Earnings release
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St. John's, NL - November 4, 2025 FORTIS INC. RELEASES THIRD QUARTER 2025 RESULTS, NEW FIVE-YEAR CAPITAL OUTLOOK AND 4% INCREASE IN FOURTH QUARTER DIVIDEND This news release constitutes a "Designated News Release" incorporated by reference in the prospectus supplement dated December 9, 2024 to Fortis' short form base shelf prospectus dated December 9, 2024. Fortis Inc. ("Fortis" or the "Corporation") (TSX/NYSE: FTS), a diversified leader in the North American regulated electric and gas utility industry, released its third quarter results and 2026-2030 outlook1. Highlights • Third quarter net earnings of $409 million or $0.81 per common share, compared to $0.85 per common share in 2024 • Adjusted net earnings per common share 2 of $0.87, up from $0.85 in the third quarter of 2024 • Capital expenditures 2 of $4.2 billion through September; capital investments of $5.6 billion expected for 2025 • Released 2026-2030 capital plan of $28.8 billion, $2.8 billion higher than prior plan and supporting 7.0% rate base growth 3 • Increased fourth quarter common share dividend by 4.1% and extended annual dividend growth guidance of 4-6% through 2030 • Disposition of FortisTCI closed in September 2025 and sale of Belize assets closed in October 2025 "During the third quarter, our utilities delivered earnings growth and executed capital investments in line with expectations," said David Hutchens, President and Chief Executive Officer, Fortis. "Today we are pleased to unveil our largest five-year capital plan of $28.8 billion, an increase of $2.8 billion over our prior plan. The increase is driven by higher transmission investments at ITC, as well as customer growth and reliability investments across our utilities. We remain focused on low-risk, regulated utility growth, and our recent decisions to sell assets further support our funding plan and strengthen the balance sheet. Our highly executable capital plan extends our robust rate base growth and supports annual dividend growth of 4-6% through 2030 for shareholders." Net Earnings The Corporation reported net earnings attributable to common equity shareholders ("Net Earnings") of $409 million for the third quarter of 2025, or $0.81 per common share, a decrease of $11 million, or $0.04 per common share compared to the third quarter of 2024. The decrease was due to income taxes and closing costs totalling $32 million, or $0.06 per common share, associated with the disposition of FortisTCI. Excluding the above-noted item, Net Earnings increased by $21 million, or $0.02 per common share, compared to the third quarter of 2024. The increase was primarily due to rate base growth across our utilities, including growth associated with major capital projects. The higher U.S. dollar-to-Canadian dollar exchange rate also contributed to the increase in earnings. The increase was partially offset by higher costs associated with rate base growth not yet reflected in customer rates at UNS Energy, the expiration of a regulatory incentive and a lower allowed rate of return on common equity ("ROE") at FortisAlberta, and higher holding company finance costs. On a year-to-date basis and excluding the impact of the disposition of FortisTCI as discussed above, Net Earnings increased by $114 million, or $0.18 per common share compared to the same period in 2024. The increase was due to the factors discussed for the quarter, and also reflected growth at Central Hudson due to the rebasing of costs and a higher allowed ROE effective July 1, 2024 and the timing of operating costs in 2025. The increase was partially offset by lower margin on wholesale sales at UNS Energy and the timing of operating costs at FortisAlberta. The change in earnings per share for both the third quarter and year-to-date periods also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's dividend reinvestment plan. __________________ 1 Financial information is presented in Canadian dollars unless otherwise specified. 2 Fortis uses financial measures that do not have a standardized meaning under generally accepted accounting principles in the United States of America ("U.S. GAAP") and may not be comparable to similar measures presented by other entities. Fortis presents these non-U.S. GAAP measures because management and external stakeholders use them in evaluating the Corporation's financial performance. Refer to the Non-U.S. GAAP Reconciliation provided herein. 3 Reflects the five-year compound annual growth rate calculated using a constant U.S. dollar-to-Canadian dollar exchange rate. i
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Adjusted Net Earnings2 Adjusted net earnings attributable to common equity shareholders ("Adjusted Net Earnings") reflects the removal of items that management excludes in its key decision-making processes and evaluation of operating results. For the three and nine months ended September 30, 2025, Net Earnings were favourably adjusted by $32 million related to the disposition of FortisTCI, as previously discussed. There were no adjustments to Net Earnings for the three and nine months ended September 30, 2024. 2025 Capital Expenditures and New Five-Year Capital Plan Capital expenditures for 2025 are expected to be approximately $5.6 billion, up from $5.2 billion previously anticipated for the year. The increase is driven by higher transmission investments at ITC and a higher forecast U.S. dollar-to-Canadian dollar exchange rate. The Corporation's new 2026-2030 capital plan totals $28.8 billion, $2.8 billion higher than the previous five-year plan. The increase is primarily driven by higher transmission investments associated with new interconnections, the Midcontinent Independent System Operator ("MISO") long-range transmission plan ("LRTP") and baseline reliability projects at ITC. It also includes incremental capital at UNS Energy, reflecting an increase in transmission and distribution investments to serve load growth, increase reliability, and provide a path for connecting future generation resources. Planned generation investments in Arizona have also been updated to reflect the recently announced Springerville Natural Gas Conversion project. Customer growth and reliability investments across our utilities, as well as a higher assumed U.S. dollar-to-Canadian dollar exchange also contributed to the increase in the five-year plan. The plan is low-risk and highly executable, with only 21% relating to major capital projects. The five-year capital plan is expected to be funded primarily by cash from operations and regulated debt. Common equity proceeds are expected to be provided by the Corporation's dividend reinvestment plan, assuming current participation levels. The Corporation's $500 million at-the-market common equity program has not been utilized to date and remains available for funding flexibility as required. Significant opportunities remain beyond the five-year plan, including incremental investments associated with MISO LRTP tranche 2.1 projects. ITC estimates a range of US$3.7 billion to US$4.2 billion in capital expenditures for the MISO tranche 2.1 projects located in Michigan and Minnesota where rights of first refusal are in effect and for projects requiring system upgrades in Iowa which are not subject to a competitive bidding process. Tranche 2.1 investments of only US$0.4 billion have been included in the Corporation's 2026-2030 capital plan. Any additional tranche 2.1 projects awarded to ITC as part of a competitive bidding process would be incremental to the estimated range of investments. ITC is evaluating projects within the portfolio and preparing to bid as deemed appropriate. Tucson Electric Power ("TEP") is experiencing interest from potential new large retail customers in the manufacturing, data center, and mining sectors with energy demands that may create new energy needs. In particular, negotiations are ongoing with a customer for capacity to support a multi-phase data center development. Additional generation investments would be required to support such capacity requirements, and TEP continues to work with the potential customers to assess capital requirements and associated timelines. TEP and UNS Electric are expecting to file new Integrated Resource Plans in 2026, which will support increasing energy needs while taking into account reliable and affordable energy solutions. Fourth Quarter 2025 Dividends The Board of Directors of Fortis has declared the following dividends payable on December 1, 2025 to the Shareholders of Record of the following Shares of the Corporation at the close of business on November 17, 2025: • $0.3063 per share on the First Preference Shares, Series "F"'; • $0.3826875 per share on the First Preference Shares, Series "G"; • $0.26144 per share on the First Preference Shares, Series "H"; • $0.258290 per share on the First Preference Shares, Series "I"; • $0.2969 per share on the First Preference Shares, Series "J"; • $0.3418125 per share on the First Preference Shares, Series "K"; • $0.3433125 per share on the First Preference Shares, Series "M"; and, • $0.64 per share on the Common Shares. The Corporation has designated the common share dividend and preference share dividends as eligible dividends for federal and provincial dividend tax credit purposes. Disposition of Assets The Corporation sold its utility in Turks and Caicos in September 2025, and its assets in Belize, including the non-regulated hydro generation facilities, in October 2025. Proceeds from the dispositions will be used to further strengthen the balance sheet and provide additional funding flexibility in support of our regulated utility growth strategy. ii
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Regulatory Update In August 2025, the New York State Public Service Commission approved a three-year rate plan for Central Hudson with retroactive application to July 1, 2025, including the continuation of a 9.5% allowed ROE and a 48% common equity component of capital structure. The three-year rate plan also reflects the use of existing regulatory balances and other measures to reduce customer bill impacts, as well as initiatives to support New York States's energy conservation emission reduction goals. Outlook Fortis continues to enhance shareholder value through the execution of its capital plan, the balance and strength of its diversified portfolio of regulated utility businesses, and growth opportunities within and proximate to its service territories. The Corporation's $28.8 bi llion five-year capital plan is expected to increase midyear rate base from $41.9 billion in 2025 to $57.9 billion by 2030, representing an annual growth rate of 7.0%. 3 Fortis expects its long-term growth in rate base will drive earnings that support dividend growth guidance of 4-6% annually through 2030. Planned capital expenditures are based on forecasted energy demand, labour and material costs, and macro economic factors. The Corporation continues to monitor government policy on foreign trade, including the imposition of tariffs and the potential impacts on the supply chain, commodity prices, the cost of energy and general economic conditions. While it is not possible to predict the impact on the supply chain, business operations or the five-year capital plan, the Corporation does not currently expect a material financial impact in 2025. Beyond the five-year capital plan, opportunities to expand and extend growth include: further expansion of the electric transmission grid in the U.S. to support load growth and facilitate the interconnection of new energy resources; transmission investments associated with the MISO LRTP as well as regional transmission in New York; grid resiliency and climate adaptation investments; investments in renewable gas and liquefied natural gas infrastructure in British Columbia; and the acceleration of load growth and cleaner energy infrastructure investments across our jurisdictions. The Corporation's ability to achieve its interim greenhouse gas ("GHG") emissions reduction targets of 50% by 2030 and 75% by 2035 is expected to be impacted by factors including significant load growth, customer affordability, the pace of development of clean energy technology as well as federal, state and provincial energy policies. While Fortis remains committed to a coal-free generation mix by 2032 and its 2050 net-zero goal, the Corporation expects it will take longer to achieve the interim GHG reduction targets. As energy resource planning advances across the utilities, Fortis will reassess the interim targets and will share the results once complete. Non-U.S. GAAP Reconciliation Periods ended September 30 Quarter Year-to-Date ($ millions, except as indicated) 2025 2024 Variance 2025 2024 Variance Adjusted Net Earnings Net Earnings 409 420 (11) 1,292 1,210 82 Adjusting item: Disposition of FortisTCI4 32 — 32 32 — 32 Adjusted Net Earnings 441 420 21 1,324 1,210 114 Adjusted net earnings per share ($) 0.87 0.85 0.02 2.63 2.45 0.18 Capital Expenditures Additions to property, plant and equipment 1,362 1,248 114 4,324 3,383 941 Additions to intangible assets 91 52 39 216 142 74 Adjusting items: Eagle Mountain Pipeline Project5 (137) — (137) (369) — (369) Wataynikaneyap Transmission Power Project6 — — — — 29 (29) Capital Expenditures 1,316 1,300 16 4,171 3,554 617 ___________________ 4 Reflects income taxes and closing costs associated with the disposition of FortisTCI. 5 Represents contributions in aid of construction received for the Eagle Mountain Pipeline project. 6 Represents Fortis' 39% share of capital spending during the construction of the Wataynikaneyap Transmission Power project. Construction was completed in the second quarter of 2024. iii
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About Fortis Fortis is a diversified leader in the North American regulated electric and gas utility industry with 2024 revenue of $12 billion and total assets of $75 billion as at September 30, 2025. The Corporation's 9,600 employees serve utility customers in five Canadian provinces, ten U.S. states and the Caribbean. Forward-Looking Information Fortis includes forward-looking information in this news release within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates, expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would, and the negative of these terms, and other similar terminology or expressions, have been used to identify the forward-looking information, which includes, without limitation: forecast capital expenditures for 2025 and 2026 through 2030; annual dividend growth guidance through 2030; the nature, timing, benefits and costs of certain major capital projects, including investments associated with the MISO LRTP and the Springerville Natural Gas Conversion project; expected sources of funding for the capital plan, including sources of common equity proceeds; the nature, timing, benefits and costs of additional investment opportunities, including further investments at ITC associated with the MISO LRTP tranche 2.1 projects, further investments at TEP required to serve potential new large retail customers in the manufacturing, data center and mining sectors, and further investments at TEP and UNS Electric associated with new Integrated Resource Plans expected to be filed in 2026; the expected use of proceeds related to the disposition of assets; forecast rate base and rate base growth through 2030; the expectation that long-term growth in rate base will drive earnings that support dividend growth guidance of 4-6% annually through 2030; the expectation that government policy on foreign trade, including the imposition of tariffs and the potential impacts on the supply chain, commodity prices, the cost of energy and general economic conditions, will not have a material financial impact on the Corporation in 2025; the nature and benefits of opportunities to expand and extend the capital plan; the 2030 and 2035 interim GHG emissions reduction targets; the expectation that factors, including significant load growth, customer affordability, the pace of development of clean energy technology as well as federal, state and provincial energy policies, will impact the Corporation's ability to achieve its interim GHG emission reduction targets; the expectation that the Corporation will take longer to achieve its interim GHG reduction targets; and the planned reassessment of the Corporation's interim GHG reduction targets and associated disclosure. Forward-looking information involves significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: the successful execution of the capital plan; the continued ability to maintain the performance of the electricity and gas systems; no material capital project and financing cost overrun; sufficient human resources to deliver service and execute the capital plan; the continued availability of natural gas, fuel, coal and electricity supply; reasonable outcomes for regulatory proceedings and the expectation of regulatory stability; no significant variability in interest rates; no material changes in the assumed U.S. dollar- to-Canadian dollar exchange rate; the Board of Directors of the Corporation exercising its discretion to declare dividends, taking into account the business performance and financial condition of the Corporation; no significant operational disruptions or environmental liability or upset; no severe and prolonged economic downturn; no significant changes in government energy plans, environmental laws and regulations that could have a material negative impact; and the realization of additional opportunities beyond the capital plan. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. For additional information with respect to certain risk factors, reference should be made to the continuous disclosure materials filed from time to time by the Corporation with Canadian securities regulatory authorities and the Securities and Exchange Commission. All forward-looking information herein is given as of the date of this media release. Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise. Teleconference and Webcast A teleconference and webcast will be held on November 4, 2025 at 8:30 a.m. (Eastern) during which David Hutchens, President and Chief Executive Officer and Jocelyn Perry, Executive Vice President and Chief Financial Officer will discuss the Corporation's third quarter financial results and new five-year outlook. Shareholders, analysts, members of the media and other interested parties are invited to listen to the teleconference via the live webcast on the Corporation's website, www.fortisinc.com/investors/events-and-presentations. Those members of the financial community in Canada and the United States wishing to ask questions during the call are invited to participate toll free by calling 1.833.821.0229. Individuals in other international locations can participate by calling 1.647.846.2371. Please dial in 10 minutes prior to the start of the call. No access code is required. An archived audio webcast of the teleconference will be available on the Corporation's website two hours after the conclusion of the call until December 4, 2025. Please call 1.855.669.9658 or 1.412.317.0088 and enter access code 1925124#. iv
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Additional Information This news release should be read in conjunction with the Corporation's September 30, 2025 Interim Management Discussion and Analysis and Condensed Consolidated Financial Statements. This and additional information can be accessed at www.fortisinc.com, www.sedarplus.ca, or www.sec.gov. For more information, please contact: Investor Enquiries Media Enquiries Ms. Stephanie Amaimo Ms. Karen McCarthy Vice President, Investor Relations Vice President, Communications & Government Relations Fortis Inc. Fortis Inc. 248.946.3572 709.737.5323 investorrelations@fortisinc.com media@fortisinc.com v
