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
This MD&A should be read in conjunction with our unaudited interim condensed consolidated financial statements as at and for the three months ended March 31, 2026 and 2025, and should be read in conjunction with the audited annual consolidated financial statements and MD&A (2025 Annual MD&A) contained within our 2025 Annual Report. In this MD&A, unless the context otherwise requires, “we”, “our”, “us”, the “Company” and “TransAlta” refer to TransAlta Corporation and its subsidiaries. The unaudited interim condensed consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) for Canadian publicly accountable enterprises as issued by the International Accounting Standards Board (IASB) and in effect at March 31, 2026. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted, except amounts per share, which are in whole dollars to the nearest two decimals. This MD&A is dated May 5, 2026. Additional information with respect to TransAlta, including our Annual Information form (AIF) for the year ended Dec. 31, 2025, is available on SEDAR+ at www.sedarplus.ca, on EDGAR at www.sec.gov and on our website at www.transalta.com. Information on or connected to our website is not incorporated by reference herein. For the Glossary of Key Terms used in this MD&A refer to the 2025 Annual Report.
Forward-Looking Statements
This MD&A includes "forward-looking information" within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of applicable U.S. securities laws, including the Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements").
Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may", "will", "can", "could", "would", "shall", "believe", "expect", "estimate", "anticipate", "intend", "plan", "forecast", "foresee", "potential", "enable", "continue" or other comparable terminology.
In particular, this MD&A contains forward-looking statements about the following, among other things:
•Our 2026 Outlook and the targets contained therein;
•Our hedging assumptions;
•Our estimated spot price sensitivity and the associated impacts on our Adjusted EBITDA target;
•Our expectation that cash flow from our operating activities will be sufficient to meet our short and long-term financial obligations;
•Our expectations about strategies for growth and expansion;
•Expected costs and schedules for planned projects, including the Centralia planned coal-to-gas conversion project;
•The power generation industry generally and the supply of, and demand for, electricity;
•The cyclicality of our business;
•The expected impact of future tax and accounting changes; and
•Expected industry, market and economic conditions.
The forward-looking statements contained in this MD&A are based on many assumptions including, but not limited to, the following:
•No significant changes to applicable laws and regulations, including carbon pricing, renewable energy incentives, royalty rates and climate-related regulations;
•No unexpected delays in obtaining required regulatory and other third-party approvals;
•No material adverse impacts to investment and credit markets;
•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 or foreign exchange rates;
•No significant changes to the demand for, and growth of, electricity generation;
•No significant changes to the integrity and reliability of our facilities;
•No significant changes to the Company's debt and credit ratings;
•No unforeseen changes to economic and market conditions;
•No significant events occurring outside the ordinary course of business;
•No significant changes to the Company's ability to develop, access or implement, on a timely basis and on reasonable terms, the technology necessary to efficiently and effectively operate the Company's assets and achieve expected future results;
•No significant supply chain disruptions or shortages of raw materials or skilled labour;
•No significant changes to the Company's ability to access the capital markets on reasonable terms; and
•No material changes to international trade laws, regulations, agreements, treaties, taxes, tariffs, duties or policies of Canada, the United States or other countries.
These assumptions are based on information currently available to TransAlta, including information obtained from third-party sources. Actual results may differ materially from those predicted by such assumptions.
Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this MD&A include, but are not limited to:
•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;
•Our ability to develop, access or implement, on a timely basis and on reasonable terms, the technology necessary to efficiently and effectively operate our assets and achieve expected future results;
•Any difficulty raising needed capital in the future on reasonable terms;
•Long-term commitments on gas transportation capacity that may not be fully utilized over time;
•Changes to legislative, regulatory and political environments, including changes to carbon pricing, renewable energy policies and emissions regulations in Canada, the United States and Australia;
•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;
•Grid reliability;
•Reductions in production;
•Impairments and/or writedowns of assets;
•Adverse impacts on our information technology systems and our internal control systems, including increased cybersecurity threats;
•Commodity risk management and energy-trading risks;
•Reduced labour availability, ability to continue to staff our operations and facilities and other labour relations matters;
•Disruptions to our supply chains;
•Weather conditions and their impact on electricity generation and demand;
•Climate change-related risks, including the increased frequency and severity of extreme weather events;
•Reductions to our generating units' relative efficiency or capacity factors;
•General economic risks, including deterioration of equity markets, increasing interest rates, changes to foreign exchange rates or rising inflation;
•General domestic and international economic and political developments, including potential trade tariffs;
•Industry risk and competition, including from emerging technologies affecting the demand, generation, distribution or storage of electricity;
•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;
•Reputational and stakeholder-related risks; and
•Reliance on key personnel.
The foregoing risk factors, among others, are described in further detail in the "Risk Management" section of the 2025 Annual Report.
Readers are urged to consider these factors carefully when evaluating the forward-looking statements, which reflect the Company's expectations only as of the date of this MD&A and are cautioned not to place undue reliance on them. The forward-looking statements included in this document are made only as of the date of its release and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. The purpose of the financial outlooks contained in this document is to give the reader information about management's current expectations and plans and readers are cautioned that such information may not be appropriate for other purposes. In light of these risks, uncertainties and assumptions, the forward-looking statements might occur to a different extent or at a different time than we have described, or might not occur at all. We cannot assure that projected results or events will be achieved.
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 (U.S.) and Western Australia. Our portfolio includes hydro, wind, solar, battery storage and thermal generation, complemented by our asset optimization and energy marketing capabilities. As one of Canada’s largest producers of wind and thermal generation and Alberta’s largest producer of hydroelectric power, TransAlta remains committed to a diverse generation mix. With strong cash flows underpinned by a high-quality portfolio, TransAlta strives to deliver sustainable long-term shareholder value in an evolving energy landscape. We have four generation segments including Hydro, Wind and Solar, Gas and Energy Transition, along with two non-generation segments including Energy Marketing and Corporate.
Our diversified portfolio consists of both high-quality contracted assets and merchant assets. Our contracted
assets provide stable long-term cash flow and earnings, balancing our merchant fleet. Our merchant assets include our unique hydro portfolio, legacy and peaking thermal assets and wind assets. Our merchant exposure is primarily in Alberta, where 61 per cent of our generating capacity is located and 77 per cent exposed to the merchant market.
In Alberta, the Company manages its merchant exposure by executing hedging strategies that include a significant base of commercial and industrial customers, supplemented with financial hedges. A significant portion of our thermal and hydro generation capacity in Alberta may be hedged to provide greater cash flow certainty while also being available to capture upside. Refer to the "2026 Outlook" section and the "Optimization of the Alberta Portfolio" section of this MD&A for further details.
The following table provides our consolidated ownership by segment of our facilities across Alberta and other regions in which we operate as at March 31, 2026:
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As at March 31, 2026 | | Hydro | Wind & Solar | Gas(4)(5) | | | | Total |
| Alberta | Gross installed capacity (MW)(2) | 834 | | 764 | | 3,650 | | | | | 5,248 | |
Number of facilities | 17 | | 14 | | 15 | | | | | 46 | |
Weighted average contract life (years) | — | | 16 | | 8 | | | | | 10 | |
Contracted capacity (MW) | — | | 336 | | 887 | | | | | 1,223 | |
Contracted capacity as a % of total capacity (%) | — | | 44 | | 24 | | | | | 23 | |
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Other regions(1) | Gross installed capacity (MW)(2) | 88 | | 1,823 | | 1,464 | | | | | 3,375 | |
| Number of facilities | 7 | | 22 | | 14 | | | | | 43 | |
| Weighted average contract life (years) | 14 | | 10 | | 8 | | | | | 10 | |
| Contracted capacity (MW) | 88 | | 1,823 | | 1,155 | | | | | 3,066 | |
Contracted capacity as a % of total capacity (%) | 100 | | 100 | | 79 | | | | | 91 | |
| Total | Gross installed capacity (MW)(2) | 922 | | 2,587 | | 5,114 | | | | | 8,623 | |
Number of facilities | 24 | | 36 | | 29 | | | | | 89 | |
Weighted average contract life (years) | 14 | | 11 | | 8 | | | | | 10 | |
Contracted capacity (MW) | 88 | | 2,159 | | 2,042 | | | | | 4,289 | |
Contracted capacity as a % of total capacity (%)(3) | 10 | | 83 | | 40 | | | | | 50 | |
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(1)Other regions include the U.S., Western Australia and Canada, excluding Alberta. Gross installed capacity across all segments for the U.S., Western Australia and Canada, excluding Alberta, totaled 1,024 MW, 498 MW and 1,853 MW, respectively, with the number of facilities across all segments totaling 10, 9 and 24, respectively. Refer to 2025 Annual Report for details.
(2)Gross installed capacity for consolidated reporting is based on a proportionate interest held in a facility.
(3)Approximately 50 per cent of our total installed capacity is contracted with creditworthy counterparties.
(4)Gas segment includes gross installed capacity of 310 MW from four facilities in Ontario attributable to the acquisition of Far North. The contracted capacity of these facilities as at March 31, 2026 was nil and increased to 100 per cent effective May 1, 2026. Refer to the "Significant and Subsequent events" section.
(5)Gas segment excludes Ada Cogeneration facility in the U.S, with a fully contracted gross installed capacity of 29 MW, due to its retirement on Jan. 5, 2026.
Following Centralia's cessation of coal-fired operations at the end of 2025 in the normal course, the Energy Transition segment is no longer considered a reportable segment. The segment has therefore been excluded from the table above. Refer to Note 19 of our unaudited interim condensed consolidated financial statements for details.
The facility currently remains available for power generation in accordance with and for the duration of the order received from the U.S. Department of Energy. Refer to Significant and Subsequent Events for detail.
Highlights
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| 3 months ended March 31, | |
| (in millions of Canadian dollars except where noted) | 2026 | 2025 | | |
Operational information(1) | | | | |
| Availability (%) | 93.8 | | 94.9 | | | |
| Production (GWh) | 5,444 | | 6,832 | | | |
Select financial information(1) | | | | |
| Revenues | 565 | | 758 | | | |
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Adjusted EBITDA(2) | 204 | | 270 | | | |
Adjusted Earnings before income taxes(2) | 30 | | 28 | | | |
Earnings before income taxes | 23 | | 49 | | | |
Adjusted Net Earnings Attributable to Common Shareholders(2) | 18 | | 30 | | | |
Net earnings attributable to common shareholders | 13 | | 46 | | | |
Cash flows(1) | | | | |
| Cash flow from operating activities | 123 | | 7 | | | |
Funds from operations(2) | 137 | | 179 | | | |
Free cash flow(2) | 102 | | 139 | | | |
Per share(1) | | | | |
Weighted average number of common shares outstanding (in millions) | 297 | | 298 | | | |
Adjusted Net Earnings Attributable to Common Shareholders per share(2)(3) | 0.06 | | 0.10 | | | |
Net earnings per share attributable to common shareholders, basic and diluted | 0.04 | | 0.15 | | | |
| Dividends declared per common share | 0.07 | | 0.07 | | | |
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Cash flow from operating activities per share(4) | 0.41 | | 0.02 | | | |
Funds from operations per share(2)(3) | 0.46 | | 0.60 | | | |
Free cash flow per share(2)(3) | 0.34 | | 0.47 | | | |
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(1)IFRS financial statements for the three months ended March 31, 2025 include the results attributable to Poplar Hill and Rainbow Lake facilities (collectively, the Required Divestitures), which the Company divested in accordance with a consent agreement entered into with the Commissioner of Competition for Canada. Our non-IFRS measures and operational Key Performance Indicators exclude the results of the Required Divestitures.
(2)These are non-IFRS measures and ratios, which are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Segmented Financial Performance and Operating Results by Geographical Location" section of this MD&A for further discussion of these items. Also, refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding these non-IFRS measures and ratios, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
(3)Adjusted Net Earnings Attributable to Common Shareholders per share, funds from operations (FFO) per share and free cash flow (FCF) per share are calculated using the weighted average number of common shares outstanding during the period. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding these non-IFRS measures and ratios.
(4)Represents a supplementary financial measure and is calculated as cash flow from operating activities for the period divided by the weighted average number of common shares outstanding during the period.
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As at | March 31, 2026 | Dec. 31, 2025 |
| Liquidity and capital resources | | |
Available liquidity(1) | 1,542 | | 1,500 | |
Adjusted Net Debt to Adjusted EBITDA (times)(2)(3) | 4.3 | | 4.0 | |
Total Consolidated Net Debt(2)(4) | 3,785 | | 3,725 | |
| Assets and liabilities | | |
| Total assets | 8,787 | | 8,661 | |
Total long-term liabilities(5) | 5,494 | | 5,366 | |
Total liabilities | 7,311 | | 7,196 | |
(1)Available liquidity is a supplementary financial measure and is calculated as the sum of total available capacity under the committed credit and term facilities and cash and cash equivalents less bank overdraft and the amounts drawn under the non-committed demand facilities.
(2)These are non-IFRS measures and ratios, which are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Segmented Financial Performance and Operating Results by Geographical Location" section of this MD&A for further discussion of these items. Also, refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding these non-IFRS measures and ratios, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
(3)The most directly comparable IFRS ratio to Adjusted Net Debt to Adjusted EBITDA (times) is calculated as credit facilities, long-term debt and lease liabilities of $3,706 million (Dec. 31, 2025 — $3,593 million) divided by loss before income taxes for the last four quarters of $167 million (Dec. 31, 2025 — loss before income taxes $141 million) and is equal to (22) times (Dec. 31, 2025 — (25) times). Refer to the "Key Non-IFRS Financial Ratios" section of this MD&A for details of the calculation.
(4)The most directly comparable IFRS measure to Total Consolidated Net Debt is total credit facilities, long-term debt and lease liabilities, which is equal to $3,706 million (Dec. 31, 2025 — $3,593 million). Refer to the table in the "Financial Condition" section of this MD&A for more details on the composition of Total Consolidated Net Debt.
(5)Total long-term liabilities are equal to total non-current liabilities in the consolidated statements of financial position under IFRS.
Significant and Subsequent Events
Appointment of New Chief Financial Officer (CFO) and Chief Commercial Officer
Mike Politeski was appointed Executive Vice President, Finance and CFO, effective May 1, 2026 and Grant Arnold has been appointed Executive Vice President, Growth and Chief Commercial Officer, effective May 6, 2026.
Chief Executive Officer Succession
John Kousinioris, President and Chief Executive Officer and a Director of TransAlta retired on April 30, 2026. Joel Hunter, TransAlta’s Executive Vice President, Finance and CFO, succeeded Mr. Kousinioris as President and Chief Executive Officer effective April 30, 2026. Mr. Kousinioris has agreed to serve as a strategic advisor to Mr. Hunter and the Board for a period of six months following his retirement.
Annual Shareholder Meeting
Joel Hunter was elected to the Board of Directors following the annual shareholder meeting on April 30, 2026. At the annual shareholder meeting, the Company received strong
support on all items of business, including the election of the nominated directors, the reappointment of auditors, the Company's approach to executive compensation and the increase in shares available under the Company's share unit plan.
