) Contractual Measures
TransAlta’s contracts include appropriate verification,
notification requirements, audit, and inspection clauses,
and we reserve the right to conduct inspections,
assessments and audits to ensure that suppliers comply
with applicable laws, rules, and standards, including those
related to human rights. In addition, our standard terms
require suppliers to commit to adhering to the principles
and standards in our Supplier Code and to requiring their
own suppliers to commit to similar principles and
standards. TransAlta also reserves the right to discontinue
business relationships in cases of non-adherence to the
Supplier Code.
Our suppliers are obligated to take reasonable steps to
ensure that goods and services are procured from ethical
sources. This includes refraining from benefiting, directly or
indirectly, from child or forced labour or any other
discriminatory work practices.
Furthermore, TransAlta may request that a supplier
provides
information
about
its
corporate
structure
(including relevant subcontractors), its policies (including
those related to forced labour and child labour), and the
steps the supplier has taken to assess, manage, remediate,
or provide training in regard to the principles and
requirements covered by the Supplier Code.
(j) Ongoing Monitoring
Compliance monitoring is a central focus for TransAlta. In
line with a risk-based approach, we may initiate periodic
reassessments
linked
to
contract
renewals
or
anniversaries.
We are committed to continually enhancing various
measures, including the terms outlined in our suppliers'
contracts, alongside proactive monitoring of diverse
information sources, such as the Uyghur Forced Labour
Prevention Act Entity List, Global Affairs Canada advisories,
industry
group
updates,
and
non-governmental
organization websites to identify suppliers at risk.
6.
Risks in TransAlta’s Operations and Supply Chains
(a) TransAlta’s Operations
We have assessed the risk of forced labour or child labour
in our operations to be low for the following reasons:
• TransAlta’s workforce exists only within Canada, the
United States, and Australia, which have comprehensive
and robust labour, employment, and human rights laws.
• All site operational and office staff are hired in
accordance with the laws and regulations in the
jurisdictions where we operate.
• During the onboarding process, we conduct checks
related to the right to work and ensure that individuals
are choosing to work of their own free will.
• A portion of our workforce is represented by strong
prominent labour unions.
• All staff have the freedom to join a trade union or other
association.
• TransAlta benchmarks all the roles against three different
remuneration surveys.
(b) TransAlta’s Supply Chains
For TransAlta, our supply chains, organizations that provide
goods or services, play a key role in our ability to satisfy
our social responsibility commitments and sustainability
objectives. We strive to work with suppliers who are
leaders in their industries, adhere to our fundamental
policies and procedures, and share our commitment to
meet the highest standards relating to human rights.
Like many entities operating within the energy sector, and
particularly the renewable energy space, we recognize
risks of forced labour and child labour may exist in our
supply chains. As outlined by the United Nations Guiding
Principles on Business and Human Rights, our primary
exposure to forced labour is expected to be beyond the
second tier1 of our third-party relationships rather than
direct causative impacts or contributory actions of our
business.
This is particularly relevant in the following higher-risk
sectors and products:
• solar panels;
• battery energy storage equipment;
• wind turbines;
• engineered equipment;
• information and communications technologies;
• industrial consumables;
• electronics and electrical hardware; and
• freight services.
During the Reporting Period, TransAlta has not identified
any instances of modern slavery or child labour in its
supply chains or operations. No remedial steps have been
deemed necessary at this time, including related to
remediation of income loss to the most vulnerable families
that results from remediation measures.
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295
C. STEPS TO MANAGE AND ASSESS RISK
1.
TransAlta’s Operations
TransAlta is dedicated to fostering a work environment
where all employees feel secure and are valued.
TransAlta’s Code outlines the expected behavior of
individuals doing work for TransAlta. Employees are
required on an annual basis to complete mandatory Code
training and to acknowledge in writing its requirements.
This training was updated and provided to employees
during the Reporting Period.
2.
TransAlta's Supply Chains
We have taken proactive steps to enhance supplier risk
identification, assessment, analysis, remediation, and
monitoring. We risk map of our supplier base to evaluate
critical suppliers, group and prioritize them, identify
potential vulnerabilities, and assess controls in place. We
examine
the
geographic
location
of
suppliers,
differentiating
between
Organization
for
Economic
Cooperation and Development (OECD) and non-OECD
regions, complexity of their supply chains, especially those
leading to areas known for forced or child labour, industry-
specific risks linked to human rights and labour practices,
the critical or unique nature of the products procured
versus commodity items, the duration of the supply
relationships, and overall spend.
