Earnings release
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Capital Power Corporation 10423 – 101 Street NW Suite 1200 Edmonton, AB T5H 0E9 mm Capital Power announces strong first quarter 2025 results Strong quarterly results driven by enhanced portfolio diversification EDMONTON, Alberta – April 30, 2025 – Capital Power Corporation (TSX: CPX) today released financial results for the quarter ended March 31, 2025. Highlights • Entered into a definitive agreement to acquire two natural gas-fired power generation facilities located in the PJM1 market for ~$3.0 billion (US $2.2 billion), adding ~2.2 GW of capacity to our U.S. flexible generation2 portfolio • Continued progressing five Ontario growth projects to add ~350 MW of long-term contracted capacity • Commenced construction of the Hornet Solar project in North Carolina • Generated adjusted funds from operations (AFFO) of $218 million and net cash flows from operating activities of $210 million • Generated adjusted EBITDA of $367 million and a net income of $150 million “By adding the Hummel and Rolling Hills generating assets and expanding into PJM, we are driving long-term cash flow per share growth, superior diversification of our portfolio and enhanced our positioning for the future. Our existing assets continue to see strong generation driven by long-term fundamentals that underpin our strategy. This supports our thesis that natural gas-fired assets are critical to reliability, provide opportunity for growth and creation of shareholder value in various market conditions,” said Avik Dey, President and CEO of Capital Power. “Our financial results and portfolio growth demonstrate the prudence of our strategy. We continue to grow our portfolio with a focus on geographic diversification, and pro-active risk management and maintenance of our investment grade credit rating. These efforts stabilize our cash flows through market cycles and, along with the dividend, continue to offer a compelling total return for our shareholders,” stated Sandra Haskins, SVP Finance and CFO of Capital Power. 1 Pennsylvania-New Jersey-Maryland Interconnection. 2 Flexible generation is defined as natural gas generation assets and energy storage business. For immediate release April 30, 2025
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2 Operational and Financial Highlights1 ($ millions, except per share amounts) Three months ended March 31 2025 2024 Electricity generation (Gigawatt hours) 9,555 8,809 Generation facility availability 90% 94% Revenues and other income $ 988 $ 1,119 Adjusted EBITDA 2 $ 367 $ 279 Net income 3 $ 150 $ 205 Net income attributable to shareholders of the Company $ 151 $ 205 Basic earnings per share $ 1.03 $ 1.58 Diluted earnings per share $ 1.03 $ 1.57 Net cash flows from operating activities $ 210 $ 334 AFFO 2 $ 218 $ 142 AFFO per share 2 $ 1.57 $ 1.15 Purchase of property, plant and equipment and other assets , net $ 288 $ 218 Dividends per common share, declared $ 0.6519 $ 0.6150 1 The operational and financial highlights in this press release should be read in conjunction with the Management’s Discussion and Analysis and the audited condensed interim financial statements for the three months ended March 31, 2025. 2 Earnings before net finance expense, income tax expense, depreciation and amortization, impairments, foreign exchange gains o r losses, finance expense and depreciation expense from joint venture interests, gains or losses on disposals and other transactions and unrealized changes in fair value of commodity derivatives and emissions credits and other items that are not reflective of the long-term performance of the Company’s underlying business (adjusted EBITDA) and AFFO are used as non-GAAP financial measures by the Company. The Company also uses AFFO per share which is a non-GAAP ratio. These measures and ratios do not have standardized meanings under GAAP and are, therefore, unlikely to be comparable to similar measures used by other enterprises. See Non-GAAP Financial Measures and Ratios. 3 Includes depreciation and amortization for the three months ended March 31, 2025 and 2024 of $126 million and $122 million, respectively. Forecasted depreciation and amortization for the remainder of 2025 is $129 million per quarter. Subsequent Events Acquisition of Hummel Station Intermediate Holdings III, LLC and Rolling Hills Generating Holdings, LLC Consistent with the Company’s strategy to acquire flexible generation assets in the U.S, on April 14, 2025, Capital Power entered into a definitive agreement with Hummel Station Intermediate Holdings III, LLC and Rolling Hills Generating Holdings, LLC, each a subsidiary of LS Power Equity Advisors, LLC, to acquire 100% of the equity interests in: 1. Hummel Station, LLC, which owns the 1,124 MW Hummel Station, a combined-cycle natural gas facility in Shamokin Dam, Pennsylvania (Hummel Acquisition), and 2. Rolling Hills Generating, L.L.C., which owns the 1,023 MW Rolling Hills plant, a combustion turbine natural gas facility in Wilkesville, Ohio (Rolling Hills Acquisition and together with the Hummel Acquisition, the Acquisition). The total purchase price of the Acquisition is expected to be approximately ~$3.0 billion (US$2.2 billion), subject to customary post-closing adjustments, including working capital and estimated transaction expenses. The Acquisition is expected to close in the third quarter of 2025, subject to regulatory approvals and other customary closing conditions. Capital Power will finance the Acquisition using the net proceeds from its concurrent common share offering, outlined in further detail below, and a combination of some or all of the following (i) cash on hand from a prior equity issuance and asset divestitures; (ii) longer term debt financing; (iii) other immediately available funds, including potential draws under Capital Power’s existing credit facilities; and (iv) funding provided under Acquisition Term Loan Facilities, described in further detail below. This funding plan maintains Capital Power’s investment grade credit rating and preserves its strong balance sheet and financial flexibility. Common share offering On April 22, 2025, the Company completed a public offering of 11,902,500 common shares, which included 1,552,500 common shares issued pursuant to the full exercise of the over-allotment option, at $43.45 per common share (Offering Price) for total gross proceeds of approximately $517 million. The Company also issued 3,455,000 common shares at the Offering Price on a private placement basis, for gross proceeds of $150 million, subject to a statutory hold period of 4 months and one day from the closing date of the private placement.
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3 Acquisition Term Loan Facilities For purposes of financing the Acquisition, the Company entered into an agreement with a lender on April 14, 2025, whereby the lender has agreed to provide, on a fully underwritten basis, senior unsecured term loan facilities in the aggregate principal amount of up to $2 billion (Acquisition Term Loan Facilities). The Acquisition Term Loan Facilities are comprised of two tranches of $1 billion non-extendible, non-revolving, syndicated term credit facilities, with the first tranche maturing in 2028 and the second tranche maturing in 2027. Analyst conference call and webcast Capital Power will be hosting a conference call and live webcast with analysts on April 30, 2025 at 9:00 am (MT) to discuss the first quarter financial results. The webcast can be accessed at: https://edge.media- server.com/mmc/p/msjz5xzh/. 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. Non-GAAP Financial Measures and Ratios Capital Power uses (i) earnings before net finance expense, income tax expense, depreciation and amortization, impairments, foreign exchange gains or losses, finance expense and depreciation expense from our joint venture interests, gains or losses on disposals and other transactions and unrealized changes in fair value of commodity derivatives and emission credits (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.
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4 Adjusted EBITDA 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 and other items that are not reflective of the long-term performance of the Company’s underlying business. A reconciliation of adjusted EBITDA to net income is as follows: ($ millions) Three months ended Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Sep 2023 Jun 2023 Revenues and other income 988 853 1,030 774 1,119 984 1,150 881 Energy purchases and fuel, other raw materials and operating charges, staff costs and employee benefits expense, and other administrative expense (628) (658) (612) (504) (677) (694) (626) (614) Remove unrealized changes in fair value of commodity derivatives and emission credits (58) 48 (78) (8) (200) (14) (151) 23 Remove other non-recurring items 1 4 43 - 4 - 1 4 - Adjusted EBITDA from joint ventures 2 61 44 61 57 37 36 37 37 Adjusted EBITDA 367 330 401 323 279 313 414 327 Depreciation and amortization (126) (137) (124) (120) (122) (142) (148) (143) Unrealized changes in fair value of commodity derivatives and emission credits 58 (48) 78 8 200 14 151 (23) Other non-recurring items (4) (43) - (4) - (1) (4) - Impairment - - (27) - - - - - Foreign exchange gains (losses) 2 (20) 5 (4) (10) (2) (9) 4 Net finance expense (61) (61) (65) (53) (42) (49) (35) (34) Gain on divestiture - 309 - - - - - - (Losses) gains on disposal and other transactions (1) (11) (5) (17) 2 (5) 5 (3) Other items 2,3 (37) (32) (32) (34) (25) (22) (19) (19) Income tax expense (48) (45) (53) (23) (77) (11) (83) (24) Net income 150 242 178 76 205 95 272 85 Net income attributable to: Non-controlling interests (1) 2 (1) 1 - (2) (2) (2) Shareholders of the Company 151 240 179 75 205 97 274 87 Net income 150 242 178 76 205 95 272 85 1 For the three months ended March 31, 2025, other non-recurring items reflects costs related to the end -of-life of Genesee coal operations of $4 million. For the three months ended December 31, 2024, other non -recurring items reflects restructuring costs of $39 million and costs related to the end-of-life of Genesee coal operations of $4 million. 2 Total income from joint ventures as per our consolidated statements of income. 3 Includes finance expense, depreciation expense and unrealized changes in fair value of derivative instruments from joint ventures.
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5 AFFO and AFFO per share AFFO and AFFO per share are measures of the Company’s ability to generate cash from its operating activities to fund growth capital expenditures, the repayment of debt and the payment of common share dividends. AFFO represents net cash flows from operating activities adjusted to: • remove timing impacts of cash receipts and payments that may impact period-to-period comparability which include deductions for net finance expense and current income tax expense, the removal of deductions for interest paid and income taxes paid and removing changes in operating working capital, • include the Company’s share of the AFFO of its joint venture interests and exclude distributions received from the Company’s joint venture interests which are calculated after the effect of non-operating activity joint venture debt payments, • include cash from off-coal compensation received annually through to 2030, • remove the tax equity financing project investors’ shares of AFFO associated with assets under tax equity financing structures so only the Company’s share is reflected in the overall metric, • deduct sustaining capital expenditures and preferred share dividends, • exclude the impact of fair value changes in certain unsettled derivative financial instruments that are charged or credited to the Company’s bank margin account held with a specific exchange counterparty, and • exclude other typically non-recurring items affecting cash from operating activities that are not reflective of the long-term performance of the Company’s underlying business. A reconciliation of net cash flows from operating activities to AFFO is as follows: ($ millions) Three months ended March 31 2025 2024 Net cash flows from operating activities per condensed interim consolidated statements of cash flows 210 334 Add (deduct): Interest paid 85 48 Change in fair value of derivatives reflected as cash settlement (11) (12) Distributions received from joint venture s (5) (8) Miscellaneous financing charges paid 1 (2) (7) Income taxes (recovered) paid (2) 15 Change in non-cash operating working capital (25) (162) 40 (126) Net finance expense 2 (53) (35) Current income tax recovery (expense)3 27 (16) Sustaining capital expenditures 4 (31) (25) Preferred share dividends paid (7) (9) Remove tax equity interests’ respective shares of AFFO (1) (1) AFFO from joint ventures 37 21 Other non-recurring items 5 (4) (1) AFFO 218 142 Weighted average number of common shares outstanding (millions) 139.2 123.7 AFFO per share ($) 1.57 1.15 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 in related to the partial divestiture of Quality Wind and Port Dover and Nanticoke Wind as the amount is considered an investing activity. 4 Includes sustaining capital expenditures net of partner contributions of $4 million and $5 million for the three months ended March 31, 2025 and 2024, respectively. 5 For the three months ended March 31, 2025, non -recurring items reflect costs related to the end-of-life of Genesee coal operations of $5 million net of current income tax expenses of $9 million. For the three months ended March 31, 2024, non -recurring items reflect current income tax expenses of $1 million related to other non -recurring items recognized in prior periods.