Centralia Unit 2 Mandated to Remain Available for additional 90 days
On March 16, 2026, the Company received another order from the U.S. Department of Energy (the Order) requiring that our 700 MW Centralia Unit 2 facility (Facility) remain available for operation for an additional period of 90 days, until June 14, 2026. As previously communicated, the first order from the U.S. Department of Energy dated Dec. 16, 2025 required that our Facility remain available if called upon to operate for a period of 90 days, until March 16, 2026. The Company is currently compliant with the Order and continues to work with the state and federal governments in relation thereto.
Memorandum of Understanding for Data Centre Development at Keephills Site Signed
On Feb. 26, 2026, the Company entered into a Memorandum of Understanding (MOU) with Canada Pension Plan Investments and Brookfield to advance a data centre development in Alberta, for which TransAlta is the exclusive site and power provider. The MOU establishes a framework for phased development at the Company's Keephills site in Parkland County, including an initial long-term power purchase agreement for approximately 230 MW and the evaluation of additional development aggregating up to 1 gigawatt of load. Development is subject to regulatory approvals and the parties reaching definitive agreements.
Declared Increase in Common Share Dividend
The Company’s Board has approved a $0.02 annualized (eight per cent) increase to the common share dividend and declared a dividend of $0.07 per common share on Feb. 25, 2026 to be payable on July 1, 2026 to shareholders of record at the close of business on June 1,
2026. The quarterly dividend of $0.07 per common share represents an annualized dividend of $0.28 per common share.
Acquisition of Far North
On Feb. 2, 2026, the Company closed the acquisition of Far North Power Corporation (Far North), including 310 MW of capacity from four natural gas-fired facilities, for a purchase price of $95 million from an affiliate of Hut 8 Corporation, subject to working capital and other adjustments. The net cash payment for the transaction was funded through a combination of cash on hand and borrowings under TransAlta's credit facilities.
Mothballing of Sheerness Unit 1
On Apr. 1, 2026, the Company mothballed Sheerness Unit 1. The Company initially provided notice to the Alberta Electric System Operator (AESO) on Dec. 18, 2025, that Sheerness Unit 1 would be mothballed on April 1, 2026, for a period of up to two years. The Company maintains the flexibility to return the mothballed unit to service when market fundamentals improve or contracting opportunities are secured.
Operating and Financial Performance
Operating Performance
The following table provides availability (%) by segment:
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| 3 months ended March 31 | | | 2026 | 2025 | |
| Hydro | | | 95.4 | | 93.6 | | |
| Wind and Solar | | | 92.9 | | 94.0 | | |
| Gas | | | 94.0 | | 95.5 | | |
Energy Transition(1) | | | 100.0 | | 97.1 | | |
Availability(1) (%) | | | 93.8 | | 94.9 | | |
(1)Centralia Unit 2 facility ceased coal-fired operations at the end of 2025 in the normal course and therefore, the facility is excluded from total availability. The facility remains available for power generation as mandated by the United States Department of Energy.
Availability measures the percentage of time a facility is able to produce electricity and is a key indicator of fleet performance. It is affected by planned and unplanned outages and derates. Planned outages are scheduled to minimize operational impacts, and in strong price environments may be adjusted to accelerate a unit’s return to service.
Availability for the three months ended March 31, 2026, was 93.8 per cent compared to 94.9 per cent for the same period in 2025, primarily due to:
•Higher unplanned maintenance outages in the Wind and Solar and Gas segments; partially offset by
•Lower planned maintenance outages in the Hydro segment.
Production and Long-Term Average Generation
The following table provides the production and long-term average generation on a consolidated basis for each of our segments:
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As at March 31 | Actual production (GWh) | LTA generation (GWh) | Production as a % of LTA | | Actual production (GWh) | LTA generation (GWh) | Production as a % of LTA |
| Hydro | 360 | | 373 | | 97 | % | | 383 | | 402 | | 95 | % |
Wind and Solar | 1,938 | | 1,921 | | 101 | % | | 1,905 | | 2,056 | | 93 | % |
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Gas | 3,146 | | | | | 3,504 | | | |
Energy Transition | — | | | | | 1,040 | | | |
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| Total | 5,444 | | | | | 6,832 | | | |
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In addition to availability, the Company uses long‑term average (LTA) generation as a key performance indicator for its renewable facilities, comparing actual production to expected long‑term output. While Hydro and Wind and Solar production can vary period to period, over longer durations, facilities are expected to perform in-line with their LTA, which represents an annualized energy output expected from our facilities based on historical resource data, observed operating performance and forward‑looking assumptions about future conditions. LTA generation is not applicable to the Gas segment, as these dispatchable facilities operate based on market conditions, and merchant and customer demand.
Total production for the three months ended March 31, 2026, decreased by 1,388 GWh, or 20 per cent, compared to the same period in 2025, primarily due to:
•No production at Centralia Unit 2 in the Energy Transition segment. Refer to the "Description of the Business" section of this MD&A; and
•Higher dispatch optimization in Alberta in the Gas segment due to lower market prices.
Financial Performance Review of Consolidated Information
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| 3 months ended March 31 | 2026 | 2025 | | | |
| Revenues | 565 | | 758 | | | | |
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Gross Margin | 361 | | 432 | | | | |
| Operations, maintenance and administration | (181) | | (173) | | | | |
| Depreciation and amortization | (105) | | (146) | | | | |
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Interest expense | (82) | | (93) | | | | |
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Earnings before income taxes | 23 | | 49 | | | | |
Income tax expense | (6) | | (7) | | | | |
Net earnings attributable to common shareholders | 13 | | 46 | | | | |
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Adjusted earnings before income taxes(1) | 30 | | 28 | | | | |
Adjusted net earnings attributable to common shareholders(1) | 18 | | 30 | | | | |
Adjusted EBITDA(1) | 204 | | 270 | | | | |
Free Cash Flow(1) | 102 | | 139 | | | | |
Cash flow from Operating activities | 123 | | 7 | | | | |
(1)These are non-IFRS measures, which are not defined, have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding these non-IFRS measures, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
First Quarter Variance Analysis (2026 versus 2025)
Revenues for the three months ended March 31, 2026, decreased by $193 million, or 25 per cent, compared to the same period in 2025, primarily due to:
•No production at Centralia Unit 2;
•Lower spot and hedged power prices in the Alberta market; and
•Higher dispatch optimization in the Gas segment driven by lower power prices in Alberta.
Gross Margin for the three months ended March 31, 2026, decreased by $71 million, or 16 per cent, compared to the same period in 2025, primarily due to:
•Lower revenues as explained above; partially offset by
•Lower fuel and purchased power costs at Centralia due to no production as stated above; and
•Lower fuel and purchase power and carbon compliance costs in the Gas segment due to lower production and lower natural gas prices.
OM&A expenses for the three months ended March 31, 2026 increased by $8 million, or five per cent, compared to the same period in 2025, primarily due to:
•Higher termination, restructuring and facility shutdown costs;
•Higher legal costs arising from cost determinations made after the conclusion of arbitration proceedings; partially offset by
•Lower spending on early stage growth and development projects; and
•Expected cost recoveries as a result of complying with the Order related to Centralia
Depreciation and amortization for the three months ended March 31, 2026, decreased by $41 million, or 28 per cent, compared to the same period in 2025, primarily due to:
•Lower depreciation in the Gas segment in the current period due to a change in the useful life assumptions in 2025 for the Sheerness facilities; and
•Lower depreciation for Centralia Unit 2 due to the cessation of coal-fired operations in the normal course.
Interest expense for the three months ended March 31, 2026, decreased by $11 million, or 12 per cent, compared to 2025, primarily due to:
•Lower interest on certain senior notes following their refinancing at lower interest rates during 2025;
•Lower interest on lease liabilities; and
•Lower accretion and other interest on provisions.
Earnings before income taxes for the three months ended March 31, 2026, decreased by $26 million, or 53 per cent, compared to the same period in 2025, due to:
•The items noted above; and
•Fair value gain on contingent consideration payable totalling $34 million related to the Required Divestitures recognized in the first quarter of 2025; partially offset by
•Higher asset impairment reversals in the current period primarily related to a change in discount rates on decommissioning and restoration provisions on retired assets; and
•Higher other operating income due to legal settlement recoveries.
Income tax expense for the three months ended March 31, 2026, decreased by $1 million, or 14 per cent, compared to the same period in 2025 due to a decrease in earnings before income taxes, partially offset by other non-taxable differences.
Net earnings attributable to common shareholders for the three months ended March 31, 2026, decreased by $33 million, or 72 per cent, compared to the same period of 2025 due to:
•The items noted above; and
•Net earnings attributable to non-controlling interests compared to net loss in the comparative period due to higher net earnings for TransAlta Cogeneration, LP (TA Cogen) resulting from higher revenues in Ontario and lower depreciation for the Sheerness facilities, partially offset by lower revenues at the Sheerness facilities due to weaker merchant pricing in Alberta.
Adjusted Earnings before income taxes for the three months ended March 31, 2026, increased by $2 million, or seven per cent, compared to the same period in 2025, primarily due to:
•Lower depreciation and amortization, and lower interest expense as explained above; partially offset by
•The factors causing lower Adjusted EBITDA described in the "Adjusted EBITDA" section of this MD&A.
Adjusted Net Earnings attributable to common shareholders for the three months ended March 31, 2026, decreased by $12 million, or 40 per cent compared to the same period in 2025, primarily due to:
•Net earnings attributable to non-controlling interests compared to net loss in the comparative period due to higher net earnings for TA Cogen resulting from higher revenues in Ontario and lower depreciation for Sheerness facilities, partially offset by lower revenues at Sheerness facilities due to weaker merchant pricing in Alberta; partially offset by
•The factors causing higher Adjusted Earnings before Income Taxes explained above.
For FCF variance commentary refer to the "Free Cash Flow" section of this MD&A.
For Cash flow from operating activities variance commentary, refer to the "Cash Flows" section of this MD&A.
For reconciliation Cash flow from operating activities to FCF refer to the "Reconciliation of Cash Flow from Operations to FFO and FCF" section of this MD&A.
Adjusted EBITDA
For the three months ended March 31, 2026, the Company's Adjusted EBITDA was $204 million compared to $270 million for the same period in 2025, a decrease of $66 million, or 24 per cent.
The major factors impacting Adjusted EBITDA are summarized in the following table:
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Adjusted EBITDA(1) for the three months ended March 31, 2025 | 270 | |
Hydro: Lower due to lower environmental and tax attributes sales to third parties and lower spot power prices in the Alberta market, partially offset by higher ancillary services volumes. | (12) | |
Wind and Solar: Lower due to lower contract revenue driven by reduced availability and lower wind resource in Eastern Canada. | (7) | |
Gas: Lower primarily due to higher natural gas cost in Eastern Canada, the retirement of the Ada Cogeneration facility and lower hedge and spot power prices in the Alberta market, which led to higher dispatch optimization. | (11) | |
Energy Marketing: Lower primarily due to higher OM&A due to higher incentive costs driven by higher unrealized mark-to-market gains included in the incentive calculation. | (4) | |
Corporate: Comparable to the same period in 2025. | 4 | |
Energy Transition: Lower due to no production at Centralia Unit 2. | (36) | |
Adjusted EBITDA(1) for the three months ended March 31, 2026 | 204 | |
(1)Adjusted EBITDA is a non-IFRS measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A. The most directly comparable IFRS measure is earnings before income taxes of $23 million ($49 million for the three months ended March 31, 2025). Refer to the "Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segments" section of this MD&A.
Free Cash Flow
For the three months ended March 31, 2026, the Company's FCF decreased by $37 million, or 27 per cent, compared to the same period in 2025.
The major factors impacting FCF are summarized in the following table:
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| 3 months ended March 31 |
FCF(1) for the three months ended March 31, 2025 | 139 | |
Lower Adjusted EBITDA due to the items noted above. | (66) | |
Lower net interest expense(2) primarily due to lower interest on certain senior notes following their refinancing at lower interest rates during 2025 and lower interest on lease liabilities. | 11 | |
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Higher realized foreign exchange gains from operating activities. | 17 | |
Other(3) | 1 | |
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FCF(1) for the three months ended March 31, 2026 | 102 | |
(1)FCF is a non-IFRS measure, is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding this measure. The most directly comparable IFRS measure is cash flow from operating activities, which was $123 million and $7 million for the three months ended March 31, 2026 and 2025, respectively. Refer to the "Cash Flows" section of this MD&A.
(2)Net Interest Expense is a non-IFRS measure, not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Net Interest Expense includes interest expense less interest income and excludes non-cash items like financing amortization and accretion. Net Interest Expense reconciliation is available in "Financial Condition" section of this MD&A
(3)Other consists primarily of lower decommissioning and restoration costs settled, lower sustaining capital and lower loan advances by the Company's subsidiary, Kent Hills Wind LP to its 17 per cent partner. Other also includes changes in deferred payments, contract assets and liabilities, onerous contracts and long-term incentive accruals.
For 2026, the Company reaffirms Adjusted EBITDA to be in the range of $950 million to $1,050 million and FCF to be in the range of $350 million to $450 million. The assumptions disclosed in the "2026 Outlook" of the 2025 Annual MD&A remain the same. For details, please refer to the "2026 Outlook" section of the 2025 Annual Report.
The following table outlines our expectations on key financial targets and related assumptions for 2026 and should be read in conjunction with the narrative discussion that follows and the "Risk Management" section of the 2025 Annual Report:
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| Measure | 2026 Target(2) | | | 2025 Actual(3) |
Adjusted EBITDA(1) | $950 million to $1,050 million | | | $1,104 million |
FCF(1) | $350 million to $450 million | | | $514 million |
FCF per share(1) | $1.18 to $1.51 | | | $1.73 |
Dividend per share | $0.28 annualized | | | $0.26 annualized |
(1)These are non-IFRS measures, which are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Reconciliation of Non-IFRS Measures" section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.
(2)Represents forward-looking information.
(3)The actual 2025 amounts for the most directly comparable IFRS measures for Adjusted EBITDA and FCF were as follows: Loss before income taxes of $141 million and Cash flow from operating activities of $646 million. The most directly comparable IFRS ratio to FCF per share is cash flow from operating activities per share of $2.18, which is calculated as cash flow from operating activities for the period divided by the weighted average number of common shares outstanding during the period. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for additional information.
The Company's 2026 outlook may be impacted by a number of factors, including hedging assumptions detailed further below.
Alberta Hedging
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| Range of hedging assumptions | | Q2 2026 | Q3 2026 | Q4 2026 | 2027 | |
| Hedged production (GWh) | | 2,253 | | 2,399 | | 2,199 | | 5,495 | | |
| Hedge price ($/MWh) | | $64 | $63 | $65 | $65 | |
Hedged gas amounts (GJ) | | 8.3 million | 8.9 million | 7.2 million | 27.2 million | |
| Hedge gas prices ($/GJ) | | $3.05 | $3.07 | $3.39 | $2.81 | |
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Alberta spot price sensitivity: a +/- $1 per MWh change in spot price is expected to have a +/- $2 million impact on Adjusted EBITDA for 2026.