Following the risk mapping, assessment, and analysis, no
instances of forced labour or child labour were identified
during the Reporting Period. However, we have classified
certain goods and services as medium risk, such as
transformers, due to their manufacturing origin in China,
and freight services, given the inherent risk for some
modern slavery practices within the shipping industry. That
said, we predominantly procure freight services from low-
risk jurisdictions. We are also aware of the elevated risks of
forced and child labour associated with certain renewable
energy technologies, such as wind turbines, solar panels,
and batteries. However, no such goods were purchased
during the Reporting Period.
Certain manufacturing regions and materials carry a higher
risk of forced labour due to its prevalence in specific
countries. We understand that many of our direct suppliers
rely on global supply chains to provide goods and services
to us, which presents challenges in obtaining visibility
beyond the first tier.1 As a whole, considering the factors
and processes set out above, we view the risks of forced
labour or child labour in our supply chains as low.
3.
Employee Training
In addition to annual, mandatory Code training during the
Reporting Period, we successfully developed and delivered
mandatory employee training on forced labour and child
labour to all employees involved in the procurement of
goods and services. This training covered essential
aspects of responsible procurement and sustainability-
focused supplier management, including recognizing
indicators of human trafficking behaviors. Participants
explored the concept of forced labour in depth, examined
international treaties and definitions, and learned about key
indicators and "hot geographies" where forced labour is
more prevalent. The training also addressed reporting
legislation, trade and government contracting prohibitions,
the role of the Canadian Ombudsperson for Responsible
Enterprise, as well as potential litigation and reputational
risks.
Through practical applications, the training equipped
TransAlta employees with the necessary tools and
awareness to promote responsible procurement practices,
fostering a culture of ethical and sustainable sourcing
within the organization.
D. ASSESSING EFFECTIVENESS OF OUR ACTIONS
TransAlta understands that it has a responsibility to assess
and mitigate the risks of modern slavery in its operations
and supply chains over the long term. The Board has
overall responsibility for the strategy around modern
slavery. It has delegated to the Governance, Safety and
Sustainability Committee the development of strategies,
policies and practices to create value consistent with the
long-term preservation and enhancement of shareholder
value and social wellbeing, including human rights, working
conditions and responsible sourcing.
We are committed to continuously enhancing our program
to identify, assess, and manage modern slavery risks in our
operations and supply chains. When evaluating the
immediate effectiveness of our modern slavery program,
we focus on reviewing the operation of existing processes
and systems, identifying gaps or opportunities to refine our
approach, and designing and implementing improvements
to address identified issues.
(1) Tier Two: supplier of goods or services directly to Tier One suppliers. Tier Two suppliers are subcontractors who may not have a direct relationship with
the client company. Tier Three: suppliers of raw material or base product to Tier Two suppliers. Tier Three suppliers may, for example, provide minerals for
the manufacture of products by Tier Two suppliers.
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2024 Integrated Report
During the course of 2025, we plan to:
1.
Continue reviewing and analyzing ESG data from our
supplier network, with a focus on gaining deeper
insights into the upstream sourcing of materials,
equipment, and services provided by our key vendor
partners to support both growth and operations.
2.
Establish a vendor management database to formally
record the assessment of modern slavery risk and
commitment to the Supplier Code by our suppliers.
3.
Continue to enhance our internal due diligence tools
and processes, including, but not limited to, updating
our Vendor Onboarding Questionnaire forms.
4.
Advance the integration of Heartland into TransAlta’s
compliance framework.
5.
These improvements will further advance our efforts to
prevent and reduce the risk of forced labour and child
labour in our business and supply chains, aligning with
our mission to uphold the highest standards of ethical
and responsible business practices.
E. CONSULTATION AND APPROVAL
In accordance with the Act, specifically section 11 thereof, I
attest I have reviewed the information contained in the
Report for the TransAlta entities listed above. Based on my
knowledge and having exercised reasonable diligence, I
attest that the information in the Report is true, accurate
and complete in material respects for the purposes of the
Act, for the reporting year listed above.