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6 Forward-looking Information Forward-looking information or statements included in this press release are provided to inform the Company’s 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 press release 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 press release includes disclosures regarding (i) status of the Company’s 2025 AFFO and adjusted EBITDA guidance, (ii) forecasted 2025 depreciation, (iii) the timing of, funding of, generation capacity of, costs of technologies selected for, environmental benefits or commercial and partnership arrangements regarding existing, planned and potential development projects and acquisitions (including the Hummel and Rolling Hill Generating Stations acquisitions), transaction close timing and receipt of required regulatory approvals, and the satisfaction of other customary closing conditions and (iv) the financial impacts of the Hummel and Rolling Hill Generating Stations acquisitions. These statements are based on certain assumptions and analyses made by the Company considering 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: (i) electricity, other energy and carbon prices, (ii) performance, (iii) business prospects (including potential re-contracting of facilities) and opportunities including expected growth and capital projects, (iv) status of and impact of policy, legislation and regulations and (v) effective tax rates. Whether actual results, performance or achievements will conform to the Company’s 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 the Company’s expectations. Such material risks and uncertainties are: (i) changes in electricity, natural gas and carbon prices in markets in which the Company operates and the use of derivatives, (ii) regulatory and political environments including changes to environmental, climate, financial reporting, market structure and tax legislation, (iii) disruptions, or price volatility within our supply chains, (iv) generation facility availability, wind capacity factor and performance including maintenance expenditures, (v) ability to fund current and future capital and working capital needs, (vi) acquisitions and developments including timing and costs of regulatory approvals and construction, (vii) changes in the availability of fuel, (viii) ability to realize the anticipated benefits of acquisitions, (ix) limitations inherent in the Company’s review of acquired assets, (x) changes in general economic and competitive conditions and (xi) changes in the performance and cost of technologies and the development of new technologies, new energy efficient products, services and programs. See Risks and Risk Management in the Company’s Integrated Annual Report for the year ended December 31, 2024, prepared as of February 25, 2025, 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 specified approval date. The Company 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 the Company’s expectations or any change in events, conditions or circumstances on which any such statement is based, except as required by law.
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7 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 region and Métis Nation of Alberta Region 4. 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 10 GW of power generation at 30 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. 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
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 8 CAPITAL POWER CORPORATION Management’s Discussion and Analysis This Management’s Discussion and Analysis (MD&A), prepared as of April 29, 2025, should be read in conjunction with the unaudited condensed interim consolidated financial statements of Capital Power Corporation and its subsidiaries for the three months ended March 31, 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 9. 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 three months ended March 31, 2025 and March 31, 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 April 29, 2025. Contents Forward-Looking Information ................................ ................................ ................................ ................................ 9 Overview of Business and Corporate Structure ................................ ................................ ................................ ... 10 Corporate Strategy ................................ ................................ ................................ ................................ ............ 10 Performance Overview ................................ ................................ ................................ ................................ ....... 10 Outlook................................ ................................ ................................ ................................ .............................. 11 Non-GAAP Financial Measures and Ratios ................................ ................................ ................................ ......... 12 Financial Highlights ................................ ................................ ................................ ................................ ............ 15 Subsequent Events ................................ ................................ ................................ ................................ ............ 16 Consolidated Net Income and Results of Operations ................................ ................................ ........................... 17 Financial Position................................ ................................ ................................ ................................ ............... 25 Liquidity and Capital Resources ................................ ................................ ................................ ......................... 26 Contingent Liabilities, Other Legal Matters and Provisions ................................ ................................ .................. 30 Risks and Risk Management ................................ ................................ ................................ .............................. 30 Environmental Matters ................................ ................................ ................................ ................................ ....... 30 Regulatory and Government Matters ................................ ................................ ................................ .................. 30 Use of Judgments and Estimates ................................ ................................ ................................ ....................... 32 Financial Instruments ................................ ................................ ................................ ................................ ......... 33 Disclosure Controls and Procedures and Internal Control over Financial Reporting ................................ .............. 35 Summary of Quarterly Results ................................ ................................ ................................ ............................ 36 Share and Partnership Unit Information ................................ ................................ ................................ .............. 39 Additional Information ................................ ................................ ................................ ................................ ........ 40
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 9 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 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 (including Halkirk 2 Wind, the repowering of Genesee Generating Station Units 1 and 2, the upgrades at Goreway and York Energy, Goreway Battery Energy Storage System (BESS), York Energy BESS, East Windsor expansion, Maple Leaf Solar, Bear Branch Solar, Hornet Solar and the acquisition of Hummel Station Intermediate Holdings III, LLC and Rolling Hills Generating Holdings, LLC (see Subsequent Events)). This includes expectations around timing, transaction close timing and receipt of required regulatory approvals, and the satisfaction of other customary closing conditions, funding, project and acquisition costs, 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, • future growth and emerging opportunities in our target markets, • market and regulation designs and regulatory and legislative proposals and changes, regulatory updates 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, • foreign exchange rates, and • other matters discussed under the Performance Overview, Outlook and Risks and Risk Management sections of this 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,
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 10 • 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 10 GW of power generation at 30 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. CORPORATE STRATEGY Capital Power’s corporate strategy remains unchanged from that disclosed in our 2024 Integrated Annual Report. PERFORMANCE OVERVIEW We measure our operational and financial performance in relation to our corporate strategy through financial and non-financial targets that are 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. Operational priorities and performance targets for Capital Power in 2025 include a balanced approach to the energy transition: Priority 2025 target Status at March 31, 2025 Deliver Execution of major turnarounds Sustaining capital expenditures of $195 million to $225 million $46 million1,2 Generate financial stability and strength AFFO3 of $850 million to $950 million Adjusted EBITDA3 of $1,340 million to $1,440 million $218 million1 $367 million1 Portfolio optimization and integration Re-contract/contract flexible generation Maximize facility asset life and value Discussions with counterparties are in progress to re-contract flexible generation. 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). The Ontario BESS projects are approximately 90% constructed. East Windsor expansion has received substantially all major equipment to be installed. On April 14, 2025, the Company announced the acquisition of two U.S. flexible generation assets in the PJM market expected to close in the third quarter of 2025 (see Subsequent Events ). Grow renewables portfolio Continue construction on Alberta and North Carolina growth and commercial initiative projects Construction for Hornet Solar commenced during the first quarter of 2025. Bear Branch Solar and Maple Leaf Solar are expected to commence construction in the second quarter of 202 5 and
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 11 Priority 2025 target Status at March 31, 2025 Continue to explore opportunities to build or acquire renewables facilities 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 remains on track. Provide integrated energy solutions to commercial and industrial customers Discussions with counterparties are in progress to provide integrated energy solutions. 1 For the three months ended March 31, 202 5. 2 Includes our share of joint venture sustaining capital expenditures of $ 15 million net of partner contributions of $ 4 million. 3 AFFO and adjusted EBITDA are non-GAAP financial measures. See Non -GAAP Financial Measures and Ratios. 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. A 2025 guidance presentation was held in January 2025 providing financial guidance for 2025 AFFO in the range of $850 million to $950 million and 2025 adjusted EBITDA in the range of $1,340 million to $1,440 million (see Non- GAAP Financial Measures and Ratios). Our U.S. and Ontario flexible generation fleet performance contributed to the stronger than planned first quarter of 2025, and the Company expects 2025 full year results to be within the guidance ranges. With the acquisitions of Hummel Station Intermediate Holdings III, LLC and Rolling Hills Generating Holdings, LLC located in the PJM market anticipated to close in the third quarter of 2025 (see Subsequent Events), integration of these assets will be a priority during the remainder of 2025. The Alberta portfolio position, contracted prices and forward Alberta pool prices for 2026, 2027 and 2028 (all at March 31, 2025) were: Alberta portfolio 2026 2027 2028 Power Hedged volume (GWh) 11,500 5,500 3,000 Weighted average hedged prices 1 ($/MWh) Low-$70s High-$70s Low-$80s Forward Alberta pool prices ($/MWh) $45 $49 $55 Natural gas Hedged volume (TJ) 70,000 40,000 25,000 Weighted average hedged prices 1,2 ($/GJ) < $4.00 < $4.00 < $4.00 Forward Alberta natural gas prices ($/GJ) $3.20 $3.10 $3.00 1 Forecasted average contracted prices may differ significantly from future average realized prices as future realized prices are driven by a combination of previously contracted prices and settled prices. When long-term forward portfolio optimization hedges are transacted, they reflect the market’s expectations for future period pricing. 2 Net of gains as part of the Company’s natural gas portfolio optimization activities, including sales of previously purchased length. The power hedged volumes and weighted average hedged prices include origination contracts with contract terms greater than 12 months. The weighted average hedged price of these longer-term duration contracts was in the high-$70s per megawatt hour range. In addition to the remaining open baseload position, Alberta natural gas peaking assets in the Company’s Canada flexible generation portfolio are available to capture upside from higher Alberta power prices. The 2025 targets and forecasts are based on numerous assumptions including power and natural gas price forecasts. They do not include the effects of asset sell-downs, potential future acquisitions or development activities, or potential market and operational impacts relating to significant unplanned facility outages including outages at facilities of other market participants, and the related impacts on market power prices.