Segmented Financial Performance and Operating Results by Geographical Location
Segmented information is prepared on the same basis that the Company manages its business, evaluates financial results and makes key operating decisions. The following table reflects the Adjusted EBITDA by segment across the regions we operate in for the three months ended March 31, 2026 and 2025:
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3 months ended March 31, 2026 | | Hydro | Wind & Solar(2) | Gas | Energy Marketing | Corporate | Energy Transition | Total |
| Alberta | | 35 | | 12 | | 47 | | 17 | | (37) | | (1) | | 73 | |
| Canada, excluding Alberta | | — | | 33 | | 19 | | — | | — | | — | | 52 | |
| U.S. | | — | | 48 | | — | | — | | — | | 2 | | 50 | |
Western Australia | | — | | 2 | | 27 | | — | | — | | — | | 29 | |
Adjusted EBITDA(1) | | 35 | | 95 | | 93 | | 17 | | (37) | | 1 | | 204 | |
Adjusted Earnings (Loss) before Income Taxes(1) | | 26 | | 45 | | 51 | | 17 | | (110) | | 1 | | 30 | |
Earnings (loss) before income taxes | | 29 | | 46 | | 63 | | 28 | | (143) | | — | | 23 | |
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3 months ended March 31, 2025 | | Hydro | Wind & Solar(2) | Gas | Energy Marketing | Corporate | Energy Transition | Total |
| Alberta | | 47 | | 10 | | 50 | | 21 | | (41) | | (2) | | 85 | |
| Canada, excluding Alberta | | — | | 48 | | 27 | | — | | — | | — | | 75 | |
| U.S. | | — | | 42 | | 3 | | — | | — | | 39 | | 84 | |
Western Australia | | — | | 2 | | 24 | | — | | — | | — | | 26 | |
Adjusted EBITDA(1) | | 47 | | 102 | | 104 | | 21 | | (41) | | 37 | | 270 | |
Adjusted Earnings (Loss) before Income Taxes(1) | | 38 | | 49 | | 40 | | 19 | | (140) | | 22 | | 28 | |
Earnings (loss) before income taxes | | 59 | | 11 | | 65 | | 18 | | (151) | | 47 | | 49 | |
(1)Adjusted EBITDA and Adjusted Earnings (Loss) before Income Taxes are non-IFRS measures, are not defined, have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.
(2)Earnings before income taxes for the Wind and Solar segment exclude the contribution from Skookumchuck wind facility.
Hydro
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| 3 months ended March 31 | | | 2026 | 2025 | Change | | | |
Gross installed capacity (MW) | | | 922 | | 922 | | — | | — | % | | | | |
LTA generation (GWh) | | | 373 | | 402 | | (29) | | (7) | % | | | | |
| Availability (%) | | | 95.4 | | 93.6 | | 1.8 | | 2 | % | | | | |
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| Production | | | | | | | | | | |
| Contract production (GWh) | | | 52 | | 38 | | 14 | | 37 | % | | | | |
| Merchant production (GWh) | | | 308 | | 345 | | (37) | | (11) | % | | | | |
| Total energy production (GWh) | | | 360 | | 383 | | (23) | | (6) | % | | | | |
Ancillary service volumes (GWh)(1) | | | 826 | | 713 | | 113 | | 16 | % | | | | |
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Alberta Hydro Assets ancillary services revenues(1) | | | 23 | | 20 | | 3 | | 15 | % | | | | |
Alberta Hydro Assets revenues(2) | | | 22 | | 26 | | (4) | | (15) | % | | | | |
Other Hydro Assets revenues and other Hydro revenues(3) | | | 8 | | 9 | | (1) | | (11) | % | | | | |
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Environmental and tax attributes revenues | | | 1 | | 10 | | (9) | | (90) | % | | | | |
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Adjusted Revenues(4) | | | 54 | | 65 | | (11) | | (17) | % | | | | |
| Fuel and purchased power | | | (4) | | (4) | | — | | — | % | | | | |
Adjusted Gross Margin(4) | | | 50 | | 61 | | (11) | | (18) | % | | | | |
OM&A | | | (14) | | (13) | | (1) | | 8 | % | | | | |
| Taxes, other than income taxes | | | (1) | | (1) | | — | | — | % | | | | |
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Adjusted EBITDA(4) | | | 35 | | 47 | | (12) | | (26) | % | | | | |
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Earnings before income taxes | | | 29 | | 59 | | (30) | | (51) | % | | | | |
Supplementary Information: Gross revenues per MWh | | | | | | | | | | |
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Alberta Hydro Assets revenues ($/MWh)(2) | | | 71 | | 75 | | (4) | | (5) | % | | | | |
Alberta Hydro Assets ancillary services revenues ($/MWh)(1) | | | 28 | | 28 | | — | | — | % | | | | |
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(1)Alberta Hydro Assets ancillary services revenues is a supplementary financial measure. Alberta Hydro Assets ancillary services revenues are revenues earned from providing services required to ensure that the interconnected electric system is operated in a manner that provides a satisfactory level of service with acceptable levels of voltage and frequency as described in the AESO Consolidated Authoritative Document Glossary. Revenues per MWh are calculated by dividing Alberta Hydro Assets ancillary services revenues by ancillary service volumes in MWh.
(2)Alberta Hydro Assets revenues is a supplementary financial measure and is comprised of revenues from 13 hydro facilities on the Bow and North Saskatchewan river systems, as well as revenues from swaps and forward hedges. Revenues per MWh are calculated by dividing Alberta Hydro Assets revenues by merchant production in MWh.
(3)Other Hydro Assets revenues is a supplementary financial measure and consists of revenues from our hydro facilities in British Columbia, Ontario and Alberta (other than the Alberta Hydro Assets). Other Hydro revenues is a supplementary financial measure and includes revenues from our transmission business and other contractual arrangements, including the flood mitigation agreement with the Government of Alberta and black start services.
(4)Adjusted Revenues, Adjusted Gross Margin and Adjusted EBITDA are non-IFRS measures, are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding these measures. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $57 million (March 31, 2025 — $86 million), to Adjusted Gross Margin — gross margin of $53 million (March 31, 2025 — $82 million), to Adjusted EBITDA — earnings before income taxes of $29 million (March 31, 2025 — $59 million).
Adjusted Revenues for the three months ended March 31, 2026 decreased compared to the same period in 2025, primarily due to:
•Lower environmental and tax attributes revenues due to lower sales of emission credits to third parties; and
•Lower spot and hedged power prices in the Alberta market; partially offset by
•Higher ancillary services volumes due to production optimization between the Gas and Hydro segments.
Adjusted EBITDA for the three months ended March 31, 2026, decreased compared to the same period in 2025, primarily due to lower Adjusted Revenues as explained by the factors above.
Earnings before income taxes for the three months ended March 31, 2026 decreased compared to the same period in 2025, primarily due to:
•Lower Adjusted EBITDA as explained above; and
•Lower unrealized mark-to-market gains due to unfavourable changes in forward prices in the current period.
For further discussion on the Alberta market conditions and pricing, refer to the Optimization of the Alberta Portfolio section of this MD&A.
Wind and Solar
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| 3 months ended March 31 | | | 2026 | 2025 | Change | | | | |
Gross installed capacity (MW) | | | 2,587 | | 2,587 | — | | — | % | | | | | |
| LTA generation (GWh) | | | 1,921 | | 2,056 | (135) | | (7) | % | | | | | |
| Availability (%) | | | 92.9 | | 94.0 | (1.1) | | (1) | % | | | | | |
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| Production | | | | | | | | | | | |
| Contract production (GWh) | | | 1,570 | | 1,610 | | (40) | | (2) | % | | | | | |
| Merchant production (GWh) | | | 368 | | 295 | | 73 | | 25 | % | | | | | |
| Total production (GWh) | | | 1,938 | | 1,905 | | 33 | | 2 | % | | | | | |
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Adjusted Revenues(1)(3) | | | 109 | | 119 | | (10) | | (8) | % | | | | | |
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Environmental and tax attributes revenues(1) | | | 24 | | 26 | | (2) | | (8) | % | | | | | |
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Adjusted Revenues(2)(3) | | | 133 | | 145 | | (12) | | (8) | % | | | | | |
| Fuel and purchased power | | | (7) | | (10) | | 3 | | (30) | % | | | | | |
Carbon compliance costs | | | — | | (1) | | 1 | | (100) | % | | | | | |
Adjusted Gross Margin(2)(3) | | | 126 | | 134 | | (8) | | (6) | % | | | | | |
OM&A | | | (25) | | (29) | | 4 | | (14) | % | | | | | |
| Taxes, other than income taxes | | | (7) | | (5) | | (2) | | 40 | % | | | | | |
Adjusted Net Other Operating Income(3) | | | 1 | | 2 | | (1) | | (50) | % | | | | | |
Adjusted EBITDA(2)(3) | | | 95 | | 102 | | (7) | | (7) | % | | | | | |
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Earnings before income taxes(4) | | | 46 | | 11 | | 35 | | 318 | % | | | | | |
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(1)Production Tax Credits related to the U.S. wind facilities that are subject to tax equity financing arrangements are excluded from the Environmental and tax attributes revenues line and are included under Adjusted Revenues line.
(2)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(3)Adjusted Revenues, Adjusted Gross Margin, Adjusted Net Other Operating Income, Adjusted EBITDA are non-IFRS measures, are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more information regarding these measures. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $118 million (March 31, 2025 — $100 million), to Adjusted Gross Margin — gross margin of $111 million (March 31, 2025 — $89 million), to Adjusted Net Other Operating Income — net other operating income of $13 million (March 31, 2025 — $4 million), to Adjusted EBITDA — earnings before income taxes of $46 million (March 31, 2025 — $11 million).
(4)Earnings before income taxes exclude the contribution from Skookumchuck wind facility.
Adjusted Revenues for the three months ended March 31, 2026 decreased compared to the same period in 2025, primarily due to lower contract revenue driven by lower availability and wind resource in Eastern Canada.
Adjusted EBITDA for the three months ended March 31, 2026 decreased compared to the same period in 2025,
primarily due to lower Adjusted Revenues as explained by the factors above.
Earnings before income taxes for the three months ended March 31, 2026 increased compared to the same period in 2025, primarily due to:
•Lower unrealized mark-to-market losses in the current period mainly due to the adoption of IFRS 9 hedge accounting. Effective Jan. 1, 2026, certain Virtual Power Purchase Agreement (VPPA) contracts were designated as cash flow hedges. As a result, the effective portion of
unrealized gains and losses due to changes in fair value is recognized in other comprehensive income, while the ineffective portion is recognized in revenue; and
•Higher legal settlement recoveries compared to the same period in 2025; partially offset by
•Lower Adjusted EBITDA as explained above.
Gas
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| 3 months ended March 31 | | | 2026 | 2025 | Change | | | | |
Gross installed capacity(1) (MW) | | | 5,114 | | 4,834 | | 280 | | 6 | % | | | | | |
| Availability (%) | | | 94.0 | | 95.5 | | (1.5) | | (2) | % | | | | | |
| Production | | | | | | | | | | | |
Contract sales volume (GWh) | | | 2,394 | | 2,550 | | (156) | | (6) | % | | | | | |
Merchant sales volume (GWh) | | | 1,000 | | 1,292 | | (292) | | (23) | % | | | | | |
Purchased power (GWh)(2) | | | (248) | | (338) | | 90 | | (27) | % | | | | | |
Total production (GWh) | | | 3,146 | | 3,504 | | (358) | | (10) | % | | | | | |
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Adjusted Revenues(3) | | | 342 | | 366 | | (24) | | (7) | % | | | | | |
Adjusted Fuel and Purchased Power(3) | | | (154) | | (161) | | 7 | | (4) | % | | | | | |
Carbon compliance costs | | | (39) | | (49) | | 10 | | (20) | % | | | | | |
Adjusted Gross Margin(3) | | | 149 | | 156 | | (7) | | (4) | % | | | | | |
Adjusted OM&A(3) | | | (62) | | (57) | | (5) | | 9 | % | | | | | |
| Taxes, other than income taxes | | | (5) | | (5) | | — | | — | % | | | | | |
| Net other operating income | | | 11 | | 10 | | 1 | | 10 | % | | | | | |
Adjusted EBITDA(3) | | | 93 | | 104 | | (11) | | (11) | % | | | | | |
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Earnings before income taxes | | | 63 | | 65 | | (2) | | (3) | % | | | | | |
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(1)Includes gross installed capacity of 310 MW from four facilities in Ontario attributable to the acquisition of Far North. Refer to the "Significant and Subsequent events" section. Gas segment excludes the Ada Cogeneration facility in the U.S, with a gross installed capacity of 29 MW, due to its retirement on Jan. 5, 2026.
(2)Power required to fulfil contractual obligations is included in purchased power.
(3)Adjusted Revenues, Adjusted Fuel and Purchased Power, Adjusted Gross Margin, Adjusted OM&A and Adjusted EBITDA are non-IFRS measures, are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $348 million (March 31, 2025 — $390 million), to Adjusted Fuel and Purchased Power — fuel and purchased power of $154 million (March 31, 2025 — $163 million), to Adjusted Gross Margin — gross margin of $155 million (March 31, 2025 — $178 million), to Adjusted OM&A — OM&A of $62 million (March 31, 2025 — $59 million) and to Adjusted EBITDA — earnings before income taxes of $63 million (March 31, 2025 — $65 million).
Adjusted Revenues for the three months ended March 31, 2026 decreased compared to the same period in 2025, primarily due to:
•Lower hedge and spot power prices in the Alberta market compared to the same period in 2025, which led to higher dispatch optimization in the current period;
•Lower contract revenue from the Ada Cogeneration facility due to its retirement in the first quarter of 2026; partially offset by
•Positive contribution from higher realized pricing in Ontario and the acquisition of the Far North facilities.
Adjusted EBITDA for the three months ended March 31, 2026 decreased compared to the same period in 2025, primarily due to:
•Lower Adjusted Revenues as explained above;
•Higher natural gas costs in Eastern Canada; partially offset by
•Lower fuel and carbon compliance costs due to higher dispatch optimization.
Earnings before income taxes for the three months ended March 31, 2026 were comparable to the same period in 2025, primarily due to:
•Lower Adjusted EBITDA as explained above; and
•Lower unrealized mark-to-market gains in the current period due to less favourable hedge prices in the current period; partially offset by
•Lower depreciation driven by a change in the useful life assumptions in 2025 for the Sheerness facilities.
Energy Marketing
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| 3 months ended March 31 | | | 2026 | 2025 | Change | | | |
Adjusted Revenues(1) | | | 28 | | 28 | | — | | — | % | | | | |
| OM&A | | | (11) | | (7) | | (4) | | 57 | % | | | | |
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Adjusted EBITDA(1) | | | 17 | | 21 | | (4) | | (19) | % | | | | |
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Earnings before income taxes | | | 28 | | 18 | | 10 | | 56 | % | | | | |
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(1)Adjusted Revenues and Adjusted EBITDA are non-IFRS measures, are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $39 million (March 31, 2025 — $27 million) and to Adjusted EBITDA — earnings before income taxes of $28 million (March 31, 2025 — $18 million).
Adjusted Revenues for the three months ended March 31, 2026 were comparable to the same period in 2025.
Adjusted EBITDA for the three months ended March 31, 2026 was lower compared to the same period in 2025 primarily driven by higher OM&A due to higher accrued incentive costs driven by higher unrealized mark-to-market gains.
