Earnings release
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For immediate release October 29, 2025 Capital Power reports strong third quarter 2025 results, advancing flexible generation1 growth and contracting success CFO Sandra Haskins announces retirement after 23 years of leadership and financial excellence EDMONTON, Alberta – October 29, 2025 – Capital Power Corporation (TSX: CPX) today released financial results for the quarter ended September 30, 2025. Strategic highlights • Executed a new long-term contract for Midland Cogeneration Venture (MCV)2 through to 2040, with improved economic terms, adding 10 years of incremental contracted revenue • Commissioned 170 MW of battery storage in Ontario contracted through to 2047 • MCV entered into a term sheet with a leading colocation data centre developer for the potential development of a 250 MW data centre adjacent to the facility. The proposed project is subject to due diligence, execution of definitive agreements, and the requisite regulatory approvals Financial highlights • Generated AFFO of $369 million and net cash flows from operating activities of $404 million • Generated adjusted EBITDA of $477 million and net income of $153 million • Negotiated a two-year, $600 million revolving credit facility maturing in 2027 On October 29, 2025, Sandra Haskins, SVP Finance & CFO announced her plans to retire from her role on December 31, 2025 after a 23-year tenure. Sandra has played a pivotal role in shaping the strategic direction and successful growth of Capital Power. Scott Manson, Chief Accounting Officer, & Treasurer will transition to Interim SVP Finance & CFO. A search for a new SVP Finance & CFO is underway, and a successor will be announced in due course. Sandra will support a smooth leadership transition by remaining in an advisory capacity until the end of Q1 2026. “Our third quarter results reflect the continued execution of our strategy to strengthen our U.S. platform and expand our contracted cash flows,” said Avik Dey, President and Chief Executive Officer. “The MCV contract is a prime example of the critical role natural gas will continue to play in meeting the needs of grids. With scale, diversification, and unmatched operational and commercial excellence and a surging demand for reliable power, we are well positioned to deliver sustained value for shareholders.” “Capital Power delivered multiple projects through to 2040 and beyond in the third quarter, demonstrating our strong execution on high-value growth opportunities and financial discipline. Our established track record of securing and delivering long-term partnership contracts enhances cash flow stability, which we only expect to continue. Additionally, our two Ontario battery storage assets further strengthens our balance sheet and the new $600 million credit facility enhances our liquidity,” said Sandra Haskins, Senior Vice President, Finance and Chief Financial Officer. "These actions reinforce our commitment to stable, contracted cash flows and long-term value creation for shareholders.” “On behalf of the entire executive team and Board of Directors, I also want to express our gratitude to Sandra Haskins for her exceptional service and dedication over the past 23 years," continued Avik Dey. "Sandra has been instrumental in driving our company forward, building a strong culture, and delivering outstanding results. While we will greatly miss her leadership, we wish Sandra only the best in this well-deserved next chapter ahead." 1 References to flexible generation are defined as natural gas generation assets and energy storage 2 Jointly owned with 50% working interest with Manulife Investment Management Capital Power Corporation 10423 – 101 Street NW Suite 1200 Edmonton, AB T5H 0E9
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Reaffirming 2025 Guidance Capital Power is reaffirming revised guidance ranges across Adjusted EBITDA, AFFO and Sustaining Capital for 2025 despite updates to planned outages and delays on Alberta projects. To ensure portfolio reliability, and best position the assets to capitalize on stronger market fundamentals beyond 2026, our updated Alberta maintenance schedule is planned as follows: • Genesee 3 (G3) unit is advancing its planned outage to Q4 2025. This strategic decision ensures that G3 is fully available in 2026 to provide system support and mitigate the impact of concurrent outages elsewhere in the fleet. • The recently commissioned Genesee 1 (G1) and Genesee 2 (G2) units are scheduled for incremental maintenance that require us to extend the previously scheduled outages in Q2 2026 to balance reliability and growing dispatch requirements heading into 2027, which is typical for newly installed turbines. • Shepard Energy Centre, Joffre Cogeneration, and Clover Bar Energy Centre have routine planned outages scheduled in 2026. • In 2026, we expect approximately a 40% increase in outage days for our Canada flexible generation portfolio. As part of its ongoing Alberta fleet optimization, Capital Power remains focused on dispatching as much of its existing capacity at the Genesee site as possible. Further to that, incremental performance testing of Capital Power’s technical solution for generation above the Most Single Severe Contingency limit (MSSC) will continue including additional tuning, operational refinement, and extended runtime evaluations. Furthermore, Capital Power will also continue its proactive engagement with the AESO pursuant to the Phase 2 Large Load Allocation process to potentially unlock as much as the full nameplate capacity of the G1 and G2 units. Capital Power will update on the timing and quantum of incremental capacity above the MSSC that can be dispatched from the Genesee site once it is able to do so. 2025 Annual Guidance Execution of major turnarounds Sustaining capital expenditures of $215 million to $245 million3 $134 million1,2 Generate financial stability and strength AFFO3,4 of $950 million to $1,100 million $822 million1 Adjusted EBITDA3,4 of $1,500 million to $1,650 million $1,166 million1 Priority 2025 targets Status at September 30, 2025 1 For the nine months ended September 30, 2025. 2 Includes our share of equity-accounted investments sustaining capital expenditures of $49 million net of partner contributions of $8 million. 3 The Company provided updated guidance for 2025 based on the Company’s year-to-date results, expectations for the remainder of the year and the expected results from the acquisition of Hummel Station, LLC and Rolling Hills Generating, LLC for the periods subsequent to the close of the transaction on June 9, 2025. 4 AFFO and adjusted EBITDA are non-GAAP financial measures. See Non-GAAP Financial Measures and Ratios. Operational and Financial Highlights1 ($ millions, except per share amounts) Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Electricity generation (Gigawatt hours) 2 13,374 11,001 31,952 28,413 Generation facility availability 3 93 % 94 % 92 % 94 % Revenues and other income 1,213 1,030 2,642 2,923 Adjusted EBITDA 4 477 401 1,166 1,013 Net income 153 178 172 459 Net income attributable to shareholders of the Company 154 179 173 459 Basic earnings per share ($) 0.94 1.32 1.02 3.39 Diluted earnings per share ($) 5 0.94 1.32 1.01 3.38 Net cash flows from operating activities 404 236 757 706 Adjusted funds from operations 4 369 315 822 642 Adjusted funds from operations per share ($) 4 2.37 2.42 5.53 5.00 Purchase of property, plant and equipment and other assets, net 147 231 576 675 Dividends per common share, declared ($) 0.6910 0.6519 1.9948 1.8819 2
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1 The operational and financial highlights in this press release should be read in conjunction with the Management’s Discussion and Analysis and the unaudited condensed interim financial statements for the nine months ended September 30, 2025. 2 Gigawatt hours (GWh) of electricity generation reflects the Company’s share of facility output. 3 Facility availability represents the percentage of time in the period that the facility was available to generate power regardless of whether it was running and therefore is reduced by planned and unplanned outages. 4 The consolidated financial highlights, except for adjusted EBITDA, AFFO and AFFO per share were prepared in accordance with GAAP. See Non-GAAP Financial Measures and Ratios. 5 Diluted earnings per share was calculated after giving effect to outstanding share purchase options. Significant Events York Energy and Goreway Battery Energy Storage Systems commissioned and contracted to 2047 On September 22, 2025, 120 MW York BESS and 50 MW Goreway BESS projects successfully achieved commercial operations. A leader of Ontario’s BESS development, Capital Power delivered both projects on time, under budget and with an excellent safety record. The projects are contracted until 2047 with the IESO (part of their Expedited Long-Term 1 RFP process) and will add approximately $35 million in annual adjusted EBITDA over the contract term. These facilities enhance our portfolio of flexible generation sources that provide grid stability, support the integration of renewable resources, and meet the province’s unprecedented, growing demand for electricity. MCV new contract with Consumers Energy to 2040 In September 2025, Capital Power successfully executed a new long-term contract with improved economic terms for MCV with Consumers Energy, extending to 2040 and providing 10 years of incremental contracted revenue, subject to customary regulatory approvals. MCV is the largest natural gas-fired combined electric and steam generation facility in the United States, and a cornerstone of reliable power generation in Michigan. MCV will receive payments for 1,240 MW, approximately 75% of the facility's capacity starting in June 2030 under the new power purchase agreement (PPA), creating long-term revenue stability throughout the contract term. The contract is expected to generate a gross increase in full year adjusted EBITDA for the facility of approximately $140 million (US$100 million)1 annually representing an 85% increase over current contract pricing. 1 Jointly owned with 50% working interest with Manulife Investment Management. MCV data center In September 2025, MCV1 entered into a term sheet with a leading colocation data centre developer for the potential development of a data centre adjacent to the facility. Subject to due diligence, execution of formal agreements, and the requisite regulatory approvals, the proposed project would see 250 MW of power sold under a PPA agreement of up to 15- years. 1 Jointly owned with 50% working interest with Manulife Investment Management. Virtual power purchase agreement cancellation As a result of delayed commissioning on Halkirk 2 Wind, Saputo Inc. (Saputo) elected to terminate the VPPA with Capital Power, resulting in a $5 million penalty paid in the third quarter of 2025. The termination also resulted in an unrealized mark to market loss of $8 million upon unwinding of the VPPA in the third quarter of 2025. Despite the contract with Saputo representing 45% of plant output, Capital Power expects the financial impact to be minimal due to forecasted merchant pricing exceeding the Saputo VPPA pricing. $1.5 billion credit facility and $600 million revolving credit facility On June 30, 2025, the Company terminated its $300 million unsecured club credit facility, increased the capacity of its committed credit facility from $700 million to $1.5 billion, and extended the term from 2029 to 2030. On August 8, 2025, the Company entered into a 2-year revolving credit agreement with a total commitment of $600 million, maturing in 2027. The funds can be drawn in Canadian or US dollars. Interest is floating and is based on the type of draw, plus margin. Analyst conference call and webcast Capital Power will be hosting a conference call and live webcast with analysts on October 29, 2025 at 9:00 am (MT) to discuss the third quarter financial results. The webcast can be accessed at: https://edge.media-server.com/mmc/p/ pfzzokqy/. Conference call details will be sent directly to analysts. An archive of the webcast will be available on the Company’s website at www.capitalpower.com following the conclusion of the analyst conference call. 3
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Non-GAAP Financial Measures and Ratios Capital Power uses (i) earnings before, income tax expense, depreciation and amortization, net finance expense, foreign exchange gains or losses, gains or losses on disposals and other transactions, unrealized changes in fair value of commodity derivatives and emission credits, other expenses from our joint venture interests, acquisition and integration costs, and other items that are not reflective of the Company’s facility operating performance (adjusted EBITDA), and (ii) AFFO as specified financial measures. Adjusted EBITDA and AFFO are both non-GAAP financial measures. Capital Power also uses AFFO per share as a specified performance measure. This measure is a non-GAAP ratio determined by applying AFFO to the weighted average number of common shares used in the calculation of basic and diluted earnings per share. These terms are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and, therefore, are unlikely to be comparable to similar measures used by other enterprises. These measures should not be considered alternatives to net income, net income attributable to shareholders of Capital Power, net cash flows from operating activities or other measures of financial performance calculated in accordance with GAAP. Rather, these measures are provided to complement GAAP measures in the analysis of our results of operations from management’s perspective. Adjusted EBITDA During the second quarter of 2025, the Company amended the composition of adjusted EBITDA to exclude acquisition and integration costs, as these costs are not reflective of facility operating performance. The Company has applied this change to all historical amounts reported. Capital Power uses adjusted EBITDA to measure the operating performance of facilities and categories of facilities from period to period. Management believes that a measure of facility operating performance is more meaningful if results not related to facility operations are excluded from the adjusted EBITDA measure such as impairments, foreign exchange gains or losses, gains or losses on disposals and other transactions, unrealized changes in fair value of commodity derivatives and emission credits, acquisition and integration costs, and other items that are not reflective of the long-term performance of the Company’s underlying operations. A reconciliation of adjusted EBITDA to net income is as follows: ($ millions) Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Net income 153 178 172 459 Depreciation and amortization 157 124 421 366 Unrealized changes in fair value of commodity derivatives and emission credits (13) (78) 176 (286) Other non-recurring items – – 4 4 Acquisition and integration costs 4 – 41 10 Impairment – 27 – 27 Foreign exchange loss (gain) 7 (5) (16) 9 Net finance expense 92 65 217 160 Loss on disposals and other transactions 5 5 12 20 Other items1 37 32 110 91 Income tax expense 35 53 29 153 Adjusted EBITDA 477 401 1,166 1,013 1 Includes finance expense, depreciation expense and unrealized changes in fair value of derivative instruments from equity-accounted investments. 4
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AFFO and AFFO per share AFFO and AFFO per share are measures of our ability to generate cash from our operating activities to fund growth capital expenditures, repayment of debt, and payment of common share dividends. During the second quarter of 2025, the Company amended the composition of AFFO and AFFO per share to exclude acquisition and integration costs, as these costs are not reflective of cash generated from facility operations. The Company has applied this change to all historical amounts reported. AFFO represents net cash flows from operating activities adjusted to: • remove timing impacts of cash receipts and payments that may impact period-to-period comparability which include deductions for net finance expense and current income tax expense, the removal of deductions for interest paid and income taxes paid and removing changes in operating working capital, • include our share of AFFO of joint venture interests and exclude distributions received from our joint venture interests which are calculated after the effect of non-operating activity joint venture debt payments, • include cash from off-coal compensation received annually through to 2030, • remove the tax equity financing project investors’ shares of AFFO associated with assets under tax equity financing structures so only Capital Power’s share is reflected in the overall metric, • deduct sustaining capital expenditures and preferred share dividends, • exclude the impact of fair value changes in certain unsettled derivative financial instruments that are charged or credited to our bank margin account held with a specific exchange counterparty, • exclude acquisition and integration costs, and • exclude other typically non-recurring items affecting cash flows from operating activities that are not reflective of the long-term performance of the Company’s underlying business. A reconciliation of net cash flows from operating activities to AFFO is as follows: ($ millions) Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Net cash flows from operating activities per condensed interim consolidated statements of cash flows 404 236 757 706 Add (deduct): Interest paid 87 73 202 132 Change in fair value of derivatives reflected as cash settlement — 2 7 (17) Realized gain on settlement of interest rate derivatives — (28) (17) (42) Distributions received from joint ventures (9) (13) (47) (24) Miscellaneous financing charges paid 1 4 1 (2) (6) Income taxes (recovered) paid (11) (3) (14) 17 Change in non-cash operating working capital (77) 63 (23) (7) (7) 95 105 53 Net finance expense 2 (81) (56) (192) (136) Current income tax recovery (expense) 3 16 (7) 72 (29) Sustaining capital expenditures 4 (44) (35) (85) (96) Preferred share dividends paid (7) (6) (20) (24) Cash received for off-coal compensation 5 50 50 60 50 Remove tax equity interests’ respective shares of AFFO (1) (1) (4) (4) AFFO from joint ventures 38 40 101 99 Acquisition and integration costs 6 3 — 41 7 Other non-recurring items 7 (3) (1) (14) 16 AFFO 369 315 822 642 Weighted average number of common shares outstanding (millions) 155.3 130.3 148.6 127.8 AFFO per share ($) 2.37 2.42 5.53 5.00 5
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1 Included in other cash items on the condensed interim consolidated statements of cash flows to reconcile net income to net cash flows from operating activities. 2 Excludes unrealized changes on interest rate derivative contracts, amortization, accretion charges, and non-cash implicit interest on tax equity investment structures. 3 Excludes current income tax expense related to the partial divestiture of Quality Wind and Port Dover and Nanticoke Wind as the amount is classified as an investing activity. 4 Includes sustaining capital expenditures net of partner contributions of $2 million and $8 million for the three and nine months ended September 30, 2025, respectively, compared with $2 million and $8 million for the three and nine months ended September 30, 2024, respectively. 5 Reflects annual off-coal compensation payments received from the Government of Alberta (GoA). For the nine months ended September 30, 2025, an additional payment was received for the settlement of previously disputed off-coal compensation payments as described in the Company’s 2024 annual consolidated financial statements. 6 For the three and nine months ended September 30, 2025, net of current income tax recoveries of $1 million and $2 million, respectively, compared with $3 million for the three and nine months ended September 30, 2024. 7 For the three months ended September 30, 2025, other non-recurring items reflect costs related to the termination of the Halkirk 2 Wind VPPA of $5 million (see Significant Events), net of current income tax recoveries of $8 million related to other non-recurring items recognized in the current and prior periods. For the nine months ended September 30, 2025, other non-recurring items reflect costs related to the termination of the Halkirk 2 Wind VPPA and end-of-life of Genesee coal operations of $5 million each, net of current income tax recoveries of $24 million related to other non-recurring items recognized in the current and prior periods. For the three and nine months ended September 30, 2024, other non-recurring items reflects costs related to the end-of-life of Genesee coal operations of $1 million and $5 million, respectively, and a provision of $18 million for the discontinuation of the Genesee carbon capture and storage project related to the termination of sequestration hub evaluation work, net of current income tax recoveries of $2 million and $7 million for the three and nine months ended September 30, 2024, related to other non-recurring items recognized in the prior and current periods, respectively. Forward-looking information Forward-looking information or statements included in this MD&A are provided to inform our shareholders and potential investors about management’s assessment of Capital Power’s future plans and operations. This information may not be appropriate for other purposes. The forward-looking information in this MD&A is generally identified by words such as will, anticipate, believe, plan, intend, target, and expect or similar words that suggest future outcomes. Material forward-looking information in this MD&A includes expectations regarding: • our priorities and long-term strategies, including our corporate, and decarbonization strategies, • our 2025 performance targets, including sustaining capital expenditures, adjusted funds from operations (AFFO) and adjusted earnings before interest, taxes, depreciation, and amortization (EBITDA), • future revenues, expenses, earnings, adjusted EBITDA and AFFO, • the future pricing of electricity and market fundamentals in existing and target markets, • our future cash requirements including interest and principal repayments, capital expenditures, dividends and distributions, • our sources of funding, adequacy and availability of committed bank credit facilities and future borrowings, various aspects around existing, planned and potential development projects and acquisitions. This includes expectations around timing, generation capacity, costs of technologies selected, environmental and sustainability benefits, and commercial and partnership arrangements, • our 2025 estimated capital expenditures for previously announced growth projects, • the performance of future projects and the performance of such projects in comparison to the market, • the timing of 2026 planned maintenance outages at the Company's Alberta facilities, • the increase in outage days in 2026 expected for the Company's Canadian flexible generation portfolio, • plans and results related to the acquisition of Hummel Station, LLC (Hummel Station) and Rolling Hills Generating, LLC (Rolling Hills), • the return to operation of the out of service unit at the Rolling Hills facility, • re-bidding the Halkirk 2 Wind facility into future requests for proposals and the financial impact of the VPPA cancellation, • anticipated pricing trends, growth opportunities, market conditions, and future power demand in the Pennsylvania- New Jersey-Maryland market, • legislative developments regarding carbon pricing in Pennsylvania and Ohio, • future growth and emerging opportunities in our target markets, • market and regulation designs and regulatory and legislative proposals and changes, regulatory updates, initiatives, projects and the impact thereof on the Company’s core markets and business, and • the impact of climate change, including our assumptions relating to our identification of future risks and opportunities from climate change, our plans to mitigate transition and physical climate risks, and opportunities resulting from those risks. 6