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 12 At our 2024 guidance call held in January 2024, management reiterated the 6% annual dividend growth guidance through to 2025. At Investor Day in May 2024, management announced a long-term targeted dividend growth guidance of 2% – 4% after 2025. The reduced dividend growth rate will facilitate funding for 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 future cash requirements and expected sources of funding. NON-GAAP FINANCIAL MEASURES AND RATIOS Capital Power uses (i) earnings before net finance expense, income tax expense, depreciation and amortization, impairments, foreign exchange gains or losses, finance expense and depreciation expense from our joint venture interests, gains or losses on disposals and other transactions and 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 (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 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 and other items that are not reflective of the long-term performance of the Company’s underlying business.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 13 A reconciliation of adjusted EBITDA to net income is as follows: ($ millions) Three months ended Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Sep 2023 Jun 2023 Revenues and other income 988 853 1,030 774 1,119 984 1,150 881 Energy purchases and fuel, other raw materials and operating charges, staff costs and employee benefits expense, and other administrative expense (628) (658) (612) (504) (677) (694) (626) (614) Remove unrealized changes in fair value of commodity derivatives and emission credits (58) 48 (78) (8) (200) (14) (151) 23 Remove other non-recurring items 1 4 43 - 4 - 1 4 - Adjusted EBITDA from joint ventures 2 61 44 61 57 37 36 37 37 Adjusted EBITDA 367 330 401 323 279 313 414 327 Depreciation and amortization (126) (137) (124) (120) (122) (142) (148) (143) Unrealized changes in fair value of commodity derivatives and emission credits 58 (48) 78 8 200 14 151 (23) Other non-recurring items (4) (43) - (4) - (1) (4) - Impairment - - (27) - - - - - Foreign exchange gains (losses) 2 (20) 5 (4) (10) (2) (9) 4 Net finance expense (61) (61) (65) (53) (42) (49) (35) (34) Gain on divestiture - 309 - - - - - - (Losses) gains on disposals and other transactions (1) (11) (5) (17) 2 (5) 5 (3) Other items 2,3 (37) (32) (32) (34) (25) (22) (19) (19) Income tax expense (48) (45) (53) (23) (77) (11) (83) (24) Net income 150 242 178 76 205 95 272 85 Net income attributable to: Non-controlling interests (1) 2 (1) 1 - (2) (2) (2) Shareholders of the Company 151 240 179 75 205 97 274 87 Net income 150 242 178 76 205 95 272 85 1 For the three months ended March 31, 202 5, other non-recurring items reflects costs related to the end-of-life of Genesee coal operations of $4 million. For the three months ended December 31, 2024, other non -recurring items reflects restructuring costs of $39 million and costs related to the end-of-life of Genesee coal operations of $4 million . 2 Total income from joint ventures as per our consolidated statements of income (loss). 3 Includes finance expense, depreciation expense and unrealized changes in fair value of derivative instruments from joint ventures.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 14 AFFO and AFFO per share AFFO and AFFO per share are measures of our ability to generate cash from our operating activities to fund growth capital expenditures, repayment of debt, and payment of common share dividends. AFFO represents net cash flows from operating activities adjusted to: • remove timing impacts of cash receipts and payments that may impact period-to-period comparability which include deductions for net finance expense and current income tax expense, the removal of deductions for interest paid and income taxes paid and removing changes in operating working capital, • include our share of AFFO of joint venture interests and exclude distributions received from our joint venture interests which are calculated after the effect of non-operating activity joint venture debt payments, • include cash from off-coal compensation received annually through to 2030, • remove the tax equity financing project investors’ shares of AFFO associated with assets under tax equity financing structures so only Capital Power’s share is reflected in the overall metric, • deduct sustaining capital expenditures and preferred share dividends, • exclude the impact of fair value changes in certain unsettled derivative financial instruments that are charged or credited to our bank margin account held with a specific exchange counterparty, and • exclude other typically non-recurring items affecting cash flows from operating activities that are not reflective of the long-term performance of the Company’s underlying business. A reconciliation of net cash flows from operating activities to AFFO is as follows: ($ millions) Three months ended March 31 2025 2024 Net cash flows from operating activities per condensed interim consolidated statements of cash flows 210 334 Add (deduct): Interest paid 85 48 Change in fair value of derivatives reflected as cash settlement (11) (12) Distributions received from joint venture s (5) (8) Miscellaneous financing charges paid 1 (2) (7) Income taxes (recovered) paid (2) 15 Change in non-cash operating working capital (25) (162) 40 (126) Net finance expense 2 (53) (35) Current income tax recovery (expense) 3 27 (16) Sustaining capital expenditures 4 (31) (25) Preferred share dividends paid (7) (9) Remove tax equity interests’ respective shares of AFFO (1) (1) AFFO from joint ventures 37 21 Other non-recurring items 5 (4) (1) AFFO 218 142 Weighted average number of common shares outstanding (millions) 139.2 123.7 AFFO per share ($) 1.57 1.15 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 $4 million and $5 million for the three months ended March 31, 2025 and 2024, respectively. 5 For the three months ended March 31, 2025, non-recurring items reflect costs related to the end-of-life of Genesee coal operations of $5 million net of current income tax expenses of $9 million. For the three months ended March 31, 2024, non - recurring items reflect current income tax expenses of $ 1 million related to other non-recurring items recognized in prior periods.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 15 FINANCIAL HIGHLIGHTS ($ millions, except per share amounts) Three months ended March 31 2025 2024 Revenues and other income 988 1,119 Adjusted EBITDA 1 367 279 Net income 150 205 Net income attributable to shareholders of the Company 151 205 Basic earnings per share ($) 1.03 1.58 Diluted earnings per share ($) 2 1.03 1.57 Net cash flows from operating activities 210 334 AFFO 1 218 142 AFFO per share ($) 1 1.57 1.15 Purchase of property, plant and equipment and other assets , net 288 218 Dividends per common share, declared ($) 0.6519 0.6150 Dividends per Series 1 preferred share, declared ($) 0.1638 0.1638 Dividends per Series 3 preferred share, declared ($) 0.4288 0.4288 Dividends per Series 5 preferred share, declared ($) 0.4144 0.4144 Dividends per Series 11 preferred share, declared ($) 3 N/A 0.3594 March 31, 2025 December 31, 2024 Loans and borrowings including current portion 4,939 4,976 Total assets 12,850 12,930 1 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. 2 Diluted earnings per share was calculated after giving effect to outstanding share purchase options. 3 On June 30, 2024, Capital Power redeemed all of our 6 million issued and outstanding 5.75% cumulative minimum rate reset preference shares, Series 11. Adjusted EBITDA for the three months ended March 31, 2025 was higher than the corresponding period in 2024 largely due to the net impact of: • lower emissions cost in the Canada flexible generation segment driven by the repowering of Genesee Generating Station to be off-coal, • higher contributions for the U.S. flexible generation segment due to full quarter results from La Paloma and Harquahala which were acquired in February 2024 and overall higher generation due to increased dispatch compared to 2024, • lower corporate expenses driven by lower business development costs and lower share-based compensation. AFFO for the three months ended March 31, 2025 was higher than the corresponding period in 2024 primarily due to the net impact of: • higher adjusted EBITDA described above, • decreased current income tax expense due to lower overall consolidated net income before tax and higher tax deductions for certain capital projects partly offset by higher U.S. current tax resulting from the acquisitions of La Paloma and Harquahala, • increased finance expense driven mainly by increased interest on loans and borrowing, and • higher sustaining capital expenditures due to larger scope during 2025. Revenues and other income for the three months ended March 31, 2025, were lower than the corresponding period in 2024 primarily due to lower gains on unrealized changes in fair value of commodity derivatives and emission credits as described in Consolidated Net Income and Results of Operations, and reduced power prices realized on Canada flexible generation facilities. Partly offsetting these decreases were increased revenues from U.S. flexible generation from La Paloma and Harquahala which were acquired in February 2024. See Consolidated Net Income and Results of Operations for further discussion of the key drivers of the changes in revenues and other income, adjusted EBITDA, net income and net income attributable to shareholders of the Company. Basic and diluted earnings per share changes were driven by the same factors as net income, which are discussed in Consolidated Net Income and Results of Operations and the changes from period to period in the weighted average number of common shares outstanding.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 16 See Liquidity and Capital Resources for discussion of key drivers of changes in net cash flows from operating activities. The increase in purchases of property, plant and equipment and other assets is discussed in Liquidity and Capital Resources. SUBSEQUENT EVENTS Acquisition of Hummel Station Intermediate Holdings III, LLC and Rolling Hills Generating Holdings, LLC Consistent with the Company’s strategy to acquire flexible generation assets in the U.S, on April 14, 2025, Capital Power entered into a definitive agreement with Hummel Station Intermediate Holdings III, LLC and Rolling Hills Generating Holdings, LLC, each a subsidiary of LS Power Equity Advisors, LLC, to acquire 100% of the equity interests in: 1. Hummel Station, LLC, which owns the 1,124 MW Hummel Station, a combined-cycle natural gas facility in Shamokin Dam, Pennsylvania (Hummel Acquisition), and 2. Rolling Hills Generating, L.L.C., which owns the 1,023 MW Rolling Hills plant, a combustion turbine natural gas facility in Wilkesville, Ohio (Rolling Hills Acquisition and together with the Hummel Acquisition, the Acquisition). The total purchase price of the Acquisition is expected to be approximately $3.0 billion (US$2.2 billion), subject to customary post-closing adjustments, including working capital and estimated transaction expenses. The Acquisition is expected to close in the third quarter of 2025, subject to regulatory approvals and other customary closing conditions. Capital Power will finance the Acquisition using the net proceeds from its concurrent common share offering, outlined in further detail below, and a combination of some or all of the following (i) cash on hand from a prior equity issuance and asset divestitures; (ii) longer term debt financing; (iii) other immediately available funds, including potential draws under Capital Power’s existing credit facilities; and (iv) funding provided under Acquisition Term Loan Facilities, described in further detail below. This funding plan maintains Capital Power’s investment grade credit rating and preserves its strong balance sheet and financial flexibility. Common share offering On April 22, 2025, the Company completed a public offering of 11,902,500 common shares, which included 1,552,500 common shares issued pursuant to the full exercise of the over-allotment option, at $43.45 per common share (Offering Price) for total gross proceeds of approximately $517 million. The Company also issued 3,455,000 common shares at the Offering Price on a private placement basis, for gross proceeds of $150 million, subject to a statutory hold period of 4 months and one day from the closing date of the private placement. Acquisition Term Loan Facilities For purposes of financing the Acquisition, the Company entered into an agreement with a lender on April 14, 2025, whereby the lender has agreed to provide, on a fully underwritten basis, senior unsecured term loan facilities in the aggregate principal amount of up to $2 billion (Acquisition Term Loan Facilities). The Acquisition Term Loan Facilities are comprised of two tranches of $1 billion non-extendible, non-revolving, syndicated term credit facilities, with the first tranche maturing in 2028 and the second tranche maturing in 2027.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 17 CONSOLIDATED NET INCOME AND RESULTS OF OPERATIONS The primary factors contributing to the change in consolidated net income for the three months ended March 31, 2025 compared with 2024 are presented below followed by further discussion of these items. ($ millions) Consolidated net income for the three months ended March 31, 2024 205 Increase (decrease) in adjusted EBITDA: Canada flexible generation 28 Canada renewables (11) U.S. flexible generation 35 U.S. renewables 3 Corporate 33 88 Change in unrealized net gains or losses related to the fair value of commodity derivatives and emission credits (142) Increase in loss on disposals and other transactions (3) Increase in depreciation and amortization expense (4) Increase in foreign exchange gain 12 Increase in finance expense and depreciation from joint ventures (12) Increase in net finance expense (19) Non-recurring items (4) Decrease in income before tax (84) Decrease in income tax expense 29 Decrease in net income (55) Consolidated net income for the three months ended March 31, 2025 150