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Contents About Fortis .............................................................................................. 1 Cash Flow Summary ............................................................................. 13 Performance at a Glance ........................................................................... 2 Contractual Obligations ........................................................................ 15 Business Unit Performance ....................................................................... 5 Capital Structure and Credit Ratings ..................................................... 15 ITC ........................................................................................................ 5 Capital Plan ........................................................................................... 16 UNS Energy ........................................................................................... 5 Business Risks ............................................................................................ 19 Central Hudson .................................................................................... 6 Accounting Matters .................................................................................. 19 FortisBC Energy .................................................................................... 7 Financial Instruments ................................................................................ 20 FortisAlberta ......................................................................................... 7 Long-Term Debt and Other .................................................................. 20 FortisBC Electric .................................................................................... 8 Derivatives ............................................................................................ 20 Other Electric ........................................................................................ 8 Summary of Quarterly Results ................................................................... 20 Corporate and Other ............................................................................ 9 Related-Party and Inter-Company Transactions ........................................ 21 Non-U.S. GAAP Financial Measures ........................................................... 9 Outlook ..................................................................................................... 21 Regulatory Matters .................................................................................... 10 Forward-Looking Information ................................................................... 22 Financial Position ...................................................................................... 11 Glossary ..................................................................................................... 23 Liquidity and Capital Resources ................................................................ 12 Condensed Consolidated Interim Financial Statements (Unaudited) ....... F-1 Cash Flow Requirements ...................................................................... 12 Dated November 3, 2025 This Interim MD&A has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations . It should be read in conjunction with the Interim Financial Statements, the 2024 Annual Financial Statements and the 2024 Annual MD&A and is subject to the cautionary statement and disclaimer provided under "Forward-Looking Information" on page 22. Further information about Fortis, including its Annual Information Form can be accessed at www.fortisinc.com, www.sedarplus.ca, or www.sec.gov. Financial information herein has been prepared in accordance with U.S. GAAP (except for indicated Non-U.S. GAAP Financial Measures) and, unless otherwise specified, is presented in Canadian dollars based, as applicable, on the following U.S. dollar-to-Canadian dollar exchange rates: (i) average of 1.38 and 1.36 for the quarters ended September 30, 2025 and 2024, respectively; (ii) average of 1.40 and 1.36 year-to-date September 30, 2025 and 2024, respectively; (iii) 1.39 and 1.35 as at September 30, 2025 and 2024, respectively; (iv) 1.44 as at December 31, 2024; (v) 1.38 for the 2025 annual forecast; and (vi) 1.35 for all other forecast periods. Certain terms used in this Interim MD&A are defined in the "Glossary" on page 23. ABOUT FORTIS Fortis (TSX/NYSE: FTS) is a diversified leader in the North American regulated electric and gas utility industry, with 2024 revenue of $12 billion and total assets of $75 billion as at September 30, 2025. The Corporation's 9,600 employees serve 3.5 million utility customers in five Canadian provinces, ten U.S. states and the Caribbean. For additional information on the Corporation's operations, reportable segments and strategy, refer to the "About Fortis" section of the 2024 Annual MD&A and Note 1 to the Interim Financial Statements. Interim Management Discussion and Analysis 1 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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PERFORMANCE AT A GLANCE Key Financial Metrics Periods ended September 30 Quarter Year-to-Date ($ millions, except as indicated) 2025 2024 Variance 2025 2024 Variance Revenue 2,938 2,771 167 9,091 8,559 532 Common Equity Earnings Actual 409 420 (11) 1,292 1,210 82 Adjusted (1) 441 420 21 1,324 1,210 114 Basic EPS ($) Actual 0.81 0.85 (0.04) 2.57 2.45 0.12 Adjusted (1) 0.87 0.85 0.02 2.63 2.45 0.18 Dividends paid per common share ($) 0.615 0.590 0.025 1.845 1.770 0.075 Weighted average number of common shares outstanding (# millions) 504.5 496.2 8.3 502.5 493.9 8.6 Operating Cash Flow 1,027 1,338 (311) 3,044 2,920 124 Capital Expenditures (1) 1,316 1,300 16 4,171 3,554 617 (1) See "Non-U.S. GAAP Financial Measures" on page 9 Revenue The increase in revenue for the quarter was due to: (i) Rate Base growth; (ii) higher flow-through costs in customer rates; (iii) higher customer delivery rates, as approved by the PSC effective July 1, 2025 in relation to Central Hudson's 2025 general rate application; and (iv) the higher U.S. dollar-to-Canadian dollar exchange rate. The increase in revenue year to date was due to: (i) Rate Base growth; (ii) higher flow-through costs in customer rates; (iii) higher customer delivery rates effective July 1, 2024 and 2025 as approved by the PSC; and (iv) the higher U.S. dollar-to-Canadian dollar exchange rate. The increase was partially offset by lower wholesale sales revenue at UNS Energy, reflecting a reduction in short-term wholesale electricity sales as well as lower pricing due to market conditions. Earnings and EPS Common Equity Earnings decreased by $11 million compared to the third quarter of 2024. The decrease was due to income taxes and closing costs totalling $32 million associated with the disposition of FortisTCI in September 2025. Excluding the above-noted item, Common Equity Earnings increased by $21 million compared to the third quarter of 2024. The increase was primarily due to Rate Base growth across the utilities , including AFUDC associated with Major Capital Projects. The higher U.S. dollar-to-Canadian dollar exchange rate also contributed to the increase in earnings. The increase was partially offset by higher costs associated with Rate Base growth not yet reflected in customer rates at UNS Energy, the expiration of a regulatory incentive and a lower allowed ROE at FortisAlberta, and higher holding company finance costs. On a year-to-date basis, and excluding the impact of the disposition of FortisTCI as discussed above, Common Equity Earnings increased by $114 million compared to the prior year. The increase was due to the factors discussed for the quarter, and also reflected growth at Central Hudson due to the rebasing of costs and a higher allowed ROE effective July 1, 2024 and the timing of operating costs in 2025. The increase was partially offset by lower margin on wholesale sales at UNS Energy and the timing of operating costs at FortisAlberta. In addition to the above-noted items impacting earnings, the change in basic EPS for the quarter and year-to-date periods reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP. For the quarter and year-to-date periods: (i) Adjusted Common Equity Earnings increased by $21 million and $114 million, respectively, as discussed above; and (ii) Adjusted Basic EPS increased by $0.02 and $0.18, respectively. Refer to "Non-U.S. GAAP Financial Measures" on page 9 for a reconciliation of these measures. The changes in Adjusted Basic EPS for the quarter and year-to-date periods are illustrated in the following charts. Interim Management Discussion and Analysis 2 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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THIRD QUARTER CHANGE IN ADJUSTED BASIC EPS $0.85 $0.03 $0.02 $0.01 $0.01 $(0.03) $(0.02) $0.87 Q3 2024 Actual and Adjusted Basic EPS U.S. Electric and Gas (1) ITC Transmission (2) Western Canadian Electric and Gas (3) Foreign Exchange (4) Corporate and Other (5) Weighted Average Shares (6) Q3 2025 Adjusted Basic EPS (1) Includes UNS Energy and Central Hudson. Reflects higher earnings at Central Hudson due to Rate Base growth and a change in a regulatory deferral for uncollectible accounts as approved in the order on the 2025 general rate application, partially offset by higher costs associated with a contribution to a customer benefit fund. Also reflects higher earnings at UNS Energy due to an increase in transmission revenue and higher AFUDC associated with ongoing Major Capital Projects, partially offset by higher costs associated with Rate Base growth not yet reflected in customer rates (2) Reflects Rate Base growth, partially offset by an increase in non-recoverable stock-based compensation costs and higher holding company finance costs (3) Includes FortisBC Energy, FortisAlberta and FortisBC Electric. Reflects Rate Base growth, including earnings associated with FortisBC Energy's investment in the Eagle Mountain Pipeline project, partially offset by the expiration of the PBR efficiency carry over mechanism at the end of 2024, and a lower allowed ROE effective January 1, 2025 at FortisAlberta (4) Reflects the change in the average U.S. dollar-to-Canadian dollar exchange rate (5) Reflects higher holding company costs, unrealized losses on foreign exchange contracts, and lower unrealized gains on total return swaps (6) Weighted average shares of 504.5 million in 2025 compared to 496.2 million in 2024 YEAR-TO-DATE CHANGE IN ADJUSTED BASIC EPS $2.45 $0.09 $0.05 $0.03 $0.03 $0.06 $(0.04) $(0.04) $2.63 YTD 2024 Actual and Adjusted Basic EPS U.S. Electric and Gas (1) Western Canadian Electric and Gas (2) ITC Transmission (3) Other Electric (4) Foreign Exchange (5) Corporate and Other (6) Weighted Average Shares (7) YTD 2025 Adjusted Basic EPS (1) Includes UNS Energy and Central Hudson. Reflects higher earnings at Central Hudson due to Rate Base growth, the rebasing of costs and a higher allowed ROE effective July 1, 2024, the timing of operating costs, and a change in a regulatory deferral for uncollectible accounts as approved in the order on the 2025 general rate application. Also reflects lower earnings at UNS Energy due to lower margin on wholesale sales and higher costs associated with Rate Base growth not yet reflected in customer rates, partially offset by higher transmission revenue and AFUDC (2) Includes FortisBC Energy, FortisAlberta and FortisBC Electric. Reflects higher earnings at FortisBC due to Rate Base growth, including earnings associated with FortisBC Energy's investment in the Eagle Mountain Pipeline project. Also reflects lower earnings at FortisAlberta primarily due to the timing of operating costs, the expiration of the PBR efficiency carry-over mechanism at the end of 2024, and a lower allowed ROE effective January 1, 2025 (3) Reflects Rate Base growth, partially offset by an increase in non-recoverable stock-based compensation costs and higher holding company finance costs (4) Primarily reflects higher electricity sales, Rate Base growth, as well as the timing of earnings at Newfoundland Power, partially offset by the September 2025 disposition of FortisTCI (5) Reflects the change in the average U.S. dollar-to-Canadian dollar exchange rate and the revaluation of U.S. dollar denominated liabilities (6) Reflects higher holding company finance costs, the timing of income tax recoveries and higher stock-based compensation costs, partially offset by unrealized gains on foreign exchange contracts and total return swaps (7) Weighted average shares of 502.5 million in 2025 compared to 493.9 million in 2024 Interim Management Discussion and Analysis 3 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Dividends and TSR Fortis paid a dividend of $0.615 per common share in the third quarter of 2025, up from $0.590 paid in the third quarter of 2024. On November 3, 2025, Fortis declared a fourth quarter common share dividend of $0.64, up 4.1% from its third quarter 2025 common share dividend. Fortis has increased its common share dividends for 52 consecutive years and is targeting annual dividend growth of approximately 4-6% through 2030. See "Outlook" on page 21. Growth in dividends and the market price of the Corporation's common shares have yielded the following TSRs. TSR (1) (%) 1-Year 5-Year 10-Year 20-Year Fortis 19.3 9.5 10.5 9.5 (1) Annualized TSR per Bloomberg as at September 30, 2025 Operating Cash Flow The $311 million decrease in Operating Cash Flow for the quarter was due to amounts collected at FortisBC Energy in the third quarter of 2024 associated with: (i) deposits, net of construction costs incurred, related to the Eagle Mountain Pipeline project; and (ii) an income tax refund. In addition, the timing of payments at FortisBC Energy and transmission charges at FortisAlberta, and higher interest payments, also contributed to the decrease. The decrease was partially offset by higher cash earnings, reflecting Rate Base growth and the implementation of customer rate changes at Central Hudson in July 2024 and 2025. The $124 million increase in Operating Cash Flow for the year-to-date period was due to: (i) higher cash earnings, as discussed above; (ii) the timing of flow-through costs at FortisBC Energy, largely reflecting changes in commodity and midstream costs; (iii) higher deposits received, net of construction costs incurred, for the Eagle Mountain Pipeline project; and (iv) the higher U.S. dollar-to-Canadian dollar exchange rate. The increase was partially offset by the timing of flow-through costs at UNS Energy largely associated with higher PPFAC collections in 2024, the receipt of a tax refund at FortisBC Energy in 2024, as well as higher interest payments. Capital Expenditures Capital Expenditures for 2025 are expected to be $5.6 billion, up from $5.2 billion disclosed in the 2024 Annual MD&A. The increase is largely due to the acceleration of investments at ITC related to tranche 1 LRTP projects and the Big Cedar Load Expansion project, as well as a higher forecast U.S. dollar-to-Canadian dollar exchange rate. The Corporation is now using an assumed foreign exchange rate of 1.38 for 2025, as compared to 1.30 assumed previously. Year-to-date Capital Expenditures of $4.2 billion represent 75% of the annual forecast, and are $0.6 billion higher than the same period in 2024, largely related to energy storage and transmission investments at UNS Energy, as well as transmission projects at ITC. Capital Expenditures is a Non-U.S. GAAP Financial Measure. Refer to "Non-U.S. GAAP Financia l Measures " on page 9 and in the "Glossary" on page 23. New Five-Year Capital Plan The Corporation's new 2026-2030 Capital Plan totals $28.8 billion, $2.8 billion higher than the previous five-year plan. The increase is primarily driven by higher FERC regulated transmission investments associated with new interconnections, the MISO LRTP and baseline reliability projects at ITC. It also includes incremental capital at UNS Energy, reflecting an increase in transmission and distribution investments to serve load growth, increase reliability, and provide a path for connecting future generation resources. Planned generation investments in Arizona have also been updated to reflect the recently announced Springerville Natural Gas Conversion project. Customer growth and reliability investments across our utilities, as well as a higher assumed U.S. dollar-to-Canadian dollar exchange rate also contributed to the increase in the five-year plan. See "Capital Plan" on page 16 for additional information. Subsequent Event On October 31, 2025, Fortis sold its 100% ownership in Fortis Belize and its 33% ownership in Belize Electricity to the Government of Belize. A loss on sale of approximately $60 million is expected to be recorded in the fourth quarter of 2025, approximately half of which reflects income taxes. Proceeds from the sale will be used to further strengthen the balance sheet and provide funding flexibility in support of our regulated utility growth strategy. Interim Management Discussion and Analysis 4 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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BUSINESS UNIT PERFORMANCE Common Equity Earnings Quarter Year-to-Date Periods ended September 30 Variance Variance ($ millions) 2025 2024 FX (1) Other 2025 2024 FX (1) Other Regulated Utilities ITC 149 138 2 9 442 415 12 15 UNS Energy 209 204 2 3 394 396 8 (10) Central Hudson 31 20 1 10 121 62 3 56 FortisBC Energy — (4) — 4 202 173 — 29 FortisAlberta 54 54 — — 132 139 — (7) FortisBC Electric 15 14 — 1 57 54 — 3 Other Electric (2) 41 39 — 2 129 111 1 17 499 465 5 29 1,477 1,350 24 103 Non-Regulated Corporate and Other (3) (90) (45) — (45) (185) (140) 4 (49) Common Equity Earnings 409 420 5 (16) 1,292 1,210 28 54 (1) The reporting currency for each of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and Fortis Belize is the U.S. dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the U.S. dollar at BZ$2.00=US$1.00. Certain corporate and non-regulated holding company transactions, included in the Corporate and Other segment, are denominated in U.S. dollars (2) Consists of the utility operations in eastern Canada and the Caribbean: Newfoundland Power; Maritime Electric; FortisOntario; Wataynikaneyap Power; Caribbean Utilities; and Belize Electricity (see "Subsequent Event" on page 4). Also includes FortisTCI up to the September 2, 2025 date of disposition (3) Consists of non-regulated holding company expenses, as well as long-term contracted generation assets in Belize (see "Subsequent Event" on page 4) ITC Quarter Year-to-Date Periods ended September 30 Variance Variance ($ millions) 2025 2024 FX Other 2025 2024 FX Other Revenue (1) 625 556 5 64 1,870 1,662 46 162 Earnings (1) 149 138 2 9 442 415 12 15 (1) Revenue represents 100% of ITC. Earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflect consolidated purchase price accounting adjustments Revenue The increase in revenue, net of foreign exchange, for the quarter and year-to-date periods was due primarily to Rate Base growth and higher flow- through costs in customer rates. Earnings The increase in earnings, net of foreign exchange, for the quarter and year-to-date periods was due to Rate Base growth, partially offset by an increase in non-recoverable stock-based compensation costs and higher holding company finance costs. UNS Energy Quarter Year-to-Date Periods ended September 30 Variance Variance ($ millions, except as indicated) 2025 2024 FX Other 2025 2024 FX Other Retail electricity sales (GWh) 3,654 3,631 — 23 8,456 8,522 — (66) Wholesale electricity sales (GWh) (1) 1,328 1,325 — 3 3,513 4,515 — (1,002) Gas sales (PJ) 2 2 — — 12 12 — — Revenue 893 883 8 2 2,267 2,348 61 (142) Earnings 209 204 2 3 394 396 8 (10) (1) Primarily short-term wholesale sales Interim Management Discussion and Analysis 5 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Sales The increase in retail electricity sales for the quarter was due primarily to higher average use by industrial customers. The decrease in retail electricity sales year to date was due primarily to lower average use associated with milder temperatures in comparison to the prior year. Wholesale electricity sales for the quarter were relatively consistent with the same period in 2024. The decrease in wholesale electricity sales year to date was driven by lower short-term wholesale sales reflecting unfavourable market conditions as well as outages at certain of the company's generation facilities, resulting in lower generation levels. Revenue from short-term wholesale sales, which relate to contracts that are less than one-year in duration, is primarily credited to customers through the PPFAC mechanism and, therefore, does not materially impact earnings. Gas sales for the quarter and year-to-date periods were consistent with the same periods in 2024. Revenue Revenue for the quarter, excluding foreign exchange, was comparable with the third quarter of 2024. An increase in retail revenue, largely reflecting higher transmission revenue and retail electricity sales, was largely offset by the recovery of overall lower fuel and non-fuel costs through the normal operation of regulatory mechanisms. The decrease in revenue, net of foreign exchange, year to date was due primarily to: (i) the recovery of overall lower fuel and non-fuel costs through the normal operation of regulatory mechanisms; (ii) lower wholesale electricity sales, discussed above; and (iii) lower pricing on wholesale sales in the first quarter of 2025. The decrease was partially offset by higher transmission revenue. Earnings The increase in earnings, net of foreign exchange, for the quarter was primarily due to: (i) an increase in retail margin, including the impact of higher transmission revenue and retail electricity sales; and (ii) an increase in AFUDC associated with ongoing Major Capital Projects, partially offset by higher costs associated with Rate Base growth not yet reflected in customer rates. The decrease in earnings, net of foreign exchange, year to date was primarily due to lower margin on wholesale sales, reflecting less favourable market conditions, and higher costs associated with Rate Base growth not yet reflected in customer rates. The decrease was partially offset by higher transmission revenue and AFUDC. Central Hudson Quarter Year-to-Date Periods ended September 30 Variance Variance ($ millions, except as indicated) 2025 2024 FX Other 2025 2024 FX Other Electricity sales (GWh) 1,356 1,402 — (46) 3,874 3,873 — 1 Gas sales (PJ) 8 6 — 2 21 19 — 2 Revenue 388 338 4 46 1,208 1,016 32 160 Earnings 31 20 1 10 121 62 3 56 Sales The decrease in electricity sales for the quarter was due to lower average consumption by residential, industrial and commercial customers. Electricity sales for the year-to-date period were consistent with the same period in 2024. The increase in gas sales for the quarter and year-to-date periods was due to higher average consumption by industrial customers. Changes in electricity and gas sales at Central Hudson are subject to regulatory revenue decoupling mechanisms and, therefore, do not materially impact earnings. Revenue The increase in revenue, net of foreign exchange, for the quarter was due primarily to: (i) the flow-through of higher energy supply costs driven by commodity prices; (ii) Rate Base growth; and (iii) higher customer delivery rates, as approved by the PSC effective July 1, 2025 