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These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions, expected future developments, and other factors it believes are appropriate including its review of purchased businesses and assets. The material factors and assumptions used to develop these forward-looking statements relate to: • electricity and other energy and carbon prices, • performance, • business prospects (including potential re-contracting of facilities) and opportunities including expected growth and capital projects, • the status and impact of policy, legislation and regulations, • effective tax rates, • the development and performance of technology, • the outcome of claims and disputes, • foreign exchange rates, and • other matters discussed under the Performance Outlook and Risks and Risk Management sections of the MD&A. Whether actual results, performance or achievements will conform to our expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results and experience to differ materially from our expectations. Such material risks and uncertainties are: • changes in electricity, natural gas and carbon prices in markets in which we operate and the use of derivatives, • regulatory and political environments including changes to environmental, climate, financial reporting, market structure and tax legislation, • disruptions, or price volatility within our supply chains, • generation facility availability, wind capacity factor and performance including maintenance expenditures, • ability to fund current and future capital and working capital needs, • acquisitions and developments including timing and costs of regulatory approvals and construction, • changes in the availability of fuel, • ability to realize the anticipated benefits of acquisitions, • limitations inherent in our review of acquired assets, • changes in general economic and competitive conditions, including inflation and recession, • changes in the performance and cost of technologies and the development of new technologies, new energy efficient products, services and programs, and • risks and uncertainties discussed under the Risks and Risk Management section of the MD&A. See Risks and Risk Management in our 2024 Integrated Annual Report, for further discussion of these and other risks. Readers are cautioned not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Capital Power does not undertake or accept any obligation or undertaking to release publicly any updates or revisions to any forward-looking statements to reflect any change in our expectations or any change in events, conditions or circumstances on which any such statement is based, except as required by law. Territorial Acknowledgement In the spirit of reconciliation, Capital Power respectfully acknowledges that we operate within the ancestral homelands, traditional and treaty territories of the Indigenous Peoples of Turtle Island, or North America. Capital Power’s head office is located within the traditional and contemporary home of many Indigenous Peoples of the Treaty 6 Territory and Métis homeland. We acknowledge the diverse Indigenous communities that are located in these areas and whose presence continues to enrich the community. About Capital Power Capital Power is a growth-oriented power producer with approximately 12 GW of owned power generation at 32 power generation facilities and two BESS facilities across North America. We prioritize safely delivering reliable and affordable power communities can depend on, building lower-carbon power systems, and creating balanced solutions for our energy future. We are Powering Change by Changing PowerTM. 7
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For more information, please contact: Media Relations: Katherine Perron (780) 392-5335 kperron@capitalpower.com Investor Relations: Roy Arthur (403) 736-3315 investor@capitalpower.com 8
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CAPITAL POWER CORPORATION Management’s Discussion and Analysis This Management’s Discussion and Analysis (MD&A), prepared as of October 28, 2025, should be read in conjunction with the unaudited condensed interim consolidated financial statements of Capital Power Corporation and its subsidiaries for the nine months ended September 30, 2025, the audited consolidated financial statements and the 2025 Performance Targets, Powering the Energy Expansion and Business Report sections of the Integrated Annual Report of Capital Power Corporation for the year ended December 31, 2024 (the 2024 Integrated Annual Report), the Annual Information Form of Capital Power Corporation dated February 25, 2025, and the cautionary statements regarding Forward-Looking Information which begin on page 10. Effective January 1, 2025, the Company reassessed its reportable segments due to changes in internal reporting for performance results provided to the Company's Chief Operating Decision Maker (CODM). These operating segments are now grouped by both business activity and geographical areas into flexible generation and renewables and Canada and U.S. Prior to 2025, these segments were based on geographical areas. Comparative segment information has been restated to conform to the current period’s presentation. References to flexible generation are defined as natural gas generation assets and energy storage. In this MD&A, any reference to the Company or Capital Power, except where otherwise noted or the context otherwise indicates, means Capital Power Corporation together with its subsidiaries. In this MD&A, financial information for the nine months ended September 30, 2025 and September 30, 2024 is based on the unaudited condensed interim consolidated financial statements of the Company for such periods which were prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board and are presented in Canadian dollars unless otherwise specified. In accordance with its terms of reference, the Audit Committee of the Company’s Board of Directors reviews the contents of the MD&A and recommends its approval by the Board of Directors. The Board of Directors approved this MD&A as of October 28, 2025. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 9
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FORWARD-LOOKING INFORMATION Forward-looking information or statements included in this MD&A are provided to inform our shareholders and potential investors about management’s assessment of Capital Power’s future plans and operations. This information may not be appropriate for other purposes. The forward-looking information in this MD&A is generally identified by words such as will, anticipate, believe, plan, intend, target, and expect or similar words that suggest future outcomes. Material forward-looking information in this MD&A includes expectations regarding: • our priorities and long-term strategies, including our corporate, and decarbonization strategies, • our 2025 performance targets, including sustaining capital expenditures, adjusted funds from operations (AFFO) and adjusted earnings before interest, taxes, depreciation, and amortization (EBITDA), • future revenues, expenses, earnings, adjusted EBITDA and AFFO, • the future pricing of electricity and market fundamentals in existing and target markets, • our future cash requirements including interest and principal repayments, capital expenditures, dividends and distributions, • our sources of funding, adequacy and availability of committed bank credit facilities and future borrowings, various aspects around existing, planned and potential development projects and acquisitions. This includes expectations around timing, generation capacity, costs of technologies selected, environmental and sustainability benefits, and commercial and partnership arrangements, • our 2025 estimated capital expenditures for previously announced growth projects, • the performance of future projects and the performance of such projects in comparison to the market, • the timing of 2026 planned maintenance outages at the Company's Alberta facilities, • the increase in outage days in 2026 expected for the Company's Canadian flexible generation portfolio, • plans and results related to the acquisition of Hummel Station, LLC (Hummel Station) and Rolling Hills Generating, LLC (Rolling Hills), • the return to operation of the out of service unit at the Rolling Hills facility, • re-bidding the Halkirk 2 Wind facility into future requests for proposals and the financial impact of the virtual power purchase agreement (VPPA) cancellation, • anticipated pricing trends, growth opportunities, market conditions, and future power demand in the Pennsylvania-New Jersey-Maryland (PJM) market, • legislative developments regarding carbon pricing in Pennsylvania and Ohio, • future growth and emerging opportunities in our target markets, • market and regulation designs and regulatory and legislative proposals and changes, regulatory updates, initiatives, projects and the impact thereof on the Company’s core markets and business, and • the impact of climate change, including our assumptions relating to our identification of future risks and opportunities from climate change, our plans to mitigate transition and physical climate risks, and opportunities resulting from those risks. These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions, expected future developments, and other factors it believes are appropriate including its review of purchased businesses and assets. The material factors and assumptions used to develop these forward-looking statements relate to: • electricity and other energy and carbon prices, • performance, • business prospects (including potential re-contracting of facilities) and opportunities including expected growth and capital projects, • the status and impact of policy, legislation and regulations, • effective tax rates, • the development and performance of technology, • the outcome of claims and disputes, • foreign exchange rates, and • other matters discussed under the Performance Outlook and Risks and Risk Management sections of this MD&A. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 10
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Whether actual results, performance or achievements will conform to our expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results and experience to differ materially from our expectations. Such material risks and uncertainties are: • changes in electricity, natural gas and carbon prices in markets in which we operate and the use of derivatives, • regulatory and political environments including changes to environmental, climate, financial reporting, market structure and tax legislation, • disruptions, or price volatility within our supply chains, • generation facility availability, wind capacity factor and performance including maintenance expenditures, • ability to fund current and future capital and working capital needs, • acquisitions and developments including timing and costs of regulatory approvals and construction, • changes in the availability of fuel, • ability to realize the anticipated benefits of acquisitions, • limitations inherent in our review of acquired assets, • changes in general economic and competitive conditions, including inflation and recession, • changes in the performance and cost of technologies and the development of new technologies, new energy efficient products, services and programs, and • risks and uncertainties discussed under the Risks and Risk Management section of this MD&A. See Risks and Risk Management in our 2024 Integrated Annual Report, for further discussion of these and other risks. Readers are cautioned not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Capital Power does not undertake or accept any obligation or undertaking to release publicly any updates or revisions to any forward-looking statements to reflect any change in our expectations or any change in events, conditions or circumstances on which any such statement is based, except as required by law. OVERVIEW OF BUSINESS AND CORPORATE STRUCTURE Capital Power is a growth-oriented power producer with approximately 12 GW of owned power generation at 32 power generation facilitie s and two battery energy storage (BESS) facilities across North America. We prioritize safely delivering reliable and affordable power communities can depend on, building lower-carbon power systems, and creating balanced solutions for our energy future. We are Powering Change by Changing PowerTM. The Company’s power generation operations and assets are owned by Capital Power L.P. (CPLP), Capital Power L.P. Holdings Inc., and Capital Power (US Holdings) Inc., all wholly owned subsidiaries of the Company. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 11
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PERFORMANCE OUTLOOK The following discussion should be read in conjunction with the forward-looking information section of this MD&A which identifies the material factors and assumptions used to develop forward-looking information and their material associated risk factors. We measure our operational and financial performance in relation to our corporate strategy through financial and non-financial targets approved by the Board of Directors. The measurement categories include corporate measures and measures specific to certain groups within Capital Power. The corporate measures are company-wide and include adjusted EBITDA, AFFO and safety. The group-specific measures include facility operating margin and other operations measures, committed capital, construction and sustaining capital expenditures on budget and on schedule, and facility site safety. The 2025 targets and forecasts, which were updated in the second quarter of 2025, are based on numerous assumptions including power and natural gas price forecasts, facility performance, and planned outages. Capital Power is reaffirming the revised guidance ranges across Adjusted EBITDA, AFFO and Sustaining Capital for 2025 despite updates to planned outages and delays on Alberta projects (see Significant Events and Capital expenditures and investments). To ensure portfolio reliability, and best position the assets to capitalize on stronger market fundamentals beyond 2026, our updated Alberta maintenance schedule is planned as follows: • Genesee 3 (G3) unit is advancing its planned outage to Q4 2025. This strategic decision ensures that G3 is fully available in 2026 to provide system support and mitigate the impact of concurrent outages elsewhere in the fleet. • The recently commissioned Genesee 1 (G1) and Genesee 2 (G2) units are scheduled for incremental maintenance that require us to extend the previously scheduled outages in Q2 2026 to balance reliability and growing dispatch requirements heading into 2027, which is typical for newly installed turbines. • Shepard Energy Centre, Joffre Cogeneration, and Clover Bar Energy Centre have routine planned outages scheduled in 2026. • In 2026, we expect approximately a 40% increase in outage days for our Canada flexible generation portfolio. As part of its ongoing Alberta fleet optimization, Capital Power remains focused on dispatching as much of its existing capacity at the Genesee site as possible. Further to that, incremental performance testing of Capital Power’s technical solution for generation above the Most Single Severe Contingency limit (MSSC) will continue including additional tuning, operational refinement, and extended runtime evaluations. Furthermore, Capital Power will also continue its proactive engagement with the AESO pursuant to the Phase 2 Large Load Allocation process to potentially unlock as much as the full nameplate capacity of the G1 and G2 units. Capital Power will update on the timing and quantum of incremental capacity above the MSSC that can be dispatched from the Genesee site once it is able to do so. Operational priorities and performance targets for Capital Power in 2025 include a balanced approach to the energy transition: Deliver Execution of major turnarounds Sustaining capital expenditures of $215 million to $245 million 3 $134 million 1,2 Generate financial stability and strength AFFO 3,4 of $950 million to $1,100 million $822 million 1 Adjusted EBITDA 3,4 of $1,500 million to $1,650 million $1,166 million 1 Portfolio optimization and integration Re-contract/contract flexible generation Maximize facility asset life and value In Q3 2025, the Company executed a new long-term contract with improved economic terms for Midland Cogeneration, extending to 2040 and providing 10 years of incremental contracted revenue (see Significant Events). Discussions with counterparties for other flexible generation facilities are in progress. Priority 2025 targets Status at September 30, 2025 Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 12
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Build Expand flexible generation portfolio Continue construction on Ontario growth and commercial initiative projects Continue to explore opportunities to build or acquire flexible generation facilities Construction is underway and the projects remain on track to meet their targeted completion dates (see Capital Expenditures and Investments). Reached commercial operation of the 40 MW uprate project at Goreway in Q2 2025. The Ontario BESS projects achieved commercial operations in Q3 2025. East Windsor Expansion environmental permits have been received and all major equipment is on site. Site civil work and foundations are advanced. In Q2 2025, the Company completed the acquisition of two U.S. flexible generation assets in the PJM market, Hummel Station and Rolling Hills (see Significant Events). Grow renewables portfolio Continue construction on Alberta and North Carolina growth and commercial initiative projects Continue to explore opportunities to build or acquire renewables facilities Construction for Hornet Solar commenced during the first quarter of 2025. Bear Branch Solar and Maple Leaf Solar commenced construction in the second quarter of 2025. These projects remain on schedule for targeted completion (see Capital Expenditures and Investments). Create Balanced energy solutions Evaluate Small Modular Reactors (SMRs) in Alberta Pre-feasibility study work for the Alberta SMR project with Ontario Power Generation (OPG) remains on track. The first funded phase of the pre-feasibility study for the Alberta SMR project with OPG has been completed. We continue to evaluate the development opportunity through this project. Provide integrated energy solutions to commercial and industrial customers Discussions with counterparties are in progress to provide integrated energy solutions. Priority 2025 targets Status at September 30, 2025 1 For the nine months ended September 30, 2025. 2 Includes our share of equity-accounted investments sustaining capital expenditures of $49 million net of partner contributions of $8 million. 3 The Company provided updated guidance for 2025 b ased on the Company’s year-to-date results, expectations for the remainder of the year and the expected results from the acquisition of Hummel Station, LLC and Rolling Hills Generating, LLC for the periods subsequent to the close of the transaction on June 9, 2025. 4 AFFO and adjusted EBITDA are non-GAAP financial measures. See Non-GAAP Financial Measures and Ratios. The Board of Directors has approved a 6% increase in the common share dividend for 2025 and we continue to anticipate a long-term targeted dividend growth of 2% – 4% after 2025, as previously announced at our Investor Day Presentation in May 2024. The reduction of our targeted dividend growth after 2025 aligns with our strategy to reinvest cash flows and to fund future growth opportunities. Each annual increase is premised on the assumptions listed under Forward-Looking Information and subject to approval by the Board of Directors of Capital Power at the time of the increase. See Liquidity and Capital Resources for discussion of expected sources of funding. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 13
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NON-GAAP FINANCIAL MEASURES AND RATIOS Capital Power uses (i) earnings before income tax expense, depreciation and amortization, net finance expense, foreign exchange gains or losses, gains or losses on disposals and other transactions, unrealized changes in fair value of commodity derivatives and emission credits, other expenses from our joint venture interests, acquisition and integration costs, and other items that are not reflective of the Company’s facility operating performance (adjusted EBITDA), and (ii) AFFO as specified financial measures. Adjusted EBITDA and AFFO are both non- GAAP financial measures. Capital Power also uses AFFO per share as a specified performance measure. This measure is a non-GAAP ratio determined by applying AFFO to the weighted average number of common shares used in the calculation of basic and diluted earnings per share. These terms are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and, therefore, are unlikely to be comparable to similar measures used by other enterprises. These measures should not be considered alternatives to net income, net income attributable to shareholders of Capital Power, net cash flows from operating activities or other measures of financial performance calculated in accordance with GAAP. Rather, these measures are provided to complement GAAP measures in the analysis of our results of operations from management’s perspective. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 14
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Adjusted EBITDA During the second quarter of 2025, the Company amended the composition of adjusted EBITDA to exclude acquisition and integration costs, as these costs are not reflective of facility operating performance. The Company has applied this change to all historical amounts reported. Capital Power uses adjusted EBITDA to measure the operating performance of facilities and categories of facilities from period to period. Management believes that a measure of facility operating performance is more meaningful if results not related to facility operations are excluded from the adjusted EBITDA measure such as impairments, foreign exchange gains or losses, gains or losses on disposals and other transactions, unrealized changes in fair value of commodity derivatives and emission credits, acquisition and integration costs, and other items that are not reflective of the long-term performance of the Company’s underlying operations. A reconciliation of adjusted EBITDA to net income is as follows: ($ millions) Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Net income 153 178 172 459 Depreciation and amortization 157 124 421 366 Unrealized changes in fair value of commodity derivatives and emission credits (13) (78) 176 (286) Other non-recurring items – – 4 4 Acquisition and integration costs 4 – 41 10 Impairment – 27 – 27 Foreign exchange loss (gain) 7 (5) (16) 9 Net finance expense 92 65 217 160 Loss on disposals and other transactions 5 5 12 20 Other items 1 37 32 110 91 Income tax expense 35 53 29 153 Adjusted EBITDA 477 401 1,166 1,013 1 Includes finance expense, depreciation expense and unrealized changes in fair value of derivative instruments from equity- accounted investments. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 15