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 18 Results by facility category and other Three months ended March 31 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 9,555 8,809 90 94 606 679 Canada Canada flexible generation Genesee Generating Station, Alberta 4 2,755 2,388 96 92 116 243 Clover Bar Energy Centre, Alberta 114 165 77 56 8 22 Joffre, Alberta 164 215 98 100 15 28 Shepard, Alberta 712 820 100 98 31 60 Clover Bar Landfill Gas, Alberta - - - - - - Island Generation, British Columbia 74 34 99 100 2 3 York Energy, Ontario 5 11 6 92 100 N/A N/A East Windsor, Ontario 6 12 98 99 8 8 Goreway, Ontario 954 799 90 99 115 85 EnPower, British Columbia 9 6 100 85 1 1 4,799 4,445 94 93 296 450 Alberta portfolio optimization N/A N/A N/A N/A 284 227 4,799 4,445 94 93 580 677 207 179 Canada renewables Quality Wind, British Columbia 5 51 87 98 95 N/A 15 Halkirk 1 Wind, Alberta 121 109 97 93 10 13 Halkirk 2 Wind, Alberta 6 - N/A - N/A - N/A Whitla Wind, Alberta 308 325 97 95 15 15 Strathmore Solar, Alberta 12 13 95 97 1 1 Clydesdale Solar, Alberta 23 32 96 97 1 2 Kingsbridge 1, Ontario 40 28 97 90 3 2 Port Dover and Nanticoke Wind, Ontario 5 42 82 80 98 N/A 13 597 676 96 95 30 61 33 44 Total Canada 5,396 5,121 94 94 610 738 240 223 U.S. U.S. flexible generation Decatur Energy, Alabama 1,070 455 100 100 35 26 Arlington Valley, Arizona 652 840 73 82 70 53 Midland Cogen, Michigan 5 1,100 1,298 94 93 N/A N/A Frederickson 1, Washington 192 246 97 89 6 6 Harquahala, Arizona 5,7 138 - 78 100 N/A N/A La Paloma, California 7 423 277 75 95 128 43 U.S. Trading N/A N/A N/A N/A 11 7 3,575 3,116 85 94 250 135 119 84 U.S. renewables Beaufort Solar, North Carolina 6 7 99 98 1 1 Bloom Wind, Kansas 156 174 89 98 8 10 Macho Springs Wind, New Mexico 40 41 97 96 5 5 New Frontier Wind, North Dakota 117 89 95 83 7 5 Cardinal Point Wind, Illinois 169 165 81 87 13 12 Buckthorn Wind, Texas 96 96 96 96 7 7 584 572 90 92 41 40 31 28 Total U.S. 4,159 3,688 86 93 291 175 150 112
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 19 Corporate 8 14 3 (23) (56) Unrealized changes in fair value of commodity derivatives and emission credits 73 203 Consolidated revenues and other income and adjusted EBITDA 988 1,119 367 279 1 Gigawatt hours (GWh) of electricity generation reflects the Company’s share of facility output. 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 Statio n. 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 joint ventures 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 the facilit ies revenue was $149 million and $99 million for the three months ended March 31, 2025 and 2024, respectively. The facilities revenues are not included in the above results. 6 Halkirk 2 Wind commenced partial operations in the fourth quarter of 2024 with commercial operations expected in the second quarter of 2025 (see Capital Expenditures and Investments). 7 Harquahala and La Paloma were acquired February 16, 2024 and February 9, 2024, respectively. 8 Corporate revenues are partly offset by interplant category eliminations.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 20 Adjusted EBITDA and revenues and other income by fuel type for the three months ended March 31 Alberta portfolio optimization and trading activity amounts directly related to U.S. facilities in adjusted EBITDA and revenues and other income are allocated to fuel source based on generation. The period-over-period increases in percentages from our flexible generation facilities are largely driven by the acquisition of La Paloma in the first quarter of 2024 and transition to be off-coal at our Genesee Generating Station during 2024. Contributions to revenue and adjusted EBITDA from renewable facilities decreased due to Port Dover and Nanticoke Wind which were partially divested in December 2024. 92% 8% 2025 1 See Non-GAAP Financial Measures and Ratios. 2 The allocation of revenues and other income by fuel type excludes the impacts of unrealized changes in fair value of commodity derivatives and emission credits. Adjusted EBITDA1 by fuel type Revenues and other income by fuel type2 Renewables Flexible generation Natural gas / coal dual-fuel 23% 68% 9% 2024 12% 62% 26% 2024 84% 16% 2025
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 21 Adjusted EBITDA and revenues and other income by facility geography for the three months ended March 31 Trading activity amounts directly related to facilities are included in adjusted EBITDA and revenues and other income based on the geographic location of the facility that the trading relates to. Corporate adjusted EBITDA and revenues and other income are excluded from these amounts. The period-over-period increases in percentages from the U.S. is largely driven by the acquisitions of La Paloma and Harquahala in the first quarter of 2024, contributing a full quarter of results during 2025. This was further impacted by the partial divestiture at the end of 2024 of Quality Wind and Port Dover and Nanticoke Wind both located in Canada. Adjusted EBITDA1 by facility geography U.S. Canada Revenues and other income by facility geography2 1 See Non-GAAP Financial Measures and Ratios. 2 The allocation of revenues and other income by facility geography excludes the impacts of unrealized changes in fair value of commodity derivatives and emission credits. 68% 32% 2025 81% 19% 2024 62% 38% 2025
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 22 Canada flexible generation energy prices and hedged positions Three months ended March 31 Year ended December 31, 2024 Alberta portfolio 2025 2024 Power Hedged volume at beginning of period (GWh) 3,000 3,000 11,000 Spot power price average ($/MWh) 40 99 63 Realized power price average 1 ($/MWh) 73 82 78 Natural gas Hedged volume at beginning of period (TJ) 22,500 18,500 70,000 Spot natural gas price average (AECO) 2 ($/GJ) 2.03 1.94 1.29 1 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 mate rially from spot pricing. 2 AECO refers to the historical virtual trading hub located in Alberta and known as the NOVA Inventory Transfer system operated by TC Energy. Canada flexible generation Alberta spot price averaged $40 per MWh for the first quarter ended March 31, 2025, compared to $99 per MWh in the same period 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 and availability for the quarter ended March 31, 2025 increased compared to the same quarter in the previous year 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. Generation and availability also increased year-over- year to more unplanned outages in the first quarter of 2024. • lower dispatch and generation at Clover Bar Energy Center, Joffre and Shepard due to lower year-over-year power pricing. Availability increased year-over-year at Clover Bar Energy Centre because of more unplanned outages in the first quarter of 2024. • despite lower availability year-over-year at Goreway due to a planned outage in the first quarter of 2025, the facility saw increased generation from tighter market conditions and colder weather in 2025 compared to 2024. Lower revenues and other income for the quarter ended March 31, 2025 compared to the same quarter 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 price 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 in late 2024. Lower Alberta power prices further reduced revenues and other income and adjusted EBITDA at Halkirk. U.S. flexible generation Availability for the quarter ended March 31, 2025, was lower compared to the same period in 2024 due to several planned outages at various facilities. Strong generation year-over-year was primarily due to higher demand and increased dispatch and a full quarter of generation of the La Paloma and Harquahala facilities which was acquired in February 2024. Stronger generation and a stronger U.S. dollar relative to the Canadian dollar year-over-year contributed to higher revenues and other income and adjusted EBITDA. U.S. renewables The results of U.S. renewables remained consistent year-over-year.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 23 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 quarter ended March 31, 2025, were higher compared to the same period in 2024, primarily due to insurance proceeds received in 2025. Adjusted EBITDA increased due to lower share-based compensation, and a success fee paid in 2024 for the La Paloma and Harquahala acquisitions. Unrealized changes in fair value of commodity derivatives and emission credits ($ millions) Three months ended March 31 Unrealized changes in fair value of commodity derivatives and emission credits 2025 2024 2025 2024 Revenues and other income1 Income before tax1 Unrealized gains on Alberta power derivatives 39 247 39 247 Unrealized gains (losses) on U.S. power derivatives 87 (29) 69 (29) Unrealized (losses) gains on natural gas derivatives (29) (13) 13 (16) Unrealized losses on emission derivatives (24) (2) (52) (2) Unrealized losses on emission credits held for trading - - (11) - 73 203 58 200 1 Revenues and other income and adjusted EBITDA from our Alberta facilities and portfolio optimization and U.S. trading 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. 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 months ended March 31, 2025 and 2024, we recognized unrealized gains of $39 million and $247 million, respectively, on Alberta power derivatives, mainly due to impacts of decreasing forward prices on net forward sale contracts. During the three months ended March 31, 2025, we recognized unrealized gains on U.S. power derivatives of $69 million mainly due to impacts of decreasing forward pricing on forward sales contracts at our U.S. renewable facilities and La Paloma. During the comparable period in March 31, 2024, we recognized unrealized losses on U.S. power derivatives of $29 million, mainly due to impacts of increasing forward power prices on forward sales contracts. During the three months ended March 31, 2025, we recognized unrealized gains on natural gas derivatives of $13 million due to impacts of increasing forward pricing on net forward buy contracts. During the comparable period in March 31, 2024, we recognized unrealized losses of $16 million on natural gas derivatives mainly due to the reversal of prior period unrealized gains on positions that settled during the quarter, partially offset by impacts of decreasing forward prices on forward purchase contracts. During the three months ended March 31, 2025, we recognized unrealized losses of $52 million on emissions derivatives due to the impact of decreased forward pricing on our U.S. emissions derivatives on forward net purchases. During the comparative period in 2024, we recognized unrealized losses of $2 million on emissions derivatives, mainly due to the reversal of prior period unrealized gains on positions that settled in the quarter. During the three months ended March 31, 2025, Capital Power recognized unrealized losses of $11 million on emissions credits held for trading due to the impacts of decreased forward pricing on our U.S. emissions inventory.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 24 Consolidated other expenses and non-controlling interests ($ millions) Three months ended March 31 2025 2024 Interest on borrowings less capitalized interest (59) (47) Realized gains on settlement of interest rate derivatives 3 3 Other net finance income (expense) – bank interest, interest on off-coal compensation from the Province of Alberta, lease liability interest, sundry interest, guarantee and other fees (1) 6 (57) (38) Unrealized losses representing changes in the fair value of interest rate derivatives (1) - Other net finance expense – amortization and accretion charges, including accretion of deferred revenue pertaining to off-coal compensation from the Province of Alberta (3) (4) Total net finance expense (61) (42) Depreciation and amortization (126) (122) Foreign exchange gain (loss) 2 (10) (Losses) gains on disposals and other transactions (1) 2 Other items from joint ventures 1 (37) (25) Income tax expense (48) (77) Net loss attributable to non-controlling interests 1 - 1 Includes finance expense, depreciation expense and fair value changes on derivatives from joint ventures. Net finance expense Higher net finance expense for the three months ended March 31, 2025 compared with the same period in the prior year largely reflects higher interest due to the increased loans and borrowings outstanding from $450 million and $600 million notes issued during 2024. This was further impacted by lower capitalized interest during 2025 due to the construction of the Genesee repowering project in 2024. Foreign exchange gain (loss) The Company recognized foreign exchange gains for the three months ended March 31, 2025 due to a slight decrease in the USD to CAD exchange rates during the period. Comparatively, exchange rates during the period ending March 31, 2024 were increasing resulting in foreign exchange losses. Other items from joint ventures Other items from joint ventures 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 and Harquahala joint ventures, which are accounted for under the equity method. Other items from joint ventures increased compared with 2024 primarily due to Quality Wind and Port Dover and Nanticoke Wind becoming joint ventures upon Capital Power’s partial divestiture of these assets at the end of 2024. Income tax expense Income tax expense for the three months ended March 31, 2025, decreased compared with the corresponding period in 2024 primarily due to lower overall consolidated net income before tax.