in relation to Central Hudson's 2025 general rate application. The increase in revenue, net of foreign exchange, year to date was due to the flow-through of higher energy supply costs, Rate Base growth, and higher customer delivery rates effective July 1, 2024 and 2025 as approved by the PSC. Interim Management Discussion and Analysis 6 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Earnings The increase in earnings, net of foreign exchange, for the quarter was due primarily to: (i) a change in the timing of recognition of a regulatory deferral for uncollectible accounts, as approved in the order on the 2025 general rate application; and (ii) Rate Base growth, partially offset by a contribution to a customer benefit fund, which was accepted by the PSC in August 2025 in connection with a joint settlement agreement (see "Regulatory Matters" on page 10). The increase in earnings, net of foreign exchange, year to date was due primarily to: (i) Rate Base growth; (ii) the rebasing of customer rates effective July 1, 2024, which reflected a higher allowed ROE and improved recovery of costs; (iii) the timing of operating costs; and (iv) a change in a regulatory deferral for uncollectible accounts, as discussed above. This increase was partially offset by the net impact of contributions made to a customer benefit fund in both 2024 and 2025. FortisBC Energy Periods ended September 30 Quarter Year-to-Date ($ millions, except as indicated) 2025 2024 Variance 2025 2024 Variance Gas sales (PJ) 29 32 (3) 152 153 (1) Revenue 281 246 35 1,298 1,143 155 Earnings — (4) 4 202 173 29 Sales The decrease in gas sales for the quarter and year-to-date periods was due to lower average consumption by transportation and residential customers, partially offset by higher average consumption by industrial customers. Lower average consumption by residential customers was primarily due to milder weather in the third quarter of 2025. Revenue The increase in revenue for the quarter and year-to-date periods was due primarily to: (i) the normal operation of regulatory mechanisms; (ii) Rate Base growth; and (iii) a higher cost of natural gas recovered from customers. Earnings The increase in earnings for the quarter and year-to-date periods was due primarily to Rate Base growth, including higher AFUDC associated with the timing of FortisBC Energy's investment in the Eagle Mountain Pipeline project. FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for delivery. Due to regulatory deferral mechanisms, changes in consumption levels and commodity costs do not materially impact earnings. FortisAlberta Periods ended September 30 Quarter Year-to-Date ($ millions, except as indicated) 2025 2024 Variance 2025 2024 Variance Electricity deliveries (GWh) 4,257 4,388 (131) 13,054 12,896 158 Revenue 213 209 4 621 610 11 Earnings 54 54 — 132 139 (7) Deliveries The decrease in electricity deliveries for the quarter was due primarily to lower average consumption by commercial and industrial customers. This decrease was partially offset by higher sales to residential customers due to customer additions. On a year-to-date basis, the increase in electricity deliveries was primarily due to higher average consumption by industrial customers, largely reflecting higher activity in the energy sector. Customer additions, as well as higher average consumption by residential customers due to warmer weather in the second quarter of 2025, also contributed to the increase. As approximately 85% of FortisAlberta's revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries. Significant variations in weather conditions, however, can impact revenue and earnings. Interim Management Discussion and Analysis 7 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Revenue The increase in revenue for the quarter and year-to-date periods was due to Rate Base growth and customer additions, partially offset by: (i) the expiration of the PBR efficiency carry-over mechanism, as this regulatory incentive was only available through 2024; (ii) favourable non-recurring true-ups recorded in 2024 associated with the finalization of prior period Rate Base balances; and (iii) a reduction in the allowed ROE from 9.28% to 8.97% effective January 1, 2025 due to the automatic adjustment mechanism. Earnings Earnings for the quarter were consistent with the same period in 2024. An increase in earnings associated with Rate Base growth and customer additions was offset by the expiration of the PBR efficiency carry-over mechanism, the non-recurring true-ups recorded in 2024 and the lower allowed ROE, as discussed above. The decrease in earnings year to date was due to the items discussed above for the quarter, as well as the timing of operating costs. FortisBC Electric Periods ended September 30 Quarter Year-to-Date ($ millions, except as indicated) 2025 2024 Variance 2025 2024 Variance Electricity sales (GWh) 887 864 23 2,705 2,597 108 Revenue 133 130 3 412 396 16 Earnings 15 14 1 57 54 3 Sales The increase in electricity sales for the quarter and year-to-date periods was due primarily to higher average consumption by industrial and commercial customers. The increase was partially offset by lower average consumption by residential customers in the third quarter of 2025 due to milder weather. Revenue The increase in revenue for the quarter was due primarily to the normal operation of regulatory mechanisms, higher electricity sales and Rate Base growth. The increase in revenue year to date was due primarily to higher energy supply costs recovered from customers, higher electricity sales and Rate Base growth. The increase was partially offset by the normal operation of regulatory mechanisms. Earnings The increase in earnings for the quarter and year-to-date periods was due primarily to Rate Base growth. Due to regulatory deferral mechanisms, changes in consumption levels do not materially impact earnings. Other Electric Quarter Year-to-Date Periods ended September 30 Variance Variance ($ millions, except as indicated) 2025 2024 FX Other 2025 2024 FX Other Electricity sales (GWh) 1,899 1,924 — (25) 7,403 7,346 — 57 Revenue 393 399 1 (7) 1,386 1,359 10 17 Earnings 41 39 — 2 129 111 1 17 Sales The decrease in electricity sales for the quarter was primarily due to the September 2, 2025 disposition of FortisTCI. The increase in electricity sales year to date was due to higher average consumption by residential and commercial customers, as well as customer additions. Higher average consumption for residential customers was largely due to the conversion of home heating systems from oil to electric in Eastern Canada. The increase was partially offset by the disposition of FortisTCI. Interim Management Discussion and Analysis 8 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Revenue The decrease in revenue, net of foreign exchange, for the quarter was due primarily to the flow-through of lower energy supply costs recovered from customers and the disposition of FortisTCI. The decrease was partially offset by the July 1, 2025 electricity rate increase at Newfoundland Power, as well as Rate Base growth. The increase in revenue, net of foreign exchange, year to date was due primarily to higher electricity sales and Rate Base growth. The July 1, 2025 electricity rate increase and the operation of regulatory deferral mechanisms at Newfoundland Power also contributed to the increase in revenue. The increase was partially offset by the flow-through of lower energy supply costs recovered from customers and the disposition of FortisTCI. Earnings The increase in earnings for the quarter was primarily due to Rate Base growth, partially offset by the disposition of FortisTCI. The increase in earnings, net of foreign exchange, year to date was due to higher electricity sales and Rate Base growth, as well as the timing of earnings at Newfoundland Power, reflecting the timing of approval of regulatory applications and the related cost recovery mechanisms. The increase was partially offset by the disposition of FortisTCI. Corporate and Other Quarter Year-to-Date Periods ended September 30 Variance Variance ($ millions, except as indicated) 2025 2024 FX Other 2025 2024 FX Other Electricity sales (GWh) 67 59 — 8 154 135 — 19 Revenue 12 10 — 2 29 25 1 3 Net loss (90) (45) — (45) (185) (140) 4 (49) Sales and Revenue The increase in electricity sales and revenue for the quarter and year-to-date periods reflected higher hydroelectric production in Belize associated with rainfall levels. Net Loss The increase in net loss for the quarter was due primarily to income taxes and closing costs totalling $32 million associated with the disposition of FortisTCI in September 2025. Higher holding company finance costs, unrealized losses on foreign exchange contracts, and lower unrealized gains on total return swaps also contributed to the increase in net loss. The increase in net loss, excluding foreign exchange, year to date was primarily due to the disposition of FortisTCI, as discussed above. Higher holding company finance costs, the timing of income tax recoveries and an increase in stock-based compensation costs also contributed to the increase in net loss, partially offset by unrealized gains on foreign exchange contracts and total return swaps. The favourable foreign exchange impact for the year-to-date period was due to the change in the U.S. dollar-to-Canadian dollar exchange rate since December 31, 2024, and the related revaluation of U.S. dollar denominated liabilities, partially offset by the increase in the average exchange rate in 2025. NON-U.S. GAAP FINANCIAL MEASURES Adjusted Common Equity Earnings, Adjusted Basic EPS and Capital Expenditures are Non-U.S. GAAP Financial Measures and may not be comparable to similar measures used by other entities. They are presented because management and external stakeholders use them in evaluating the Corporation's financial performance. Net earnings attributable to common equity shareholders (i.e. Common Equity Earnings) and basic EPS are the most directly comparable U.S. GAAP measures to Adjusted Common Equity Earnings and Adjusted Basic EPS, respectively. These adjusted measures reflect the removal of items that management excludes in its key decision-making processes and evaluation of operating results. Capital Expenditures include additions to property, plant and equipment and additions to intangible assets, as shown on the condensed consolidated interim statements of cash flows, less CIACs received by FortisBC Energy associated with the Eagle Mountain Pipeline project. The CIACs received for this Major Capital Project are significant and presentation of Capital Expenditures net of CIACs better aligns with the Rate Base growth associated with this project. Capital Expenditures for 2024 also included Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power project, consistent with Fortis' evaluation of operating results and its role as project manager during the construction of the project. Interim Management Discussion and Analysis 9 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Non-U.S. GAAP Reconciliation Periods ended September 30 Quarter Year-to-Date ($ millions, except as indicated) 2025 2024 Variance 2025 2024 Variance Adjusted Common Equity Earnings and Adjusted Basic EPS Common Equity Earnings 409 420 (11) 1,292 1,210 82 Adjusting item: Disposition of FortisTCI (1) 32 — 32 32 — 32 Adjusted Common Equity Earnings 441 420 21 1,324 1,210 114 Adjusted Basic EPS ($) 0.87 0.85 0.02 2.63 2.45 0.18 Capital Expenditures Additions to property, plant and equipment 1,362 1,248 114 4,324 3,383 941 Additions to intangible assets 91 52 39 216 142 74 Adjusting items: Eagle Mountain Pipeline Project (2) (137) — (137) (369) — (369) Wataynikaneyap Transmission Power Project (3) — — — — 29 (29) Capital Expenditures 1,316 1,300 16 4,171 3,554 617 (1) Reflects income taxes and closing costs associated with the disposition of FortisTCI, included in the Corporate and Other segment (2) Represents CIACs received for the Eagle Mountain Pipeline project, included in the FortisBC Energy segment (3) Represents Fortis' 39% share of capital spending during the construction of the Wataynikaneyap Transmission Power project, included in the Other Electric segment. Construction was completed in the second quarter of 2024 REGULATORY MATTERS ITC MISO Base ROE: In October 2024, FERC issued an order that revised the base ROE for transmission owners operating in the MISO region, including ITC, from 10.02% to 9.98%, with a maximum ROE inclusive of incentives not to exceed 12.58%. The order also directed the payment of certain refunds, with interest, by December 2025, for the 15-month period from November 2013 through February 2015, and prospectively from September 2016. Certain MISO transmission owners, including ITC, filed a request for rehearing with FERC in November 2024, and filed an appeal of the order with the D.C. Circuit Court in January 2025, with particular focus on the refund period and related interest. In March 2025, FERC issued an order addressing the request for rehearing but made no changes to the October 2024 order. The MISO transmission o wners continue to pursue an appeal at the D.C. Circuit Court in relation to FERC's October 2024 and March 2025 orders. The timing and outcome of this appeal are unknown. In addition, MISO and the MISO transmission owners are awaiting a response from FERC with respect to a request filed in September 2025 to extend the period to pay refunds from December 2025 to June 30, 2026. Transmission Incentives: In 2021, FERC issued a supplemental NOPR on transmission incentives modifying the proposal in the initial NOPR released by FERC in 2020. The supplemental NOPR proposes to eliminate the 50-basis point RTO ROE incentive adder for RTO members that have been members for longer than three years. Although the timing and outcome of this proceeding are unknown, every 10-basis point change in ROE at ITC impacts Fortis' annual EPS by approximately $0.01. UNS Energy TEP General Rate Application: In June 2025, TEP filed a general rate application with the ACC requesting new rates effective September 1, 2026 using a December 31, 2024 test year, with post-test year adjustments through June 30, 2025 . The application includes a proposal to phase-out or eliminate certain adjustor mechanisms, and requests an annual formulaic rate adjustment mechanism consistent with the ACC's approval of a formula rate policy statement in 2024. UNS Gas General Rate Application: In November 2024, UNS Gas filed a general rate application with the ACC requesting an increase in gas delivery rates effective February 1, 2026. In January 2025, UNS Gas filed supplemental material proposing an annual formulaic rate adjustment mechanism. The outcome of this proceeding is unknown. Central Hudson 2025 General Rate Application: In August 2025, the PSC approved a three-year rate plan for Central Hudson with retroactive application to July 1 2025, including the continuation of a 9.5% allowed ROE and a 48% common equity component of capital structure. The three-year rate plan also includes the use of existing regulatory balances and other measures to reduce customer bill impacts, as well as initiatives to support New York States's energy conservation emission reduction goals. Interim Management Discussion and Analysis 10 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Enforcement Proceeding: In August 2025, the PSC issued an order which accepted a joint settlement agreement and concluded the enforcement proceeding in connection with a gas-related explosion that occurred in November 2023. As part of the order, Central Hudson agreed to make a contribution to a customer benefit fund which was recorded in the third quarter of 2025. FortisBC 2025-2027 Rate Framework: In March 2025, the BCUC issued a decision on FortisBC's application with respect to the rate framework for 2025 through 2027. The rate framework builds upon the previous multi-year rate plan and includes, amongst other items, updates to depreciation and capitalized overhead rates, a revised level of operation and maintenance expense per customer indexed for inflation less a fixed productivity adjustment factor, a similar approach to growth capital, a forecast approach to sustaining and other capital, continued collection of an innovation fund recognizing the need to accelerate investment in clean energy innovation, and the continued sharing with customers of variances from the allowed ROE. The rate framework also includes the continuation of deferral mechanisms included in the previous multi-year rate plan. FortisAlberta GCOC Decision: FortisAlberta filed an appeal with respect to the AUC's decision on the 2024 GCOC proceeding based on FortisAlberta's business and regulatory risks associated with REAs located in its service area. In March 2025, the Court of Appeal dismissed the appeal. Third PBR Term Decision: In 2023, the AUC issued a decision establishing the parameters for the third PBR term for the period of 2024 through 2028. FortisAlberta sought permission to appeal the decision to the Court of Appeal on the basis that the AUC erred in its decision to determine capital funding using 2018-2022 historical capital investments without consideration for funding of new capital programs included in the company's 2023 cost of service revenue requirement as approved by the AUC. In March 2025, the Court of Appeal granted FortisAlberta permission to appeal, which is expected to be heard in the first quarter of 2026. FINANCIAL POSITION Cash and cash equivalents (5) 174 Primarily due to the issuance of subordinated notes at the Corporation in September 2025. Fortis plans to utilize the net proceeds from this issuance by the end of the year. Balances on hand have been largely invested in interest-bearing accounts. Accounts receivable and other current assets (37) (227) Primarily due to seasonality of revenues, particularly in Canada and New York. Other assets (42) 183 Reflects an increase in long-term payment arrangements with customers at Central Hudson as a result of collection efforts, as well as an equity contribution to Wataynikaneyap Power. Regulatory assets (current and long-term) (44) 262 Due to changes associated with various regulatory mechanisms, including an increase in deferred income taxes and deferred energy management costs, partially offset by lower unrealized losses on natural gas derivatives at FortisBC Energy. Property, plant and equipment, net (1,066) 2,172 Due to capital expenditures, partially offset by depreciation expense and CIACs, as well as the September 2025 disposition of FortisTCI. Short-term borrowings (3) 199 Reflects the issuance of commercial paper at ITC to finance working capital requirements. Accounts payable and other current liabilities (52) (308) Primarily due to timing of the declaration of common share dividends. Regulatory liabilities (current and long-term) (91) 195 Due to changes associated with various regulatory mechanisms including an increase in future removal costs, deferred income taxes, and rate stabilization accounts. Deferred income taxes (107) 242 Due to higher temporary differences associated with ongoing capital investments. Significant Changes between September 30, 2025 and December 31, 2024 Balance Sheet Account Increase (Decrease) ($ millions) FX Other Explanation Interim Management Discussion and Analysis 11 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Long-term debt (including current portion) (693) 1,255 Reflects debt issuances, partially offset by debt and credit facility repayments, in support of the Corporation's Capital Plan. Shareholders' equity (647) 1,040 Due primarily to: (i) Common Equity Earnings for the nine months ended September 30, 2025, less dividends declared on common shares; and (ii) the issuance of common shares, largely under the DRIP. Significant Changes between September 30, 2025 and December 31, 2024 Balance Sheet Account Increase (Decrease) ($ millions) FX Other Explanation LIQUIDITY AND CAPITAL RESOURCES Cash Flow Requirements At the subsidiary level, it is expected that operating expenses and interest costs will be paid from Operating Cash Flow, with varying levels of residual cash flow available for capital expenditures and/or dividend payments to Fortis. Remaining capital expenditures are expected to be financed primarily from borrowings under credit facilities, long-term debt offerings and equity injections from Fortis. Borrowings under credit facilities may be required periodically to support seasonal working capital requirements. Cash required of Fortis to support subsidiary growth is generally derived from borrowings under the Corporation's credit facilities, the operation of the DRIP, as well as issuances of long-term debt, preference equity, and common shares including any issued through the ATM Program. The subsidiaries pay dividends to Fortis and receive equity injections from Fortis when required. Both Fortis and its subsidiaries initially borrow through their credit facilities and periodically replace these borrowings with long-term financing. Financing needs also arise to refinance maturing debt. Credit facilities are syndicated primarily with large banks in Canada and the U.S., with no one bank holding more than approximately 20% of the Corporation's total revolving credit facilities. Approximately $5.4 billion of the total credit facilities are committed with maturities ranging from 2027 through 2030. Available credit facilities are summarized in the following table. Credit Facilities As at Regulated Utilities Corporate and Other September 30, 2025 December 31, 2024($ millions) Total credit facilities (1) 4,230 1,581 5,811 6,342 Credit facilities utilized: Short-term