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AFFO and AFFO per share AFFO and AFFO per share are measures of our ability to generate cash from our operating activities to fund growth capital expenditures, repayment of debt, and payment of common share dividends. During the second quarter of 2025, the Company amended the composition of AFFO and AFFO per share to exclude acquisition and integration costs, as these costs are not reflective of cash generated from facility operations. The Company has applied this change to all historical amounts reported. AFFO represents net cash flows from operating activities adjusted to: • remove timing impacts of cash receipts and payments that may impact period-to-period comparability which include deductions for net finance expense and current income tax expense, the removal of deductions for interest paid and income taxes paid and removing changes in operating working capital, • include our share of AFFO of joint venture interests and exclude distributions received from our joint venture interests which are calculated after the effect of non-operating activity joint venture debt payments, • include cash from off-coal compensation received annually through to 2030, • remove the tax equity financing project investors’ shares of AFFO associated with assets under tax equity financing structures so only Capital Power’s share is reflected in the overall metric, • deduct sustaining capital expenditures and preferred share dividends, • exclude the impact of fair value changes in certain unsettled derivative financial instruments that are charged or credited to our bank margin account held with a specific exchange counterparty, • exclude acquisition and integration costs, and • exclude other typically non-recurring items affecting cash flows from operating activities that are not reflective of the long-term performance of the Company’s underlying business. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 16
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A reconciliation of net cash flows from operating activities to AFFO is as follows: ($ millions) Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Net cash flows from operating activities per condensed interim consolidated statements of cash flows 404 236 757 706 Add (deduct): Interest paid 87 73 202 132 Change in fair value of derivatives reflected as cash settlement – 2 7 (17) Realized gain on settlement of interest rate derivatives – (28) (17) (42) Distributions received from joint ventures (9) (13) (47) (24) Miscellaneous financing charges paid 1 4 1 (2) (6) Income taxes (recovered) paid (11) (3) (14) 17 Change in non-cash operating working capital (77) 63 (23) (7) (7) 95 105 53 Net finance expense 2 (81) (56) (192) (136) Current income tax recovery (expense) 3 16 (7) 72 (29) Sustaining capital expenditures 4 (44) (35) (85) (96) Preferred share dividends paid (7) (6) (20) (24) Cash received for off-coal compensation 5 50 50 60 50 Remove tax equity interests’ respective shares of AFFO (1) (1) (4) (4) AFFO from joint ventures 38 40 101 99 Acquisition and integration costs 6 3 – 41 7 Other non-recurring items 7 (3) (1) (14) 16 AFFO 369 315 822 642 Weighted average number of common shares outstanding (millions) 155.3 130.3 148.6 127.8 AFFO per share ($) 2.37 2.42 5.53 5.00 1 Included in other cash items on the condensed interim consolidated statements of cash flows to reconcile net income to net cash flows from operating activities. 2 Excludes unrealized changes on interest rate derivative contracts, amortization, accretion charges, and non-cash implicit interest on tax equity investment structures. 3 Excludes current income tax expense related to the partial divestiture of Quality Wind and Port Dover and Nanticoke Wind as the amount is classified as an investing activity. 4 Includes sustaining capital expenditures net of partner contributions of $2 million and $8 million for the three and nine months ended September 30, 2025 , respectively, compared with $2 million and $8 million for the three and nine months ended September 30, 2024, respectively. 5 Reflects annual off-coal compensation payments received from the Government of Alberta (GoA). For the nine months ended September 30, 2025, an additional payment was received for the settlement of previously disputed off-coal compensation payments as described in the Company’s 2024 annual consolidated financial statements. 6 For the three and nine months ended September 30, 2025 , net of current income tax recoveries of $1 million and $2 million, respectively, compared with $3 million for the nine months ended September 30, 2024. 7 For the three months ended September 30, 2025 , other non-recurring items reflect costs related to the termination of the Halkirk 2 Wind VPPA of $ 5 million (see Significant Events), net of current income tax recoveries of $8 million related to other non-recurring items recognized in the current and prior periods. For the nine months ended September 30, 2025 , other non- recurring items reflect costs related to the termination of the Halkirk 2 Wind VPPA and end-of-life of Genesee coal operations of $5 million each, net of current income tax recoveries of $24 million related to other non-recurring items recognized in the current and prior periods. For the three and nine months ended September 30, 2024, other non-recurring items reflects costs related to the end-of-life of Genesee coal operations of $1 million and $5 million, respectively, and a provision of $18 million for the discontinuation of the Genesee carbon capture and storage project related to the termination of sequestration hub evaluation work, net of current income tax recoveries of $2 million and $7 million for the three and nine months ended September 30, 2024, related to other non-recurring items recognized in the prior and current periods, respectively. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 17
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FINANCIAL HIGHLIGHTS ($ millions, except per share amounts) Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Revenues and other income 1,213 1,030 2,642 2,923 Net income 153 178 172 459 Net income attributable to shareholders of the Company 154 179 173 459 Basic earnings per share ($) 0.94 1.32 1.02 3.39 Diluted earnings per share ($) 1 0.94 1.32 1.01 3.38 Adjusted EBITDA 2 477 401 1,166 1,013 AFFO 2 369 315 822 642 AFFO per share ($) 2 2.37 2.42 5.53 5.00 Net cash flows from operating activities 404 236 757 706 Purchase of property, plant and equipment and other assets, net 147 231 576 675 Dividends per common share, declared ($) 0.6910 0.6519 1.9948 1.8819 Dividends per Series 1 preferred share, declared ($) 0.1638 0.1638 0.4914 0.4914 Dividends per Series 3 preferred share, declared ($) 0.4288 0.4288 1.2863 1.2863 Dividends per Series 5 preferred share, declared ($) 0.4144 0.4144 1.2433 1.2433 Dividends per Series 11 preferred share, declared ($) 3 N/A N/A N/A 0.7188 As at September 30, 2025 December 31, 2024 Loans and borrowings including current portion 6,670 4,976 Total assets 15,345 12,930 1 Diluted earnings per share was calculated after giving effect to outstanding share purchase options. 2 The consolidated financial highlights, except for adjusted EBITDA, AFFO and AFFO per share were prepared in accordance with GAAP. See Non-GAAP Financial Measures and Ratios. 3 On June 30, 2024, Capital Power redeemed all of its 6 million issued and outstanding 5.75% cumulative minimum rate reset preference shares, Series 11. Revenues and other income for the three months ended September 30, 2025 , were higher than the corresponding period in 2024 primarily due to increased revenues from the U.S. flexible generation segment due to the Hummel Station and Rolling Hills facilities which were acquired in June 2025 (see Significant Events). Revenues and other income for the nine months ended September 30, 2025 were lower than the prior year due to losses on unrealized changes in fair value of commodity derivatives and emission credits, partially offset by the Hummel Station and Rolling Hills facilities acquired in June 2025 and increased revenues from La Paloma which was acquired in February 2024. Net income for the three and nine months ended September 30, 2025, was lower than the same periods last year due to the impacts of: • changes in adjusted EBITDA described below, • unfavorable changes in unrealized changes in fair value of commodity derivatives, • higher depreciation and amortization primarily due to the acquisition of the Hummel Station and Rolling Hills facilities in the second quarter of 2025, and the commissioning of Genesee Repower 1 and 2 in the fourth quarter of 2024, • increased other administrative expenses including acquisition and integration costs, and • increased net finance expense due to increased long term borrowings in the current year. Basic and diluted earnings per share changes were driven by the same factors as net income, and the changes from period to period in the weighted average number of common shares outstanding. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 18
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Adjusted EBITDA for the three months ended September 30, 2025 was higher than the same period last year due to: • higher contributions for the U.S. flexible generation segment due to the Hummel Station and Rolling Hills facilities which were acquired in June, 2025 (see Significant Events), partially offset by lower results from La Paloma due to lower generation from reduced demand related to the weather, and lower results from Decatur Energy due to lower generation and facility availability resulting from a planned plant outage in August 2025. Adjusted EBITDA for the nine months ended September 30, 2025 , was higher than the corresponding period in 2024 largely due to the net impact of: • higher contributions for the U.S. flexible generation segment due to the Hummel Station and Rolling Hills facilities which were acquired in June, 2025 (see Significant Events), and the full year results from La Paloma and Harquahala which were acquired in February 2024, partially offset by lower results from Midland Cogeneration due to lower revenue from a capacity rate reduction in the power purchase agreement (PPA) contract and increased fuel costs resulting in a lower dispatch, • lower emissions costs in the Canada flexible generation segment driven by the repowering of Genesee Generating Station to be off coal, • lower corporate expenses driven by lower salary costs that resulted from a reorganization late in 2024, and • partially offset by lower contributions from the Canada renewables segment due to the sell down of Quality Wind and Port Dover and Nanticoke facilities in the fourth quarter of 2024. See Consolidated Net Income and Results of Operations for further discussion of the key drivers of the changes in revenues and other income, net income and net income attributable to shareholders of the Company and adjusted EBITDA. AFFO for the three months ended September 30, 2025, was higher than the corresponding period in 2024 primarily due to: • higher adjusted EBITDA described above, and • current income tax recovery due to lower overall consolidated net income before tax, • partially offset by higher finance expense from increased loans and borrowings. AFFO for the nine months ended September 30, 2025, was higher than the corresponding period in 2024 primarily due to: • higher adjusted EBITDA and current income tax recovery described above, • lower sustaining capital expenditures due mainly to a credit received for parts at La Paloma during 2025, and • settlement received for disputed off-coal compensation payments in 2025, • partially offset by higher finance expense described above. See Liquidity and Capital Resources for discussion of key d rivers of changes in net cash flows from operating activities. Purchases of property, plant and equipment and other assets is discussed in Liquidity and Capital Resources. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 19
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SIGNIFICANT EVENTS York Energy and Goreway Battery Energy Storage Systems commissioned and contracted to 2047 On September 22, 2025, 1 20 MW York BESS and 50 MW Goreway BESS projects successfully achieved commercial operations. A leader of Ontario’s BESS development, Capital Power delivered both projects on time, under budget and with an excellent safety record. The projects are contracted until 2047 with the Ontario Independent Electricity System Operator ( IESO) (part of their Expedited Long-Term 1 RFP process) and will add approximately $35 million in annual adjusted EBITDA over the contract term. These facilities enhance our portfolio of flexible generation sources that provide grid stability, support the integration of renewable resources, and meet the province’s unprecedented, growing demand for electricity. Midland Cogeneration Venture (MCV) with Consumers Energy to 2040 In September 2025, Capital Power successfully executed a new long-term contract with improved economic terms for MCV with Consumers Energy, extending to 2040 and providing 10 years of incremental contracted revenue, subject to customary regulatory approvals. MCV is the largest natural gas-fired combined electric and steam generation facility in the United States, and a cornerstone of reliable power generation in Michigan. MCV will receive payments for 1,240 MW, approximately 75% of the facility's capacity starting in June 2030 under the new PPA, creating long-term revenue stability throughout the contract term. The contract is expected to generate a gross increase in full year adjusted EBITDA for the facility of approximately $140 million (US$100 million) 1 annually representing an 85% increase over current contract pricing. 1 Jointly owned with 50% working interest with Manulife Investment Management. MCV1 data centre In September 2025, MCV entered into a term sheet with a leading colocation data centre developer for the potential development of a data centre adjacent to the facility. Subject to due diligence, execution of formal agreements, and the requisite regulatory approvals, the proposed project would see 250 MW of power sold under a PPA agreement up to 15-years. 1 Jointly owned with 50% working interest with Manulife Investment Management. Virtual power purchase agreement cancellation As a result of delayed commissioning on Halkirk 2 Wind, Saputo Inc. (Saputo) elected to terminate the VPPA with Capital Power, resulting in a $5 million penalty paid in the third quarter of 2025. The termination also resulted in an unrealized mark to market loss of $8 million upon unwinding of the VPPA in the third quarter of 2025. Despite the contract with Saputo representing 45% of plant output, Capital Power expects the financial impact to be minimal due to forecasted merchant pricing exceeding the Saputo VPPA pricing. $1.5 billion credit facility and $600 million revolving credit facility On June 30, 2025, the Company terminated its $300 million unsecured club credit facility, increased the capacity of its committed credit facility from $700 million to $1.5 billion, and extended the term from 2029 to 2030. On August 8, 2025, the Company entered into a 2-year revolving credit agreement with a total commitment of $600 million, maturing in 2027. The funds can be drawn in Canadian or US dollars. Interest is floating and is based on the type of draw, plus margin. Acquisition of Hummel Station and Rolling Hills On June 9, 2025, Capital Power completed its previously announced acquisition of 100% of the equity interests in: • Hummel Station, LLC, owner of the 1,124 MW Hummel combined cycle natural gas facility in Shamokin Dam, Pennsylvania (the Hummel Acquisition), and • Rolling Hills Generating , LLC, owner of the 1,023 MW Rolling Hills Generation plant, a combustion turbine natural gas facility in Wilkesville, Ohio (the Rolling Hills Acquisition and together with the Hummel Acquisition, the Acquisition). The Acquisition expands the Company’s operations into the PJM interconnection market and adds to its U.S. flexible generation fleet. Both the Hummel Station and Rolling Hills facilities sell their energy, ancillary services and capacity into the PJM market on a merchant basis. Energy margins are earned through a combination of day-ahead and real-time sale while capacity will be sold through the annual auction and potential interim balancing auctions as required. The Hummel Station facility benefits from a strategically advantageous location with respect to gas supply. It is connected to the UGI Sunbury pipeline (Sunbury), which links to the Transco interstate pipeline in central Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 20
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Pennsylvania. The Hummel facility holds firm gas transport capacity on Sunbury, providing access to competitively priced Marcellus shale gas. The Hummel facility sources gas at the Leidy gas point which trades in the spot market at a discount to most other regional gas hubs. Similar to the Hummel Station facility, the Rolling Hills facility is well positioned with respect to its gas supply as it has access to low-cost Marcellus Basin gas. It is connected to the Texas Eastern Transmission Corporation (TETCO) interstate pipeline and procurement occurs in the spot market. The facility sources its gas from the TETCO East Louisiana hub, which typically trades in the spot market at a discount compared to other regional gas hubs. Currently, one unit at the Rolling Hills facility is out of service as a result of a Generator Step Up (GSU) transformer fire on or about September 12, 2024. The unit has been out of service while awaiting procurement of a replacement GSU, with a full unit restoration target date of December 2025. Lost revenues associated with the unit were negotiated as part of the purchase price, and the Company has insurance coverage for the cost of the replacement GSU. The total purchase price of the Acquisition was $3.0 billion (US$2.2 billion) in total cash consideration, including working capital and other closing adjustments. Capital Power partially financed the acquisition with net proceeds from an offering of common shares and a private offering of senior notes, described in further detail below. The balance of the Acquisition was funded with additional cash on hand and a drawdown on the Company’s existing revolving credit facilities. On July 22, 2025, PJM posted their Base Residual Auction (BRA) results for the 2026/2027 delivery year. The auction secured commitments for 134,311 MW of unforced capacity in the Regional Transmission Organization from annual, summer-period and winter-period matched resources and price-responsive demand. Prices for all locational deliverability areas (LDAs), including the LDAs where the Rolling Hills and Hummel facilities are located, cleared at the cap of US$329/MW-day, further supporting the economics of the Acquisition. $1.7 billion (US$1.2 billion) senior notes offering On May 28, 2025, Capital Power closed a private placement offering of $966 million (US$700 million) aggregate principal amount of 5.257% senior notes due 2028 and $690 million (US$500 million) aggregate principal amount of 6.189% senior notes due 2035 issued by Capital Power (US Holdings) Inc., a U.S. wholly-owned subsidiary of the Company. The notes are guaranteed by the Company and the Company’s subsidiaries that guarantee the Company’s revolving credit facilities. The net proceeds of the offering were used to fund a portion of the Acquisition. $667 million bought deal offering of common shares On April 22, 2025, the Company completed its bought deal offering of 11,902,500 common shares of Capital Power, which included 1,552,500 common shares issued pursuant to the full exercise of the over-allotment option, at an offering price of $43.45 per common share (the Offering Price), for total gross proceeds of approximately $517 million (the Public Offering). Concurrently, the Company issued 3,455,000 common shares at the Offering Price to Alberta Investment Management Corporation on a private placement basis for gross proceeds of approximately $150 million. The net proceeds of the offerings were used to partially finance the Acquisition. SUBSEQUENT EVENT On October 29, 2025, Sandra Haskins, SVP Finance & CFO announced her plans to retire from her role on December 31, 2025 after a 23-year tenure. Sandra has played a pivotal role in shaping the strategic direction and successful growth of Capital Power. Scott Manson, Chief Accounting Officer, & Treasurer will transition to Interim SVP Finance & CFO. A search for a new SVP Finance & CFO is underway, and a successor will be announced in due course. Sandra will support a smooth leadership transition by remaining in an advisory capacity until the end of Q1 2026. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 21
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CONSOLIDATED NET INCOME AND RESULTS OF OPERATIONS The primary factors contributing to the change in consolida ted net income f or the three and nine months ended September 30, 2025, compared with 2024 are presented below followed by further discussion of these items. ($ millions) Three months Nine months Consolidated net income for the periods ended September 30, 2024 178 459 Increase (decrease) in adjusted EBITDA 1: Canada flexible generation (6) 25 Canada renewables (9) (34) U.S. flexible generation 88 136 U.S. renewables (4) (3) Corporate 7 76 29 153 Change in unrealized net gains or losses related to the fair value of commodity derivatives and emission credits (65) (462) Increase in depreciation and amortization expense (33) (55) Decrease in impairments 27 27 Increase in foreign exchange (loss) or gain (12) 25 Increase in net finance expense from equity accounted investments (5) (19) Increase in net finance expense (27) (57) Decrease in loss on disposals and other transactions – 8 Acquisition and integration costs (4) (31) Decrease in income before tax (43) (411) Decrease in income tax expense 18 124 Decrease in net income (25) (287) Consolidated net income for the periods ended September 30, 2025 153 172 1 Adjusted EBITDA is a non-GAAP financial measure. See Non-GAAP Financial Measures and Ratios. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 22
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Results by facility category and other Three months ended September 30, 2025 2024 2025 2024 2025 2024 2025 2024 Electricity generation (GWh) 1 Facility availability (%) 2 Revenues and other income ($ millions) 3 Adjusted EBITDA ($ millions) 3 Total electricity generation, average facility availability and facility revenues 13,374 11,001 93 94 836 638 Canada flexible generation Genesee Generating Station, Alberta 4 2,670 2,114 96 83 138 125 Clover Bar Energy Centre, Alberta 98 203 55 94 12 17 Joffre, Alberta 167 164 98 100 14 15 Shepard, Alberta 724 807 100 100 36 39 Island Generation, British Columbia – 300 100 100 1 3 York Energy, Ontario 5 16 19 100 100 N/A N/A East Windsor, Ontario 11 5 98 93 7 8 Goreway, Ontario 1,336 901 100 100 84 77 EnPower, British Columbia 6 5 99 100 1 – BESS, Ontario 6 1 N/A 96 N/A 6 N/A Alberta portfolio optimization N/A N/A N/A N/A 234 236 5,029 4,518 95 93 533 520 181 187 Canada renewables Quality Wind, British Columbia 5 39 84 97 87 N/A 11 Halkirk 1 Wind, Alberta 92 96 97 95 7 8 Halkirk 2 Wind, Alberta 7 – N/A – N/A – N/A Whitla Wind, Alberta 215 234 96 96 10 12 Strathmore Solar, Alberta 28 24 97 97 2 1 Clydesdale Solar, Alberta 53 55 97 97 3 4 Kingsbridge 1 Wind, Ontario 11 11 96 97 1 1 Port Dover and Nanticoke Wind, Ontario 5 18 37 97 97 N/A 6 456 541 97 95 23 43 18 27 Total Canada 5,485 5,059 96 93 556 563 199 214 U.S. flexible generation Decatur Energy, Alabama 685 1,287 67 100 39 44 Arlington Valley, Arizona 917 832 100 97 39 36 Midland Cogeneration, Michigan 5 1,341 1,436 97 95 N/A N/A Frederickson 1, Washington 264 258 100 97 7 6 Harquahala, Arizona 5,8 897 860 99 98 N/A N/A La Paloma, California 8 642 901 95 94 193 194 Hummel Station, Pennsylvania 9 2,143 N/A 100 N/A 130 N/A Rolling Hills, Ohio 9 661 N/A 86 N/A 79 N/A PJM portfolio optimization and other U.S. trading 9 N/A N/A N/A N/A 9 6 7,550 5,574 93 96 496 286 307 219 U.S. renewables Beaufort Solar, North Carolina 8 5 99 94 1 1 Bloom Wind, Kansas 121 137 92 92 10 11 Macho Springs Wind, New Mexico 14 19 94 95 2 2 New Frontier Wind, North Dakota 71 77 88 90 5 4 Cardinal Point Wind, Illinois 56 65 89 75 4 7 Buckthorn Wind, Texas 69 65 89 96 5 6 339 368 91 88 27 31 15 19 Total U.S. 7,889 5,942 91 95 523 317 322 238 Corporate 10 5 5 (44) (51) Unrealized changes in fair value of commodity derivatives and emission credits 129 145 Consolidated revenues and other income and adjusted EBITDA 1,213 1,030 477 401 Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 23
