40-F - FTS - Equibles

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________

FORM 40-F

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

☒ ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

Commission file number: 001-37915

_______________________

FORTIS INC.

(Exact name of Registrant as specified in its charter)

Newfoundland and Labrador, Canada	4911	98-0352146
(Province or other jurisdiction of<br>incorporation or organization)	(Primary Standard Industrial Classification<br>Code Number)	(I.R.S. Employer Identification Number)

Fortis Place, Suite 1100

5 Springdale Street

St. John's, Newfoundland and Labrador

Canada A1E 0E4

(709) 737-2800

(Address and telephone number of Registrant's principal executive offices)

_______________________

CT Corporation System

28 Liberty Street

New York, New York 10015

(212) 894-8940

(Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Exchange Act:

Common Shares, without par value	FTS	New York Stock Exchange
(Title of each class)	(Trading Symbol(s))	(Name of exchange on which registered)

Securities registered or to be registered pursuant to Section 12(g) of the Exchange Act:

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Exchange Act:

None

(Title of Class)

For annual reports, indicate by check mark the information filed with this Form:

☒ Annual information form ☒ Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report.

507,340,068 Common Shares as of December 31, 2025

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).

Yes ☒ No ☐

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term "new or revised financial accounting standard" refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Exchange Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

EXPLANATORY NOTE

Fortis Inc. (the "Corporation" or "Fortis") is a Canadian issuer eligible to file its annual report pursuant to Section 13 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), on Form 40-F pursuant to the multi-jurisdictional disclosure system of the Exchange Act. The Corporation is a "foreign private issuer" as defined in Rule 405 under the Securities Act of 1933, as amended. Equity securities of the Corporation are accordingly exempt from Sections 14(a), 14(b), 14(c), 14(f) and 16 of the Exchange Act pursuant to Rule 3a12-3. However, the recent enactment of the Holding Foreign Insiders Accountable Act will require directors and officers of foreign private issuers to comply with the insider reporting rules under Section 16(a) of the Exchange Act. As a result, subject to any applicable exemptions, directors and officers of the Corporation will be required to file with the U.S. Securities and Exchange Commission (the "SEC") reports of their ownership of and trades in the Corporation's equity securities.

FORWARD LOOKING INFORMATION

The Corporation includes forward-looking information in this Annual Report on Form 40-F and the exhibits attached hereto (the "Form 40-F") 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 the Corporation's 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 expressions have been used to identify the forward-looking information, which includes, without limitation: forecast capital expenditures for 2026 through 2030; expected funding sources for the 2026-2030 capital plan, including sources of common equity; forecast midyear rate base for 2030 and forecast five-year rate base compound annual growth rate 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; expected nature, timing and benefits of additional opportunities to expand and extend growth beyond the capital plan, including 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 Midcontinent Independent System Operator ("MISO") long range transmission plan ("LRTP") as well as regional transmission in New York, grid resiliency and climate adaptation investments, investments in renewable gas and liquefied natural gas ("LNG") infrastructure in British Columbia, and energy infrastructure investments to support the acceleration of load growth; the expectation that the Corporation is positioned well for future investment opportunities; the potential for competition to the transmission business and/or challenges to existing right of first refusal statutes applicable to the transmission business to restrict future growth; the potential for changes to government energy policies to impact the competitiveness of natural gas relative to other energy sources; Tucson Electric Power's ("TEP") plans to convert Springerville Units 1 and 2 from coal-fired generation to natural gas fired generation by 2030; planned in-service dates and expected capacity of various renewable resources of TEP; expected approach to the determination of compensation owed to FortisAlberta Inc. ("FortisAlberta") under a termination of any municipal franchise agreement where a municipality exercises its option to purchase FortisAlberta distribution assets; the expectation that FortisAlberta will provide notices to extend franchise agreements to affected municipalities prior to expiration; expected output of FortisBC Inc.'s Kootenay River system plants in the event of the termination of the canal plant agreement; expected timing, outcome and impact of regulatory and legal proceedings and decisions; expected timing for the negotiation of the renewal of Maritime Electric Company, Limited's energy supply agreement with New Brunswick Power Corporation; the expectation that the Corporation and its utilities will be targeted by direct and/or third-party cybersecurity threats, cyber attacks, data breaches, cyber extortion and similar compromises; the expectation that no risks arising from any past or present cybersecurity threat are reasonably likely to materially affect the Corporation's business strategy, results of operations, or financial condition; the expectation that the Corporation will review its decarbonization strategy in 2026; the potential establishment of new interim emissions targets; expected filing of new integrated resource plans at TEP and UNS Electric, Inc. ("UNS Electric"); the expectation that the Corporation will have a coal-free generation mix in 2032; the Corporation's 2050 net-zero greenhouse gas emissions target; TEP's estimated mine reclamation costs; Central Hudson Gas & Electric Corporation's estimated remediation costs, including the potential for insurance reimbursement and partial cost recovery from rates, related to former manufactured gas plant facilities; annual dividend growth guidance through 2030; expected implications of industry trends on the utility sector and the Corporation's capital investments; the expectation that Fortis is well-positioned to support energy security, climate adaptation, and load growth across the Corporation's footprint; expected or potential funding sources for operating expenses, interest costs and capital expenditures; the expectation that maintaining the targeted capital structure of the regulated operating subsidiaries will not have an impact on the Corporation's ability to pay dividends in the foreseeable future; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will continue to have reasonable access to long-term capital and will remain compliant with debt covenants; expected uses of proceeds from debt financings; the potential requirement to accelerate equity capital contributions to Wataynikaneyap Power Limited Partnership; expectations related to UNS Energy Corporation's joint generation performance guarantees, potential obligations arising from participant defaults, and associated recovery mechanisms; expected nature, timing, benefits and costs associated with TEP's energy supply agreement with a customer to support a planned data center in TEP's service territory; expected in-service date for a new pipeline in UNS Energy's service territory and the expectation that TEP and UNS Electric will enter into gas transportation service agreements and estimated purchase commitments associated therewith; the potential impact of new or revised tariffs on forecasted capital expenditures; forecast midyear rate base for 2026 and 2030 by business segment; the nature, timing, benefits and costs of certain major capital projects, including ITC Investment Holding's ("ITC") transmission projects associated with the MISO LRTP and Big Cedar Load Expansion, the TEP Transmission Project, Springerville Natural Gas Conversion, Black Mountain Gas Generation, Vail-to-Tortolita Transmission Project, Roadrunner Reserve Battery Storage Project, Tilbury LNG Storage Expansion, AMI Project, Tilbury 1B Project, and the Eagle Mountain Pipeline Project; the nature, timing, benefits and costs of additional investment opportunities, including ITC's investments associated with the MISO LRTP tranche 2.1, TEP's investments associated with additional energy demands from new large retail customers, and FortisBC Energy's investments associated with the Tilbury LNG Storage Expansion project and Tilbury Marine Jetty project; the potential and expected impacts of new accounting policies and future accounting pronouncements on the Corporation's disclosures; the potential impact of the recognition of goodwill impairment losses; and the potential and expected impacts of income tax compliance examinations and legislation with respect to interest deductibility limitations and global minimum tax.

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 dividend reinvestment plan; the Corporation's board of directors (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.

Forward-looking information involves significant risks, uncertainties and assumptions. The Corporation 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. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. For additional information with respect to certain of these risks or factors, reference should be made to the information detailed under the heading "Business Risks" on page 21 of the Annual MD&A (as defined below), and to continuous disclosure materials filed from time to time by the Corporation with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission (the "SEC").

Key risk factors for 2026 include, but are not limited to:

•risks associated with changes in utility regulation, including the outcome of regulatory proceedings at the Corporation's utilities;

•physical risks related to the provision of electric and gas service, which can be exacerbated by the impacts of climate change;

•risks associated with capital projects and the impact on the Corporation's continued growth;

•risks associated with cybersecurity and information and operations technology, including disruption to electric and gas service, consumption and load settlement systems, and financial or general operations, as well as the risk of misappropriation and/or disclosure of confidential or proprietary information;

•risks related to environmental laws and regulations;

•the impact of weather variability and seasonality on heating and cooling loads and gas distribution volumes;

•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 in this Form 40-F is given as of the date of this Form 40-F and the Corporation disclaims any intention or obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

CURRENCY

The Corporation presents its consolidated financial statements in Canadian dollars unless otherwise specified. All dollar amounts in this Form 40-F are stated in Canadian dollars ("$" or "C$"), except where otherwise indicated. On February 11, 2026, the daily average exchange rate (as reported by the Bank of Canada) of United States dollars ("US$") into Canadian dollars was US$1.00 equals C$1.36.

CANADIAN ANNUAL DISCLOSURE DOCUMENTS

The following documents are filed as exhibits to this Form 40-F:

1.The Annual Information Form for the fiscal year ended December 31, 2025, which is filed as Exhibit 99.1 to this Form 40-F and incorporated by reference herein (the "AIF");

2.Audited Consolidated Financial Statements for the fiscal year ended December 31, 2025, which are filed as Exhibit 99.2 to this Form 40-F and incorporated by reference herein (the "Annual Financial Statements"); and

3.Management's Discussion and Analysis for the fiscal year ended December 31, 2025, which is filed as Exhibit 99.3 to this Form 40-F and incorporated by reference herein (the "Annual MD&A").

CERTIFICATIONS

See Exhibits 99.4, 99.5, 99.6 and 99.7 to this Form 40-F.

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and United States securities laws. As of December 31, 2025, an evaluation was carried out under the supervision of, and with the participation of, the Corporation's management, including the President and Chief Executive Officer and the Executive Vice President, Chief Financial Officer, of the effectiveness of the Corporation's disclosure controls and procedures, as defined in the applicable Canadian and United States securities laws. Based on that evaluation, the President and Chief Executive Officer and the Executive Vice President, Chief Financial Officer concluded that such disclosure controls and procedures are effective as of December 31, 2025.

MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is designed by, or under the supervision of, the Corporation's President and Chief Executive Officer and the Executive Vice President, Chief Financial Officer and effected by the Corporation's Board, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Corporation's management, including the Corporation's President and Chief Executive Officer and the Executive Vice President, Chief Financial Officer, assessed the effectiveness of the Corporation's internal control over financial reporting as of December 31, 2025, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that, as of December 31, 2025, the Corporation's internal control over financial reporting was effective.

Deloitte LLP, an independent registered public accounting firm, has audited the Annual Financial Statements, and has included its attestation report on management's assessment of the Corporation's internal control over financial reporting, which is found on page 2 of the Annual Financial Statements.

ATTESTATION REPORT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Deloitte LLP's attestation report on management's assessment of the Corporation's internal control over financial reporting is found on page 5 of the Annual Financial Statements.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Management regularly reviews its system of internal control over financial reporting and makes changes to the Corporation's processes and systems to improve controls and increase efficiency, while ensuring that the Corporation maintains an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.

During the year ended December 31, 2025, there have been no changes in the Corporation's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Corporation's internal control over financial reporting.

NOTICES PURSUANT TO REGULATION BTR

The Corporation did not send any notices required by Rule 104 of Regulation BTR during the year ended December 31, 2025 concerning any equity security subject to a blackout period under Rule 101 of Regulation BTR.

IDENTIFICATION OF THE AUDIT COMMITTEE

The Corporation has a separately designated standing Audit Committee established in accordance with section 3(a)(58)(A) of the Exchange Act. As of December 31, 2025, the Audit Committee is composed of Margarita K. Dilley (Chair), Tracey C. Ball, Lawrence T. Borgard, Maura J. Clark, Gregory E. Knight, Donald R. Marchand and Jo Mark Zurel as described under "Audit Committee - Members" on page 28 of the AIF.

AUDIT COMMITTEE FINANCIAL EXPERT

The Board has determined that the Corporation has at least one "audit committee financial expert" (as defined in paragraph (8) of General Instruction B to Form 40-F) and that Tracey C. Ball, Maura J. Clark, Margarita K. Dilley, Donald R. Marchand and Jo Mark Zurel are the Corporation's "audit committee financial experts" serving on the Audit Committee of the Board. Each of the audit committee financial experts is "independent" under applicable listing standards.

CODE OF ETHICS

The Corporation has a "code of ethics" (as defined in paragraph (9)(b) of General Instruction B to Form 40-F) that applies to all the Corporation's employees, officers and directors, including the Chief Executive Officer, Chief Financial Officer, principal accounting officer or controller, and persons performing similar functions. The Corporation's code of ethics (referred to as the "Code of Conduct") is available on the Corporation's website at https://www.fortisinc.com/ or, without charge, upon request from the Corporate Secretary, Fortis Inc., Fortis Place, Suite 1100, 5 Springdale Street, St. John's, Newfoundland and Labrador, Canada A1E 0E4 (telephone (709) 737-2800).

The Code of Conduct was amended during the fiscal year ended December 31, 2025 as follows:

•On January 1, 2025, the Code of Conduct was amended to reflect administrative changes.

•On December 4, 2025, the Code of Conduct was amended with effect from January 1, 2026 to reflect certain editorial, organizational and administrative changes. The amended Code of Conduct was furnished as an exhibit to a report on Form 6-K filed by the Corporation on January 13, 2026.

The amended Code of Conduct reflecting the revisions described above is filed as an exhibit to this Form 40-F. During the fiscal year ended December 31, 2025, there have not been any amendments to, or waivers of, including implicit waivers of, any provision of the Code of Conduct which is applicable to the Corporation's Chief Executive Officer, Chief Financial Officer, principal accounting officer or controller, or persons performing similar functions and that relates to any element of the code of ethics definition enumerated in paragraph (9)(b) of General Instruction B to Form 40-F.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Deloitte LLP served as the Corporation's independent public accountant for the fiscal years ended December 31, 2025 and 2024. For a description of the total amount billed to the Corporation by Deloitte LLP for services performed in the last two fiscal years by category of service (audit fees, audit-related fees, tax fees and all other fees), see "Audit Committee - External Auditor Service Fees" on page 29 of the AIF.

AUDIT COMMITTEE PRE‑APPROVAL POLICIES AND PROCEDURES

For a description of the pre-approval policies and procedures of the Corporation's Audit Committee, see "Audit Committee - Pre-Approval Policies and Procedures" on page 29 of the AIF.

No audit-related fees, tax fees or other non-audit fees were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S‑X.

OFF‑BALANCE SHEET ARRANGEMENTS

Except for letters of credit outstanding of $105 million as at December 31, 2025 and certain unrecorded commitments disclosed under the heading "Liquidity and Capital Resources - Contractual Obligations" on page 16 of the Annual MD&A, the Corporation has not entered into any "off-balance sheet arrangements", as defined in General Instruction B(11) to Form 40-F, that have or are reasonably likely to have a current or future effect on the Corporation's financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION

The Corporation has adopted a compensation recovery policy effective October 2, 2023 (referred to as the "Executive Compensation Clawback Policy") as required by NYSE listing standards and pursuant to Rule 10D-1 of the Exchange Act. The Executive Compensation Clawback Policy is filed as Exhibit 97 to this Form 40-F. At no time during or after the fiscal year ended December 31, 2025 (as of the date of this Annual Report), was the Corporation required to prepare an accounting restatement that required recovery of erroneously awarded compensation pursuant to the Executive Compensation Clawback Policy and, as of December 31, 2025, there was no outstanding balance of erroneously awarded compensation to be recovered from the application of the Executive Compensation Clawback Policy to a prior restatement.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

For tabular disclosure of the Corporation's contractual obligations, see page 16 of the Annual MD&A, under the heading "Liquidity and Capital Resources - Contractual Obligations".

COMPARISON OF NYSE CORPORATE GOVERNANCE RULES

The Corporation is subject to a variety of corporate governance guidelines and requirements enacted by the Toronto Stock Exchange (the "TSX"), the Canadian securities regulatory authorities, the New York Stock Exchange (the "NYSE") and the SEC. The Corporation is listed on the NYSE and, although the Corporation is not required to comply with most of the NYSE corporate governance requirements to which the Corporation would be subject if it were a U.S. corporation, the Corporation's governance practices differ from those required of U.S. domestic issuers only as described herein. The NYSE rules for U.S. domestic issuers require shareholder approval of all equity compensation plans (as defined in the NYSE rules) regardless of whether new issuances, treasury shares or shares that the Corporation has purchased in the open market are used. The TSX rules require shareholder approval of share compensation arrangements involving new issuances of shares, and of certain amendments to such arrangements, but do not require such approval if the compensation arrangements involve only shares purchased in the open market. The NYSE rules for U.S. domestic issuers also require shareholder approval of certain transactions or series of related transactions that result in the issuance of common shares, or securities convertible into or exercisable for common shares, that have, or will have upon issuance, voting power equal to or in excess of 20% of the voting power outstanding prior to the transaction or if the issuance of common shares, or securities convertible into or exercisable for common shares, are, or will be upon issuance, equal to or in excess of 20% of the number of common shares outstanding prior to the transaction. The TSX rules require shareholder approval of acquisition transactions resulting in dilution in excess of 25%. The TSX also has broad general discretion to require shareholder approval in connection with any issuances of listed securities. The Corporation complies with the TSX rules described in this paragraph.

UNDERTAKING

The Corporation undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the SEC staff, and to furnish promptly, when requested to do so by the SEC staff, information relating to: the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

DISCLOSURE PURSUANT TO SECTION 13(r) OF THE EXCHANGE ACT

In accordance with Section 13(r) of the Exchange Act, the Corporation is required to include certain disclosures in its periodic reports if it or any of its affiliates knowingly engaged in certain specified activities during the period covered by the report. Neither the Corporation nor its affiliates have knowingly engaged in any transaction or dealing reportable under Section 13(r) of the Exchange Act during the year ended December 31, 2025.

CONSENT TO SERVICE OF PROCESS

Any change to the name or address of the Corporation's agent for service shall be communicated promptly to the SEC by amendment to the Form F-X referencing the file number of the Corporation.

INCORPORATION BY REFERENCE

The Corporation's Annual Report on Form 40-F (other than the section entitled "Credit Ratings" in Exhibit 99.1 to this Form 40-F) is incorporated by reference into the Corporation's Registration Statements on Form S-8 (File No. 333-264838), Form S-8 (File No. 333-276111), Form S-8 (File No. 333-276112), Form S-8 (File No. 333-281205), Form S-8 (File No. 333-226663), Form S-8 (File No. 333-236213), Form F-3 (File No. 333-279253), and Form F-10 (File No. 333-283687).

EXHIBIT INDEX

Exhibit	Description
97	Executive Compensation Clawback Policy effective October 2, 2023
99.1	Annual Information Form of the Corporation dated February 1 1 , 202 6
99.2	Audited Consolidated Financial Statements for the fiscal year ended December 31, 202 5
99.3	Management's Discussion and Analysis for the fiscal year ended December 31, 202 5
99.4	Chief Executive Officer certification required by Rule 13a-14(a)
99.5	Chief Financial Officer certification required by Rule 13a-14(a)
99.6	Chief Executive Officer certification required by Rule 13a-14(b)
99.7	Chief Financial Officer certification required by Rule 13a-14(b)
99.8	Consent of Deloitte LLP
99.9	Code of Conduct dated January 1, 2026
101.INS	XBRL Instance
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Corporation certifies that it meets all of the requirements for filing on Form 40‑F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.

FORTIS INC.
/s/ Jocelyn H. Perry
Jocelyn H. Perry<br>Executive Vice President, Chief Financial Officer
Date: February 12, 2026

Document

Exhibit 97

Fortis Inc.

Executive Compensation Clawback Policy

I. INTRODUCTION

The board of directors (the "Board") of Fortis Inc. ("Fortis" or the "Corporation") believes that it is in the best interests of the Corporation to adopt this executive compensation clawback policy (the "Policy"). The Policy is divided into two parts and is intended to comply with (i) Section 304 of the United States Sarbanes-Oxley Act of 2002 (see Part II below) and (ii) Section 10D of the United States Securities Exchange Act of 1934, as amended (the "Exchange Act"), Rule 10D-1 promulgated under the Exchange Act ("Rule 10D-1") and Section 303A.14 of the New York Stock Exchange Listed Corporation Manual (the "NYSE Listing Standards") (see Part III below).

1. Authority

Except as specifically set forth herein, the Policy shall be administered by the Board or, if so designated by the Board, a committee of the Board (the Board or such committee designated by the Board to administer the Policy, the "Administrator"). The Administrator is authorized to interpret and construe the Policy and to make all determinations necessary, appropriate or advisable for the administration of the Policy. Any determinations made by the Administrator shall be final and binding on all affected individuals.

In the administration of the Policy, the Administrator is authorized and directed to consult with the full Board or such other committees of the Board, as may be necessary or appropriate as to matters within the scope of such other committee's responsibility and authority. Subject to any limitation at applicable law, the Administrator may authorize and empower any officer or employee of the Corporation to take any and all actions necessary or appropriate to carry out the purpose and intent of the Policy (other than with respect to any recovery under the Policy involving such officer or employee).

2. Indemnification

Any members of the Administrator, and any other members of the Board who assist in the administration of the Policy, shall not be personally liable for any action, determination or interpretation made in good faith with respect to the Policy and such persons shall be indemnified by the Corporation with respect to any such action, determination or interpretation to the fullest extent permitted under applicable law and the policies of the Corporation in effect from time to time. The foregoing sentence shall not limit any other rights to indemnification of the members of the Board under applicable law or the policies of the Corporation in effect from time to time.

3. Amendment; Termination

The Board may amend, modify, supplement, rescind or replace all or any portion of the Policy at any time and from time to time in its discretion, and shall amend the Policy as it deems necessary to comply with applicable law or any rules or standards adopted by a securities exchange on which the Corporation's securities are listed.

4. Severability

If any provision of the Policy or its application shall be adjudicated to be invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provisions of the Policy, and the invalid, illegal or unenforceable provisions shall be deemed amended to the minimum extent necessary to render any such provision or application enforceable.

5. Other Recoupment Rights

The Board intends that the Policy shall be applied to the fullest extent permitted by law. Any right of recoupment under the Policy is in addition to, and not in lieu of, any other remedies or rights of recoupment that may be available to the Corporation under applicable law, rules or regulations with respect to the claw back or recoupment of erroneously awarded compensation or pursuant to the terms of any employment agreement, equity award agreement, or similar agreement. To the extent that Fortis, the Board, or any committee of the Board is required to comply with any such laws, rules or regulations, the Policy shall be read to incorporate such requirements to the extent applicable.

6. Other Claims

Nothing contained in the Policy, and no recoupment or recovery as contemplated by the Policy, shall limit any claims, damages or other legal remedies the Corporation or any of its affiliates may have against any person arising out of or resulting from any actions or omissions by such person.

7. Absence of Conflicts

Subject to Section 5b) of Part III of the Policy, the application of the Policy by the Administrator may result in recoupment of compensation pursuant to Part II or Part III of the Policy or both Part II and Part III of the Policy, as determined to be necessary, appropriate and advisable.

8. Successors

The Policy shall be binding and enforceable against all persons subject thereto and their beneficiaries, heirs, executors, administrators or other legal representatives.

9. Disclosure Requirements

The Corporation shall file all disclosures with respect to the Policy required by applicable laws and regulations, including applicable rules of the United States Securities and Exchange Commission ("SEC").

II. [Intentionally Omitted]

III. DODD-FRANK CLAWBACK

Part III of the Policy is intended to comply with, and shall be interpreted to be consistent with, Section 10D of the Exchange Act, Rule 10D-1 and Section 303A.14 of the NYSE Listing Standards.

1. Definitions

As used in this Part III of the Policy, the following terms shall have the meanings ascribed to them below:

"Accounting Restatement" means an accounting restatement due to the material noncompliance of Fortis with any financial reporting requirement under securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements (a “Big R” restatement), or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period (a “little r” restatement).

"Applicable Period" means the three completed fiscal years immediately preceding the date on which Fortis is required to prepare an Accounting Restatement, as well as any transition period (that results from a change in the Corporation's fiscal year) within or immediately following those three completed fiscal years (except that a transition period that comprises a period of at least nine months shall count as a completed fiscal year).

The "date on which the Corporation is required to prepare an Accounting Restatement" is the earlier to occur of (a) the date the Board, a committee of the Board (e.g., the Audit Committee), or the officer or officers of the Corporation authorized to take such action (if Board action is not required) concludes, or reasonably should have concluded, that the Corporation is required to prepare an Accounting Restatement or (b) the date a court, regulator or other legally authorized body directs the Corporation to prepare an Accounting Restatement, in each case regardless of if or when the restated financial statements are filed.

"Erroneously Awarded Compensation" has the meaning set forth in Section 4 of this Part III of the Policy.

"Executives" means the Corporation's current and former president, principal financial officer, principal accounting officer (or, if there is no such accounting officer, the controller), any vice-president of the Corporation in charge of a principal business unit, division or function (such as sales, administration or finance), any other executive who performs a policy-making function, or any other person who performs similar policy-making functions for the Corporation, as determined by the Administrator in accordance with the definition of executive officer set forth in Rule 10D-1 and the NYSE Listing Standards.

"Financial Reporting Measure" means measures that are determined and presented in accordance with the accounting principles used by Fortis in preparing its financial statements, and all other measures that are derived wholly or in part from such measures. Share price and total shareholder return (and any measures that are derived wholly or in part from share price or total shareholder return) shall, for purposes of this Part III of the Policy, be considered Financial Reporting Measures. For the avoidance of doubt, a Financial Reporting Measure need not be presented within Fortis financial statements or included in a filing with any securities regulatory authority, including the SEC.

"Incentive-Based Compensation" means any compensation that is granted, earned or vested based wholly or in part upon the attainment of a Financial Reporting Measure.

Incentive-Based Compensation is "received", for purposes of this Part III of the Policy, in the Corporation's fiscal period during which the Financial Reporting Measure specified in the Incentive-Based Compensation award is attained, even if the payment or grant of such Incentive-Based Compensation occurs after the end of that period.

2. Covered Executives; Incentive-Based Compensation

Part III of the Policy applies to Incentive-Based Compensation received by an Executive (i) after beginning services as an Executive; (ii) if the Executive served as an Executive at any time during the performance period for such Incentive-Based Compensation; and (iii) while the Corporation has (or had) a class of securities listed on the New York Stock Exchange (“NYSE”) or any other U.S. national securities exchange.

3. Recoupment of Erroneously Awarded Compensation in the Event of an Accounting Restatement

If the Corporation is required to prepare an Accounting Restatement, the Corporation shall promptly recoup the amount of any Erroneously Awarded Compensation received by any Executive during the Applicable Period as calculated pursuant to Section 4 of this Part III of the Policy.

4. Erroneously Awarded Compensation: Amount Subject to Recovery

The amount of "Erroneously Awarded Compensation" subject to recovery under this Part III of the Policy, as determined by the Administrator, is the amount of Incentive-Based Compensation received by the Executive that exceeds the amount of Incentive-Based Compensation that would have been received by the Executive had the Incentive-Based Compensation been determined based on the restated financial statements.

Erroneously Awarded Compensation shall be computed by the Administrator without regard to any taxes paid by the Executive in respect of the Erroneously Awarded Compensation.

For Incentive-Based Compensation based on share price or total shareholder return, where the amount of Erroneously Awarded Compensation is not subject to mathematical recalculation directly from the information in the applicable accounting restatement:

a) the Administrator shall determine the amount of Erroneously Awarded Compensation based on a reasonable estimate of the effect of the Accounting Restatement on the share price or total shareholder return upon which the Incentive-Based Compensation was received; and

b) Fortis shall maintain documentation of the determination of that reasonable estimate and provide such documentation to the NYSE.

5. Method of Recoupment

a) The Administrator shall have discretion to determine the appropriate means of recouping Erroneously Awarded Compensation based on the particular facts and circumstances. Notwithstanding the foregoing, except as set forth in Section 6 of this Part III of the Policy, in no event may Fortis accept an amount that is less than the amount of Erroneously Awarded Compensation in satisfaction of an Executive's obligations hereunder.

b) To the extent that the Executive reimburses Fortis for any Incentive-Based Compensation received that constitutes Erroneously Awarded Compensation under any duplicative recovery obligation established by the Corporation in the Policy or otherwise, or pursuant to applicable law, any such reimbursed amount may be credited to the amount of Erroneously Awarded Compensation that is subject to recovery under this Part III of the Policy.

c) To the extent that an Executive fails to repay all Erroneously Awarded Compensation to Fortis when due, the Corporation shall take all actions reasonable and appropriate to recover such Erroneously Awarded Compensation from the applicable Executive. The applicable Executive shall be required to reimburse the Corporation for any and all expenses reasonably incurred (including legal fees) by the Corporation in recovering such Erroneously Awarded Compensation in accordance with the immediately preceding sentence.

6. Exceptions to Recovery

Fortis will recover Erroneously Awarded Compensation in compliance with this Part III of the Policy unless any of the following conditions are met and the Administrator determines that recovery would be impracticable:

a) The direct expense paid to a third party to assist in enforcing this Part III of the Policy would exceed the amount to be recovered. Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation based on the expense of enforcement, the Corporation must make a reasonable attempt to recover such Erroneously Awarded Compensation, document such reasonable attempt(s) to recover, and provide that documentation to the NYSE.

b) Recovery would violate applicable Canadian federal or provincial law (provided that law was adopted prior to November 28, 2022). Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation based on violation of Canadian federal or provincial law, the Corporation shall obtain an opinion of Canadian counsel, acceptable to the NYSE, that recovery would result in such a violation, and must provide such opinion to the NYSE.

c) Recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Corporation, to fail to meet the requirements of Section 401(a)(13) or 411(a) of the United States Internal Revenue Code and the regulations thereunder.