Earnings before income taxes for the three months ended March 31, 2026 increased compared to the same period in 2025 due to:
•Higher unrealized mark-to-market gains due to more favourable trading positions; partially offset by
•Lower Adjusted EBITDA as explained above.
Corporate
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Adjusted OM&A(1) | (38) | | (41) | | 3 | | (7) | % | | | | |
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Adjusted EBITDA(1) | (37) | | (41) | | 4 | | (10) | % | | | | |
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| Loss before income taxes | (143) | | (151) | | 8 | | (5) | % | | | | |
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(1)Adjusted OM&A and Adjusted EBITDA are non-IFRS measures, are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. The most directly comparable IFRS measure to Adjusted OM&A is OM&A of $62 million (March 31, 2025 — $49 million). The most directly comparable IFRS measure to Adjusted EBITDA is loss before income taxes of $143 million (March 31, 2025 — $151 million).
Adjusted EBITDA for the three months ended March 31, 2026 was comparable to the same period in 2025.
Loss before income taxes for the three months ended March 31, 2026 decreased compared to the same period in 2025 due to:
•Comparable Adjusted EBITDA as stated above;
•Lower interest expense driven by lower interest on certain senior notes, following their refinancing at lower interest rates during 2025, lower interest on lease liabilities and lower accretion and other interest on
provisions; and
•Lower spending on early stage growth and development projects; partially offset by
•Higher unrealized foreign exchange losses driven by unfavourable changes in foreign currency rates;
•Higher termination and restructuring costs as part of strategic decisions; and
•Higher legal costs arising from cost determinations made after the conclusion of arbitration proceedings in the current period.
Energy Transition(1)
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| 3 months ended March 31 | | | 2026 | 2025 | Change | | | | | |
Gross installed capacity (MW) | | | 671 | | 671 | | — | | — | % | | | | | | |
Availability(2) (%) | | | 100.0 | | 97.1 | | 2.9 | | 3 | % | | | | | | |
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| | | | | | | | | | | | |
| Total production (GWh) | | | — | | 1,040 | | (1,040) | | (100) | % | | | | | | |
| | | | | | | | | | | | |
Adjusted Revenues(3) | | | 2 | | 153 | | (151) | | (99) | % | | | | | | |
| Fuel and purchased power | | | — | | (98) | | 98 | | (100) | % | | | | | | |
| | | | | | | | | | | | |
Adjusted Gross Margin(3) | | | 2 | | 55 | | (53) | | (96) | % | | | | | | |
Adjusted OM&A(3) | | | (1) | | (17) | | 16 | | (94) | % | | | | | | |
| Taxes, other than income taxes | | | — | | (1) | | 1 | | (100) | % | | | | | | |
| | | | | | | | | | | | |
Adjusted EBITDA(3) | | | 1 | | 37 | | (36) | | (97) | % | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Earnings before income taxes | | | — | | 47 | | (47) | | (100) | % | | | | | | |
Supplementary information: | | | | | | | | | | | | |
Highvale mine reclamation spend(4) | | | 3 | | 3 | | — | | — | % | | | | | | |
Centralia mine reclamation spend(4) | | | 3 | | 4 | | (1) | | (25) | % | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
(1)The Energy Transition segment is a non-reportable segment as at March 31, 2026. Refer to Note 19 of the condensed consolidated financial statements the three months ended March 31, 2026.
(2)Centralia Unit 2 facility ceased coal-fired operations at the end of 2025 in the normal course. The facility remains available for power generation as mandated by the United States Department of Energy.
(3)Adjusted Revenues, Adjusted Gross Margin, Adjusted OM&A, Adjusted EBITDA are non-IFRS measures, are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. The most directly comparable IFRS measure to Adjusted Revenues is revenues of $2 million (March 31, 2025 — $154 million), to Adjusted Gross Margin — gross margin of $2 million (March 31, 2025 — $56 million), to Adjusted OM&A — OM&A of $8 million (March 31, 2025 — $17 million), to Adjusted EBITDA — earnings before income taxes of $— million (March 31, 2025 — $47 million).
(4)Highvale and Centralia mine reclamation spending, which represent the costs necessary to bring the sites to their original condition, are supplementary financial measures and are included in the decommissioning and restoration liabilities settled during the period in the condensed consolidated statements of financial position under IFRS.
Adjusted Revenues and Adjusted EBITDA for the three months ended March 31, 2026 decreased compared to the same period in 2025, primarily due to no production at Centralia.
Adjusted OM&A has been reduced by the expected recoveries as a result of complying with the Order. Refer to the "Regulatory Updates" section of this MD&A.
Earnings before income taxes for the three months ended March 31, 2026 decreased compared to the same period in 2025, due to:
•Lower Adjusted EBITDA as explained above;
•Lower impairment reversal due to the reversal in the comparative period related to the generation equipment classified as held for sale; and
•Community fund expense related to the retirement of coal operations at Centralia; partially offset by
•Lower depreciation due to the cessation of coal-fired operations at Centralia in the normal course; and
•Higher asset impairment reversals in the current period due to a decrease in decommissioning and restoration provisions on retired assets primarily driven by changes in discount rates.
Mine reclamation spending for the three months ended March 31, 2026 was consistent with the same period in 2025.
Optimization of the Alberta Portfolio
The Alberta electricity portfolio metrics disclosed below are supplementary financial measures used to provide additional insight into the segment performance in the Alberta market.
Approximately 61 per cent of our generating capacity is located in Alberta, with 77 per cent exposed to merchant market. Our portfolio of assets consists of hydro, wind, battery storage and natural gas generation facilities.
Our hydro and gas fleets provide ancillary services, with hydro assets also supporting grid reliability, including black start capability and contributing to drought mitigation through regulated river flows. Our Alberta wind and hydro assets generate environmental credits sold to third parties and our Gas segment.
Portfolio performance is supported by fuel and asset diversity, enabling optimization between energy production and ancillary services. A significant portion of our Alberta capacity is hedged through commercial and industrial customer contracts and financial instruments to enhance cash‑flow stability.
During periods of low market prices, we may elect not to dispatch gas generation and instead monetize contracted or hedged positions. In the first quarter of 2026, this strategy resulted in contracted and hedged gas volumes exceeding actual merchant production.
The following table provides information for the Company's Alberta electricity portfolio:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2026 | 2025 | |
3 months ended March 31 | Hydro | Wind & Solar | Gas | | Total | Hydro | Wind & Solar | Gas | | Total | | | | | |
| Gross installed capacity (MW) | 834 | | 764 | | 3,650 | | | 5,248 | | 834 | | 764 | | 3,650 | | | 5,248 | | | | | | |
Total production(1) (GWh) | 308 | | 659 | | 2,004 | | | 2,971 | | 345 | | 557 | | 2,293 | | | 3,195 | | | | | | |
| Contract production (GWh) | — | | 291 | | 1,318 | | | 1,609 | | — | | 262 | | 1,370 | | | 1,632 | | | | | | |
| Merchant production (GWh) | 308 | | 368 | | 686 | | | 1,362 | | 345 | | 295 | | 923 | | | 1,563 | | | | | | |
| | | | | | | | | | | | | | | |
| Ancillary services volumes (GWh) | 826 | | 15 | | 144 | | | 985 | | 714 | | 19 | | 268 | | | 1,001 | | | | | | |
Hedged volumes (GWh) | 243 | | 23 | | 2,088 | | | 2,354 | | 276 | | 38 | | 1,959 | | | 2,273 | | | | | | |
| Production contracted or hedged (%) | 79 | % | 48 | % | 170 | % | | 133 | % | 80 | % | 54 | % | 145 | % | | 122 | % | | | | | |
Hedged volumes as a percentage of gross installed capacity (%) | 13 | % | 1 | % | 26 | % | | 21 | % | 15 | % | 2 | % | 25 | % | | 20 | % | | | | | |
| | | | | | | | | | | | | | | |
Adjusted Revenues(2)(3) ($) | 49 | | 26 | | 199 | | | 274 | | 62 | | 28 | | 226 | | | 316 | | | | | | |
Fuel ($) | (1) | | (3) | | (85) | | | (89) | | (1) | | (4) | | (99) | | | (104) | | | | | | |
Purchased power ($) | (2) | | (1) | | (8) | | | (11) | | (3) | | (1) | | (11) | | | (15) | | | | | | |
Carbon compliance costs(3)($) | — | | — | | (30) | | | (30) | | — | | (1) | | (36) | | | (37) | | | | | | |
Adjusted Gross Margin ($) | 46 | | 22 | | 76 | | | 144 | | 58 | | 22 | | 80 | | | 160 | | | | | | |
| | | | | | | | | | | | | | | |
(1)Total production includes contract and merchant production and excludes ancillary services volumes.
(2)Revenues have been adjusted to exclude the impact of unrealized mark-to-market gains or losses. The Energy Transition segment is a non-reportable segment as at March 31, 2026 and is no longer included in the table above. Refer to Note 19 of the condensed consolidated financial statements the three months ended March 31, 2026.
(3)The intercompany sales of emission credits from the Hydro and Wind and Solar segments to the Gas segment are eliminated on consolidation in the Corporate segment. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.
Total production for the Alberta portfolio for the three months ended March 31, 2026, was 2,971 GWh, compared to 3,195 GWh for the same period in 2025. The decrease of 224 GWh, or seven per cent, was primarily due to:
•Lower merchant production in the Gas segment due to dispatch optimization driven by lower market prices;
•Lower production from the Hydro segment due to lower storage levels in the beginning of the year; partially offset by
•Higher production volumes in the Wind and Solar segment due to higher wind resource.
Ancillary services volumes for the three months ended March 31, 2026 were comparable to the the same period of 2025, due to production optimization between the Gas and Hydro segments.
Hedged volumes for the Alberta portfolio for the three months ended March 31, 2026, increased compared to the same period in 2025. In anticipation of the risk of lower
prices in 2026, the Company deployed a defensive strategy to increase financial hedges for the merchant portfolio at attractive margins. Realized gains and losses on financial hedges are included in Adjusted Revenues in the table above.
Adjusted Gross Margin for the Alberta portfolio for the three months ended March 31, 2026, was $144 million, compared to $160 million in the same period of 2025. The decrease of $16 million, or 10 per cent, was primarily due to:
•Lower gross margin for the Hydro segment due to lower environmental and tax attributes revenue due to lower sales of emission credits to third parties and lower spot power prices; and
•Lower gross margin for the Gas segment due to the impact of lower Alberta spot and hedge power prices, resulting in higher dispatch optimization and lower contributions from hedging.
The following table provides information for the Company's Alberta electricity portfolio:
| | | | | | | | | | | |
| | | |
| | | |
| 3 months ended March 31 | 2026 | 2025 | | | |
| Alberta Market | | | | | |
| Spot power price average per MWh | 32 | | 40 | | | | |
| Natural gas price (AECO) per GJ | 1.93 | | 2.03 | | | | |
Carbon compliance price per tonne(1) | 110 | | 95 | | | | |
| Alberta Portfolio Results | | | | | |
Realized merchant power price per MWh(2) | 101 | | 122 | | | | |
Ancillary services price per MWh(3) | 29 | | 26 | | | | |
| Hydro energy spot power price per MWh | 46 | | 70 | | | | |
Hydro ancillary services price per MWh | 28 | | 28 | | | | |
| Wind energy spot power price per MWh | 20 | | 20 | | | | |
Gas spot power price per MWh | 48 | | 56 | | | | |
Hedged power price average per MWh(4) | 66 | | 71 | | | | |
Hedged volume (GWh) | 2,354 | | 2,273 | | | | |
Fuel cost per MWh(5) | 44 | | 45 | | | | |
Carbon compliance cost per MWh(6) | 15 | | 16 | | | | |
| | | | | |
(1)The Government of Alberta froze the carbon price per tonne at $95 under the Technology Innovation and Emissions Reduction regulation. During the three months ended March 31, 2026, the carbon compliance obligation has been accrued at a price of $110 per tonne in consideration of the federal Output‑Based Pricing System backstop, which, if imposed on the province of Alberta, would result in a carbon pricing obligation of $110 per tonne.
(2)Realized merchant power price per MWh for the Alberta electricity portfolio is a supplementary financial measure and represents the average price realized as a result of the Company's merchant power sales and portfolio optimization activities. It is calculated as merchant revenues (excluding assets under long-term contract and ancillary revenues, but including the impact of gains and losses from derivatives and trading activities) for the reporting period divided by total merchant GWh produced during the reporting period.
(3)Ancillary services price per MWh for the Alberta electricity portfolio is a supplementary financial measure and represents the average ancillary services price across Hydro, Gas and Wind and Solar segments.
(4)Hedged power price average per MWh is a supplementary financial measure and is calculated as the average sales price for all hedges and direct customer sales during the reporting period.
(5)Fuel cost per MWh is a supplementary financial measure and is calculated as total fuel costs for the facilities in Alberta divided by production from carbon-emitting generation in the Gas segment.
(6)Carbon compliance per MWh is a supplementary financial measure and is calculated as total carbon compliance costs for the Gas segment in Alberta divided by production from carbon-emitting generation in the Gas segment.
The average spot power price per MWh in Alberta for the three months ended March 31, 2026, decreased by $8 per MWh, compared to the same period in 2025, primarily due to the impact of milder weather during the current period.
The realized merchant power price per MWh of production for Alberta for the three months ended March 31, 2026, decreased by $21 per MWh, compared to the same period in 2025, primarily due to:
•Lower average spot power prices as explained above and lower hedge power prices compared to the same period in 2025; partially offset by
•Favourable hedge positions settling and production optimization, which generated positive contributions over settled spot prices in Alberta.
Fuel cost per MWh for the three months ended March 31, 2026, was comparable to the same period in 2025.
Carbon compliance cost per MWh of production for the Alberta portfolio for the three months ended March 31, 2026 was comparable to the same period in 2025, primarily due to:
•A favourable impact on carbon compliance cost per MWh due to a higher proportion of production from lower-carbon-emitting cogeneration facilities; partially offset by
•An increase in the carbon price per tonne from $95 in 2025 to $110 in 2026.