I have the authority to bind TransAlta Corporation.
____________________________
Full name: John H. Kousinioris
Title: President and Chief Executive Officer
Date: Feb. 19, 2025
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297
Corporate Information
Corporate Governance:
New York Stock Exchange
Disclosure Differences
TransAlta’s Corporate Governance Guidelines, Board
Charter, Committee Charters, position descriptions for
the Chair and President & CEO, and codes of business
conduct and ethics are available on our website at
www.transalta.com. Also available on our website is a
summary of the significant ways in which TransAlta’s
corporate governance practices differ from those
required to be followed by US domestic companies
under the New York Stock Exchange’s listing standards.
Currently there are no significant differences between
our governance practices and those of the New York
Stock Exchange.
Ethics Helpline
The Board of Directors has established an anonymous
and confidential Internet portal, email address and
toll-free telephone number for employees, contractors,
shareholders and other stakeholders who wish to report
accounting irregularities, ethical violations or any other
matters they wish to bring to the attention of the Board.
The Ethics Helpline phone number is 1.855.374.3801
(US/Canada) and 1.800.40.5308 (Australia)
Internet portal: transalta.com/ethics-helpline
Email: ethics_helpline@transalta.com
Any communications to the Board of Directors may also
be sent to corporate_secretary@transalta.com.
TransAlta Corporate Officers
John Kousinioris
President and Chief Executive Officer
Joel Hunter
Executive Vice President, Finance and
Chief Financial Officer
Nancy Brennan
Executive Vice President, Legal and External Affairs
Jane Fedoretz
Executive Vice President, People, Culture and Chief
Administrative Officer
Mark Flickinger
Executive Vice President, Project Delivery and
Construction
Chris Fralick
Executive Vice President, Generation
Kerry O'Reilly Wilks
Executive Vice President, Growth and Energy Marketing
Blain van Melle
Executive Vice President, Commercial and
Customer Relations
David Little
Senior Vice President, Growth
Michelle Cameron
Vice President and Corporate Controller
Jon Ozirny
Vice President, Legal and Corporate Secretary
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Glossary of Key Terms
Alberta Electric System Operator (AESO)
Alberta Electric System Operator; the independent system
operator
and
regulatory
authority
for
the
Alberta
Interconnected Electric System.
Alberta Hydro Assets
The Company's hydroelectric assets owned through a
wholly owned subsidiary, TA Alberta Hydro LP. These
assets are located in Alberta and consist of the Barrier,
Bearspaw, Bighorn, Brazeau, Cascade, Ghost, Horseshoe,
Interlakes, Kananaskis, Pocaterra, Rundle, Spray and Three
Sisters hydro facilities.
Alberta Thermal
The business segment previously disclosed as Canadian
Coal has been renamed to reflect the ongoing conversion
of the boilers to burn gas in place of coal. The segment
includes the legacy and converted generating units at our
Sundance
and
Keephills
sites
and
includes
the
Highvale mine.
Ancillary Services
As defined by the Electric Utilities Act, ancillary services
are
those
services
required
to
ensure
that
the
interconnected electric system is operated in a manner
that provides a satisfactory level of service with
acceptable levels of voltage and frequency.
Automatic Share Purchase Plan (ASPP)
The ASPP is intended to facilitate repurchases of common
shares under the NCIB, including at times when the
Company would ordinarily not be permitted to make
purchases due to regulatory restrictions or self-imposed
blackout periods.
Availability
A measure of time, expressed as a percentage of
continuous operation - 24 hours a day, 365 days a year -
that a generating unit is capable of generating electricity,
regardless
of
whether
or
not
it
is
actually
generating electricity.
Balancing Pool
The Balancing Pool was established in 1999 by the
Government of Alberta to help manage the transition to
competition in Alberta's electric industry. Their current
obligations and responsibilities are governed by the
Electric Utilities Act (effective June 1, 2003) and the
Balancing Pool Regulation. For more information go to
www.balancingpool.ca.
Capacity
The rated, continuous load-carrying ability of generation
equipment, expressed in megawatts.
Cash-Generating Unit (CGU)
A cash-generating unit 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.