7. No indemnification of Executives

Fortis shall not insure or indemnify any Executive against (i) the loss of any Erroneously Awarded Compensation that is repaid, returned or recovered pursuant to the terms of this Part III of the Policy, or (ii) any claims relating to the Corporation's enforcement of its rights under this Part III of the Policy. Fortis shall not enter into any agreement that exempts any Incentive-Based Compensation that is granted, paid or awarded to an Executive from the application of this Part III of the Policy or that waives the Corporation's right to recovery of any Erroneously Awarded Compensation, and this Part III of the Policy shall supersede any such agreement (whether entered into before, on or after the Effective Date of this Part III of the Policy).

8. Part III Effective Date; Retroactive Application

Part III of the Policy shall be effective as of October 2, 2023 (the "Part III Effective Date"). The terms of Part III of the Policy shall apply to any Incentive-Based Compensation that is received by Executives on or after the Part III Effective Date, even if such Incentive-Based Compensation was approved, awarded, granted or paid to Executives prior to the Part III Effective Date. Without limiting the generality of Section 5 of this Part III of the Policy, and subject to applicable law, the Administrator may affect recovery under this Part III of the Policy from any amount of compensation approved, awarded, granted, payable or paid to the Executive prior to, on or after the Part III Effective Date.

[TO BE SIGNED BY FORTIS EXECUTIVES:]

Acknowledgment of the Fortis Inc. Executive Compensation Clawback Policy

I, the undersigned, agree and acknowledge that I have read, and that I am fully bound by, and subject to, all of the terms and conditions of the Fortis Inc. Executive Compensation Clawback Policy (as such policy may be amended, restated, supplemented or otherwise modified from time to time, the "Policy"). Any capitalized terms used in this Acknowledgment without definition shall have the meaning set forth in the Policy.

If there is any inconsistency between the Policy and the terms of any employment agreement to which I am a party, or the terms of any compensation plan, program or agreement under which any compensation has been granted, awarded, earned or paid, the terms of the Policy shall govern. If it is determined by the Administrator that any amounts granted, awarded, earned or paid to me must be forfeited or reimbursed to the Corporation, I will promptly take any action necessary to effectuate such forfeiture and/or reimbursement.

By: ______________________________

[Name]

[Title]

Date: ______________________________

Document

Exhibit 99.1

Annual Information Form
Table of Contents
---	---	---	---	---	---
Forward-Looking Information	2		Governance and Oversight		19
Glossary	3		Risk Management and Strategy		21
Corporate Structure	5		Social and Environmental Policies		21
Name and Incorporation	5		Ethical Conduct		21
Inter-Corporate Relationships	5		Safety and Reliability		21
General Development of the Business	5		Climate Change and Environmental Matters		22
Overview	5		Environmental Regulation and Contingencies		22
Three-Year History	6		Capital Structure and Dividends		22
Outlook	7		Description of Capital Structure		22
Description of the Business	7		Dividends and Distributions		23
Regulated Utilities	8		Debt Covenant Restrictions on Dividend Distributions		23
ITC	8		Credit Ratings		23
UNS Energy	10		Directors and Officers		26
Central Hudson	12		Audit Committee		28
FortisBC Energy	13		Members		28
FortisAlberta	14	Education and Experience		28
FortisBC Electric	15		Pre-Approval Policies and Procedures		29
Other Electric	16		External Auditor Service Fees		29
Non-Regulated	18		Transfer Agent and Registrar		29
Corporate and Other	18		Interests of Experts		29
Human Resources	18		Additional Information		30
Legal Proceedings and Regulatory Actions	19		Exhibit A: Summary of Terms and Conditions of Authorized Securities		31
Interest of Management and Others in Material Transactions	19		Exhibit B: Market for Securities		33
Risk Factors	19		Exhibit C: Audit Committee Mandate		35
Cybersecurity	19		Exhibit D: Material Contracts		42

Dated February 11, 2026

Financial information in this AIF has been prepared in accordance with U.S. GAAP and is presented in Canadian dollars ($) based, as applicable, on the following U.S. dollar-to-Canadian dollar exchange rates: (i) average of 1.40 and 1.37 for the years ended December 31, 2025 and 2024, respectively; (ii) 1.37 and 1.44 as at December 31, 2025 and 2024, respectively; and (iii) 1.35 for all forecast periods.

Except as otherwise expressly noted, the information in this AIF is given as of December 31, 2025.

FORTIS INC.	December 31, 2025	1
Annual Information Form
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FORWARD-LOOKING INFORMATION

Fortis includes forward-looking information in this AIF 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: forecast Capital Expenditures for 2026 through 2030; expected funding sources for the Capital Plan, including sources of common equity; forecast midyear rate base for 2030 and forecast five-year rate base CAGR 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; expected nature, timing and benefits of additional opportunities to expand and extend growth beyond the Capital Plan, including 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 energy infrastructure investments to support the acceleration of load growth; the expectation that the Corporation is positioned well for future investment opportunities; the potential for competition to the transmission business and/or challenges to existing right of first refusal statutes applicable to the transmission business to restrict future growth; the potential for changes to government energy policies to impact the competitiveness of natural gas relative to other energy sources; TEP's plans to convert Springerville Units 1 and 2 from coal-fired generation to natural gas fired generation by 2030; planned in-service dates and expected capacity of various renewable resources of TEP; expected approach to the determination of compensation owed to FortisAlberta under a termination of any municipal franchise agreement where a municipality exercises its option to purchase FortisAlberta distribution assets; the expectation that FortisAlberta will provide notices to extend franchise agreements to affected municipalities prior to expiration; expected output of FortisBC Electric's Kootenay River system plants in the event of the termination of the CPA; expected timing, outcome and impact of regulatory and legal proceedings and decisions; expected timing for the negotiation of the renewal of Maritime Electric's energy supply agreement with NB Power; the expectation that the Corporation and its utilities will be targeted by direct and/or third-party cybersecurity threats, cyber attacks, data breaches, cyber extortion and similar compromises; the expectation that no risks arising from any past or present cybersecurity threat are reasonably likely to materially affect the Corporation's business strategy, results of operations, or financial condition; the expectation that the Corporation will review its decarbonization strategy in 2026; the potential establishment of new interim emissions targets; expected filings of new IRPs at TEP and UNS Electric; the expectation that the Corporation will have a coal-free generation mix in 2032; the Corporation's 2050 net-zero GHG emissions target; TEP's estimated mine reclamation costs; and Central Hudson's estimated remediation costs, including the potential for insurance reimbursement and partial cost recovery from rates, related to former manufactured gas plant facilities.

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; no material capital project or financing cost overrun; sufficient human resources to deliver service and execute the Capital Plan; the realization of additional opportunities to expand and extend growth 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 business performance and financial condition of the Corporation; no significant operational disruptions or environmental liability or upset; reasonable outcomes for legal and regulatory proceedings and the expectation of regulatory stability; 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.

All forward-looking information in this AIF is given as of the date of this AIF. 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.

FORTIS INC.	December 31, 2025	2
Annual Information Form
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GLOSSARY

Certain terms used in this 2025 Annual Information Form are defined below:

2025 Annual Information Form or AIF: this annual information form of the Corporation in respect of the year ended December 31, 2025

AECO/NIT: Alberta Energy Company/Nova Inventory Transfer

AFUDC: allowance for funds used during construction

Algoma Power: Algoma Power Inc.

APS: Arizona Public Service Company

ATM Program: the Corporation's $500 million at-the-market equity program

AUC: Alberta Utilities Commission

BC Hydro: BC Hydro and Power Authority

BCUC: British Columbia Utilities Commission

Belize Electricity: Belize Electricity Limited

Board: Board of Directors of the Corporation

CAGR: compound annual growth rate. Calculated on a constant U.S. dollar-to-Canadian dollar exchange rate

Canadian Niagara Power: Canadian Niagara Power Inc.

Capital Expenditures: cash outlay for additions to property, plant and equipment and intangible assets, 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 the "Non-U.S. GAAP Financial Measures" section of the MD&A

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.

Central Hudson: Central Hudson Gas & Electric Corporation

CMS: Consumers Energy Company

Columbia Pipeline: Columbia Pipeline Group Inc.

Common Equity Earnings: net earnings attributable to common equity shareholders

Cornwall Electric: Cornwall Street Railway, Light and Power Company, Limited

Corporation: Fortis Inc.

CIACs: contributions in aid of construction

CPA: Canal Plant Agreement

CRMP: cybersecurity risk management program

CUPE: Canadian Union of Public Employees

Director: director on the Board

DRIP: dividend reinvestment plan

DTE: DTE Electric Company

EDGAR: SEC's system for Electronic Data Gathering, Analysis and Retrieval available at www.sec.gov

Eiffel Investment: Eiffel Investment Pte Ltd.

EPS: earnings per common share

FERC: Federal Energy Regulatory Commission

FFO: funds from operations

FHI: FortisBC Holdings Inc.

Financial Statements: the Corporation's Audited Consolidated Financial Statements in respect of the year ended December 31, 2025

Fitch: Fitch Ratings Inc.

Fortis: Fortis Inc.

FortisAlberta: FortisAlberta Inc.

FortisBC Electric: collectively, the operations of FortisBC Inc. and its parent company, FortisBC Pacific Holdings Inc.

FortisBC Energy: FortisBC Energy Inc.

FortisCanada: FortisCanada Inc.

FortisOntario: FortisOntario Inc.

FortisTCI: FortisTCI Limited

FortisUS: FortisUS Inc.

FortisUS Holdings: FortisUS Holdings Nova Scotia Limited

Fortis Belize: Fortis Belize Limited

GHG: greenhouse gas

GIC: GIC Private Limited

IBEW: International Brotherhood of Electrical Workers

FORTIS INC.	December 31, 2025	3
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IESO: Independent Electricity System Operator of Ontario

IPL: Interstate Power and Light Company

IRP: integrated resource plan

IT: information technology

ITC: ITC Holdings together with all of its subsidiaries

ITC Great Plains: ITC Great Plains, LLC

ITC Holdings: ITC Holdings Corp.

ITC Investment Holdings: ITC Investment Holdings Inc.

ITC Midwest: ITC Midwest LLC

ITC's MISO Regulated Operating Subsidiaries: collectively METC, ITCTransmission, and ITC Midwest

ITC's Regulated Operating Subsidiaries: collectively, METC, ITC Midwest, ITCTransmission, and ITC Great Plains

ITCTransmission: International Transmission Company

LNG: liquefied natural gas

LRTP: long-range transmission plan

OT: operations technology

Maritime Electric: Maritime Electric Company, Limited

Major Capital Projects: projects, other than ongoing maintenance projects, individually costing $200 million or more in the forecast/planning period

MD&A: the Corporation's Management Discussion and Analysis in respect of the year ended December 31, 2025

METC: Michigan Electric Transmission Company, LLC

MISO: Midcontinent Independent System Operator, Inc.

Moody's: Moody's Investors Service, Inc.

Morningstar DBRS: DBRS Limited

MoveUP: Movement of United Professionals

NB Power: New Brunswick Power Corporation

NERC: North American Electric Reliability Corporation

Newfoundland Power: Newfoundland Power Inc.

NL Hydro: Newfoundland and Labrador Hydro Corporation

NYSE: New York Stock Exchange

PEI: Prince Edward Island, Canada

PNM: Public Service Company of New Mexico

PPA: power purchase agreement

PUB: Newfoundland and Labrador Board of Commissioners of Public Utilities

PWU: Power Workers' Union

RNG: renewable natural gas

RTO: regional transmission organization

S&P: Standard & Poor's Financial Services LLC

SEC: United States Securities and Exchange Commission

SEDAR+: the System for Electronic Document Analysis and Retrieval + of the Canadian Securities Administrators available at www.sedarplus.ca

SPP: Southwest Power Pool, Inc.

SRP: Salt River Project Agricultural Improvement and Power District

T&D: transmission and distribution

TC Energy: TC Energy Corporation

TEP: Tucson Electric Power Company

TSX: Toronto Stock Exchange

UNS Electric and UNSE: UNS Electric, Inc.

UNS Energy: UNS Energy Corporation

UNS Gas: UNS Gas, Inc.

U.S.: United States of America

U.S. GAAP: accounting principles generally accepted in the U.S.

UUWA: United Utility Workers' Association of Canada

Waneta Expansion: Waneta Expansion hydroelectric generating facility

Wataynikaneyap Power: Wataynikaneyap Power Limited Partnership

Measurements: Conversions:

GW Gigawatt(s) 1 litre = 0.22 imperial gallons

GWh Gigawatt hour(s) 1 kilometer = 0.62 miles

km Kilometer(s)

MW Megawatt(s)

TJ Terajoule(s)

PJ Petajoule(s)

Conversion using the above factors on rounded numbers appearing in this AIF may produce small differences from reported amounts as a result.

FORTIS INC.	December 31, 2025	4
Annual Information Form
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CORPORATE STRUCTURE

Name and Incorporation

Fortis Inc. is a holding company that was incorporated as 81800 Canada Ltd. under the Canada Business Corporations Act on June 28, 1977 and continued under the Corporations Act (Newfoundland and Labrador) on August 28, 1987. The corporate head office and registered office of Fortis is located at Fortis Place, Suite 1100, 5 Springdale Street, P.O. Box 8837, St. John's, Newfoundland and Labrador, Canada, A1B 3T2.

The articles of continuance of the Corporation were amended to: (i) change its name to Fortis on October 13, 1987; (ii) set out the rights, privileges, restrictions and conditions attached to the common shares on October 15, 1987; (iii) designate 2,000,000 First Preference Shares, Series A on September 11, 1990; (iv) replace the class rights, privileges, restrictions and conditions attaching to the First Preference Shares and the Second Preference Shares on July 22, 1991; (v) designate 2,000,000 First Preference Shares, Series B on December 13, 1995; (vi) designate 5,000,000 First Preference Shares, Series C on May 27, 2003; (vii) designate 8,000,000 First Preference Shares, Series D and First Preference Shares, Series E on January 23, 2004; (viii) amend the redemption provisions attaching to the First Preference Shares, Series D on July 15, 2005; (ix) designate 5,000,000 First Preference Shares, Series F on September 22, 2006; (x) designate 9,200,000 First Preference Shares, Series G on May 20, 2008; (xi) designate 10,000,000 First Preference Shares, Series H and 10,000,000 First Preference Shares, Series I on January 20, 2010; (xii) designate 8,000,000 First Preference Shares, Series J on November 8, 2012; (xiii) designate 12,000,000 First Preference Shares, Series K and 12,000,000 First Preference Shares, Series L on July 11, 2013; and (xiv) designate 24,000,000 First Preference Shares, Series M and 24,000,000 First Preference Shares, Series N on September 16, 2014.

Inter-Corporate Relationships

The following table lists the principal subsidiaries of the Corporation, their jurisdictions of incorporation and the percentage of votes attaching to voting securities held directly or indirectly by the Corporation. The principal subsidiaries together comprise approximately 92% of the Corporation's consolidated assets as at December 31, 2025 and approximately 87% of the Corporation's 2025 consolidated revenue. This table excludes certain subsidiaries, the assets and revenues of which do not individually exceed 10%, or in the aggregate exceed 20%, of the total consolidated assets or total consolidated revenue of the Corporation.

Subsidiary	Jurisdiction of Incorporation	Votes attaching to voting securities beneficially owned, controlled or directed by the Corporation (%)
ITC (1)	Michigan, United States	80.1
UNS Energy (2)	Arizona, United States	100
Central Hudson (3)	New York, United States	100
FortisBC Energy (4)	British Columbia, Canada	100
FortisAlberta (5)	Alberta, Canada	100
Newfoundland Power (6)	Newfoundland and Labrador, Canada	100

(1)ITC Holdings, a Michigan corporation, owns all of the shares of ITC Great Plains, ITC Midwest, ITCTransmission and METC. ITC Investment Holdings, a Michigan corporation, owns all of the shares of ITC Holdings. FortisUS, a Delaware corporation, holds an 80.1% interest in ITC Investment Holdings. FortisUS Holdings, a Canadian corporation, owns all of the shares of FortisUS. Fortis owns all of the shares of FortisUS Holdings. 19.9% of the securities of ITC Investment Holdings are owned by an affiliate of GIC, but are held as a passive investment, retaining only those rights necessary to protect its passive minority investment.

(2)UNS Energy, an Arizona corporation, owns all of the shares of TEP, UNS Electric and UNS Gas. FortisUS owns all of the shares of UNS Energy.

(3)CH Energy Group, Inc., a New York corporation, owns all of the shares of Central Hudson. FortisUS owns all of the shares of CH Energy Group, Inc.

(4)FHI, a British Columbia corporation, owns all of the shares of FortisBC Energy. Fortis owns all of the shares of FHI.

(5)FortisAlberta Holdings Inc., an Alberta corporation, owns all of the shares of FortisAlberta. FortisCanada, a Canadian corporation, owns all of the shares of FortisAlberta Holdings Inc. Fortis owns all of the shares of FortisCanada.

(6)Fortis owns all the shares of Newfoundland Power.

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Fortis is a diversified leader in the North American regulated electric and gas utility industry, with 2025 revenue of $12 billion and total assets of $75 billion as at December 31, 2025.

Regulated utilities account for virtually all of the Corporation's assets. The Corporation's 9,900 employees serve 3.5 million utility customers in five Canadian provinces, ten U.S. states and the Caribbean. As at December 31, 2025, 67% of the Corporation's assets are located outside Canada and 62% of 2025 revenue was derived from foreign operations.

FORTIS INC.	December 31, 2025	5
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Three-Year History

Over the past three years, Fortis has continued to experience significant growth. Total assets have increased from $64.3 billion at the start of 2023 to $74.8 billion as at December 31, 2025. Consolidated Capital Expenditures totalled $15.2 billion from 2023 through 2025, resulting in a three-year midyear rate base CAGR of 6%. The Corporation's shareholders' equity has also grown from $21.0 billion at the start of 2023 to $23.8 billion as at December 31, 2025. Common Equity Earnings for 2023 totalled $1,506 million compared to $1,714 million in 2025. The growth in earnings over the three-year period reflects the Corporation's regulated growth strategy, and is also impacted by the higher average U.S. dollar-to-Canadian dollar exchange rate in 2025 of 1.40 compared to 1.35 in 2023.

An overview of the Corporation's performance for the past three years follows:

2023

The Corporation delivered safe and reliable service in 2023. In September 2023, Fortis released its 2024-2028 capital plan of $25 billion, reflecting incremental capital investment of $2.7 billion over the previous five-year plan. The increase was driven by organic growth, largely reflecting regional transmission projects at ITC associated with tranche one of the MISO LRTP, as well as additional investments in Arizona to support TEP's exit from coal. Investments supporting system adaptation and resiliency, customer growth and economic development also contributed to capital growth across the Corporation's utilities.

2024

The Corporation safely and reliably delivered electricity and gas service. In September 2024, Fortis released its 2025-2029 capital plan of $26.0 billion, representing 6.5% rate base growth and reflecting incremental capital investment of $1.0 billion over the previous five-year plan. The increase was driven by projects associated with the MISO LRTP and resiliency investments at ITC, as well as distribution investments largely due to customer growth at FortisAlberta.

2025

The Corporation continued to safely and reliably deliver electricity and gas service to its customers. In November 2025, Fortis released its 2026-2030 Capital Plan of $28.8 billion, representing 7.0% five-year rate base growth and reflecting incremental capital investment of $2.8 billion over 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 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.

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.

The Corporation reported Common Equity Earnings of $1.7 billion in 2025, or $3.40 per common share, compared to $1.6 billion, or $3.24 per common share in 2024. Earnings growth in 2025 was impacted by $63 million of losses associated with the dispositions of FortisTCI, Fortis Belize and Belize Electricity, approximately half of which related to income taxes. In addition, results for 2024 were unfavourably impacted by $20 million associated with the retroactive impact of a reduction in the MISO base ROE at ITC as approved by FERC.

Excluding the above-noted items, Common Equity Earnings increased by $151 million, or $0.25 per common share, compared to 2024. The increase was primarily due to Rate Base growth across the utilities, including AFUDC associated with Major Capital Projects. Growth in earnings was also due to the rebasing of costs effective July 1, 2024 at Central Hudson, unrealized gains on derivative contracts, and the favourable impact of changes in the U.S. dollar-to-Canadian dollar exchange rate. The increase was partially offset by: (i) higher costs associated with Rate Base growth not yet reflected in customer rates, lower retail electricity sales due to milder weather, and lower margins on wholesale electricity sales at UNS Energy; (ii) the expiration of a regulatory incentive at FortisAlberta; and (iii) higher stock-based compensation and holding company finance costs. Lower earnings from FortisTCI and Fortis Belize, net of finance cost savings associated with the proceeds received on the dispositions, also unfavourably impacted results. The change in EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

Capital Expenditures in 2025 were $5.6 billion, consistent with expectations and $0.4 billion higher than 2024. The increase compared to 2024 was largely related to: (i) investments in Major Capital Projects, including projects within the first tranche of the MISO LRTP and the Big Cedar Load Expansion project at ITC, as well as the Vail-to-Tortolita and Black Mountain Gas Generation projects at UNS Energy; (ii) incremental transmission and distribution investments across the Corporation's utilities; and (iii) the impact of the higher U.S. dollar-to-Canadian dollar exchange rate. The increase was partially offset by FortisBC Energy's investment in the Eagle Mountain Pipeline project in 2024. Construction of the project in 2025 was largely funded by CIACs rather than investments by FortisBC Energy.

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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 $42.4 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.

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 energy infrastructure investments to support the acceleration of load growth across our jurisdictions.

DESCRIPTION OF THE BUSINESS

Fortis is principally an energy delivery company, with approximately 95% of its assets related to transmission and distribution. The business is characterized by low-risk, stable and predictable earnings and cash flows.

The Corporation's regulated utility businesses are: ITC (electric transmission - Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin); UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas distribution - New York State); FortisBC Energy (natural gas transmission and distribution - British Columbia); FortisAlberta (electric distribution - Alberta); FortisBC Electric (integrated electric - British Columbia); Newfoundland Power (integrated electric - Newfoundland and Labrador); Maritime Electric (integrated electric - Prince Edward Island); FortisOntario (integrated electric - Ontario); and Caribbean Utilities (integrated electric - Grand Cayman). The Corporation also owns a 39% equity investment in Wataynikaneyap Power (electric transmission - Ontario). Fortis sold FortisTCI (integrated electric - Turks and Caicos Islands) on September 2, 2025 and its 33% equity investment in Belize Electricity (integrated electric - Belize) on October 31, 2025.

The Corporation's only non-regulated business was Fortis Belize (three hydroelectric generation facilities - Belize), which was also sold on October 31, 2025.

Fortis has a unique operating model with a small corporate office in St. John's, Newfoundland and Labrador and business units that operate on a substantially autonomous basis. Each utility has its own management team and board of directors, with most having a majority of independent board members, which provides effective oversight within the broad parameters of Fortis policies and best practices. Subsidiary autonomy supports constructive relationships with regulators, policy makers, customers and communities. Fortis believes this model enhances accountability, opportunity and performance across the Corporation's businesses, and positions Fortis well for future investment opportunities.

Fortis is focused on providing safe, reliable and cost-effective service to customers. In addition, management is focused on delivering long-term profitable growth for shareholders through the execution of its capital plan and the pursuit of investment opportunities within and proximate to its service territories.

Competition

Most of the Corporation's regulated utilities operate as the sole supplier of electricity and/or gas within their respective service territories.

Competition in the regulated electric business is primarily from alternative energy sources and on-site generation by customers. The Corporation faces competition in its transmission business which may restrict its ability to grow this business outside of its established service territories. Challenges to existing right of first refusal statutes applicable to the transmission business may also restrict future growth.

At the Corporation's regulated gas utilities, natural gas primarily competes with electricity for space and hot water heating load. In addition to other price comparisons, upfront capital cost differences between electric and natural gas equipment for hot water and space heating applications continue to present challenges for the competitiveness of natural gas on a fully-costed basis. As governments develop policies to address climate change, any resulting changes to energy policy may impact the competitiveness of natural gas relative to other energy sources. Specifically, government policy could impact the competitiveness of natural gas in British Columbia, which accounts for approximately 80% of the Corporation's natural gas revenue.

Seasonality

As the Corporation's subsidiaries operate in various jurisdictions throughout North America, seasonality impacts each utility differently. Earnings for the 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.

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Summary of Operations

The following table and sections describe the Corporation's operations and reportable segments.

		Customers	Peak<br><br>Demand (1)		Electric T&D Lines (circuit km)	Gas T&D Lines (km)	Generating Capacity (MW)	Revenue<br><br>($ millions)	GWh Sales	Gas Volumes (PJ)	Employees
Regulated Utilities
ITC		—	23,502	MW	26,000	—	—	2,495	—	—	868
UNS Energy		738,000	3,394	MW	23,400	5,200	3,443	2,913	15,768	16	2,147
			110	TJ
Central Hudson		405,000	1,163	MW	15,400	2,400	43	1,620	5,092	30	1,263
			141	TJ
FortisBC Energy		1,105,000	1,473	TJ	—	51,700	—	1,874	—	217	2,238
FortisAlberta		615,000	2,749	MW	91,100	—	—	829	17,561	—	1,301
FortisBC Electric		199,000	739	MW	7,400	—	225	557	3,619	—	607
Other Electric
	Newfoundland Power	280,000	1,429	MW	11,700	—	145	808	5,932	—	667
	Maritime Electric	92,000	345	MW	7,300	—	90	299	1,581	—	265
	FortisOntario	70,000	284	MW	3,400	—	3	250	1,417	—	219
	Caribbean Utilities	35,000	128	MW	800	—	166	405	767	—	293
	FortisTCI (2)	—	—	MW	—	—	—	89	221	—	—
Non-Regulated
Corporate and Other (3)		—	—		—	—	—	31	167	—	58
Total		3,539,000	33,733	MW	186,500	59,300	4,115	12,170	52,125	263	9,926
			1,724	TJ

(1)Electric (MW) or gas (TJ)

(2)Revenue and sales through the September 2, 2025 date of disposition.

(3)Includes revenue and sales for Fortis Belize through the October 31, 2025 date of disposition.

Regulated Utilities

ITC

ITC's business consists primarily of electric transmission operations. ITC's Regulated Operating Subsidiaries own, operate, maintain and invest in high‑voltage electric transmission systems in Michigan's Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin that transmit electricity from generating stations to local distribution facilities connected to ITC's transmission systems.

The primary operating responsibilities of ITC's Regulated Operating Subsidiaries include maintaining, improving and expanding transmission systems to meet their customers' ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded. ITC owns and operates 26,000 circuit km of transmission lines.

ITC's Regulated Operating Subsidiaries earn revenue from the use of their transmission systems by customers, including investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, ITC's Regulated Operating Subsidiaries are subject to rate regulation by FERC. The rates charged are established using cost-based formula rates.

ITC's principal transmission service customers are DTE, CMS and IPL. These customers, individually and together, have consistently represented a significant percentage of ITC's operating revenue. Nearly all of ITC's revenue is from transmission customers in the U.S.

Market and Sales

Revenues

ITC's revenue was $2,495 million in 2025 compared to $2,229 million in 2024.

ITC derives nearly all of its revenue from transmission, scheduling, control and dispatch services and other related services over ITC's Regulated Operating Subsidiaries' transmission systems to DTE, CMS, IPL and other entities, such as alternative energy suppliers, power marketers and other wholesale customers that provide electricity to end-use customers, as well as from transaction-based capacity reservations on ITC's transmission systems. MISO and SPP are responsible for billing and collecting the majority of transmission service revenues. As the billing agents for ITC's MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP collect fees for the use of ITC's transmission systems, invoicing DTE, CMS, IPL and other customers on a monthly basis.

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The following table compares the composition of ITC's 2025 and 2024 revenue by customer class.

		Revenue (%)
	2025		2024
Network revenues		71.3		72.3
Regional cost-sharing revenues		24.6		24.7
Point-to-point		1.6		1.3
Scheduling, control and dispatch		0.9		1.1
Other		1.6		0.6
Total		100.0		100.0

Network revenue is generated from network customers for their use of ITC's electric transmission systems and are based on the actual revenue requirements under its cost-based formula rates that contain a true-up mechanism.

Network revenue from ITC Great Plains includes the annual revenue requirements specific to projects that are charged exclusively within one pricing zone within SPP or are classified as direct assigned network upgrades under the SPP tariff and contain a true-up mechanism.

Regional cost-sharing revenue is generated from transmission customers throughout RTO regions for their use of ITC's MISO Regulated Operating Subsidiaries' network upgrade projects that are eligible for regional cost-sharing under provisions of the MISO tariff. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. Regional cost-sharing revenue is treated as a reduction to the net network revenue requirement under ITC's cost-based formula rates.

Point-to-point revenue consists of revenue generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenue also includes other components pursuant to schedules under the MISO and SPP transmission tariffs. Point-to-point revenue is treated as a revenue credit to network or regional customers and is a reduction to the gross revenue requirement when calculating the net revenue requirement under ITC's cost-based formula rates.

Scheduling, control and dispatch revenue is allocated to ITC's MISO Regulated Operating Subsidiaries by MISO as compensation for the services performed in operating the transmission system. Such services include monitoring of reliability data, current and next-day analysis, implementation of emergency procedures and outage coordination and switching.