borrowings (294) — (294) (98) Long-term debt (including current portion) (1,478) — (1,478) (2,216) Letters of credit outstanding (94) (22) (116) (102) Credit facilities unutilized 2,364 1,559 3,923 3,926 (1) See Note 14 in the 2024 Annual Financial Statements for a description of the credit facilities as at December 31, 2024 In April 2025, FortisAlberta increased its operating credit facility from $250 million to $300 million and extended the maturity to April 2030. In May 2025, the Corporation amended its $1.3 billion revolving term committed credit facility to extend the maturity to July 2030. In September 2025, FortisUS Inc., a holding company subsidiary of Fortis, extended the maturity on its unsecured US$150 million revolving term credit facility to October 2027. Also in September 2025, the Corporation fully repaid its unsecured US$250 million non-revolving term credit facility. The Corporation's ability to service debt and pay dividends is dependent on the financial results of, and the related cash payments from, its subsidiaries. Certain regulated subsidiaries are subject to restrictions that limit their ability to distribute cash to Fortis, including restrictions by certain regulators limiting annual dividends and restrictions by certain lenders limiting debt to total capitalization. There are also practical limitations on using the net assets of the regulated subsidiaries to pay dividends, based on management's intent to maintain the subsidiaries' regulator-approved capital structures. Fortis does not expect that maintaining these capital structures will impact its ability to pay dividends in the foreseeable future. As at September 30, 2025 , consolidated fixed-term debt maturities/repayments are expected to average $1.7 billion annually over the next five years, with a maximum of $2.4 billion due in any one year. Approximately 74% of the Corporation's consolidated long-term debt, excluding credit facility borrowings, had maturities beyond five years. Interim Management Discussion and Analysis 12 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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In December 2024, Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts, or debt securities in an aggregate principal amount of up to $2.0 billion. Fortis re-established the ATM Program pursuant to the short-form base shelf prospectus, which allows the Corporation to issue up to $500 million of common shares from treasury to the public from time to time, at the Corporation's discretion, effective until January 10, 2027. As at September 30, 2025, $500 million remained available under the ATM Program and $1.5 billion remained available under the short-form base shelf prospectus. Fortis is well positioned with strong liquidity. The combination of available credit facilities and manageable annual debt maturities/repayments provides flexibility in the timing of access to capital markets. Given current credit ratings and capital structures, the Corporation and its subsidiaries currently expect to continue to have access to long-term capital. Fortis and its subsidiaries were in compliance with debt covenants as at September 30, 2025 and are expected to remain compliant. Cash Flow Summary Summary of Cash Flows Periods ended September 30 Quarter Year-to-Date ($ millions) 2025 2024 Variance 2025 2024 Variance Cash and cash equivalents, beginning of period 221 561 (340) 220 625 (405) Cash from (used in): Operating activities 1,027 1,338 (311) 3,044 2,920 124 Investing activities (1,081) (1,313) 232 (4,016) (3,599) (417) Financing activities 220 316 (96) 1,156 939 217 Effect of exchange rate changes on cash and cash equivalents 2 (6) 8 (15) 11 (26) Cash and cash equivalents, end of period 389 896 (507) 389 896 (507) Operating Activities See "Performance at a Glance - Operating Cash Flow" on page 4. Investing Activities Cash used in investing activities for the third quarter of 2025 was $232 million lower than the same period in 2024 due to proceeds received on the disposition of FortisTCI in September 2025 partially offset by higher demand side expenditures at FortisBC Energy. An increase in Capital Expenditures in the third quarter of 2025 was offset by higher CIACs largely associated with the Eagle Mountain Pipeline project. On a year-to-date basis, cash used in investing activities increased by $417 million as compared to the same period in 2024. The increase was due to: (i) higher Capital Expenditures, net of CIACs, (ii) higher demand side management expenditures at FortisBC Energy; (iii) an equity contribution to Wataynikaneyap Power; and (iv) the higher U.S. dollar-to-Canadian dollar exchange rate. The increase was partially offset by proceeds received on the disposition of FortisTCI. Financing Activities Cash flows related to financing activities will fluctuate largely as a result of changes in the subsidiaries' capital expenditures and the amount of Operating Cash Flow available to fund those capital expenditures, which together impact the amount of funding required from debt and common equity issuances. See "Cash Flow Requirements" on page 12. Cash provided by financing activities for the third quarter of 2025 decreased by $96 million as compared to the third quarter of 2024. The reduction was due to an increase in the net repayment of credit facilities, largely associated with proceeds received on the disposition of FortisTCI. On a year-to-date basis, cash provided by financing activities increased by $217 million as compared to the same period in 2024 due to a net increase in borrowings in support of the Corporation's annual Capital Plan. Interim Management Discussion and Analysis 13 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Debt Financing Significant Long-Term Debt Issuances Year-to-date September 30, 2025 Month Interest Use of Proceeds($ millions, except as noted) Issued Rate (%) Maturity Amount UNS Energy Unsecured senior notes February 5.90 2055 US $300 (1) (2) (3) Central Hudson Senior notes April 5.61 2035 US $20 (1) (3) Senior notes April 5.81 2040 US $30 (1) (3) Senior notes April 6.01 2045 US $20 (1) (3) FortisAlberta Unsecured senior debentures July 4.76 2055 200 (1) (2) (3) Newfoundland Power First mortgage bonds August 4.91 2055 120 (1) (2) (3) Maritime Electric First mortgage bonds July 4.94 2055 120 (1) (2) Fortis Unsecured senior notes March 4.09 2032 600 (1) (3) Subordinated notes (4) September 5.10 2055 750 (1) (3) (1) Repay credit facility borrowings (2) Fund capital expenditures (3) General corporate purposes (4) Issuance reflects fixed-to-fixed rate hybrid subordinated notes. The interest rate will be reset on December 4, 2030, and every 5-years thereafter, equal to the 5-year Government of Canada bond yield plus 2.09% provided that the interest rate reset will not be below the initial interest rate of 5.10%. The subordinated notes receive partial equity treatment from credit rating agencies In October 2025, UNS Energy issued US$50 million of 10-year, 5.38% unsecured senior notes. Proceeds will be used to repay credit facility borrowings and for general corporate purposes. In October 2025, FortisBC Energy issued $200 million of 5-year, 3.38% unsecured debentures. Proceeds will be used to repay credit facility borrowings. In October 2025, Central Hudson priced US$80 million of senior notes with funding expected in November 2025. The related issuances will consist of US$15 million of 10-year, 5.25% notes and US$65 million of 20-year, 5.90% notes. Proceeds are expected to be used for general corporate purposes. Common Equity Financing Common Equity Issuances and Dividends Paid Periods ended September 30 Quarter Year-to-Date ($ millions, except as indicated) 2025 2024 Variance 2025 2024 Variance Common shares issued: Cash (1) 11 13 (2) 45 34 11 Non-cash (2) 112 107 5 346 324 22 Total common shares issued 123 120 3 391 358 33 Number of common shares issued (# millions) 1.8 2.1 (0.3) 6.1 6.7 (0.6) Common share dividends paid: Cash (198) (186) (12) (581) (549) (32) Non-cash (3) (112) (106) (6) (345) (324) (21) Total common share dividends paid (310) (292) (18) (926) (873) (53) Dividends paid per common share ($) 0.615 0.590 0.025 1.845 1.770 0.075 (1) Includes common shares issued under stock option and employee share purchase plans (2) Common shares issued under the DRIP and stock option plan (3) Common share dividends reinvested under the DRIP Interim Management Discussion and Analysis 14 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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On February 13, 2025 and July 31, 2025 Fortis declared a dividend of $0.615 per common share which was paid on June 1, 2025, and September 1, 2025, respectively. On November 3, 2025, Fortis declared a dividend of $0.64 per common share payable on December 1, 2025. The payment of dividends is at the discretion of the Board and depends on the Corporation's financial condition and other factors. On June 1, 2025, the annual fixed dividend per share for the First Preference Shares, Series H reset from $0.4588 to $1.0458 for the five-year period up to but excluding June 1, 2030. Also on June 1, 2025, 11,298 First Preference Shares, Series H were converted on a one-for-one basis into First Preference Shares, Series I and 248,830 First Preference Shares, Series I were converted on a one-for-one basis into First Preference Shares, Series H. Contractual Obligations There were no material changes to the contractual obligations disclosed in the 2024 Annual MD&A, other than issuances of long-term debt and credit facility utilization (see "Cash Flow Summary" on page 13), and new agreements at UNS Electric and TEP as detailed below. UNS Electric entered into a US$233 million Engineering, Procurement, and Construction Agreement for the development of four gas engine turbines at the Black Mountain Generating Station, which are expected to be placed in service in 2028. TEP entered into an energy supply agreement to serve a customer expected to be located in TEP's service territory. The agreement, requiring potential power demand of approximately 300 MW, is subject to approval by the ACC and other contractual contingencies. The initial phase is expected to be operational as early as 2027, with a ramp schedule through 2029. TEP currently expects to serve this customer from its existing and planned capacity, including solar and battery storage projects currently in development. TEP and UNS Electric entered into long-term gas transportation precedent agreements to secure reliable access to natural gas. The agreements support the development of a new pipeline, expected to be in service in 2029, which will be owned and operated by a third-party. The purchase commitments, expected to begin in 2029, are estimated to total US$1.9 billion over the 25-year service period, and are conditional on the construction and commercial operation of the new pipeline. Off-Balance Sheet Arrangements There were no material changes to off-balance sheet arrangements from those disclosed in the 2024 Annual MD&A. Capital Structure and Credit Ratings Fortis requires ongoing access to capital and, therefore, targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. The regulated utilities maintain their own capital structures in line with those reflected in customer rates. Consolidated Capital Structure September 30, 2025 December 31, 2024 As at ($ millions) (%) ($ millions) (%) Debt (1) 34,030 56.4 33,435 56.4 Preference shares 1,623 2.7 1,623 2.7 Common shareholders' equity and non-controlling interests (2) 24,630 40.9 24,230 40.9 60,283 100.0 59,288 100.0 (1) Includes long-term debt and finance leases, including current portion, and short-term borrowings, net of cash (2) Includes shareholders' equity, excluding preference shares, and non-controlling interests. Non-controlling interests represented 3.4% as at September 30, 2025 (December 31, 2024 - 3.4%) Outstanding Share Data As at November 3, 2025, the Corporation had issued and outstanding 505.4 million common shares and the following first preference shares: 5.0 million Series F; 9.2 million Series G; 7.9 million Series H; 2.1 million Series I; 8.0 million Series J; 10.0 million Series K; and 24.0 million Series M. The common shares of the Corporation have voting rights. The Corporation's first preference shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive or declared. If all outstanding stock options were converted as at November 3, 2025, an additional 1.1 million common shares would be issued and outstanding. Interim Management Discussion and Analysis 15 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Credit Ratings The Corporation's credit ratings shown below reflect its low business risk profile, diversity of operations, the stand-alone nature and financial separation of each regulated subsidiary, and the level of holding company debt. As at September 30, 2025 Rating Type Outlook S&P A- Issuer Negative BBB+ Unsecured debt Fitch BBB+ Issuer Stable BBB+ Unsecured debt Morningstar DBRS A (low) Issuer Stable A (low) Unsecured debt Stable Moody's Baa3 Issuer Stable Baa3 Unsecured debt In March 2025, Moody's confirmed the Corporation's Baa3 issuer and senior unsecured debt credit ratings and stable outlook. In May 2025, Fitch assigned first time issuer and senior unsecured debt ratings of BBB+ to the Corporation with a stable outlook. In May 2025, Morningstar DBRS confirmed the Corporation's A (low) issuer and senior unsecured debt credit ratings and stable outlook. Capital Plan Capital Expenditures for 2025 are expected to be $5.6 billion, up from $5.2 billion disclosed in the 2024 Annual MD&A. The increase is largely due to the acceleration of investments at ITC related to tranche 1 LRTP projects and the Big Cedar Load Expansion project, as well as a higher forecast U.S. dollar-to-Canadian dollar exchange rate. The Corporation is now assuming a forecast foreign exchange rate of 1.38 for 2025, as compared to 1.30 assumed previously. Year-to-date Capital Expenditures of $4.2 billion are consistent with expectations and represent 75% of the annual forecast. Capital Expenditures (1) Year-to-date September 30, 2025 Regulated Utilities UNS Energy Central Hudson FortisBC Energy Fortis Alberta FortisBC Electric Other Electric Total Regulated Utilities Non-Regulated Corporate and Other($ millions, except as indicated) ITC Total (1) Total 1,363 1,128 330 423 424 127 373 4,168 3 4,171 (1) See "Non-U.S. GAAP Financial Measures" on page 9 New Five-Year Capital Plan The Corporation's five-year 2026-2030 Capital Plan is targeted at $28.8 billion. ($ billions) 2026 2027 2028 2029 2030 Total (1) Five-Year Capital Plan 5.6 5.9 5.6 6.2 5.5 28.8 (1) Reflects an assumed U.S. dollar-to-Canadian dollar exchange rate of 1.35. On average, a five-cent increase or decrease in the U.S. dollar relative to the Canadian dollar would increase or decrease the new Capital Plan by approximately $0.7 billion over the five-year planning period The 2026-2030 Capital Plan is $2.8 billion higher than the previous five-year plan. The increase is primarily driven by higher FERC regulated transmission investments associated with new interconnections, the MISO LRTP and baseline reliability projects at ITC. It also includes incremental capital at UNS Energy, reflecting an increase in transmission and distribution investments to serve load growth, increase reliability, and provide a path for connecting future generation resources. Planned generation investments in Arizona have also been updated to reflect the recently announced Springerville Natural Gas Conversion project. Customer growth and reliability investments across our utilities also contributed to the increase, and the higher assumed U.S. dollar-to-Canadian dollar exchange rate of 1.35 resulted in approximately $0.6 billion of additional capital as compared to the previous plan. Investments in the 2026-2030 Capital Plan are categorized as: (i) 46% transmission; (ii) 31% distribution; (iii) 7% generation; (iv) 5% renewable gas and LNG; and (v) 11% other, largely related to information technology and facility investments. The five-year Capital Plan is low risk and highly executable, with only 21% relating to Major Capital Projects. Geographically, 63% of planned expenditures are expected in the U.S., including 34% at ITC, with 35% in Canada and the remaining 2% in the Caribbean. Interim Management Discussion and Analysis 16 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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The Capital Plan is expected to be funded primarily by cash from operations and regulated utility debt. Common equity is expected to be provided by the Corporation's DRIP, assuming current participation levels. The Corporation's $500 million ATM Program has not been utilized to date and remains available for funding flexibility as required. Planned capital expenditures are based on detailed forecasts of energy demand as well as labour and material costs, including inflation, supply chain availability, general economic conditions, foreign exchange rates and other factors. These factors, including new or revised tariffs, could change and cause actual expenditures to differ from forecast. In particular, the Corporation continues to monitor government policy on foreign trade, including the imposition of tariffs and the potential impacts on the supply chain, commodity prices, the cost of energy and general economic conditions. While it is not possible to predict the impact on the supply chain, business operations or the five-year Capital Plan, the Corporation does not currently expect a material financial impact in 2025. Major Capital Projects Forecast Plan Expected ($ millions) 2025 2026-2030 Completion ITC MISO LRTP Tranche 1 208 1,776 2030 MISO LRTP Tranche 2.1 1 536 Post-2030 Big Cedar Load Expansion 90 472 2028 UNS Energy TEP Transmission Project — 608 2029 Springerville Natural Gas Conversion — 238 2030 Black Mountain Gas Generation 30 366 2028 Vail-to-Tortolita Transmission Project 131 158 2027 Roadrunner Reserve Battery Storage Project 319 8 2026 FortisBC Energy Tilbury LNG Storage Expansion 4 628 Post-2030 AMI Project 159 547 2028 Tilbury 1B Project 20 334 2030 Eagle Mountain Pipeline Project (1) 8 280 2027 Total 970 5,951 (1) Net of customer contributions MISO LRTP - Tranches 1 and 2.1 Six projects included in first tranche of the MISO LRTP portfolio run through ITC's MISO operating companies' service territories. ITC estimates a majority of its investment associated with these projects is reflected in the 2026-2030 Capital Plan. ITC has reflected investments of approximately $0.5 billion (US$0.4 billion) in the Corporation's 2026-2030 Capital Plan associated with MISO LRTP tranche 2.1 projects located in Michigan and Minnesota where ROFRs are in effect and for projects requiring system upgrades in Iowa which are not subject to a competitive bidding process. Significant additional investment opportunities remain for tranche 2.1 (see "Additional Investment Opportunities" on page 18). In July 2025, certain state regulatory commissions in the MISO region filed a complaint at FERC challenging the manner in which MISO developed the tranche 2.1 portfolio. The timing and outcome of this filing, and any potential impact on the Capital Plan, are unknown. Big Cedar Load Expansion The project consists of two phases and includes transmission upgrades to serve up to 1,600 MW of new data center load at the Big Cedar Industrial Center. The first phase of the project requires transmission upgrades to support 800 MW of new load with a targeted in-service date of 2027, and phase two requires an additional 800 MW with an expected in-service date of 2028. TEP Transmission Project Reflects a transmission project with expected completion in 2029 to serve load demand growth, increase reliability, and provide a path for connecting future generation investments. Springerville Natural Gas Conversion The project reflects the conversion of 793 MW of coal-fired generation at TEP's existing Springerville Generating Station to natural gas-fired generation with similar capacity by 2030. The conversion supports customer affordability, local communities, and reliability, and satisfies the need for replacement capacity included in TEP's 2023 IRP. Interim Management Discussion and Analysis 17 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Black Mountain Gas Generation Reflects the expansion of the existing Black Mountain Generation Station owned and operated by UNS Electric to support rising capacity demands in the service territory. The expansion will include four gas turbines, each with a nominal capacity of 48 MW, a 230 kV substation, and a 230 kV interconnection substation. The project is scheduled for completion in 2028. Vail-to-Tortolita Transmission Project Includes investment in one circuit of a new double circuit 230 kV transmission line to tie infrastructure into the TEP system, improving service and reliability to customers. The project is scheduled for completion in 2027. Roadrunner Reserve Battery Storage Project Reflects the second 200 MW Roadrunner Reserve battery project at TEP, following the completion of the first Roadrunner Reserve project in July 2025. The project consists of a battery energy storage system that will facilitate the integration of renewable energy into the electric grid. The system is capable of storing 800 MW hours of energy, enough to serve approximately 42,000 homes for four hours when deployed at full capacity. TEP will own and operate the system. The project is scheduled for completion in 2026. Tilbury LNG Storage Expansion Project In October 2025, the CPCN application for this project was approved by the BCUC. Consistent with the expansion options outlined