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 25 FINANCIAL POSITION The following highlights changes in the consolidated statements of financial position from December 31, 2024 to March 31, 2025 were as follows: March 31, 2025 December 31, 2024 Assets Current assets 1,805 1,948 Non-current assets: Property, plant and equipment 8,090 8,061 Equity-accounted investments 1,109 1,096 Intangible assets and goodwill 726 744 Right-of-use assets 115 118 Derivative financial instruments 476 412 Government grant receivable 385 380 Deferred tax assets 25 26 Other assets 119 145 Total assets $ 12,850 $ 12,930 Liabilities and equity Current liabilities 1,513 1,353 Non-current liabilities: Derivative financial instruments 504 494 Loans and borrowings 4,472 4,819 Lease liabilities 133 134 Deferred tax liabilities 920 863 Provisions 360 373 Deferred revenue and other liabilities 315 323 Total liabilities 8,217 8,359 Share capital 4,317 4,301 Deficit (21) (74) Other reserves 344 349 Equity attributable to shareholders of the Company 4,640 4,576 Non-controlling interests (7) (5) Total equity 4,633 4,571 Total liabilities and equity $ 12,850 $ 12,930 Net working capital decreased from December 31, 2024 to March 31, 2025 by $303 million, mainly driven by: • reduction in cash balances as described in Liquidity and Capital Resources, • reclassifying the current portion of loans and borrowing from non-current, • partly offset by deferred payments on capital project costs for the construction of Halkirk 2 Wind. Net non-current derivative liabilities decreased from December 31, 2024 to March 31, 2025 due to reduction in forward power pricing on short positions, higher natural gas forward pricing on long positions and increased heat rate call option values, partly offset by gains realized during 2025 and decreasing forward power pricing on long positions. Deferred tax liabilities increased from December 31, 2024 to March 31, 2024 due to recognition of taxable temporary differences that will reverse in the future.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 26 LIQUIDITY AND CAPITAL RESOURCES ($ millions) Three months ended March 31 Cash inflows (outflows) 2025 2024 Change Operating activities 210 334 (124) Investing activities (276) (1,439) 1,163 Financing activities (115) (165) 50 Operating activities Cash flows from operating activities for the three months ended March 31, 2025 were lower than the same period in 2024 mainly due to the net impact of: • decreased cash flows from change in working capital most notably from higher collections of outstanding receivables from December 2023 collected during the first quarter of 2024, • increased interest paid due to increased loans and borrowings outstanding from $450 million and $600 million notes issued during 2024, and • decreases in favourable changes in adjusted EBITDA described in the Consolidated Net Income and Results of Operations. Investing activities Cash flows used in investing activities for the three months ended March 31, 2025 were lower than the same period in 2024 due to the acquisitions of La Paloma and Harquahala in February of 2024 and lower capital expenditures for the Genesee Repowering project, Ontario growth projects, and Halkirk 2 Wind in 2025 compared to 2024. This was partly offset by increased capital expenditures on the construction of Hornet Solar during 2025 and deferred cash payments on construction liabilities.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 27 Capital expenditures and investments ($ millions) Pre- 2025 actual Three months ended March 31, 2025 actual Balance of 2025 estimated 1,2 Actual or projected total 2 Targeted completion Repowering of Genesee 1 and 2 3 1,487 12 51 to 151 1,550 to 1,650 Achieved commercial operations fourth quarter of 2024 with project completion expected in the second quarter of 2025. Halkirk 2 Wind 4 298 1 2 301 Second quarter of 2025 Ontario growth projects 356 49 182 600 York and Goreway BESS in Q3 2025 East Windsor Expansion in Q2 2026 Maple Leaf Solar 12 8 51 219 First quarter of 2027 Bear Branch Solar 8 - 75 103 Fourth quarter of 2026 Hornet Solar 15 15 157 209 Third quarter of 2026 Commercial initiatives 5 268 3 20 Development sites and projects 63 (2) - Subtotal growth projects 86 538 to 638 Sustaining – plant maintenance 35 Total capital expenditures 6 121 Emission credits held for compliance 17 Capitalized interest (9) Additions of property, plant and equipment and other assets 129 Change in other non-cash investing working capital and non-current liabilities 159 Purchase of property, plant and equipment and other assets, net 288 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 reac h the advanced development stage. 3 Projected costs for the project including post -commercial operations date , 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 fe ll from the tower in November 2024. 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.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 28 Financing activities Cash flows used in financing activities decreased in the three months ended March 31, 2025 mainly due to lower repayments of loans and borrowings partly offset by higher cash dividends paid due to a higher dividend rate and increased shares outstanding during 2025. The Company’s credit facilities consisted of: ($ millions) Maturity timing At March 31, 2025 At December 31, 2024 Total facilities Credit facility utilization Available Total facilities Credit facility utilization Available Committed credit facilities 2029 1,000 1,000 Letters of credit outstanding - - Bankers’ acceptances outstanding - - Bank loans outstanding - - 1,000 - 1,000 1,000 - 1,000 Bilateral demand credit facilities N/A 1,421 1,421 Letters of credit outstanding 610 608 1,421 610 811 1,421 608 813 Demand credit facilities N/A 25 - 25 25 - 25 2,446 610 1,836 2,446 608 1,838 At March 31, 2025, the committed credit facility utilization remained consistent compared with December 31, 2024. 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 March 31, 2025, $99 million of bonds were issued under these facilities (December 31, 2024 - $99 million). Capital Power has a corporate credit rating of BBB- with a stable outlook from Standard & Poor’s (S&P), which was affirmed in April 2025. The BBB rating category assigned by S&P is the fourth highest rating of S&P’s ten rating categories for long-term debt obligations. According to S&P, a BBB corporate credit rating exhibits adequate capacity to meet financial commitments; however, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments. Capital Power has a corporate credit rating of BBB (low) with a stable trend from DBRS Limited (DBRS), which was affirmed in April 2025. The BBB rating category assigned by DBRS is the fourth highest rating of DBRS’s ten rating categories for long-term debt obligations. According to DBRS, long-term debt rated BBB is of adequate credit quality and the capacity of the payment of financial obligations is considered acceptable but the entity is vulnerable to future events. The above credit ratings from S&P and DBRS are investment grade credit ratings which enhance Capital Power’s ability to re-finance existing debt as it matures and to access cost competitive capital for future growth.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 29 Future cash requirements The following estimates of future cash requirements are subject to variable factors including those discussed in the Forward-Looking Information section. Capital Power’s expected cash requirements for 2025 include: ($ millions) Three months ended March 31, 2025 actual Balance of 2025 estimated Total 2025 expected cash requirements Repayment of debt payable 1 19 64 83 Interest on loans and borrowings 85 172 257 Capital expenditures – sustaining 46 164 210 Capital expenditures – ongoing growth projects 2 95 602 697 Capital expenditures – commercial initiatives 3 20 23 Common share dividends 3 75 223 298 Preferred share dividends 7 21 28 330 1,266 1,596 1 Excludes repayment of credit facilities. 2 Includes repayments of deferred capital expenditures on the Genesee 1 and 2 repowering project. 3 Includes 6% annual dividend growth, subject to approval by the Board of Directors of Capital Power. 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. Off-statement of financial position arrangements At March 31, 2025, Capital Power has $610 million of outstanding letters of credit for collateral support for trading operations, conditions of certain service agreements, and to satisfy legislated reclamation requirements and $99 million of surety bonds issued for certain capital projects and contracts. If Capital Power were to terminate these off-statement of financial position arrangements, the penalties or obligations would not have a material impact on our financial condition, results of operations, liquidity, capital expenditures or resources. Capital resources ($ millions) March 31, 2025 December 31, 2024 Loans and borrowings 4,939 4,976 Lease liabilities 1 150 151 Less cash and cash equivalents (689) (865) Net debt 4,400 4,262 Share capital 4,317 4,301 Deficit and other reserves 323 275 Non-controlling interests (7) (5) Total equity 4,633 4,571 Total capital 9,033 8,833 1 Includes the current portion presented within deferred revenue and other liabilities .
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 30 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 and therefore no provision has been made. A dispute arose in 2024 between the Company and the contractor regarding construction work on the Genesee Repowering Project. The parties are actively participating in an agreed-upon mediation process to resolve the claims by both parties. The Company has withheld payments pending the resolution of the dispute. The mediation session is scheduled for the second quarter of 2025. RISKS AND RISK MANAGEMENT For the three months ended March 31, 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 three months ended March 31, 2025. ENVIRONMENTAL MATTERS Capital Power recorded decommissioning provisions of $347 million at March 31, 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. Capital Power has forward contracts to purchase environmental credits totaling $1,317 million and forward contracts to sell environmental credits totaling $1,023 million in future years. Included within these forward purchases and sales are net purchase amounts which will be used to comply with 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 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 U.S. Environmental Protection Agency (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 principal pollutants. Further, Maricopa County has until May 17, 2025 to submit a plan to EPA addressing moderate level air quality requirements or a 2:1 offsets sanction will be put in place, which would require any new or modified major pollution sources to offset their increased emissions by reducing emissions from existing sources or from purchasing emission reduction credits at a ratio of at least 2 to 1. If Maricopa County 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.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 31 U.S. tariffs 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. Management has consulted external legal counsel and assessed potential scenarios under President Trump’s tariff announcements that could impact the Company’s operations, specifically Canadian electricity sales to the U.S, and the sales of renewable energy certificates from Canada to the U.S. 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. Canada Canadian federal election A federal election was called for April 28, 2025. Management is monitoring the election for potential policy shifts that could impact the regulatory environment in which the Company operates. Alberta Alberta electric system operator restructured energy market (REM) On March 11, 2024, the Government of Alberta and the Alberta Electric System Operator (AESO) announced plans to restructure the energy market to address long-term reliability, affordability, and decarbonization objectives. Over the course of 2024 the AESO consulted on high-level design. On April 4, 2025, the AESO shared that it is refining the REM design to simplify the implementation and that it will no longer be pursuing day ahead energy and commitment markets as part of the design. The AESO also pivoted on key pricing parameters, indicating that the offer cap will increase from the current level of $999.99/MWh and the price cap will increase to $3,000/MWh at times of scarcity. The AESO has also indicated that its preferred approach to manage congestion is through the introduction of locational marginal pricing (LMP). Other elements of the REM design remain in place including allowing prices to be determined by strategic offers of market participants, evolving the secondary offer cap, co- optimization of energy and ancillary services, and security constrained economic dispatch. The AESO will be re-starting consultation in the second quarter of 2025 to further discuss these changes including further consultation on congestion management, LMP, and market access. The AESO and government are still pursuing the drafting and enactment of rules in 2025, which are anticipated late in 2025 or early in 2026. The AESO does not expect this to impact the longer implementation timeline of having REM implemented in 2027. Management will continue to participate in the AESO’s consultation and will assess more detailed design impacts as they become available. 