Other revenue consists of rental revenue, easement revenue, revenue relating to utilization of jointly-owned assets under ITC's transmission ownership and operating agreements and revenue from providing ancillary services to customers. The majority of other revenue is treated as a revenue credit and taken as a reduction to the gross revenue requirement when calculating the net revenue requirement under ITC's cost-based formula rates.

Contracts

ITCTransmission

DTE operates an electric distribution system that is interconnected with ITCTransmission's transmission system. A set of three operating contracts outlines the terms and conditions related to DTE's and ITCTransmission's interconnected systems. These contracts include:

Master Operating Agreement - governs the primary day-to-day operational responsibilities of ITCTransmission and DTE. It identifies the control area coordination services that ITCTransmission provides to DTE and certain generation-based support services that DTE is required to provide to ITCTransmission.

Generator Interconnection and Operation Agreement - established and maintains the direct electricity interconnection of DTE's electricity generating assets with ITCTransmission's transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.

Coordination and Interconnection Agreement - outlines the rights, obligations and responsibilities of ITCTransmission and DTE regarding, among other things, the operation and interconnection of DTE's distribution system and ITCTransmission's transmission system and the construction of new facilities or modification of existing facilities. Additionally, this agreement allocates costs for operation of supervisory, communications and metering equipment.

METC

CMS operates an electric distribution system that interconnects with METC's transmission system. METC is a party to a number of operating contracts with CMS that govern the operations and maintenance of its transmission system. These contracts include:

Amended and Restated Easement Agreement - CMS provides METC with an easement to the land on which a majority of METC's transmission towers, poles, lines and other transmission facilities used to transmit electricity for CMS and others are located. METC pays CMS an annual rent for the easement and also pays for any rentals, property taxes and other fees related to the property covered by the agreement.

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Amended and Restated Operating Agreement - METC is responsible for maintaining and operating its transmission system, providing CMS with information and access to its transmission system and related books and records, administering and performing the duties of control area operator (that is, the entity exercising operational control over the transmission system) and, if requested by CMS, building connection facilities necessary to permit interaction with new distribution facilities built by CMS.

Amended and Restated Purchase and Sale Agreement for Ancillary Services - Since METC does not own any generating facilities, it must procure ancillary services from third-party suppliers, such as CMS. Currently, under this agreement, METC pays CMS for providing certain generation-based services necessary to support the reliable operation of the bulk power grid, such as voltage support and generation capability and capacity to balance loads and generation.

Amended and Restated Distribution-Transmission Interconnection Agreement - provides for the interconnection of CMS' distribution system with METC's transmission system and defines the continuing rights, responsibilities and obligations of the parties with respect to the use of certain of their respective property, assets and facilities.

Amended and Restated Generator Interconnection Agreement - specifies the terms and conditions under which CMS and METC maintain the interconnection of CMS' generation resources and METC's transmission assets.

ITC Midwest

IPL operates an electric distribution system that interconnects with ITC Midwest's transmission system. ITC Midwest is a party to a number of operating contracts with IPL that govern the operations and maintenance of their respective systems. These contracts include:

Distribution-Transmission Interconnection Agreement - governs the rights, responsibilities and obligations of ITC Midwest and IPL with respect to the use of certain of their respective property, assets and facilities and the construction of new facilities or modification of existing facilities.

Large Generator Interconnection Agreement - ITC Midwest, IPL and MISO entered into this agreement in order to establish and maintain the direct electricity interconnection of IPL's electricity generating assets with ITC Midwest's transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.

Operations Services Agreement - specifies the terms and conditions under which IPL performs certain operations functions for ITC Midwest's 34.5 kV transmission system.

UNS Energy

UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona. It is engaged through its subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving 738,000 retail electricity and gas customers. UNS Energy primarily consists of three wholly owned regulated utilities: TEP, UNS Electric and UNS Gas.

TEP is a vertically integrated regulated electric utility that generates, transmits and distributes electricity. TEP serves 459,000 retail customers in a territory comprising 2,991 square km in southeastern Arizona, including the greater Tucson metropolitan area. TEP also sells wholesale electricity to other entities in the western U.S.

UNS Electric is a vertically integrated regulated electric utility that generates, transmits and distributes electricity to 107,000 retail customers in southeastern Arizona.

TEP and UNS Electric own generation resources with an aggregate capacity of 3,443 MW, including 319 MW of renewable resources. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. As at December 31, 2025, 26% of the generating capacity was fueled by coal.

TEP also owns transmission-related assets representing approximating 15% of UNS Energy's total assets.

UNS Gas is a regulated gas distribution utility that serves 172,000 retail customers in northern and southern Arizona.

Market and Sales

UNS Energy's electricity sales were 15,768 GWh in 2025 compared to 16,680 GWh in 2024. Gas volumes were 16 PJ in 2025, largely consistent with 2024. Revenue was $2,913 million in 2025 compared to $3,007 million in 2024.

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The following table provides the composition of UNS Energy's 2025 and 2024 revenue, electricity sales, and gas volumes by customer class.

	Revenue (%)		GWh Sales (%)		PJ Volumes (%)
	2025	2024	2025	2024	2025	2024
Residential	39.7	39.8	31.0	30.1	50.4	53.4
Commercial	20.8	20.3	17.1	16.2	21.7	22.2
Industrial	14.0	14.4	19.9	18.8	1.7	2.0
Wholesale	8.1	9.0	31.9	34.8	—	—
Other (1)	17.4	16.5	0.1	0.1	26.2	22.4
Total	100.0	100.0	100.0	100.0	100.0	100.0

(1)Electricity sales include transmission, participant billings, alternative revenue and revenue from sources other than from the sale of electricity. Gas volumes include negotiated sales program customers.

Power Supply

TEP meets the electricity supply requirements of its retail and wholesale customers with its owned electrical generating capacity of 3,127 MW and its transmission and distribution system consisting of approximately 16,000 circuit km of line. In 2025, TEP met a peak demand of 2,908 MW, which includes firm sales to wholesale customers. TEP is a member of a regional reserve-sharing organization and has reliability and power sharing relationships with other utilities.

TEP's generating capacity is set forth in the following table.

Generation Source	Unit No.	Location	Date in <br>Service	Total Capacity (MW)	Operating Agent	TEP's Share (%)	TEP's Share (MW)
Coal
Springerville Station (1)	1	Springerville, AZ	1985	387	TEP	100.0	387
Springerville Station (1) (2)	2	Springerville, AZ	1990	406	TEP	100.0	406
Four Corners Station	4	Farmington, NM	1969	785	APS	7.0	55
Four Corners Station	5	Farmington, NM	1970	785	APS	7.0	55
Natural Gas
Gila River Power Station	2	Gila Bend, AZ	2003	607	SRP	100.0	607
Gila River Power Station (3)	3	Gila Bend, AZ	2003	607	SRP	75.0	455
Luna Generating Station	1	Deming, NM	2006	555	PNM	33.3	185
Sundt Station	3	Tucson, AZ	1962	104	TEP	100.0	104
Sundt Station	4	Tucson, AZ	1967	156	TEP	100.0	156
Sundt Internal Combustion Turbines		Tucson, AZ	1972-1973	50	TEP	100.0	50
Sundt Reciprocating Internal Combustion Engine (2)	1-10	Tucson, AZ	2019-2020	188	TEP	100.0	188
DeMoss Petrie (4)	N/A	Tucson, AZ	2001	75	TEP	100.0	75
North Loop	N/A	Tucson, AZ	2001	96	TEP	100.0	96
Renewable
Utility-Owned Renewables		Various	2002-2023	308	TEP	100.0	308
Total Capacity							3,127

(1)In July 2025, TEP announced a plan to convert Springerville Units 1 and 2 from coal-fired generation to natural-gas fired generation by 2030.

(2)Springerville Generating Station Unit 2 is owned by San Carlos Resources Inc., a wholly owned subsidiary of TEP.

(3)TEP owns 75% of Gila River Unit 3 and UNS Electric owns 25%

(4)Demoss Petrie is accompanied by 10 MW of battery storage

UNS Electric meets the electricity supply requirements of its retail customers with its owned electrical generating capacity of 316 MW and purchasing power on the wholesale market, and its transmission and distribution system consisting of approximately 7,000 circuit km of line. In 2025, UNS Electric met a peak demand of 486 MW.

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UNS Electric's generating capacity is set forth in the following table.

Generation Source	Unit No.	Location	Date In<br><br>Service	Resource Type	Total Capacity (MW)	Operating Agent	UNSE's Share (%)	UNSE's Share (MW)
Black Mountain	1	Kingman, AZ	2011	Gas	45	UNSE	100.0	45
Black Mountain	2	Kingman, AZ	2011	Gas	45	UNSE	100.0	45
Valencia	1	Nogales, AZ	1989	Gas/Oil	14	UNSE	100.0	14
Valencia	2	Nogales, AZ	1989	Gas/Oil	14	UNSE	100.0	14
Valencia	3	Nogales, AZ	1989	Gas/Oil	14	UNSE	100.0	14
Valencia	4	Nogales, AZ	2006	Gas/Oil	21	UNSE	100.0	21
Gila River Power Station	3	Gila Bend, AZ	2003	Gas	607	SRP	25.0	152
Utility-Owned Renewables	N/A	Various	2011-2017	Solar	11	UNSE	100.0	11
Total Capacity								316

Utility-Owned Renewable and Battery Resources

TEP owns 308 MW of renewable generation resources, and has 3 MW of solar generation resources under development. It also has one 200 MW battery storage system and a second under development with a planned 2026 in-service date. UNS Electric owns 11 MW of solar generation capacity.

Renewable and Battery Storage Power Purchase Agreements

TEP has renewable PPAs of 256 MW from solar resources and 179 MW from wind resources. The solar PPAs contain options that allow TEP to purchase all or part of the related facilities at a future date. The Babacomari North and Wilmot II solar facilities are expected to be placed in service in 2026 and the Winchester solar facility is expected to be placed in service in 2027. Through the PPAs, these facilities are expected to add 340 MW to TEP's renewable capacity. UNS Electric has renewable PPAs of 83 MW from solar resources and 10 MW from wind resources. TEP has PPAs for battery storage of 50 MW located on renewable sites, with 180 MW of battery storage under development at Wilmot II and Winchester.

Gas Purchases

TEP and UNS Gas directly manage their gas supply and transportation contracts. The price for gas varies based on market conditions, which include weather, supply balance, economic growth rates and other factors. TEP and UNS Gas hedge their gas supply prices by entering into fixed-price forward contracts, collars and financial swaps from time to time, up to three years in advance, with a view to hedging 70-90% of expected monthly energy volumes prior to the beginning of each month.

UNS Gas met peak demand of 110 TJ in 2025.

Central Hudson

Central Hudson is a regulated electric and gas transmission and distribution utility serving 315,000 electricity customers and 90,000 natural gas customers in portions of New York State's Mid-Hudson River Valley. Central Hudson serves a territory of approximately 6,700 square km. Electric service is available throughout the territory, and natural gas service is provided in and around the cities of Poughkeepsie, Beacon, Newburgh and Kingston, New York, and in certain outlying and intervening territories.

Central Hudson's electric system consists of 15,400 circuit km of transmission and distribution lines and met a peak demand of 1,163 MW in 2025.

Central Hudson's natural gas system consists of 2,400 km of transmission and distribution pipelines and met a peak demand of 141 TJ in 2025.

Market and Sales

Central Hudson's electricity sales were 5,092 GWh in 2025 compared to 5,060 GWh in 2024. Natural gas sales volumes were 30 PJ in 2025 compared to 25 PJ in 2024. Revenue was $1,620 million in 2025 compared to $1,372 million in 2024.

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The following table compares the composition of Central Hudson's 2025 and 2024 revenue, electricity sales and natural gas volumes by customer class.

	Revenue (%)		GWh Sales (%)		PJ Volumes (%)
	2025	2024	2025	2024	2025	2024
Residential	63.8	63.1	44.1	42.9	20.4	22.3
Commercial	28.3	30.0	39.5	39.7	24.8	28.7
Industrial	4.1	4.6	15.6	16.6	49.8	42.5
Wholesale (1)	0.9	0.9	0.8	0.8	5.0	6.5
Other (2)	2.9	1.4	—	—	—	—
Total	100.0	100.0	100.0	100.0	100.0	100.0

(1)Includes sales for resale.

(2)Other includes regulatory deferrals and revenue from sources other than from the sale of gas and electricity.

Power Supply

Central Hudson relies on purchased capacity and energy from third-party providers, together with its own minimal generating capacity, to meet the demands of its full-service customers.

Costs of electric and natural gas commodity purchases are recovered from customers, without earning a profit on these costs. Rates are reset monthly based on Central Hudson's actual costs to purchase the electricity and natural gas needed to serve its full-service customers.

FortisBC Energy

FortisBC Energy is the largest distributor of natural gas in British Columbia, serving 1,105,000 residential, commercial, industrial, and transportation customers. FortisBC Energy provides transmission and distribution services to customers and obtains natural gas and renewable gas supplies on behalf of most of its residential, commercial and industrial customers. Gas supplies are sourced primarily from northeastern British Columbia and, through FortisBC Energy's Southern Crossing Pipeline, from Alberta. FortisBC Energy owns and operates 51,700 km of natural gas pipelines and met a peak demand of 1,473 TJ in 2025.

Market and Sales

FortisBC Energy's natural gas sales volumes were 217 PJ in 2025 compared to 220 PJ in 2024. Revenue was $1,874 million in 2025 compared to $1,665 million in 2024.

The following table compares the composition of FortisBC Energy's 2025 and 2024 revenue and natural gas volumes by customer class.

	Revenue (%)		PJ Volumes (%)
	2025	2024	2025	2024
Residential	54.7	56.6	34.6	35.4
Commercial	30.4	30.6	26.3	25.9
Industrial	10.9	8.0	14.7	11.4
Other (1)	4.0	4.8	24.4	27.3
Total	100.0	100.0	100.0	100.0

(1)Includes revenue and gas volumes from transportation customers. Due to the nature of transportation contracts, the percentage of revenue by customer category may not correlate with associated volumes.

Gas Purchase Agreements

To ensure supply of adequate resources for reliable natural gas deliveries to its customers, FortisBC Energy purchases natural gas supply from counterparties, including producers, aggregators and marketers. FortisBC Energy contracts for approximately 179 PJ of baseload and seasonal supply, of which the majority is sourced in northeastern British Columbia and transported on Westcoast Energy Inc.'s T‑South pipeline system. The remainder is sourced in Alberta and transported on TC Energy's pipeline transportation system. FortisBC Energy purchased 4.1 PJs of RNG in 2025.

FortisBC Energy procures and delivers natural gas directly to core market customers. Transportation customers are responsible to procure and deliver their own natural gas to the FortisBC Energy system and FortisBC Energy then delivers the gas to the operating premises of these customers. FortisBC Energy contracts for transportation capacity on third-party pipelines, such as the T‑South pipeline and the TC Energy pipeline, to transport gas supply from various market hubs to FortisBC Energy's system. These third-party pipelines are regulated by the Canada Energy Regulator. FortisBC Energy pays both fixed and variable charges for the use of transportation capacity on these pipelines, which are recovered through rates paid by FortisBC Energy's core market customers. FortisBC Energy contracts for firm transportation capacity to ensure it is able to meet its obligation to supply customers within its broad operating region under all reasonable demand scenarios.

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Gas Storage and Peak Shaving Arrangements

FortisBC Energy incorporates peak shaving and gas storage facilities into its portfolio to: (i) supplement contracted base load and seasonal gas supply in the winter months, while injecting excess base load supply to refill storage in the summer months; (ii) mitigate the risk of supply shortages during cooler weather and peak demand; (iii) manage the cost of gas during the winter months; and (iv) balance daily supply and demand on the distribution system during periods of peak use that occur during the winter months.

FortisBC Energy holds 37 PJs of total storage capacity. FortisBC Energy owns Tilbury and Mount Hayes LNG peak shaving facilities, which provide on-system storage capacity and deliverability. FortisBC Energy also contracts for underground storage capacity and deliverability from parties in northeastern British Columbia, Alberta and the Pacific Northwest of the U.S. On a combined basis, FortisBC Energy's Tilbury and Mount Hayes facilities, the contracted storage facilities and other peaking arrangements can deliver up to 0.83 PJs per day of supply to FortisBC Energy on the coldest days of the heating season. The heating season typically occurs during the period from December to February.

Mitigation Activities

FortisBC Energy engages in off-system sales activities that allow for the recovery or mitigation of costs of any unutilized supply and/or pipeline and storage capacity that is available once customers' daily load requirements are met.

Under the Gas Supply Mitigation Incentive Plan revenue sharing model approved by the BCUC, FortisBC Energy can earn an incentive payment for mitigation activities. Subject to the BCUC's approval, FortisBC Energy earned an incentive payment of approximately $3.7 million for the gas contract year ending October 31, 2025.

The BCUC has approved extensions of the program through October 31, 2028.

Price-Risk Management Plan

FortisBC Energy engages in price-risk management activities to mitigate the impact on customer rates of fluctuations in natural gas prices. These activities include: (i) physical gas purchasing and storage strategies; (ii) quarterly commodity rate-setting and a deferral account mechanism; and (iii) the use of derivative instruments, which were implemented pursuant to a price-risk management plan approved by the BCUC, as discussed below.

For the April 2024 to March 2028 period, FortisBC Energy has implemented fixed price AECO/NIT hedges to mitigate the impact of rising prices at the AECO/NIT market hub and provide increased pricing diversity to the commodity supply portfolio. FortisBC Energy's AECO/NIT Price Risk Mitigation Application was approved by the BCUC in June 2023.

Unbundling

A Customer Choice program at FortisBC Energy allows eligible commercial and residential customers to buy their natural gas commodity supply from FortisBC Energy or from third-party marketers. FortisBC Energy continues to provide the delivery service of the natural gas to all its customers. In 2025, approximately 9% of eligible commercial customers and 3% of eligible residential customers purchased their commodity supply from alternate providers.

FortisAlberta

FortisAlberta is a regulated electricity distribution utility operating in Alberta. Its business is the ownership and operation of electric distribution facilities that distribute electricity, generated by other market participants, from high-voltage transmission substations to end-use customers. FortisAlberta is not involved in the generation, transmission or direct retail sale of electricity. FortisAlberta operates the electricity distribution system in a substantial portion of southern and central Alberta around and between the cities of Edmonton and Calgary, totalling 91,100 circuit km of distribution lines. FortisAlberta's distribution network serves 615,000 customers and met a peak demand of 2,749 MW in 2025.

Market and Sales

FortisAlberta's energy deliveries were 17,561 GWh in 2025 compared to 17,324 GWh in 2024. Revenue was $829 million in 2025 compared to $817 million in 2024.

The following table compares the composition of FortisAlberta's 2025 and 2024 revenue and energy deliveries by customer class.

	Revenue (%)		GWh Deliveries (%) (1)
	2025	2024	2025	2024
Residential	44.5	44.3	28.2	28.2
Commercial	24.4	24.8	13.2	13.3
Industrial	18.1	18.2	58.6	58.5
Other (2)	13.0	12.7	—	—
Total	100.0	100.0	100.0	100.0

(1)GWh percentages exclude FortisAlberta's GWh deliveries to "transmission-connected" customers. These deliveries were 6,226 GWh in 2025 and 6,906 GWh in 2024 and consisted primarily of energy deliveries to large-scale industrial customers directly connected to the transmission grid.

(2)Includes rate riders, deferrals and adjustments.

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Franchise Agreements

FortisAlberta customers located within a city, town, village or summer village boundary are served under franchise agreements between FortisAlberta and the respective customers' municipality of residence. FortisAlberta maintains standard franchise agreements with many municipalities throughout Alberta. Any franchise agreement that is not renewed at the expiry of the term continues in effect until either FortisAlberta or the municipality terminates it with the approval of the AUC. The Municipal Government Act (Alberta) provides municipalities an option to purchase FortisAlberta assets located within their municipal boundaries upon termination of a franchise agreement. FortisAlberta must be compensated if a franchise agreement is terminated and the municipality subsequently exercises its option to purchase FortisAlberta distribution assets. In such a case, compensation would likely be determined based on a methodology approved by the AUC.

FortisAlberta holds franchise agreements with 163 municipalities within its service area. The franchise agreements include 10‑year terms with an option to renew for up to two subsequent five-year terms. Amalgamations between a small number of municipalities that have occurred since the initial implementation of certain agreements have reduced the overall number of agreements subject to renewal in 2026. Notices to extend the franchise agreements expiring in 2026 have been or will be provided to affected municipalities prior to expiration.

FortisBC Electric

FortisBC Electric is an integrated regulated electric utility that owns hydroelectric generating plants, high voltage transmission lines and a large network of distribution assets located in the southern interior of British Columbia. FortisBC Electric serves 199,000 customers and met a peak demand of 739 MW in 2025. FortisBC Electric's assets include 7,400 circuit km of transmission and distribution lines.

FortisBC Electric is also responsible for operation, maintenance and management services at the 493 MW Waneta hydroelectric generating facility owned by BC Hydro and the 340 MW Waneta Expansion, the 149 MW Brilliant hydroelectric plant, the 120 MW Brilliant hydroelectric expansion plant and the 185-MW Arrow Lakes generating station, all ultimately owned by Columbia Basin Trust and Columbia Power Corporation.

Market and Sales

Electricity sales were 3,619 GWh in 2025 compared to 3,513 GWh in 2024. Revenue was $557 million in 2025 compared to $545 million in 2024.

The following table compares the composition of FortisBC Electric's 2025 and 2024 revenue and electricity sales by customer class.

	Revenue (%)		GWh Sales (%)
	2025	2024	2025	2024
Residential	46.6	48.4	35.9	37.6
Commercial	27.0	26.6	28.7	28.7
Industrial	13.9	12.1	19.3	16.7
Wholesale	12.5	12.9	16.1	17.0
Total	100.0	100.0	100.0	100.0

Generation and Power Supply

FortisBC Electric meets the electricity supply requirements of its customers through a mix of its own generation and PPAs. FortisBC Electric owns four regulated hydroelectric generating plants on the Kootenay River with an aggregate capacity of 225 MW, which provide approximately 41% of its energy needs and 27% of its peak capacity needs. FortisBC Electric meets the balance of its requirements through a portfolio of long-term and short-term PPAs.

FortisBC Electric's four hydroelectric generating facilities are governed by the multiparty CPA that enables the five separate owners of nine major hydroelectric generating plants, with a combined capacity of 1,907 MW and located in relatively close proximity to each other, to coordinate the operation and dispatch of their generating plants.

The following table lists the plants and their respective capacity and owner.

Plant	Capacity<br><br>(MW)	Owners
Canal Plant	580	BC Hydro
Waneta Dam	493	BC Hydro
Waneta Expansion	340	Waneta Expansion Power Corporation
Kootenay River System	225	FortisBC Electric
Brilliant Dam	149	Brilliant Power Corporation
Brilliant Expansion	120	Brilliant Expansion Power Corporation
Total	1,907
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Brilliant Power Corporation, Brilliant Expansion Power Corporation, Teck Metals Ltd., Waneta Expansion Power Corporation and FortisBC Electric are collectively defined in the CPA as the entitlement parties. The CPA enables BC Hydro and the entitlement parties to generate more power from their respective generating plants than they could if they operated independently through coordinated use of water flows, subject to the 1961 Columbia River Treaty between Canada and the U.S., and coordinated operation of storage reservoirs and generating plants. Under the CPA, BC Hydro takes into its system all power actually generated by the plants listed in the table above. In exchange for permitting BC Hydro to determine the output of these facilities, each of the entitlement parties is contractually entitled to a fixed annual entitlement of capacity and energy from BC Hydro, which is based on 50-year historical water flows and the plants' generating capabilities. The entitlement parties receive their defined entitlements irrespective of actual water flows to the entitlement parties' generating plants. BC Hydro enjoys the benefits of the additional power generated through coordinated operation and optimal use of water flows. The entitlement parties benefit by knowing years in advance the amount of power that they will receive from their generating plants and, therefore, do not face hydrology variability in generation supply planning. However, FortisBC Electric retains rights to its original water licences and flows in perpetuity. Should the CPA be terminated, the output of FortisBC Electric's Kootenay River system plants would, with the water and storage authorized under its existing licences and on a long‑term average, be approximately the same power output as FortisBC Electric receives under the CPA. The CPA does not affect FortisBC Electric's ownership of its physical generation assets. The CPA continues in force until terminated by any of the parties by giving no less than five years' notice at any time on or after December 31, 2030.

FortisBC Electric's remaining electricity supply is acquired primarily through long-term PPAs with a number of counterparties, including the Brilliant PPA, the BC Hydro PPA and the Waneta Expansion Capacity Agreement. Additionally, FortisBC Electric purchases capacity and energy from the market to meet its peak energy requirements and optimize its overall power supply portfolio. These market purchases provided approximately 11% of FortisBC Electric's energy supply requirements in 2025. FortisBC Electric's PPAs and market purchases have been accepted by the BCUC and prudently incurred costs thereunder flow through to customers through FortisBC Electric's electricity rates.

Other Electric

Other Electric consists of utilities in eastern Canada and the Caribbean as follows: Newfoundland Power; Maritime Electric; FortisOntario; a 39% investment in Wataynikaneyap Power; and an approximate 60% controlling interest in Caribbean Utilities. It also includes FortisTCI until the September 2, 2025 disposition date and the Corporation's 33% equity investment in Belize Electricity until the October 31, 2025 disposition date.

Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador. Maritime Electric is an integrated regulated electric utility and the principal distributor of electricity on PEI. FortisOntario provides integrated electric utility service through its three regulated operating utilities primarily in Fort Erie, Port Colborne, Cornwall, Gananoque, and the District of Algoma in Ontario.

Wataynikaneyap Power is a transmission company majority-owned by 24 First Nations communities (51%), in partnership with FortisOntario (39%) and Algonquin Power & Utilities Corp. (10%). The 1,800 km Wataynikaneyap Power transmission line connects 17 remote First Nations communities to the Ontario power grid. Wataynikaneyap Power is excluded from the following discussion as Fortis holds a minority interest in this entity.

Caribbean Utilities is an integrated regulated electric utility and the sole distributor of electricity on Grand Cayman, Cayman Islands.

The following table sets out the customers, installed generating capacity, peak demand and kilometers of transmission and distribution lines for the segment.

	Customers	Peak Demand (MW)	T&D Lines (circuit km)	Generating Capacity (MW)	Resource Type(s)
Newfoundland Power	280,000	1,429	11,700	145	Hydroelectric, Gas, Diesel
Maritime Electric	92,000	345	7,300	90	Diesel
FortisOntario (1)	70,000	284	3,400	3	Natural Gas Cogeneration
Caribbean Utilities (2)	35,000	128	800	166	Diesel
Total	477,000	2,186	23,200	404

(1) FortisOntario also owns a 10% interest in certain regional electric distribution companies serving approximately 40,000 customers.

(2) Includes 24 km of high-voltage submarine cable.

Market and Sales

Electricity sales attributable to Other Electric were 9,918 GWh in 2025 compared to 9,879 GWh in 2024. Revenue was $1,851 million in 2025 compared to $1,838 million in 2024.

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The following table compares the composition of revenue and electricity sales by customer class for Other Electric in 2025 and 2024.

		Revenue (2) (%)				GWh Sales (2) (%)
	2025		2024		2025		2024
Residential		56.6		55.7		57.0		56.9
Commercial		37.2		37.2		39.9		40.0
Industrial		1.8		1.8		2.6		2.6
Other (1)		4.4		5.3		0.5		0.5
Total		100.0		100.0		100.0		100.0

(1) Includes revenue from sources other than from the sale of electricity.

(2) Includes FortisTCI through the September 2, 2025 disposition date.

Power Supply

Newfoundland Power

Approximately 93% of Newfoundland Power's energy requirements are purchased from NL Hydro with the remaining 7% generated by Newfoundland Power. The principal terms of the supply arrangements with NL Hydro are regulated by the PUB on a basis similar to that upon which Newfoundland Power's service to its customers is regulated.

NL Hydro charges Newfoundland Power for purchased power and includes charges for both demand and energy purchased. The energy charge is a two-block demand charge based on the peak billing demand for the most recent winter season. The second block charge, under the new wholesale rate effective January 1, 2025, reflects NL Hydro's current marginal energy costs based on energy exports. Energy from the Muskrat Falls project supplies a significant portion of NL Hydro's electricity requirements and, in turn, Newfoundland Power's electricity requirements. The Government of Newfoundland and Labrador finalized the rate mitigation plan in respect of the Muskrat Falls project effective July 1, 2024 that limits annual domestic customer rate increases associated with the Muskrat Falls project and NL Hydro's operations to 2.25% until 2030. The impact of the Muskrat Falls project on customer rates beyond 2030 remains uncertain.

In October 2022, NL Hydro filed an updated study with the PUB recommending, among other things, that its 490 MW Holyrood Thermal Generating Station remain operational until 2030 as backup generation in the event of an extended outage to the Labrador Island Link. In March 2025, NL Hydro submitted applications to the PUB for capital expenditures emphasizing the need for investment to maintain system reliability and meet future capacity requirements. The applications state that approximately 525 MW of capacity is required by 2034 to address additional demand and to allow for the retirement of aging thermal assets, including the Holyrood Thermal Generating Station. NL Hydro is requesting the approval of approximately $2 billion to expand the Bay d’Espoir Hydroelectric Generating Station and to build a combustion turbine on the existing Holyrood site. In April 2025, the PUB approved NL Hydro's request for $47.4 million in early execution capital related to the application. These costs will only be recovered from customers if the application is approved.