in the CPCN, the approval will allow FortisBC Energy to replace the original LNG storage tank at the Tilbury site with a new, expanded LNG storage tank, as well as increased regasification capacity, to ensure FortisBC Energy can continue to provide reliable and resilient energy services. The project remains subject to an environmental assessment process. AMI Project The project includes replacement of residential, commercial and industrial meters with advanced gas meters to support the safety, resiliency, and efficient operation of FortisBC Energy's gas distribution system. The project will enable remote meter reading and remote shutoff of gas. The CPCN application was approved by the BCUC in 2023. The installation of the advanced meters commenced in 2025 and is expected to be substantially complete in 2028. Tilbury 1B Project Construction of additional liquefaction and dispensing, including on-shore piping, in support of marine bunkering and to further optimize the Tilbury Phase 1A Expansion Project. This FortisBC Energy project has received an Order in Council from the Government of British Columbia. An initial project scope has been filed with regulators to support the federal impact assessment and provincial environmental assessment required to further expand the Tilbury site. Eagle Mountain Pipeline Project The project consists of a 50-km pipeline expansion to a small-scale LNG facility owned by Woodfibre LNG near Squamish, British Columbia. FortisBC Energy commenced construction of the project in 2023 which is scheduled for completion in 2027. Additional Investment Opportunities ITC The MISO board has approved tranche 2.1 LRTP projects with estimated transmission costs of approximately US$22 billion. ITC estimates a total range of US$3.7 billion to US$4.2 billion in capital expenditures for the MISO tranche 2.1 projects located in Michigan and Minnesota where ROFRs are in effect and for projects requiring system upgrades in Iowa which are not subject to a competitive bidding process. The majority of the tranche 2.1 investments are expected beyond 2030. Any additional tranche 2.1 projects awarded to ITC as part of a competitive bidding process would be incremental to the estimated range of tranche 2.1 investments discussed above. ITC is evaluating projects within the portfolio and preparing to bid as deemed appropriate. UNS Energy In addition to the energy supply agreement signed in July 2025 (see "Contractual Obligations" on page 15), further negotiations are ongoing with the customer for additional capacity to support a full build at the initial site for a total of 600 MW. The customer has also indicated that additional capacity may be required for 500 MW to 700 MW at a second site. Should discussions progress and an agreement be negotiated, additional generation and transmission investments would be required for these subsequent phases. TEP is experiencing interest from other potential new large retail customers in the manufacturing, data center, and mining sectors with demands that may create new energy needs. TEP continues to work with the potential customers to assess capital requirements and associated timelines. TEP and UNS Electric are expecting to file new IRPs with the ACC in 2026, which will support increasing energy needs while taking into account reliable and affordable energy solutions. Interim Management Discussion and Analysis 18 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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FortisBC Energy As indicated above, the BCUC approved the Tilbury LNG Storage Expansion project in October 2025. Based on the expansion option approved by the BCUC, the project has potential upside of $300 million as the five-year Capital Plan assumed the tank replacement would be a similar size and configuration to the existing tank. The incremental opportunity may extend beyond 2030 depending on the timing of environmental assessment approvals. During 2024, provincial and federal environmental assessment certificates were issued for the Tilbury Marine Jetty project. The construction of the jetty supports further expansion of FortisBC's Tilbury LNG facility, which is uniquely positioned to meet customer demand for LNG. The site is scalable, can accommodate additional storage and liquefaction equipment and is close to international shipping lanes. Other Opportunities Other opportunities include incremental transmission investments across our FERC regulated jurisdictions to support customer connections and grid modernization; further renewable gas and LNG infrastructure opportunities in British Columbia; grid resiliency and climate adaptation investments; and the acceleration of load growth and cleaner energy infrastructure investments across our jurisdictions. GHG Emissions Reduction Targets Fortis is primarily an energy delivery company with 94% of its assets related to transmission and distribution. This limits the impact of the Corporation's utilities on the environment when compared to more generation-intensive businesses. Fortis has a relatively small amount of fossil-fuel generation in its portfolio and plans to transition to cleaner sources of energy for its customers. The Corporation has made consistent progress to decarbonize its energy mix and deliver cleaner energy to customers, achieving a 34% reduction in scope 1 GHG emissions through 2024 compared to 2019 levels. The Corporation's ability to achieve its interim GHG emissions reduction targets of 50% by 2030 and 75% by 2035 is expected to be impacted by factors including significant load growth, customer affordability, the pace of development of clean energy technology as well as federal, state and provincial energy policies. While Fortis remains committed to a coal-free generation mix by 2032 and its 2050 net-zero goal, the Corporation expects it will take longer to achieve the interim GHG reduction targets. As energy resource planning advances across the utilities, Fortis will reassess the interim targets and will share the results once complete. BUSINESS RISKS The Corporation's business risks remain substantially unchanged from those disclosed in its 2024 Annual MD&A. ACCOUNTING MATTERS Accounting Policies The Interim Financial Statements have been prepared following the same accounting policies and methods as those used to prepare the 2024 Annual Financial Statements. A new disclosure standard for 2025 is described below. Income Taxes: The Corporation adopted ASU No. 2023-09, Improvements to Income Tax Disclosures , effective January 1, 2025. The ASU requires additional disclosure of income tax information by jurisdiction to reflect an entity's exposure to potential changes in tax legislation, and associated risks and opportunities. The guidance is to be applied on a prospective basis with retrospective application permitted. The updated disclosure will be reflected in the Corporation's annual consolidated financial statements. Fortis does not expect the ASU to materially impact its disclosures. Future Accounting Pronouncements Expense Disaggregation: ASU No. 2024-03, Disaggregation of Income Statement Expenses , is effective for Fortis on January 1, 2027 for annual periods and on January 1, 2028 for interim periods, on a prospective basis, with retrospective application and early adoption permitted. The ASU requires detailed disclosure of certain expense categories included on the consolidated statements of earnings, including energy supply costs, operating expenses, and depreciation and amortization expense. Fortis is assessing the impact on its disclosures. Credit Losses: ASU No. 2025-05, Measurement of Credit Losses for Accounts Receivable and Contract Assets, is effective for Fortis on January 1, 2026 on a prospective basis with early adoption permitted. The ASU provides entities with an option to use a practical expedient to estimate credit losses which would use existing conditions as of the balance sheet date, rather than forecast conditions for the contractual term of the asset. Fortis is assessing the impact on its consolidated financial statements. Internal-Use Software: ASU No. 2025-06, Targeted Improvements to the Accounting for Internal-Use Software , is effective for Fortis on January 1, 2028. The ASU may be adopted prospectively, retrospectively, or using a modified transition approach, and early adoption permitted. The ASU removes references to development stages and requires capitalization of software costs once funding is authorized and project completion is probable, including assessment of whether significant development uncertainty exists. The guidance also clarifies that all capitalized internal-use software costs must follow the disclosure requirements in Subtopic 360-10, Property, Plant and Equipment . Fortis is assessing the impact on its consolidated financial statements and disclosures. Interim Management Discussion and Analysis 19 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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Critical Accounting Estimates The preparation of the Interim Financial Statements required management to make estimates and judgments, including those related to regulatory decisions, that affect the reported amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. Actual results could differ materially from estimates There were no material changes to the nature of the Corporation's critical accounting estimates or contingencies from those disclosed in the 2024 Annual MD&A. FINANCIAL INSTRUMENTS Long-Term Debt and Other As at September 30, 2025, the carrying value of long-term debt, including the current portion, was $34.0 billion (December 31, 2024 - $33.4 billion) compared to an estimated fair value of $32.3 billion (December 31, 2024 - $31.3 billion). The consolidated carrying value of the remaining financial instruments, other than derivatives, approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature. Derivatives Derivatives are recorded at fair value with certain exceptions, including those derivatives that qualify for the normal purchase and normal sale exception. There were no material changes with respect to the nature and purpose, methodologies for fair value determination, and portfolio of the Corporation's derivatives from those disclosed in the 2024 Annual MD&A. See Note 14 of the Interim Financial Statements for additional information. SUMMARY OF QUARTERLY RESULTS Common Equity Revenue Earnings Basic EPS Diluted EPS Quarter ended ($ millions) ($ millions) ($) ($) September 30, 2025 2,938 409 0.81 0.81 June 30, 2025 2,815 384 0.76 0.76 March 31, 2025 3,338 499 1.00 1.00 December 31, 2024 2,949 396 0.79 0.79 September 30, 2024 2,771 420 0.85 0.85 June 30, 2024 2,670 331 0.67 0.67 March 31, 2024 3,118 459 0.93 0.93 December 31, 2023 2,885 381 0.78 0.78 Generally, within each calendar year, quarterly results fluctuate in accordance with seasonality. Given the diversified nature of the Corporation's subsidiaries, seasonality varies. Earnings for utilities in Canada and New York tend to be highest in the first and fourth quarters due to space- heating requirements. Earnings for UNS Energy tend to be highest in the second and third quarters due to the use of air conditioning and other cooling equipment. Generally, from one calendar year to the next, quarterly results reflect: (i) continued organic growth driven by the Corporation's Capital Plan; (ii) any significant temperature fluctuations from seasonal norms; (iii) the impact of market conditions, particularly with respect to wholesale sales at UNS Energy; (iv) the timing and significance of any regulatory decisions; (v) changes in the U.S. dollar-to-Canadian dollar exchange rate; (vi) for revenue, the flow-through in customer rates of commodity costs; and (vii) for EPS, increases in the weighted average number of common shares outstanding. September 2025/September 2024 See "Performance at a Glance" on page 2. Interim Management Discussion and Analysis 20 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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June 2025/June 2024 Common Equity Earnings increased by $53 million and basic EPS increased by $ 0.09 compared to the second quarter of 2024. The increase was due to Rate Base growth across the utilities, including earnings associated with FortisBC Energy's investment in the Eagle Mountain Pipeline project, as well as higher earnings at Central Hudson due to the rebasing of costs and a higher allowed ROE effective July 1, 2024 and the timing of operating costs in 2025. The higher U.S. dollar-to-Canadian dollar exchange rate also favourably impacted earnings year over year. The increase was partially offset by: (i) the timing of operating costs, the expiration of a regulatory incentive at the end of 2024 and a lower allowed ROE effective January 1, 2025 at FortisAlberta; and (ii) higher holding company finance costs. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP. March 2025/March 2024 Common Equity Earnings increased by $40 million and basic EPS increased by $ 0.07 compared to the first quarter of 2024. The increase was due to Rate Base growth across the utilities, and higher earnings at Central Hudson due to the rebasing of costs and a higher allowed ROE, as well as a shift in quarterly revenue effective July 1, 2024. The higher U.S. dollar-to-Canadian dollar exchange rate also favourably impacted earnings. The increase was partially offset by: (i) lower earnings at UNS Energy due to lower margin on wholesale sales and higher costs associated with Rate Base growth not yet reflected in customer rates; (ii) lower earnings at FortisAlberta due to the timing of operating costs, the expiration of a regulatory incentive at the end of 2024 and a lower allowed ROE effective January 1, 2025; and (iii) higher holding company finance costs. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP. December 2024/December 2023 Common Equity Earnings increased by $15 million and basic EPS increased by $ 0.01 compared to the fourth quarter of 2023. The increase was driven by Rate Base growth as well as higher earnings at Central Hudson due to the rebasing of costs and a higher allowed ROE, as well as a shift in quarterly revenue effective July 1, 2024. The increase was partially offset by: (i) the recognition of a refund liability at ITC in the fourth quarter of 2024, largely reflecting the prior period impact of the reduction in the MISO base ROE approved by FERC; (ii) lower earnings in Arizona, due primarily to higher operating costs; (iii) unrealized losses on derivative contracts; and (iv) the $10 million gain on the disposition of Aitken Creek recognized in the fourth quarter of 2023. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP. RELATED-PARTY AND INTER-COMPANY TRANSACTIONS Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions for the three and nine months ended September 30, 2025 and 2024. Fortis periodically provides short-term financing to subsidiaries to support capital expenditures and seasonal working capital requirements, the impacts of which are eliminated on consolidation. As at September 30, 2025 and December 31, 2024, there were no material inter-segment loans outstanding. Interest charged on inter-segment loans was not material for the three and nine months ended September 30, 2025 and 2024. OUTLOOK Fortis continues to enhance shareholder value through the execution of its Capital Plan, the balance and strength of its diversified portfolio of regulated utility businesses, and growth opportunities within and proximate to its service territories. The Corporation's $28.8 billion five-year Capital Plan is expected to increase midyear Rate Base from $41.9 billion in 2025 to $57.9 billion by 2030, translating into a five-year CAGR of 7.0%. Fortis expects its long-term growth in Rate Base will drive earnings that support dividend growth guidance of 4-6% annually through 2030. Planned capital expenditures are based on forecasted energy demand, labour and material costs, and macro economic factors. The Corporation continues to monitor government policy on foreign trade, including the imposition of tariffs and the potential impacts on the supply chain, commodity prices, the cost of energy and general economic conditions. While it is not possible to predict the impact on the supply chain, business operations or the five-year Capital Plan, the Corporation does not currently expect a material financial impact in 2025. Beyond the five-year Capital Plan, opportunities to expand and extend growth include: further expansion of the electric transmission grid in the U.S. to support load growth and facilitate the interconnection of new energy resources; transmission investments associated with the MISO LRTP as well as regional transmission in New York; grid resiliency and climate adaptation investments; investments in renewable gas and LNG infrastructure in British Columbia; and the acceleration of load growth and cleaner energy infrastructure investments across our jurisdictions. The Corporation's ability to achieve its interim GHG emissions reduction targets of 50% by 2030 and 75% by 2035 is expected to be impacted by factors including significant load growth, customer affordability, the pace of development of clean energy technology as well as federal, state and provincial energy policies. While Fortis remains committed to a coal-free generation mix by 2032 and its 2050 net-zero goal, the Corporation expects it will take longer to achieve the interim GHG reduction targets. As energy resource planning advances across the utilities, Fortis will reassess the interim targets and will share the results once complete. Interim Management Discussion and Analysis 21 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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FORWARD-LOOKING INFORMATION Fortis includes forward-looking information in this MD&A within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance, business prospects and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates, expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would, and the negative of these terms, and other similar terminology or expressions, have been used to identify the forward-looking information, which includes, without limitation: annual dividend growth guidance through 2030; forecast Capital Expenditures for 2025 and 2026 through 2030; expected impact and use of proceeds related to the sale of Fortis Belize and Belize Electricity; the expected timing, outcome and impact of legal and regulatory proceedings; expected and potential funding sources for operating expenses, interest costs, and capital expenditures; the expectation that maintaining the targeted capital structures of the regulated operating subsidiaries will not have an impact on the Corporation's ability to pay dividends in the foreseeable future; consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will continue to have access to long-term capital and will remain compliant with debt covenants; expected uses of proceeds from debt financings; expected in-service date of four gas engine turbines at Black Mountain Generating Station; the nature, timing, benefits and costs of data center-related retail load growth opportunities at TEP and TEP's and UNS Electric's purchase commitments in connection with a new planned pipeline which will be owned and operated by a third party; estimated impact of variations in the U.S. dollar-to-Canadian dollar exchange rate on the Capital Plan; expected sources of funding for the Capital Plan, including the sources of common equity proceeds; the expectation that government policy on foreign trade, including the imposition of tariffs and the potential impacts on the supply chain, commodity prices, the cost of energy and general economic conditions, will not have a material financial impact on the Corporation in 2025; the nature, timing, benefits and costs of certain Major Capital Projects, including ITC's investments associated with MISO LRTP tranche 1 and tranche 2.1 and the Big Cedar Load Expansion, TEP's Transmission Project, Springerville Natural Gas Conversion, Black Mountain Gas Generation, Vail-to-Tortolita Transmission project, and Roadrunner Reserve Battery Storage Project, as well as FortisBC Energy's Tilbury LNG Storage Expansion, AMI Project, Tilbury 1B Project and Eagle Mountain Pipeline Project; the nature, timing, benefits and costs of additional investment opportunities, including further investments at ITC associated with the MISO LRTP tranche 2.1 projects, further investments at TEP required to serve potential new large retail customers in the manufacturing, data center and mining sectors, further investments at TEP and UNS Electric associated with new Integrated Resource Plans expected to be filed in 2026, further investments at FortisBC Energy in association with the Tilbury LNG Storage Expansion Project and expansion of the Tilbury LNG facility, and other opportunities, including transmission investments to support customer connections and grid modernization, further renewable gas and LNG infrastructure, grid resiliency and climate adaptation investments, and the acceleration of load growth and cleaner energy infrastructure investments; the 2030 and 2035 interim GHG emissions reduction targets; the expectation that factors including significant load growth, customer affordability, the pace of development of clean energy technology as well as federal, state and provincial energy policies, will impact the Corporation's ability to achieve its interim GHG emissions reduction targets; the expectation of having a coal-free generation mix by 2032; the 2050 net-zero direct GHG emissions target; the expectation that the Corporation will take longer to achieve its interim GHG reduction targets; the planned reassessment of the Corporation's interim GHG reduction targets and associated disclosure; the expectation that the adoption of ASU No. 2023-09 will not materially impact the Corporation's disclosures; expected impacts and timing of future accounting pronouncements; forecast Rate Base and Rate Base growth through 2030; the expectation that long-term growth in Rate Base will drive earnings that support dividend growth guidance of 4-6% annually through 2030; and the expected nature and benefits of opportunities to expand and extend the Capital Plan. Forward-looking information involves significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information including, without limitation: reasonable legal and regulatory decisions and the expectation of regulatory stability; the successful execution of the Capital Plan; no material capital project or financing cost overrun; sufficient human resources to deliver service and execute the Capital Plan; the realization of additional opportunities beyond the Capital Plan; no significant variability in interest rates; no material changes in the assumed U.S. dollar-to-Canadian dollar exchange rate; the continuation of current participation levels in the Corporation's DRIP; the Board exercising its discretion to declare dividends, taking into account the financial performance and condition of the Corporation; no significant operational disruptions or environmental liability or upset; the continued ability to maintain the performance of the electricity and gas systems; no severe and prolonged economic downturn; sufficient liquidity and capital resources; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; the continued availability of natural gas, fuel, coal and electricity supply; continuation of power supply and capacity purchase contracts; no significant changes in government energy plans, environmental laws and regulations that could have a material negative impact; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; no significant changes in tax laws and the continued tax deferred treatment of earnings from the Corporation's foreign operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with Indigenous Peoples; and favourable labour relations. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from those discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risks" in this MD&A and in other continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2025 include, but are not limited to: uncertainty regarding changes in utility regulation, including the outcome of regulatory proceedings at the Corporation's utilities; the physical risks associated with the provision of electric and gas service, which can be exacerbated by the impacts of climate change; risks related to environmental laws and regulations; risks associated with capital projects and the impact on the Corporation's continued growth; risks associated with cybersecurity and information and operations technology; the impact of weather variability and seasonality on heating and cooling loads, gas distribution volumes and hydroelectric generation; risks associated with commodity price volatility and supply of purchased power; and risks related to general economic conditions, including inflation, interest rate and foreign exchange risks. All forward-looking information herein is given as of November 3, 2025 . Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise. Interim Management Discussion and Analysis 22 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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GLOSSARY 2024 Annual Financial Statements: the Corporation's audited consolidated financial statements and notes thereto for the year ended December 31, 2024 2024 Annual MD&A : the Corporation's management discussion and analysis for the year ended December 31, 2024 Adjusted Basic EPS: Adjusted Common Equity Earnings divided by the basic weighted average number of common shares outstanding Adjusted Common Equity Earnings: net earnings attributable to common equity shareholders adjusted as shown under "Non-U.S. GAAP Financial Measures" on page 9 ACC: Arizona Corporation Commission AFUDC: allowance for funds used during construction ASU: accounting standards update ATM Program: at-the-market equity program AUC: Alberta Utilities Commission BCUC: British Columbia Utilities Commission Belize Electricity: Belize Electricity Limited, in which Fortis indirectly holds a 33% equity interest. See "Subsequent Event" on page 4 Board: Board of Directors of the Corporation CAGR(s): compound annual growth rate of a particular item. CAGR = (EV/ BV)(1/n)-1, where: (i) EV is the ending value of the item; (ii) BV is the beginning value of the item; and (iii) n is the number of periods. Calculated on a constant U.S. dollar-to-Canadian dollar exchange rate Capital Expenditures: cash outlay for additions to property, plant and equipment and intangible assets as shown in the Interim Financial Statements, less CIACs received by FortisBC Energy associated with the Eagle Mountain Pipeline project. Also includes Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power project in 2024. See "Non-U.S. GAAP Financial Measures" on page 9 Capital Plan: forecast Capital Expenditures. Represents a non-U.S. GAAP financial measure calculated in the same manner as Capital Expenditures Caribbean Utilities: Caribbean Utilities Company, Ltd., an indirect approximately 60%-owned (as at December 31, 2024) subsidiary of Fortis, together with its subsidiary Central Hudson: CH Energy Group Inc., an indirect wholly owned subsidiary of Fortis, together with its subsidiaries, including Central Hudson Gas & Electric Corporation CIACs: contributions in aid of construction Common Equity Earnings: net earnings attributable to common equity shareholders Corporation: Fortis Inc. Court of Appeal: Court of Appeal of Alberta CPCN: Certificate of Public Convenience and Necessity D.C. Circuit Court: U.S. Court of Appeals for the District of Columbia Circuit DRIP: dividend reinvestment plan EPS: earnings per common share FERC: Federal Energy Regulatory Commission Fitch: Fitch Ratings, Inc. Fortis: Fortis Inc. FortisAlberta: FortisAlberta Inc., an indirect wholly owned subsidiary of Fortis FortisBC: FortisBC Energy and FortisBC Electric FortisBC Electric: FortisBC Inc., an indirect wholly owned subsidiary of Fortis, together with its subsidiaries FortisBC Energy: FortisBC Energy Inc., an indirect wholly owned subsidiary of Fortis, together with its subsidiaries FortisOntario: FortisOntario Inc., a direct wholly owned subsidiary of Fortis, together with its subsidiaries FortisTCI: FortisTCI Limited, an indirect wholly owned subsidiary of Fortis, together with its subsidiary, sold on September 2, 2025 Fortis Belize: Fortis Belize Limited, an indirect wholly owned subsidiary of Fortis. See "Subsequent Event" on page 4 FX: foreign exchange associated with the translation of U.S. dollar- denominated amounts. Foreign exchange is calculated by applying the change in the U.S. dollar-to-Canadian dollar FX rates to the prior period U.S. dollar balance GCOC: generic cost of capital GHG: greenhouse gas GWh: gigawatt hour(s) Interim Financial Statements: the Corporation's unaudited condensed consolidated interim financial statements and notes thereto for the three and nine months ended September 30, 2025 Interim MD&A: the Corporation's management discussion and analysis for the three and nine months ended September 30, 2025 IRP: integrated resource plan ITC: ITC Investment Holdings Inc., an indirect 80.1%-owned subsidiary of Fortis, together with its subsidiaries, including International Transmission Company, Michigan Electric Transmission Company, LLC, ITC Midwest LLC, and ITC Great Plains, LLC kV: kilovolt(s) LNG: liquefied natural gas LRTP: long-range transmission plan Major Capital Projects: projects, other than ongoing maintenance projects, individually costing $200 million or more in the forecast/planning period Maritime Electric: Maritime Electric Company, Limited, an indirect wholly owned subsidiary of Fortis Interim Management Discussion and Analysis 23 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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MW: megawatt MISO: Midcontinent Independent System Operator, Inc. Moody's: Moody's Investor Services, Inc. Morningstar DBRS: DBRS Limited Newfoundland Power: Newfoundland Power Inc., a direct wholly owned subsidiary of Fortis Non-U.S. GAAP Financial Measures: financial measures that do not have a standardized meaning prescribed by U.S. GAAP NOPR: notice of proposed rulemaking NYSE: New York Stock Exchange Operating Cash Flow: cash from operating activities PBR: performance-based rate setting PJ: petajoule(s) PPFAC: Purchased Power and Fuel Adjustment Clause PSC: New York State Public Service Commission Rate Base: the stated value of property on which a regulated utility is permitted to earn a specified return in accordance with its regulatory construct REA: Rural Electrification Association ROE: rate of return on common equity ROFR: right of first refusal RTO: regional transmission organization S&P: Standard & Poor's Financial Services LLC TEP: Tucson Electric Power Company, a direct wholly owned subsidiary of UNS Energy TSR: total shareholder return, which is a measure of the return to common equity shareholders in the form of share price appreciation and dividends (assuming reinvestment) over a specified time period in relation to the share price at the beginning of the period TSX: Toronto Stock Exchange UNS Energy: UNS Energy Corporation, an indirect wholly owned subsidiary of Fortis, together with its subsidiaries, including TEP, UNS Electric and UNS Gas UNS Electric: UNS Electric, Inc. UNS Gas: UNS Gas, Inc. U.S.: United States of America U.S. GAAP: accounting principles generally accepted in the U.S. Wataynikaneyap Power: Wataynikaneyap Power Limited Partnership, in which Fortis indirectly holds a 39% equity interest Interim Management Discussion and Analysis 24 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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FORTIS INC. Condensed Consolidated Interim Financial Statements For the three and nine months ended September 30, 2025 and 2024 (Unaudited) Interim Financial Statements 1 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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CONDENSED CONSOLIDATED INTERIM BALANCE SHEETS (Unaudited) FORTIS INC. September 30, December 31, As at (in millions of Canadian dollars) 2025 2024 ASSETS Current assets Cash and cash equivalents $ 389 $ 220 Accounts receivable and other current assets (Note 5) 1,622 1,886 Prepaid expenses 238 182 Inventories 655 685 Regulatory assets (Note 6) 752 823 Total current assets 3,656 3,796 Other assets 1,794 1,653 Regulatory assets (Note 6) 4,097 3,808 Property, plant and equipment, net 50,562 49,456 Intangible assets, net 1,708 1,661 Goodwill 12,686 13,112 Total assets $ 74,503 $ 73,486 LIABILITIES AND EQUITY Current liabilities Short-term borrowings (Note 7) $ 294 $ 98 Accounts payable and other current liabilities 2,993 3,353 Regulatory liabilities (Note 6) 537 595 Current installments of long-term debt (Note 7) 1,685 1,990 Total current liabilities 5,509 6,036 Regulatory liabilities (Note 6) 3,858 3,696 Deferred income taxes 5,155 5,020 Long-term debt (Note 7) 32,091 31,224 Finance leases 349 343 Other liabilities 1,288 1,314 Total liabilities 48,250 47,633 Commitments and contingencies (Note 15) Equity Common shares (1) 15,980 15,589 Preference shares 1,623 1,623 Additional paid-in capital 4 8 Accumulated other comprehensive income 1,399 2,067 Retained earnings 5,195 4,521 Shareholders' equity 24,201 23,808 Non-controlling interests 2,052 2,045 Total equity 26,253 25,853 Total liabilities and equity $ 74,503 $ 73,486 (1) No par value. Unlimited authorized shares. 505.4 million and 499.3 million issued and outstanding as at September 30, 2025 and December 31, 2024, respectively. See accompanying Notes to Condensed Consolidated Interim Financial Statements Interim Financial Statements 2 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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CONDENSED CONSOLIDATED INTERIM STATEMENTS OF EARNINGS (Unaudited) FORTIS INC. Quarter Year-to-Date For the periods ended September 30 (in millions of Canadian dollars, except per share amounts) 2025 2024 2025 2024 Revenue $ 2,938 $ 2,771 $ 9,091 $ 8,559 Expenses Energy supply costs 759 737 2,513 2,459 Operating expenses 790 740 2,409 2,245 Depreciation and amortization 518 480 1,545 1,427 Total expenses 2,067 1,957 6,467 6,131 Operating income 871 814 2,624 2,428 Other income, net (Note 11) 78 102 274 240 Finance charges 370 355 1,109 1,038 Earnings before income tax expense 579 561 1,789 1,630 Income tax expense 105 83 313 253 Net earnings $ 474 $ 478 $ 1,476 $ 1,377 Net earnings attributable to: Non-controlling interests $ 43 $ 39 $ 121 $ 112 Preference equity shareholders (Note 8) 22 19 63 55 Common equity shareholders 409 420 1,292 1,210 $ 474 $ 478 $ 1,476 $ 1,377 Earnings per common share (Note 12) Basic $ 0.81 $ 0.85 $ 2.57 $ 2.45 Diluted $ 0.81 $ 0.85 $ 2.57 $ 2.45 See accompanying Notes to Condensed Consolidated Interim Financial Statements CONDENSED CONSOLIDATED INTERIM STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Quarter Year-to-Date For the periods ended September 30 (in millions of Canadian dollars) 2025 2024 2025 2024 Net earnings $ 474 $ 478 $ 1,476 $ 1,377 Other comprehensive income (loss) Unrealized foreign currency translation gains (losses) (1) 450 (211) (661) 358 Other (2) — (2) (23) (4) 450 (213) $ (684) $ 354 Derecognition of foreign currency translation amount on disposition (Note 10) (52) — (52) — 398 (213) (736) 354 Comprehensive income $ 872 $ 265 $ 740 $ 1,731 Comprehensive income attributable to: Non-controlling interests $ 87 $ 18 $ 53 $ 150 Preference equity shareholders 22 19 63 55 Common equity shareholders 763 228 624 1,526 $ 872 $ 265 $ 740 $ 1,731 (1) Net of hedging activities and income tax recovery (expense) of $2 million and $(6) million for the three and nine months ended September 30, 2025, respectively (three and nine months ended September 30, 2024 - income tax (expense) recovery of $(2) million and $5 million, respectively) (2) Net of income tax recovery of $4 million and $10 million for the three and nine months ended September 30, 2025, respectively (three and nine months ended September 30, 2024 - income tax recovery of $nil and $1 million, respectively) See accompanying Notes to Condensed Consolidated Interim Financial Statements Interim Financial Statements 3 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS (Unaudited) FORTIS INC. Quarter Year-to-Date For the periods ended September 30 (in millions of Canadian dollars) 2025 2024 2025 2024 Operating activities Net earnings $ 474 $ 478 $ 1,476 $ 1,377 Adjustments to reconcile net earnings to net cash provided by operating activities: Depreciation - property, plant and equipment 451 424 1,362 1,254 Amortization - intangible assets 40 37 118 114 Amortization - other 27 19 65 59 Deferred income tax expense 45 61 169 112 Equity component, allowance for funds used during construction (Note 11) (42) (37) (123) (99) Other 41 17 60 39 Change in long-term regulatory assets and liabilities (51) 88 (70) (12) Change in working capital (Note 13) 42 251 (13) 76 Cash from operating activities 1,027 1,338 3,044 2,920 Investing activities Additions to property, plant and equipment (1,362) (1,248) (4,324) (3,383) Additions to intangible assets (91) (52) (216) (142) Contributions in aid of construction 175 30 487 81 Contribution to equity-accounted investee — — (27) — Proceeds on disposition, net (Note 10) 298 — 298 — Other (101) (43) (234) (155) Cash used in investing activities (1,081) (1,313) (4,016) (3,599) Financing activities Proceeds from long-term debt, net of issuance costs (Note 7) 1,179 1,190 2,310 2,608 Repayments of long-term debt and finance leases (4) (413) (66) (1,109) Borrowings under committed credit facilities 2,089 2,368 8,479 6,096 Repayments under committed credit facilities (2,822) (2,642) (9,180) (5,972) Net change in short-term borrowings (16) 30 261 (22) Issue of common shares, net of costs and dividends reinvested 11 13 45 34 Dividends Common shares, net of dividends reinvested (198) (186) (581) (549) Preference shares (22) (19) (63) (55) Subsidiary dividends paid to non-controlling interests (5) (32) (49) (86) Other 8 7 — (6) Cash from financing activities 220 316 1,156 939 Effect of exchange rate changes on cash and cash equivalents 2 (6) (15) 11 Change in cash and cash equivalents 168 335 169 271 Cash and cash equivalents, beginning of period 221 561 220 625 Cash and cash equivalents, end of period $ 389 $ 896 $ 389 $ 896 Supplementary Cash Flow Information (Note 13) See accompanying Notes to Condensed Consolidated Interim Financial Statements Interim Financial Statements 4 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CHANGES IN EQUITY (Unaudited) FORTIS INC. For the quarter ended September 30 (in millions of Canadian dollars, except share numbers) Common Shares (# millions) Common Shares Preference Shares Additional Paid-In Capital Accumulated Other Comprehensive Income (Loss) Retained Earnings Non- Controlling Interests Total Equity As at June 30, 2025 503.6 $ 15,857 $ 1,623 $ 6 $ 1,045 $ 5,095 $ 1,968 $ 25,594 Net earnings — — — — — 431 43 474 Other comprehensive income — — — — 406 — 44 450 Derecognition of foreign currency translation amount on disposition — — — — (52) — — (52) Common shares issued 1.8 123 — (1) — — — 122 Subsidiary dividends paid to non- controlling interests — — — — — — (5) (5) Dividends declared on common shares ($0.615 per share) — — — — — (309) — (309) Dividends on preference shares — — — — — (22) — (22) Other — — — (1) — — 2 1 As at September 30, 2025 505.4 $ 15,980 $ 1,623 $ 4 $ 1,399 $ 5,195 $ 2,052 $ 26,253 As at June 30, 2024 495.2 $ 15,346 $ 1,623 $ 8 $ 1,161 $ 4,611 $ 1,908 $ 24,657 Net earnings — — — — — 439 39 478 Other comprehensive loss — — — — (192) — (21) (213) Common shares issued 2.1 120 — — — — — 120 Subsidiary dividends paid to non- controlling interests — — — — — — (32) (32) Dividends declared on common shares ($1.205 per share) — — — — — (598) — (598) Dividends on preference shares — — — — — (19) — (19) As at September 30, 2024 497.3 $ 15,466 $ 1,623 $ 8 $ 969 $ 4,433 $ 1,894 $ 24,393 See accompanying Notes to Condensed Consolidated Interim Financial Statements Interim Financial Statements 5 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CHANGES IN EQUITY (Unaudited) FORTIS INC. For the nine months ended September 30 (in millions of Canadian dollars, except share numbers) Common Shares (# millions) Common Shares Preference Shares Additional Paid-In Capital Accumulated Other Comprehensive Income (Loss) Retained Earnings Non- Controlling Interests Total Equity As at December 31, 2024 499.3 $ 15,589 $ 1,623 $ 8 $ 2,067 $ 4,521 $ 2,045 $ 25,853 Net earnings — — — — — 1,355 121 1,476 Other comprehensive loss — — — — (616) — (68) (684) Derecognition of foreign currency translation amount on disposition — — — — (52) — — (52) Common shares issued 6.1 391 — (2) — — — 389 Subsidiary dividends paid to non- controlling interests — — — — — — (49) (49) Dividends declared on common shares ($1.23 per share) — — — — (618) — (618) Dividends on preference shares — — — — — (63) — (63) Other — — — (2) — — 3 1 As at September 30, 2025 505.4 $ 15,980 $ 1,623 $ 4 $ 1,399 $ 5,195 $ 2,052 $ 26,253 As at December 31, 2023 490.6 $ 15,108 $ 1,623 $ 9 $ 653 $ 4,112 $ 1,827 $ 23,332 Net earnings — — — — — 1,265 112 1,377 Other comprehensive income — — — — 316 — 38 354 Common shares issued 6.7 358 — — — — — 358 Subsidiary dividends paid to non- controlling interests — — — — — — (86) (86) Dividends declared on common shares ($1.795 per share) — — — — — (889) — (889) Dividends on preference shares — — — — — (55) — (55) Other — — — (1) — — 3 2 As at September 30, 2024 497.3 $ 15,466 $ 1,623 $ 8 $ 969 $ 4,433 $ 1,894 $ 24,393 See accompanying Notes to Condensed Consolidated Interim Financial Statements Interim Financial Statements 6 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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1. DESCRIPTION OF BUSINESS Nature of Operations Fortis Inc. ("Fortis" or the "Corporation") is a well-diversified North American regulated electric and gas utility holding company. Earnings for interim periods may not be indicative of annual results due to: (i) the impact of seasonal weather conditions on customer demand; (ii) the impact of market conditions, particularly with respect to wholesale sales at UNS Energy; (iii) changes in the U.S. dollar-to-Canadian dollar exchange rate; and (iv) the timing and significance of regulatory decisions. Earnings for utilities in Canada and New York tend to be highest in the first and fourth quarters due to space-heating requirements. Earnings for UNS Energy tend to be highest in the second and third quarters due to the use of air conditioning and other cooling equipment. Entities within the reporting segments that follow operate with substantial autonomy. Regulated Utilities ITC: ITC Investment Holdings Inc., ITC Holdings Corp. and the electric transmission operations of its regulated operating subsidiaries, which include International Transmission Company, Michigan Electric Transmission Company, LLC, ITC Midwest LLC and ITC Great Plains, LLC. Fortis owns 80.1% of ITC and an affiliate of GIC Private Limited owns a 19.9% minority interest. UNS Energy: UNS Energy Corporation, which primarily includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas"). Central Hudson: CH Energy Group, Inc., which primarily includes Central Hudson Gas & Electric Corporation. FortisBC Energy: FortisBC Energy Inc. FortisAlberta: FortisAlberta Inc. FortisBC Electric: FortisBC Inc. Other Electric: Eastern Canadian and Caribbean utilities, as follows: Newfoundland Power Inc.; Maritime Electric Company, Limited; FortisOntario Inc.; a 39% equity investment in Wataynikaneyap Power Limited Partnership; an approximate 60% controlling interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities"); and a 33% equity investment in Belize Electricity Limited ("Belize Electricity") (Note 16). Also includes the results for FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "FortisTCI") until the September 2, 2025 date of disposition (Note 10). Non-Regulated Corporate and Other: Captures expenses and revenues not specifically related to any reportable segment and those business operations that are below the required threshold for segmented reporting. Consists of non-regulated holding company expenses, as well as non-regulated long-term contracted generation assets in Belize held through Fortis Belize Limited ("Fortis Belize") (Note 16). 