Selected Quarterly Information
Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are often incurred in the spring and fall when electricity prices are expected to be lower, and electricity prices generally increase in the peak winter and summer months in our main markets due to increased heating and cooling loads. Margins are also typically impacted in the second
quarter due to the volume of hydro production resulting from spring runoff and rainfall in the Pacific Northwest. Typically, hydroelectric facilities generate most of their electricity and revenues during the spring months when melting snow starts feeding watersheds and rivers. Inversely, wind speeds are historically greater during the cold winter months and lower in the warm summer months.
| | | | | | | | | | | | | | |
| | Q2 2025 | Q3 2025 | Q4 2025 | Q1 2026 |
| Revenues | 433 | | 615 | | 599 | | 565 | |
Gross margin | 334 | | 353 | | 301 | | 361 | |
OM&A | 173 | | 179 | | 186 | | 181 | |
Depreciation and amortization | 150 | | 135 | | 148 | | 105 | |
| | | | |
(Loss) earnings before income taxes | (95) | | (53) | | (42) | | 23 | |
| | | | |
| | | | |
Net (loss) earnings attributable to common shareholders | (112) | | (62) | | (62) | | 13 | |
Net (loss) earnings per share attributable to common shareholders, basic and diluted(1) | (0.38) | | (0.20) | | (0.21) | | 0.04 | |
| | | | |
| | | | |
| | | | |
| | | | | | | | | | | | | | |
| Q2 2024 | Q3 2024 | Q4 2024 | Q1 2025 |
| Revenues | 582 | | 638 | | 678 | | 758 | |
Gross margin | 436 | | 384 | | 390 | | 432 | |
| OM&A | 144 | | 143 | | 234 | | 173 | |
| Depreciation and amortization | 131 | | 133 | | 143 | | 146 | |
| Earnings (loss) before income taxes | 94 | | 9 | | (51) | | 49 | |
| Net earnings (loss) attributable to common shareholders | 56 | | (36) | | (65) | | 46 | |
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1) | 0.18 | | (0.12) | | (0.22) | | 0.15 | |
| | | | |
| | | | — | |
| | | | |
(1)Basic and diluted earnings (loss) per share attributable to common shareholders is calculated in each period using the basic and diluted weighted average common shares outstanding during the period, respectively. As a result, the sum of the earnings (loss) per share for the four quarters making up the calendar year may sometimes differ from the annual earnings (loss) per share.
Operating results have been impacted by the following events:
•The acquisition of Far North on Feb. 2, 2026;
•The acquisition of Heartland on Dec. 4, 2024; and
•No production at Centralia starting the first quarter of 2026 due to the cessation of coal-fired operations in the normal course.
Refer to the "Description of the Business" section of this MD&A.
In addition to the items described above, revenues have been impacted by:
•Alberta spot and hedged power prices;
•Mid-Columbia power prices until the fourth quarter of 2025;
•Ontario spot power prices;
•The effects of unrealized mark-to-market gains and losses from hedging and derivative positions due to favourable and unfavourable changes in forward rates; and
•The effects of realized mark-to-market gains and losses on settled trades.
Effective Jan. 1, 2026, certain VPPA contracts were designated as cash flow hedges. As a result, the effective portion of unrealized gains and losses due to changes in fair value is recognized in other comprehensive income, while the ineffective portion is recognized in revenue.
Gross Margin has been impacted by:
•Factors impacting revenues as described above;
•Natural gas prices;
•Purchased power costs;
•Carbon price per tonne, which increased from $80 in 2024 to $95 in 2025 and $110 in 2026; and
•Utilization of internally generated and externally purchased emission credits to settle a portion of our 2024 and 2023 GHG obligation, which reduced the carbon compliance obligation in the second quarters of 2025 and 2024, respectively.
OM&A has been impacted by:
•Strategic and growth initiatives;
•Legal costs arising from cost determinations made after the conclusion of arbitration proceedings in the first quarter of 2026;
•The planning, design and implementation of an upgrade to our ERP system;
•Expected recoveries for Centralia as a result of complying with the Order in the first quarter of 2026; and
•Acquisition-related transaction and restructuring costs related to Heartland and Far North acquisitions.
Depreciation has been impacted by:
•Lower depreciation in the Gas segment in the current period due to a change in the useful life assumptions in 2025 for the Sheerness facilities;
•Lower depreciation for Centralia Unit 2 facility due to the cessation of coal-fired operations in the normal course; and
•The revision to the useful lives of certain facilities in the third quarter of 2024.
(Loss) earnings before income taxes have been impacted by:
•The factors explained above;
•Net other operating income, which includes insurance recoveries and legal settlement recoveries;
•Interest expense and foreign exchange gains and losses; and
•Asset impairment charges and reversals on operating and retired assets primarily driven by changes in decommissioning liabilities and impairment, net of reversals, related to certain Wind and Solar facilities in the third quarter of 2025.
Net (loss) earnings attributable to common shareholders have been impacted by:
•The factors explained above;
•Changes in net earnings (losses) attributable to non-controlling interests primarily due to changes in net earnings for TA Cogen resulting from weaker merchant pricing in the Alberta market and depreciation impacts from changes in the useful life assumptions of the Sheerness facilities.
Financial Condition
Balance Sheet Analysis
The following table highlights significant changes in the Condensed Consolidated Statements of Financial Position from Dec. 31, 2025 to March 31, 2026:
| | | | | | | | | | | | |
| As at | March 31, 2026 | Dec. 31, 2025 | Increase/(decrease) | |
| Total current assets | 1,385 | | 1,336 | | 49 | | |
| Total non-current assets | 7,402 | | 7,325 | | 77 | | |
| Total assets | 8,787 | | 8,661 | | 126 | | |
| | | | |
| Total current liabilities | 1,817 | | 1,830 | | (13) | | |
| Total non-current liabilities | 5,494 | | 5,366 | | 128 | | |
| Total liabilities | 7,311 | | 7,196 | | 115 | | |
| | | | |
| | | | |
Working Capital
The deficit of current assets relative to current liabilities, including the current portion of long-term debt and lease liabilities, was $432 million as at March 31, 2026 (Dec. 31, 2025 – $494 million).
The working capital deficit was primarily caused by the classification of exchangeable securities totaling $750 million as current liabilities as a result of Brookfield's conversion option that can be exercised at any time after Dec. 31, 2024, although there is no obligation to deliver cash equivalent resources and Brookfield cannot call for repayment. Refer to Note 26 of the 2025 consolidated financial statements for details.
The deficit as at March 31, 2026, decreased from Dec. 31, 2025 primarily as a result of lower accounts receivable and collateral provided, partially offset by lower accounts payable and accrued liabilities and higher income taxes receivable. For the working capital management discussion, refer to the "Financial Capital" section below.
Non-Current Assets
Non-current assets as at March 31, 2026, were $7,402 million, an increase of $77 million from $7,325 million as at Dec. 31, 2025, primarily due to higher property, plant and equipment (PP&E) resulting from the acquisition of Far
North totaling $101 million, capital additions of $27 million and higher foreign exchange gains on translation of the balances denominated in foreign currency to the presentation currency, partially offset by depreciation of $97 million for the three months ended March 31, 2026.
In addition, during the three months ended March 31, 2026, the Company completed Mount Keith West Network Upgrade project and accordingly derecognized $39 million from the assets under construction and recognized a finance lease receivable.
Non-Current Liabilities
Non-current liabilities as at March 31, 2026, were $5,494 million, an increase of $128 million from $5,366 million as at Dec. 31, 2025, mainly due to an increase in credit facilities, long-term debt and lease liabilities driven by cash drawings on the syndicated credit facility to finance the Far North acquisition.
Contractual Obligations
There were no material changes to the Company’s contractual obligations during the quarter. The Company’s significant contractual commitments are described in Note 36 Commitments and Contingencies of the consolidated financial statements for the year ended Dec. 31, 2025.
Financial Capital
The Company is focused on maintaining a strong balance sheet and financial position to ensure access to sufficient financial capital. The Company expects cash flow from operating activities to be sufficient to meet its obligations, support sustaining capital expenditures and fund dividends over both the short- and long-term. Given its financing track record in recent years, the Company has robust access to capital markets for future funding needs. The Company has a total of $2.2 billion committed capacity under its credit facilities as at March 31, 2026, of which $1.3 billion remains available for short-term borrowings. Refer to the "Credit Facilities" section below for further details.
The Company manages working capital deficits primarily through cash generated from operating activities and the availability of credit facilities. Management regularly monitors liquidity and funding requirements, and evaluates the Company's capital structure in light of prevailing market conditions. Current leverage levels are considered manageable, they reflect management’s ongoing assessment of the risk profile and cash flow characteristics associated with the Company’s assets.
For information on Company's credit ratings, refer to "Financial Condition" section of the 2025 Annual Report. Risks associated with our credit ratings are discussed in the "Risk Management" section of the 2025 Annual Report.
Capital Structure
Our capital structure consists of the following components as shown below:
| | | | | | | | | | | | | | | | | | | | | | |
As at | March 31, 2026 | | Dec. 31, 2025 | |
| $ | % of total | $ | % of total | | |
| | | | | | | | |
Senior unsecured debt | 1,852 | | | 33 | | | 1,734 | | 31 | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Non-recourse debt | 1,481 | | | 26 | | | 1,471 | | 26 | | | |
| | | | | | | | |
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| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Recourse debt - OCP Bond | 153 | | | 3 | | | 166 | | 3 | | | |
| | | | | | | | |
Tax equity financing | 72 | | | 1 | | | 76 | | 1 | | | |
| Lease liabilities | 148 | | | 3 | | | 146 | | 3 | | | |
Credit facilities, long-term debt and lease liabilities(1) | 3,706 | | | 66 | | | 3,593 | | 64 | | | |
| Add: Exchangeable debentures | 350 | | | 6 | | | 350 | | 6 | | | |
| Add: Bank overdraft | 7 | | | — | | | — | | — | | | |
| Less: Cash and cash equivalents | (274) | | | (5) | | | (205) | | (3) | | | |
Less: TransAlta OCP LP restricted cash(2) | — | | | — | | | (17) | | — | | | |
| Less: Fair value of foreign exchange forward contracts on foreign-currency denominated debt | (4) | | | — | | | 4 | | — | | | |
Total Consolidated Net Debt(3)(4)(5) | 3,785 | | | 67 | | | 3,725 | | 67 | | | |
Exchangeable preferred securities(5) | 400 | | | 7 | | | 400 | | 7 | | | |
| Total equity | 1,476 | | | 26 | | | 1,465 | | 26 | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Total capital | 5,661 | | | 100 | | | 5,590 | | 100 | | | |
| | | | | | | | |
(1)Credit facilities, long-term debt and lease liabilities consist of current and non-current portions in the Condensed Consolidated Statements of Financial Position.
(2)Principal portion of the TransAlta OCP LP restricted cash related to the TransAlta OCP LP bonds, as this cash is restricted specifically to repay the bonds.
(3)Total Consolidated Net Debt is a non-IFRS measure, which is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. The most directly comparable IFRS measure is total credit facilities, long-term debt and lease liabilities. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for further discussion.
(4)Tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in these amounts.
(5)Total Consolidated Net Debt excludes the exchangeable preferred shares as they are considered equity with dividend payments for credit purposes.
Credit Facilities
The Company's credit facilities are summarized in Note 14 of the Condensed Consolidated Financial Statements.
The Company maintains a strong financial position, with $1.5 billion in liquidity as at March 31, 2026. Credit facilities are the primary source of short-term liquidity after internally generated cash flow.
As at March 31, 2026, the Company had total committed capacity of $2.2 billion, against which $526 million of letters of credit were issued and $200 million was drawn in cash. Under the $400 million non-committed capacity, the Company issued $221 million of fully backstopped letters of credit, which reduced the available capacity on the committed credit facilities.
The Company is in compliance with all covenants under its credit facilities and all undrawn amounts are fully available.
In addition to the net $1.3 billion of remaining committed capacity, the Company held $274 million in cash and cash equivalents, resulting in total available liquidity of $1.5 billion as at March 31, 2026.
TransAlta's debt has terms and conditions, including financial covenants, that are considered ordinary and customary. As at March 31, 2026, the Company was in compliance with all of its debt covenants.
Non-Recourse Debt and Other
All non-recourse debt, the TransAlta OCP LP bond, and the 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 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 first quarter of 2026, with the exception of Windrise Wind LP. The funds in Windrise that have accumulated will remain there until the debt-service coverage ratio distribution threshold is met. At March 31, 2026, $133 million (Dec. 31, 2025 – $101 million) of cash was subject to these financial restrictions.
At March 31, 2026, $9 million (AU$9 million) of funds held by TEC Hedland Pty Ltd. are not accessible by other corporate entities as the funds must be solely used by the project entities to pay 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.
The $750 million of exchangeable securities are exchangeable into an equity ownership interest in TransAlta’s Alberta Hydro Assets between Dec. 31, 2024 and Dec. 31, 2028.
Returns to Providers of Capital
Interest Income and Interest Expense
The components of interest expense are disclosed in Note 7 of the Condensed Consolidated Financial Statements. Net Interest Expense in the reconciliation of our Adjusted EBITDA to our FFO and FCF is calculated as follows:
| | | | | | | | | | |
| | |
| 3 months ended March 31 | 2026 | 2025 | | |
Interest expense | 82 | | 93 | | | |
Less: Interest Income | (7) | | (5) | | | |
Less: non-cash items(1) | (14) | | (16) | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Net Interest Expense(2) | 61 | | 72 | | | |
(1)Non-cash items consists of accretion of provisions, financing cost amortization, interest paid in kind and other non-cash items.
(2)Net Interest Expense is a non-IFRS measure, is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers.
Interest expense for the three months ended March 31, 2026 was lower compared to the same period in 2025, primarily due to lower interest on certain senior notes, following their refinancing at lower interest rates during
2025, lower interest on lease liabilities and lower accretion and other interest on provisions.
Interest income for the three months ended March 31, 2026 was comparable to the same period in 2025.
Series B Preferred Shares conversion
On March 31, 2026, holders of Series B preferred shares converted 1,148,549 of the 2,370,087 outstanding Series B shares into Series A shares on a one‑for‑one basis. As a result of the conversion, on March 31, 2026, the Company had 10,778,462 Series A Shares and 1,221,538 Series B Shares issued and outstanding.
Other Series Preferred Shares
Other Series preferred shares outstanding for the three months ended March 31, 2026 remained unchanged.
Share Capital
For details on common and preferred shares issued and outstanding refer to Notes 15 and 16 of the Condensed Consolidated Financial Statements.
As at May 5, 2026, the outstanding number of common shares was 297.8 million. The outstanding number of preferred shares was as follows: Series A 10.8 million, Series B 1.2 million, Series C 10.0 million, Series D 1.0 million, Series E 9.0 million and Series G 6.6 million.
Cash Flows
The following table highlights significant changes in the Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2026 and March 31, 2025:
| | | | | | | | | | | | | | |
| | |
3 months ended March 31 | 2026 | | 2025 | Increase/ (decrease) |
Cash and cash equivalents, beginning of period | 205 | | | 337 | | (132) | |
| Provided by (used in): | | | | |
| Operating activities | 123 | | | 7 | | 116 | |
| Investing activities | (93) | | | (144) | | 51 | |
| Financing activities | 38 | | | 38 | | — | |
Effect of translation on foreign currency cash | 1 | | | — | | 1 | |
| | | | |
Cash and cash equivalents, end of period | 274 | | | 238 | | 36 | |
Cash Flow from Operating Activities
Cash from operating activities increased in the three months ended March 31, 2026, primarily due to favourable working capital movements driven by lower accounts receivable and collateral provided, partially offset by lower accounts payable and accrued liabilities. Gross margin was lower primarily due to lower revenues, partially offset by lower fuel and purchased power costs. Cash taxes decreased during the three months ended March 31, 2026, attributed to a lower tax obligation as at Dec. 31, 2025, resulting from lower earnings before income taxes for the year ended Dec. 31, 2025 compared to 2024.
Cash Flow used in Investing Activities
Cash used in investing activities for the three months ended March 31, 2026, decreased compared to the same period in 2025, primarily due to Nova facilities issued during the first quarter of 2025, partially offset by the cash paid to acquire Far North facilities in the current period and favourable change in non-cash investing working capital balances due to lower capital accruals.