Maritime Electric

Maritime Electric is interconnected to the Province of New Brunswick via four provincially owned submarine cables with a total capacity of 560 MW. The company purchases its energy requirements through energy purchase agreements with NB Power, a New Brunswick Crown corporation, and from renewable energy facilities owned by the PEI Energy Corporation. Company-owned on-island generation facilities totalling 90 MW are used primarily for peaking, submarine-cable loading issues and emergency purposes.

Maritime Electric has identified a need for an additional 150 MW of on-island dispatchable generating capacity due to customer load growth associated with increased population and electrification. In 2024, Maritime Electric filed an application with the Island Regulatory and Appeals Commission seeking approval to purchase a 50 MW combustion turbine, a 10 MW 4-hour battery energy storage system, and 90 MW of reciprocating internal combustion engines. Maritime Electric was subsequently presented with an opportunity to obtain 100 MW at a lower cost and with a faster in-service date. Therefore, in August 2025, Maritime Electric filed a supplemental application seeking approval to purchase two 50 MW combustion turbines, which would fulfill 100 MW of the original 150 MW requested.

Maritime Electric has the following contracts with NB Power: (i) an energy supply agreement covering the period March 1, 2019 to December 31, 2026, for which negotiations to renew will commence in 2026; (ii) a transmission capacity contract allowing Maritime Electric to reserve 30 MW of capacity to PEI expiring November 2032; and (iii) an entitlement agreement for 4.55% of the output from NB Power's Point Lepreau Nuclear Generating Station for the life of the unit. Maritime Electric also has several renewable energy contracts with the PEI Energy Corporation for the purchase of energy for remaining periods ranging from one to 15 years.

As part of its entitlement agreement relating to the output of the Point Lepreau Nuclear Generating Station, Maritime Electric is required to pay its share of the unit's capital and operating costs.

FortisOntario

The power requirements of FortisOntario's service territories are met through various sources. Canadian Niagara Power purchases all its power requirements for Fort Erie and Port Colborne from the IESO, purchases 84% of energy requirements for the Gananoque region from Hydro One Networks Inc. and purchases the remaining 16% from five hydroelectric generating plants owned by EO Generation LP. Algoma Power purchases its energy requirements primarily from the IESO. Under the Ontario Energy Board's Standard Supply Code, Canadian Niagara Power and Algoma Power must provide standard service supply to all its customers who do not choose to contract with an electricity retailer. This energy is provided to customers at either regulated or market prices.

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Cornwall Electric purchases substantially all of its power requirements from Hydro-Québec Energy Marketing under a contract that expires in December 2030 and which provides a minimum of 537 GWh of energy per year and up to 145 MW of capacity at any one time.

Caribbean Utilities

Caribbean Utilities largely relies upon in-house diesel-powered generation to produce electricity for its customers. The utility has identified a need for additional generation capacity for Grand Cayman. In August 2025, Caribbean Utilities and the Cayman Islands Utility Regulation and Competition Office agreed on an approach to address the need for additional generating capacity requirements. In September 2025, Caribbean Utilities filed an application outlining the generation resources required to meet Grand Cayman's projected energy demand, with a need for additional generation capacity to be in place by 2027.

Caribbean Utilities is party to primary and secondary fuel supply contracts that expire in 2027 with two different suppliers from whom it is committed to purchasing 60% and 40%, respectively, of its diesel fuel requirements for its diesel-powered generating plant.

Non-Regulated

Corporate and Other

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. This segment consists of non-regulated holding company expenses and also included revenue and earnings from non-regulated generation assets in Belize until the October 31, 2025 disposition date.

Market and Sales

Energy sales were 167 GWh in 2025 compared to 215 GWh in 2024. Revenue was $31 million in 2025 compared to $35 million in 2024. The decrease compared to 2024 reflects the disposition of Fortis Belize in October 2025.

HUMAN RESOURCES

Fortis and its subsidiaries have 9,900 employees, with 54% in Canada, 43% in the U.S. and 3% in the Cayman Islands. The following table provides the breakdown of employees by reportable segment.

	Employees	Participation in a Collective Agreement		Union(s)	Collective Agreement(s) Expiry Date(s)
Regulated Utilities
ITC	868	None		—	—
UNS Energy	2,147	46	%	IBEW	June 2024 – June 2028(1)
Central Hudson	1,263	55	%	IBEW	April 2026 – March 2028
FortisBC Energy(2)	2,238	58	%	IBEW, MoveUP	March 2027 – March 2029
FortisAlberta	1,301	75	%	UUWA	December 2025(3)
FortisBC Electric	607	66	%	IBEW, MoveUP	March 2027 – June 2028
Other Electric	1,444	41	%	CUPE, IBEW, PWU	February 2026 – December 2026
Non-Regulated
Corporate(4)	58	None		—	—
Total	9,926	49	%

(1)The UNS Gas and IBEW Local Union 1116 collective agreement expired in June 2024 and negotiations are ongoing.

(2)Includes employees at FHI.

(3)The FortisAlberta and UUWA collective agreement expired in December 2025 and negotiations are ongoing.

(4)Employees at Fortis Inc.

The Corporation's culture is built on safety and integrity. Fortis and its utilities respect their employees' freedom to associate and right to a fair wage and strive to maintain positive and constructive relationships with labour associations and unions.

Fortis values its 9,900 employees and recognizes that success is dependent on a strong workforce which is safe, supported and empowered. Fortis and its utilities have compensation and benefit programs designed to attract and retain talent. Fortis believes that the foundation for a healthy work environment starts with leadership from the most senior levels of the organization and must be driven by clearly articulated values that are understood and practiced at all levels of the organization.

The Corporation's subsidiaries are required to develop and retain a skilled workforce for their operations. Many of the employees of the Corporation's utilities possess specialized skills and training and Fortis must compete in the marketplace for these workers.

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LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings that involve a claim for damages exceeding 10% of the Corporation's current assets in respect of which the Corporation is or was a party, or in respect of which any of the Corporation's property is or was the subject during 2025, nor are there any such proceedings known to the Corporation to be contemplated.

During 2025, there were not any: (i) penalties or sanctions imposed against the Corporation by a court relating to securities legislation or by a securities regulatory authority; (ii) other penalties or sanctions imposed by a court or regulatory body against the Corporation that would likely be considered important to a reasonable investor in making an investment decision; or (iii) settlement agreements entered into by the Corporation before a court relating to securities legislation or with a securities regulatory authority.

The Corporation's utilities operate under a cost of service regulation, in combination with performance-based rate-setting mechanisms in certain jurisdictions, and are regulated by the regulatory body in their respective operating jurisdiction.

For information with respect to the nature of regulation and material regulatory decisions and applications associated with each of the Corporation's utilities, refer to the "Regulatory Highlights - Significant Regulatory Matters" section of the MD&A and to Notes 2 and 8 of the Financial Statements, each of which are incorporated by reference in this AIF and available on SEDAR+ and EDGAR.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There were no directors or executive officers of the Corporation, or any associate or affiliate of a director or executive officer of the Corporation, with a material interest in any transaction within the three most recently completed financial years or during the current financial year that has materially affected the Corporation or is reasonably expected to materially affect the Corporation.

RISK FACTORS

For information with respect to the Corporation's business risks, refer to the "Business Risks" section of the MD&A, which is incorporated by reference in this AIF and available on SEDAR+ and EDGAR.

CYBERSECURITY

The Corporation and its utilities are at risk of cybersecurity threats, including cyber attacks, data breaches, cyber extortion or similar compromises, which may target operations, critical infrastructure assets, information systems and/or data. Certain of the Corporation's and its utilities' information systems have been targeted by malware, phishing efforts, denial-of-service attacks and other cyber attacks, and certain of the information systems of the Corporation's utilities have been subjected to direct and third-party cyberattacks and/or information security breaches, none of which have been material. The Corporation has not experienced an information security breach or third-party information security breach since it began reporting on this metric in 2018. No risks have arisen from any past or present cybersecurity threats that materially affect, or are reasonably likely to materially affect, the Corporation's business strategy, results of operations or financial condition. Fortis and its utilities expect to be targeted by similar attacks in the future.

The Board and management of the Corporation oversee the Corporation's cybersecurity strategy, policies and practices, including the Corporation's Cybersecurity Policy and enterprise-wide CRMP. Each utility is required to implement the CRMP and adopt a cybersecurity policy that meets the minimum program standards and elements of the Fortis Cybersecurity Policy.

Governance and Oversight

The Board, through the Governance and Sustainability Committee, oversees the Corporation's strategies and policies relating to IT and OT, as well as reviews the Corporation's cybersecurity risks and the measures taken to monitor or mitigate such exposures. The Governance and Sustainability Committee is responsible specifically for overseeing the Corporation's IT and OT use and protection policies and practices, including in respect of cybersecurity, system integrity, data protection, privacy and compliance.

The Corporation's Executive Vice President, Operations and Technology has oversight responsibilities for operations, cybersecurity and technology functions. The Vice President, Chief Information Officer of the Corporation reports to the Executive Vice President, Operations and Technology, and coordinates the CRMP with the leaders of each utility's cybersecurity program. The Vice President, Chief Information Officer has overall accountability for the operation of the CRMP. A summary of the relevant expertise of these executives is below:

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Executive	Summary of Relevant Experience and Expertise
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Gary J. Smith, Executive Vice President, Operations and Technology	Mr. Smith has held a number of senior leadership positions within the Fortis group throughout his 40-year tenure including: Executive Vice President, Operations and Innovation of Fortis; Executive Vice President, Eastern Canadian and Caribbean Operations of Fortis; President and Chief Executive Officer of Newfoundland Power; Vice President of Customer Operations and Engineering of Newfoundland Power; and Vice President of Operations and Engineering of FortisAlberta. Mr. Smith serves as Chair of the board of directors of FortisOntario and Wataynikaneyap Power PM Inc., and serves on the boards of FortisAlberta, UNS Energy, Caribbean Utilities and Fortis Energy Caribbean Inc. Mr. Smith holds a Bachelor of Engineering (Electrical) from Memorial University of Newfoundland. He is a former director of the Canadian Electricity Association and was elected as a Fellow of the Canadian Academy of Engineering in 2021. He is a member of the Association of Professional Engineers and Geoscientists of Newfoundland and the Steering Committee on Power Engineering for the Canadian Standards Association. Mr. Smith is a subject matter expert in all areas of power engineering and utility operations. As a result of his extensive career in the utility industry, leading both operations and innovation functions, Mr. Smith has specialized knowledge of utility IT and OT systems, uniquely qualifying him to oversee the protection and integrity of our critical infrastructure.
Keri L. Glitch, Vice President, Chief Information Officer	Ms. Glitch has extensive IT leadership experience within the power and utilities sector. Prior to joining the Fortis group in 2023, Ms. Glitch served in technology leadership roles for six years at MISO as the Chief Digital Officer and the Chief Information Security Officer. In her positions with MISO, Ms. Glitch had responsibility for integrating technology functions to develop a long-term digital strategy to enable reliable, secure operations for future grid operational requirements. Ms. Glitch was also the senior manager responsible for NERC Critical Infrastructure Protection compliance. Prior to MISO, Ms. Glitch held the positions of Vice President, Chief Security Officer of Avangrid Inc. and Executive Director, Information Technology, Chief Information Officer, at Iberdrola USA. Ms. Glitch holds a Bachelor of Science from the State University of New York at Geneseo and a Master of Science in multidisciplinary studies from the Rochester Institute of Technology. She is a former board member of the Midwest Reliability Organization, where she served as Chair of their Organizational Group Oversight Committee. Given her many years of IT experience and her technical expertise in the energy industry, Ms. Glitch is a subject matter expert in IT leadership in the power and utilities sector.

In addition, Stuart Lochray, Executive Vice President, Strategy and Business Development, and Kevin Woodbury, Vice President, Innovation and Technology, lead our innovation initiatives, which include investing in new technologies that may further increase the security of our IT and OT systems.

Management reports on matters related to information security, technology and cybersecurity to the Governance and Sustainability Committee at each quarterly meeting of the committee. These updates include high-risk security items, metrics, disclosure of significant cyber or physical incidents or breaches, and updates related to the cybersecurity programs of the Corporation and each utility, as applicable. At least annually, the Governance and Sustainability Committee reviews, both with the Board and management, the Corporation's IT and OT risk exposures, including cybersecurity, system integrity, data and privacy risks, and the steps the Corporation has taken to monitor or mitigate such exposures around critical Corporation assets, including any related policies, such as cyber incident response plans, data and privacy risk assessments, security measures, system controls and testing, and cyber insurance coverage.

The Cybersecurity Executive Committee of the Corporation is chaired by the Vice President, Chief Information Officer, and its members include: the Chief Executive Officer and all Executive Vice Presidents of the Corporation. The Cybersecurity Executive Committee meets at least twice annually to review various cybersecurity matters which may include objectives, policies, risk assessments, metrics and audits. The Vice President, Chief Information Officer further escalates matters to the Cybersecurity Executive Committee as required under the Cybersecurity Policy or CRMP.

Each utility board of directors, or a designated committee of a utility board, provides oversight of the utility's cybersecurity and physical security programs. The Corporation's Cybersecurity Policy requires that each utility has a cybersecurity steering committee that meets a minimum of twice annually and as otherwise required to address the committees' responsibilities. Each subsidiary steering committee is responsible for reviewing cybersecurity projects, objectives, policies, metrics, cyber incidents or breaches, audits and other matters that arise pertaining to cybersecurity risk management. Further, the Fortis Cybersecurity Policy requires that each utility appoint a member of management to oversee its cybersecurity program and chair its cybersecurity steering committee Such individual is responsible for ensuring compliance with the standards and elements of the Fortis Cybersecurity Policy and implementation of the CRMP. Each utility's management must provide updates at each quarterly meeting of the utility's board or committee with oversight over cybersecurity. These updates include high-risk security items, metrics, disclosure of significant cyber or physical incidents or breaches, and updates related to the cybersecurity program from the applicable steering committee.

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Risk Management and Strategy

CRMP includes a cybersecurity risk framework which establishes enterprise-wide cybersecurity risk management practices for the Corporation and its utilities that identifies and monitors cybersecurity risks and provides insights for remediation of any risks that could lead to cybersecurity incidents throughout the enterprise. The framework includes a process by which key cyber threats and vulnerabilities are identified and sorted by threat actors, motives and potential attack path. Once threats or vulnerabilities are identified, the CRMP assesses and prioritizes them based on the likelihood and potential impact. Under this framework, utilities assess cybersecurity threats and set risk targets that are appropriate for their business. The CRMP is incorporated into, and closely linked with, the overall Fortis enterprise risk management program. When the CRMP highlights a risk, the respective cybersecurity steering committee develops and implements a mitigation roadmap. Monitoring of the mitigation roadmap occurs to ensure the risk is mitigated at an acceptable level. Further, under the Fortis Cybersecurity Policy, utilities are required to have a cybersecurity incident response plan, which must include processes and escalation levels for classifying the severity and actual or potential impact of cybersecurity incidents.

Fortis uses third parties to manage, monitor and assess cyber activities and cybersecurity risks. The use of third parties supplements the Corporation's internal team and provides unbiased assessments. The Corporation further utilizes a variety of tools and sources to oversee and detect risks from cybersecurity threats associated with our use of third-party service providers. These include external monitoring services and information provided by external information sharing services, such as United States and Canadian intelligence services, reputable cybersecurity raters and the Electricity Information Sharing and Analysis Center (E-ISAC) which is operated by NERC.

The Corporation and its utilities are required to maintain a cybersecurity vendor management program to assess and manage information security risks associated with technology and cyber vendors. Such program must be reviewed annually by the applicable cybersecurity steering committee.

The CRMP addresses the requisite technical controls across our critical asset classes for all Fortis companies. The CRMP is aligned with the National Institute of Standards and Technology's (NIST) Cybersecurity Framework, the International Organization for Standardization’s Security Standard (ISO 27001), the Standard of Good Practice for Information Security and NERC’s Critical Infrastructure Protection (NERC CIP) reliability standards. The Corporation's U.S. utilities are required to follow NERC CIP requirements, which include standards targeted at protecting critical information assets that operate the bulk electric system and are audited regularly by their governing RTO.

The CRMP is externally audited every two years based on the NIST Information Security Standards and the results of the audit are reviewed by Management and the Governance and Sustainability Committee.

The Corporation employs a team of cybersecurity professionals with certifications in cybersecurity engineering and cybersecurity operational areas. Fortis continues to invest in training for all employees on the specific technologies utilized by the Corporation and professional development for cybersecurity professionals to keep their knowledge current. As the cybersecurity threat landscape continues to evolve, the Corporation continues to adapt its defensive strategy, deploy new technology and advance its protections from cybersecurity threats, leveraging threat intelligence and external industry practices for continuous improvement and refinement of the CRMP.

SOCIAL AND ENVIRONMENTAL POLICIES

Ethical Conduct

The Fortis Code of Conduct is guided by the Corporation's purpose and values and sets out standards for the ethical conduct of its directors, officers, and employees. The core principles of the Code of Conduct apply across the organization, with each operating subsidiary adopting its own substantially similar code. Fortis and its utilities hold regular Code of Conduct employee training and all Fortis employees and Board members annually certify compliance.

The Code of Conduct is supported by other policies that outline the actions and behaviours expected from management and employees, including the Anti-Corruption Policy and Respectful Workplace Policy. The Corporation also has a Vendor Code of Conduct, which applies to vendors, suppliers, contractors, consultants and other service providers that do business with the Corporation, and a Human Rights Policy which details the Corporation's commitment to respecting and upholding human rights. Fortis has a Speak Up Policy to support and facilitate the anonymous reporting of conduct that may breach the Code of Conduct or other workplace policies. All Fortis operating subsidiaries have policies in place that uphold the Corporation's values as contained in these policies and demonstrate their commitment to ensuring equal opportunity and providing safe, respectful work environments.

Safety and Reliability

Fortis is an industry leader in safety and reliability, with the Corporation's utilities consistently performing above industry averages. Fortis leverages its unique operating model and utility experience to deliver safe and reliable service to its customers and the communities it serves. Senior operational executives from all Fortis utilities meet regularly to share best practices and identify opportunities for collaboration on a range of operational areas including health and safety.

All contractors are required to share Fortis' commitment to conduct work in a safe manner. Contractors must demonstrate a strong safety program with a high level of training centered around risk management. Historical safety performance is a consideration when selecting successful contractors.

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Climate Change and Environmental Matters

The Corporation has made consistent progress to decarbonize its energy mix and deliver cleaner energy to customers, achieving an approximate 38% reduction in scope 1 GHG emissions through 2025 compared to 2019 levels. The decrease in emissions in 2025 was primarily driven by outages at certain TEP fossil fuel generating units during the year. In 2026, Fortis will be reviewing its decarbonization strategy, including potentially establishing new interim emission targets to replace its former targets. This work will be informed by resource planning across the Corporation's utilities, including the new IRPs to be filed in 2026 by TEP and UNS Electric. Fortis remains committed to having a coal-free generation mix in 2032 and advancing toward net-zero emissions by 2050.

Each utility has extensive environmental compliance programs aligned with the ISO 14001 standard, regularly reviews its environmental management systems and protocols, strives for continual performance improvement and sets and reviews its own environmental objectives, targets and programs.

Environmental Regulation and Contingencies

As part of the regulatory process, operating subsidiaries engage with stakeholders, including community groups, regulators and customers, to consult on the potential environmental impact of their operations. Fortis and its subsidiaries are subject to various federal, provincial, state and municipal laws, regulations and guidelines relating to the protection of the environment. Environmental compliance involves significant operating and capital costs. At the Corporation's regulated utilities, prudently incurred costs associated with environmental protection and compliance are generally eligible for recovery in customer rates.

The following environmental contingencies exist as of December 31, 2025:

Mine Reclamation at Generation Facilities Not Operated by TEP. TEP pays ongoing reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is permitted to fully recover these costs from customers and, accordingly, these costs are deferred as a regulatory asset for future recovery.

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing the San Juan and Four Corners power stations. TEP's estimated share of final mine reclamation costs at Four Corners is $4 million upon expiration of the related coal supply agreement, which expires in 2031. TEP's estimated share of final mine reclamation costs at the San Juan generating station, which was retired in June 2022, is $32 million.

Former Manufactured Gas Plant Facilities. Environmental regulations require Central Hudson to investigate sites at which Central Hudson or its predecessors once owned and/or operated manufactured gas plants and, if necessary, remediate these sites. Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated. As at December 31, 2025, an obligation of $100 million was recognized. Central Hudson has notified its insurers and intends to seek reimbursement where insurance coverage exists. Further, as authorized by the New York Public Service Commission, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for manufactured gas plant site investigation and remediation and the associated rate allowances.

CAPITAL STRUCTURE AND DIVIDENDS

Description of Capital Structure

The authorized share capital of the Corporation consists of an unlimited number of common shares without nominal or par value, an unlimited number of first preference shares without nominal or par value and an unlimited number of second preference shares without nominal or par value.

As at February 11, 2026, the Corporation had issued and outstanding 507.4 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.9 million First Preference Shares, Series H; 2.1 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M.

For a summary of the terms and conditions of the Corporation's authorized securities and trading information for the Corporation's publicly listed securities, refer to Exhibit "A" and Exhibit "B" of this AIF.

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Dividends and Distributions

The declaration and payment of dividends on the Corporation's common shares and first preference shares are at the discretion of the Board. Dividends on the common shares are typically paid quarterly, on the first day of March, June, September and December of each year. Dividends on the Corporation's First Preference Shares, Series F, G, H, I, J, K and M are typically also paid quarterly.

In November 2025, Fortis declared an increase in the 2025 fourth quarter dividend per common share of 4.1% to $0.64 per share, or $2.56 on an annualized basis. In December 2025 and February 2026, the Board declared first and second quarter 2026 dividends, respectively, on the common shares of $0.64 per share and on the First Preference Shares, Series F, G, H, I, J, K and M in accordance with the applicable prescribed rate. The first and second quarter 2026 dividends on the common shares and the First Preference Shares, Series F, G, H, I, J, K and M are to be paid on March 1 and June 1, 2026 to holders of record as of February 17 and May 15, 2026, respectively.

The following table summarizes the dividends declared per share for each of the Corporation's class of shares for the past three years.

	2025	2024	2023
Common Shares	2.5100	2.4100	2.3100
First Preference Shares, Series F (1)	1.2250	1.2250	1.2250
First Preference Shares, Series G (2)	1.5308	1.5308	1.3145
First Preference Shares, Series H (3)	0.8990	0.4588	0.4588
First Preference Shares, Series I (4)	1.0277	1.4902	1.5619
First Preference Shares, Series J (1)	1.1875	1.1875	1.1875
First Preference Shares, Series K (5)	1.3673	1.3673	0.9823
First Preference Shares, Series M (6)	1.3733	1.0770	0.9783

(1) The dividend rate on the First Preference Shares, Series F and First Preference Shares, Series J are fixed and do not reset.

(2) The annual dividend per share was reset to $1.5308 for the five-year period from September 1, 2023 up to but excluding September 1, 2028.

(3) The annual dividend per share was reset to $1.0458 for the five-year period from June 1, 2025 up to but excluding June 1, 2030.

(4) The First Preference Shares, Series I are entitled to receive floating rate cumulative dividends, which rate will reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus 1.45%.

(5) The annual dividend per share was reset to $1.3673 for the five-year period from March 1, 2024 up to but excluding March 1, 2029.

(6) The annual dividend per share was reset to $1.3733 for the five-year period from December 1, 2024 up to but excluding December 1, 2029.

For purposes of the enhanced dividend tax credit rules contained in the Income Tax Act (Canada) and any corresponding provincial and territorial tax legislation, all dividends paid on common and preference shares after December 31, 2005 by Fortis to Canadian residents are designated as "eligible dividends". Unless stated otherwise, all dividends paid by Fortis hereafter are designated as "eligible dividends" for the purposes of such rules.

Debt Covenant Restrictions on Dividend Distributions

The Trust Indenture pertaining to the Corporation's $200 million Unsecured Debentures contains a covenant which provides that Fortis shall not declare or pay any dividends (other than stock dividends or cumulative preferred dividends on preferred shares not issued as stock dividends) or make any other distribution on its shares or redeem any of its shares or prepay subordinated debt if, immediately thereafter, its consolidated funded obligations would be in excess of 75% of its total consolidated capitalization.

The Corporation has a $1.3 billion unsecured committed revolving corporate credit facility, maturing July 2030. The credit facility contains a covenant that provides that Fortis shall not: (i) declare, pay or make any ordinary course dividend except that in giving effect to the payment of such ordinary course dividend, it would not result in the Corporation's consolidated debt to consolidated capitalization ratio exceeding 70%; or (ii) declare, pay or make any restricted payments (including special or extraordinary dividends) if, immediately thereafter, its consolidated debt to consolidated capitalization ratio would exceed 65%.

As at December 31, 2025 and 2024, the Corporation was in compliance with its debt covenant restrictions pertaining to dividend distributions, as described above.

Credit Ratings

Credit ratings provide an opinion about the creditworthiness of an issuer and the issuer's capacity and willingness to meet its financial commitments on the obligation in accordance with its terms. Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities and are not recommendations to buy, sell or hold securities. The ratings assigned to securities issued by Fortis and its utilities are reviewed by the agencies on an ongoing basis. Ratings may be subject to revision or withdrawal at any time by the rating organization. The following table summarizes the Corporation's debt credit ratings as at February 11, 2026.

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Company/Security	S&P	Fitch	Morningstar DBRS	Moody's
---	---	---	---	---
Fortis
Unsecured Debt	BBB+	BBB+	A (low), Stable	___(1)
Unsecured Subordinated Notes	BBB	BBB-	BBB, Stable	—
Preference Shares	P-2	BBB-	Pfd-2 (low), Stable	—
Caribbean Utilities - Unsecured Debt	BBB+	—	A (low), Stable	—
Central Hudson - Unsecured Debt	BBB+	BBB+	—	Baa1
FortisAlberta - Unsecured Debt	A-	—	A (low), Stable	Baa1
FortisBC Electric		—
Unsecured Debt	—	—	A (low), Stable	Baa1
Commercial Paper	—	—	R-1 (low), Stable	—
FortisBC Energy		—
Unsecured Debt	—	—	A, Stable	A3
Commercial Paper	—	—	R-1 (low), Stable	—
ITC Holdings		—
Unsecured Debt	BBB+	—	—	Baa2
Commercial Paper	A-2	—	—	Prime-2
ITC Great Plains - First Mortgage Bonds	A+	—	—	A1
ITC Midwest - First Mortgage Bonds	A+	—	—	A1
ITCTransmission - First Mortgage Bonds	A+	—	—	A1
Maritime Electric - Secured Debt	A	—	—	—
METC - Secured Debt	A+	—	—	A1
Newfoundland Power - First Mortgage Bonds	—	—	A, Stable	A2
TEP		—
Unsecured Debt	A-	—	—	A3
Unsecured Bank Credit Facility	—	—	—	A3
UNS Electric		—
Unsecured Debt	—	—	—	Baa1
Unsecured Bank Credit Facility	—	—	—	Baa1
UNS Gas - Unsecured Debt	—	—	—	A3

(1) In January 2026, Moody's withdrew its ratings for Fortis at the Corporation's request. The withdrawal does not impact the subsidiary credit ratings.

In May 2025, Fitch assigned first time issuer and senior unsecured debt ratings of BBB+ to the Corporation with a stable outlook.

In November 2025, S&P confirmed the Corporation's A- issuer and BBB+ senior unsecured debt credit ratings and revised the outlook for the Corporation and certain of its subsidiaries from negative to stable. S&P noted that the change in outlook reflects improvement in the Corporation's FFO to debt ratio and developments at the subsidiaries to mitigate physical risks, namely wildfires.

The table below highlights rating category ranges from highest to lowest quality of such securities for the issuer's credit rating agencies.

Security	S&P	Fitch	Morningstar DBRS	Moody's
Long-term debt	AAA to D (1)	AAA to D (1)	AAA to D (2)	Aaa to C (5)
Short-term debt	A-1 to D (3)	N/A	R-1 to D (2)	Prime-1 to Not Prime (6)
Preference Shares	P-1 to D (4)	AAA to D (1)	Pfd-1 to D (2)	N/A

(1)S&P and Fitch use '+' or '-' designations to indicate the relative standing of securities within a particular rating category. Such modifiers are not added to ratings below CCC or ratings at AAA.

(2)All rating categories contain subcategories of '(high)' or '(low)' other than AAA and D for long-term debt and below R-2 for short-term debt. The absence of either a '(high)' or '(low)' designation indicates the rating is in the middle of a category.

(3)Within only the A-1 category may certain obligations be designated with a '+', indicating that the issuer's capacity to meet its financial commitments under these obligations is extremely strong.

(4)S&P uses 'high' or 'low' designations to indicate the relative standing of securities within a particular rating category. Such modifiers are not added to ratings below P-5.

(5)Moody's applies numerical modifiers 1, 2 and 3 to each generic rating classification from Aa to Caa to indicate relative standing within such classification. The modifier 1 indicates that the security ranks at the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates a ranking at the lower end of that generic rating category.

(6)Short-term obligations with a Not Prime rating do not fall within any of the Prime rating categories.