2. REGULATORY MATTERS Regulation of the Corporation's utilities is generally consistent with that disclosed in Note 2 of the Corporation's annual audited consolidated financial statements ("2024 Annual Financial Statements"). A summary of significant outstanding regulatory matters follows. ITC MISO Base ROE: In October 2024, the Federal Energy Regulatory Commission ("FERC") issued an order that revised the base rate of return on common equity ("ROE") for transmission owners operating in the Midcontinent Independent System Operator, Inc. ("MISO") region, including ITC, from 10.02% to 9.98%, with a maximum ROE inclusive of incentives not to exceed 12.58%. The order also directed the payment of certain refunds, with interest, by December 2025, for the 15-month period from November 2013 through February 2015, and prospectively from September 2016. Certain MISO transmission owners, including ITC, filed a request for rehearing with FERC in November 2024, and filed an appeal of the order with the U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit Court") in January 2025, with particular focus on the refund period and related interest. In March 2025, FERC issued an order addressing the request for rehearing but made no changes to the October 2024 order. The MISO transmission owners continue to pursue an appeal at the D.C. Circuit Court in relation to FERC's October 2024 and March 2025 orders. The timing and outcome of this appeal are unknown. In addition, MISO and the MISO transmission owners are awaiting a response from FERC with respect to a request filed in September 2025 to extend the period to pay refunds from December 2025 to June 30, 2026. Transmission Incentives: In 2021, FERC issued a supplemental notice of proposed rulemaking ("NOPR") on transmission incentives modifying the proposal in the initial NOPR released by FERC in 2020. The supplemental NOPR proposes to eliminate the 50-basis point regional transmission organization ("RTO") ROE incentive adder for RTO members that have been members for longer than three years. The timing and outcome of this proceeding are unknown. Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 7 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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2. REGULATORY MATTERS (cont'd) UNS Energy TEP General Rate Application: In June 2025, TEP filed a general rate application with the Arizona Corporation Commission ("ACC") requesting new rates effective September 1, 2026 using a December 31, 2024 test year, with post-test year adjustments through June 30, 2025. The application includes a proposal to phase-out or eliminate certain adjustor mechanisms, and requests an annual formulaic rate adjustment mechanism consistent with the ACC's approval of a formula rate policy statement in 2024. UNS Gas General Rate Application: In November 2024, UNS Gas filed a general rate application with the ACC requesting an increase in gas delivery rates effective February 1, 2026. In January 2025, UNS Gas filed supplemental material proposing an annual formulaic rate adjustment mechanism. The outcome of this proceeding is unknown. Central Hudson 2025 General Rate Application: In August 2025, the New York State Public Service Commission ("PSC") approved a three-year rate plan for Central Hudson with retroactive application to July 1, 2025, including the continuation of a 9.5% allowed ROE and a 48% common equity component of capital structure. The three-year rate plan also includes the use of existing regulatory balances and other measures to reduce customer bill impacts, as well as initiatives to support New York States's energy conservation emission reduction goals. Enforcement Proceeding: In August 2025, the PSC issued an order which accepted a joint settlement agreement and concluded the enforcement proceeding in connection with a gas-related explosion that occurred in November 2023. As part of the order, Central Hudson agreed to make a contribution to a customer benefit fund which was recorded in the third quarter of 2025. FortisBC Energy and FortisBC Electric 2025-2027 Rate Framework: In March 2025, the British Columbia Utilities Commission issued a decision on FortisBC's application with respect to the rate framework for 2025 through 2027. The rate framework builds upon the previous multi-year rate plan and includes, amongst other items, updates to depreciation and capitalized overhead rates, a revised level of operation and maintenance expense per customer indexed for inflation less a fixed productivity adjustment factor, a similar approach to growth capital, a forecast approach to sustaining and other capital, continued collection of an innovation fund recognizing the need to accelerate investment in clean energy innovation, and the continued sharing with customers of variances from the allowed ROE. The rate framework also includes the continuation of deferral mechanisms included in the previous multi-year rate plan. FortisAlberta Generic Cost of Capital ("GCOC") Decision: FortisAlberta filed an appeal with respect to the Alberta Utilities Commission's ("AUC") decision on the 2024 GCOC proceeding based on FortisAlberta's business and regulatory risks associated with Rural Electrification Associations located in its service area. In March 2025, the Court of Appeal of Alberta ("Court of Appeal") dismissed the appeal. Third Performance-based Rate-setting ("PBR") Term Decision: In 2023, the AUC issued a decision establishing the parameters for the third PBR term for the period of 2024 through 2028. FortisAlberta sought permission to appeal the decision to the Court of Appeal on the basis that the AUC erred in its decision to determine capital funding using 2018-2022 historical capital investments without consideration for funding of new capital programs included in the company's 2023 cost of service revenue requirement as approved by the AUC. In March 2025, the Court of Appeal granted FortisAlberta permission to appeal, which is expected to be heard in the first quarter of 2026. 3. ACCOUNTING POLICIES These condensed consolidated interim financial statements ("Interim Financial Statements") have been prepared and presented in accordance with accounting principles generally accepted in the United States of America for rate-regulated entities and are in Canadian dollars unless otherwise indicated. The Interim Financial Statements include the accounts of the Corporation and its subsidiaries and reflect the equity method of accounting for entities in which Fortis has significant influence, but not control, and proportionate consolidation for assets that are jointly owned with non-affiliated entities. These Interim Financial Statements do not include all of the disclosures required in the annual financial statements and should be read in conjunction with the Corporation's 2024 Annual Financial Statements. In management's opinion, these Interim Financial Statements include all adjustments that are of a normal recurring nature, necessary for fair presentation. The preparation of the Interim Financial Statements required management to make estimates and judgments, including those related to regulatory decisions, that affect the reported amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. Actual results could differ materially from estimates. The Corporation considers the applicability and impact of all Accounting Standards Updates ("ASUs") issued by the Financial Accounting Standards Board. Any ASUs not included in these Interim Financial Statements were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the Interim Financial Statements. Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 8 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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3. ACCOUNTING POLICIES (cont'd) The accounting policies applied herein are consistent with those outlined in the Corporation's 2024 Annual Financial Statements, except as described below. New Accounting Policy Income Taxes: The Corporation adopted ASU No. 2023-09, Improvements to Income Tax Disclosures , effective January 1, 2025. The ASU requires additional disclosure of income tax information by jurisdiction to reflect an entity's exposure to potential changes in tax legislation, and associated risks and opportunities. The guidance is to be applied on a prospective basis with retrospective application permitted. The updated disclosure will be reflected in the Corporation's annual consolidated financial statements. Fortis does not expect the ASU to materially impact its disclosures. Future Accounting Pronouncements Expense Disaggregation: ASU No. 2024-03, Disaggregation of Income Statement Expenses, is effective for Fortis on January 1, 2027 for annual periods and on January 1, 2028 for interim periods, on a prospective basis, with retrospective application and early adoption permitted. The ASU requires detailed disclosure of certain expense categories included on the consolidated statements of earnings, including energy supply costs, operating expenses, and depreciation and amortization expense. Fortis is assessing the impact on its disclosures. Credit Losses: ASU No. 2025-05, Measurement of Credit Losses for Accounts Receivable and Contract Assets , is effective for Fortis on January 1, 2026 on a prospective basis with early adoption permitted. The ASU provides entities with an option to use a practical expedient to estimate credit losses which would use existing conditions as of the balance sheet date, rather than forecast conditions for the contractual term of the asset. Fortis is assessing the impact on its consolidated financial statements. Internal-Use Software: ASU No. 2025-06, Targeted Improvements to the Accounting for Internal-Use Software , is effective for Fortis on January 1, 2028. The ASU may be adopted prospectively, retrospectively, or using a modified transition approach, and early adoption permitted. The ASU removes references to development stages and requires capitalization of software costs once funding is authorized and project completion is probable, including assessment of whether significant development uncertainty exists. The guidance also clarifies that all capitalized internal-use software costs must follow the disclosure requirements in Subtopic 360-10, Property, Plant and Equipment. Fortis is assessing the impact on its consolidated financial statements and disclosures. 4. SEGMENTED INFORMATION Fortis' President and Chief Executive Officer is considered the chief operating decision maker ("CODM") for purposes of reviewing segment performance. Fortis segments its business based on regulatory jurisdiction and service territory, as well as the information used by the CODM in deciding how to allocate resources. Segment performance is evaluated principally on net earnings attributable to common equity shareholders, and this measure is used consistently in the evaluation of actual segment performance as well as in the Corporation’s business plan and forecasting processes. Related-Party and Inter-Company Transactions Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions for the three and nine months ended September 30, 2025 and 2024. Fortis periodically provides short-term financing to subsidiaries to support capital expenditures and seasonal working capital requirements, the impacts of which are eliminated on consolidation. As at September 30, 2025 and December 31, 2024, there were no material inter-segment loans outstanding. Interest charged on inter-segment loans was not material for the three and nine months ended September 30, 2025 and 2024. Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 9 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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4. SEGMENTED INFORMATION (cont'd) Regulated Non- Regulated Inter- UNS Central FortisBC Fortis FortisBC Other Sub Corporate segment ($ millions) ITC Energy Hudson Energy Alberta Electric Electric Total and Other eliminations Total Quarter ended September 30, 2025 Revenue 625 893 388 281 213 133 393 2,926 12 — 2,938 Energy supply costs — 311 138 59 — 42 209 759 — — 759 Operating expenses 160 209 166 103 46 33 58 775 15 — 790 Depreciation and amortization 121 106 39 95 75 23 57 516 2 — 518 Operating income 344 267 45 24 92 35 69 876 (5) — 871 Other income, net 21 16 16 13 2 2 5 75 3 — 78 Finance charges 129 42 21 39 34 20 22 307 63 — 370 Income tax expense 53 32 9 (2) 6 2 2 102 3 — 105 Net earnings 183 209 31 — 54 15 50 542 (68) — 474 Non-controlling interests 34 — — — — — 9 43 — — 43 Preference share dividends — — — — — — — — 22 — 22 Net earnings attributable to common equity shareholders 149 209 31 — 54 15 41 499 (90) — 409 Additions to property, plant and equipment and intangible assets 435 385 121 215 136 50 110 1,452 1 — 1,453 As at September 30, 2025 Goodwill 8,543 1,923 628 913 231 235 213 12,686 — — 12,686 Total assets 27,455 15,136 6,337 10,515 6,385 2,907 5,251 73,986 530 (13) 74,503 Quarter ended September 30, 2024 Revenue 556 883 338 246 209 130 399 2,761 10 — 2,771 Energy supply costs — 330 106 45 — 39 217 737 — — 737 Operating expenses 128 193 165 101 45 33 60 725 15 — 740 Depreciation and amortization 110 100 35 85 73 21 54 478 2 — 480 Operating income 318 260 32 15 91 37 68 821 (7) — 814 Other income, net 23 16 14 12 4 2 6 77 25 — 102 Finance charges 121 40 20 40 34 21 22 298 57 — 355 Income tax expense 51 32 6 (9) 7 4 5 96 (13) — 83 Net earnings 169 204 20 (4) 54 14 47 504 (26) — 478 Non-controlling interests 31 — — — — — 8 39 — — 39 Preference share dividends — — — — — — — — 19 — 19 Net earnings attributable to common equity shareholders 138 204 20 (4) 54 14 39 465 (45) — 420 Additions to property, plant and equipment and intangible assets 355 303 107 237 147 29 121 1,299 1 — 1,300 As at September 30, 2024 Goodwill 8,301 1,869 610 913 231 235 257 12,416 — — 12,416 Total assets 25,349 14,035 5,651 9,885 6,161 2,786 5,431 69,298 355 (11) 69,642 Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 10 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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4. SEGMENTED INFORMATION (cont'd) Regulated Non- Regulated Inter- UNS Central FortisBC Fortis FortisBC Other Sub Corporate segment ($ millions) ITC Energy Hudson Energy Alberta Electric Electric Total and Other eliminations Total Year-to-date September 30, 2025 Revenue 1,870 2,267 1,208 1,298 621 412 1,386 9,062 29 — 9,091 Energy supply costs — 816 399 378 — 120 800 2,513 — — 2,513 Operating expenses 477 606 518 314 148 105 190 2,358 51 — 2,409 Depreciation and amortization 361 319 117 274 228 63 177 1,539 6 — 1,545 Operating income 1,032 526 174 332 245 124 219 2,652 (28) — 2,624 Other income, net 60 55 53 37 5 4 17 231 43 — 274 Finance charges 387 127 69 115 101 60 68 927 182 — 1,109 Income tax expense 163 60 37 51 17 11 19 358 (45) — 313 Net earnings 542 394 121 203 132 57 149 1,598 (122) — 1,476 Non-controlling interests 100 — — 1 — — 20 121 — — 121 Preference share dividends — — — — — — — — 63 — 63 Net earnings attributable to common equity shareholders 442 394 121 202 132 57 129 1,477 (185) — 1,292 Additions to property, plant and equipment and intangible assets 1,363 1,128 330 792 424 127 373 4,537 3 — 4,540 As at September 30, 2025 Goodwill 8,543 1,923 628 913 231 235 213 12,686 — — 12,686 Total assets 27,455 15,136 6,337 10,515 6,385 2,907 5,251 73,986 530 (13) 74,503 Year-to-date September 30, 2024 Revenue 1,662 2,348 1,016 1,143 610 396 1,359 8,534 25 — 8,559 Energy supply costs — 928 324 284 — 109 814 2,459 — — 2,459 Operating expenses 393 588 503 297 142 100 185 2,208 37 — 2,245 Depreciation and amortization 330 299 96 253 217 65 162 1,422 5 — 1,427 Operating income 939 533 93 309 251 122 198 2,445 (17) — 2,428 Other income, net 77 37 44 31 9 5 16 219 21 — 240 Finance charges 354 112 56 118 101 61 69 871 167 — 1,038 Income tax expense 153 62 19 48 20 12 17 331 (78) — 253 Net earnings 509 396 62 174 139 54 128 1,462 (85) — 1,377 Non-controlling interests 94 — — 1 — — 17 112 — — 112 Preference share dividends — — — — — — — — 55 — 55 Net earnings attributable to common equity shareholders 415 396 62 173 139 54 111 1,350 (140) — 1,210 Additions to property, plant and equipment and intangible assets 1,021 726 294 660 410 89 322 3,522 3 — 3,525 As at September 30, 2024 Goodwill 8,301 1,869 610 913 231 235 257 12,416 — — 12,416 Total assets 25,349 14,035 5,651 9,885 6,161 2,786 5,431 69,298 355 (11) 69,642 Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 11 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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5. ALLOWANCE FOR CREDIT LOSSES The allowance for credit losses, which is recorded in accounts receivable and other current assets, changed as follows. Quarter Year-to-Date ($ millions) 2025 2024 2025 2024 Periods ended September 30 Balance, beginning of period (74) (69) (78) (68) Credit loss expense (11) (7) (25) (23) Credit loss deferral (19) (6) (36) (26) Write-offs, net of recoveries 19 9 51 45 Disposition (Note 10) 6 — 6 — Foreign exchange (1) — 2 (1) Balance, end of period (80) (73) (80) (73) See Note 14 for disclosure on the Corporation's credit risk. 6. REGULATORY ASSETS AND LIABILITIES Detailed information about the Corporation's regulatory assets and liabilities is provided in Note 8 to the 2024 Annual Financial Statements. A summary follows. As at September 30, December 31, ($ millions) 2025 2024 Regulatory assets Deferred income taxes 2,392 2,248 Deferred energy management costs 663 591 Rate stabilization and related accounts 457 453 Employee future benefits 221 235 Deferred lease costs 154 142 Derivatives 128 175 Deferred restoration costs 121 133 Manufactured gas plant site remediation deferral 83 82 Generation early retirement costs 55 66 Renewable natural gas account 42 58 Other regulatory assets 533 448 Total regulatory assets 4,849 4,631 Less: Current portion (752) (823) Long-term regulatory assets 4,097 3,808 Regulatory liabilities Future cost of removal 1,837 1,728 Deferred income taxes 1,396 1,329 Employee future benefits 420 459 Rate stabilization and related accounts 261 208 Renewable energy surcharge 163 155 Energy efficiency liability 85 88 Electric and gas moderator account 44 61 Alberta Electric System Operator charges deferral 20 58 Other regulatory liabilities 169 205 Total regulatory liabilities 4,395 4,291 Less: Current portion (537) (595) Long-term regulatory liabilities 3,858 3,696 Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 12 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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7. LONG-TERM DEBT As at September 30, December 31, ($ millions) 2025 2024 Long-term debt 32,489 31,189 Credit facility borrowings 1,478 2,216 Total long-term debt 33,967 33,405 Less: Deferred financing costs and debt discounts (191) (191) Less: Current installments of long-term debt (1,685) (1,990) 32,091 31,224 Significant Long-Term Debt Issuances Interest Year-to-date September 30, 2025 Month Rate Use of ($ millions, except as noted) Issued (%) Maturity Amount Proceeds UNS Energy Unsecured senior notes February 5.90 2055 US $300 (1) (2) (3) Central Hudson Senior notes April 5.61 2035 US $20 (1) (3) Senior notes April 5.81 2040 US $30 (1) (3) Senior notes April 6.01 2045 US $20 (1) (3) FortisAlberta Unsecured senior debentures July 4.76 2055 200 (1) (2) (3) Newfoundland Power First mortgage bonds August 4.91 2055 120 (1) (2) (3) Maritime Electric First mortgage bonds July 4.94 2055 120 (1) (2) Fortis Unsecured senior notes March 4.09 2032 600 (1) (3) Subordinated notes (4) September 5.10 2055 750 (1) (3) (1) Repay credit facility borrowings (2) Fund capital expenditures (3) General corporate purposes (4) Issuance reflects fixed-to-fixed rate hybrid subordinated notes. The interest rate will be reset on December 4, 2030, and every 5-years thereafter, equal to the 5-year Government of Canada bond yield plus 2.09% provided that the interest rate reset will not be below the initial interest rate of 5.10%. The subordinated notes receive partial equity treatment from credit rating agencies In October 2025, UNS Energy issued US$50 million of 10-year, 5.38% unsecured senior notes. Proceeds will be used to repay credit facility borrowings and for general corporate purposes. In October 2025, FortisBC Energy issued $200 million of 5-year, 3.38% unsecured debentures. Proceeds will be used to repay credit facility borrowings. In October 2025, Central Hudson priced US$80 million of senior notes with funding expected in November 2025. The related issuances will consist of US$15 million of 10-year, 5.25% notes and US$65 million of 20-year, 5.90% notes. Proceeds are expected to be used for general corporate purposes. In December 2024, Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts, or debt securities in an aggregate principal amount of up to $2.0 billion. Fortis re-established the at-the-market equity program ("ATM Program") pursuant to the short-form base shelf prospectus, which allows the Corporation to issue up to $500 million of common shares from treasury to the public from time to time, at the Corporation's discretion, effective until January 10, 2027. As at September 30, 2025, $500 million remained available under the ATM Program and $1.5 billion remained available under the short-form base shelf prospectus. As at Credit facilities Regulated Corporate September 30, December 31, ($ millions) Utilities and Other 2025 2024 Total credit facilities 4,230 1,581 5,811 6,342 Credit facilities utilized: Short-term borrowings (1) (294) — (294) (98) Long-term debt (including current portion) (2) (1,478) — (1,478) (2,216) Letters of credit outstanding (94) (22) (116) (102) Credit facilities unutilized 2,364 1,559 3,923 3,926 (1) The weighted average interest rate was 4.4% (December 31, 2024 - 6.1%). (2) The weighted average interest rate was 4.3% (December 31, 2024 - 4.6%). The current portion was $797 million (December 31, 2024 - $1,860 million). Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 13 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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7. LONG-TERM DEBT (cont'd) Credit facilities are syndicated primarily with large banks in Canada and the U.S., with no one bank holding more than approximately 20% of the Corporation's total revolving credit facilities. Approximately $5.4 billion of the total credit facilities are committed with maturities ranging from 2027 through 2030. See Note 14 in the 2024 Annual Financial Statements for a description of the credit facilities as at December 31, 2024. In April 2025, FortisAlberta increased its operating credit facility from $250 million to $300 million and extended the maturity to April 2030. In May 2025, the Corporation amended its $1.3 billion revolving term committed credit facility to extend the maturity to July 2030. In September 2025, FortisUS Inc., a holding company subsidiary of Fortis, extended the maturity on its unsecured US$150 million revolving term credit facility to October 2027. Also in September 2025, the Corporation fully repaid its unsecured US$250 million non-revolving term credit facility. 8. PREFERENCE SHARES On June 1, 2025, the annual fixed dividend per share for the First Preference Shares, Series H reset from $0.4588 to $1.0458 for the five-year period up to but excluding June 1, 2030. Also on June 1, 2025, 11,298 First Preference Shares, Series H were converted on a one-for-one basis into First Preference Shares, Series I and 248,830 First Preference Shares, Series I were converted on a one-for-one basis into First Preference Shares, Series H. 9. EMPLOYEE FUTURE BENEFITS Fortis and each subsidiary maintain one or a combination of defined benefit pension plans and defined contribution pension plans, as well as other post- employment benefit ("OPEB") plans, including health and dental coverage and life insurance benefits, for qualifying members. The net benefit cost is detailed below. Defined Benefit Pension Plans OPEB Plans ($ millions) 2025 2024 2025 2024 Quarter ended September 30 Service costs 17 18 6 6 Interest costs 42 40 8 7 Expected return on plan assets (53) (54) (7) (7) Amortization of actuarial gains (4) (1) (6) (4) Amortization of past service credits/plan amendments (1) 1 (1) — Regulatory adjustments — (1) 2 — Net benefit cost 1 3 2 2 Year-to-date September 30 Service costs 53 55 17 18 Interest costs 128 120 23 22 Expected return on plan assets (160) (164) (21) (20) Amortization of actuarial gains (12) (1) (18) (13) Amortization of past service credits/plan amendments (1) — (1) — Regulatory adjustments (1) (1) 6 1 Net benefit cost 7 9 6 8 Defined contribution pension plan expense for the three and nine months ended September 30, 2025 was $15 million and $50 million, respectively (three and nine months ended September 30, 2024 - $14 million and $45 million, respectively). 10. DISPOSITION On September 2, 2025, Fortis sold its 100% ownership interest in FortisTCI. As a result of the sale, Fortis recognized a $32 million loss related to income taxes and closing costs, which has been reflected in the Corporate and Other segment. Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 14 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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11. OTHER INCOME, NET Quarter Year-to-Date ($ millions) 2025 2024 2025 2024 Periods ended September 30 Equity component, allowance for funds used during construction 42 37 123 99 Non-service component of net periodic benefit cost 19 19 58 55 Gain on derivatives, net 7 23 39 17 Interest income 9 17 31 49 Equity income 3 1 10 5 Other (2) 5 13 15 78 102 274 240 12. EARNINGS PER COMMON SHARE 2025 2024 Net Earnings Weighted Net Earnings Weighted to Common Average to Common Average Shareholders Shares EPS Shareholders Shares EPS ($ millions) (# millions) ($) ($ millions) (# millions) ($) Quarter ended September 30 Basic EPS 409 504.5 0.81 420 496.2 0.85 Potential dilutive effect of stock-based compensation — 0.3 — 0.2 Diluted EPS 409 504.8 0.81 420 496.4 0.85 Year-to-date September 30 Basic EPS 1,292 502.5 2.57 1,210 493.9 2.45 Potential dilutive effect of stock-based compensation — 0.3 — 0.2 Diluted EPS 1,292 502.8 2.57 1,210 494.1 2.45 13. SUPPLEMENTARY CASH FLOW INFORMATION Quarter Year-to-Date ($ millions) 2025 2024 2025 2024 Periods ended September 30 Change in working capital Accounts receivable and other current assets 50 20 132 83 Prepaid expenses (48) (47) (68) (76) Inventories (9) (17) (41) (31) Regulatory assets - current portion 1 (27) 21 107 Accounts payable and other current liabilities 40 271 — (76) Regulatory liabilities - current portion 8 51 (57) 69 42 251 (13) 76 Non-cash financing activity Common share dividends reinvested 112 106 345 324 As at September 30 2025 2024 Non-cash investing activities Accrued capital expenditures 708 638 Contributions in aid of construction 16 10 Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 15 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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14. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Derivatives The Corporation generally lim its the use of derivatives to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. Derivatives are recorded at fair value with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. Fair values reflect estimates based on current market information about the derivatives as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future consolidated earnings or cash flow. Energy Contracts Subject to Regulatory Deferral UNS Energy holds electricity power purchase contracts, customer supply contracts and gas swap contracts to reduce its exposure to energy price risk. Fair values are measured primarily under the market approach using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission costs and line losses. Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price. Fair values are measured using forward pricing provided by independent third-party information. FortisBC Energy holds gas supply contracts to fix the effective purchase price of natural gas. Fair values reflect the present value of future cash flows based on published market prices and forward natural gas price curves. Unrealized gains or losses associated with changes in the fair value of these energy contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. As at September 30, 2025, unrealized losses of $128 million (December 31, 2024 - $175 million) were recognized as regulatory assets and unrealized gains of $40 million (December 31, 2024 - $41 million) were recognized as regulatory liabilities. Energy Contracts Not Subject to Regulatory Deferral UNS Energy holds wholesale trading contracts to fix power prices and realize potential margin, of which 10% of any realized gains is shared with customers through rate stabilization accounts. Fair values are measured using a market approach incorporating, where possible, independent third-party information. Gains or losses associated with changes in the fair value of these energy contracts are recognized in revenue . During the three and nine months ended September 30, 2025, gains of $4 million and $36 million were recognized in revenue, respectively ( three and nine months ended September 30, 2024 - gains of $5 million and $44 million, respectively). Total Return Swaps The Corporation holds total return swaps to manage the cash flow risk associated with forecast future cash and/or share settlements of certain stock- based compensation obligations. The swaps have a combined notional amount of $136 million and terms up to three years expiring at varying dates through January 2028. Fair value is measured using an income valuation approach based on forward pricing curves. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. During the three and nine months ended September 30, 2025, unrealized gains of $13 million and $22 million, respectively were recognized in other income, net ( three and nine months ended September 30, 2024 - unrealized gains of $20 million and $16 million, respectively). Foreign Exchange Contracts The Corporation holds U.S. dollar denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The contracts expire at varying dates through September 2027 and have a combined notional amount of US$427 million. Fair value was measured using independent third-party information. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. During the three and nine months ended September 30, 2025, unrealized losses of $7 million and unrealized gains of $12 million, respectively were recognized in other income, net (three and nine months ended September 30, 2024 - unrealized gains of $2 million and unrealized losses of $3 million, respectively). Interest Rate Contracts ITC has entered into 5-year interest rate swap contracts with a combined notional value of US$705 million which will be used to manage interest rate risk associated with forecasted debt issuances. Fair value was measured using a discounted cash flow method based on secured overnight financing rates ("SOFR"). Unrealized gains and losses associated with the changes in fair value are recognized in other comprehensive income, and will be reclassified to earnings as a component of interest expense over the life of the debt. Unrealized losses of less than US$1 million and US$8 million were recorded in other comprehensive income for the three and nine months ended September 30, 2025 (three and nine months ended September 30, 2024 - unrealized gains of less than $1 million). Cross-Currency Interest Rate Swaps The Corporation holds cross-currency interest rate swaps, maturing in 2029, to effectively convert its $500 million , 4.43% unsecured senior notes to US$391 million, 4.34% debt. The Corporation has designated this notional U.S. debt as an effective hedge of its foreign net investments and unrealized gains and losses associated with exchange rate fluctuations on the notional U.S. debt are recognized in other comprehensive income, consistent with the translation adjustment related to the foreign net investments. Other changes in the fair value of the swaps are also recognized in other comprehensive income but are excluded from the assessment of hedge effectiveness. Fair value is measured using a discounted cash flow method based on SOFR. During the three and nine months ended September 30, 2025, unrealized losses of $12 million and unrealized gains of $5 million, respectively were recorded in other comprehensive income ( three and nine months ended September 30, 2024 - unrealized gains of $6 million and unrealized losses of $9 million, respectively). Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 16 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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14. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd) Recurring Fair Value Measures The following table presents assets and liabilities that are accounted for at fair value on a recurring basis. ($ millions) Level 1 (1) Level 2 (1) Level 3 (1) Total As at September 30, 2025 Assets Energy contracts subject to regulatory deferral (2) (3) — 58 — 58 Energy contracts not subject to regulatory deferral (2) — 6 — 6 Total return swaps (2) — 32 — 32 Other investments (4) 133 — — 133 133 96 — 229 Liabilities Energy contracts subject to regulatory deferral (3) (5) — (146) — (146) Energy contracts not subject to regulatory deferral (5) — (1) — (1) Cross-currency interest rate swaps, foreign exchange and interest rate contracts (5) — (34) — (34) — (181) — (181) As at December 31, 2024 Assets Energy contracts subject to regulatory deferral (2) (3) — 63 — 63 Energy contracts not subject to regulatory deferral (2) — 7 — 7 Total return swaps and interest rate contracts (2) — 16 — 16 Other investments (4) 150 — — 150 150 86 — 236 Liabilities Energy contracts subject to regulatory deferral (3) (5) — (197) — (197) Energy contracts not subject to regulatory deferral (5) — (2) — (2) Foreign exchange contracts and cross-currency interest rate swaps (5) — (45) — (45) — (244) — (244) (1) Under the hierarchy, fair value is determined using: (i) level 1 - unadjusted quoted prices in active markets; (ii) level 2 - other pricing inputs directly or indirectly observable in the marketplace; and (iii) level 3 - unobservable inputs, used when observable inputs are not available. Classifications reflect the lowest level of input that is significant to the fair value measurement. (2) Included in accounts receivable and other current assets or other assets (3) Unrealized gains and losses arising from changes in fair value of these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates as permitted by the regulators, with the exception of wholesale trading contracts and certain gas swap contracts (4) UNS Energy holds investments in money market accounts, and ITC and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees, which include mutual funds and money market accounts. The fair value of these investments is included in cash and cash equivalents and other assets, with gains and losses recognized in other income, net (5) Included in accounts payable and other current liabilities or other liabilities Energy Contracts The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which apply only to its energy contracts. The following table presents the potential offset of counterparty netting. Gross Amount Counterparty Recognized in Netting of Cash Collateral ($ millions) Balance Sheet Energy Contracts Posted/(Received) Net Amount As at September 30, 2025 Derivative assets 64 (36) 15 43 Derivative liabilities (147) 36 — (111) As at December 31, 2024 Derivative assets 70 (30) 15 55 Derivative liabilities (199) 30 — (169) Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 17 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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14. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd) Volume of Derivative Activity As at September 30, 2025, the Corporation had various energy contracts that will settle on various dates through 2030. The volumes related to electricity and natural gas derivatives are outlined below. As at September 30, December 31, 2025 2024 Energy contracts subject to regulatory deferral (1) Electricity swap contracts (GWh) 913 774 Electricity power purchase contracts (GWh) 225 430 Gas swap contracts (PJ) 203 236 Gas supply contracts (PJ) 191 105 Energy contracts not subject to regulatory deferral (1) Wholesale trading contracts (GWh) 2,755 1,499 Gas swap contracts (PJ) 1 3 (1) GWh means gigawatt hours and PJ means petajoules. Credit Risk For cash equivalents, accounts receivable and other current assets, and long-term other receivables, credit risk is generally limited to the carrying value on the consolidated balance sheets. The Corporation's subsidiaries generally have a large and diversified customer base, which minimizes the concentration of credit risk. Policies in place to minimize credit risk include requiring customer deposits, prepayments and/or credit checks for certain customers, performing disconnections and/or using third-party collection agencies for overdue accounts. ITC has a concentration of credit risk as approximately 65% of its revenue is derived from three customers. The customers have investment-grade credit ratings and credit risk is further managed by MISO by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors. FortisAlberta has a concentration of credit risk as its distribution service billings are to a relatively small group of retailers. Credit risk is managed by obtaining from the retailers either a cash deposit, letter of credit, an investment-grade credit rating, or a financial guarantee from an entity with an investment-grade credit rating. Central Hudson has seen an increase in accounts receivable since the suspension of collection efforts initially required in response to the COVID-19 pandemic. Central Hudson continues to contact customers regarding past-due balances and collection efforts continue to expand. Under its regulatory framework, Central Hudson can defer uncollectible write-offs above the amounts collected in customer rates for future recovery. UNS Energy, Central Hudson, FortisBC Energy, and Fortis may be exposed to credit risk in the event of non-performance by counterparties to derivative contracts. Credit risk is managed by net settling payments, when possible, and dealing only with counterparties that have investment-grade credit ratings. At UNS Energy, Central Hudson and FortisBC Energy, certain contractual arrangements require counterparties to post collateral. The value of derivatives in net liability positions under contracts with credit risk-related contingent features that, if triggered, could require the posting of a like amount of collateral was $74 million as at September 30, 2025 (December 31, 2024 - $117 million). Hedge of Foreign Net Investments The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, Fortis Belize Limited and Belize Electricity is, or is pegged to, the U.S. dollar. The earnings and cash flow from, and net investments in, these entities are exposed to fluctuations in the U.S. dollar-to-Canadian dollar exchange rate. The Corporation has reduced this exposure through hedging. As at September 30, 2025, US$1.9 billion (December 31, 2024 - US$2.2 billion) of corporately issued U.S. dollar-denominated long-term debt has been designated as an effective hedge of net investments, leaving approximately US$13.1 billion (December 31, 2024 - US$12.6 billion) unhedged. Exchange rate fluctuations associated with the net investment in foreign subsidiaries and the debt serving as the hedge are recognized in accumulated other comprehensive income. Financial Instruments Not Carried at Fair Value Excluding long-term debt, the consolidated carrying value of the Corporation's remaining financial instruments approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature. As at September 30, 2025, the carrying value of long-term debt, including current portion, was $34.0 billion (December 31, 2024 - $33.4 billion) compared to an estimated fair value of $32.3 billion (December 31, 2024 - $31.3 billion). Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 18 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT
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15. COMMITMENTS AND CONTINGENCIES There were no material changes in commitments and contingencies from that disclosed in the Corporation's 2024 Annual Financial Statements, except as detailed below. UNS Electric entered into a US$233 million Engineering, Procurement, and Construction Agreement for the development of four gas engine turbines at the Black Mountain Generating Station, which are expected to be placed in service in 2028. TEP entered into an energy supply agreement to serve a customer expected to be located in TEP's service territory. The agreement, requiring potential power demand of approximately 300 MW, is subject to approval by the ACC and other contractual contingencies. The initial phase is expected to be operational as early as 2027, with a ramp schedule through 2029. TEP currently expects to serve this customer from its existing and planned capacity, including solar and battery storage projects currently in development. TEP and UNS Electric entered into long-term gas transportation precedent agreements to secure reliable access to natural gas. The agreements support the development of a new pipeline, expected to be in service in 2029, which will be owned and operated by a third-party. The purchase commitments, expected to begin in 2029, are estimated to total US$1.9 billion over the 25-year service period, and are conditional on the construction and commercial operation of the new pipeline. 16. SUBSEQUENT EVENT On October 31, 2025, Fortis sold its 100% ownership in Fortis Belize and its 33% ownership in Belize Electricity to the Government of Belize. A loss on sale of approximately $60 million is expected to be recorded in the fourth quarter of 2025, approximately half of which reflects income taxes. Notes to Condensed Consolidated Interim Financial Statements (Unaudited) For the three and nine months ended September 30, 2025 and 2024 19 FORTIS INC. SEPTEMBER 30, 2025 QUARTER REPORT