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Nine months ended September 30, 2025 2024 2025 2024 2025 2024 2025 2024 Electricity generation (GWh) 1 Facility availability (%) 2 Revenues and other income ($ millions) 3 Adjusted EBITDA ($ millions) 3 Total electricity generation, average facility availability and facility revenues 31,952 28,413 92 94 1,959 1,756 Canada flexible generation Genesee Generating Station, Alberta 4 7,882 6,530 93 91 356 468 Clover Bar Energy Centre, Alberta 314 497 71 69 28 48 Joffre, Alberta 498 518 99 93 43 56 Shepard, Alberta 2,081 2,179 99 91 98 125 Island Generation, British Columbia 74 334 100 100 5 9 York Energy, Ontario 5 47 37 86 100 N/A N/A East Windsor, Ontario 21 19 98 97 25 24 Goreway, Ontario 2,823 2,252 96 94 275 225 EnPower, British Columbia 20 14 100 95 2 1 BESS, Ontario 6 1 N/A 96 N/A 6 N/A Alberta portfolio optimization N/A N/A N/A N/A 747 714 13,761 12,380 93 91 1,585 1,670 554 529 Canada renewables Quality Wind, British Columbia 5 141 264 98 94 N/A 36 Halkirk 1 Wind, Alberta 313 311 96 94 24 30 Halkirk 2 Wind, Alberta 7 – N/A – N/A – N/A Whitla Wind, Alberta 781 897 97 96 38 45 Strathmore Solar, Alberta 71 62 96 97 4 3 Clydesdale Solar, Alberta 134 139 97 97 9 11 Kingsbridge 1 Wind, Ontario 71 58 95 94 6 5 Port Dover and Nanticoke Wind, Ontario 5 99 182 92 97 N/A 28 1,610 1,913 97 96 81 158 78 112 Total Canada 15,371 14,293 94 93 1,666 1,828 632 641 U.S. flexible generation Decatur Energy, Alabama 2,626 2,625 88 99 96 92 Arlington Valley, Arizona 2,326 2,467 89 93 151 121 Midland Cogeneration, Michigan 5 3,613 4,178 95 94 N/A N/A Frederickson 1, Washington 529 641 95 79 19 18 Harquahala, Arizona 5,8 1,268 1,193 89 91 N/A N/A La Paloma, California 8 1,310 1,495 89 94 403 302 Hummel Station, Pennsylvania 9 2,659 N/A 100 N/A 164 N/A Rolling Hills, Ohio 9 821 N/A 89 N/A 100 N/A PJM portfolio optimization and other U.S. trading 9 N/A N/A N/A N/A 26 26 15,152 12,599 92 94 959 559 567 431 U.S. renewables Beaufort Solar, North Carolina 21 19 99 97 2 2 Bloom Wind, Kansas 436 495 91 95 30 33 Macho Springs Wind, New Mexico 93 101 95 96 12 12 New Frontier Wind, North Dakota 277 273 91 89 17 16 Cardinal Point Wind, Illinois 347 373 84 82 26 29 Buckthorn Wind, Texas 255 260 92 96 20 19 1,429 1,521 90 91 107 111 73 76 Total U.S. 16,581 14,120 91 95 1,066 670 640 507 Corporate 10 36 8 (106) (135) Unrealized changes in fair value of commodity derivatives and emission credits (126) 417 Consolidated revenues and other income and adjusted EBITDA 2,642 2,923 1,166 1,013 Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 24
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1 Gigawatt hours (GWh) of electricity generation reflects the Company’s share of facility output and includes GWh discharged from BESS. 2 Facility availability represents the percentage of time in the period that the facility was available to generate power regardless of whether it was running and therefore is reduced by planned and unplanned outages. 3 The financial results by facility category, except for adjusted EBITDA, were prepared in accordance with GAAP. See Non-GAAP Financial Measures and Ratios. 4 Genesee repowered units 1 and 2 simple cycle commissioned May 3, 2024 and June 28, 2024, respectively and dual cycle commissioned November 18, 2024 and December 13, 2024, respectively. Genesee Units 1, 2 and 3 are now presented together as the Genesee Generating Station. The generating capacities of Units 1, 2 and 3 are 666 MW, 666 MW and 525 MW, respectively. However, there is currently a system limit in place, called the Most Severe Single Contingency (MSSC) (see Regulatory and Government Matters), that sets the maximum amount of supply loss the Alberta grid can reliably withstand when operating in an interconnected (466 MW limit) or islanded condition (425 MW limit). This means generation from each of Units 1, 2 and 3 is currently limited to a maximum of 466 MW or 425 MW, as applicable. The Company is exploring, with the AESO, ways to enable an increase to the generating output of each facility above the MSSC. 5 Quality Wind, York Energy, Port Dover and Nanticoke Wind, Midland Cogeneration and Harquahala are accounted for under the equity method. Capital Power’s share of each facility’s net income is included in income from equity-accounted investments on our consolidated statements of income. Capital Power’s share of each facility’s adjusted EBITDA is included in adjusted EBITDA above. Quality Wind and Port Dover and Nanticoke Wind were partially divested on December 20, 2024. Revenues and other income and adjusted EBITDA are included up until December 20, 2024, for Capital Power’s full ownership. The equivalent of Capital Power’s share of all of the equity-accounted facilities revenue and adjusted EBITDA was $135 million and $62 million, and $405 million and $175 million, for the three and nine months ended September 30, 2025 respectively, compared with $116 million and $61 million, and $325 million and $115 million for three and nine months ended September 30, 2024, respectively. The facilities revenues and adjusted EBITDA are not included in the above results. 6 York Energy and Goreway BESS projects commenced commercial operations on August 29, 2025 (see Significant Events). 7 Halkirk 2 Wind commenced partial operations in the fourth quarter of 2024 with commercial operations expected in the first quarter of 2026 (see Capital Expenditures and Investments and Significant Events). 8 Harquahala and La Paloma were acquired February 16, 2024 and February 9, 2024, respectively. 9 Hummel Station and Rolling Hills facilities were acquired June 9, 2025. Trading activity related to the optimization of these assets is included in PJM portfolio optimization and other U.S. trading. 10 Corporate revenues are partially offset by interplant category eliminations. Power and natural gas energy pricing Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Power prices PJM - Western Hub (US$/MWh) 1 36.04 N/A 37.01 N/A PJM - AEP Dayton Hub (US$/MWh) 1 43.47 N/A 44.77 N/A PJM realized power price average (US$/MWh) 1,2 39.58 N/A 40.75 N/A Alberta AESO ($/MWh) 51.30 55.36 43.90 66.56 Alberta realized power price average ($/MWh) 2 72.68 75.53 73.45 78.72 Natural gas prices PJM - Transco Leidy (US$/GJ) 1 2.16 N/A 2.19 N/A PJM - Tetco ELA (US$/GJ) 1 2.83 N/A 2.84 N/A Alberta AECO ($/GJ) 0.63 0.65 1.43 1.24 1 Pricing for the nine months ended September 30, 2025 is from the date of acquisition of Hummel Station and Rolling Hills facilities in June 2025 (see Significant Events). 2 Realized power price is the average aggregate price realized through selling power generation into the spot market, the Company’s commercial contracted sales and portfolio optimization activities. When long-term forward portfolio optimization hedges are transacted, they reflect the market’s expectations for future period pricing. Ultimately, spot pricing may vary from expected forward pricing due to a number of factors resulting in realized power prices in a given period that can differ materially from spot pricing. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 25
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Canada flexible generation Alberta spot price averaged $ 51 per MWh for the third quarter and $44 per MWh for the first nine months of 2025, compared to $55 per MWh and $67 per MWh in the same periods last year. Mild temperatures across the province throughout the majority of the period and improved thermal supply resulted in lower Alberta settled and captured pricing by our Alberta portfolio year-over-year. Generation for the three and nine months ended September 30, 2025 increased compared to the same periods in the previous year while availability remained consistent due to the following net effect: • increased generation at Genesee Generation Station due to incremental capacity gained from the repowering of units 1 & 2 which achieved commercial operations in the fourth quarter of 2024, • increased availability and generation year-over-year at Goreway due to tighter market conditions with increased load demand, increased exports and colder weather early in 2025 compared to 2024, • partially offset by lower dispatch and generation at Clover Bar Energy Centre, Joffre and Shepard due to lower year-over-year power pricing. Lower revenues and other income for the nine months ended September 30, 2025, compared to the same period in 2024 were primarily due to reduced power pricing realized by the Alberta portfolio slightly offset by higher generation as listed above. Adjusted EBITDA was favorable year-over-year due to lower emissions costs from reduced intensity driven by a shift to natural gas versus coal consumption at the Genesee Generating Station, which more than offset the lower power prices and higher gas prices realized in the Alberta portfolio in 2025 compared to 2024. Canada renewables While availability was consistent year-over-year, generation and revenues and other income and adjusted EBITDA were lower in 2025 primarily due to the renewable asset sell-down of the Quality Wind and Port Dover and Nanticoke facilities in the fourth quarter of 2024. Lower Alberta power prices further reduced revenues and other income and adjusted EBITDA at Halkirk and lower generation from lower wind resource in Alberta overall. U.S. flexible generation Generation for the three and nine months ended September 30, 2025 increased compared to the same periods in 2024 due to the following net effect: • acquisition of the Hummel Station and Rolling Hills facilities in June 2025 (see Significant Events), • full year of generation at the Harquahala and La Paloma facilities in 2025 that were acquired in February 2024, slightly offset by a planned outage at La Paloma in 2025, • partially offset by the impact of hi gher fuel costs on MCV's position in the merit curve, resulting in lower dispatch. Year-to-date and quarter-to-date availability compared to the same quarter last year is impacted by standard fall maintenance outages. Revenues and other income and adjusted EBITDA for the three months ended September 30, 2025 were higher than the prior year due to the acquisition of Hummel Station and Rolling Hills facilities in June 2025 (see Significant Events). Results for the nine months ended September 30, 2025 were higher than prior year due to the acquisition, higher captured prices at La Paloma and Arlington as a result of various outages in the area , increased energy revenues at MCV, partially offset by a contracted reduction in the MCV power purchase capacity rate, and a favorable foreign exchange with a stronger U.S. currency. U.S. renewables The results of U.S. renewables remained relatively stable year-over-year. Corporate Corporate results include (i) costs of support services such as treasury, finance, internal audit, legal, people services, enterprise risk management, asset management, and environment, health and safety, and (ii) business development expenses. Cost recovery revenues are primarily intercompany revenues that are offset by interplant category transactions. Net corporate revenues and other income for the three months ended September 30, 2025 were consistent with the same period in 2024. Net corporate revenues and other income for the nine months ended September 30, 2025, were higher compared to the same period in 2024, primarily due to insurance proceeds and government grant revenues received in 2025. Adjusted EBITDA for the three months ended September 30, 2025 was higher compared with the same period in 2024 primarily due to lower business development project fees in the current Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 26
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period. Adjusted EBITDA for the nine months ended September 30, 2025 was higher than the comparative period due to insurance proceeds received in 2025, lower salary costs that resulted from a reorganization late in 2024, and the lower business development project fees previously discussed, offset partially by higher share-based compensation in 2025 compared with the same period of last year as a result of increased valuations in 2025. Unrealized changes in fair value of commodity derivatives and emission credits ($ millions) Three months ended September 30, Unrealized changes in fair value of commodity derivatives and emission credits 2025 2024 2025 2024 Revenues and other income 1 Income before tax 1 Unrealized (losses) gains on Alberta power derivatives (12) 38 (12) 35 Unrealized gains on U.S. power derivatives 126 129 87 109 Unrealized gains (losses) on natural gas derivatives 18 (15) (80) (58) Unrealized (losses) gains on emission derivatives (3) (7) 9 (18) Unrealized gains on emission credits held for trading – – 9 10 129 145 13 78 ($ millions) Nine months ended September 30, Unrealized changes in fair value of commodity derivatives and emission credits 2025 2024 2025 2024 Revenues and other income 1 Income before tax 1 Unrealized (losses) gains on Alberta power derivatives (129) 332 (128) 328 Unrealized gains on U.S. power derivatives 14 124 13 104 Unrealized losses on natural gas derivatives (8) (31) (22) (120) Unrealized losses on emission derivatives (3) (8) (31) (25) Unrealized losses on emission credits held for trading – – (8) (1) (126) 417 (176) 286 1 Revenues and other income and adjusted EBITDA include realized changes in the fair value of commodity derivatives and emission credits but exclude unrealized changes in these values. The unrealized changes are also excluded from our adjusted EBITDA metric. 2 When a derivative instrument settles, the unrealized fair value changes recorded in prior periods for that instrument are reversed from this category. The gain or loss realized upon settlement is then reflected in adjusted EBITDA for the relevant facility category. During the three and nine months ended September 30, 2025, we recognized unrealized losses on A lberta power derivatives of $12 million and $128 million, respectively, mainly due to impacts of increasing forward prices on net forward sale contracts. During the comparable periods in September 30, 2024, we recognized unrealized gains of $35 million and $328 million, respectively, mainly due to the impacts of decreasing forward prices on net forward sale contracts. During the three and nine months ended September 30, 2025 , we recognized unrealized gains on U.S. power derivatives of $87 million and $13 million, respectively, mainly due to decreasing forward pricing on net forward sale contracts in California, partially offset by unrealized losses on contracts at our Hummel Station, Rolling Hills and U.S. renewable facilities. During the comparable periods in September 30, 2024, we recognized unrealized gains of $109 million and $104 million, respectively, mainly due to the impact of decreased forward prices on forward sale contracts associated with the majority of the Company’s U.S. renewables facilities and La Paloma. During the three and nine months ended September 30, 2025 , we recognized unrealized losses on natural gas derivatives of $80 million and $22 million, respectively, due to impacts of decreasing forward pricing on net forward buy contracts in the U.S. During the comparable periods in September 30, 2024, we recognized unrealized losses of $58 million and $120 million, respectively, due to the impacts of decreased forward pricing on forward purchase contracts. During the nine months ended September 30, 2025, we recognized unrealized losses of $31 million on emissions derivatives due to the impact of decreased forward pricing on our U.S. emissions derivatives on forward net purchases. During the three and nine months ended September 30, 2024 we recognized unrealized losses on emissions derivatives of $18 million and $25 million, respectively, mainly due to decreased forward prices on forward purchases. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 27
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Consolidated other expenses and non-controlling interests ($ millions) Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Net finance expense (92) (65) (217) (160) Depreciation and amortization (157) (124) (421) (366) Impairment – (27) – (27) Foreign exchange (loss) gain (7) 5 16 (9) Loss on disposals and other transactions (5) (5) (12) (20) Other items from equity-accounted investments 1 (37) (32) (110) (91) Income tax expense (35) (53) (29) (153) Net loss attributable to non-controlling interests (1) (1) (1) – 1 Includes finance expense, depreciation expense and fair value changes on derivatives from equity-accounted investments. Net finance expense Higher net finance expense for the three and nine months ended September 30, 2025 compared with the same periods in the prior year largely reflects higher interest due to the increased loans and borrowings outstanding from draws on the $600 million credit facility, $1.7 billion senior notes issued during 2025 (see Significant Events) and the $450 million and $600 million notes issued during the second half of 2024. This was further impacted by lower capitalized interest during 2025 due to higher construction activity for the Genesee repowering project in 2024. Depreciation and amortization Higher depreciation and amortization for the three and nine months ended September 30, 2025 was due to the Goreway uprate which achieved commercial operation in the second quarter of 2025, the acquisitions of the Hummel Station and Rolling Hills facilities in the second quarter of 2025, and La Paloma in the first quarter of 2024 and the commissioning of Genesee Repower 1 and 2 in the fourth quarter of 2024. Foreign exchange (loss) gain The Company recognized foreign exchange losses for the three months ended September 30, 2025 due to an increase in the USD to CAD exchange rates during the period, compared to gains in the same quarter last year due to a decrease in rates in the prior year. Foreign exchange gains were recognized for the nine months ended September 30, 2025 due to a decrease in the USD to CAD exchange rates during the period. Comparatively, exchange rates during the period ending September 30, 2024 were increasing resulting in foreign exchange losses. Other items from equity-accounted investments Other items from equity-accounted investments includes Capital Power’s share of finance expense, depreciation expense and unrealized changes in fair value of derivative instruments from our York Energy, Quality Wind, Port Dover and Nanticoke Wind, Midland Cogen eration and Harquahala equity-accounted investments. Other items from equity-accounted investments increased compared with 2024 primarily due to Quality Wind and Port Dover and Nanticoke Wind becoming equity-accounted investments upon Capital Power’s partial divestiture of these assets in the fourth quarter of 2024. Income tax expense Income tax expense for the three and nine months ended September 30, 2025 , decreased compared with the corresponding periods in 2024 primarily due to lower overall consolidated net income before tax. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 28
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FINANCIAL POSITION The following highlights changes in the consolidated statements of financial position from December 31, 2024 to September 30, 2025 were as follows: ($ millions) September 30, 2025 December 31, 2024 Assets Current assets 1,451 1,948 Non-current assets: Property, plant and equipment 11,155 8,061 Equity-accounted investments 1,081 1,096 Intangible assets and goodwill 637 744 Right-of-use assets 138 118 Derivative financial instruments 430 412 Government grant receivable 315 380 Deferred tax assets 37 26 Other assets 101 145 Total assets 15,345 12,930 Liabilities and equity Current liabilities 1,960 1,353 Non-current liabilities: Derivative financial instruments 615 494 Loans and borrowings 5,960 4,819 Lease liabilities 155 134 Deferred tax liabilities 915 863 Provisions 425 373 Deferred revenue and other liabilities 307 323 Total liabilities 10,337 8,359 Share capital 5,009 4,301 Deficit (222) (74) Other reserves 229 349 Equity attributable to shareholders of the Company 5,016 4,576 Non-controlling interests (8) (5) Total equity 5,008 4,571 Total liabilities and equity 15,345 12,930 Net working capital d ecreased from December 31, 2024 to September 30, 2025 by $ 1,104 million, mainly driven by: • reduction in cash balances as described in Liquidity and Capital Resources, • reclassifying the current portion of loans and borrowing from non-current, • partially offset by deferred payments on capital project costs for the construction of Halkirk 2 Wind. The C ompany has $1.9 billion of available liquidity from credit facilities if needed to meet obligations as they become due (2024 - $1.0 billion) (see Liquidity and Capital Resources). Property, plant and equipment increased from December 31, 2024 to September 30, 2025 primarily due to the additions of the Hummel Station and Rolling Hills facilities. Intangible assets and goodwill decreased from December 31, 2024 to September 30, 2025 primarily due to amortization and the use of emissions credits for compliance purposes. Non-current loans and borrowings increased from December 31, 2024 to September 30, 2025 due to draws on the credit facility obtained in the current quarter and the $1.7 billion of senior notes issued in the second quarter of 2025 (see Significant Events), partially offset by reclassifying the current portion of loans and borrowings. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 29
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LIQUIDITY AND CAPITAL RESOURCES ($ millions) Nine months ended September 30, Cash inflows (outflows) 2025 2024 Change Operating activities 757 706 51 Investing activities (3,477) (1,846) (1,631) Financing activities 2,082 (129) 2,211 Operating activities Cash flows from operating activities for the nine months ended September 30, 2025 were higher than the same period in 2024 mainly due to the net impact of: • cash inflows from the contributions of Hummel Station and Rolling Hills in June 2025 (see Significant Events), • lower cash taxes paid mainly due to tax depreciation and lower overall consolidated net income before tax, • increased distributions received from equity-accounted investments, • partially offset by increased interest paid mainly due to increased interest on loans and borrowings. Investing activities Cash flows used in investing activities for the nine months ended September 30, 2025 were higher than the same period in 2024 due to the acquisitions of the Hummel Station and Rolling Hills facilities in June 2025 (see Significant Events). Financing activities Cash flows from financing activities for the nine months ended September 30, 2025 were higher than the same period in 2024 due to the proceeds received from the $1.7 billion senior notes issued and increased share capital from the bought deal offering and private placement in the second quarter of 2025 (see Significant Events) and lower repayments of loans and borrowings. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 30