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S&P

Long-term debt

According to S&P, a rating of A is assigned to long-term debt instruments that are somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than those in higher-rated categories; however, the issuer's capacity to meet its financial obligations is still strong. Debt instruments rated BBB exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the issuer to meet its financial commitments on the obligation.

Short-term debt

According to S&P, a short-term obligation rated A-2 is somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher rating categories; however, the issuer's capacity to meet its financial commitments on the short-term obligation is satisfactory.

Preference shares

According to S&P, a rating of P-2 means that the preference shares have adequate protection parameters; however, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the issuer to meet its financial commitments on the obligation.

Fitch

Long-term debt and preference shares

According to Fitch, a rating of BBB is assigned to long-term obligations that have good credit quality, with the issuer having adequate capacity for payment of financial commitments. The capacity may nevertheless be more vulnerable to adverse business or economic conditions than is the case for higher ratings.

Morningstar DBRS

Long-term debt

According to Morningstar DBRS, a rating of A is assigned to a long-term debt instrument that has good credit quality, with the issuer having substantial capacity to pay its financial obligations, but credit quality is less than AA-rated instruments and may be vulnerable to future events, but qualifying negative factors are considered manageable. Debt instruments rated BBB are considered adequate credit quality, with the issuer having acceptable capacity to pay its financial obligations, but credit quality may be vulnerable to future events.

Short-term debt

According to Morningstar DBRS, a rating of R-1 (low) means that the short-term debt obligation has good credit quality, with the issuer having substantial capacity to repay short-term debt obligations and may be vulnerable to future events, but qualifying negative factors are considered manageable. The overall strength of R-1 (low) rated instruments is not as favourable as those in higher rated categories.

Preference shares

According to Morningstar DBRS, a rating of Pfd-2 (low) means that the preference shares have good credit quality and although the protection of dividends and principal is substantial, earnings, the balance sheet and coverage ratios of companies with Pfd-2 rated securities are not as strong as for those companies with Pfd-1 rated securities.

Moody's

Long-term debt

According to Moody's, a rating of Baa is assigned to long-term debt instruments considered to be of medium-grade quality. Debt instruments rated Baa are subject to moderate credit risk and may possess certain speculative characteristics. Debt instruments rated A are considered upper-medium grade and are subject to low credit risk.

Short-term debt

According to Moody's, a rating of Prime-2 means that an issuer has a strong ability to repay short-term debt obligations.

The Corporation and/or each of its currently rated utilities pay S&P, Fitch, Morningstar DBRS, and/or Moody's an annual monitoring fee and a one-time fee in connection with each rated issuance.

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DIRECTORS AND OFFICERS

The Board has governance guidelines that cover various items, including director tenure. The governance guidelines provide that Directors of the Corporation are to be elected for a term of one year and are eligible for re‑election until the annual meeting of shareholders following the date they turn 72 or until they have served on the Board for 12 years, whichever is earlier. Exceptions may be made by the Board if it is in the best interests of the Corporation and the Director has received solid annual performance evaluations, has the necessary skills and experience and meets the other Board policies and legal requirements for Board service.

The following table sets out the name, province or state and country of residence of each of the Directors of the Corporation and their principal occupations during the five preceding years. Each Director's current term expires at the next annual meeting of shareholders.

Name, Residence, Principal Occupation Within Five Preceding Years		Director Since		Committees (1)(2)
	AC		GS		HR
TRACEY C. BALL, British Columbia, Canada<br><br>Corporate Director.		2014		l		l
PIERRE J. BLOUIN, Quebec, Canada<br><br>Corporate Director.		2015				l	l
LAWRENCE T. BORGARD, Florida, United States of America<br><br>Corporate Director.		2017		l			l
MAURA J. CLARK, New York, United States of America<br><br>Corporate Director.		2015		l			l
MARGARITA K. DILLEY, District of Columbia, United States of America<br><br>Corporate Director.		2016		C			l
JULIE A. DOBSON, Maryland, United States of America<br><br>Corporate Director.		2018				l	C
LISA L. DUROCHER, Ontario, Canada<br><br>Corporate Director. Executive Vice President, Financial and Emerging Services of Rogers Communications Inc. from January 2021 to June 2023.		2021				l	l
DAVID G. HUTCHENS, Arizona, United States of America<br><br>President and Chief Executive Officer of the Corporation.		2021
GREGORY E. KNIGHT, Georgia, United States of America<br><br>Corporate Director. Executive Vice President and Division President, Energy Systems Group and Home Services Plus, CenterPoint Energy, Inc. from 2020 to 2023.		2025		l		l
GIANNA M. MANES, South Carolina, United States of America<br><br>Corporate Director.		2021				C	l
DONALD R. MARCHAND, Alberta, Canada<br><br>Corporate Director. Executive Vice-President of TC Energy from July to November 2021 and Chief Financial Officer of TC Energy and its predecessor TransCanada Corporation from 2010 until July 2021.		2023		l		l
JO MARK ZUREL (Chair), Newfoundland and Labrador, Canada<br><br>Corporate Director.		2016		l		l	l

(1) Audit Committee, Governance and Sustainability Committee and Human Resources Committee. "C" represents Chair.

(2) Mr. Hutchens does not serve on any of the committees because he is the President and Chief Executive Officer of the Corporation but is invited to and attends all committee meetings.

Proceedings

From 2010 to November 2021, Donald Marchand held various senior executive positions with TC Energy (formerly TransCanada Corporation), including serving as Chief Financial Officer from 2010 until July 2021. In 2018, former shareholders of Columbia Pipeline commenced a class action lawsuit in the Delaware Court of Chancery against two Columbia Pipeline executives and TC Energy, alleging breaches of fiduciary duties and material disclosure omissions during the acquisition. On July 10, 2025, the Delaware Court of Chancery granted a final order dismissing the plaintiffs' claims against TC Energy. As a result, this matter is now concluded in TC Energy's favour with no liability and there is no further right of appeal.

From October 2018 until April 2021, Maura Clark served on the board of directors of Garrett Motion Inc. (Garrett), a NYSE listed company. On September 20, 2020, Garrett and certain affiliated companies filed petitions in the United States Bankruptcy Court for the Southern District of New York seeking relief under Chapter 11 of the United States Bankruptcy Code. Garrett emerged from the Chapter 11 proceedings in April 2021.

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The following table sets out the name, province or state, and country of residence of each of the executive officers of Fortis and indicates the office held and principal occupations of the executive officers during the five preceding years.

Name, Residence, Principal Occupation During the Five Preceding Years	Office
DAVID G. HUTCHENS, Arizona, United States of America<br><br>President and Chief Executive Officer since January 2021.	President and Chief Executive Officer
JOCELYN H. PERRY, Newfoundland and Labrador, Canada<br><br>Executive Vice President, Chief Financial Officer since June 2018.	Executive Vice President, Chief Financial Officer
JAMES R. REID, Ontario, Canada<br><br>Executive Vice President, Sustainability and Chief Legal Officer since July 2022. Executive Vice President, Chief Legal Officer and Corporate Secretary from March 2018 to June 2022.	Executive Vice President, Sustainability and Chief Legal Officer
GARY J. SMITH, Newfoundland and Labrador, Canada<br><br>Executive Vice President, Operations and Technology, effective January 1, 2025. Executive Vice President, Operations and Innovation from January 2022 to December 2024, and Executive Vice President, Eastern Canadian and Caribbean Operations from June 2017 to December 2021.	Executive Vice President, Operations and Technology
STUART I. LOCHRAY, Ontario, Canada<br><br>Executive Vice President, Strategy and Business Development, effective January 1, 2025. Senior Vice President, Capital Markets and Business Development from September 2021 to December 2024. Various senior executive roles at Scotiabank in Houston, including Managing Director & Head, US Corporate Investment Banking from September 2019 to September 2021.	Executive Vice President, Strategy and Business Development
STEPHANIE A. AMAIMO, Michigan, United States of America<br><br>Vice President, Investor Relations since October 2017.	Vice President, Investor Relations
JULIE M. AVERY, Newfoundland and Labrador, Canada<br><br>Vice President, Controller since July 2022. Senior Director, Finance from September 2020 to June 2022.	Vice President, Controller
TANYA N. FINLAY, Newfoundland and Labrador, Canada<br><br>Vice President, People and Culture since July 2023. Director, Talent Management and Human Resources from September 2016 to July 2023.	Vice President, People and Culture
KAREN J. GOSSE, Newfoundland and Labrador, Canada<br><br>Vice President, Finance since July 2022. Vice President, Controller from September 2021 to June 2022. Vice President, Treasury and Planning from April 2018 to September 2021.	Vice President, Finance
KERI L. GLITCH, Indiana, United States of America<br><br>Vice President, Chief Information Officer since April 2024. Vice President, Information Technology of FortisUS from June 2023 to March 2024. Vice President, Chief Information Security Officer of MISO from May 2017 to May 2023 and Vice President, Chief Information Security Officer and Chief Digital Officer of MISO from October 2022 to May 2023.	Vice President, Chief Information Officer
KEALEY D. MARTIN, Newfoundland and Labrador, Canada<br><br>Vice President, Sustainability and Climate Strategy since July 2023. Director, Sustainability from November 2019 to July 2023.	Vice President, Sustainability and Climate Strategy
KAREN M. MCCARTHY, Newfoundland and Labrador, Canada<br><br>Vice President, Communications and Government Relations since March 2023. Vice President, Communications and Corporate Affairs from May 2018 to March 2023.	Vice President, Communications and Government Relations
REGAN P. O'DEA, Newfoundland and Labrador, Canada<br><br>Vice President, General Counsel since May 2017.	Vice President, General Counsel
KEVIN D. WOODBURY, Newfoundland and Labrador, Canada<br><br>Vice President, Innovation & Technology since July 2022. Director, Innovation & Technology from September 2021 to June 2022. Director, Business Development from November 2015 to September 2021.	Vice President, Innovation and Technology

The directors and executive officers of Fortis, as a group, beneficially own, directly or indirectly, or exercise control or direction over 473,243 common shares, representing 0.09% of the issued and outstanding common shares of Fortis. The common shares are the only voting securities of the Corporation.

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AUDIT COMMITTEE

Members

The members of the Corporation's Audit Committee are Margarita Dilley (Chair), Tracey Ball, Lawrence Borgard, Maura Clark, Gregory Knight, Donald Marchand and Jo Mark Zurel. All members of the Audit Committee are independent and financially literate as those terms are defined by Canadian and U.S. securities laws and TSX and NYSE requirements. In addition, the Board has determined that Ms. Ball, Ms. Clark, Ms. Dilley, Mr. Marchand and Mr. Zurel are financial experts and has designated each of them as "audit committee financial experts" under U.S. securities laws.

The Corporation's Audit Committee Mandate, effective as of January 1, 2025 is attached as Exhibit "C" to this AIF.

Education and Experience

The education and experience of each Audit Committee member that is relevant to such member's responsibilities as a member of the Audit Committee are set out below.

Committee Member	Relevant Education and Experience
MARGARITA K. DILLEY (Chair)	Ms. Dilley retired from ASTROLINK International LLC in 2004, an international wireless broadband telecommunications company, where she was Vice President and Chief Financial Officer. Ms. Dilley's prior experience includes serving as Director, Strategy & Corporate Development as well as Treasurer for Intelsat. Ms. Dilley graduated from Cornell University with a Bachelor of Arts, from Columbia University with a Master of Arts and from Wharton Graduate School, University of Pennsylvania with a MBA.
TRACEY C. BALL	Ms. Ball retired in September 2014 as Executive Vice President and Chief Financial Officer of Canadian Western Bank Group. Ms. Ball has served on several private and public sector boards, including the Province of Alberta Audit Committee and the Financial Executives Institute of Canada. She graduated from Simon Fraser University with a Bachelor of Arts (Commerce). She is a member of the Chartered Professional Accountants of Alberta and the Chartered Professional Accountants of British Columbia. Ms. Ball was elected as a Fellow of the Chartered Professional Accountants of Alberta in 2007. She holds an ICD.D designation from the Institute of Corporate Directors.
LAWRENCE T. BORGARD	Mr. Borgard retired from Integrys Energy Group in 2015 where he was President and Chief Operating Officer and the Chief Executive Officer of each of Integrys' six regulated electric and natural gas utilities. Mr. Borgard graduated from Michigan State University with a Bachelor of Science (Electrical Engineering) and the University of Wisconsin-Oshkosh with a MBA. He also attended the Advanced Management Program at Harvard University Business School.
MAURA J. CLARK	Ms. Clark retired from Direct Energy, a subsidiary of Centrica plc, in March 2014 where she was President of Direct Energy Business, a leading energy retailer in Canada and the U.S. Previously, Ms. Clark was Executive Vice President of North American Strategy and Mergers and Acquisitions for Direct Energy. Ms. Clark's prior experience includes investment banking and serving as Chief Financial Officer of an independent oil refining and marketing company. Ms. Clark graduated from Queen's University with a Bachelor of Arts in Economics. She is a member of the Association of Chartered Professional Accountants of Ontario.
GREGORY E. KNIGHT	Mr. Knight was Executive Vice President and Division President, Energy Systems Group and Home Services Plus at CenterPoint Energy, Inc., an energy delivery company, from 2020 until his retirement in 2023. In this role, he had oversight over customer operations, information technology, marketing, energy efficiency, economic development, and facilities management. Mr. Knight's prior experience includes serving as Chief Customer Officer, U.S. Energy and Utilities, of National Grid USA Service Company, Inc., and Senior Vice President and Chief Customer Officer, Utility and Commercial Businesses, at CenterPoint Energy, Inc. Mr. Knight earned a Bachelor in American Studies with a Minor in Economics from the University of Colorado at Boulder. He has also completed the executive management program at Rice University’s Jesse H. Jones Graduate School of Business in Houston and has a certificate in audit committee governance from Harvard Business School’s Corporate Board Director Program.
DONALD R. MARCHAND	Mr. Marchand was Executive Vice President of TC Energy, a leading North American energy infrastructure company, from July 2021 until his retirement in November 2021. He served as Chief Financial Officer of TC Energy and its predecessor, TransCanada Corporation, from 2010 until July 2021, with additional responsibility for Strategy and Corporate Development from 2015 to 2017 and from 2020 to 2021. During his 27-year tenure with the company, Mr. Marchand led many of its financial functions, including treasury, finance, accounting, taxation, risk management and investor relations. Mr. Marchand graduated from the University of Manitoba with a Bachelor of Commerce degree and subsequently qualified as a Chartered Accountant and Chartered Financial Analyst. He is a member of the Chartered Professional Accountants of Alberta, the CFA Institute and the Calgary Society of Financial Analysts.
JO MARK ZUREL	Mr. Zurel was the president of Stonebridge Capital Inc., a private investment company, from 2006 to March 2019. From 1998 to 2006, Mr. Zurel was Senior Vice President and Chief Financial Officer of CHC Helicopter Corporation. Mr. Zurel graduated from Dalhousie University with a Bachelor of Commerce and is a Fellow of the Association of Chartered Professional Accountants of Newfoundland and Labrador. He holds an ICD.D designation from the Institute of Corporate Directors.
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Pre-Approval Policies and Procedures

The Audit Committee has established a policy that requires pre-approval of all audit and non-audit services provided to the Corporation and its subsidiaries by the Corporation's external auditor. The Pre-Approval Policy for Independent Auditor Services describes the services that may be contracted from the external auditor and the related limitations and authorization procedures. This policy defines prohibited services, including but not limited to bookkeeping, valuations, internal audit and management functions, which may not be contracted from the external auditor and establishes an annual limit for permissible non-audit services not greater than the total fee for audit services. Audit Committee pre-approval is required for all services provided by the external auditor.

External Auditor Service Fees

The aggregate fees billed by the Corporation's external auditors during each of the last two fiscal years are set out in the following table.

		Deloitte LLP
($ thousands)	Description of Fee Category	2025	2024
Audit Fees	Core audit services	11,458	11,111
Audit-Related Fees	Assurance and related services that are reasonably related to the audit or review of the Financial Statements and are not included under Audit Fees	1,666	1,775
Tax Fees	Services related to tax compliance, planning and advice	113	107
All Other Fees	Services which are not Audit Services, Audit-Related Fees or Tax Fees	178	356
Total		13,415	13,349

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar in Canada for the common shares and first preference shares of Fortis is Computershare Trust Company of Canada in Montréal and Toronto.

The co-transfer agent and co-registrar in the U.S. for the common shares is Computershare Trust Company, N.A. in Canton, MA, Jersey City, NJ and Providence, RI.

Computershare Trust Company of Canada

14th Floor, 320 Bay Street

Toronto, ON M5H 4A6

T: 514.982.7555 or 1.866.586.7638

F: 416.263.9394 or 1.888.453.0330

E: service@computershare.com

W: www.investorcentre.com/fortisinc

Computershare Trust Company, N.A.

Attn: Shareholder Services

Overnight Mail Delivery: 150 Royall Street, Canton, MA 02021

Regular Mail Delivery (U.S. Shareholders): P.O. Box 43078, Providence, RI 02940-3078

Regular Mail Delivery (Shareholders outside the U.S.): P.O. Box 43006, Providence, RI 02940-3006

T: 1.781.575.2000 or 1.877.373.6374

E: service@computershare.com

INTERESTS OF EXPERTS

The Corporation's auditors, Deloitte LLP, is independent with respect to the Corporation within the meaning of the U.S. Securities Act of 1933 and the applicable rules and regulations thereunder adopted by the SEC and the Public Company Accounting Oversight Board (United States) and within the meaning of the rules of professional conduct of the Chartered Professional Accountants of Newfoundland and Labrador.

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ADDITIONAL INFORMATION

Additional information relating to the Corporation can be found on the Corporation's website at www.fortisinc.com, on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. The information contained on, or accessible through, any of these websites is not incorporated by reference into this document unless otherwise stated.

Additional financial information is provided in the Corporation's MD&A and Financial Statements, which are incorporated by reference in this AIF and can be found on the Corporation's website at www.fortisinc.com, on SEDAR+ and on EDGAR.

Further additional information, including officers' and directors' remuneration and indebtedness, principal holders of the securities of Fortis, options to purchase securities and interests of insiders in material transactions, where applicable, is contained in the Management Information Circular of Fortis dated March 21, 2025 for the May 8, 2025 annual general meeting of shareholders.

Requests for additional copies of the above‑mentioned documents, as well as this AIF, should be directed to the Executive Vice President, Sustainability and Chief Legal Officer, Fortis, P.O. Box 8837, St. John's, NL, A1B 3T2 (telephone: 709.737.2800).

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EXHIBIT A:

SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SECURITIES

Common Shares

Dividends on common shares are declared at the discretion of the Board. Holders of common shares are entitled to dividends on a pro rata basis if, as and when declared by the Board. Subject to the rights of the holders of the first preference shares and second preference shares and any other classes of shares of the Corporation entitled to receive dividends in priority to or ratably with the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other classes of shares of the Corporation.

On the liquidation, dissolution or winding-up of Fortis, holders of common shares are entitled to participate ratably in any distribution of assets of Fortis, subject to the rights of holders of first preference shares and second preference shares and any other classes of shares of the Corporation entitled to receive the assets of the Corporation on such a distribution in priority to or ratably with the holders of the common shares.

Holders of the common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Fortis, other than separate meetings of holders of any other classes or series of shares, and are entitled to one vote in respect of each common share held at such meetings.

Preference Shares

First Preference Shares

The following is a summary of the material rights, privileges, conditions and restrictions attached to the first preference shares as a class. The specific terms of the first preference shares, including the currency in which first preference shares may be purchased and redeemed and the currency in which any dividend is payable, if other than Canadian dollars, and the extent to which the general terms described herein apply to those first preference shares, is or will be as set forth in the applicable articles of amendment of Fortis relating to such series.

Issuance in Series

The Board may from time to time issue first preference shares in one or more series. Prior to issuing shares in a series, the Board is required to fix the number of shares in the series and determine the designation, rights, privileges, restrictions and conditions attaching to that series of first preference shares.

Priority

The shares of each series of first preference shares rank on a parity with the first preference shares of every other series and in priority to all other shares of Fortis, including the second preference shares, as to the payment of dividends, return of capital and the distribution of assets in the event of the liquidation, dissolution or winding-up of Fortis, whether voluntary or involuntary, or any other distribution of the assets of Fortis among its shareholders for the purpose of winding-up its affairs.

Each series of first preference shares participates ratably with every other series of first preference shares in respect of accumulated cumulative dividends and returns of capital, if any, cumulative dividends, whether or not declared and any amount payable on the return of capital in respect of a series of first preference shares, if not paid in full.

Voting

The holders of the first preference shares are not entitled to any voting rights as a class except to the extent that voting rights may from time to time be attached to any series of first preference shares and except as provided by law or as described below under the heading "Modification". At any meeting of the holders of first preference shares, each holder shall have one vote in respect of each first preference share held.

Redemption

Subject to the provisions of the Corporations Act (Newfoundland and Labrador) and any provisions relating to any particular series, Fortis, upon giving proper notice, may redeem out of capital or otherwise at any time, or from time to time, the whole or any part of the then outstanding first preference shares of any one or more series on payment for each such first preference share at such price or prices as may be applicable to such series. Subject to the foregoing, if only a part of the then outstanding first preference shares of any particular series is at any time redeemed, the shares to be redeemed will be selected by lot in such manner as the directors or the transfer agent for the first preference shares, if any, decide, or if the directors so determine, may be redeemed pro rata, disregarding fractions.

Modification

The class provisions attached to the first preference shares may only be amended with the prior approval of the holders of the first preference shares, in addition to any other approvals required by the Corporations Act (Newfoundland and Labrador) or any other statutory provisions of like or similar effect in force from time to time.

The approval of the holders of the first preference shares with respect to any and all matters may be given by at least two-thirds of the votes cast at a meeting of the holders of the first preference shares duly called for that purpose.

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First Preference Shares Authorized and Outstanding

The following table summarizes the series of first preference shares as of February 11, 2026.

	Authorized	Issued and Outstanding	Dividend Rate (%)	Annual Dividend ($) (1)	Reset Dividend Yield<br><br>(%)	Redemption and/or Conversion Option Date (2)	Redemption Value ($)	Right to Convert on a One for One Basis
Perpetual Fixed Rate
Series F	5,000,000	5,000,000	4.90	1.2250	—	Currently Redeemable	25.00	—
Series J	8,000,000	8,000,000	4.75	1.1875	—	Currently Redeemable	25.00	—
Fixed Rate Reset (3)
Series G	9,200,000	9,200,000	6.12	1.5308	2.13	September 1, 2028	25.00	—
Series H (4)(5)	10,000,000	7,902,614	4.18	1.0458	1.45	June 1, 2030	25.00	Series I
Series K (4)	12,000,000	10,000,000	5.47	1.3673	2.05	March 1, 2029	25.00	Series L
Series M (4)	24,000,000	24,000,000	5.49	1.3733	2.48	December 1, 2029	25.00	Series N
Floating Rate Reset (4) (6)
Series I	10,000,000	2,097,386	(6)	—	1.45	June 1, 2030	25.00	Series H
Series L	12,000,000	—	—	—	—	—	—	Series K
Series N	24,000,000	—	—	—	—	—	—	Series M

(1)Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board, payable in equal installments on the first day of each quarter.

(2)On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding first preference shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the first preference shares that reset, on every fifth anniversary date thereafter.

(3)On the redemption and/or conversion option date, and on each five-year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield.

(4)On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their shares into an equal number of Cumulative Redeemable first preference shares of a specified series.

(5)The annual dividend per share of the First Preference Shares, Series H was reset from $0.4588 to 1.0458 for a five year period from June 1, 2025 up to, but excluding, June 1, 2030.

(6)The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.

Second Preference Shares

The rights, privileges, conditions and restrictions attaching to the second preference shares are substantially identical to those attaching to the first preference shares, except that the second preference shares are junior to the first preference shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Fortis in the event of a liquidation, dissolution or winding up of Fortis.

The specific terms of the second preference shares, including the currency in which second preference shares may be purchased and redeemed and the currency in which any dividend is payable, if other than Canadian dollars, and the extent to which the general terms described herein apply to those second preference shares, will be as set forth in the applicable articles of amendment of Fortis relating to such series.

As of February 11, 2026, there were no second preference shares issued and outstanding.

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EXHIBIT B:

MARKET FOR SECURITIES

Common Shares

The common shares are traded on the TSX in Canada and on the NYSE in the U.S., in each case under the symbol FTS. The following table sets forth the reported high and low trading prices and trading volumes, on a monthly basis for the year ended December 31, 2025, for the common shares on the TSX and NYSE in Canadian Dollars and U.S. Dollars, respectively.

	2025 Trading Prices and Volumes – Common Shares
	TSX			NYSE
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	62.66	57.98	31,713,232	43.56	40.32	8,056,271
February	64.39	60.50	41,124,193	45.46	41.24	16,596,303
March	66.26	62.35	36,591,500	46.08	43.47	11,588,784
April	68.38	61.32	38,764,905	49.65	43.28	14,687,687
May	69.24	64.06	42,559,783	50.06	45.87	12,793,130
June	67.21	63.85	26,723,874	49.03	46.57	10,424,028
July	68.24	63.54	24,968,232	49.38	46.46	12,122,156
August	71.02	67.84	32,987,088	51.45	49.34	12,360,404
September	70.68	67.15	25,128,216	50.79	48.64	11,499,316
October	73.43	69.26	26,016,469	52.47	49.60	15,091,973
November	74.00	69.81	43,145,538	52.83	49.60	15,444,034
December	73.43	69.06	33,634,201	52.56	49.99	15,624,470

Preference Shares

The First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series I; First Preference Shares, Series J; First Preference Shares, Series K; and First Preference Shares, Series M of Fortis are listed on the TSX under the symbols FTS.PR.F; FTS.PR.G; FTS.PR.H; FTS.PR.I; FTS.PR.J; FTS.PR.K and FTS.PR.M, respectively.

The following tables set forth the reported high and low trading prices and volumes for the First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series I; First Preference Shares, Series J; First Preference Shares, Series K; and First Preference Shares, Series M on a monthly basis for the year ended December 31, 2025.

	2025 Trading Prices and Volumes – First Preference Shares
	First Preference Shares, Series F			First Preference Shares, Series G
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	22.49	21.34	50,570	22.96	22.34	163,010
February	22.83	21.81	25,940	23.10	21.99	133,814
March	22.71	22.03	27,569	22.30	21.80	64,895
April	22.27	20.51	34,129	22.45	20.26	141,275
May	21.75	20.99	25,711	22.80	21.74	192,531
June	22.58	21.59	28,287	22.99	22.55	127,618
July	23.14	21.82	21,088	24.45	22.92	237,785
August	23.52	22.79	24,888	24.45	23.53	89,364
September	24.00	23.06	106,538	24.60	23.86	107,495
October	23.97	23.25	87,496	25.01	24.31	84,137
November	24.19	22.89	35,646	25.34	23.57	118,508
December	24.30	23.42	69,585	25.10	24.41	96,950
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	First Preference Shares, Series H			First Preference Shares, Series I
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Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	17.61	16.30	163,633	17.67	16.49	52,787
February	16.90	16.26	225,213	17.35	16.22	90,594
March	16.40	15.72	193,868	16.60	16.00	59,183
April	16.40	14.64	128,818	16.55	14.72	39,797
May	17.35	15.60	77,084	16.89	15.80	29,829
June	17.90	16.69	124,905	16.95	16.31	14,895
July	18.95	17.90	268,731	18.30	16.69	68,521
August	19.25	18.30	75,104	17.75	17.05	23,899
September	18.75	18.40	516,813	17.74	17.11	21,365
October	18.99	18.71	753,999	17.99	17.33	37,604
November	18.98	18.25	118,658	17.80	17.20	19,865
December	19.35	18.74	306,528	18.00	17.20	35,683
	First Preference Shares, Series J			First Preference Shares, Series K
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	21.33	20.16	107,651	21.44	20.87	116,370
February	21.17	20.41	61,401	21.50	20.64	91,737
March	21.72	20.87	95,316	21.25	20.62	121,116
April	21.18	19.70	63,085	21.60	19.02	124,062
May	21.23	20.29	26,049	21.58	20.65	128,572
June	21.47	20.69	45,403	22.28	21.50	88,559
July	22.76	21.05	47,312	23.30	21.91	326,504
August	22.78	22.05	43,039	23.26	22.50	165,061
September	23.10	21.75	70,296	22.98	22.42	147,560
October	23.14	22.30	46,623	23.69	22.77	119,325
November	23.35	21.85	144,398	23.97	21.85	110,505
December	23.15	22.32	101,153	23.98	22.85	120,080
	First Preference Shares, Series M
Month	High ($)	Low ($)	Volume
January	21.78	21.25	668,955
February	21.72	21.27	470,575
March	21.69	21.18	635,306
April	22.00	19.41	566,728
May	21.94	20.72	915,740
June	23.33	21.94	167,509
July	24.10	23.02	261,698
August	24.15	23.24	250,115
September	24.15	23.51	514,366
October	24.39	23.94	253,957
November	24.95	23.85	224,467
December	24.96	24.45	226,516
FORTIS INC.	December 31, 2025	34
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EXHIBIT C:

AUDIT COMMITTEE MANDATE

(effective January 1, 2025)

1.0 PURPOSE AND AUTHORITY

1.1 The purpose of the Committee is to advise and assist the Board in fulfilling its oversight responsibilities relating to, among other things:

a.the integrity of the Corporation's financial statements, financial disclosures and internal controls over financial reporting and disclosure controls and procedures;

b.the Corporation's compliance with related legal and regulatory requirements;

c.the qualifications, independence and performance of the Independent Auditor and Internal Auditor, together with the compensation of the Independent Auditor;

d.the Corporation's ERM Program and the management and mitigation of significant risks identified thereunder;

e.the related policies of the Corporation set out herein; and

f.other matters set out herein or otherwise delegated to the Committee by the Board.