Cash Flow from Financing Activities
Cash from financing activities for the three months ended March 31, 2026, was consistent compared to the same period in 2025, primarily due to higher cash drawings under the syndicated credit facility to finance the Far North acquisition in the current period and a repayment of the $400 million variable rate term loan facility and the issuance of $450 million senior notes during the first quarter of 2025.
Capital Expenditures
Sustaining capital and growth and development capital expenditures represent supplementary financial measures used to present our spending related to the safe and reliable operation of our existing facilities and the construction of projects, respectively. The sum of sustaining capital and growth and development capital
expenditures, adjusted for non-cash items and transfers, is equal to the additions to property, plant and equipment and intangible assets, and development capital expenditures during the period in the condensed consolidated statement of cash flows.
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. Sustaining capital are capital expenditures incurred for major maintenance to sustain the existing capacity or production of the existing asset to the end of its useful life.
Total sustaining capital expenditures for the three months
ended March 31, 2026 were comparable to the same period in 2025.
The Company's sustaining capital expenditures by segment are summarized in the table below:
| | | | | | | | | | | |
| | | |
| 3 months ended March 31 | 2026 | 2025 | | | |
| Hydro | 1 | | 4 | | | | |
| Wind and Solar | 4 | | 4 | | | | |
| Gas | 14 | | 11 | | | | |
| | | | | |
| Corporate | 2 | | 4 | | | | |
| | | | | |
Sustaining capital expenditures | 21 | | 23 | | | | |
Growth and Development Capital Expenditures
Growth and development expenditures are impacted by the timing and construction of projects within the development pipeline. Growth capital represents capital expenditures incurred that will add megawatts to the Company or will generate new incremental revenues and consists of engineering, design, contracting, permitting, payroll and overhead expenditures that meet capitalization criteria.
On Dec. 9, 2025 the Company had entered into a long-term tolling agreement (Tolling Agreement) with Puget Sound Energy to convert our 700 MW Centralia Unit 2 facility from coal to natural gas. The conversion extends the operating life of the facility and will leverage existing turbines, transmission and infrastructure, while also lowering emissions.
The Tolling Agreement provides a fixed-price capacity payment through 2044 for the facility. The coal-to-gas conversion project is expected to require approximately US$600 million in capital and, once in service, will generate contracted cash flow over the life of the Tolling Agreement. The Company expects to declare a final investment decision for the project in early 2027, after receiving required regulatory approvals. Permitting and project development will continue through 2026, followed by construction in 2027–2028, with converted natural gas-fired operations expected to begin in late 2028.
The following table provides our growth and development spending by segment:
| | | | | | | | | | | |
| | | |
| 3 months ended March 31 | 2026 | 2025 | | | |
| Hydro | 1 | | — | | | | |
| | | | | |
| Gas | 4 | | 11 | | | | |
Energy Transition | 3 | | — | | | | |
| | | | | |
Growth and development expenditures | 8 | | 11 | | | | |
Growth and development expenditures for the three months ended March 31, 2026 were lower compared to the same period in 2025, primarily due to:
•Lower spend in the Gas segment primarily due to a completion of the capital maintenance at Sarnia during the first quarter of 2025 caused by the plant outage in the fourth quarter of 2024; partially offset by
•Higher spending in the Energy Transition segment related to the Centralia conversion from coal to natural gas, which extends the operating life of the existing plant.
Refer to the "Strategic Priorities" section of the 2025 Annual Report for more details.
Growth
Over the course of 2025 and 2024, we refined our development pipeline to align with evolving regulatory and interconnection dynamics, while progressing opportunities at our legacy assets. The pipeline now includes 860 MW of mid-stage projects and 2,890 MW of early-stage projects. We remain focused on the redevelopment of existing thermal sites and pursuing greenfield and M&A opportunities in our core markets.
Early-Stage Development
Project feasibility is evaluated through initial assessments including market, technical, land and permitting evaluations. Milestones include securing key landowner control, establishment of interconnection access, transmission capacity, on-site resource measurement and initial stakeholder consultations. Projects are advanced to mid-stage development if a viable economic development path is identified.
The following table shows the pipeline of future growth projects currently under early-stage development:
| | | | | | | | | | | | | | | | | |
| Early-Stage Projects (MW) | Thermal | Wind | Solar | Storage | Total |
| Various | 1,890 | | 465 | | 190 | | 345 | | 2,890 | |
Mid-Stage Development
Project scope and commercial structure are matured at mid-stage development. Key milestones include finalizing core technologies and location, securing full land control, progressing through the interconnection process, initiating
offtake negotiations, advancing environmental and regulatory applications, and preparing a Class 4 capital cost estimate. Successful completion of mid-stage development means a project is ready for detailed definition to support a final investment decision.
The following table shows the pipeline of future growth projects currently under mid-stage development:
| | | | | | | | | | | | | | | | | |
| Mid-Stage Projects (MW) | Thermal | Wind | Solar | Storage | Total |
| Canada | — | | 100 | | — | | 20 | | 120 | |
U.S. | 700 | | — | | — | | — | | 700 | |
| Western Australia | — | | — | | 40 | | — | | 40 | |
| Total | 700 | | 100 | | 40 | | 20 | | 860 | |
Projects under Construction
The Mount Keith West network upgrade transmission project was completed during the three months ended March 31, 2026.
Accordingly, the Company derecognized $39 million from the assets under construction and recognized a finance lease receivable.
Other Consolidated Analysis
Commitments
The Company has not incurred any additional material contractual commitments in the three months ended March 31, 2026, either directly or through its interests in joint operations and joint ventures. For the current material outstanding commitments, please refer to Note 18 Commitments and Contingencies in the condensed consolidated financial statements and Note 36 of the 2025 audited annual consolidated financial statements.
Natural Gas Transportation 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 160 TJ per day on average and up to approximately 450 TJ per day during peak periods, while remarketing excess capacity.
Contingencies
For the current material outstanding contingencies, please refer to Note 36 of the 2025 audited annual consolidated financial statements. There were no material changes to the contingencies during the three months ended March 31, 2026.
Financial Instruments
For details on Financial instruments refer to Note 14 of the notes to the audited annual 2025 consolidated financial statements and Note 10 of our unaudited interim condensed consolidated financial statements as at and for the three months ended March 31, 2026.
We may enter into commodity transactions involving non-standard features for which market-observable data is not available. These transactions are defined under IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable from the market and fair value is therefore determined using valuation techniques. Fair values are validated by using reasonably possible
alternative assumptions as inputs to valuation techniques and any material differences are disclosed in the notes to the unaudited interim condensed consolidated financial statements.
At March 31, 2026, Level III instruments had a net liabilities carrying value of $319 million (2025 – net liabilities $312 million). The Level III liabilities increased during the three months ended March 31, 2026 due to volatility in market prices across multiple markets on existing contracts and contract settlements, and a decrease in the the carrying value of Nova facilities. Our risk management profile and practices have not changed materially from Dec. 31, 2025.
Non-IFRS and Supplementary Financial Measures
We use a number of financial measures to evaluate our performance and the performance of our business segments, including measures and ratios that are presented on a non-IFRS basis, as described below. Unless otherwise indicated, all amounts are in Canadian dollars and have been derived from our condensed consolidated financial statements prepared in accordance with IFRS. We believe that these non-IFRS amounts, measures and ratios, read together with our IFRS amounts, provide readers with a better understanding of how management assesses results.
Non-IFRS amounts, measures and ratios do not have standardized meanings under IFRS. They are unlikely to be comparable to similar measures presented by other companies and should not be viewed in isolation from, as an alternative to, or more meaningful than our IFRS results.
We calculate adjusted measures by adjusting certain IFRS measures for certain items that we do not believe reflect our ongoing operations in the period. Except as otherwise
described, these adjusted measures are calculated on a consistent basis from period to period.
Non-IFRS Financial Measures
This section provides additional information on these non-IFRS measures, including their reconciliation to the most comparable IFRS measure.
Adjusted EBITDA
Each business segment assumes responsibility for its operating results measured by Adjusted EBITDA. Adjusted EBITDA is an important metric for management that represents our core operational results.
Interest, taxes, depreciation and amortization are not included, as differences in accounting treatment may distort our core business results. In addition, certain reclassifications and adjustments are made to better assess results, excluding those items that may not be reflective of ongoing business performance. This
presentation may facilitate the readers' analysis of trends. The most directly comparable IFRS measure is earnings before income taxes.
The following are descriptions of the adjustments made to arrive at the non-IFRS measures:
Adjusted Revenue
Adjusted Revenues are revenues (the most directly comparable IFRS measure) adjusted to exclude:
•The impact of unrealized mark-to-market gains or losses and unrealized foreign exchange gains or losses on commodity transactions.
•Certain assets that we own in Canada and Western Australia are fully contracted and recorded as finance leases under IFRS. We believe that it is more appropriate to reflect the payments we receive under the contracts as a capacity payment in our revenues instead of as finance lease income and a decrease in finance lease receivables.
•Revenues from the Required Divestitures as they do not reflect ongoing business performance.
Adjusted Fuel and Purchased Power
Adjusted Fuel and Purchased Power is fuel and purchased power (the most directly comparable IFRS measure) adjusted to exclude fuel and purchased power from the Required Divestitures as it does not reflect ongoing business performance.
Adjusted OM&A
Adjusted OM&A is OM&A (the most directly comparable IFRS measure) adjusted to exclude:
•Termination, restructuring and facility shutdown costs mainly for costs incurred as part of strategic decisions and facility shutdowns, and that do not represent ongoing business performance and are not reflective of the Company's ability to generate cash flows in the future. Termination, restructuring and facility shutdown costs mainly include termination, severance, inventory write downs and related costs.
•Legal costs arising from cost determinations made after the conclusion of arbitration proceedings that are not reflective of ongoing business performance.
•The expenses related to the Centralia community fund (Fund), which was established under the Company'’s obligations in the Energy Transition Bill related to the retirement of coal operations at Centralia, with a total commitment of US$55 million over the 2015–2026 period. With the facility reaching end of life on Dec. 31, 2025, and all commercial operations now ceased, expenditures associated with the Fund in 2026 no longer relate to a revenue-generating facility and are not reflective of ongoing business performance.
•ERP integration costs representing planning, design and implementation costs of upgrades to the existing ERP system as they represent project costs that do not occur on a regular basis, and therefore do not reflect ongoing business performance.
•Acquisition-related transaction and restructuring costs, mainly comprising severance, legal and consultant fees as these do not reflect ongoing business performance.
•OM&A from the Required Divestitures as it does not reflect ongoing business performance.
Adjusted Net Other Operating Income
Adjusted Net Other Operating Income is net other operating income (the most directly comparable IFRS measure) adjusted to exclude:
•Insurance recoveries related to the Kent Hills replacement costs of the tower collapse as these relate to investing activities and are not reflective of ongoing business performance; and
•Legal settlement recoveries related to investing activities and not reflective of operating performance.
Additional Adjustments
Adjustments to Earnings (Loss) in Addition to Interest, Taxes, Depreciation and Amortization
•Fair value change in contingent consideration payable is not included as it is not reflective of ongoing business performance.
•Asset impairment charges and reversals are not included as these are accounting adjustments that impact depreciation and amortization and do not reflect ongoing business performance.
•Any gains or losses on asset sales or foreign exchange gains or losses are not included as these are not part of operating income.
Adjustments for Equity-Accounted Investments
During the fourth quarter of 2020, we acquired a 49 per cent interest in the Skookumchuck wind facility, which is treated as an equity investment under IFRS and our proportionate share of the net earnings is reflected as equity income on the statement of earnings under IFRS. As this investment is part of our regular power-generating operations, we have included our proportionate share of Adjusted EBITDA for the Skookumchuck wind facility in our total Adjusted EBITDA. In addition, in the Wind and Solar adjusted results, we have included our proportionate share of revenues and expenses to reflect the full operational results of this investment. We have not included Adjusted EBITDA of other equity-accounted investments in our total Adjusted EBITDA as it does not represent our regular power-generating operations.
Adjusted Earnings (Loss) before Income Taxes
Adjusted Earnings (Loss) before Income Taxes represents segmented earnings (loss) adjusted for certain items that we believe do not reflect ongoing business performance and is an important metric for evaluating performance trends in each segment.
For details of the adjustments made to earnings (loss) before income taxes (the most directly comparable IFRS measure) to calculate Adjusted Earnings (Loss) before Income Taxes, refer to the "Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment" section of this MD&A.
Adjusted Net Earnings (Loss) Attributable to Common Shareholders
Adjusted Net Earnings (Loss) Attributable to Common Shareholders represents net earnings (loss) attributable to common shareholders adjusted for specific reclassifications and adjustments and their tax impact, and is an important metric for evaluating performance. For details of the reclassifications and adjustments made to net earnings (loss) attributable to common shareholders (the most directly comparable IFRS measure), please refer to the reconciliation of net earnings attributable to common shareholders to Adjusted Net Earnings attributable to common shareholders of this section of MD&A.
Adjusted Net Earnings (Loss) per Common Share Attributable to Common Shareholders
Adjusted Net Earnings (Loss) per Common Share Attributable to Common Shareholders is calculated as Adjusted Net Earnings (Loss) attributable to Common Shareholders divided by a weighted average number of common shares outstanding during the period. The measure is useful in showing the earnings per common share for our core operational results as it excludes the impact of items that do not reflect an ongoing business performance. Adjusted Net Earnings (Loss) Attributable per Common Share is a non-IFRS ratio and the most directly comparable IFRS measure is net income (loss) per common share attributable to common shareholders. Refer to the reconciliation of net earnings attributable to common shareholders to Adjusted Net Earnings Attributable to Common Shareholders of this section of MD&A.
Funds From Operations (FFO)
FFO is an important metric as it provides a proxy for cash generated from operating activities before changes in working capital and provides the ability to evaluate cash flow trends in comparison with results from prior periods. FFO is a non-IFRS measure. For a description of the adjustments made to cash flow from operating activities (the most directly comparable IFRS measure) to calculate FFO, refer to the "Reconciliation of Cash Flow from Operations to FFO and FCF" section of this MD&A.
Adjustments to Cash Flow from Operations
•FFO related to the Skookumchuck wind facility, which is treated as an equity-accounted investment under IFRS and equity income, net of distributions from joint ventures, is included in cash flow from operations under IFRS. As this investment is part of our regular power-generating operations, we have included our proportionate share of FFO.
•We adjust for legal costs related to arbitration proceedings that are not reflective of ongoing business performance.
•Payments received on finance lease receivables are reclassified to reflect cash from operations.
•We adjust for costs associated with acquisition-related transaction and restructuring costs that are not reflective of ongoing operations.
•Penalties totalling $33 million were issued by the Alberta Market Surveillance Administrator for self-reported contraventions pertaining to ancillary services provided during 2021 and 2022 at our Brazeau hydro facility. The penalties were paid during the first quarter of 2025 and have been excluded from FFO composition.
•Other adjustments include payments/receipts for production tax credits, which are reductions to tax equity debt and include distributions from equity-accounted joint ventures.