Centralia
The business segment previously disclosed as US Coal has
been renamed to reflect the sole asset.
Cogeneration
A generating facility that produces electricity and another
form of useful thermal energy (such as heat or steam) used
for industrial, commercial, heating or cooling purposes.
Disclosure Controls and Procedures (DC&P)
Refers to controls and other procedures designed to
ensure that information required to be disclosed in the
reports filed by the Company or submitted under securities
legislation is recorded, processed, summarized and
reported within the time frame specified in applicable
securities legislation. DC&P include, without limitation,
controls
and
procedures
designed
to
ensure
that
information required to be disclosed by the Company in its
reports that it files or submits under applicable securities
legislation
is
accumulated
and
communicated
to
management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate to allow timely
decisions regarding required disclosure.
Dispatch Optimization
Purchasing
power
to
fulfil
contractual
obligations,
when economical.
Economic Dispatch
Purchasing power to fulfil contractual obligations, when
economical.
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299
Emissions Performance Standards (EPS)
Under the Government of Ontario, emission performance
standards establish greenhouse gas (GHG) emissions limits
for covered facilities.
Environmental Management Systems (EMS)
A set of processes and practices that enable an
organization to reduce its environmental impacts and
increase its operating efficiency.
Exchangeable Debentures
On May 1, 2019, Brookfield invested $350 million in
exchange for seven per cent unsecured subordinated
debentures due May 1, 2039.
Exchangeable Preferred Shares
On Oct. 30, 2020, Brookfield invested $400 million in the
Company in exchange for redeemable, retractable first
preferred shares (Series I). The Series I Preferred Shares
are accounted for as current debt and the exchangeable
preferred share dividends are reported as interest
expense.
Exchangeable Securities
On March 22, 2019, the Company entered into an
Investment Agreement whereby Brookfield Renewable
Partners or its affiliates (collectively "Brookfield") agreed to
invest $750 million in TransAlta through the purchase of
exchangeable securities, which are exchangeable into an
equity ownership interest in TransAlta’s Alberta hydro
assets in the future at a value based on a multiple of the
Alberta hydro assets’ future-adjusted EBITDA (Option to
Exchange).
Force Majeure
Literally means “greater force.” A clause in a contract that
excuses a party from liability if some unforeseen event
beyond the control of that party prevents it from
performing its obligations under the contract.
Free Cash Flow (FCF)
Amount of cash generated by the Company through its
operations (cash from operations) minus the funds used
by the Company for the purchase, improvement or
maintenance
of
the
long-term
assets
to
improve
the
efficiency
or
capacity
of
the
Company
(capital expenditures).
Funds from Operations (FFO)
Calculated as cash flow from operating activities before
changes in working capital and is adjusted for transactions
and amounts that the Company believes are not
representative of ongoing cash flows from operations.
Gigajoule (GJ)
A metric unit of energy commonly used in the energy
industry. One GJ equals 947,817 British thermal units (Btu).
One GJ is also equal to 277.8 kilowatt hours.
Gigawatt (GW)
A measure of electric power equal to 1,000 megawatts.
Gigawatt Hour (GWh)
A measure of electricity consumption equivalent to the use
of 1,000 megawatts of power over a period of one hour.
Global Reporting Initiative (GRI)
An independent not-for-profit organization that leads a
global multi-stakeholder process to develop and refine
rigorous yet practical sustainability reporting.
Greenhouse Gas (GHG)
A gas that has the potential to retain heat in the
atmosphere, including water vapour, carbon dioxide,
methane,
nitrous
oxide,
hydrofluorocarbons
and perfluorocarbons.
Heartland Credit Facilities
As part of the Heartland acquisition on Dec. 4, 2024, the
Company assumed a $232 million drawn term facility and a
$25 million revolving facility with a syndicate of banks,
(collectively Heartland Credit Facilities). At Dec. 31, 2024
the drawn term facility was $224 million. The $25 million
revolving facility is undrawn and available for working
capital and general corporate purposes.
ICFR
Internal control over financial reporting.
IFRS
International Financial Reporting Standards.
Megawatt (MW)
A measure of electric power equal to 1,000,000 watts.
Megawatt Hour (MWh)
A measure of electricity consumption equivalent to the use
of 1,000,000 watts of power over a period of one hour.