1.2 Consistent with this purpose, the Committee shall encourage continuous improvement of, and foster adherence to, the Corporation's policies, procedures and practices at all levels. The Committee shall also provide for open communication among the Independent Auditor, the Internal Auditor, Management and the Board.

1.3 To perform its duties and responsibilities, the Committee has the authority to: (i) conduct investigations into any matters within its scope of responsibility; (ii) have unrestricted access to information, management and employees and books and records of the Corporation and its affiliates; and (iii) directly access and communicate with the Independent Auditor and Internal Auditor.

2.0 DEFINITIONS

2.1 In this Mandate:

a."Board" means the board of directors of the Corporation;

b."Chair" means the Chair of the Committee;

c."Committee" means the audit committee of the Board;

d."Core Audit Services" means services necessary to: (i) audit the Corporation's annual consolidated or non-consolidated financial statements; (ii) review the Corporation's condensed consolidated interim financial statements; and (iii) audit internal controls over financial reporting in accordance with the requirements of all applicable laws, regulations and professional standards;

e."Corporation" means Fortis Inc.;

f."CPAB" means the Canadian Public Accountability Board or its successor;

g."Director" means a member of the Board;

h."ERM Program" means the Corporation's Enterprise Risk Management Program that incorporates an effective risk management framework to identify, evaluate, manage, monitor and communicate key corporate risks;

i."Financial Expert" means an "audit committee financial expert" as defined in SEC Regulation S-K;

j."Financially Literate" means having the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breath and complexity of the issues that can reasonably be expected to be present in the Corporation's financial statements;

k."Governance and Sustainability Committee" means the governance and sustainability committee of the Board;

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l."Independent" means, in the context of a Member and in accordance with all applicable laws and stock exchange requirements, being free from any direct or indirect material relationship with the Corporation and its subsidiaries which, in the view of the Board, could reasonably be expected to interfere with the exercise of a Member's independent judgment;

m."Independent Auditor" means the firm of chartered professional accountants, registered with the CPAB and the PCAOB, and appointed by the shareholders to act as external auditor;

n."Internal Auditor" means the person(s) employed or engaged by the Corporation to perform the internal audit function of the Corporation;

o."Management" means the senior officers of the Corporation;

p."Mandate" means this mandate of the Committee;

q."MD&A" means the Corporation's management discussion and analysis prepared in accordance with the requirements of National Instrument 51-102 and the SEC in respect of the Corporation's annual consolidated and interim condensed consolidated financial statements;

r."Member" means a Director appointed to the Committee;

s."NYSE" means the New York Stock Exchange;

t."PCAOB" means the Public Company Accounting Oversight Board or its successor;

u."Related Party Transactions" means those transactions required to be disclosed under Items 404(a) and 404(b) of SEC Regulation S-K and required to be evaluated by an appropriate group within the Corporation pursuant to Section 314.00 of the NYSE Listed Company Manual and all applicable laws and stock exchange requirements which include, without limitation, transactions between: (i) executive officers, directors, principal shareholders or their immediate family members; and (ii) the Corporation or any of its subsidiaries; and

v."SEC" means the United States Securities and Exchange Commission.

3.0 ESTABLISHMENT AND COMPOSITION OF COMMITTEE

3.1 The Committee shall be comprised of three (3) or more Directors, each of whom is Independent and Financially Literate. No Member may be a member of Management or an employee of the Corporation or of any affiliate of the Corporation. The Board shall appoint to the Committee at least one (1) Director who is a Financial Expert.

3.2 Members shall be appointed annually by the Board, or as otherwise necessary, provided, however, that each Director serving as a Member shall continue to serve until such Member resigns, is removed or has a successor appointed.

3.3 The Board may appoint a Member to fill a vacancy which occurs on the Committee between annual elections of Directors. If a vacancy exists on the Committee, the remaining Members shall exercise all of the powers of the Committee so long as at least three (3) Members remain in office.

3.4 Any Member may be removed from the Committee or replaced by a resolution of the Board.

3.5 No Member shall serve on more than three (3) public company audit committees (inclusive of the Corporation) without the prior approval of the Board.

3.6 The Board shall appoint a Chair on the recommendation of the Corporation's Governance and Sustainability Committee, or such other committee as the Board may authorize. The Chair shall continue in that role until a successor is appointed. The Board shall periodically rotate the Chair and shall make reasonable efforts to rotate the Chair every four (4) years.

4.0 COMMITTEE MEETINGS

4.1 The Committee shall meet at least quarterly and at such other times as it deems appropriate. Meetings of the Committee shall be held at the call of: (i) the Chair; (ii) any two Members; or (iii) the Independent Auditor.

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4.2 The Chief Executive Officer, the Chief Financial Officer, the Independent Auditor and the Internal Auditor shall receive notice of and, unless otherwise determined by the Chair, shall be entitled to attend all meetings of the Committee. For clarity, the Independent Auditor must attend the Committee meetings at which the Corporation's annual audited consolidated and non-consolidated financial statements and unaudited condensed consolidated interim financial statements are reviewed.

4.3 A quorum at any meeting of the Committee shall be three (3) Members.

4.4 Each Member shall have the right to vote on matters that come before the Committee.

4.5 Matters to be determined by the Committee shall be decided by a majority of votes cast at a meeting of the Committee where such matter is considered. Actions of the Committee may also be taken by instruments in writing signed by all of the Members.

4.6 The Chair shall act as chair of all meetings of the Committee at which the Chair attends, otherwise the Members present at the meeting shall appoint one of their number to act as chair of the meeting.

4.7 Unless otherwise determined by the Chair, the Corporate Secretary of the Corporation shall act as secretary of all meetings of the Committee.

4.8 The Committee shall periodically meet separately with Management, the Internal Auditor and the Independent Auditor to discuss any matters that the Committee or any of these persons or firms believes should be discussed privately. The Committee shall conduct in camera sessions without Management present at each meeting of the Committee.

4.9 The Committee may invite any Directors, officers or employees of the Corporation or any other person to attend the meetings of the Committee to assist in the discussion and examination of the matters under consideration by the Committee.

4.10 Subject to section 5.4, the Committee may delegate authority to individual Members or subcommittees, if deemed appropriate.

5.0 DUTIES AND RESPONSIBILITIES OF THE COMMITTEE

A. Independent Auditor

5.1 In consultation and coordination with the subsidiary audit committees, the Committee shall be directly responsible for the selection and appointment (through a recommendation to the Board for the appointment by the shareholders), compensation and retention of the Independent Auditor.

5.2 The Committee shall oversee the work of the Independent Auditor in connection with the Core Audit Services and any other services performed for the Corporation. The Independent Auditor shall report directly to the Committee and the Committee has the authority to communicate directly with the Independent Auditor.

5.3 The Committee shall oversee the resolution of any disagreements between Management and the Independent Auditor. The Committee shall discuss with the Independent Auditor the matters required to be discussed under PCAOB Auditing Standard No. 1301 relating to the conduct of the audit, including any problems or difficulties encountered and Management's responses thereto and any restrictions on the scope of activities or access to requested information.

5.4 The Committee shall pre-approve all services performed by the Independent Auditor in accordance with the Corporation's Pre-Approval Policy for Independent Auditor Services. For any service, other than Core Audit Services, requiring specific pre-approval in accordance with such policy, the Committee may delegate pre-approval authority to one or more of its Members. Currently, pre-approval authority in this regard has been delegated to the Chair or, in that person's absence, the Chair of the Board who is a Member. Delegates must report all pre-approval decisions to the Committee at the next scheduled meeting.

5.5 The Committee shall annually obtain and review a report from the Independent Auditor delineating all relationships between the Independent Auditor and the Corporation and its subsidiaries in accordance with Item 407(d) of SEC Regulation S-K and Section 303A.07 of the NYSE Listed Company Manual and addressing the matters set forth in PCAOB Rule 3526 and all applicable laws and stock exchange requirements and any other applicable regulations and professional standards. The Committee shall use reasonable efforts, including discussion with the Independent Auditor, to satisfy itself as to the Independent Auditor's independence in accordance with Canadian generally accepted auditing standards and PCAOB standards, the applicable requirements and interpretative guidance of SEC Regulation S-X and any other applicable regulations and professional standards. The Committee shall discuss any potential independence issues with the Board and recommend any action that the Committee deems appropriate.

5.6 The Committee shall review and evaluate the qualifications, independence and performance of the Independent Auditor and its lead engagement partner. Without limiting the foregoing, the Committee shall:

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a.review and discuss with Management and separately with the Independent Auditor the results of the Corporation's annual Independent Auditor assessment process; and

b.at least annually, obtain and review a report from the Independent Auditor describing the firm's internal quality control processes and procedures, including any material issues raised by the most recent internal quality control review or peer review, or by any inquiry or investigation by governmental or professional authorities (including without limitation the PCAOB and the CPAB) within the preceding five (5) years with respect to independent audits carried out by the Independent Auditor, and any steps taken to address such issues.

The Committee shall discuss any material issues identified with the Board and recommend any action that the Committee deems appropriate.

5.7 The Committee shall ensure the rotation of the audit partner(s) as required by applicable law and consider the need for rotation of the Independent Auditor.

5.8 The Committee shall meet with the Independent Auditor prior to the audit to discuss the planning and staffing of the audit, including the general approach, scope, areas subject to significant risk of material misstatement, estimated fees and other terms of engagement.

B. Financial Reporting

5.9 In consultation with Management, the Independent Auditor and the Internal Auditor, the Committee shall review and satisfy itself as to: (i) the integrity of the Corporation's internal and external financial reporting processes; (ii) the adequacy and effectiveness of the Corporation's disclosure controls and procedures (including those pertaining to the review of disclosure containing financial information extracted or derived from the Corporation's financial statements) and internal controls over financial reporting; and (iii) the competence of the Corporation's personnel responsible for accounting and financial reporting. Without limiting the generality of the foregoing, the Committee shall receive and review:

a.reports regarding: (i) critical accounting estimates, policies and practices; (ii) goodwill impairment testing; (iii) derivatives and hedges; (iv) any reserves, accruals, provisions and estimates that may have a material effect on the Corporation's financial statements; (v) any pro forma, adjusted or restated financial information, forecasts, or projections; and (vii) the effect of regulatory and accounting initiatives, as well as off-balance sheet arrangements, on the Corporation's financial statements;

b.analyses by Management and the Independent Auditor regarding significant financial reporting issues and judgments made in connection with the preparation of the Corporation's consolidated financial statements including: (i) alternative treatments of financial information within generally accepted accounting principles related to material matters that have been discussed with Management, their ramifications and the treatment preferred by the Independent Auditor; (ii) major issues regarding auditing and accounting principles and presentations, including significant changes in the selection or application of auditing and accounting principles; and (iii) major issues regarding the adequacy of the Corporation's internal controls over financial reporting and disclosure controls and procedures and any specific audit steps adopted in light of material weaknesses or significant deficiencies in such controls; and

c.other material written communication between Management and the Independent Auditor.

5.10 The Committee shall, prior to external release, if applicable, review and discuss with Management and the Independent Auditor, and with others as it deems appropriate:

a.the Corporation's annual audited consolidated and non-consolidated financial statements and unaudited condensed consolidated interim financial statements and the Independent Auditor's related attestation reports, as well as any related MD&As;

b.Management's report and the Independent Auditor's audit report on internal controls over financial reporting;

c.significant reports or summaries thereof pertaining to the Corporation's processes for compliance with the requirements of the Sarbanes Oxley Act of 2002 with respect to internal controls over financial reporting;

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d. the Independent Auditor's quarterly review reports and annual audit results report summarizing the scope, status, results and recommendations of the quarterly reviews of the Corporation's condensed consolidated interim financial statements and of the audit of the Corporation's annual consolidated financial statements and related audit of internal controls over financial reporting, and also containing at least: (i) the communications with respect thereto between the Independent Auditor and the Committee required by PCAOB Auditing Standard No. 1301 and any other applicable regulations and professional standards, including without limitation schedules of corrected and uncorrected account and disclosure misstatements and significant deficiencies and material weaknesses in internal controls; (ii) the (at least) annual independence communication required by PCAOB Rule 3526; (iii) the Management representation letter; and (iv) the documentation and communication required quarterly from the Independent Auditor under the Corporation's Pre-Approval Policy for Independent Auditor Services;

e. the report to shareholders contained in the Corporation's annual report; and

f. any other document that the Committee determines should be reviewed and discussed with Management and the Independent Auditor or for which a legal or regulatory requirement in that regard exists.

5.11 The Committee shall, prior to external release, review and discuss with Management and with others as it deems appropriate, the financial information to be disclosed in the Corporation's interim and annual earnings releases or other news releases.

5.12 The Committee shall recommend the Corporation's annual audited consolidated financial statements together with the Independent Auditor's audit report thereon and on internal controls over financial reporting, Management's report on internal controls over financial reporting and disclosure controls and procedures, MD&As, earnings releases, and reports to shareholders for approval by the Board and subsequent external release, as well as inclusion of the noted financial statements in the Corporation's annual reports on Form 40-F. The Committee shall approve the external release of the Corporation's unaudited condensed consolidated interim financial statements and related interim MD&As and earnings releases on behalf of the Board.

5.13 The Committee shall, prior to external release, review and discuss with Management and with others as it deems appropriate, and recommend for approval by the Board:

a.any future oriented financial information, financial outlooks, and earnings or dividend guidance to be provided by the Corporation;

b.the Annual Information Form and Management Information Circular to be filed by the Corporation;

c.any prospectus or other offering documents and documents related thereto for the issuance of securities by the Corporation; and

d.other disclosure documents to be released publicly by the Corporation containing or derived from financial information.

5.14 The Committee shall review, discuss with Management and with others as it deems appropriate, the disclosures made by the Chief Executive Officer and Chief Financial Officer of the Corporation pursuant to their certification of the Corporation's annual and quarterly reports regarding significant deficiencies or material weaknesses in the design or operation of internal controls over financial reporting and any alleged fraud involving Management or other employees.

5.15 The Committee shall ensure that action is taken by Management to remediate any material weaknesses or significant deficiencies identified in the design or operation of internal controls over financial reporting in a timely manner.

5.16 The Committee shall use reasonable efforts to satisfy itself as to the appropriateness of the Corporation's material financing, capital and tax structures.

5.17 The Committee shall review, discuss with Management and with others as it deems appropriate, financial information provided to analysts and ratings agencies. Such discussions may be in general terms (i.e., discussion of the types of information to be disclosed and the types of presentations to be made) and need not occur in advance of each release of information.

5.18 The Committee shall prepare, or cause to be prepared, any reports of the Committee required to be included in the Corporation's public disclosures or otherwise required by applicable laws.

5.19 The Committee shall review, discuss with Management and with others as it deems appropriate, and approve all Related Party Transactions and the disclosure thereof.

C. Internal Audit

5.20 The Committee shall be responsible for the appointment and oversight of the Internal Auditor in accordance with the Policy on the Role of the Internal Audit Function and has the authority to communicate directly with the Internal Auditor.

5.21 The Committee shall review and discuss with the Internal Auditor and others as it deems appropriate, and approve the annual internal audit plan.

FORTIS INC.	December 31, 2025	39
Annual Information Form
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5.22 The Committee shall review and discuss with Management, the Internal Auditor and others as it deems appropriate, the quarterly internal audit reports prepared for the Committee (which shall incorporate all significant activities of the internal audit function for the quarter) and any Management responses thereto.

5.23 The Committee shall periodically discuss with the Internal Auditor any significant difficulties, disagreements with Management, or scope restrictions encountered in the course of carrying out the work of the internal audit function.

5.24 The Committee shall periodically discuss with the Internal Auditor the internal audit function's responsibility, budget, staffing and compensation.

5.25 The Committee shall satisfy itself as to the performance of the internal audit function and the integrity and qualifications of its staff.

D. Risk Management and Other

5.26 The Committee shall be responsible for the oversight of the ERM Program, including ensuring that Management has in place policies, processes, procedures and the appropriate organizational structure, budget and resources to manage significant risks, and shall report any actions or findings of the ERM Program to the Board.

5.27 The Committee shall review and discuss with Management and others as it deems appropriate Management's report regarding identifying, assessing, managing and mitigating significant risks and related matters identified pursuant to the ERM Program.

5.28 The Committee shall satisfy itself as to the appropriateness of the Corporation's internal controls and processes associated with the release of any sustainability disclosures and may consult with the third party retained by the Corporation to provide independent assurance in respect of the Corporation's sustainability disclosures.

5.29 The Committee shall review and discuss with Management and others as it deems appropriate the quarterly report prepared by Management regarding significant litigation and other material legal matters that could have a significant impact on the Corporation or its financial statements.

5.30 The Committee shall be responsible for the oversight of the Corporation's insurance programs, any renewals or replacements thereof, including in respect of directors' and officers' insurance and indemnification of Directors.

E. Policies and Mandate

5.31 The Committee is responsible for the oversight of the following policies:

a.Policy on Reporting Allegations of Suspected Improper Conduct and Wrongdoing (Speak Up Policy), including overseeing procedures for the receipt, retention, and treatment of complaints regarding accounting, internal controls, or auditing matters as well as procedures for confidential, anonymous submissions by employees regarding questionable accounting or auditing matters as required by applicable law;

b.Derivative Instruments and Hedging Policy;

c.Pre-Approval Policy for Independent Auditor Services;

d.Guidelines for Hiring Employees or Former Employees of the Independent Auditor;

e.Policy on the Role of the Internal Audit Function;

f.Disclosure Policy; and

g.other policies that may be established from time-to-time regarding accounting, financial reporting, disclosure controls and procedures, internal controls over financial reporting, oversight of the external audit of the Corporation's financial statements, and oversight of the internal audit function.

5.32 The Committee shall periodically review this Mandate and the policies in Section 5.30 and recommend any necessary amendments to the Governance and Sustainability Committee for consideration and recommendation to the Board for approval, as deemed appropriate.

FORTIS INC.	December 31, 2025	40
Annual Information Form
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6.0 REPORTING

6.1 The Chair, or another designated Member, shall report to the Board at each regular meeting on those matters that were dealt with by the Committee since the last regular meeting of the Board.

7.0 REMUNERATION OF MEMBERS

7.1 Members and the Chair shall receive such remuneration for their service on the Committee as the Board may determine from time to time, having considered the recommendation of the Governance and Sustainability Committee.

8.0 GENERAL

8.1 This Mandate shall be posted on the Corporation's corporate website at www.fortisinc.com.

8.2 The Committee shall annually review its own effectiveness and performance.

8.3 The Committee shall perform any other activities consistent with this Mandate, the Corporation's by-laws and applicable laws, that the Board or Committee determines are necessary or appropriate.

8.4 The Committee may, in its discretion and in circumstances that it considers appropriate, obtain advice and assistance from outside legal, accounting and other advisors and approve the engagement by the Committee or any Member of outside advisors or persons having special expertise, all at the expense of the Corporation. The Corporation shall provide appropriate compensation, as determined by the Committee, for the Independent Auditor, to any independent counsel or other advisors that the Committee chooses to engage, and for payment of ordinary administrative expenses of the Committee that are necessary and appropriate in carrying out its duties and responsibilities.

8.5 The Committee is not responsible for certifying the accuracy or completeness of the Corporation's financial statements or their presentation in accordance with generally accepted accounting principles, or for guaranteeing the accuracy of the attestation reports of the Independent Auditor. The fundamental responsibility for the Corporation's financial statements and reporting, internal controls over financial reporting and disclosure controls and processes rests with Management and, in accordance with its professional responsibilities, the Independent Auditor. Nothing in this Mandate is intended to modify or augment the obligations of the Corporation or the fiduciary duties of the members of the Committee or the Board under applicable laws.

FORTIS INC.	December 31, 2025	41
Annual Information Form
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EXHIBIT D:

MATERIAL CONTRACTS

The following are the material contracts of Fortis filed on SEDAR+ and EDGAR during 2025 or which were entered into prior to 2025 and are still in effect. Requests for additional copies of these material contracts should be directed to the Executive Vice President, Sustainability and Chief Legal Officer, Fortis, P.O. Box 8837, St. John's, NL, A1B 3T2 (telephone: 709.737.2800). All such contracts are also available under the Corporation's profile at www.sedarplus.ca and www.sec.gov.

Revolving Credit Facility

Fortis is a party to a Fourth Amended and Restated Credit Facility dated May 4, 2022, with The Bank of Nova Scotia as underwriter, sole lead arranger, book runner, sustainability structuring agent and administrative agent and Canadian Imperial Bank of Commerce and Royal Bank of Canada as co-syndication agents, and the lenders party thereto from time to time, as amended by the First Amending Agreement dated May 4, 2023, the Second Amending Agreement dated June 6, 2024 and the Third Amending Agreement dated May 7, 2025 between Fortis, The Bank of Nova Scotia and the lenders named therein. The Fourth Amended and Restated Credit Facility is a $1.3 billion unsecured committed revolving credit facility and contains the terms and conditions upon which such credit is available to Fortis during the duration of the facility. The Fourth Amended and Restated Credit Facility contains customary representations and warranties, affirmative and negative covenants and events of default. Customary fees are payable by Fortis in respect of the facility and amounts outstanding under the facility bear interest at market rates.

Amended and Restated Shareholders' Agreement

On January 28, 2021, ITC Investment Holdings, ITC Holdings, FortisUS and Eiffel Investment, an affiliate of GIC, entered into an Amended and Restated Shareholders' Agreement, amending the shareholders' agreement among the parties originally entered into on October 14, 2016. The Amended and Restated Shareholders' Agreement governs the rights of the parties in their respective capacities as direct or indirect shareholders of ITC Holdings.

Under the terms of the Amended and Restated Shareholders' Agreement, Eiffel Investment has certain minority approval rights relating to ITC Investment Holdings and ITC Holdings which depend on: (x) whether Eiffel Investment is a holder of Class A common stock or Class B non-voting common stock at the relevant time; and (y) the satisfaction by Eiffel Investment of certain ownership thresholds with respect to ITC Investment Holdings. The minority approval rights available to Eiffel Investment contingent on its ITC Investment Holdings share class and percentage ownership include rights with respect to: (i) amendments to charter documents; (ii) changes in board size; (iii) issuances of equity; (iv) business combinations that would impact Eiffel Investment differently than other shareholders; (v) insolvency; (vi) certain acquisitions of, investments in, or joint ventures relating to non-core assets, or certain material sales or dispositions of core assets; (vii) in limited circumstances, the incurrence of indebtedness by ITC Investment Holdings, ITC Holdings or its subsidiaries or the taking of certain actions that would reasonably be expected to result in the long-term unsecured indebtedness of ITC Investment Holdings, ITC Holdings and its subsidiaries being rated below investment grade; (viii) actions that would cause a ratio of ITC Holding's cash flow to debt to exceed an agreed targeted threshold; (ix) limitations on corporate overhead costs paid by ITC Holdings to Fortis; and (x) expansion of the core business outside ITC Holdings' current regulatory jurisdictions. The Amended and Restated Shareholders' Agreement also provides for a dividend policy, which can be amended only with the approval of all the independent directors of ITC Investment Holdings.

Indenture and First Supplemental Indenture

On October 4, 2016, Fortis entered into an Indenture and a First Supplement thereto with The Bank of New York Mellon, as U.S. trustee, and BNY Trust Company of Canada, as Canadian co-trustee. The Indenture and the First Supplement set forth the terms of the Corporation's currently outstanding US$1.1 billion aggregate principal amount of 3.055% Unsecured Notes due 2026. The Indenture contains customary covenants, events of default and rights for the benefit of security holders and the trustees. An unlimited amount of debt securities may be issued under the Indenture, which is governed by the laws of the State of New York.

Indenture and Supplemental Indentures

The Corporation currently has outstanding $3.35 billion aggregate principal amount of senior unsecured notes pursuant to an Indenture dated December 12, 2016 and six supplemental indentures thereto with Computershare Trust Company of Canada, as trustee, as follows: the Second Supplemental Indenture dated May 14, 2021 sets out the terms of the Corporation's $500 million 2.18% senior unsecured notes due 2028; the Third Supplemental Indenture dated May 31, 2022 sets forth the terms of the Corporation's $500 million 4.431% senior unsecured notes due 2029; the Fourth Supplemental Indenture dated November 8, 2023 sets forth the terms of the Corporation's $500 million 5.677% senior unsecured notes due 2033; the Fifth Supplemental Indenture dated September 9, 2024 sets forth the terms of the Corporation's $500 million 4.171% senior unsecured notes due 2031; the Sixth Supplemental Indenture dated March 26, 2025 sets forth the terms of the Corporation's $600 million 4.090% senior unsecured notes due 2032; and the Seventh Supplemental Indenture dated September 4, 2025 sets forth the terms of the Corporation's $750 million 5.100% fixed-to-fixed rate subordinated unsecured notes due 2055. The Indenture contains customary covenants, events of default and rights for the benefit of security holders and the trustee. An unlimited amount of debt securities may be issued under the Indenture, which is governed by the laws of the Province of Newfoundland and Labrador and the laws of Canada applicable therein.

FORTIS INC.	December 31, 2025	42

fts-20251231_d2

Exhibit 99.2

Consolidated Financial Statements

FORTIS INC.

Audited Consolidated Financial Statements

As at and for the years ended December 31, 2025 and 2024

FORTIS INC.	DECEMBER 31, 2025	1
Consolidated Financial Statements
---		Table of Contents
---	---	---	---	---	---
Management's Report on Internal Control over Financial Reporting		2	NOTE 9	Other Assets	22
Report of Independent Registered Public Accounting Firm			NOTE 10	Property, Plant and Equipment	22
("PCAOB ID No. 01208") - Opinion on the Financial Statements		3	NOTE 11	Intangible Assets	23
Report of Independent Registered Public Accounting Firm - Opinion on			NOTE 12	Goodwill	24
Internal Control over Financial Reporting		5	NOTE 13	Accounts Payable and Other Current Liabilities	24
Consolidated Balance Sheets		6	NOTE 14	Long-Term Debt	25
Consolidated Statements of Earnings		7	NOTE 15	Leases	28
Consolidated Statements of Comprehensive Income		7	NOTE 16	Other Liabilities	29
Consolidated Statements of Cash Flows		8	NOTE 17	Earnings Per Common Share	29
Consolidated Statements of Changes in Equity		9	NOTE 18	Preference Shares	30
Notes to Consolidated Financial Statements			NOTE 19	Accumulated Other Comprehensive Income	31
NOTE 1	Description of Business	10	NOTE 20	Stock-Based Compensation Plans	31
NOTE 2	Regulation	11	NOTE 21	Dispositions	33
NOTE 3	Summary of Significant Accounting Policies	12	NOTE 22	Other Income, Net	33
NOTE 4	Segmented Information	18	NOTE 23	Income Taxes	34
NOTE 5	Revenue	19	NOTE 24	Employee Future Benefits	35
NOTE 6	Accounts Receivable and Other Current Assets	20	NOTE 25	Supplementary Cash Flow Information	39
NOTE 7	Inventories	20	NOTE 26	Fair Value of Financial Instruments and Risk Management	39
NOTE 8	Regulatory Assets and Liabilities	20	NOTE 27	Commitments and Contingencies	43

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Fortis Inc. and its subsidiaries (the "Corporation") is responsible for establishing and maintaining adequate internal control over financial reporting ("ICFR"). The Corporation's ICFR is designed by, or under the supervision of, the Corporation's President and Chief Executive Officer ("CEO") and Executive Vice President, Chief Financial Officer ("CFO") and effected by the Corporation's board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Corporation's management, including its CEO and CFO, assessed the effectiveness of the Corporation's ICFR as of December 31, 2025, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that, as of December 31, 2025, the Corporation's ICFR was effective.

The Corporation's ICFR as of December 31, 2025 has been audited by Deloitte LLP, an Independent Registered Public Accounting Firm, which also audited the Corporation's consolidated financial statements for the year ended December 31, 2025. Deloitte LLP issued an unqualified opinion for both audits.