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 is comprehensive and will include addressing ancillary service cost allocation, system access charges for generators and amendments to the connection process with a filing with the Alberta Utilities Commission (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. AESO update on data centres On March 20, 2025, the AESO provided an industry update on how data cent re projects introduce technical and operational challenges and its plans for a path forward. This includes near- and longer-term actions that the AESO is taking to provide projects with a reasonable opportunity to connect to the grid in a manner that is fair, efficient, and competitive. Management is actively following developments in this space and will continue to work with the AESO and other stakeholders to progress data centre development in the province. Optimal transmission planning On July 11, 2024, the Alberta Minister of Affordability and Utilities announced policy direction on long-standing transmission policy. On a go forward basis , the policy direction is to move away from the current zero -congestion transmission planning standard to an optimally planned transmission planning standard where costs of transmission are evaluated against the benefits. This will result in congestion becoming more pertinent to Alberta’s market. In response to this, the AESO will be initiating a consultation process in the second quarter of 2025 to develop this new transmission planning framework. The AESO’s objective is to develop this through the rest of 2025 with rules to be filed with the Commission in the first half of 2026. Management will monitor and participate in this engagement.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 32 Alberta TIER review In March 2025, the Province on Alberta started to consult on the performance of the TIER program for pricing industrial carbon emissions. Management is assessing how potential changes to industrial carbon policy could impact the Company and will be participating in any consultations on this topic. Ontario Market Renewal Program (MRP) Ontario's MRP is a set of coordinated market and IESO system reforms intended to improve market transparency, competitiveness, and real-time unit scheduling. It will introduce locational marginal pricing, market power mitigation, and a financially binding day-ahead market. MRP design work is complete and the IESO Board unanimously approved the market rule amendments associated with the MRP on October 18, 2024. The IESO is targeting May 1, 2025 to transition to the new market. The MRP will trigger amendments to the Company’s generating contracts with the IESO. While the overall impact MRP will have on the Company will largely depend on these amendments, the Company, if necessary, may leverage various provisions within the contracts that are intended to protect suppliers from adverse effects resulting from market rule changes. Management continues to work with the IESO to minimize the impact MRP will have on its existing fleet. On November 7, 2024, a consortium of market participants that own non-quick start natural gas generating units, including the Company, submitted an application to the Ontario Energy Board (OEB) appealing the MRP market rule amendments. The application requested the OEB to review the amendments for consistency to the Electricity Act 1998 and to determine if the MRP unjustly discriminates against a class of market participants. The OEB issued their decision in March 2025, finding that the rule amendments are not discriminatory. British Columbia (BC) BC Hydro Integrated Resource Plan (IRP) In approving BC Hydro’s 2021 IRP, the BC Utilities Commission directed BC Hydro to file a new IRP by October 31, 2025. On February 20, 2025, BC Hydro applied to the Commission to extend this filing to October 31, 2026. This was made in response to economic uncertainty that impact BC Hydro’s load forecast including the impact of tariffs, lower estimates in population growth due to lowering immigration targets and shifts in approaches to greenhouse gas emission reduction. On March 6, 2025, the Commission denied BC Hydro’s request citing the need to plan and account for a range of scenarios as part of its load forecasting approach. Management is monitoring this proceeding and related developments. 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.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 33 FINANCIAL INSTRUMENTS The classification, carrying amounts and fair values of financial instruments held at March 31, 2025 and December 31, 2024 were as follows: ($ millions) March 31, 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 689 689 865 865 Trade and other receivables 2 N/A 558 558 546 546 Government grant receivable 3 Level 2 444 423 438 400 Fair value through profit or loss Derivative financial instruments assets 3 See below 706 706 601 601 Fair value through other comprehensive income Derivative financial instruments assets 3 See below 62 62 55 55 Financial liabilities: Other financial liabilities Trade and other payables N/A 694 694 751 751 Loans and borrowings 3 Level 2 4,939 5,184 4,976 5,244 Fair value through profit or loss Derivative financial instruments liabilities 3 See below 664 664 621 621 Fair value through other comprehensive income Derivative financial instruments liabilities 3 See below 24 24 20 20 1 Fair values for Level 1 financial assets and liabilities are based on unadjusted quoted prices in active markets for identica l instruments while fair values for Level 2 financial assets and liabilities are generally based on indirectly observable price s. Level 3 valuations are determined by appropriate subject matter experts and reviewed by the Company’s commodity risk group and by management. 2 Excludes current portion of government grant receivable. 3 Includes current and non-current portion.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 34 Risk management and hedging activities There have been no material changes in the three months ended March 31, 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 March 31, 2025 compared with December 31, 2024 and used for risk management purposes were measured at fair value and consisted of the following: ($ millions) At March 31, 2025 Fair value hierarchy level Commodity cash flow hedges Commodity non-hedges Interest rate cash flow hedges Interest rate non- hedges Foreign exchange cash flow hedges Total Derivative financial instruments assets Level 2 56 579 5 - 1 641 Level 3 - 127 - - - 127 56 706 5 - 1 768 Derivative financial instruments liabilities Level 2 (2) (378) (22) (1) - (403) Level 3 - (285) - - - (285) (2) (663) (22) (1) - (688) Net derivative financial instruments assets (liabilities) 54 43 (17) (1) 1 80 ($ 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 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.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 35 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 There were no significant changes in Capital Power’s disclosure controls and procedures and internal controls over financial reporting that occurred during the three months ended March 31, 2025 that have materially affected or are reasonably likely to materially affect disclosures of required information and internal control over financial reporting.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 36 SUMMARY OF QUARTERLY RESULTS (GWh) Three months ended Electricity generation Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Sep 2023 Jun 2023 Total generation 9,555 9,408 11,001 8,603 8,809 8,692 8,521 7,857 Canada flexible generation Genesee Generating Station, Alberta 1 2,755 2,029 2,114 2,028 2,388 2,666 2,650 2,552 Clover Bar Energy Centre, Alberta 114 141 203 129 165 163 294 130 Joffre, Alberta 164 140 164 139 215 138 110 150 Shepard, Alberta 712 759 807 552 820 781 768 741 Clover Bar Landfill Gas, Alberta - - - - - - 2 1 Island Generation, British Columbia 74 - 300 - 34 - - 2 York Energy, Ontario 11 5 19 12 6 4 8 3 East Windsor, Ontario 6 3 5 2 12 3 5 3 Goreway, Ontario 954 515 901 552 799 552 800 608 EnPower, British Columbia 9 4 5 3 6 5 4 3 4,799 3,596 4,518 3,417 4,445 4,312 4,641 4,193 Canada renewables Quality Wind, British Columbia 51 100 84 93 87 135 74 73 Halkirk 1 Wind, Alberta 121 100 96 106 109 139 85 107 Halkirk 2 Wind, Alberta 2 - 2 N/A N/A N/A N/A N/A N/A Whitla Wind, Alberta 308 371 234 338 325 345 222 280 Strathmore Solar, Alberta 12 8 24 25 13 7 24 28 Clydesdale Solar, Alberta 23 16 55 52 32 7 57 54 Kingsbridge 1, Ontario 40 33 11 19 28 28 11 16 Port Dover and Nanticoke Wind, Ontario 42 74 37 63 82 81 41 54 597 704 541 696 676 742 514 612 Total Canada 5,396 4,300 5,059 4,113 5,121 5,054 5,155 4,805 U.S. flexible generation Decatur Energy, Alabama 1,070 964 1,287 883 455 666 723 494 Arlington Valley, Arizona 652 1,099 832 795 840 1,067 1,007 908 Midland Cogen, Michigan 1,100 1,295 1,436 1,444 1,298 1,333 1,276 1,154 Frederickson 1, Washington 3 192 220 258 137 246 N/A N/A N/A Harquahala, Arizona 4 138 465 860 333 - N/A N/A N/A La Paloma, California 4 423 497 901 317 277 N/A N/A N/A 3,575 4,540 5,574 3,909 3,116 3,066 3,006 2,556 U.S. renewables Beaufort Solar, North Carolina 6 6 5 7 7 6 8 8 Bloom Wind, Kansas 156 174 137 184 174 169 107 153 Macho Springs Wind, New Mexico 40 29 19 41 41 26 21 41 New Frontier Wind, North Dakota 117 107 77 107 89 110 74 83 Cardinal Point Wind, Illinois 169 162 65 143 165 167 69 134 Buckthorn Wind, Texas 96 90 65 99 96 94 81 77 584 568 368 581 572 572 360 496 Total U.S. 4,159 5,108 5,942 4,490 3,688 3,638 3,366 3,052 1 Genesee Generating Station 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 (see Significant Events in the Company’s 2024 Integrated Annual Report ). 2 Halkirk 2 Wind commenced partial operations in the fourth quarter of 2024 with full commercial operations expected in the second quarter of 2025 (See Capital Expenditures and Investments) . 3 Frederickson 1 was acquired on December 28, 202 3. Due to the proximity of the acquisition to December 31, 2023, generation for the quarter ended December 31, 2023 was immaterial. 4 Harquahala and La Paloma were acquired February 16, 2024 and February 9, 2024, respectively.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 37 (%) Three months ended Facility availability Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Sep 2023 Jun 2023 Total average facility availability 90 89 94 91 94 93 96 95 Canada flexible generation Genesee Generating Station, Alberta 1 96 78 83 96 92 96 96 96 Clover Bar Energy Centre, Alberta 77 88 94 58 56 56 95 47 Joffre, Alberta 98 91 100 80 100 89 76 95 Shepard, Alberta 100 100 100 74 98 100 99 98 Clover Bar Landfill Gas, Alberta - - - - - - 48 58 Island Generation, British Columbia 99 100 100 100 100 100 100 100 York Energy, Ontario 92 95 100 100 100 100 99 89 East Windsor, Ontario 98 97 93 99 99 97 95 99 Goreway, Ontario 90 87 100 85 99 96 100 98 EnPower, British Columbia 100 75 100 100 85 91 91 94 94 87 93 88 93 95 97 93 Canada renewables Quality Wind, British Columbia 98 97 87 98 95 98 96 92 Halkirk 1 Wind, Alberta 97 97 95 95 93 95 91 96 Halkirk 2 Wind, Alberta 2 - 100 N/A N/A N/A N/A N/A N/A Whitla Wind, Alberta 97 96 96 98 95 96 94 94 Strathmore Solar, Alberta 95 97 97 97 97 88 97 98 Clydesdale Solar, Alberta 96 97 97 97 97 88 97 97 Kingsbridge 1, Ontario 97 96 97 94 90 91 92 89 Port Dover and Nanticoke Wind, Ontario 80 89 97 98 98 97 95 96 96 96 95 97 95 95 94 94 Total Canada 94 89 93 90 94 95 96 93 U.S. flexible generation Decatur Energy, Alabama 100 81 100 98 100 79 98 100 Arlington Valley, Arizona 73 99 97 99 82 98 100 98 Midland Cogen, Michigan 94 94 95 95 93 93 97 94 Frederickson 1, Washington 3 97 100 97 50 89 N/A N/A N/A Harquahala, Arizona 4 78 56 98 80 100 N/A N/A N/A La Paloma, California 4 75 96 94 94 95 N/A N/A N/A 85 88 96 93 94 89 98 97 U.S. renewables Beaufort Solar, North Carolina 99 98 94 99 98 100 99 99 Bloom Wind, Kansas 89 93 92 94 98 96 91 98 Macho Springs Wind, New Mexico 97 97 95 96 96 97 96 98 New Frontier Wind, North Dakota 95 93 90 95 83 91 97 94 Cardinal Point Wind, Illinois 81 90 75 84 87 94 92 95 Buckthorn Wind, Texas 96 94 96 96 96 96 93 94 90 93 88 92 92 95 93 96 Total U.S. 86 89 95 93 93 90 97 97 1 Genesee Generating Station Repower 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 (see Significant Events in the Company’s 2024 Integrated Annual Report ). 2 Halkirk 2 Wind commenced partial operations in the fourth quarter of 2024 with full commercial operations expected in the second quarter of 2025 (See Capital Expenditures and Investments) . 3 Frederickson 1 was acquired on December 28, 2023. Due to the proximity of the acquisition to December 31, 2023, availability for the quarter ended December 31, 2023 was immaterial. 4 Harquahala and La Paloma was acquired February 16, 2024 and February 9, 2024, respectively .
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 38 Financial results ($ millions) Three months ended Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Sep 2023 Jun 2023 Revenues and other income Canada flexible generation 580 523 520 473 677 666 761 680 Canada renewables 30 56 43 54 61 70 50 51 U.S. flexible generation 250 198 286 138 135 84 88 69 U.S. renewables 41 37 31 38 40 39 33 34 Corporate1 14 9 5 2 3 27 35 35 Unrealized changes in fair value of commodity derivatives and emission credits 73 30 145 69 203 98 183 12 988 853 1,030 774 1,119 984 1,150 881 Adjusted EBITDA 2 Canada flexible generation 3 207 200 187 163 179 209 256 208 Canada renewables3 33 42 27 41 44 56 30 38 U.S. flexible generation 3 119 123 219 128 84 46 109 64 U.S. renewables 31 26 19 29 28 29 21 24 Corporate (23) (61) (51) (38) (56) (27) (2) (7) 367 330 401 323 279 313 414 327 1 Revenues are partly 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 Cogen and Harquahala joint ventures. 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.