Free Cash Flow (FCF)
FCF is an important metric as it represents the amount of cash that is available to invest in growth initiatives, make scheduled principal debt repayments, repay maturing debt, pay common share dividends or repurchase common shares, and it provides the ability to compare cash flow trends with results from prior periods. Changes in working capital are excluded so that FFO and FCF are not distorted by changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and timing of receipts and payments. FCF is a non-IFRS measure. For a description of the adjustments made to cash flow from operating activities (the most directly comparable IFRS measure) to calculate FCF, refer to the "Reconciliation of Cash Flow from Operations to FFO and FCF" section of this MD&A.
Adjusted Net Debt
Adjusted Net Debt is calculated as a sum of current and non-current portions of credit facilities, long-term debt and lease liabilities, exchangeable debentures, 50 per cent of issued preferred shares and exchangeable preferred shares, less cash and cash equivalents, less the principal portion of TransAlta OCP restricted cash and fair value of hedging instruments on debt. Presenting this item from period to period provides management and investors with the ability to evaluate leverage trends more readily in comparison with prior periods’ results. The most directly
comparable IFRS measure is total credit facilities, long-term debt and lease liabilities.
Total Consolidated Net Debt
Total consolidated debt is calculated as a sum of current and non-current portions of credit facilities, long-term debt and lease liabilities, exchangeable debentures, less principal portion of TransAlta OCP restricted cash. Total Consolidated Net Debt excludes the exchangeable preferred shares as they are considered equity with dividend payments for credit purposes. Presenting this item from period to period provides management and investors with the ability to evaluate leverage trends more readily in comparison with prior periods’ results. The most directly comparable IFRS measure is total credit facilities, long-term debt and lease liabilities; for reconciliation, refer to "Financial Capital" section of this MD&A.
Net Interest Expense
Net Interest Expense is calculated as total interest expense less total interest income and non-cash items. For detailed calculation refer to the table in the "Reconciliation of Adjusted EBITDA to FFO and FCF" section of this MD&A. Net Interest Expense is a proxy for the actual cash interest paid that approximates the cash outflow in the FFO and FCF calculation. The most directly comparable IFRS measure is total interest expense.
Adjusted Gross Margin
Adjusted Gross Margin is calculated as Adjusted Revenues less Adjusted Fuel and Purchased Power and carbon compliance costs, where adjustments to revenue or fuel and purchased power were applied as stated above. The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment. The most directly comparable IFRS measure is gross margin in the condensed consolidated statement of earnings.
Non-IFRS Ratios
FFO per share, FCF per share and Adjusted Net Debt to Adjusted EBITDA are non-IFRS ratios that are presented in this MD&A. Refer to the "Reconciliation of Cash Flow from Operations to FFO and FCF" and "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.
Supplementary Financial Measures
•Available liquidity
•Cash flow from operating activities per share
•Sustaining capital expenditures
•Growth and development expenditures
•Alberta Hydro Assets ancillary services revenues (total and revenues per MWh)
•Alberta Hydro Assets revenues (total and revenues per MWh)
•Other Hydro Assets revenues
•Other Hydro revenues
•Highvale mine reclamation spend
•Centralia mine reclamation spend
•Realized foreign exchange gain (loss)
•Unrealized foreign exchange gain (loss)
•The Alberta electricity portfolio metrics
•Realized merchant power price per MWh
•Ancillary services price per MWh
•Hedged power price average per MWh
•Fuel cost per MWh
•Carbon compliance per MWh
Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment
The following table reflects Adjusted EBITDA and Adjusted Earnings (Loss) before income taxes by segment and provides reconciliation to earnings (loss) before income taxes for the three months ended March 31, 2026:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Hydro | Wind & Solar(1) | Gas | Energy
Marketing | Corporate | Energy Transition | Total | Equity- accounted investments(1) | Reclass adjustments | IFRS financials |
| Revenues | 57 | | 125 | | 348 | | 39 | | 1 | | 2 | | 572 | | (7) | | — | | 565 | |
| Reclassifications and adjustments: | | | | | | | | | | |
Unrealized mark-to-market (gain) loss | (3) | | 6 | | (18) | | (11) | | — | | — | | (26) | | — | | 26 | | — | |
| | | | | | | | | | |
| Decrease in finance lease receivable | — | | 1 | | 7 | | — | | — | | — | | 8 | | — | | (8) | | — | |
| Finance lease income | — | | 1 | | 6 | | — | | — | | — | | 7 | | — | | (7) | | — | |
| | | | | | | | | | |
| | | | | | | | | | |
Unrealized foreign exchange gain on commodity | — | | — | | (1) | | — | | — | | — | | (1) | | — | | 1 | | — | |
Adjusted Revenue | 54 | | 133 | | 342 | | 28 | | 1 | | 2 | | 560 | | (7) | | 12 | | 565 | |
| Fuel and purchased power | (4) | | (7) | | (154) | | — | | — | | — | | (165) | | — | | — | | (165) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Carbon compliance | — | | — | | (39) | | — | | — | | — | | (39) | | — | | — | | (39) | |
Adjusted Gross Margin | 50 | | 126 | | 149 | | 28 | | 1 | | 2 | | 356 | | (7) | | 12 | | 361 | |
| OM&A | (14) | | (25) | | (62) | | (11) | | (62) | | (8) | | (182) | | 1 | | — | | (181) | |
| Reclassifications and adjustments: | | | | | | | | | | |
| Termination, restructuring and facility shutdown costs | — | | — | | — | | — | | 11 | | — | | 11 | | — | | (11) | | — | |
Legal costs related to arbitration proceedings | — | | — | | — | | — | | 9 | | — | | 9 | | — | | (9) | | — | |
Centralia community fund expenses | — | | — | | — | | — | | — | | 7 | | 7 | | — | | (7) | | — | |
| | | | | | | | | | |
| ERP integration costs | — | | — | | — | | — | | 3 | | — | | 3 | | — | | (3) | | — | |
| Acquisition-related transaction and restructuring costs | — | | — | | — | | — | | 1 | | — | | 1 | | — | | (1) | | — | |
| Adjusted OM&A | (14) | | (25) | | (62) | | (11) | | (38) | | (1) | | (151) | | 1 | | (31) | | (181) | |
| Taxes, other than income taxes | (1) | | (7) | | (5) | | — | | — | | — | | (13) | | — | | — | | (13) | |
Net other operating income | — | | 13 | | 11 | | — | | — | | — | | 24 | | — | | — | | 24 | |
| Reclassifications and adjustments: | | | | | | | | | | |
| Legal settlement recoveries | — | | (12) | | — | | — | | — | | — | | (12) | | — | | 12 | | — | |
| Adjusted Net other operating income | — | | 1 | | 11 | | — | | — | | — | | 12 | | — | | 12 | | 24 | |
Adjusted EBITDA(2) | 35 | | 95 | | 93 | | 17 | | (37) | | 1 | | 204 | | | | |
| Depreciation and amortization | (9) | | (50) | | (42) | | — | | (4) | | — | | (105) | | — | | — | | (105) | |
| Equity income | — | | — | | — | | — | | (1) | | — | | (1) | | — | | 4 | | 3 | |
| Interest income | — | | — | | — | | — | | 7 | | — | | 7 | | — | | — | | 7 | |
| Interest expense | — | | — | | — | | — | | (84) | | — | | (84) | | 2 | | — | | (82) | |
Realized foreign exchange gain(3) | — | | — | | — | | — | | 9 | | — | | 9 | | — | | — | | 9 | |
Adjusted Earnings (Loss) before income taxes(2) | 26 | | 45 | | 51 | | 17 | | (110) | | 1 | | 30 | | | | |
| Reclassifications and adjustments above | 3 | | 4 | | 6 | | 11 | | (24) | | (7) | | (7) | | | | |
| Finance lease income | — | | 1 | | 6 | | — | | — | | — | | 7 | | — | | — | | 7 | |
Skookumchuk earnings reclass to Equity income(1) | — | | (4) | | — | | — | | 4 | | — | | — | | — | | — | | — | |
| | | | | | | | | | |
| Asset impairment reversals | — | | — | | — | | — | | — | | 6 | | 6 | | — | | — | | 6 | |
| Loss on sale of assets and other | — | | — | | — | | — | | (2) | | — | | (2) | | — | | — | | (2) | |
Unrealized foreign exchange loss(3) | — | | — | | — | | — | | (11) | | — | | (11) | | — | | — | | (11) | |
| | | | | | | | | | |
| Earnings (loss) before income taxes | 29 | | 46 | | 63 | | 28 | | (143) | | — | | 23 | | — | | — | | 23 | |
(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)Adjusted EBITDA, Adjusted Earnings (Loss) before income taxes are non-IFRS measures, are not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Additional IFRS Measures and Non-IFRS Measures" section of this MD&A.
(3)Realized and unrealized foreign exchange (loss) gain are supplementary financial measures. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.
The following table reflects Adjusted EBITDA and Adjusted Earnings (Loss) before income taxes by segment and provides reconciliation to earnings (loss) before income taxes for the three months ended March 31, 2025:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Hydro | Wind & Solar(1) | Gas | Energy
Marketing | Corporate | Energy Transition | Total | Equity- accounted investments(1) | Reclass adjustments | IFRS financials |
| Revenues | 86 | | 107 | | 390 | | 27 | | 1 | | 154 | | 765 | | (7) | | — | | 758 | |
| Reclassifications and adjustments: | | | | | | | | | | |
| Unrealized mark-to-market (gain) loss | (21) | | 36 | | (32) | | 1 | | — | | (1) | | (17) | | — | | 17 | | — | |
| | | | | | | | | | |
| Decrease in finance lease receivable | — | | 1 | | 7 | | — | | — | | — | | 8 | | — | | (8) | | — | |
| Finance lease income | — | | 1 | | 5 | | — | | — | | — | | 6 | | — | | (6) | | — | |
Revenues from Required Divestitures | — | | — | | (4) | | — | | — | | — | | (4) | | — | | 4 | | — | |
| | | | | | | | | | |
| | | | | | | | | | |
Adjusted Revenues | 65 | | 145 | | 366 | | 28 | | 1 | | 153 | | 758 | | (7) | | 7 | | 758 | |
| Fuel and purchased power | (4) | | (10) | | (163) | | — | | (2) | | (98) | | (277) | | — | | — | | (277) | |
| Reclassifications and adjustments: | | | | | | | | | | |
Fuel and purchased power related to Required Divestitures | — | | — | | (2) | | — | | — | | — | | (2) | | — | | (2) | | — | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Adjusted Fuel and Purchased Power | (4) | | (10) | | (161) | | — | | (2) | | (98) | | (275) | | — | | (2) | | (277) | |
| Carbon compliance | — | | (1) | | (49) | | — | | 1 | | — | | (49) | | — | | — | | (49) | |
Gross margin | 61 | | 134 | | 156 | | 28 | | — | | 55 | | 434 | | (7) | | 5 | | 432 | |
| OM&A | (13) | | (29) | | (59) | | (7) | | (49) | | (17) | | (174) | | 1 | | — | | (173) | |
| Reclassifications and adjustments: | | | | | | | | | | |
OM&A related to Planned Divestitures | — | | — | | 2 | | — | | — | | — | | 2 | | — | | (2) | | — | |
ERP integration costs | — | | — | | — | | — | | 4 | | — | | 4 | | — | | (4) | | — | |
Acquisition-related transaction and restructuring costs | — | | — | | — | | — | | 4 | | — | | 4 | | — | | (4) | | — | |
| Adjusted OM&A | (13) | | (29) | | (57) | | (7) | | (41) | | (17) | | (164) | | 1 | | (10) | | (173) | |
| Taxes, other than income taxes | (1) | | (5) | | (5) | | — | | — | | (1) | | (12) | | — | | — | | (12) | |
| Net other operating income | — | | 4 | | 10 | | — | | — | | — | | 14 | | — | | — | | 14 | |
| Reclassifications and adjustments: | | | | | | | | | | |
| | | | | | | | | | |
Insurance recovery | — | | (2) | | — | | — | | — | | — | | (2) | | — | | 2 | | — | |
Adjusted Net Other Operating Income | — | | 2 | | 10 | | — | | — | | — | | 12 | | — | | 2 | | 14 | |
Adjusted EBITDA(2) | 47 | | 102 | | 104 | | 21 | | (41) | | 37 | | 270 | | | | |
| Depreciation and amortization | (9) | | (53) | | (64) | | (2) | | (5) | | (15) | | (148) | | 2 | | — | | (146) | |
| Equity income | — | | — | | — | | — | | (1) | | — | | (1) | | — | | 3 | | 2 | |
| Interest income | — | | — | | — | | — | | 5 | | — | | 5 | | — | | — | | 5 | |
| Interest expense | — | | — | | — | | — | | (94) | | — | | (94) | | 1 | | — | | (93) | |
Realized foreign exchange loss(3) | — | | — | | — | | — | | (4) | | — | | (4) | | — | | — | | (4) | |
Adjusted Earnings (Loss) before income taxes(2) | 38 | | 49 | | 40 | | 19 | | (140) | | 22 | | 28 | | | | |
| Reclassifications and adjustments above | 21 | | (36) | | 20 | | (1) | | (8) | | 1 | | (3) | | | | |
| Finance lease income | — | | 1 | | 5 | | — | | — | | — | | 6 | | — | | — | | 6 | |
Skookumchuk earnings reclass to equity income(1) | — | | (3) | | — | | — | | 3 | | — | | — | | — | | — | | — | |
Fair value change in contingent consideration payable | — | | — | | 34 | | — | | — | | — | | 34 | | — | | — | | 34 | |
Asset impairment (charges) reversals | — | | — | | (34) | | — | | (5) | | 24 | | (15) | | — | | — | | (15) | |
| | | | | | | | | | |
Loss on sale of assets and other | — | | — | | — | | — | | (1) | | — | | (1) | | — | | — | | (1) | |
| Earnings (loss) before income taxes | 59 | | 11 | | 65 | | 18 | | (151) | | 47 | | 49 | | — | | — | | 49 | |
(1)The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)Adjusted EBITDA, Adjusted Earnings (Loss) before income taxes are non-IFRS measures, are not defined, have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.
(3)Realized and unrealized foreign exchange (loss) gain are supplementary financial measures. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.