February 11, 2026

/s/ David G. Hutchens	/s/ Jocelyn H. Perry
David G. Hutchens	Jocelyn H. Perry
President and Chief Executive Officer, Fortis Inc.	Executive Vice President, Chief Financial Officer, Fortis Inc.
St. John's, Canada			FORTIS INC.	DECEMBER 31, 2025	2
---	---	---
Consolidated Financial Statements
---

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of Fortis Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Fortis Inc. and subsidiaries (the "Corporation") as of December 31, 2025 and 2024, the related consolidated statements of earnings, comprehensive income, cash flows, and changes in equity, for each of the two years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the results of operations of the Corporation as of December 31, 2025 and 2024, and its financial performance and its cash flows for each of the two years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Corporation's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 11, 2026, expressed an unqualified opinion on the Corporation's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the Corporation's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Impact of Rate Regulation on the financial statements - Refer to Notes 2, 3 and 8 to the financial statements

Critical Audit Matter Description

The Corporation's regulated utilities are subject to rate regulation and annual earnings oversight by various federal, state and provincial regulatory authorities who have jurisdiction in the United States and Canada. Rates and resultant earnings of the Corporation's regulated utilities are determined under cost of service regulation, with some using performance-based rate-setting mechanisms. The regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on asset value ("ROA") or common shareholders' equity ("ROE"). Regulatory decisions can have an impact on the timely recovery of costs and the regulator-approved ROE and/or ROA. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues and expenses; income taxes; and depreciation expense.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery of costs incurred or a refund to customers through the rate-setting process. While the Corporation's regulated utilities have indicated they expect to recover costs from customers through regulated rates, there is a risk that the respective regulatory authority will not approve full recovery of the costs incurred and a reasonable ROE and/or ROA. Auditing these matters required especially subjective judgment and specialized knowledge of accounting for rate regulation due to its inherent complexities across different jurisdictions.

| FORTIS INC. | DECEMBER 31, 2025 | 3 | | --- | --- | --- || Consolidated Financial Statements | | --- |

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the likelihood of recovery of costs incurred or a refund to customers through the rate-setting process, included the following, among others:

•Evaluating the effectiveness of controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•Assessing relevant regulatory orders, regulatory statutes and interpretations as well as procedural memorandums, utility and intervener filings, and other publicly available information to evaluate the likelihood of recovery in future rates or of a future reduction in rates and the ability to earn a reasonable ROA or ROE.

•For regulatory matters in progress, inspecting the regulated utilities' filings for any evidence that might contradict management's assertions. We obtained an analysis from management and letters from internal and external legal counsel, as appropriate, regarding cost recoveries or a future reduction in rates.

•Evaluating the Corporation's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

/s/ Deloitte LLP

Chartered Professional Accountants

St. John's, Canada

February 11, 2026

We have served as the Corporation's auditor since 2017.

FORTIS INC.	DECEMBER 31, 2025	4
Consolidated Financial Statements
---

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of Fortis Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Fortis Inc. and subsidiaries (the "Corporation") as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2025, of the Corporation and our report dated February 11, 2026, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte LLP

Chartered Professional Accountants

St. John's, Canada

February 11, 2026

FORTIS INC.	DECEMBER 31, 2025	5
Consolidated Financial Statements
---		CONSOLIDATED BALANCE SHEETS
---	---	---	---	---
FORTIS INC.
As at December 31 (in millions of Canadian dollars)	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	367	$	220
Accounts receivable and other current assets (Note 6)	1,695		1,886
Prepaid expenses	179		182
Inventories (Note 7)	649		685
Regulatory assets (Note 8)	915		823
Total current assets	3,805		3,796
Other assets (Note 9)	1,782		1,653
Regulatory assets (Note 8)	4,107		3,808
Property, plant and equipment, net (Note 10)	50,886		49,456
Intangible assets, net (Note 11)	1,723		1,661
Goodwill (Note 12)	12,527		13,112
Total assets	$	74,830	$	73,486
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings (Note 14)	$	412	$	98
Accounts payable and other current liabilities (Note 13)	3,503		3,353
Regulatory liabilities (Note 8)	452		595
Current installments of long-term debt (Note 14)	3,146		1,990
Total current liabilities	7,513		6,036
Regulatory liabilities (Note 8)	3,810		3,696
Deferred income taxes (Note 23)	5,292		5,020
Long-term debt (Note 14)	30,723		31,224
Finance leases (Note 15)	348		343
Other liabilities (Note 16)	1,275		1,314
Total liabilities	48,961		47,633
Commitments and contingencies (Note 27)
Equity
Common shares (1)	16,112		15,589
Preference shares (Note 18)	1,623		1,623
Additional paid-in capital	5		8
Accumulated other comprehensive income (Note 19)	1,101		2,067
Retained earnings	4,969		4,521
Shareholders' equity	23,810		23,808
Non-controlling interests	2,059		2,045
Total equity	25,869		25,853
Total liabilities and equity	$	74,830	$	73,486
(1) No par value. Unlimited authorized shares. 507.3 million and 499.3 million issued and outstanding as at December 31, 2025 and 2024, respectively	Approved on Behalf of the Board
---	---	---
	/s/ Jo Mark Zurel	/s/ Margarita K. Dilley
	Jo Mark Zurel,	Margarita K. Dilley
See accompanying Notes to Consolidated Financial Statements	Director	Director		FORTIS INC.	DECEMBER 31, 2025	6
---	---	---
Consolidated Financial Statements
---		CONSOLIDATED STATEMENTS OF EARNINGS
---	---	---	---	---	---
FORTIS INC.
For the years ended December 31 (in millions of Canadian dollars, except per share amounts)		2025		2024
Revenue (Note 5)		$	12,170	$	11,508
Expenses
Energy supply costs		3,371		3,249
Operating expenses		3,250		3,040
Depreciation and amortization		2,057		1,927
Total expenses		8,678		8,216
Operating income		3,492		3,292
Other income, net (Note 22)		340		288
Finance charges		1,478		1,406
Earnings before income tax expense		2,354		2,174
Income tax expense (Note 23)		393		346
Net earnings		$	1,961	$	1,828
Net earnings attributable to:
	Non-controlling interests	$	162	$	148
	Preference equity shareholders (Note 18)	85		74
	Common equity shareholders	1,714		1,606
		$	1,961	$	1,828
Earnings per common share (Note 17)
Basic		$	3.40	$	3.24
Diluted		$	3.40	$	3.24
See accompanying Notes to Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
---	---	---	---	---
For the years ended December 31 (in millions of Canadian dollars)	2025		2024
Net earnings	$	1,961	$	1,828
Other comprehensive (loss) income
Unrealized foreign currency translation (losses) gains, net of hedging activities and income tax (expense) recovery of $(7) million and $14 million, respectively	(950)		1,561
Other, net of income tax recovery (expense) of $9 million and $(3) million, respectively	(26)		9
	(976)		1,570
Derecognition of foreign currency translation amount on dispositions (Note 19)	(86)		—
	(1,062)		1,570
Comprehensive income	$	899	$	3,398
Comprehensive income attributable to:
Non-controlling interests	$	66	$	304
Preference equity shareholders	85		74
Common equity shareholders	748		3,020
	$	899	$	3,398
See accompanying Notes to Consolidated Financial Statements						FORTIS INC.	DECEMBER 31, 2025	7
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Consolidated Financial Statements
---		CONSOLIDATED STATEMENTS OF CASH FLOWS
---	---	---	---	---
FORTIS INC.
For the years ended December 31 (in millions of Canadian dollars)	2025		2024
Operating activities
Net earnings	$	1,961	$	1,828
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation - property, plant and equipment	1,810		1,695
Amortization - intangible assets	160		153
Amortization - other	87		79
Deferred income tax expense (Note 23)	252		154
Equity component, allowance for funds used during construction (Note 22)	(174)		(139)
Sale of investment tax credits	63		—
Other	106		43
Change in long-term regulatory assets and liabilities	(85)		(99)
Change in working capital (Note 25)	(118)		168
Cash from operating activities	4,062		3,882
Investing activities
Additions to property, plant and equipment	(5,942)		(5,012)
Additions to intangible assets	(292)		(206)
Contributions in aid of construction	775		106
Proceeds on dispositions, net (Note 21)	479		—
Contributions to equity-accounted investees	(27)		—
Other	(350)		(283)
Cash used in investing activities	(5,357)		(5,395)
Financing activities
Proceeds from long-term debt, net of issuance costs (Note 14)	2,687		3,124
Repayments of long-term debt and finance leases	(108)		(1,718)
Borrowings under committed credit facilities	10,405		8,618
Repayments under committed credit facilities	(11,056)		(8,055)
Net change in short-term borrowings	385		(25)
Issue of common shares, net of costs and dividends reinvested	60		46
Dividends
Common shares, net of dividends reinvested	(788)		(744)
Preference shares	(85)		(74)
Subsidiary dividends paid to non-controlling interests	(54)		(110)
Other	15		2
Cash from financing activities	1,461		1,064
Effect of exchange rate changes on cash and cash equivalents	(19)		44
Change in cash and cash equivalents	147		(405)
Cash and cash equivalents, beginning of year	220		625
Cash and cash equivalents, end of year	$	367	$	220
Supplementary Cash Flow Information (Note 25)
See accompanying Notes to Consolidated Financial Statements
FORTIS INC.	DECEMBER 31, 2025	8
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Consolidated Financial Statements
---		CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
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FORTIS INC.
For the years ended December 31<br>(in millions of Canadian dollars, except share numbers)	Common Shares<br><br>(# millions)	Common<br>Shares		Preference Shares<br><br>(Note 18)		Additional Paid-In<br>Capital		Accumulated Other Comprehensive Income (Loss)<br><br>(Note 19)		Retained<br>Earnings		Non-Controlling<br>Interests		Total<br>Equity
As at December 31, 2024	499.3	$	15,589	$	1,623	$	8	$	2,067	$	4,521	$	2,045	$	25,853
Net earnings	—	—		—		—		—		1,799		162		1,961
Other comprehensive loss	—	—		—		—		(880)		—		(96)		(976)
Derecognition of foreign currency translation amount on dispositions	—	—		—		—		(86)		—		—		(86)
Common shares issued	8.0	523		—		(2)		—		—		—		521
Subsidiary dividends paid to non-controlling interests	—	—		—		—		—		—		(54)		(54)
Dividends declared on common shares ($2.51 per share)	—	—		—		—		—		(1,266)		—		(1,266)
Dividends on preference shares	—	—		—		—		—		(85)		—		(85)
Other	—	—		—		(1)		—		—		2		1
As at December 31, 2025	507.3	$	16,112	$	1,623	$	5	$	1,101	$	4,969	$	2,059	$	25,869
As at December 31, 2023	490.6	$	15,108	$	1,623	$	9	$	653	$	4,112	$	1,827	$	23,332
Net earnings	—	—		—		—		—		1,680		148		1,828
Other comprehensive income	—	—		—		—		1,414		—		156		1,570
Common shares issued	8.7	481		—		—		—		—		—		481
Advances to non-controlling interests	—	—		—		—		—		—		21		21
Subsidiary dividends paid to non-controlling interests	—	—		—		—		—		—		(110)		(110)
Dividends declared on common shares ($2.41 per share)	—	—		—		—		—		(1,197)		—		(1,197)
Dividends on preference shares	—	—		—		—		—		(74)		—		(74)
Other	—	—		—		(1)		—		—		3		2
As at December 31, 2024	499.3	$	15,589	$	1,623	$	8	$	2,067	$	4,521	$	2,045	$	25,853
See accompanying Notes to Consolidated Financial Statements																FORTIS INC.	DECEMBER 31, 2025	9
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Notes to Consolidated Financial Statements
---		For the years ended December 31, 2025 and 2024
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1. DESCRIPTION OF BUSINESS

Fortis Inc. ("Fortis" or the "Corporation") is a diversified North American regulated electric and gas utility holding company. 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 ("ITCTransmission"), Michigan Electric Transmission Company, LLC ("METC"), ITC Midwest LLC ("ITC Midwest"), and ITC Great Plains, LLC. Fortis owns 80.1% of ITC and an affiliate of GIC Private Limited owns a 19.9% minority interest.

ITC owns and operates high-voltage transmission lines in Michigan's lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin.

UNS Energy: UNS Energy Corporation, which primarily includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas").

UNS Energy's largest operating subsidiary, TEP, and UNS Electric are vertically integrated regulated electric utilities. They generate, transmit and distribute electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area. TEP also sells wholesale electricity to other entities in the western United States. Together they own generating capacity of 3,443 megawatts ("MW"), including 69 MW of solar capacity and 250 MW of wind capacity. Several generating assets in which they have an interest are jointly owned.

UNS Gas is a regulated gas distribution utility serving retail customers in northern and southern Arizona.

Central Hudson: CH Energy Group, Inc., which primarily includes Central Hudson Gas & Electric Corporation. Central Hudson is a regulated electric and gas transmission and distribution utility that serves portions of New York State's Mid-Hudson River Valley and owns gas-fired and hydroelectric generating capacity totalling 43 MW.

FortisBC Energy: FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, providing transmission and distribution services. FortisBC Energy sources natural gas supplies primarily from northeastern British Columbia and Alberta on behalf of most customers.

FortisAlberta: FortisAlberta Inc. is a regulated electricity distribution utility operating in a substantial portion of southern and central Alberta. FortisAlberta is not involved in the direct sale of electricity.

FortisBC Electric: FortisBC Inc. is an integrated regulated electric utility operating in the southern interior of British Columbia. It owns four hydroelectric generating facilities with a combined capacity of 225 MW. It also provides operating, maintenance and management services relating to five hydroelectric generating facilities in British Columbia that are owned by third parties.

Other Electric: Eastern Canadian and Caribbean utilities, as follows: Newfoundland Power Inc. ("Newfoundland Power"); Maritime Electric Company, Limited ("Maritime Electric"); FortisOntario Inc. ("FortisOntario"); a 39% equity investment in Wataynikaneyap Power Limited Partnership ("Wataynikaneyap Power"); and an approximate 60% controlling interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities"). Also includes FortisTCI Limited and Turks and Caicos Utilities Limited (collectively, "FortisTCI") until the September 2, 2025 date of disposition and the 33% equity investment in Belize Electricity Limited ("Belize Electricity") until the October 31, 2025 date of disposition (Note 21).

Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador with a generating capacity of 145 MW, of which 98 MW is hydroelectric. Maritime Electric is an integrated regulated electric utility and the principal distributor of electricity on Prince Edward Island ("PEI") with on-Island generating capacity of 90 MW. FortisOntario consists of three regulated electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario with a generating capacity of 3 MW. Wataynikaneyap Power is a transmission company majority-owned by 24 First Nations in which Fortis owns a 39% interest. The 1,800 kilometer Wataynikaneyap Power Transmission Line connects 17 remote First Nations to the Ontario power grid. Caribbean Utilities is an integrated regulated electric utility and the sole electricity distributor on Grand Cayman with a diesel-powered generating capacity of 166 MW.

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 until the October 31, 2025 date of disposition (Note 21).

FORTIS INC.	DECEMBER 31, 2025	10
Notes to Consolidated Financial Statements
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For the years ended December 31, 2025 and 2024
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2. REGULATION

General

The earnings of the Corporation's regulated utilities are determined under cost of service ("COS") regulation, with some using performance-based rate setting ("PBR") mechanisms.

Under COS regulation, the regulator sets customer rates to permit a reasonable opportunity for the timely recovery of the estimated costs of providing service, including a fair rate of return on a deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). PBR mechanisms generally apply a formula that incorporates inflation and assumed productivity improvements for a set term.

The ability to recover prudently incurred costs of providing service and earn the regulator‑approved rate of return on common shareholders' equity ("ROE") and/or rate of return on rate base assets ("ROA") may depend on achieving the forecasts established in the rate-setting process. As well, the Corporation's regulated utilities, where applicable, are permitted by their respective regulators to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms (Note 8). There can be varying degrees of regulatory lag between when costs are incurred and when they are reflected in customer rates.

Nature of Regulation		Allowed<br><br>Common<br><br>Equity<br><br>(%)		Allowed ROE (1)<br><br>(%)
Regulated Utility	Regulatory Authority		2025			2024		Significant Features
ITC	Federal Energy Regulatory Commission ("FERC")	60.0		10.73	(2)		10.73		Cost-based formula rates, with annual true-up mechanism (3)<br><br>Incentive adders
TEP	Arizona Corporation Commission ("ACC")	54.3		9.55	(4)		9.55		COS regulation<br>Historical test year
	FERC	(5)		9.79			9.79		Formula transmission rates
UNS Electric	ACC	53.7		9.75			9.75
UNS Gas	ACC	50.8		9.75	(4)		9.75
Central Hudson	New York State Public Service Commission ("PSC")	48.0		9.50	(6)		9.50		COS regulation<br>Future test year
FortisBC Energy	British Columbia Utilities Commission ("BCUC")	45.0		9.65			9.65		COS regulation with formula components and incentives
FortisBC Electric	BCUC	41.0		9.65			9.65		Future test year
FortisAlberta	Alberta Utilities Commission ("AUC")	37.0		8.97			9.28		PBR, with formula to calculate ROE on an annual basis (7)
Newfoundland Power	Newfoundland and Labrador Board of Commissioners of Public Utilities	45.0		8.60			8.50		COS regulation<br>Future test year
Maritime Electric	Island Regulatory and Appeals Commission	40.0		9.35			9.35		COS regulation<br>Future test year
FortisOntario (8)	Ontario Energy Board	40.0		8.66-9.30			8.52-9.30		COS regulation with incentive mechanisms
Caribbean Utilities (9)	Utility Regulation and Competition Office	N/A		8.50-10.50			8.25-10.25		COS regulation<br><br>Rate-cap adjustment mechanism<br><br>based on published consumer price indices

(1) ROA for Caribbean Utilities

(2) Reflects the allowed common equity and ROE for ITCTransmission, METC, and ITC Midwest. The ROE above is inclusive of the base ROE as well as incentive adders totalling 0.75%

(3) Annual true-up collected or refunded in rates within a two-year period

(4) A general rate application is ongoing. See "Significant Regulatory Matters" below

(5) The allowed common equity component for FERC transmission rates is formulaic, and is updated annually based on TEP's actual equity ratio

(6) The PSC approved a three-year rate plan effective July 1, 2025, with the continuation of a 9.5% allowed ROE and 48% common equity component

(7) The ROE for 2026 has been set at 9.02%

(8) Two of FortisOntario's utilities follow COS regulation with incentive mechanisms, while the remaining utility is subject to a 35-year franchise agreement expiring in 2033

(9) Operates under licences from the Government of the Cayman Islands. Its exclusive transmission and distribution licence is for an initial 20-year period, expiring in April 2028, with a provision for automatic renewal. Its non-exclusive generation licence is for a 25-year term, expiring in November 2039

FORTIS INC.	DECEMBER 31, 2025	11
Notes to Consolidated Financial Statements
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For the years ended December 31, 2025 and 2024
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2. REGULATION (cont'd)

Significant Regulatory Matters

ITC

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.

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.

The Residential Utility Consumer Office has challenged the ACC's authority to implement a formula rate framework through a policy statement, and in November 2025, the Arizona Court of Appeals ruled that the Residential Utility Consumer Office may proceed with its challenge. The timing and outcome of these regulatory and legal proceedings are unknown.

UNS Gas General Rate Application: In January 2026, an ACC Administrative Law Judge issued a Recommended Opinion and Order recommending an allowed ROE of 9.57% and a 56% common equity component of capital structure. The order also recommended an annual formulaic rate adjustment mechanism including a range of +/- 40 basis points around the allowed return, a 5% efficiency credit to incremental revenue requirement, and the exclusion of post-test year adjustments. Should the annual formulaic mechanism not be approved, the order recommended the use of adjustor mechanisms for the timely recovery of infrastructure investments and income tax changes. The Recommended Opinion and Order proposes implementation of new rates by March 1, 2026. The rate application remains subject to ACC approval which is anticipated in February 2026.

FortisAlberta

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 of Alberta ("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 was heard in January 2026. A decision is expected in the third quarter of 2026.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These consolidated financial statements have been prepared and presented in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") for rate-regulated entities, and are in Canadian dollars unless otherwise indicated.

These consolidated financial statements include the accounts of the Corporation and its subsidiaries. They 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.

Cash and Cash Equivalents

Cash and cash equivalents include cash, cash held in margin accounts, and short-term deposits with initial maturities of three months or less from the date of deposit.

Allowance for Credit Losses

Fortis and its subsidiaries recognize an allowance for credit losses to reduce accounts receivable for amounts estimated to be uncollectible. The allowance for credit losses is estimated based on historical collection patterns, sales, and current and forecast economic and other conditions. Accounts receivable are written off in the period in which they are deemed uncollectible.

Inventories

Inventories, consisting of materials and supplies, gas, fuel and coal in storage, are measured at the lower of weighted average cost and net realizable value.

FORTIS INC.	DECEMBER 31, 2025	12
Notes to Consolidated Financial Statements
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For the years ended December 31, 2025 and 2024
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3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)

Regulatory Assets and Liabilities

Regulatory assets and liabilities arise as a result of the utility rate-setting process and are subject to regulatory approval. Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent: (i) future reductions or limitations of increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process; or (ii) obligations to provide future service that customers have paid for in advance.

Certain regulatory assets do not earn a return as they do not represent a past cash outlay and are offset by related liabilities that, likewise, do not incur a carrying cost for rate-making purposes. These regulatory assets are primarily related to deferred income taxes and employee future benefits.

Certain remaining recovery and settlement periods are those expected by management and the actual periods could differ based on regulatory approval.

Investments

Investments are reviewed annually for potential impairment in value. Impairments are recognized when identified.

Property, Plant and Equipment

Property, plant and equipment ("PPE") are recognized at cost less accumulated depreciation. Contributions in aid of construction by customers and governments are recognized as a reduction in the cost of, and are amortized in a manner consistent with, the related PPE.

Depreciation rates of the Corporation's regulated utilities include a provision for estimated future removal costs not identified as a legal obligation. The provision is recognized as a long-term regulatory liability (Note 8) against which actual removal costs are netted when incurred.

The Corporation's regulated utilities derecognize PPE on disposal or when no future economic benefits are expected from their use. Upon derecognition, any difference between cost and accumulated depreciation, net of salvage proceeds, is charged to accumulated depreciation. No gain or loss is recognized.

Through methodologies established by their respective regulators, the Corporation's regulated utilities capitalize: (i) overhead costs that are not directly attributable to specific PPE but relate to the overall capital expenditure plan; and (ii) an allowance for funds used during construction ("AFUDC"). The debt component of AFUDC for 2025 totalled $96 million (2024 - $74 million) and is reported as a reduction of finance charges and the equity component is reported as other income (Note 22). Both components are recorded to earnings through depreciation expense over the estimated service lives of the applicable PPE.

Excluding UNS Energy and Central Hudson, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulators, these companies recognize such items as inventory until used and reclassifies them to PPE once put into service.

Repairs and maintenance costs are charged to earnings in the period incurred. Replacements and betterments that extend the useful lives of PPE are capitalized.

PPE is depreciated using the straight-line method based on the estimated service lives of the assets. Depreciation rates for regulated PPE are approved by the respective regulators and ranged from 0.5% to 33.0% for 2025 (2024 - 0.5% to 33.0%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.7% for 2025 (2024 – 2.7%).

The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows.

	2025		2024
(years)	Service Life<br><br>Ranges	Weighted<br>Average<br>Remaining<br>Service Life	Service Life<br>Ranges	Weighted<br>Average<br>Remaining<br>Service Life
Distribution
Electric	7-80	32	5-80	32
Gas	18-83	40	18-83	37
Transmission
Electric	20-85	42	20-85	42
Gas	10-80	34	10-80	35
Generation	6-95	22	2-95	22
Other	3-80	13	3-80	13
FORTIS INC.	DECEMBER 31, 2025	13
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Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
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3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)

Intangible Assets

Intangible assets are recorded at cost less accumulated amortization. Their useful lives are assessed to be either indefinite or finite.

Intangible assets with indefinite useful lives are not amortized and are tested for impairment annually, either individually or, where the particular entity also has goodwill, at the reporting unit level in conjunction with goodwill impairment testing. An annual review is completed to determine whether the indefinite life assessment continues to be supportable. If not, the resultant changes are made prospectively.

Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets. Amortization rates for regulated intangible assets are approved by the respective regulators and ranged from 1.0% to 33.0% for 2025 (2024 – 1.0% to 33.0%).

The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows.

	2025		2024
(years)	Service Life<br>Ranges	Weighted<br>Average<br>Remaining<br>Service Life	Service Life<br>Ranges	Weighted<br>Average<br>Remaining<br>Service Life
Computer software	3-18	5	3-18	5
Land, transmission and water rights	10-85	55	30-85	52
Other	10-100	19	10-100	16

The Corporation's regulated utilities derecognize intangible assets on disposal or when no future economic benefits are expected from their use. Upon derecognition any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated amortization. No gain or loss is recognized.

Impairment of Long-Lived Assets

The Corporation reviews the valuation of PPE, intangible assets with finite lives, and other long-term assets when events or changes in circumstances indicate that the total undiscounted cash flows expected to be generated by the asset may be below carrying value. If that is determined to be the case, the asset is written down to estimated fair value and an impairment loss is recognized.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets related to business acquisitions.

Goodwill at each of the Corporation's reporting units is tested for impairment annually and whenever an event or change in circumstances indicates that fair value may be below carrying value. If so determined, goodwill is written down to estimated fair value and an impairment loss is recognized.

The Corporation performs a qualitative assessment on each reporting unit, and if it is determined that it is more likely than not that fair value is less than carrying value, then a quantitative assessment is performed. Under the quantitative test, the primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections are discounted. Underlying estimates and assumptions, with varying degrees of uncertainty, include the amount and timing of expected future cash flows, growth rates, and discount rates. A secondary valuation, the market approach, is also performed and includes the comparison of each reporting unit's estimated fair value multiple to those of comparable utilities.

Deferred Financing Costs

Issue costs, discounts and premiums are recognized against, and amortized over the life of, the related long-term debt.

Employee Future Benefits

Fortis and each subsidiary maintain one or a combination of defined benefit pension ("DBP") and defined contribution pension plans, as well as other post-employment benefit ("OPEB") plans, including certain health and dental coverage and life insurance benefits, for qualifying members. The costs of defined contribution pension plans are expensed as incurred.

For DBP and OPEB plans, the projected or accumulated benefit obligation and net benefit costs are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees and, for OPEB plans, expected health care costs. Discount rates reflect market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension or OPEB payments.

DBP and OPEB plan assets are recognized at fair value. For the purpose of determining defined benefit pension cost, FortisBC Energy and Newfoundland Power use the market-related value whereby investment returns in excess of, or below, expected returns are recognized in the asset value over a period of three years.

FORTIS INC.	DECEMBER 31, 2025	14
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
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3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)

The excess of any cumulative net actuarial gain or loss over 10% of the greater of: (i) the projected or accumulated benefit obligation; and (ii) the fair value or market-related value, as applicable, of plan assets at the beginning of the fiscal year, along with unamortized past service costs, are deferred and amortized over the average remaining service period of active employees.

The net funded or unfunded status of DBP and OPEB plans, measured as the difference between the fair value of the plan assets and the projected or accumulated benefit obligation, is recognized on the Corporation's consolidated balance sheets.

For most of the Corporation's regulated utilities, any difference between DBP or OPEB plan costs ordinarily recognized under U.S. GAAP and those recovered from customers in current rates is subject to deferral account treatment and is expected to be recovered from, or refunded to, customers in future rates. In addition, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with DBP or OPEB plans, as applicable, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account treatment (Note 8).

Leases

A right-of-use asset and lease liability is recognized for leases with a lease term greater than 12 months. The right-of-use asset and liability are both measured at the present value of future lease payments, excluding variable payments that are based on usage or performance. Future lease payments include both lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs), which Fortis accounts for as a single lease component. The present value is calculated using the rate implicit in the lease or a lease-specific secured interest rate based on the remaining lease term. Renewal options are included in the lease term when it is reasonably certain that the option will be exercised.

Finance leases are depreciated over the lease term, except where: (i) ownership of the asset is transferred at the end of the lease term, in which case depreciation is over the estimated service life of the underlying asset; and (ii) the regulator has approved a different recovery methodology for rate-setting purposes, in which case the timing of the expense recognition will conform to the regulator's requirements.

Revenue Recognition

Most revenue is derived from energy sales and the provision of transmission services to customers based on regulator-approved tariff rates. Most contracts have a single performance obligation, being the delivery of energy or the provision of transmission services. No component of the transaction price is allocated to unsatisfied performance obligations. Energy sales are generally measured in kilowatt hours, gigajoules or transmission load delivered. The billing of energy sales is based on customer meter readings, which occur systematically throughout each month. The billing of transmission services at ITC is based on peak monthly load.

FortisAlberta is a distribution company and is required by its regulator to arrange and pay for transmission services with the Alberta Electric System Operator ("AESO"). This includes the collection of transmission revenue from its customers, which occurs through the transmission component of its regulator-approved rates. FortisAlberta reports transmission revenue and expenses on a net basis.

Electricity, gas and transmission service revenue includes an estimate for unbilled energy consumed or service provided since the last meter reading that has not been billed at the end of the reporting period. Sales estimates generally reflect an analysis of historical consumption in relation to key inputs, such as current energy prices, population growth, economic activity, weather conditions and system losses. Unbilled revenue accruals are adjusted in the periods actual consumption becomes known.

Variable consideration is estimated at the most likely amount and reassessed at each reporting date until the amount is known. Variable consideration, including amounts subject to a future regulatory decision, is recognized as a refund liability until entitlement is probable.

Revenue excludes sales and municipal taxes collected from customers.

The Corporation has elected not to assess or account for any significant financing components associated with revenue billed in accordance with equal payment plans as the period between the transfer of energy to customers and the customers' payment is less than one year.

Stock-Based Compensation

Fortis recognizes liabilities associated with directors' deferred share units ("DSUs"), performance share units ("PSUs") and restricted share units ("RSUs"). DSUs represent cash-settled awards whereas PSUs and RSUs represent cash or share-settled awards. The fair value of these liabilities is based on the five-day volume weighted average price ("VWAP") of the Corporation's common shares at the end of each reporting period. The fair value of the PSU liability is also based on the expected payout probability, based on historical performance in accordance with the defined metrics of each grant and management's best estimate.