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 39 Financial highlights ($ millions except per share amounts) Three months ended Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Sep 2023 Jun 2023 Revenues and other income 988 853 1,030 774 1,119 984 1,150 881 Adjusted EBITDA 1, 2 367 330 401 323 279 313 414 327 Net income 150 242 178 76 205 95 272 85 Net income attributable to shareholders of the Company 151 240 179 75 205 97 274 87 Basic earnings per share ($) 1.03 1.76 1.32 0.51 1.58 0.74 2.27 0.68 Diluted earnings per share ($)3 1.03 1.75 1.32 0.51 1.57 0.74 2.26 0.67 Net cash flows from (used in) operating activities 210 438 236 136 334 (18) 480 11 Adjusted funds from operations 1 218 182 315 178 142 162 296 151 Adjusted funds from operations per share ($) 1 1.57 1.38 2.42 1.37 1.15 1.38 2.53 1.29 Purchase of property, plant and equipment and other assets, net 288 395 231 226 218 244 262 131 1 The consolidated financial highlights, except for adjusted EBITDA, AFFO and AFFO per share were prepared in accordance with GAAP. See Non-GAAP Financial Measures and Ratios. 2 Includes adjusted EBITDA from the York Energy, Midland Cogeneration and Harquahala joint ventures. Quality Wind and Port Dover and Nanticoke Wind were partially divested on December 20, 2024, and then became joint ventures (see Significant Events in the Company’s 2024 Integrated Annual Report ). Due to the proximity to December 31, 2024, adjusted EBITDA relating to the joint venture period during the quarter was immaterial. 3 Diluted earnings per share was calculated after giving effect to outstanding share purchase options. Three months ended Spot price averages Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Sep 2023 Jun 2023 Alberta power ($ per MWh) 40 52 55 45 99 82 152 160 Alberta natural gas (AECO) ($ per GJ) 2.03 1.45 0.65 1.14 1.94 2.19 2.49 2.39 Capital Power’s Alberta portfolio average realized power price ($ per MWh) 73 78 74 78 82 84 93 85 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. 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 Mar 2025 Dec 2024 Sep 2024 Jun 2024 Mar 2024 Dec 2023 Sep 2023 Jun 2023 Share price ($/common share) High 64.95 68.73 50.88 41.99 39.43 39.88 42.34 46.73 Low 44.68 49.20 38.33 33.90 35.55 35.11 37.84 41.16 Close 47.83 63.72 49.17 38.99 38.21 37.84 37.92 42.10 Volume of shares traded (millions) 59.2 38.0 28.3 33.5 25.9 26.0 18.6 20.7
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Q1-2025 MANAGEMENT’S DISCUSSION AND ANALYSIS | CAPITAL POWER 40 Outstanding share and partnership unit data At April 25, 2025, the Company had 154.648 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 April 25, 2025 were 155.811 million. The outstanding special limited voting share is held by EPCOR. In 2022, Capital Power issued 350,000 Series 2022-A Class A Preferred Shares to the Computershare Trust Company of Canada, to be held in trust. These shares were cancelled in August 2024 with the removal of the provision for issuing preferred shares in the event of certain bankruptcy and related events, upon conversion of the $350 million 7.95% Fixed-to-Fixed Rate Subordinated Notes, Series 1 to Series 3. At April 25, 2025, CPLP had 323.305 million general partnership units outstanding and 1,203.255 million 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.
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Condensed Interim Consolidated Financial Statements of CAPITAL POWER CORPORATION (Unaudited, in millions of Canadian dollars) Three months ended March 31, 2025 and 2024
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CAPITAL POWER CORPORATION Condensed Interim Consolidated Financial Statements Three months ended March 31, 2025 and 2024 Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 42 Condensed Interim Consolidated Financial Statements: Condensed Interim Consolidated Statements of Income 43 Condensed Interim Consolidated Statements of Comprehensive Income 44 Condensed Interim Consolidated Statements of Financial Position 45 Condensed Interim Consolidated Statements of Changes in Equity 46 Condensed Interim Consolidated Statements of Cash Flows 48 Notes to the Condensed Interim Consolidated Financial Statements 49
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CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Income (Unaudited, in millions of Canadian dollars, except per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 43 Three months ended March 31, 2025 2024 Revenues $ 955 $ 1,097 Other income 33 22 Energy purchases and fuel (489) (526) Gross margin 499 593 Other raw materials and operating charges (53) (46) Staff costs and employee benefits expense (41) (49) Depreciation and amortization (126) (122) Other administrative expense (45) (56) Foreign exchange gain (loss) 2 (10) Operating income 236 310 Net finance expense (61) (42) Income from joint ventures 24 12 (Loss) gain on disposals and other transactions (1) 2 Income before tax 198 282 Income tax expense (note 3) (48) (77) Net income $ 150 $ 205 Attributable to: Non-controlling interests $ (1) $ - Shareholders of the Company $ 151 $ 205 Earnings per share attributable to common shareholders of the Company: Basic (note 4) $ 1.03 $ 1.58 Diluted (note 4) $ 1.03 $ 1.57 See accompanying notes to the condensed interim consolidated financial statements
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CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Comprehensive Income (Unaudited, in millions of Canadian dollars) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 44 Three months ended March 31, 2025 2024 Net income $ 150 $ 205 Other comprehensive (loss) income: Items that may be reclassified subsequently to net income: Unrealized gains on derivative instruments1 (note 5) 10 70 Reclassification of (gains) losses on derivative instruments to net income2 (note 5) (9) 3 Equity-accounted investments3 (4) 5 Net investment in foreign subsidiaries: Unrealized (losses) gains (2) 39 Other comprehensive (loss) income for the period, net of tax (5) 117 Total comprehensive income for the period $ 145 $ 322 Attributable to: Non-controlling interests $ (1) $ - Shareholders of the Company $ 146 $ 322 1 For the three months ended March 31, 2025 and 2024, net of income tax expense of $4 and of $13, respectively. 2 For the three months ended March 31, 2025 and 2024, net of reclassification of income tax expense of $3 and income tax recovery of $1, respectively. 3 For the three months ended March 31, 2025 and 2024, net of income tax recovery of $1 and income tax expense of $1, respectively. See accompanying notes to the condensed interim consolidated financial statements
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CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Financial Position (Unaudited, in millions of Canadian dollars) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 45 March 31, 2025 December 31, 2024 Assets Current assets: Cash and cash equivalents $ 689 $ 865 Trade and other receivables 617 604 Inventories 207 235 Derivative financial instruments (note 5) 292 244 1,805 1,948 Non-current assets: Property, plant and equipment 8,090 8,061 Equity-accounted investments 1,109 1,096 Intangible assets and goodwill 726 744 Right-of-use assets 115 118 Derivative financial instruments (note 5) 476 412 Government grant receivable 385 380 Deferred tax assets 25 26 Other assets 119 145 Total assets $ 12,850 $ 12,930 Liabilities and equity Current liabilities: Trade and other payables $ 694 $ 751 Derivative financial instruments (note 5) 184 147 Loans and borrowings 467 157 Provisions 63 85 Deferred revenue and other liabilities 105 213 1,513 1,353 Non-current liabilities: Derivative financial instruments (note 5) 504 494 Loans and borrowings 4,472 4,819 Lease liabilities 133 134 Deferred tax liabilities 920 863 Provisions 360 373 Deferred revenue and other liabilities 315 323 Total liabilities 8,217 8,359 Share capital (note 6) 4,317 4,301 Deficit (21) (74) Other reserves 344 349 Equity attributable to shareholders of the Company 4,640 4,576 Non-controlling interests (7) (5) Total equity 4,633 4,571 Total liabilities and equity $ 12,850 $ 12,930 See accompanying notes to the condensed interim consolidated financial statements
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CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Changes in Equity (Unaudited, in millions of Canadian dollars) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 46 Share capital (note 6) 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 - - - - - 151 151 (1) 150 Other comprehensive loss - (3) (2) - - - (5) - (5) Total comprehensive income (loss) - (3) (2) - - 151 146 (1) 145 Distributions to non- controlling interests - - - - - - - (1) (1) Common share dividends (note 6) - - - - - (91) (91) - (91) Preferred share dividends, net of tax2 (note 6) - - - - - (7) (7) - (7) Dividends reinvested 16 - - - - - 16 - 16 Balance, March 31, 2025 $ 4,317 $ 105 $ 238 $ (9) $ 10 $ (21) $ 4,640 $ (7) $ 4,633 1 Accumulated other comprehensive (loss) 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 income tax expense of nil. See accompanying notes to the condensed interim consolidated financial statements
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CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Changes in Equity (Unaudited, in millions of Canadian dollars) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 47 Share capital (note 6) 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 - - - - - 205 205 - 205 Other comprehensive income - 78 39 - - - 117 - 117 Total comprehensive income - 78 39 - - 205 322 - 322 Common share dividends (note 6) - - - - - (79) (79) - (79) Preferred share dividends, net of tax2 (note 6) - - - - - (10) (10) - (10) Issue of share capital, net3 387 - - - - - 387 - 387 Dividends reinvested 15 - - - - - 15 - 15 Share options exercised 2 - - - - - 2 - 2 Balance, March 31, 2024 $ 3,928 $ 126 $ 61 $ (10) $ 10 $ (288) $ 3,827 $ (4) $ 3,823 1 Accumulated other comprehensive loss. Other reserves on the statements of financial position are the aggregate of accumulated other comprehensive loss. 2 Net of income tax expense of $1. 3 Net of income tax recovery of $3 and share issue costs of $16. See accompanying notes to the condensed interim consolidated financial statements
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CAPITAL POWER CORPORATION Condensed Interim Consolidated Statements of Cash Flows (Unaudited, in millions of Canadian dollars) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 48 Three months ended March 31, 2025 2024 Cash flows from operating activities: Net income $ 150 $ 205 Non-cash adjustments: Depreciation and amortization 126 122 Net finance expense 61 42 Fair value changes on commodity derivative instruments and emission credits held for trading (58) (200) Foreign exchange (gains) losses (2) 10 Income tax expense 48 77 Income from equity-accounted investments (24) (12) Tax-equity attributes (22) (20) Other (3) - Change in fair value of derivative instruments, cash settlement 11 12 Distributions received from joint ventures 5 8 Interest paid (85) (48) Income taxes recovered (paid) 2 (15) Other (24) (9) Change in non-cash operating working capital 25 162 Net cash flows from operating activities 210 334 Cash flows used in investing activities: Purchase of property, plant and equipment and other assets, net1 (288) (218) Business acquisition, net of acquired cash - (909) Acquisition of equity-accounted investment - (317) Other 12 5 Net cash flows used in investing activities (276) (1,439) Cash flows used in financing activities: Repayment of loans and borrowings (19) (64) Dividends paid (note 6) (82) (66) Capitalized interest paid (9) (16) Income taxes paid on preferred share dividends (3) (4) Issue costs and other (2) (15) Net cash flows used in financing activities (115) (165) Foreign exchange gain (loss) on cash held in a foreign currency 5 (1) Net decrease in cash and cash equivalents (176) (1,271) Cash and cash equivalents, beginning of period 865 1,423 Cash and cash equivalents, end of period $ 689 $ 152 1 Reflects total additions for the three months ended March 31, 2025, increased by $159 for changes in non-cash investing working capital and other non-current assets (three months ended March 31, 2024 – increased by $24), to arrive at cash additions of property, plant and equipment and other assets. See accompanying notes to the condensed interim consolidated financial statements
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 49 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 8. These condensed interim consolidated financial statements were approved and authorized for issue by the Board of Directors on April 29, 2025.
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 50 3. Income tax: Income taxes differ from the amount that would be computed by applying the federal and provincial income tax rates as follows: Three months ended March 31, 2025 2024 Net income before tax $ 198 $ 282 Income tax at the statutory rate of 23% 46 65 Increase (decrease) resulting from: Non-taxable amounts - 4 Amounts attributable to non-controlling interests and tax-equity interests - (2) Statutory and other rate differences 3 2 Other (1) 8 Income tax expense $ 48 $ 77 4. Earnings per share: The earnings and weighted average number of common shares used in the calculation of basic and diluted earnings per share are as follows: Three months ended March 31, 2025 2024 Income for the period attributable to shareholders $ 151 $ 205 Preferred share dividends1 (7) (10) Earnings available to common shareholders $ 144 $ 195 Weighted average number of common shares 139,180,095 123,669,718 Basic earnings per share $ 1.03 $ 1.58 Weighted average number of common shares 139,180,095 123,669,718 Effect of dilutive share purchase options 335,795 233,593 Diluted weighted average number of common shares 139,515,890 123,903,311 Diluted earnings per share $ 1.03 $ 1.57 1 Includes preferred share dividends declared and related taxes.