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Capital expenditures and investments ($ millions) Pre- 2025 actual Nine months ended September 30, Balance of 2025 estimated 1,2 Actual or projected total 2 Targeted completion Repowering of Genesee 1 and 2 3 1,487 60 3 to 103 1,550 to 1,650 Achieved commercial operations fourth quarter of 2024 and the project is substantially complete Halkirk 2 Wind 4 298 17 16 333 First quarter of 2026 (previously fourth quarter of 2025) Ontario growth projects 356 156 48 576 York and Goreway BESS completed in the third quarter of 2025 East Windsor Expansion in the second quarter of 2026 Maple Leaf Solar 12 37 34 230 First quarter of 2027 Bear Branch Solar 8 20 23 106 Fourth quarter of 2026 Hornet Solar 15 73 72 205 Third quarter of 2026 Commercial initiatives 5 268 17 18 Development sites and projects 63 (1) – Subtotal growth projects 379 214 to 314 Sustaining – plant maintenance 93 Total capital expenditures 6 472 Emission credits held for compliance 18 Capitalized interest (31) Additions of property, plant and equipment and other assets 459 Change in other non-cash investing working capital and non-current liabilities 117 Purchase of property, plant and equipment and other assets, net 576 1 The Company’s 2025 estimated capital expenditures include only expenditures for previously announced growth projects and exclude other potential new development projects. 2 Projected capital expenditures to be incurred over the life of the ongoing projects are based on management’s estimates. Projected capital expenditures for development sites are not reflected beyond the current period until specific projects reach the advanced development stage. 3 Projected costs for the project including incurred post-commercial operations date, remain subject to the dispute resolution with the contractor described under Contingent Liabilities, Other Legal Matters and Provisions. 4 Targeted completion date is management’s estimate of the timeline to commission the site subject to the Alberta Utilities Commission’s release of its work suspension order that resulted from the nacelle and rotor at one of the turbines that fell from the tower in November 2024. The commercial operation date required by the PPA for this project was not met. The agreement with Saputo was terminated and resulted in a termination fee of $5 million incurred in the third quarter of 2025 (see Significant Events). 5 Commercial initiatives include expected spending on various projects designed to either increase the capacity or efficiency of their respective facilities or to reduce emissions. 6 Capital expenditures include capitalized interest. Capital expenditures excluding capitalized interest are presented on the consolidated statements of cash flows as purchase of property, plant and equipment and other assets, net. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 31
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Financing activities See Liquidity and Capital Resources for significant changes in current quarter and year-to-date financing activities. The Company’s credit facilities consisted of: ($ millions) At September 30, 2025 At December 31, 2024 Maturity Timing Total facilities Credit facility utilization Available Total facilities Credit facility utilization Available Committed credit facilities 1 2030 2,100 174 1,926 1,000 – 1,000 Bilateral demand credit facilities N/A 1,408 1,421 Letters of credit outstanding 559 608 1,408 559 849 1,421 608 813 Demand credit facilities N/A 25 – 25 25 – 25 3,533 733 2,800 2,446 608 1,838 1 Committed credit facilities include letters of credit, bankers’ acceptances and bank loans outstanding. In the third quarter of 2025, the Company entered into a 2-year revolving credit agreement with a total commitment of $600 million, maturing in 2027 (see Significant Events). The funds can be drawn in Canadian or US dollars. Interest is floating and is based on the type of draw, plus margin. In the second quarter of 2025, the Company terminated its $300 million unsecured club credit facility, increased the capacity of its committed credit facility from $700 million to $1.5 billion, and extended the term from 2029 to 2030. The available credit facilities provide adequate funding for ongoing development projects. Capital Power has surety capacity to accommodate, as part of normal course of operations, the issuance of bonds for certain capital projects and contracts. At September 30, 2025 and December 31, 2024 , $99 million of bonds were issued under these facilities. Capital Power has the following corporate credit ratings which were affirmed in May 2025: Rating Agency Rating Outlook Definition Standard and Poor’s BBB - Stable Exhibits adequate capacity to meet financial commitments; however, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments. DBRS Limited BBB (low) Stable Adequate credit quality and the capacity for the payment of financial obligations is considered acceptable but the entity may be vulnerable to future events. Fitch Ratings BBB - Stable Expectation of default risk is low. The capacity for payment of financial commitments is considered adequate, but adverse business or economic conditions are more likely to impair this capacity. The above credit ratings are investment grade credit ratings which enhance Capital Power’s ability to re-finance existing debt as it matures and to access cost competitive capital for future growth. During the second quarter of 2025, we obtained a credit rating by Fitch Ratings to support our long-term growth and broaden our access in the U.S. debt capital markets. Fitch assigned Capital Power a first-time issuer default rating of BBB- with a Stable outlook, reinforcing our investment-grade profile. Off-statement of financial position arrangements At September 30, 2025 , Capital Power has $ 559 million of outstanding letters of credit for collateral support for trading operations, conditions of certain service agreements, and to satisfy legislated reclamation requirements and $99 million of surety bonds issued for certain capital projects and contracts. If Capital Power were to terminate these off-statement of financial position arrangements, the penalties or obligations would not have a material impact on our financial condition, results of operations, liquidity, capital expenditures or resources. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 32
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Capital resources ($ millions) As at September 30, 2025 December 31, 2024 Loans and borrowings 6,670 4,976 Lease liabilities 1 173 151 Less cash and cash equivalents (204) (865) Net debt 6,639 4,262 Share capital 5,009 4,301 Deficit and other reserves 7 275 Non-controlling interests (8) (5) Total equity 5,008 4,571 Total capital 11,647 8,833 1 Includes the current portion presented within deferred revenue and other liabilities. Capital Power uses a short-form base shelf prospectus to provide it with the ability, market conditions permitting, to obtain new debt and equity capital when required. Under the short-form base shelf prospectus dated June 12, 2024, Capital Power may issue an unlimited number of common shares, preferred shares, subscription receipts exchangeable for common shares and/or other securities of Capital Power and/or debt securities, including up to $3 billion of medium-term notes by way of a prospectus supplement. This prospectus expires in July 2026. If the Canadian and U.S. financial markets become unstable, Capital Power’s ability to raise new capital, to meet our financial requirements, and to refinance indebtedness under existing credit facilities and debt agreements may be adversely affected. Capital Power has credit exposure relating to various agreements, particularly with respect to our power purchase agreement, energy supply contract, trading and supplier counterparties. While Capital Power continues to monitor our exposure to significant counterparties, there can be no assurance that all counterparties will be able to meet their commitments. See Risks and Risk Management for additional discussion on recent developments pertaining to these risks and Capital Power’s risk mitigation strategies. CONTINGENT LIABILITIES, OTHER LEGAL MATTERS AND PROVISIONS Refer to the Contractual Obligations, Contingent Liabilities, Other Legal Matters and Provisions discussion in our 2024 Integrated Annual Report for details on ongoing legal matters. Contingent liabilities Capital Power and our subsidiaries are subject to various legal claims that arise in the normal course of business. Management believes that the aggregate contingent liability of the Company arising from these claims is immaterial. A dispute arose in 2024 between the Company and the contractor regarding construction work on the Genesee Repowering project. The parties are participating in an arbitration process to resolve the claims by both parties. The Company has withheld payments pending the resolution of the dispute. Preliminary matters related to the arbitration process began late in the second quarter of 2025. While final project costs remain subject to the outcome of the arbitration, the Genesee Repowering Project achieved commercial operations in 2024 and is considered substantially complete. RISKS AND RISK MANAGEMENT For the nine months ended September 30, 2025 , Capital Power’s business, operational and climate-related risks and opportunities have remained consistent with those described in our 2024 Integrated Annual Report other than risks around tariffs imposed by the U.S. and Canada. See Regulatory and Government Matters for management’s assessment of the impact of these tariffs. Future changes to tariffs imposed by both the U.S. and Canada may materially change management’s current assessment. Details around Capital Power’s approach to risk management, including principal risk factors and the associated risk mitigation strategies, are described in our 2024 Integrated Annual Report. These factors and strategies have not changed materially in the nine months ended September 30, 2025. In addition, the Company’s acquisition of the Hummel Station and Rolling Hills facilities, expands the Company’s operations into the PJM Interconnection market and presents new operational and market risks. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 33
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Market Exposure to the Hummel Station and Rolling Hills facilities In PJM, the day-ahead and real-time markets are nodal markets which are based on the supply and demand of the energy market as a whole and of each individual node on the grid, taking into account the physical constraints of the transmission system. As a result, the nodal market incorporates local losses and congestion into the price that generators receive, exposing assets to basis risk compared to the major hub and/or zonal prices where hedges are typically available. Additionally, participants in the PJM capacity market must commit to being available to supply capacity or reduce demand in the energy market. However, there is no guarantee that the Hummel Station and Rolling Hills facilities will have the required capacity when needed the most, exposing them to potential penalties for non-performance if they fail to meet their commitments during periods of grid system stress or emergencies. Merchant markets are cyclical and there is risk that future merchant revenues fall short of expectations. Given the current increase in capacity prices, PJM is making efforts to dampen capacity prices going forward, including but not limited to, proposing a lower price cap in future capacity auctions. Merchant exposure risk can be mitigated for resource adequacy through advanced contracting and risk on energy margin can be mitigated through heat rate call options and other products. Risk mitigation steps may shift risk from merchant energy to other risks, such as gas basis or operational risks. However, there remains a risk that future PJM market rule changes may not allow operators, including Capital Power with respect to the Hummel Station and Rolling Hills facilities, to earn market- based returns. The PJM BRA results for the 2026/2027 year were posted on July 22, 2025 (see Significant Events). While the Hummel Station facility and the four operational units at the Rolling Hills facility are currently capable of meeting their capacity commitments, unforeseen circumstances may prevent the facilities from meeting their future capacity commitments (see Regulatory and Government Matters – PJM market). ENVIRONMENTAL MATTERS Capital Power recorded decommissioning provisions of $ 367 mil lion at September 30, 2025 ($346 million at December 31, 2024 ) for our generation facilities and the Genesee mine as it is obliged to remove the facilities at the end of their useful lives and restore the facility and mine sites to their original condition. Decommissioning provisions for the Genesee mine were incurred over time as new areas were mined, and a portion of the liability is settled over time as areas are reclaimed prior to final pit reclamation. The timing of reclamation activities could vary and the amount of decommissioning provisions could change depending on potential future changes in environmental regulations. At September 30, 2025 , Capital Power has forward contracts to purchase environmental credit s totaling $ 1,094 million and forward contracts to sell environmental credits totaling $958 million in future years. Included within these forward purchases and sales are net purchase amounts which will be used to comply wi th applicable environmental regulations and net sale amounts related to other emissions trading activities. REGULATORY AND GOVERNMENT MATTERS Refer to the Regulatory Matters discussion in the Company’s 2024 Integrated Annual Report for further details that supplement the recent developments discussed below: United States U.S. Clean Air Act In June 2025, the Environmental Protection Agency (EPA) released a draft rule that would repeal all greenhouse gas (GHG) standards for fossil fuel electric generating units, effectively kicking off a rulemaking process to overturn a previous rule that aimed to curb GHG emissions for coal-, gas-, and oil-fired power plants. This decision, once finalized, will remove the federal requirement for Capital Power to decarbonize future expansions to our thermal fleet. Given the need for notice and comment, and the statutory time period for states to develop implementation plans for existing sources under the Clean Air Act, it is unlikely that existing gas units will face CO2 regulation until the early- to mid-2030s at the earliest from the U.S. federal government. Maricopa County, Arizona, where the Arlington Valley and Harquahala natural gas facilities are located, does not meet the National Ambient Air Quality Standards set by the EPA under the Clean Air Act for two of the six principal pollutants. Maricopa County is currently classified as “moderate” nonattainment levels for these principal pollutants, and a reclassification to “serious” nonattainment levels can occur any time after February 3, 2025, which would result in changes in permitting requirements for existing, new and modified facilities. Maricopa County was previously facing additional offset sanctions at a 2:1 level for failure to submit a plan to EPA addressing moderate level air quality requirements, but an agreement was reached with EPA in the second quarter of 2025 that a sufficient moderate level plan was received, thus halting the threat of additional 2:1 sanctions. If Maricopa County Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 34
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continues to remain in nonattainment status, Capital Power will be challenged to construct additional turbines at Arlington Valley and Harquahala without offsetting emissions. Management continues to monitor developments. The U.S. EPA proposed to rescind the 2009 Endangerment Finding, a legal precedent that determined the accumulation of greenhouse gases in the atmosphere endangers people’s health, and thus, the EPA is required to regulate such emissions under the Clean Air Act. The EPA has also proposed to terminate the Greenhouse Gas Reporting Program (GHGRP) and suspend reporting requirements until the current program ends in 2034. Since its enactment in 2009, the GHGRP has required certain large GHG emission sources, including fuel and industrial gas suppliers and CO2 injection sites, to report emissions data in a standardized way. While the termination of the program would remove the federal requirement for Capital Power to report emissions data, state-level requirements would remain in place. The 45Q Carbon Capture and Storage (CCS) tax credit requires emissions reporting data to claim tax credit eligibility, so a lack of a standardized reporting system could hinder Capital Power’s ability to claim federal CCS tax credits for project construction. Management is currently engaging U.S. federal officials to gain clarity on how tax credit eligibility could be impacted without a formal reporting structure in place. One Big Beautiful Bill (OBBB) The U.S. Congress approved a budget reconciliation bill known as the One Big Beautiful Bill (OBBB) , signed into law by President Donald Trump on July 4, 2025. The tax cuts are expected to provide a benefit of approximately $200 million to Capital Power over the next seven years through reduced current and cash taxes from accelerated recognition of tax deductions. To pay for the cost of reauthorization, members of Congress are seeking cuts to other tax provisions including the Clean Energy Investment Tax Credit and production tax credit that were authorized in the 2022 Inflation Reduction Act. The OBBB language requires a clean energy project, as defined by the OBBB, to commence construction within one year of enactment to claim 100% of the existing tax credit benefits, and a placed in-service date of December 31, 2027, to be eligible. There are also requirements on the percentage of a component, subcomponent, or critical mineral used in the project to be sourced domestically or from countries that are not considered foreign entities of concern. Capital Power projects within the scope of this legislation include: Maple Leaf Solar, Bear Branch Solar, and Hornet Solar in North Carolina; Greencastle in Indiana; and Nolin Hills in Oregon. Management will continue to monitor and assess the implications of this legislative change on the Company's renewable growth projects. U.S. tariffs / United States-Mexico-Canada Agreement (USMCA) During the first quarter of 2025, President Trump issued tariffs which have created economic and political uncertainties, such as potential counter tariffs from other countries, including those imposed by the Government of Canada and Government of Ontario. Separately, the USMCA trade agreement is due for review by July 1, 2026, and all three parties must decide whether to extend the pact beyond its initial 16-year term. If one or more parties decline, annual reviews will be triggered until consensus is reached or until the agreement terminates in 2036. While at this time, we do not expect significant impacts to Capital Power, this is an evolving risk that may impact future supply chain costs and sales of power to the U.S. Management will continue to monitor the situation as changes to the tariff framework are put into place. PJM market PJM is a regional transmission organization that dispatches generation, operates a competitive wholesale electricity market and manages the reliability of a transmission grid spanning all or parts of 13 states and the District of Columbia, serving more than 65 million people. PJM is the largest centrally operating market in North America, with approximately 200 GW of installed capacity and peak demand of approximately 150 GW. PJM is currently experiencing substantial population growth and industrial development, including growth in data centre energy consumption, driven by the rapid expansion of digital infrastructure. According to PJM's 2025 load forecast, peak demand is expected to grow at annualized rates above 3% in the next ten years. In PJM, both the day-ahead and real-time markets are nodal markets, where electricity prices are determined based on the supply and demand at each individual node on the grid, considering both the supply and demand as well as the physical constraints of the transmission system. In addition to its wholesale market, PJM operates a capacity market through the Reliability Pricing Model, which focuses on securing sufficient long-term resources to ensure grid reliability. PJM generally holds an annual BRA for capacity resources to meet expected energy demand needs for the future capacity year three years in advance; however, this schedule has been compressed due to delays beginning in 2019 around the Federal Energy Regulatory Commission’s (FERC) Minimum Offer Price Rule and further delays in the wake of Winter Storm Elliot exposing vulnerabilities to PJM's reliability, causing PJM to reform its auction rules. The auctions are currently expected to be held every six months until PJM is back on the Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 35