Merchant
A term used to describe assets that are not contracted and
are exposed to market pricing.
NCIB
Normal Course Issuer Bid.
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OM&A
Operations, maintenance and administration costs.
Other Hydro Assets
The Company's hydroelectric assets located in British
Columbia and Ontario and assets owned by TransAlta
Renewables, which include the Taylor, Belly River,
Waterton, St. Mary, Upper Mamquam, Pingston, Bone
Creek,
Akolkolex,
Ragged
Chute,
Misema,
Galetta,
Appleton and Moose Rapids facilities.
Planned Divestitures
Poplar Hill and Rainbow Lake facilities, which the Company
agreed to divest pursuant to a consent agreement entered
into with the Commissioner of Competition for Canada
following closing of the acquisition of Heartland Generation
Ltd. and certain affiliates.
Planned Outage
Periodic planned shutdown of a generating unit for major
maintenance and repairs. Duration is normally in weeks.
The time is measured from unit shutdown to putting the
unit back online.
Power Purchase Agreement (PPA)
A long-term agreement established by regulation for the
sale of electric energy to PPA buyers.
PP&E
Property, plant and equipment.
Renewable Energy Credits (REC)
All right, title, interest and benefit in and to any credit,
reduction right, offset, allocated pollution right, emission
reduction
allowance,
renewable
attribute
or
other
proprietary or contractual right, whether or not tradable,
resulting from the actual or assumed displacement or
reduction
of
emissions,
or
other
environmental
characteristic, from the production of one MWh of
electrical energy from a facility utilizing certified renewable
energy technology.
Renewable Power
Power generated from renewable terrestrial mechanisms
including
wind,
geothermal,
solar
and
biomass
with regeneration.
Sustainability Accounting Standards
Board (SASB)
Connects businesses and investors on the financial
impacts of sustainability. SASB Standards identify the
subset
of
ESG
issues
most
relevant
to
financial
performance in each of the 77 covered industries.
TA Cogen
The
Company
owns
50.01
per
cent
in
TransAlta
Cogeneration, L.P. (“TA Cogen”), which owns, operates or
has an interest in a portfolio of cogeneration facilities,
including three natural-gas-fired cogeneration facilities
(Ottawa, Windsor and Fort Saskatchewan) and a natural-
gas-fired facility (Sheerness).
Term Facility
The $400 million term facility with our banking syndicate,
which matures on Sept. 7, 2025, with floating interest rates
that vary depending on the option selected (e.g. Canadian
prime and bankers' acceptances).
Task Force on Climate-Related Financial
Disclosures (TCFD)
Designed to solicit consistent, decision-useful, forward-
looking information on the material
financial
impacts
on
climate-related
risks
and
opportunities, including those related to the global
transition to a low-carbon economy. They are adopted by
all organizations with public debt or equity in G20
jurisdictions for use in mainstream financial filings.
Taskforce on Nature-related Financial
Disclosures (TNFD)
Market-led,
science-based
and
government-backed
initiative providing organizations with the tools to act on
evolving nature-related issues.
Total Recordable Injury Frequency (TRIF)
Tracks the number of more serious injuries and excludes
minor first aids, relative to exposure hours worked.
Turbine
A machine for generating rotary mechanical power from
the energy of a stream of fluid (such as water, steam or hot
gas). Turbines convert the kinetic energy of fluids to
mechanical energy through the principles of impulse and
reaction or a mixture of the two.
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2024 Integrated Report
301
Turnaround
Periodic planned shutdown of a generating unit for major
maintenance and repairs. Duration is normally in weeks.
The time is measured from unit shutdown to putting the
unit back online.
Unplanned Outage
The
shutdown
of
a
generating
unit
due
to
an
unanticipated breakdown.
UN Sustainable Development Goals (SDGs)
Adopted by the United Nations in 2015 as a universal call
to action to end poverty, protect the planet, and ensure
that by 2030 all people enjoy peace and prosperity. The 17
SDGs are integrated—they recognize that action in one
area will affect outcomes in others, and that development
must
balance
social,
economic
and
environmental
sustainability.
Value at Risk (VaR)
A measure used to manage exposure to market risk from
commodity risk management activities.
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