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 51 5. Derivative financial instruments and hedge accounting: Derivative financial and non-financial instruments are held for the purpose of energy purchases, merchant trading or financial risk management. The Company has elected to apply hedge accounting on certain derivatives it uses 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: March 31, 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 $ 31 $ 259 $ 1 $ - $ 1 $ 292 Non-current 25 447 4 - - 476 Derivative instruments liabilities: Current (1) (175) (8) - - (184) Non-current (1) (488) (14) (1) - (504) Net fair value $ 54 $ 43 $ (17) $ (1) $ 1 $ 80 Net notional buys (sells) (millions): Megawatt hours of electricity (3) (51) Gigajoules of natural gas purchased 1 216 Gigajoules of natural gas basis swaps 1 64 Metric tonnes of emission allowances 9 Number of renewable energy credits (11) Interest rate swaps $ 861 $ 106 Forward currency buys (U.S. dollars) $ 14 Range of remaining contract terms in years 0.1 to 3.8 0.1 to 21.8 0.2 to 1.8 0.2 to 0.8 0.1 to 0.4 1 The Company’s natural gas trading strategy employs future purchase derivative instruments as well as basis swaps pertaining to certain of the future purchase derivative instruments, to manage its exposure to commodity price risk.
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 52 5. 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 2 197 Gigajoules of natural gas basis swaps 2 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 in 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 2 The Company’s natural gas trading strategy employs future purchase derivative instruments as well as basis swaps pertaining to certain of the future purchase derivative instruments, to manage its exposure to commodity price risk. Unrealized and realized pre-tax gains and (losses) on derivative instruments recognized in other comprehensive (loss) income and net income are: Three months ended March 31, 2025 Three months ended March 31, 2024 Unrealized gains (losses) Realized gains (losses) Unrealized gains Realized (losses) gains Energy cash flow hedges $ 16 $ 9 $ 42 $ (7) Energy and emission allowances non-hedges 69 60 200 (21) Interest rate cash flow hedges (9) 3 16 3 Interest rate non-hedges (1) - - - Foreign exchange cash flow hedges (5) - 29 - Foreign exchange non-hedges - (5) - (1)
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 53 5. Derivative financial instruments and hedge accounting, continued: The following realized and unrealized gains and losses on derivative financial instruments are included in the Company’s statements of income: Three months ended March 31, 2025 2024 Revenues $ 213 $ 190 Energy purchases and fuel (75) (18) Foreign exchange loss (5) (1) Net finance expense 2 3 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: March 31, 2025 Within one year $ 44 Between one and five years 64 After five years 14 $ 122 6. Share capital: Common and preferred share dividends Dividends declared Dividends paid 2025 2024 2025 2024 Per share Total Per share Total Per share Total Per share Total Common1 $ 0.6519 $ 91 $ 0.6150 $ 79 $ 0.6519 $ 91 $ 0.6150 $ 72 Preference: Series 1 0.1638 1 0.1638 1 0.1638 1 0.1638 1 Series 3 0.4288 3 0.4288 3 0.4288 3 0.4288 3 Series 5 0.4144 3 0.4144 3 0.4144 3 0.4144 3 Series 112 N/A - 0.3594 2 N/A - 0.3594 2 1 For the three months ended March 31, 202 5, common dividends consist of $75 million paid in cash and $16 million through the Company’s dividend re-investment plan (three months ended March 31, 2024, $57 million paid in cash and $15 million through the Company’s dividend re-investment plan). 2 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.
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 54 7. 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: March 31, 2025 December 31, 2024 Fair value hierarchy level Carrying amount Fair value Carrying amount Fair value Financial assets1 Government grant receivable Level 2 $ 444 $ 423 $ 438 $ 400 Financial liabilities1 Loans and borrowings Level 2 $ 4,939 $ 5,184 $ 4,976 $ 5,244 1 Includes current portion. 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. March 31, 2025 Level 1 Level 2 Level 3 Total Derivative financial instruments assets $ - $ 641 $ 127 $ 768 Derivative financial instruments liabilities - (403) (285) (688)
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 55 7. Financial instruments, continued: 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 202 4 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: March 31, 2025 December 31, 2024 REC pricing (per certificate) – Solar $4 to $206 $3 to $201 REC pricing (per certificate) – Wind $4 to $8 $3 to $8 Forward power pricing (per MWh) – Solar $21 to $165 $15 to $113 Forward power pricing (per MWh) – Wind $16 to $146 $15 to $142 Average monthly notional generation (MWh) – Solar 6,575 to 13,119 6,554 to 13,044 6,671 Average monthly notional generation (MWh) – Wind 16,465 to 60,297 16,540 to 60,060 39,123 The table below presents the change to the fair value of Level 3 derivative instruments based on a 10% change in the respective input: March 31, 2025 December 31, 2024 REC pricing – Solar $ 2 $ 2 REC pricing – Wind 4 4 Forward power pricing – Solar 15 4 Forward power pricing – Wind 55 59 Generation – Solar 2 4 Generation – Wind 16 13
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 56 7. Financial instruments, continued: Fair value hierarchy, 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: March 31, 2025 December 31, 2024 At January 11 $ (156) $ (297) Additions - 27 Unrealized and realized (losses) gains included in net income2 (13) 137 Settlements 11 (15) Transfers3 - 1 Foreign exchange losses - (9) At end of period $ (158) $ (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.
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 57 8. Segment information: Reportable segments 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. 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 March 31, 2025 Canada flexible generation1 Canada renewables1 U.S. flexible generation1 U.S. renewables Corporate Total Equity- accounted investments1 Reclass adjustments IFRS financials Revenues and other income2 $ 639 $ 16 $ 397 $ 71 $ 14 $ 1,137 $ (149) $ 988 Energy purchases and fuel (307) (2) (245) - - (554) 65 (489) Other raw materials and operating charges (20) (6) (32) (4) (1) (63) 10 (53) Staff costs and employee benefits expense (15) - (10) (1) (19) (45) 4 (41) Other administrative expense (14) (4) (14) (5) (17) (54) 9 (45) Remove unrealized changes in fair value of commodity derivatives (80) 29 23 (30) - (58) - 58 - Remove other non- recurring items 4 - - - - 4 - (4) - Adjusted EBITDA3 207 33 119 31 (23) 367 Depreciation and amortization (126) Foreign exchange gain 2 Losses on disposals (1) Net finance expense (61) Share of profits of an associate 24 Income before tax $ 198
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 58 8. Segment information, continued: Reportable segments, continued Three months ended March 31, 2024 Canada flexible generation1 Canada renewables1 U.S. flexible generation1 U.S. renewables Corporate Total Equity- accounted investments1 Reclass adjustments IFRS financials Revenues and other income2 $ 795 $ 185 $ 236 $ (1) $ 3 $ 1,218 $ (99) $ 1,119 Energy purchases and fuel (450) (8) (112) 1 - (569) 43 (526) Other raw materials and operating charges (21) (7) (19) (4) - (51) 5 (46) Staff costs and employee benefits expense (14) (1) (8) - (29) (52) 3 (49) Other administrative expense (15) (5) (10) (7) (30) (67) 11 (56) Remove unrealized changes in fair value of commodity derivatives (116) (120) (3) 39 - (200) - 200 - Adjusted EBITDA3 179 44 84 28 (56) 279 Depreciation and amortization (122) Foreign exchange loss (10) Gains on disposals 2 Net finance expense (42) Share of profits of an associate 12 Income before tax $ 282 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 Revenues and other income from external customers from Canada are comprised of the revenues and other income in the Canada flexible generation and Canada renewables segments. Revenues and other income from external customers from the U.S. are comprised of the revenues and other income in the U.S. flexible generation and U.S. renewables segments. 3 Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Additional geographic information The Company’s Canadian facilities are located in Alberta, British Columbia and Ontario and i ts U.S. facilities in Alabama, Arizona, California, Illinois, Kansas, Michigan, New Mexico, North Carolina, North Dakota, 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 March 31, 2025 At December 31, 2024 Canada U.S. Total Canada U.S. Total Property, plant and equipment $ 5,488 $ 2,602 $ 8,090 $ 5,457 $ 2,604 $ 8,061 Equity-accounted investments 408 701 1,109 397 699 1,096 Intangible assets and goodwill 507 219 726 519 225 744 Right-of-use assets 52 63 115 54 64 118 Other assets4 69 63 132 73 84 157 $ 6,524 $ 3,648 $ 10,172 $ 6,500 $ 3,676 $ 10,176 4 Includes current portion of finance lease receivable.
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 59 8. Segment information, continued: Major customer For the three months ended March 31, 2025, the Company recorded revenues o f $149 million from the Alberta Electric System Operator (AESO), within the Canada flexible generation and Canada renewables segments (2024 - $356 million). 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 March 31, 2025 Canada flexible generation Canada renewables U.S. flexible generation U.S. renewables Total from contracts with customers Other sources Total Energy revenues $ 457 $ 19 $ 155 $ 19 $ 650 $ 302 $ 952 Emission credit revenues - 14 - 2 16 (13) 3 Total revenues5 $ 457 $ 33 $ 155 $ 21 $ 666 289 $ 955 Three months ended March 31, 2024 Canada flexible generation Canada renewables U.S. flexible generation U.S. renewables Total from contracts with customers Other sources Total Energy revenues $ 643 $ 51 $ 97 $ 14 $ 805 $ 268 $ 1,073 Emission credit revenues - 10 - 2 12 12 24 Total revenues5 $ 643 $ 61 $ 97 $ 16 $ 817 280 $ 1,097 5 Included within trade and other receivables, at March 31, 202 5, were amounts related to contracts with customers of $272 million (2024 - $325 million).
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CAPITAL POWER CORPORATION Notes to the Condensed Interim Consolidated Financial Statements March 31, 2025 and 2024 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts) Q1-2025 CONSOLIDATED FINANCIAL STATEMENTS | CAPITAL POWER 60 9. Subsequent events: Acquisition of Hummel Station Intermediate Holdings III, LLC and Rolling Hills Generating Holdings, LLC Consistent with the Company’s strategy to acquire flexible generation assets in the U.S, on April 14, 2025, Capital Power entered into a definitive agreement with Hummel Station Intermediate Holdings III, LLC and Rolling Hills Generating Holdings, LLC, each a subsidiary of LS Power Equity Advisors, LLC, to acquire 100% of the equity interests in: 1. Hummel Station, LLC, which owns the 1,124 MW Hummel Station, a combined -cycle natural gas facility in Shamokin Dam, Pennsylvania (Hummel Acquisition), and 2. Rolling Hills Generating, L.L.C., which owns the 1,023 MW Rolling Hills plant, a combustion turbine natural gas facility in Wilkesville, Ohio (Rolling Hills Acquisition and together with the Hummel Acquisition, the Acquisition). The total purchase price of the Acquisition is expected to be approximately $3.0 billion (US$2.2 billion), subject to customary post -closing adjustments, including working capital and estimated transaction expenses. The Acquisition is expected to close in the third quarter of 2025, subject to regulatory approvals and other customary closing conditions. Common share offering On April 22, 2025, t he Company completed a public offering of 11,902,500 common shares, which included 1,552,500 common shares issued pursuant to the full exercise of the over-allotment option, at $43.45 per common share (Offering Price) for total gross proceeds of approximately $517 million. The Company also issued 3,455,000 common shares at the Offering Price on a private placement basis, for gross proceeds of $150 million, subject to a statutory hold period of 4 months and one day from the closing date of the private placement. Acquisition Term Loan Facilities For purposes of financing the Acquisition, the Company entered into an agreement with a lender on April 14, 2025, whereby the lender has agreed to provide, on a fully underwritten basis, senior unsecured term loan facilities in the aggregate principal amount of up to $2 billion (Acquisition Term Loan Facilities). The Acquisition Term Loan Facilities are comprised of two tranches of $1 billion non-extendible, non-revolving, syndicated term credit facilities, with the first tranche maturing in 2028 and the second tranche maturing in 2027. 10. Comparative figures: The comparative figures have been reclassified to conform with the presentation adopted for 2025.