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three-year forward schedule by May 2027. PJM has instituted a maximum capacity price of USD$325/Megawatt- day (MWd) and a minimum capacity price of USD$175/MWd for the next two auctions to increase market stability. When participants offer resources into the auction, they are committing to be available to supply capacity or reduce demand in the energy market. If participants fail to meet these commitments during periods of grid system stress or emergencies, they face penalties for non-performance. If participants are on-line at full bid capacity during periods of grid system stress or emergency, they can earn incentives. Annually, PJM performs a review of the capital additions required to provide reliable electric transmission services throughout its territory. PJM traditionally allocated the costs of constructing these facilities to those entities that benefited directly from the additions. Over the last several years, however, some of the costs of constructing large, new transmission facilities have been socialized across PJM without a direct relationship between the costs assigned to and benefits received by particular PJM members. To the extent that any costs in the future are material and Capital Power is unable to recover them, such costs could have a material adverse effect on our results of operations, financial condition and cash flows. PJM market is under pressure from various stakeholders including state consumer advocates, elected officials and public interest organizations to alleviate reliability and affordability concerns. If government officials at the state or federal level determine that market reform is needed to alleviate reliability and affordability concerns, then increased oversight over FERC, and by extension PJM, could facilitate or accelerate changes in market structures. This could disrupt competitive market dynamics and create uncertainty for market participants. In August 2025, PJM held a Critical Issue Fast Path workshop on large load additions. The conceptual proposal recommends the creation of a Non-Capacity-Backed Load (NCBL) option for large new loads, aiming to allow data centres to interconnect quicker without the need for multi-year capacity procurement obligations. It also creates economic incentives for data centres to contribute supply through demand response, providing a natural market- based solution rather than relying on the artificial reclassification of load under the NCBL option. PJM is targeting a December 2025 FERC filing, with changes going into effect for the 2028-2029 delivery year. Management will continue to monitor changes to the PJM market structure and report as needed. Canada Alberta Alberta Electric System Operator (AESO) Restructured Energy Market (REM) On August 27, 2025 the AESO released the final high-level design for REM. The final design introduces increased price caps for dispatchable assets (offer cap rising to $1,500/MWh and price cap during scarcity events set at $3,000/MWh), a new real-time ramping product (R30), and the adoption of locational marginal pricing (LMP) for congestion management. The AESO has started consultation on REM rules which are expected to be approved by the Minister of Affordability and Utilities later this year. Details of several administrative parameters, such as the cost of new entry for reference units, will be determined closer to implementation which is expected to start in mid-2027. The high-level design is supportive of providing added value for dispatchable, reliable generation and Management will continue to actively participate in the rules and implementation process. Connection for large load projects in Alberta On June 4, 2025, the AESO shared details on Phase I of their large load connection plan, updating industry with details on how data centre projects in Alberta will be provided with an opportunity to connect to the grid. For Phase I, the AESO instated a 1,200 MW interim connection limit that was allocated to qualified data centre projects, including those applied for by Capital Power, with contracting awarded in October 2025 . While the interim connection limit restricts the scale of data centre projects, Management views data centre-driven electricity demand growth in Alberta as a positive long-term development for all power producers. In August and September 2025, the AESO consulted on connection requirements for transmission connected data centres with the intention to provide clear expectations to developers while safeguarding reliability. On September 26, 2025 the AESO announced pre-engagement on its Phase II of its Large Load Integration Program which will explore changes necessary to create a long-term framework for large loads including data centres. This will include engagement on the AESO’s connection processes, planning, operations, markets, tariff and reliability. Management is actively involved in these data centre engagements and will continue to monitor as further details develop. Alberta Bill 52 – Energy and Utilities Statutes Amendment Act, 2025 On May 12, 2025, the GoA passed the Energy and Utilities Statutes Amendment Act to enable the AESO to implement the REM. The Act makes necessary changes to the rules approval process to allow the REM rules to be enacted by the Minister through regulation (instead of the AUC). The bill also removes the congestion free policy from the AESO's policy obligations for transmission planning. Other changes in the Act remove barriers to allow hydrogen blending in the natural gas distribution system for residential and commercial heating to support new Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 36
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technologies while ensuring the safety and reliability of the system; and streamline the process to connect with other jurisdictions, reducing red tape and enabling critical improvements. AESO Independent Systems Operator (ISO) tariff redesign On March 5, 2025, the AESO kicked off an engagement to redesign its ISO tariff, which outlines the rates, terms and conditions for market participants who receive access to the transmission system. The scope of the engagement will include addressing ancillary service cost allocation, system access charges for generators and amendments to the connection process with a filing with the AUC in 2026; and demand rates, tariffs for imports and exports, and additional considerations are to be filed with the Commission in 2027. New rates are expected to take effect in 2029 following the AUC review process. Management will participate as appropriate in the AESO’s engagement over the next two years. Optimal transmission planning (OTP) Following the Alberta government’s July 2024 policy direction to shift from a zero-congestion to an OTP standard, the AESO launched stakeholder engagement in the second quarter of 2025. Management participated in two AESO-led sprints which focused on refining the OTP framework and introduced the Transmission Reinforcement Payment (TRP), which is intended to replace the Generating Unit Owner’s Contribution (GUOC) – an upfront payment made by generators to fund transmission infrastructure. As part of this engagement, the AESO has been consulting on financial transmission rights (FTRs) to hedge congestion risk with the move to LMP. Management anticipates further details will be made available later this year as rule drafting is expected before year-end. On July 15, 2025 the GoA directed the AESO to adopt LMP and allocate financial transmission rights (FTRs) to incumbent generators. The AESO started consultations on FTRs holding stakeholder sessions in September to discuss the long-term potential for FTRs in the Alberta market and in October to discuss the allocation of the transition rights. The AESO has also started to consult OTP and in September published its recommended approach including how it will assess benefits and costs for transmission development. Further consultation on transmission reinforcement payments is anticipated to start in the fourth quarter of 2025 and will address the cost generators will be assessed to connect to the grid. Management is active in all transmission policy and planning consultations. AESO ISO Fast Frequency Response Plus (FFR+) procurement In June 2025, the AESO launched a new engagement on FFR+, a proposed ancillary service designed to support full import flows on Alberta’s BC and Montana interties. FFR+ builds on the existing Fast Frequency Response framework by incorporating additional non-market reliability services such as system strength, fast net demand response, and blackstart capability. In July, the AESO convened a stakeholder engagement session to solicit feedback on design options for the Fast Frequency Response Plus (FFR+) product. In August, the AESO published an Addendum to its FFR+ rationale, outlining several new design options informed by stakeholder input and solicited stakeholder feedback and concurrently invited expressions of interest for participation in a forthcoming procurement for the FFR+ product. The AESO anticipates releasing the formal call for procurement in mid-2026. Management will continue to monitor this and evaluate opportunities through the procurement process. AESO Most Severe Single Contingency Genesee repowered units 1 and 2 simple cycle commissioned May 3, 2024 and June 28, 2024, respectively and dual cycle commissioned November 18, 2024 and December 13, 2024, respectively. Genesee Units 1, 2 and 3 are presented together as the Genesee Generating Station. The generating capacities of Units 1, 2 and 3 are 666 MW, 666 MW and 525 MW, respectively. However, there is currently a system limit in place, called the MSSC, that sets the maximum amount of supply loss the Alberta grid can reliably withstand when operating in an interconnected (466 MW limit) or islanded condition (425 MW limit). This means generation from each of Units 1, 2 and 3 is currently limited to a maximum of 466 MW or 425 MW, as applicable. The Company is exploring, with the AESO, a technical solution to enable an increase to the generating output of each facility above the MSSC. Performance testing is underway to determine the incremental MWs achievable through this technical solution. Once performance testing is complete, implementation is contingent upon regulatory approval. Ontario Market Renewal Program (MRP) The IESO’s MRP is a set of coordinated market and IESO system reforms intended to improve market transparency, competitiveness, and real-time unit scheduling. It introduces LMP, market power mitigation, and a financially binding day-ahead market. The IESO transitioned to the new market on May 1, 2025. Management is now monitoring the impact the MRP has on the Company’s generating contracts and continues to work with the Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 37
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IESO to minimize any adverse outcomes. Management may, if necessary, leverage provisions within the contracts that are intended to protect suppliers from adverse effects resulting from market rule changes. Ontario Bill 40 – Protect Ontario by Securing Affordable Energy for Generations Act, 2025 On June 3, 2025 the Ontario government tabled legislation to support major growth in Ontario’s energy system to meet rising demand. The legislation is proposed to enable the IESO and the Ontario Energy Board (OEB) to prioritize projects that promote economic growth and create jobs, support made-in-Canada energy technology for security and increase support for hydrogen. Management will continue to monitor changes and opportunities resulting from the legislation and the subsequent integrated energy plan. Data centre requirements As part of the Bill 40 changes, the Ontario Government has proposed requirements for data centres to address recent growth in data centre connection interest. Under the proposed changes, approval from the Minister of Energy and Mines will be required for data centre projects to connect to the provincial electricity grid. Management will participate in the engagement, which will run through November 2025, and continue to monitor changes for opportunities. Ontario’s integrated energy plan On June 12, 2025, Ontario released the province’s inaugural integrated energy plan titled “Energy for Generations: Ontario’s Integrated Plan to Power the Strongest Economy in the G7”. The plan builds on energy policy and key initiatives including energy efficiency, Indigenous partnerships, and affordable, secure, reliable, and clean electricity. The plan also consolidates broad energy policy goals around Ontario becoming an energy superpower, streamlining permitting of large-scale energy infrastructure projects, and continued support for investment in nuclear and transmission. The plan further reaffirms the critical role natural gas plays in Ontario’s energy system and the government’s commitment to the IESO’s competitive procurements for electricity generation. Management will continue to monitor changes and opportunities resulting from the integrated energy plan and related legislation. Foreign procurement The Ministry of Energy and Mines is undertaking a consultation on the development of regulations that may limit foreign participation in Ontario’s energy sector. This would place limitations targeting identified foreign actors that may pose a threat to Ontario’s energy infrastructure and may include restrictions on procurement of strategic assets based on country-of-origin, restrictions on foreign ownership of strategic assets, or establishing preferential criteria and scoring for Canadian proponents in energy sector procurements. Management will continue to monitor changes. M2T procurement This spring, the IESO concluded their second medium-term procurement (MT2 RFP), extending contracts with 27 proponents. Capital Power was successful in securing a contract extension for Kingsbridge 1, with a price higher than the weighted average. The procurement offered 5-year flexible deemed energy or capacity contracts to assets coming off existing IESO contracts between May 1, 2026 and April 30, 2029. USE OF JUDGMENTS AND ESTIMATES In preparing the condensed interim consolidated financial statements, management made judgments, estimates and assumptions that affect the application of Capital Power’s accounting policies and the reported amount of assets, liabilities, income and expenses. Actual results may differ from these estimates. There have been no significant changes to Capital Power’s use of judgments and estimates as described in our 2024 Integrated Annual Report. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 38
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FINANCIAL INSTRUMENTS The classification, carrying amounts and fair values of financial instruments held at September 30, 2025 and December 31, 2024 were as follows: ($ millions) September 30, 2025 December 31, 2024 Fair value hierarchy level 1 Carrying amount Fair value Carrying amount Fair value Financial assets: Amortized cost Cash and cash equivalents N/A 204 204 865 865 Trade and other receivables 2 N/A 692 692 546 546 Government grant receivable 3 Level 2 400 391 438 400 Fair value through profit or loss Derivative financial instruments 3 See below 678 678 601 601 Fair value through other comprehensive income Derivative financial instruments 3 See below 32 32 55 55 Financial liabilities: Amortized cost Trade and other payables N/A 768 768 751 751 Loans and borrowings 3 Level 2 6,670 7,008 4,976 5,244 Fair value through profit or loss Derivative financial instruments 3 See below 862 862 621 621 Fair value through other comprehensive income Derivative financial instruments 3 See below 22 22 20 20 1 Fair values for Level 1 financial assets and liabilities are based on unadjusted quoted prices in active markets for identical instruments while fair values for Level 2 financial assets and liabilities are generally based on indirectly observable prices. Level 3 valuations are determined by appropriate subject matter experts and reviewed by the Company’s commodity risk group and by management. 2 Includes income taxes recoverable and excludes current portion of government grant receivable. 3 Includes current and non-current portion. Risk management and hedging activities There have been no material changes in the nine months ended September 30, 2025 to our risk management and hedging activities as described in our 2024 Integrated Annual Report. The derivative financial instruments assets and liabilities held at September 30, 2025 compared with December 31, 2024 and used for risk management purposes were measured at fair value and consisted of the following: ($ millions) At September 30, 2025 Fair value hierarchy level Commodity cash flow hedges Commodity non-hedges Interest rate cash flow hedges Interest rate non-hedges Total Derivative financial instruments assets Level 2 27 585 5 – 617 Level 3 – 93 – – 93 27 678 5 – 710 Derivative financial instruments liabilities Level 2 (2) (590) (20) (2) (614) Level 3 – (270) – (270) (2) (860) (20) (2) (884) Net derivative financial instruments assets (liabilities) 25 (182) (15) (2) (174) Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 39
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($ millions) At December 31, 2024 Fair value hierarchy level Commodity cash flow hedges Commodity non-hedges Interest rate cash flow hedges Foreign exchange cash flow hedges Total Derivative financial instruments assets Level 2 45 465 4 6 520 Level 3 – 136 – – 136 45 601 4 6 656 Derivative financial instruments liabilities Level 2 (4) (329) (16) – (349) Level 3 – (292) – – (292) (4) (621) (16) – (641) Net derivative financial instruments assets (liabilities) 41 (20) (12) 6 15 Commodity, interest rate and foreign exchange derivatives designated as accounting hedges Unrealized gains and losses from fair value changes on commodity, interest rate and foreign exchange derivatives that qualify and are elected for hedge accounting are recorded in other comprehensive income (loss). When realized, they are reclassified to net income as revenues, energy purchases and fuel, finance expense or foreign exchange gains and losses as appropriate. For interest rate derivatives used to hedge the interest rate on a future debt issuance, realized gains or losses are deferred within accumulated other comprehensive income (loss) and recognized within finance expense over the life of the debt, consistent with the interest expense on the hedged debt. For foreign exchange derivatives hedging cash flow variability from foreign currency fluctuations on future capital expenditures, realized gains and losses are also deferred within accumulated other comprehensive income (loss) and then recorded in property, plant and equipment and amortized through depreciation and amortization over the hedged asset’s estimated useful life. Commodity, interest rate and foreign exchange derivatives not designated as accounting hedges The change in fair values of commodity derivatives not designated as hedges is primarily due to changes in forward power, natural gas and REC prices and their impact within the Canada and U.S. flexible generation and renewables portfolios. Unrealized and realized gains and losses for fair value changes on commodity derivatives that do not qualify for hedge accounting are recorded in net income as revenues or energy purchases and fuel. Unrealized and realized gains and losses on foreign exchange derivatives and interest rate derivatives that are not designated as hedges for accounting purposes are recorded in net income as foreign exchange gains or losses and net finance expense, respectively. DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING With the exception of the acquisitions of Hummel Station and Rolling Hills (see Significant Events), which are being integrated into Capital Power’s systems of internal controls, there were no significant changes in Capital Power’s disclosure controls and procedures and internal controls over financial reporting that occurred during the nine months ended September 30, 2025 that have materially affected or are reasonably likely to materially affect disclosures of required information and internal control over financial reporting. In accordance with National Instrument 52-109, management’s evaluation of and conclusions on the effectiveness of internal control over financial reporting did not include the internal controls of the acquired businesses of Hummel Station, LLC and Rolling Hills Generating, LLC. The financial results are included in the Company’s September 30, 2025 consolidated financial statements because these entities were acquired by the Company through a business combination during the second quarter of 2025. The aggregate assets represent 20% o f the Company’s total assets as at September 30, 2025 , and the aggregate liabilities represent 1% of the Company’s total liabilities as at September 30, 2025 . Gross revenue earned from the date of acquisition to September 30, 2025, represents 10% of the Company’s gross revenue, and 17% for the quarter ended September 30, 2025. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 40
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SUMMARY OF QUARTERLY RESULTS Three months ended Sep 2025 Jun 2025 Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Electricity generation (GWh) Canada flexible generation 5,029 3,933 4,799 3,596 4,518 3,417 4,445 4,312 Canada renewables 456 557 597 704 541 696 676 742 U.S. flexible generation 7,550 4,026 3,575 4,540 5,574 3,909 3,116 3,066 U.S. renewables 339 506 584 568 368 581 572 572 Total electricity generation 13,374 9,022 9,555 9,408 11,001 8,603 8,809 8,692 Facility availability (%) Canada flexible generation 95 91 94 87 93 88 93 95 Canada renewables 97 97 96 96 95 97 95 95 U.S. flexible generation 93 96 85 88 96 93 94 89 U.S. renewables 91 89 90 93 88 92 92 95 Total average facility availability 93 93 90 89 94 91 94 93 Revenues and other income ($ millions) Canada flexible generation 533 472 580 523 520 473 677 666 Canada renewables 23 28 30 56 43 54 61 70 U.S. flexible generation 496 213 250 198 286 138 135 84 U.S. renewables 27 37 41 37 31 38 40 39 Corporate 1 5 19 14 9 5 2 3 27 Unrealized changes in fair value of commodity derivatives and emission credits 129 (328) 73 30 145 69 203 98 Total revenues and other income 1,213 441 988 853 1,030 774 1,119 984 Adjusted EBITDA 2 Canada flexible generation 3 181 166 207 200 187 163 179 209 Canada renewables 3 18 27 33 42 27 41 44 56 U.S. flexible generation 3 307 141 119 123 219 128 84 46 U.S. renewables 15 27 31 26 19 29 28 29 Corporate (44) (39) (23) (61) (51) (38) (46) (24) Total adjusted EBITDA 2 477 322 367 330 401 323 289 316 1 Revenues are partially offset by interplant category revenue eliminations. 2 Adjusted EBITDA is a non-GAAP financial measure. See Non-GAAP Financial Measures and Ratios. 3 Canada flexible generation includes adjusted EBITDA from York Energy joint venture. Canada renewables include adjusted EBITDA from Quality Wind and Port Dover and Nanticoke Wind joint ventures. U.S. flexible generation includes adjusted EBITDA from Midland Cogeneration and Harquahala joint ventures. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 41
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Financial highlights ($ millions except per share amounts) Three months ended Sep 2025 Jun 2025 Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Revenues and other income 1,213 441 988 853 1,030 774 1,119 984 Net income (loss) 153 (131) 150 242 178 76 205 95 Net income (loss) attributable to shareholders of the Company 154 (132) 151 240 179 75 205 97 Basic earnings (loss) per share 0.94 (0.92) 1.03 1.76 1.32 0.51 1.58 0.74 Diluted earnings (loss) per share 1 0.94 (0.92) 1.03 1.75 1.32 0.51 1.57 0.74 Adjusted EBITDA 2,3 477 322 367 330 401 323 289 316 AFFO 2 369 235 218 182 315 178 149 165 AFFO per share ($) 2 2.37 1.55 1.57 1.38 2.42 1.37 1.21 1.39 Net cash flows from operating activities 404 143 210 438 236 136 334 (18) Purchase of property, plant and equipment and other assets, net 147 141 288 395 231 226 218 244 1 Diluted earnings (loss) per share was calculated after giving effect to outstanding share purchase options. 2 The consolidated financial highlights, except for adjusted EBITDA, AFFO and AFFO per share were prepared in accordance with GAAP. See Non-GAAP Financial Measures and Ratios. 3 Includes adjusted EBITDA from the York Energy, Midland Cogeneration and Harquahala equity-accounted investments. Quality Wind and Port Dover and Nanticoke Wind were partially divested on December 20, 2024, and then became equity-accounted investments (see Significant Events in the Company’s 2024 Integrated Annual Report). Due to the proximity to December 31, 2024, adjusted EBITDA relating to the equity-accounted investments period during the quarter was immaterial. Quarterly revenues, net income and cash flows from operating activities are affected by seasonal weather conditions, fluctuations in U.S. dollar exchange rates relative to the Canadian dollar, power and natural gas prices, planned and unplanned facility outages and items outside the normal course of operations. Net income (loss) is also affected by changes in the fair value of our power, natural gas, interest rate and foreign exchange derivative contracts. Factors impacting results for the previous quarters Please refer to our 2024 Integrated Annual Report for significant events and items which affected results for the previous quarters. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 42