Reconciliation of Net Earnings Attributable to Common Shareholders to Adjusted Net Earnings Attributable to Common Shareholders
The following table reflects reconciliation of net earnings attributable to common shareholders to Adjusted Net Earnings Attributable to Common Shareholders for the three months ended March 31, 2026 and 2025:
| | | | | | | | | | | |
| | | |
| 3 months ended March 31 | | |
| (in millions of Canadian dollars except where noted) | 2026 | 2025 | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Net earnings attributable to common shareholders | 13 | | 46 | | | | |
| Adjustments and reclassifications (pre-tax): | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Adjustments and reclassifications to revenues | (12) | | (7) | | | | |
| | | | | |
| | | | | |
Adjustments and reclassifications to fuel and purchased power | — | | 2 | | | | |
| | | | | |
| | | | | |
| Adjustments and reclassifications to OM&A | 31 | | 10 | | | | |
| | | | | |
Adjustments and reclassifications to net other operating income | (12) | | (2) | | | | |
| Fair value change in contingent consideration payable (gain) | — | | (34) | | | | |
Finance lease income | (7) | | (6) | | | | |
| Asset impairment (reversals) charges | (6) | | 15 | | | | |
Loss on sale of assets and other | 2 | | 1 | | | | |
Unrealized foreign exchange loss(1) | 11 | | — | | | | |
Calculated tax expense on adjustments and reclassifications(2) | (2) | | 5 | | | | |
Adjusted Net Earnings Attributable to Common Shareholders(3) | 18 | | 30 | | | | |
Weighted average number of common shares outstanding in the period (in millions) | 297 | | 298 | | | | |
Net earnings per common share attributable to common shareholders | 0.04 | | 0.15 | | | | |
Adjustments and reclassifications (net of tax) | 0.02 | | (0.05) | | | | |
Adjusted Net Earnings per Common Share Attributable to Common Shareholders(3) | 0.06 | | 0.10 | | | | |
| | | | | |
(1)Unrealized foreign exchange loss is a supplementary financial measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.
(2)Represents a theoretical tax calculated by applying the Company's consolidated effective tax rate of 23.3 per cent for the three months ended March 31, 2026 (three months ended March 31, 2025 — 23.3 per cent). The amount does not take into account the impact of different tax jurisdictions the Company's operations are domiciled and does not include the impact of deferred taxes.
(3)Adjusted Net Earnings Attributable to Common Shareholders and Adjusted Net Earnings per Common Share attributable to Common Shareholders are non-IFRS measures, are not defined, have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. The most directly comparable IFRS measures are net earnings attributable to common shareholders and net earnings per share attributable to common shareholders, basic and diluted. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.
Reconciliation of Cash Flow from Operations to FFO and FCF
The table below reconciles our cash flow from operating activities to our FFO and FCF:
| | | | | | | | | | | |
| | | |
| 3 months ended March 31 | | |
| (in millions of Canadian dollars except where noted) | 2026 | 2025 | | | |
Cash flow from operating activities(1) | 123 | | 7 | | | | |
| Change in non-cash operating working capital balances | (19) | | 117 | | | | |
| Cash flow from operations before changes in working capital | 104 | | 124 | | | | |
| Adjustments | | | | | |
Share of adjusted FFO from joint venture(1) | 3 | | 2 | | | | |
| Decrease in finance lease receivable | 8 | | 8 | | | | |
Brazeau penalties payment | — | | 33 | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Other(2) | 22 | | 12 | | | | |
FFO(3) | 137 | | 179 | | | | |
| Deduct: | | | | | |
Sustaining capital expenditures(1) | (21) | | (23) | | | | |
| | | | | |
| Dividends paid on preferred shares | (13) | | (13) | | | | |
| Distributions paid to subsidiaries’ non-controlling interests | (1) | | — | | | | |
| | | | | |
Other(3) | — | | (4) | | | | |
FCF(4) | 102 | | 139 | | | | |
| Weighted average number of common shares outstanding in the period | 297 | | 298 | | | | |
| Cash flow from operating activities per share | 0.41 | | 0.02 | | | | |
FFO per share(4) | 0.46 | | 0.60 | | | | |
FCF per share(4) | 0.34 | | 0.47 | | | | |
(1)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture. Supplementary financial measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.
(2)Other consists of production tax credits, which is a reduction to tax equity debt, distributions from an equity-accounted joint venture and other adjustments to OM&A that are not reflective of ongoing operations.
(3)Other consists of principal payments on lease liabilities and unsecured loan advances by the Company's subsidiary, Kent Hills Wind LP to its 17 per cent partner.
(4)These items are non-IFRS measures, which are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.
Reconciliation of Adjusted EBITDA to FFO and FCF
The table below provides a reconciliation of our Adjusted EBITDA to our FFO and FCF:
| | | | | | | | | | | |
| | | |
| | | |
| 3 months ended March 31 | 2026 | 2025 | | | |
Adjusted EBITDA(1)(2) | 204 | | 270 | | | | |
| Provisions | 7 | | 8 | | | | |
Net Interest Expense(3) | (61) | | (72) | | | | |
Current income tax expense | (12) | | (13) | | | | |
Realized foreign exchange gain (loss)(4) | 15 | | (2) | | | | |
Decommissioning and restoration costs settled | (6) | | (9) | | | | |
Other non-cash items(5) | (10) | | (3) | | | | |
FFO(2)(6) | 137 | | 179 | | | | |
| Deduct: | | | | | |
Sustaining capital(2)(4) | (21) | | (23) | | | | |
| | | | | |
| Dividends paid on preferred shares | (13) | | (13) | | | | |
| Distributions paid to subsidiaries’ non-controlling interests | (1) | | — | | | | |
| | | | | |
Other(7) | — | | (4) | | | | |
FCF(2)(6) | 102 | | 139 | | | | |
(1)Adjusted EBITDA is defined in the "Non-IFRS and Supplementary Financial Measures" section of this MD&A and reconciled to earnings before income taxes above.
(2)Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture.
(3)Net Interest Expense is a non-IFRS measure, not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Net Interest Expense includes interest expense less interest income and excludes non-cash items like financing amortization and accretion. Net Interest Expense reconciliation is available in "Financial Capital" section of this MD&A
(4)Supplementary financial measure. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A for more details.
(5)Other non-cash items primarily consist of changes in deferred payments, contract assets and liabilities, onerous contracts and long-term incentive accruals.
(6)These items are non-IFRS measures, are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. FFO and FCF are defined in the "Non-IFRS and Supplementary Financial Measures" section of this MD&A and reconciled to cash flow from operating activities above.
(7)Other consists of principal payments on lease liabilities and unsecured loan advances by the Company's subsidiary, Kent Hills Wind LP to its 17 per cent partner.
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
| | | | | | | | | | | | |
| (in millions of Canadian dollars except where noted) | | | | |
As at | March 31, 2026 | | Dec. 31, 2025 | |
Credit facilities, long-term debt and lease liabilities(1) | 3,706 | | | 3,593 | | |
Exchangeable debentures | 350 | | | 350 | | |
Less: Cash and cash equivalents | (274) | | | (205) | | |
Add: Bank overdraft | 7 | | | — | | |
Add: 50 per cent of issued preferred shares and exchangeable preferred shares(2) | 671 | | | 671 | | |
Other(3) | (4) | | | (13) | | |
Adjusted Net Debt(4) | 4,456 | | | 4,396 | | |
Adjusted EBITDA(5) | 1,038 | | | 1,104 | | |
Adjusted Net Debt to Adjusted EBITDA (times) | 4.3 | | | 4.0 | | |
(1)Consists of current and non-current portions of long-term debt, which includes lease liabilities and tax equity financing.
(2)Exchangeable preferred shares are considered equity with dividend payments for credit-rating purposes. For accounting purposes, they are accounted for as debt with interest expense in the condensed consolidated financial statements. For purposes of this ratio, we consider 50 per cent of issued preferred shares, including exchangeable preferred shares, as debt.
(3)Includes principal portion of TransAlta OCP nil restricted cash as at March 31, 2026 (Dec. 31, 2025 - $17 million) and fair value of hedging instruments on debt (included in risk management assets and/or liabilities on the Condensed Consolidated Statements of Financial Position).
(4)The tax equity financing for the Skookumchuck wind facility, an equity-accounted joint venture, is not represented in this amount. Adjusted Net Debt is a non-IFRS measure, is not defined and has no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Presenting this item from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the "Non-IFRS and Supplementary Financial Measures" section of this MD&A.
(5)Last four quarters.
The Company's capital is managed using a net debt position. We use the Adjusted Net Debt to Adjusted EBITDA ratio as a measurement of financial leverage and to assess our ability to service debt. Our long-term target for Adjusted Net Debt to Adjusted EBITDA is 3.0 to 4.0 times.
Our Adjusted Net Debt to Adjusted EBITDA ratio at March 31, 2026 was higher compared to Dec. 31, 2025, due to lower trailing twelve months Adjusted EBITDA and higher debt to finance Far North acquisition as at March 31, 2026, as compared to Dec. 31, 2025.
Refer to Financial Capital section of this MD&A for further discussion on liquidity and capital management.
Material Accounting Policies, Accounting Changes and Critical Accounting Estimates
Material Accounting Policies and Accounting Changes
Our material accounting policies are described in Note 2 of the consolidated financial statements for the year ended Dec. 31, 2025.
In accordance with the amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments, effective Jan. 1, 2026, the Company has prospectively designated certain pre-existing VPPAs within the Wind and Solar segment as held for hedging and has applied hedge accounting. As a result, the effective portion of changes in the fair value of these hedging derivatives, arising on or after Jan. 1, 2026, will be recognised in OCI while any ineffective portion will be recognized in net earnings. The transitional provisions did not permit retrospective designation.
For a description of current and future accounting changes impacting our business, refer to Note 2 of the condensed consolidated financial statements the three months ended March 31, 2026.
Critical Accounting Judgments and Estimates
The preparation of the Condensed Consolidated Financial Statements in accordance with IFRS requires management to apply judgment and to develop estimates and assumptions based on the conditions and information available as of the reporting date. These judgments, estimates, and assumptions influence the reported amounts of assets, liabilities, revenue, and expenses, and actual results may differ from those estimates.
Management reviews these judgments and estimates on a continuous basis. Any revisions are recognized in the period in which they are identified and in any subsequent periods impacted by the change. Refer to Note 2 of the consolidated financial statements for the year ended Dec. 31, 2025 for a description of our significant accounting judgments and key sources of estimation uncertainty.
Governance and Risk Management
Our business activities expose us to a variety of risks and opportunities including, but not limited to, regulatory changes, rapidly changing market dynamics and increased volatility in our key commodity markets. Our goal is to manage these risks and opportunities so that we are in a position to develop our business and achieve our goals while remaining reasonably protected from an unacceptable level of risk or financial exposure. We use a multi-level risk management oversight structure to manage the risks and opportunities arising from our business activities, the markets in which we operate and the political environments and structures with which we interact.
Please refer to the "Risk Management" section of our 2025 Annual MD&A and Note 11 of our unaudited interim condensed consolidated financial statements the three months ended March 31, 2026 for details on our risks and how we manage them. Our risk management profile and practices have not changed materially from Dec. 31, 2025.
Regulatory Updates
Refer to the Significant and Subsequent Events and Risk Management discussions in our 2025 Annual MD&A for further details on the corporation's assessment and management of policy and regulatory risks that supplement the recent developments as discussed below:
Canada
Federal
The current Liberal government in Canada was elected on April 28, 2025, as a minority government. Through by-election results and floor crossings, the Liberal party now holds a majority of the seats in the House of Commons.
On Nov. 27, 2025, the Canadian and Alberta governments signed a memorandum of understanding that among other items, agreed to place the Canadian Electricity Regulations in abeyance, upon completion of a new carbon pricing agreement administered through Alberta's TIER program. The governments did not achieve the April 1, 2026 goal for completion of this work; however, have stated they remain committed. TransAlta continues to monitor these and other policy developments related to our business, including but not limited to the release of industrial strategies related to electricity and AI, Investment Tax Credits, and funding for net-zero technologies.
Alberta
On March 12, 2026, the Minister of Affordability and Utilities approved the AESO's Restructured Energy Market (REM) ISO rules. This action provides the details for the finalized REM design. The AESO also updated the implementation schedule for REM, with implementation now expected to occur in early 2028.
The AESO and Government of Alberta continue to develop the Phase 2 policy framework for incremental data center integration in the province. In 2025, the AESO released the Phase 1 design, through the allocation of 1,200 MW of large load hosting capacity with in-service dates in 2027 and 2028. The Phase 2 process will apply to data centre projects that have in-service dates in 2028 and beyond. Finalization of the Phase II design is expected to occur in 2026.
United States
On March 13, 2026, the U.S. Department of Energy (U.S. DOE) issued an amendment to the Dec. 16, 2025 202(c) order for the Centralia facility, amending the identified Balancing Authority and Reliability Coordinator. On March 16, 2026, the U.S. DOE issued a second 90-day order for the period of March 17 to June 14, 2026. At the state level, on March 11, 2026, Washington Governor Ferguson signed HB 2367 into law, which ended exemptions at the Centralia facility related to GHG emission performance standards and limitations after Dec. 31, 2025.
On April 30, 2026, TransAlta filed a petition for cost recovery for the first 90-day 202(c) order. The Company continues to work with the state and federal governments in relation to the order and filing.
At the federal level, TransAlta continues to monitor policies and agency developments related to our business, including but not limited to: wind, solar and battery tax credits; permit issuance for land-based wind and solar projects; electricity infrastructure permitting reform legislation; large load integration; and regulatory reforms for thermal power generation.
Australia
In 2025, the federal and Western Australian governments both held elections, resulting in majority, renewed terms for both incumbent governments. TransAlta continues to monitor policy developments in Australia.
Disclosure Controls and Procedures
Management is responsible for establishing and maintaining adequate internal control over financial reporting (ICFR) and disclosure controls and procedures (DC&P). During the three months ended March 31, 2026, the majority of our workforce supporting and executing our ICFR and DC&P continue to work on a hybrid basis. The Company has implemented appropriate controls and oversight for both in-office and remote work. There has been minimal impact to the design and performance of our internal controls.
ICFR is a framework designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the condensed consolidated financial statements for external purposes in accordance with IFRS. Management has used the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) to assess the effectiveness of the Company’s ICFR.
DC&P refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under securities legislation is recorded, processed, summarized and reported within the time frame specified in applicable securities legislation. DC&P include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under applicable securities legislation is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure.
Together, the ICFR and DC&P frameworks provide internal control over financial reporting and disclosure. In designing and evaluating our ICFR and DC&P, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and as such may not prevent or detect all misstatements and management is required to apply its judgment in evaluating and implementing possible controls and procedures. Further, the effectiveness of ICFR is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may change.
In Jan. 2026, the Company implemented an upgrade to our Enterprise Resource Planning (ERP) system across the organization resulting in the modification to a number of its internal controls. No other changes to the internal control over financial reporting occurred during the period ended March 31, 2026 that materially affected, or reasonably likely to materially affect, the Company's internal control over financial reporting. Management will continue to evaluate the Company's disclosure controls, procedures and internal control over financial reporting to make modifications as deemed necessary.
In accordance with the provisions of National Instrument (NI) 52-109 and consistent with U.S. Securities and Exchange Commission guidance, the scope of the evaluation did not include internal controls over financial reporting of Far North, which the Company acquired on Feb. 2, 2026. Far North was excluded from management's evaluation of the effectiveness of the Company's internal control over financial reporting as at March 31, 2026, due to the proximity of the acquisition to the end of the reporting period. Further details related to the acquisition are disclosed in Note 3 of the Condensed Consolidated Financial statements for the three months ended March 31, 2026. Far North's total and net assets represented approximately one and seven per cent of the Company's total and net assets, respectively, as at March 31, 2026 and one and eight per cent of the Company's revenues and net earnings, respectively, for the three months ended March 31, 2026.
Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our ICFR and DC&P as of the end of the period covered by this MD&A. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as at March 31, 2026, the end of the period covered by this MD&A, our ICFR and DC&P were effective.