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SHARE AND PARTNERSHIP UNIT INFORMATION Quarterly common share trading information The Company’s common shares are listed on the Toronto Stock Exchange under the symbol CPX and began trading on June 26, 2009. Three months ended Sep 2025 Jun 2025 Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Share price ($/common share) High 66.06 57.92 64.95 68.73 50.88 41.99 39.43 39.88 Low 54.03 41.87 44.68 49.20 38.33 33.90 35.55 35.11 Close 65.35 54.80 47.83 63.72 49.17 38.99 38.21 37.84 Volume of shares traded (millions) 43.8 48.7 59.2 38.0 28.3 33.5 25.9 26.0 Outstanding share and partnership unit data At October 24, 2025 , the Company had 155.606 million common shares, 5 million Cumulative Rate Reset Preference Shares (Series 1), 6 million Cumulative Rate Reset Preference Shares (Series 3), 8 million Cumulative Rate Reset Preference Shares (Series 5), and one special limited voting share outstanding. Assuming full conversion of the outstanding and issuable share purchase options to common shares and ignoring exercise prices, the outstanding and issuable common shares at October 24, 2025 were 156.818 million. The outstanding special limited voting share is held by EPCOR. At October 24, 2025, CPLP had 323.305 million general partnership units outstanding and 1,203.255 mi llion common limited partnership units outstanding. All of the outstanding general partnership units and the outstanding common limited partnership units are held by the Company. ADDITIONAL INFORMATION Additional information relating to Capital Power Corporation, including the Company’s annual information form and other continuous disclosure documents, is available on SEDAR+ at www.sedarplus.com. Q3-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 43
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Condensed Interim Consolidated Financial Statements of CAPITAL POWER CORPORATION (Unaudited, in millions of Canadian dollars) Nine months ended September 30, 2025 and 2024
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Condensed Interim Consolidated Financial Statements: Condensed Interim Consolidated Statements of Income 46 Condensed Interim Consolidated Statements of Comprehensive Income 47 Condensed Interim Consolidated Statements of Financial Position 48 Condensed Interim Consolidated Statements of Changes in Equity 49 Condensed Interim Consolidated Statements of Cash Flows 51 Notes to the Condensed Interim Consolidated Financial Statements 52 CAPITAL POWER CORPORATION Condensed Interim Consolidated Financial Statements Nine months ended September 30, 2025 and 2024 Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 45
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Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Revenues $ 1,197 $ 1,013 $ 2,559 $ 2,863 Other income 16 17 83 60 Energy purchases and fuel (632) (456) (1,381) (1,342) Gross margin 581 574 1,261 1,581 Other raw materials and operating charges (55) (54) (161) (151) Staff costs and employee benefits expense (48) (51) (142) (150) Depreciation and amortization (157) (124) (421) (366) Other administrative expense (54) (51) (188) (150) Impairment – (27) – (27) Foreign exchange (loss) gain (7) 5 16 (9) Operating income 260 272 365 728 Net finance expense (note 4) (92) (65) (217) (160) Income from equity-accounted investments 25 29 65 64 Loss on disposals and other transactions (5) (5) (12) (20) Income before tax 188 231 201 612 Income tax expense (35) (53) (29) (153) Net income $ 153 $ 178 $ 172 $ 459 Attributable to: Non-controlling interests $ (1) $ (1) $ (1) $ – Shareholders of the Company $ 154 $ 179 $ 173 $ 459 Earnings per share attributable to shareholders of the Company: Basic (note 6) $ 0.94 $ 1.32 $ 1.02 $ 3.39 Diluted (note 6) $ 0.94 $ 1.32 $ 1.01 $ 3.38 See accompanying notes to the condensed interim consolidated financial statements CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Income (Unaudited, in millions of Canadian dollars, except per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 46
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Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Net income $ 153 $ 178 $ 172 $ 459 Other comprehensive income (loss): Items that may be reclassified subsequently to net income: Unrealized gain (loss) on derivative instruments1 (note 7) 1 (8) 7 82 Reclassification of gains on derivative instruments to net income2 (note 7) (5) (9) (23) (17) Equity-accounted investments3 (1) (9) (7) (3) Net investment in foreign subsidiaries: Unrealized gains (losses) 78 (38) (97) 30 Other comprehensive income (loss) for the period, net of tax 73 (64) (120) 92 Total comprehensive income $ 226 $ 114 $ 52 $ 551 Attributable to: Non-controlling interests $ (1) $ (1) $ (1) $ – Shareholders of the Company $ 227 $ 115 $ 53 $ 551 1 For the three and nine months ended September 30, 2025, net of income tax expense of $1 and of $4, respectively. For the three and nine months ended September 30, 2024, net of income tax recovery of $2 and expense of $16, respectively. 2 For the three and nine months ended September 30, 2025, net of reclassification of income tax expense of $2 and $7, respectively. For the three and nine months ended September 30, 2024, net of reclassification of income tax expense of $3 and $5, respectively. 3 For the three and nine months ended September 30, 2025, net of income tax recovery of $1 and $3, respectively. For the three and nine months ended September 30, 2024, net of income tax recovery of $4 and $1, respectively. See accompanying notes to the condensed interim consolidated financial statements CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Comprehensive Income (Unaudited, in millions of Canadian dollars) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 47
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September 30, 2025 December 31, 2024 Assets Current assets: Cash and cash equivalents $ 204 $ 865 Trade and other receivables 588 507 Income taxes recoverable (note 5) 153 97 Inventories 226 235 Derivative financial instruments (note 7) 280 244 1,451 1,948 Non-current assets: Property, plant and equipment (note 3 and 11) 11,155 8,061 Equity-accounted investments 1,081 1,096 Intangible assets and goodwill 637 744 Right-of-use assets 138 118 Derivative financial instruments (note 7) 430 412 Government grants receivable 315 380 Deferred tax assets 37 26 Other assets 101 145 Total assets $ 15,345 $ 12,930 Liabilities and equity Current liabilities: Trade and other payables $ 768 $ 751 Derivative financial instruments (note 7) 269 147 Loans and borrowings (note 8) 710 157 Provisions (note 11) 110 85 Deferred revenue and other liabilities 103 213 1,960 1,353 Non-current liabilities: Derivative financial instruments (note 7) 615 494 Loans and borrowings (note 8) 5,960 4,819 Lease liabilities 155 134 Deferred tax liabilities 915 863 Provisions 425 373 Deferred revenue and other liabilities 307 323 Total liabilities 10,337 8,359 Share capital (note 9) 5,009 4,301 Deficit (222) (74) Other reserves 229 349 Equity attributable to shareholders of the Company 5,016 4,576 Non-controlling interests (8) (5) Total equity 5,008 4,571 Total liabilities and equity $ 15,345 $ 12,930 See accompanying notes to the condensed interim consolidated financial statements CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Financial Position (Unaudited, in millions of Canadian dollars) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 48
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Share capital (note 9) Cash flow hedges1 Cumulative translation reserve1 Defined benefit plan actuarial losses1 Employee benefits reserve Deficit Equity attributable to shareholders of the Company Non- controlling interests Total Balance, January 1, 2025 $ 4,301 $ 108 $ 240 $ (9) $ 10 $ (74) $ 4,576 $ (5) $ 4,571 Net income — — — — — 173 173 (1) 172 Other comprehensive loss — (23) (97) — — — (120) — (120) Total comprehensive income — (23) (97) — — 173 53 (1) 52 Issue of share capital, net2 653 — — — — — 653 — 653 Common share dividends (note 9) — — — — — (299) (299) — (299) Preferred share dividends, net of tax3 (note 9) — — — — — (22) (22) — (22) Dividends reinvested 55 — — — — — 55 — 55 Distributions to non-controlling interests — — — — — — — (2) (2) Balance, September 30, 2025 $ 5,009 $ 85 $ 143 $ (9) $ 10 $ (222) $ 5,016 $ (8) $ 5,008 1 Accumulated other comprehensive income. Other reserves on the statements of financial position are the aggregate of accumulated other comprehensive income and the employee benefits reserve. 2 Net of share issue costs of $29, income tax recovery of $7, and share options exercised of $8. 3 Including income tax expense of $2. See accompanying notes to the condensed interim consolidated financial statements CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Changes in Equity (Unaudited, in millions of Canadian dollars) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 49
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Share capital (note 9) Cash flow hedges1 Cumulative translation reserve1 Defined benefit plan actuarial losses1 Employee benefits reserve Deficit Equity attributable to shareholders of the Company Non- controlling interests Total Balance, January 1, 2024 $ 3,524 $ 48 $ 22 $ (10) $ 10 $ (404) $ 3,190 $ (4) $ 3,186 Net income – – – – – 459 459 – 459 Other comprehensive income – 62 30 – – – 92 – 92 Total comprehensive income – 62 30 – – 459 551 – 551 Issue of share capital, net2 387 – – – – – 387 – 387 Common share dividends (note 9) – – – – – (245) (245) – (245) Preferred share dividends, net of tax3 (note 9) – – – – – (26) (26) – (26) Preferred share redemption (150) – – – – – (150) – (150) Dividends reinvested 50 – – – – – 50 – 50 Share options exercised 15 – – – – – 15 – 15 Distributions to non-controlling interests – – – – – – – (2) (2) Balance, September 30, 2024 $ 3,826 $ 110 $ 52 $ (10) $ 10 $ (216) $ 3,772 $ (6) $ 3,766 1 Accumulated other comprehensive income. Other reserves on the statements of financial position are the aggregate of accumulated other comprehensive loss and the employee benefits reserve. 2 Net of share issue costs of $16 and income tax recovery of $3. 3 Including income tax expense of $2. See accompanying notes to the condensed interim consolidated financial statements CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Changes in Equity (Unaudited, in millions of Canadian dollars) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 50
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Nine months ended September 30, 2025 2024 Cash flows from operating activities: Net income $ 172 $ 459 Non-cash adjustments: Depreciation and amortization 421 366 Net finance expense 217 160 Impairment – 27 Fair value changes on commodity derivative instruments and emission credits held for trading 176 (286) Foreign exchange (gains) losses (16) 9 Income tax expense 29 153 Income from equity-accounted investments (65) (64) Tax-equity attributes (55) (55) Other 26 15 Change in fair value of derivative instruments, cash settlement (7) 17 Distributions received from equity-accounted investments 47 24 Interest paid (202) (132) Income taxes recovered (paid) 14 (17) Other (23) 23 Change in non-cash operating working capital 23 7 Net cash flows from operating activities 757 706 Cash flows used in investing activities: Purchase of property, plant and equipment and other assets, net1 (576) (675) Business acquisition, net of acquired cash (note 3) (2,974) (908) Acquisition of equity-accounted investment – (316) Government grants received 60 50 Other 13 3 Net cash flows used in investing activities (3,477) (1,846) Cash flows from (used in) financing activities: Net proceeds from issue of loans and borrowings2 (note 8) 1,809 1,042 Repayment of loans and borrowings (78) (754) Capitalized interest paid (31) (44) Issue of share capital3 646 6 Dividends paid (note 9) (248) (205) Redemption of preferred shares (note 9) – (150) Income taxes paid on preferred share dividends (8) (10) Other (6) (12) Distributions to non-controlling interests (2) (2) Net cash flows from (used in) financing activities 2,082 (129) Foreign exchange loss on cash held in foreign currency (23) (1) Net decrease in cash and cash equivalents (661) (1,270) Cash and cash equivalents, beginning of period 865 1,423 Cash and cash equivalents, end of period $ 204 $ 153 1 Reflects total additions, increased by $117 for changes in non-cash investing working capital and other non-current assets and liabilities (2024 – reduced by $118). 2 Net of deferred debt issue costs of $15 (2024 - $8). 3 Net of share issue costs of $29 (2024 - $8). See accompanying notes to the condensed interim consolidated financial statements CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Cash Flows (Unaudited, in millions of Canadian dollars) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 51
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1. Reporting entity Capital Power Corporation (the Company or Capital Power) develops, acquires, owns, and operates utility-scale renewable and flexible generation (natural gas generation assets and energy storage) facilities and manages its related electricity and natural gas portfolios by undertaking trading and marketing activities. The registered and head office of the Company is located at 10423 101 Street, Edmonton, Alberta, Canada, T5H 0E9. The common shares of the Company are traded on the Toronto Stock Exchange under the symbol “CPX”. Interim results will fluctuate due to plant maintenance schedules, the seasonal demands for electricity and changes in energy prices. Consequently, interim results are not necessarily indicative of annual results. 2. Basis of presentation and use of judgements and estimates These condensed interim consolidated financial statements have been prepared by management in accordance with International Accounting Standards (IAS) 34, Interim Financial Reporting . The condensed interim consolidated financial statements do not include all of the information required for full annual financial statements and should be read in conjunction with the Company’s 2024 annual consolidated financial statements prepared in accordance with International Financial Reporting Standards (IFRS) Accounting Standards as issued by the International Accounting Standards Board. The accounting policies applied, the significant judgements made, and the key sources of estimation uncertainty are consistent with those described in the Company’s 2024 annual consolidated financial statements, except as described in note 12. These condensed interim consolidated financial statements were approved and authorized for issue by the Board of Directors on October 28, 2025. 3. Business combination Acquisition of Hummel Station, LLC and Rolling Hills Generating, LLC On June 9, 2025, the Company acquired 100% of the equity interests in: 1. Hummel Station, LLC, owner of the 1,124 megawatt (MW) Hummel Station combined-cycle natural gas facility in Shamokin Dam, Pennsylvania; and 2. Rolling Hills Generating, LLC, owner of the 1,023 MW Rolling Hills Generation plant, a combustion turbine natural gas facility in Wilkesville, Ohio. The acquisition expands the Company’s operations into the Pennsylvania-New Jersey-Maryland Interconnection market and adds to its U.S. flexible generation fleet. The total purchase price of the acquisition was $3.0 billion (US$2.2 billion) in total cash consideration, including working capital and other closing adjustments, which are expected to be finalized in the fourth quarter of 2025. The valuation techniques used for measuring the fair value of material assets acquired include significant estimates associated with the depreciated replacement cost approach for property, plant and equipment, which includes estimates of replacement cost and reflects adjustments for physical deterioration as well as functional and economic obsolescence. CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 52
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3. Business combination, continued The preliminary allocation of the purchase price to the assets acquired and liabilities assumed based on their estimated fair values was as follows: June 9, 2025 Cash and cash equivalents $ 1 Trade and other receivables1 21 Inventories 15 Property, plant and equipment 3,003 Right-of-use asset 30 Other assets 12 Trade and other payables (19) Derivative financial instrument liabilities (7) Lease liabilities (30) Provisions (52) Fair value of net assets acquired $ 2,974 1 The fair value of trade and other receivables approximates the carrying value. The preliminary purchase price allocation reflects management’s best estimate of the fair value of assets acquired and liabilities assumed based on the information obtained and analysis performed to date. Management continues to obtain specific information to support the valuation of working capital, property, plant and equipment, intangible assets and provisions. If new information obtained within one year after the acquisition date about facts and circumstances that existed at the acquisition date identifies adjustments to the above amounts, or any additional provisions that existed at the date of acquisition, then the accounting for the acquisition will be revised. The Company assumed a provision to return a portion of amounts previously received by Hummel Station, LLC, from the Federal Energy Regulatory Commission (FERC) for reactive supply and voltage control from generation sources service overpayments in the estimated amount of $34 million, included in provisions. The payment will be due eighteen months after final acceptance from FERC is received. Provisions also include decommissioning provisions of $18 million. Revenues and net income from the date of acquisition to September 30, 2025 , were $268 million and $113 million, respectively. If the acquisition had occurred on January 1, 2025, consolidated revenues and consolidated net income would have been $3,109 million and $302 million, respectively.. For the nine months ended September 30, 2025 , the Company incurred acquisition costs of $43 million which were recorded on the Company’s consolidated statements of income primarily as other administrative expense. CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 53
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4. Net finance expense Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Interest expense Interest on loans and borrowings $ 93 $ 72 $ 239 $ 200 Capitalized interest (10) (14) (31) (44) Total interest expense 83 58 208 156 Other finance expense (income) Accretion on decommissioning provisions 4 3 9 8 Interest on lease liabilities 2 1 8 7 Interest on government grants receivable (2) (2) (6) (7) Other 5 5 (2) (4) Net finance expense $ 92 $ 65 $ 217 $ 160 5. Income tax Income tax expense differs from the amount that would be computed by applying the federal and provincial income tax rates as a result of the following: Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Net income before tax $ 188 $ 231 $ 201 $ 612 Income tax at the statutory rate of 23% 43 53 46 141 Increase (decrease) resulting from: Non-deductible expenses and non-taxable income 4 (4) – 3 Amounts attributable to non-controlling interests, equity-accounted investments, and tax-equity interests (7) – (14) (5) Change in unrecognized tax benefits – 2 – (3) Statutory and other rate differences 5 4 2 10 Other (10) (2) (5) 7 Income tax expense $ 35 $ 53 $ 29 $ 153 During the second quarter of 2025, there was a reclassification of $36 million from other assets to income taxes recoverable resulting from the filing of a portion of the expected Clean Technology investment tax credit claim with the Canada Revenue Agency for the 2024 taxation year. CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 54
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6. Earnings per share The earnings and weighted average number of common shares used in the calculation of basic and diluted earnings per share were as follows: Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Earnings for the period attributable to shareholders $ 154 $ 179 $ 173 $ 459 Preferred share dividends1 (8) (7) (22) (26) Earnings available to common shareholders $ 146 $ 172 $ 151 $ 433 Weighted average number of common shares 155,349,949 130,269,528 148,642,287 127,837,004 Basic earnings per share $ 0.94 $ 1.32 $ 1.02 $ 3.39 Weighted average number of common shares 155,349,949 130,269,528 148,642,287 127,837,004 Effect of dilutive share purchase options 424,617 265,218 346,508 229,713 Diluted weighted average number of common shares 155,774,566 130,534,746 148,988,795 128,066,717 Diluted earnings per share $ 0.94 $ 1.32 $ 1.01 $ 3.38 1 Includes preferred share dividends declared and related taxes. 7. Derivative financial instruments and hedge accounting Derivative financial and non-financial instruments are held for the purpose of energy and natural gas purchases, merchant trading or financial risk management. The Company has elected to apply hedge accounting to certain derivatives used to manage commodity price risk relating to electricity prices, interest rate risk relating to future borrowings, and foreign exchange risk relating to future capital investment in U.S. dollars. The derivative instruments assets and liabilities used for risk management purposes consist of the following: September 30, 2025 Energy and emission allowances Interest rate Foreign exchange cash flow hedges non- hedges cash flow hedges non- hedges cash flow hedges Total Derivative instruments assets: Current $ 19 $ 260 $ 1 $ – $ – $ 280 Non-current 8 418 4 – – 430 Derivative instruments liabilities: Current (1) (260) (8) – – (269) Non-current (1) (600) (12) (2) – (615) Net fair value $ 25 $ (182) $ (15) $ (2) $ – $ (174) Net notional buys (sells) (millions): Megawatt hours of electricity (3) (77) Gigajoules of natural gas purchased1 524 Gigajoules of natural gas basis swaps 58 Metric tonnes of emission allowances 7 Number of renewable energy credits (8) Interest rate swaps $ 1,418 $ 174 Forward currency buys (U.S. dollars) $ 10 Range of remaining contract terms (years) 0.1 to 3.3 0.1 to 21.3 0.1 to 3.0 0.1 to 2.8 0.1 to 0.3 1 Added 179 Gigajoules as part of the acquisition of Hummel Station, LL C and Rolling Hills Generating, LLC (note 3). CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 55
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7. Derivative financial instruments and hedge accounting, continued December 31, 2024 Energy and emission allowances Interest rate Foreign exchange cash flow hedges non- hedges cash flow hedges non- hedges cash flow hedges Total Derivative instruments assets: Current $ 28 $ 208 $ 2 $ – $ 6 $ 244 Non-current 17 393 2 – – 412 Derivative instruments liabilities: Current (2) (138) (7) – – (147) Non-current (2) (483) (9) – – (494) Net fair value $ 41 $ (20) $ (12) $ – $ 6 $ 15 Net notional buys (sells) (millions): Megawatt hours of electricity (3) (49) Gigajoules of natural gas purchased 197 Gigajoules of natural gas basis swaps 63 Metric tonnes of emission allowances 10 Number of renewable energy credits (11) Interest rate swaps $ 800 $ 94 Forward currency buys (U.S. dollars) $ 84 Range of remaining contract terms (years) 0.1 to 4.0 0.1 to 22.0 0.1 to 2.1 0.2 to 1.0 0.1 to 0.6 CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 56
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7. Derivative financial instruments and hedge accounting, continued Unrealized and realized pre-tax gains and (losses) on derivative instruments recognized in other comprehensive income (loss) and net income (loss) are as follows: Three months ended September 30, 2025 Three months ended September 30, 2024 Unrealized gains (losses) Realized gains (losses) Unrealized gains (losses) Realized gains Energy cash flow hedges $ – $ 6 $ 6 $ 8 Energy and emission allowances non-hedges 3 68 68 37 Interest rate cash flow hedges (6) 4 (25) 4 Interest rate non-hedges (1) – (1) – Foreign exchange cash flow hedges 1 (3) (3) – Foreign exchange non-hedges – 11 – – Nine months ended September 30, 2025 Nine months ended September 30, 2024 Unrealized (losses) gains Realized gains (losses) Unrealized gains (losses) Realized gains (losses) Energy cash flow hedges $ (18) $ 23 $ 60 $ 11 Energy and emission allowances non-hedges (169) 183 287 57 Interest rate cash flow hedges 4 10 (11) 11 Interest rate non-hedges (1) – (1) – Foreign exchange cash flow hedges (5) (3) 27 – Foreign exchange non-hedges – – – (2) The following realized and unrealized gains and losses on derivative financial instruments are included in the Company’s statements of income: Three months ended September 30, Nine months ended September 30, 2025 2024 2025 2024 Revenues $ 311 $ 285 $ 300 $ 644 Energy purchases and fuel (234) (172) (263) (289) Foreign exchange gain (loss) 8 – (3) (2) Net finance expense 3 3 9 10 Net after tax gains and losses related to derivative instruments designated as energy and interest rate cash flow hedges are expected to settle and be reclassified to net income in the following periods: September 30, 2025 Within one year $ 43 Between one and five years 48 After five years 17 $ 108 CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 57
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8. Loans and borrowings Private offering of senior notes On May 28, 2025, the Company closed a private offering of $1.7 billion (US$1.2 billion) aggregate principal amount of senior notes (the offering), guaranteed by the Company and certain of the Company’s subsidiaries. The offering consisted of $966 million (US$700 million) aggregate principal amount of 5.257% senior notes due 2028 and $690 million (US$500 million) aggregate principal amount of 6.189% senior notes due 2035. Credit facilities On August 8, 2025, the Company entered into a 2-year revolving credit agreement with a total commitment of $600 million, maturing in 2027. The funds can be drawn in Canadian or US dollars. Interest is floating and is based on the type of draw, plus margin. On June 6, 2025, the Company amended the terms of its syndicated credit facility and terminated its $300 million unsecured club credit facility. The amendments to the syndicated credit facility included an increase to the maximum principal amount from $700 million to $1.5 billion, an extension of one year to June 2030, and a change to the modified consolidated net tangible assets to consolidated net tangible assets ratio covenant to be based on total assets. No amounts were drawn on the facilities at the time of the amendment. On April 14, 2025, in anticipation of the acquisition (note 3), the Company entered into a commitment letter with TD Securities Inc. for fully underwritten $2 billion senior unsecured term loans. As the Company amended the terms of its syndicated credit facility, the commitment letter was no longer required and has been terminated. 9. Share capital Issued and fully paid shares On April 22, 2025, the Company completed a bought deal offering of 11,902,500 common shares and 3,455,000 common shares on a private placement basis, at an offering price of $43.45 per common share for total gross proceeds of approximately $667 million. Common and preferred share dividends Dividends declared For the three months ended September 30, For the nine months ended September 30, 2025 2024 2025 2024 Per share Total Per share Total Per share Total Per share Total Common $ 0.6910 $ 107 $ 0.6519 $ 86 $ 1.9948 $ 299 $ 1.8819 $ 245 Preference: Series 1 0.1638 1 0.1638 1 0.4914 3 0.4914 3 Series 3 0.4288 3 0.4288 2 1.2863 8 1.2863 8 Series 5 0.4144 3 0.4144 3 1.2433 9 1.2433 9 Series 111 – – – – – – 0.7188 4 1 On June 30, 2024, the Company redeemed all of its issued and outstanding 5.75% cumulative rate reset preference shares, Series 11. The final quarterly dividend was paid on the redemption date. Dividends paid2 For the three months ended September 30, For the nine months ended September 30, 2025 2024 2025 2024 Per share Total Per share Total Per share Total Per share Total Common3 $ 0.6519 $ 101 $ 0.6150 $ 80 $ 1.9557 $ 283 $ 1.8450 $ 231 2 Preference share dividends are declared and paid in the same period. 3 For the nine months ended September 30, 2025 common dividends consist of $228 million paid in cash and $55 million through the Company’s dividend re-investment plan ( nine months ended September 30, 2024 , $181 million paid in cash and $50 million through the Company’s dividend re-investment plan). CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 58
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9. Share capital, continued Dividend Increase On July 29, 2025, the Company’s Board of Directors approved an increase of 6% in the annual dividend for holders of its common shares, from $0.6519 per common share to $0.6910 per common share. This increased common share dividend will commence with the third quarter 2025 quarterly dividend payment on October 31, 2025 to shareholders of record at the close of business on September 29, 2025. 10. Financial Instruments Fair values The Company classifies and measures its cash and cash equivalents, trade and other receivables, and trade and other payables at amortized cost and their fair values are not materially different from their carrying amounts due to their short-term nature. The classification, carrying amount and fair value of the Company’s other financial instruments are summarized as follows: September 30, 2025 December 31, 2024 Fair value hierarchy level Carrying amount Fair value Carrying amount Fair value Financial assets1 Government grants receivable2 Level 2 $ 400 $ 391 $ 438 $ 400 Financial liabilities1 Loans and borrowings Level 2 $ 6,670 $ 7,008 $ 4,976 $ 5,244 1 Includes current portion. 2 Government grants receivable includes $ 229 million related to off-coal compensation from the Government of Alberta (GoA). As described in the Company’s 2024 annual consolidated financial statements, the GoA previously withheld approximately $2.7 million from each of the payments from 2017 to 2024, which the Company disputed. The annual payment amounts recorded by the Company were previously reduced by $1.5 million for 2017 to 2024. During the second quarter of 2025, the Company settled the disputed amounts with the GoA and received a cash payment of $10 million, which resulted in a decrease to the amount previously recorded of approximately $5 million, recorded through loss on disposals and other transactions. Fair value hierarchy Fair value represents the Company’s estimate of the price at which a financial instrument could be sold or transferred between market participants in an orderly transaction at the measurement date. Fair value measurements recognized in the consolidated statements of financial position are categorized into levels within the fair value hierarchy based on the nature of the valuation inputs, and precedence is given to observable inputs over unobservable inputs. The determination of fair value requires judgment and is based on market information where available and appropriate. The valuation techniques used by the Company in determining the fair value of its financial instruments are the same as those used at December 31, 2024. Fair value measurements are categorized into levels based upon the lowest level of significant input, as described in the Company’s 2024 annual consolidated financial statements. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment. The Company recognizes transfers between levels of the fair value hierarchy at the end of the reporting period during which the change has occurred. There were no transfers between Level 1 and Level 2. The table below presents the Company’s financial instruments measured at fair value on a recurring basis in the consolidated statements of financial position, classified using the fair value hierarchy described in the Company’s 2024 annual consolidated financial statements. CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 59
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10. Financial Instruments, continued September 30, 2025 Level 1 Level 2 Level 3 Total Derivative financial instruments assets $ – $ 617 $ 93 $ 710 Derivative financial instruments liabilities – (614) (270) (884) December 31, 2024 Level 1 Level 2 Level 3 Total Derivative financial instruments assets $ – $ 520 $ 136 $ 656 Derivative financial instruments liabilities – (349) (292) (641) Fair values of derivative instruments are determined using valuation techniques, inputs, and assumptions as described in the Company’s 2024 annual consolidated financial statements. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material. Valuation techniques used in Level 3 fair value measurements The Company has various commodity, renewable energy agreements, and renewable energy credit (REC) contracts with terms that extend beyond a liquid trading period. Certain of these contracts include notional quantities based on future actual generation of underlying generation facilities. As forward market prices and actual generation are not available for the full period of these contracts, their fair values are derived using forecasts based on internal modelling and as a result, are classified as Level 3 fair value measurements. The fair values of the Company’s commodity derivatives classified as Level 3 are determined by applying mark-to- forecast models. The valuation models used to calculate the fair values of the derivative financial instrument assets and liabilities within Level 3 are prepared by internal subject matter experts and are reviewed by the Company’s commodity risk group and management. The valuation techniques and the associated inputs are assessed on a regular basis for ongoing reasonability. The table below presents ranges for the Company’s Level 3 inputs: September 30, 2025 December 31, 2024 REC pricing (per certificate) – Solar $3 to $261 $3 to $201 REC pricing (per certificate) – Wind $3 to $6 $3 to $8 Forward power pricing (per MWh) – Solar $21 to $165 $15 to $113 Forward power pricing (per MWh) – Wind $16 to $103 $15 to $142 Average monthly notional generation (MWh) – Solar 6,503 to 12,892 6,554 to 13,044 Average monthly notional generation (MWh) – Wind 16,077 to 61,348 16,540 to 60,060 The table below presents the change to the fair value of Level 3 derivative instruments based on a 10% change in the respective input: September 30, 2025 December 31, 2024 REC pricing – Solar $ 1 $ 2 REC pricing – Wind 2 4 Forward power pricing – Solar 15 4 Forward power pricing – Wind 42 59 Generation – Solar – 4 Generation – Wind 10 13 CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 60
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10. Financial instruments, continued Continuity of Level 3 balances The Company classifies financial instruments in Level 3 of the fair value hierarchy when there is at least one significant unobservable input used in the valuation model. In addition to these unobservable inputs, the valuation model for Level 3 instruments also relies on a number of inputs that are observable either directly or indirectly. Accordingly, the unrealized gains and losses shown below include changes in the fair value related to both observable and unobservable inputs. The following table summarizes the changes in the fair value of financial instruments classified in Level 3: September 30, 2025 December 31, 2024 At January 11 $ (156) $ (297) Additions (12) 27 Unrealized and realized (losses) gains included in net income2 (46) 137 Settlements 32 (15) Transfers3 – 1 Foreign exchange gains (losses) 5 (9) At end of period $ (177) $ (156) 1 The fair value of derivative instruments assets and liabilities are presented on a net basis. 2 Recorded in revenues. 3 Relates to transfers from Level 3 to Level 2 when pricing inputs become readily observable. There were no transfers from Level 2 to Level 3. Gains and losses associated with Level 3 balances may not necessarily reflect the underlying exposures of the Company. As a result, unrealized gains and losses from Level 3 financial instruments are often offset by unrealized gains and losses on financial instruments that are classified in other levels. 11. Commitments and contingencies The Company and its subsidiaries are subject to various legal claims that arise in the normal course of business. Management believes that the aggregate contingent liability of the Company arising from these claims is immaterial. A dispute arose in 2024 between the Company and the contractor regarding construction work on the Genesee Repowering project. The parties are participating in an arbitration process to resolve the claims by both parties. The Company has withheld payments pending the resolution of the dispute. Preliminary matters related to the arbitration process began late in the second quarter of 2025. 12. Segment information The Company reassessed its reportable segments due to changes in internal reporting for performance results provided to the Company's Chief Operating Decision Maker (CODM). Comparative segment information has been restated to conform to the current period’s presentation. The Company identifies its reportable segments both by business activity and by geographical areas and has four reportable segments described below: • Flexible generation – Flexible generation refers to the ability of power-generating facilities to quickly adjust output based on grid demand. These dispatchable power sources include natural gas facilities and energy storage. Reportable segments associated with this activity include Canada flexible generation, and U.S. flexible generation. The Company actively trades in North American power, natural gas and environmental markets. The majority of the Company’s trading activities relate directly to assets or portfolios of assets within the flexible generation segments and accordingly are reported within these segments. Specifically, trading related to Alberta flexible generation portfolio of assets is included within Canada flexible generation, and trading to optimize U.S. facilities as well as other U.S. trading is included within U.S. flexible generation. • Renewables – Renewable generation includes the Company's wind and solar facilities. Reportable segments associated with this activity include Canada renewables and U.S. renewables. CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 61
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12. Segment information, continued Corporate includes costs of support services such as treasury, finance, internal audit, legal, people services, enterprise risk management, asset management, and environment, health and safety. The following tables provide each reportable segment's results in the format that the Company's CODM reviews in making operating decisions and assessing performance. The CODM assesses the performance of the operating segments based on adjusted EBITDA, which reflects earnings before net finance expense, income tax expense, depreciation and amortization, impairments, foreign exchange gains or losses, finance expense and depreciation from our joint venture interests, gains or losses on disposals, unrealized changes in fair value of commodity derivatives and emission credits, and other items that are not reflective of the long-term performance of the Company's underlying business. The tables below show the reconciliation of the total segment adjusted EBITDA to income before tax, as reported under IFRS. Three months ended September 30, 2025 Canada flexible generation1 Canada renewables1 U.S. flexible generation1 U.S. renewables Corporate Total Equity- accounted investments1 Reclass adjustments Consolidated IFRS financials Revenues and other income $ 538 $ 18 $ 778 $ 9 $ 5 $ 1,348 $ (135) $ – $ 1,213 Energy purchases and fuel (327) (2) (354) (3) – (686) 54 – (632) Other raw materials and operating charges (20) (6) (32) (5) (1) (64) 9 – (55) Staff costs and employee benefits expense (10) – (8) (1) (33) (52) 4 – (48) Other administrative expense (14) (5) (18) (4) (19) (60) 6 – (54) Remove unrealized changes in fair value of commodity derivatives 14 13 (59) 19 – (13) – 13 – Remove other non- recurring items – – – – 4 4 – (4) – Adjusted EBITDA2 181 18 307 15 (44) 477 Depreciation and amortization (157) Foreign exchange loss (7) Losses on disposals and other transactions (5) Net finance expense (92) Income from equity- accounted investments 25 Income before tax $ 188 CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 62
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12. Segment information, continued Three months ended September 30, 2024 Canada flexible generation1 Canada renewables1 U.S. flexible generation1 U.S. renewables Corporate Total Equity- accounted investments1 Reclass adjustments Consolidated IFRS financials Revenues and other income $ 550 $ 44 $ 462 $ 85 $ 5 $ 1,146 $ (116) $ – $ 1,030 Energy purchases and fuel (310) (1) (179) (1) – (491) 35 – (456) Other raw materials and operating charges (24) (8) (23) (6) (1) (62) 8 – (54) Staff costs and employee benefits expense (13) – (8) – (33) (54) 3 – (51) Other administrative expense (14) (6) (12) (6) (22) (60) 9 – (51) Remove unrealized changes in fair value of commodity derivatives (2) (2) (21) (53) – (78) – 78 – Adjusted EBITDA2 187 27 219 19 (51) 401 Depreciation and amortization (124) Impairments (27) Foreign exchange gain 5 Loss on disposals and other transactions (5) Net finance expense (65) Income from equity- accounted investments 29 Income before tax $ 231 CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 63
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12. Segment information, continued Nine months ended September 30, 2025 Canada flexible generation1 Canada renewables1 U.S. flexible generation1 U.S. renewables Corporate Total Equity- accounted investments1 Reclass adjustments Consolidated IFRS financials Revenues and other income $ 1,517 $ 76 $ 1,294 $ 124 $ 36 $ 3,047 $ (405) $ – $ 2,642 Energy purchases and fuel (911) (5) (638) 3 – (1,551) 170 – (1,381) Other raw materials and operating charges (61) (18) (89) (14) (5) (187) 26 – (161) Staff costs and employee benefits expense (37) (2) (27) (2) (86) (154) 12 – (142) Other administrative expense (43) (13) (47) (15) (92) (210) 22 – (188) Remove unrealized changes in fair value of commodity derivatives 85 40 74 (23) – 176 – (176) – Remove other non- recurring items3 4 – – – 41 45 – (45) – Adjusted EBITDA2 554 78 567 73 (106) 1,166 Depreciation and amortization (421) Foreign exchange gain 16 Losses on disposals and other transactions (12) Net finance expense (217) Income from equity- accounted investments 65 Income before tax $ 201 CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 64
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12. Segment information, continued Nine months ended September 30, 2024 Canada flexible generation1 Canada renewables1 U.S. flexible generation1 U.S. renewables Corporate Total Equity- accounted investments1 Reclass adjustments Consolidated IFRS financials Revenues and other income $ 1,871 $ 278 $ 953 $ 138 $ 8 $ 3,248 $ (325) $ – $ 2,923 Energy purchases and fuel (1,065) (11) (377) (2) – (1,455) 113 – (1,342) Other raw materials and operating charges (69) (22) (66) (15) (2) (174) 23 – (151) Staff costs and employee benefits expense (42) (1) (22) (1) (92) (158) 8 – (150) Other administrative expense (44) (16) (38) (19) (59) (176) 26 – (150) Remove unrealized changes in fair value of commodity derivatives (126) (116) (19) (25) – (286) – 286 – Remove other non- recurring items 4 – – – 10 14 – (14) – Adjusted EBITDA2 529 112 431 76 (135) 1,013 Depreciation and amortization (366) Impairments (27) Foreign exchange loss (9) Loss on disposals and other transactions (20) Net finance expense (160) Income from equity- accounted investments 64 Income before tax $ 612 1 For internal reporting purposes, adjusted EBITDA from the Company's equity-accounted investments has been presented on a proportionate basis that reflects the Company's share of each investee's earnings on a line-by- line basis. These amounts are reported within Canada flexible generation for York Energy, Canada renewables for Quality Wind and Port Dover Nanticoke Wind (from the time of the sell-down on December 20, 2024 onwards), and U.S. flexible generation for MCV Partners LLC and Harquahala. Proportionate financial information is not, and is not intended to be, presented in accordance with IFRS. Under IFRS, these investments have been accounted for as joint ventures using the equity method. 2 Adjusted EBITDA is not defined and has no standardized meaning under IFRS. 3 Includes acquisition and integration costs of $41 million for the acquisition of Hummel Station, LLC and Rolling Hills Generating, LLC (note 3). CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 65
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12. Segment information, continued Additional geographic information The Company’s Canadian facilities are located in Alberta, British Columbia and Ontario and its U.S. facilities in Alabama, Arizona, California, Illinois, Kansas, Michigan, New Mexico, North Carolina, North Dakota, Ohio, Pennsylvania, Texas and Washington. The Company also holds a portfolio of wind and solar development sites in Canada and the U.S. Select non-current assets within each geographic area are: At September 30, 2025 At December 31, 2024 Canada U.S. Total Canada U.S. Total Property, plant and equipment $ 5,580 $ 5,575 $ 11,155 $ 5,457 $ 2,604 $ 8,061 Equity-accounted investments 395 686 1,081 397 699 1,096 Intangible assets and goodwill 435 202 637 519 225 744 Right-of-use assets 50 88 138 54 64 118 Other assets4 63 53 116 73 84 157 $ 6,523 $ 6,604 $ 13,127 $ 6,500 $ 3,676 $ 10,176 4 Includes current portion of finance lease receivable. Major customer For the three and nine months ended September 30, 2025, the Company recorded revenues of $180 million and $461 million, respectively, from the Alberta Electric System Operator, within the Canada flexible generation and Canada renewables segments ( three and nine months ended September 30, 2024 - $176 million and $637 million, respectively) and $210 million and $265 million from PJM, within the U.S. flexible generation segment (three and nine months ended September 30, 2024 - nil). There were no other entities that accounted for more than 10 percent of the Company’s total revenues. Disaggregation of revenues from contracts with customers The Company’s revenues from contracts with customers are disaggregated by major type of revenues and operating segments: Three months ended September 30, 2025 Canada flexible generation Canada renewables U.S. flexible generation U.S. renewables Total from contracts with customers Other sources Total Energy revenues $ 454 $ 19 $ 351 $ 13 $ 837 $ 350 $ 1,187 Emission credit revenues – 10 – 1 11 (1) 10 Total revenues5 $ 454 $ 29 $ 351 $ 14 $ 848 $ 349 $ 1,197 Nine months ended September 30, 2025 Canada flexible generation Canada renewables U.S. flexible generation U.S. renewables Total from contracts with customers Other sources Total Energy revenues $ 1,293 $ 58 $ 652 $ 48 $ 2,051 $ 465 $ 2,516 Emission credit revenues – 35 – 3 38 5 43 Total revenues5 $ 1,293 $ 93 $ 652 $ 51 $ 2,089 $ 470 $ 2,559 CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 66
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12. Segment information, continued Three months ended September 30, 2024 Canada flexible generation Canada renewables U.S. flexible generation U.S. renewables Total from contracts with customers Other sources Total Energy revenues $ 436 $ 30 $ 115 $ 10 $ 591 $ 410 $ 1,001 Emission credit revenues – 10 – 1 11 1 12 Total revenues5 $ 436 $ 40 $ 115 $ 11 $ 602 $ 411 $ 1,013 Nine months ended September 30, 2024 Canada flexible generation Canada renewables U.S. flexible generation U.S. renewables Total from contracts with customers Other sources Total Energy revenues $ 1,436 $ 116 $ 298 $ 37 $ 1,887 $ 914 $ 2,801 Emission credit revenues – 32 – 3 35 27 62 Total revenues5 $ 1,436 $ 148 $ 298 $ 40 $ 1,922 $ 941 $ 2,863 5 Included within trade and other receivables at September 30, 2025 , were amounts related to contracts with customers of $312 million (2024 - $290 million). 13. Comparative figures The comparative figures have been reclassified to conform with the presentation adopted for 2025. CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements September 30, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q3-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 67