Compensation expense is recognized on a straight-line basis over the vesting period, which for PSUs and RSUs is over the lesser of three years or the period to retirement eligibility and for DSUs is at the time of grant. Forfeitures are accounted for as they occur.

FORTIS INC.	DECEMBER 31, 2025	15
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
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3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)

Foreign Currency Translation

Assets and liabilities of the Corporation's foreign operations, all of which have a U.S. dollar functional currency, are translated at the exchange rate in effect at the balance sheet date and the resultant unrealized translation gains and losses are recognized in accumulated other comprehensive income. The exchange rate as at December 31, 2025 was US$1.00=CA$1.37 (2024 – US$1.00=CA$1.44).

Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which was US$1.00=CA$1.40 for 2025 (2024 - US$1.00=CA$1.37).

Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate prevailing at the balance sheet date. Revenue and expenses denominated in foreign currencies are translated at the exchange rate prevailing at the transaction date. Translation gains and losses are recognized in earnings.

Translation gains and losses on foreign currency-denominated debt that is designated as an effective hedge of foreign net investments are recognized in other comprehensive income.

Derivatives and Hedging

Derivatives Not Designated as Hedges

Derivatives not designated as hedges are used by: (i) Fortis, to manage cash flow risk associated with forecast U.S. dollar cash inflows and forecast future cash settlements of DSU, PSU and RSU obligations; and (ii) UNS Energy, to meet forecast load and reserve requirements. Derivatives are measured at fair value with changes thereto recognized in earnings.

Derivatives not designated as hedges are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce energy price risk associated with purchased power and gas requirements. The settled amounts of these derivatives are generally included in regulated rates, as permitted by the respective regulators. These derivatives are measured at fair value with changes recognized as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 8).

Derivatives that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized in earnings as energy supply costs.

Derivatives Designated as Hedges

Fortis, ITC and Central Hudson use cash flow hedges, from time to time, to manage interest rate risk. Unrealized gains and losses are initially recognized in accumulated other comprehensive income and reclassified to earnings when the underlying hedged transaction affects earnings.

The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the U.S. dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through U.S. dollar-denominated debt at the corporate level. Exchange rate fluctuations associated with the translation of this debt and the foreign net investments are recognized in accumulated other comprehensive income.

Presentation of Derivatives

The fair value of derivatives is recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash flows. Derivatives under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement of all derivatives are presented in operating activities in the consolidated statements of cash flows.

Income Taxes

The Corporation and its taxable subsidiaries follow the asset and liability method of accounting for income taxes. Current income tax expense or recovery is recognized for the estimated income taxes payable or receivable in the current year.

Deferred income tax assets and liabilities are recognized for temporary differences between the tax and accounting basis of assets and liabilities, as well as for the benefit of losses available to be carried forward to future years for tax purposes that are "more likely than not" to be realized. They are measured using enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change occurs. Valuation allowances are recognized when it is "more likely than not" that all of, or a portion of, a deferred income tax asset will not be realized.

Customer rates at ITC, UNS Energy, Central Hudson and Maritime Electric reflect current and deferred income tax. Customer rates at FortisAlberta reflect current income tax. Customer rates at FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario reflect current income tax and, for certain regulatory balances, deferred income tax. Caribbean Utilities is not subject to income tax.

Differences between the income tax expense or recovery recognized under U.S. GAAP and that reflected in current customer rates, which is expected to be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities (Note 8).

FORTIS INC.	DECEMBER 31, 2025	16
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)

Fortis does not recognize deferred income taxes on temporary differences related to investments in foreign subsidiaries where it intends to indefinitely reinvest earnings. If such earnings are repatriated, the Corporation may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is impractical.

Tax benefits associated with actual or expected income tax positions are recognized when the "more likely than not" recognition threshold is met. The tax benefits are measured at the largest amount of benefit that is greater than 50% likely to be realized upon settlement.

Income tax interest and penalties are recognized as income tax expense when incurred.

Asset Retirement Obligations

The Corporation's subsidiaries have asset retirement obligations ("AROs") associated with certain generation, transmission, distribution and interconnection assets, including land and environmental remediation and/or asset removal. These assets and related licences, permits, rights-of-way and agreements are reasonably expected to effectively exist and operate in perpetuity due to their nature. Consequently, where the final date and cost of remediation and/or removal of the noted assets cannot be reasonably determined, AROs have not been recognized.

Otherwise, AROs are recognized at fair value in the period incurred as an increase in PPE and long-term other liabilities (Note 16) if a reasonable estimate of fair value can be determined. Fair value is estimated as the present value of expected future cash outlays, discounted at a credit-adjusted risk-free interest rate. The increase in the liability due to the passage of time is recognized through accretion and the capitalized cost is depreciated over the useful life of the asset. Accretion and depreciation expense are deferred as a regulatory asset or liability based on regulatory recovery of these costs. Actual settlement costs are recognized as a reduction in the accrued liability.

Contingencies

Fortis and its subsidiaries are subject to various legal proceedings and claims that arise in the normal course of business. Management makes judgments regarding the future outcome of contingent events and recognizes a loss based on its best estimate when it is determined that such loss, or range of loss, is probable and can be reasonably estimated. Legal fees are expensed as incurred. When a loss is recoverable in future rates, a regulatory asset is also recognized.

Management regularly reviews current information to determine whether recognized provisions should be adjusted and new provisions are required. However, estimating probable losses requires considerable judgment about potential actions by third parties and matters are often resolved over long periods of time. Actual outcomes may differ materially from the amounts recognized.

Use of Accounting Estimates

The preparation of these consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and judgments, including those arising from matters dependent upon the finalization of regulatory proceedings, that affect the reported amounts of assets, liabilities, revenues, expenses, gains and losses. Management evaluates these estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable at the time they are made, with any adjustments being recognized in the period they become known. Actual results may differ significantly from these estimates.

New Accounting Policies

Income Taxes: The Corporation adopted Accounting Standard Update ("ASU") No. 2023-09, Improvements to Income Tax Disclosures, effective January 1, 2025. This update 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 ASU has been applied retrospectively and the updated disclosure is included in Notes 23 and 25.

Future Accounting Pronouncements

The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board. Any ASUs not included in these consolidated 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 consolidated financial statements.

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.

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 is 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.

FORTIS INC.	DECEMBER 31, 2025	17
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

4. SEGMENTED INFORMATION

Fortis' CEO 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 in 2025 or 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 December 31, 2025 and 2024, there were no inter-segment loans outstanding. Interest charged on inter-segment loans was not material in 2025 and 2024.

	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 ended December 31, 2025
Revenue	2,495	2,913	1,620	1,874	829	557	1,851	12,139	31	—	12,170
Energy supply costs	—	1,064	507	548	—	165	1,087	3,371	—	—	3,371
Operating expenses	628	824	688	450	199	147	253	3,189	61	—	3,250
Depreciation and amortization	487	427	158	367	300	83	228	2,050	7	—	2,057
Operating income	1,380	598	267	509	330	162	283	3,529	(37)	—	3,492
Other income, net	79	73	72	54	8	5	26	317	23	—	340
Finance charges	515	167	94	152	135	81	89	1,233	245	—	1,478
Income tax expense	218	67	54	74	21	11	26	471	(78)	—	393
Net earnings	726	437	191	337	182	75	194	2,142	(181)	—	1,961
Non-controlling interests	134	—	—	1	—	—	27	162	—	—	162
Preference share dividends	—	—	—	—	—	—	—	—	85	—	85
Net earnings attributable to common equity shareholders	592	437	191	336	182	75	167	1,980	(266)	—	1,714
Additions to property, plant and equipment and intangible assets	1,840	1,365	481	1,270	598	186	491	6,231	3	—	6,234
As at December 31, 2025
Goodwill	8,423	1,896	619	913	231	235	210	12,527	—	—	12,527
Total assets	27,474	15,006	6,463	10,842	6,508	2,960	5,247	74,500	341	(11)	74,830
Year ended December 31, 2024
Revenue	2,229	3,007	1,372	1,665	817	545	1,838	11,473	35	—	11,508
Energy supply costs	—	1,183	393	423	—	155	1,095	3,249	—	—	3,249
Operating expenses	530	798	659	418	195	141	250	2,991	49	—	3,040
Depreciation and amortization	448	404	134	337	291	88	218	1,920	7	—	1,927
Operating income	1,251	622	186	487	331	161	275	3,313	(21)	—	3,292
Other income, net	96	51	58	45	11	6	29	296	(8)	—	288
Finance charges	483	155	79	155	135	81	93	1,181	225	—	1,406
Income tax expense	200	70	37	83	26	14	23	453	(107)	—	346
Net earnings	664	448	128	294	181	72	188	1,975	(147)	—	1,828
Non-controlling interests	122	—	—	1	—	—	25	148	—	—	148
Preference share dividends	—	—	—	—	—	—	—	—	74	—	74
Net earnings attributable to common equity shareholders	542	448	128	293	181	72	163	1,827	(221)	—	1,606
Additions to property, plant and equipment and intangible assets	1,456	1,151	431	1,035	554	132	454	5,213	5	—	5,218
As at December 31, 2024
Goodwill	8,828	1,987	649	913	231	235	269	13,112	—	—	13,112
Total assets	27,202	14,690	6,278	10,156	6,181	2,807	5,810	73,124	374	(12)	73,486	FORTIS INC.	DECEMBER 31, 2025	18
---	---	---
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

5. REVENUE

The following table presents the disaggregation of the Corporation's revenue on the consolidated statements of earnings by geography and substantially autonomous utility operations.

($ millions)	2025	2024
Electric and gas revenue
United States
ITC	2,470	2,205
UNS Energy	2,646	2,731
Central Hudson	1,588	1,366
Canada
FortisBC Energy	1,766	1,538
FortisAlberta	793	770
FortisBC Electric	504	481
Newfoundland Power	795	770
Maritime Electric	296	277
FortisOntario	245	235
Caribbean
Caribbean Utilities	396	402
FortisTCI (Note 21)	85	118
Total electric and gas revenue	11,584	10,893
Other services revenue	316	350
Revenue from contracts with customers	11,900	11,243
Alternative revenue	151	169
Other revenue	119	96
Total revenue	12,170	11,508

Revenue from Contracts with Customers

Electric and gas revenue includes revenue from the sale and/or delivery of electricity and gas, transmission revenue, and wholesale electric revenue, all based on regulator-approved tariff rates including the flow through of commodity costs.

Other services revenue includes management fees at UNS Energy for the operation of Springerville Units 3 and 4 and revenue from other services that reflect the ordinary business activities of Fortis' utilities.

Alternative Revenue

Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria are met. Alternative revenue is recognized on an accrual basis with a corresponding regulatory asset or liability until the revenue is settled. Upon settlement, revenue is not recognized as revenue from contracts with customers but rather as settlement of the regulatory asset or liability. The significant alternative revenue programs of Fortis' utilities are summarized as follows.

ITC's formula rates include an annual true-up mechanism that compares actual revenue requirements to billed revenue, and any under- or over-collections are accrued as a regulatory asset or liability and reflected in future rates within a two year period (Note 8). The formula rates do not require annual regulatory approvals, although inputs remain subject to legal challenge.

UNS Energy's lost fixed-cost recovery mechanism ("LFCR") surcharge recovers lost fixed costs, as measured by a reduction in non-fuel revenue, associated with energy efficiency savings and distributed generation. To recover the LFCR regulatory asset, UNS Energy is required to file an annual LFCR adjustment request with the ACC for the LFCR revenue recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of total retail revenue.

FortisBC Energy and FortisBC Electric have an earnings sharing mechanism that provides for a 50/50 sharing of variances from the allowed ROE. Additionally, variances between forecast and actual customer-use rates and industrial and other customer revenue are captured in a revenue stabilization account and a flow-through deferral account, respectively, to be refunded to, or received from, customers in rates within two years.

Other Revenue

Other revenue primarily includes gains or losses on energy contract derivatives, as well as regulatory deferrals at FortisBC Energy and FortisBC Electric including cost recovery variances from forecast.

FORTIS INC.	DECEMBER 31, 2025	19
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

6. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS

($ millions)	2025	2024
Trade accounts receivable	813	1,009
Unbilled accounts receivable	760	738
Allowance for credit losses	(80)	(78)
	1,493	1,669
Other (1)	202	217
	1,695	1,886

(1) Consists mainly of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases, and the fair value of derivative instruments (Note 26)

Central Hudson has established deferred payment agreements with certain customers for the collection of trade accounts receivable. The non-current portion of these agreements has been reflected in other assets (Note 9).

Allowance for Credit Losses

The allowance for credit losses changed as follows.

($ millions)	2025	2024
Balance, beginning of year	(78)	(68)
Credit loss expensed	(38)	(30)
Credit loss deferral	(44)	(31)
Write-offs, net of recoveries	72	55
Dispositions (Note 21)	6	—
Foreign exchange	2	(4)
Balance, end of year	(80)	(78)

See Note 26 for disclosure on the Corporation's credit risk.

7. INVENTORIES

($ millions)	2025	2024
Materials and supplies	516	548
Gas and fuel in storage	58	65
Coal inventory	75	72
	649	685

8. REGULATORY ASSETS AND LIABILITIES

($ millions)	2025	2024
Regulatory assets
Deferred income taxes (Note 3)	2,424	2,248
Deferred energy management costs (1)	701	591
Rate stabilization and related accounts (2)	552	453
Employee future benefits (Notes 3 and 24)	192	235
Deferred lease costs (3)	145	142
Derivatives (Notes 3 and 26)	135	175
Deferred restoration costs (4)	109	133
Manufactured gas plant site remediation deferral (Note 16)	84	82
Business development deposit tax (5)	58	18
Generation early retirement costs (6)	49	66
Meter cost recovery (7)	37	—
Renewable natural gas account (8)	28	58
Other regulatory assets (9)	508	430
Total regulatory assets	5,022	4,631
Less: Current portion	(915)	(823)
Long-term regulatory assets	4,107	3,808	FORTIS INC.	DECEMBER 31, 2025	20
---	---	---
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

8. REGULATORY ASSETS AND LIABILITIES (cont'd)

($ millions)	2025	2024
Regulatory liabilities
Future cost of removal (Note 3)	1,853	1,728
Deferred income taxes (Note 3)	1,349	1,329
Employee future benefits (Notes 3 and 24)	467	459
Rate stabilization and related accounts (2)	183	208
Renewable energy surcharge (10)	164	155
Energy efficiency liability (11)	68	88
Electric and gas moderator account (12)	36	61
AESO charges deferral (13)	5	58
Other regulatory liabilities (9)	137	205
Total regulatory liabilities	4,262	4,291
Less: Current portion	(452)	(595)
Long-term regulatory liabilities	3,810	3,696

(1) Deferred Energy Management Costs: Certain regulated subsidiaries provide energy management services to facilitate customer energy efficiency programs where the related expenditures have been deferred as a regulatory asset and are being amortized, and recovered from customers through rates, on a straight-line basis over periods ranging from one to 10 years.

(2) Rate Stabilization and Related Accounts: Rate stabilization accounts mitigate the earnings volatility otherwise caused by variability in the cost of fuel, purchased power and natural gas above or below a forecast or predetermined level, and by weather-driven volume variability. At certain utilities, revenue decoupling mechanisms minimize the earnings impact of reduced energy consumption as energy efficiency programs are implemented. Resultant deferrals are recovered from, or refunded to, customers in future rates as approved by the respective regulators.

Related accounts include the annual true-up mechanism at ITC (Note 5).

(3) Deferred Lease Costs: Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") (Note 15). The depreciation of the asset under finance lease and interest expense on the finance lease obligation are not being fully recovered in current customer rates since these rates only reflect the cash payments required under the BPPA. The annual differences are being deferred as a regulatory asset, which is expected to be recovered from customers in future rates over the term of the lease, which expires in 2056.

(4) Deferred Restoration Costs: Incremental costs incurred at Central Hudson and Maritime Electric associated with restoration activities due to significant weather events. Incremental costs incurred in excess of that collected in customer rates at Central Hudson are recovered through rate stabilization accounts. The form and recovery period for Maritime Electric will be determined by the regulator.

(5) Business Development Deposit Tax: Relates to the recognition of temporary tax impacts associated with deposits received from Woodfibre LNG related to future capital expenditures for the Eagle Mountain Pipeline project. As capital expenditures related to the deposits are incurred, the corresponding deferred tax amounts will reverse.

(6) Generation Early Retirement Costs: Includes costs at TEP associated with the retirement of the Navajo Generating Station ("Navajo"), Sundt Generating Facility Units 1 and 2, and the San Juan Generating Station ("San Juan"), as approved for recovery by its regulator.

(7) Meter Cost Recovery: The meter cost recovery deferral primarily captures the net book value of FortisBC Energy's meters that have been removed from service as they are replaced by advanced metering infrastructure meters. The balance is to be recovered from customers over five years.

(8) Renewable Natural Gas Account: Reflects the variance between costs incurred to procure consumable biomethane gas and the related revenue recovered in customer rates. The difference is generally refunded or recovered from customers within one year.

(9) Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $50 million.

(10) Renewable Energy Surcharge: Under the ACC's Renewable Energy Standard ("RES"), UNS Energy was required to increase its use of renewable energy each year until it represented at least 15% of its total annual retail energy requirements. The cost of carrying out the plan is recovered from retail customers through a RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory liability or asset.

The ACC measures RES compliance through Renewable Energy Credits ("RECs"). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records their cost as long-term other assets (Note 9) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are utilized for RES compliance, energy supply costs and revenue are recognized in an equal amount.

(11) Energy Efficiency Liability: The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program, established to fund environmental policies associated with energy conservation programs as approved by its regulator.

(12) Electric and Gas Moderator Account: As part of past general rate applications at Central Hudson, certain regulatory assets and liabilities were offset and included in the electric and gas moderator account, which will be used for future customer rate moderation.

(13) AESO Charges Deferral: Relates to differences in revenue collected and amounts incurred for transmission-related items at FortisAlberta that are expected to be collected or refunded in customer rates.

FORTIS INC.	DECEMBER 31, 2025	21
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

9. OTHER ASSETS

($ millions)	2025	2024
Employee future benefits (Note 24)	648	551
Other investments	246	225
Equity investments (1)	215	259
RECs (Note 8)	169	176
Supplemental Executive Retirement Plan ("SERP")	123	127
Deferred payment agreements (Note 6)	80	—
Operating leases (Note 15)	60	64
Derivatives	32	48
Deferred compensation plan	29	29
Other	180	174
	1,782	1,653

(1) Includes investments in Belize Electricity until the October 31, 2025 date of disposition and Wataynikaneyap Power

ITC, UNS Energy and Central Hudson provide additional post-employment benefits through SERPs and deferred compensation plans for directors and officers. The assets held to support these plans are reported separately from the related liabilities (Note 16). Most plan assets are held in trust and funded mainly through life insurance policies and mutual funds. Assets in mutual and money market funds are recorded at fair value on a recurring basis (Note 26).

10. PROPERTY, PLANT AND EQUIPMENT

($ millions)	Cost	Accumulated Depreciation	Net Book Value
2025
Distribution
Electric	16,283	(4,233)	12,050
Gas	7,481	(1,910)	5,571
Transmission
Electric	23,849	(5,016)	18,833
Gas	3,057	(939)	2,118
Generation	7,450	(2,955)	4,495
Other	5,198	(1,730)	3,468
Assets under construction	3,886	—	3,886
Land	465	—	465
	67,669	(16,783)	50,886	2024
---	---	---	---
Distribution
Electric	15,771	(4,078)	11,693
Gas	7,148	(1,866)	5,282
Transmission
Electric	23,084	(4,865)	18,219
Gas	2,937	(894)	2,043
Generation	8,056	(3,110)	4,946
Other	5,014	(1,809)	3,205
Assets under construction	3,578	—	3,578
Land	490	—	490
	66,078	(16,622)	49,456	FORTIS INC.	DECEMBER 31, 2025	22
---	---	---
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

10. PROPERTY, PLANT AND EQUIPMENT (cont'd)

Electric distribution assets are those used to distribute electricity at lower voltages (generally below 69 kilovolts ("kV")). These assets include poles, towers and fixtures, low-voltage wires, transformers, overhead and underground conductors, street lighting, meters, metering equipment and other related equipment. Gas distribution assets are those used to transport natural gas at low pressures (generally below 2,070 kilopascals ("kPa")). These assets include distribution stations, telemetry, distribution pipe for mains and services, meter sets and other related equipment.

Electric transmission assets are those used to transmit electricity at higher voltages (generally at 69 kV and higher). These assets include poles, wires, switching equipment, transformers, support structures and other related equipment. Gas transmission assets are those used to transport natural gas at higher pressures (generally at 2,070 kPa and higher). These assets include transmission stations, telemetry, transmission pipe and other related equipment.

Generation assets are those used to generate electricity. These assets include hydroelectric and thermal generation stations, gas and combustion turbines, coal-fired generating stations, dams, reservoirs, photovoltaic systems, wind resources and other related equipment.

Other assets include buildings, equipment, vehicles, inventory, and information technology assets.

As at December 31, 2025, assets under construction largely reflect ongoing transmission projects at ITC and UNS Energy, the second Roadrunner Reserve battery storage project at UNS Energy and the Eagle Mountain Pipeline project at FortisBC Energy.

The cost of PPE under finance lease as at December 31, 2025 was $333 million (2024 - $324 million) and related accumulated depreciation was $125 million (2024 - $119 million) (Note 15).

Jointly Owned Facilities

UNS Energy and ITC hold undivided interests in jointly owned generating facilities and transmission systems, are entitled to their pro rata share of the PPE, and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2025, interests in jointly owned facilities consisted of the following.

	Ownership		Accumulated	Net Book
($ millions, except as indicated)	(%)	Cost	Depreciation	Value
Transmission Facilities	Various	1,743	(493)	1,250
Springerville Common Facilities	86.0	560	(342)	218
Springerville Coal Handling Facilities	83.0	285	(150)	135
Four Corners Units 4 and 5 ("Four Corners")	7.0	295	(156)	139
Gila River Common Facilities	50.0	139	(52)	87
Luna Energy Facility ("Luna")	33.3	100	8	108
		3,122	(1,185)	1,937

11. INTANGIBLE ASSETS

		Accumulated	Net Book
($ millions)	Cost	Amortization	Value
2025
Computer software	1,019	(417)	602
Land, transmission and water rights	1,170	(215)	955
Other	143	(90)	53
Assets under construction	113	—	113
	2,445	(722)	1,723	2024
---	---	---	---
Computer software	1,035	(493)	542
Land, transmission and water rights	1,188	(210)	978
Other	143	(95)	48
Assets under construction	93	—	93
	2,459	(798)	1,661

Included in the cost of land, transmission and water rights as at December 31, 2025 was $124 million (2024 - $123 million) not subject to amortization. Amortization expense was $160 million for 2025 (2024 - $153 million). Amortization is estimated to average approximately $111 million for each of the next five years.

FORTIS INC.	DECEMBER 31, 2025	23
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

12. GOODWILL

($ millions)	2025	2024
Balance, beginning of year	13,112	12,184
Disposition of FortisTCI (Note 21)	(50)	—
Foreign currency translation impacts (1)	(535)	928
Balance, end of year	12,527	13,112

(1) Relates to the translation of goodwill associated with the acquisitions of ITC, UNS Energy, Central Hudson, and Caribbean Utilities, whose functional currency is the U.S. dollar

No goodwill impairment was recognized by the Corporation in 2025 or 2024.

13. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES

($ millions)	2025	2024
Trade accounts payable	1,148	1,121
Customer and other deposits	516	360
Employee compensation and benefits payable	364	303
Dividends payable	332	314
Interest payable	319	305
Accrued taxes other than income taxes	245	304
Gas and fuel cost payable	215	221
Derivatives (Note 26)	127	169
Employee future benefits (Note 24)	28	29
Income tax payable	24	33
Other	185	194
	3,503	3,353
FORTIS INC.	DECEMBER 31, 2025	24
---	---	---
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

14. LONG-TERM DEBT

( millions)	Maturity Date	2025	2024
ITC
Secured U.S. First Mortgage Bonds -
	2027-2055	3,763	3,944
Secured U.S. Senior Notes -
	2028-2055	1,441	1,511
Unsecured U.S. Senior Notes -
	2026-2043	5,353	5,610
Unsecured U.S. Shareholder Note -
	2028	273	286
UNS Energy
Unsecured U.S. Fixed Rate Notes -
	2026-2055	4,460	4,172
Central Hudson
Unsecured U.S. Promissory Notes - 4.54% weighted
	2026-2060	2,058	1,974
FortisBC Energy
Unsecured Debentures -
	2026-2052	3,495	3,295
FortisAlberta
Unsecured Debentures -
	2034-2055	3,035	2,835
FortisBC Electric
Unsecured Debentures -
	2035-2054	960	960
Other Electric
Secured First Mortgage Sinking Fund Bonds -
	2026-2060	850	739
Secured First Mortgage Bonds -
	2027-2061	425	320
Unsecured Senior Notes -
	2041-2054	207	207
Unsecured U.S. Senior Loan Notes and Bonds -
	2028-2052	521	876
Corporate and Other
Unsecured U.S. Senior Notes and Promissory Notes -
	2026-2044	2,073	2,172
Unsecured Debentures -
	2039	200	200
Unsecured Senior Notes -
	2028-2033	2,600	2,000
Subordinated Notes - 5.10% fixed rate	2055	750	—
Long-term classification of credit facility borrowings		1,515	2,216
Fair value adjustment - ITC acquisition		78	88
Total long-term debt (Note 26)		34,057	33,405
Less: Deferred financing costs and debt discounts		(188)	(191)
Less: Current installments of long-term debt		(3,146)	(1,990)
		30,723	31,224

All values are in US Dollars.

Most long-term debt at the Corporation's regulated utilities is redeemable at the option of the respective utility at the greater of par or a specified price, together with accrued and unpaid interest. Security, if provided, is typically through a fixed or floating first charge on specific assets of the utility.

FORTIS INC.	DECEMBER 31, 2025	25
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

14. LONG-TERM DEBT (cont'd)

The Corporation's unsecured debentures and senior notes are redeemable at the option of Fortis at the greater of par or a specified price together with accrued and unpaid interest.

Certain long-term debt agreements have covenants that provide that the Corporation shall not declare, pay or make any restricted payments, including special or extraordinary dividends, if immediately thereafter its consolidated debt to consolidated capitalization ratio would exceed 65%.

Significant Long-Term Debt Issuances in 2025	Month Issued	Interest<br><br>Rate<br><br>(%)	Maturity	Amount<br><br>($ millions)	Use of Proceeds
UNS Energy
Unsecured senior notes	February	5.90	2055	US $300	(1) (2) 3)
Unsecured senior notes	October	5.38	2035	US $50	(1) (3)
Central Hudson
Unsecured senior notes	April	(4)	(4)	US $70	(1) (3)
Unsecured senior notes	November	(5)	(5)	US $80	(3)
FortisBC Energy
Unsecured debentures	October	3.38	2030	200	(1)
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)
Unsecured subordinated notes	September	5.10	2055	750	(1) (3)

(1) Repay credit facility borrowings

(2) Fund capital expenditures

(3) General corporate purposes

(4) Comprised of US$20 million at 5.61% due in 2035, US$30 million at 5.81% due in 2040 and US$20 million at 6.01% due in 2045

(5) Comprised of US$15 million at 5.25% due in 2035 and US$65 million at 5.90% due in 2045

As shown in the table above, Fortis issued fixed-to-fixed rate unsecured hybrid subordinated notes in 2025. The interest rate will be reset on December 4, 2030, and every five years thereafter, equal to the then five-year Government of Canada bond yield plus 2.09% provided that the interest rate will not be below the initial interest rate of 5.10%. The subordinated notes receive 50% equity treatment from credit rating agencies.

In January 2026, ITC issued US$250 million of secured senior notes consisting of US$125 million 10-year, 5.08% notes and US$125 million 20-year, 5.71% notes. Proceeds were used to repay credit facility borrowings, fund capital expenditures and for general corporate purposes.

Long-Term Debt Repayments

The consolidated requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows.

($ millions)	Total
2026	3,146
2027	2,389
2028	1,880
2029	943
2030	1,714
Thereafter	23,985
	34,057

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 also reestablished 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 December 31, 2025, $500 million remained available under the ATM Program and $1.5 billion remained available under the short-form base shelf prospectus.

FORTIS INC.	DECEMBER 31, 2025	26
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

14. LONG-TERM DEBT (cont'd)

Credit Facilities

($ millions)	Regulated<br>Utilities	Corporate<br>and Other	2025	2024
Total credit facilities	4,196	1,577	5,773	6,342
Credit facilities utilized:
Short-term borrowings (1)	(412)	—	(412)	(98)
Long-term debt (including current portion) (2)	(1,515)	—	(1,515)	(2,216)
Letters of credit outstanding	(83)	(22)	(105)	(102)
Credit facilities unutilized	2,186	1,555	3,741	3,926

(1) The weighted average interest rate was approximately 4.2% (2024 - 6.1%).

(2) The weighted average interest rate was approximately 3.8% (2024 - 4.6%). The current portion was $707 million (2024 - $1,860 million).

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.

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.

Consolidated credit facilities of approximately $5.8 billion as at December 31, 2025 are itemized below.

($ millions)	Amount		Maturity
Unsecured committed revolving credit facilities
Regulated utilities
ITC (1)	US	1,000	2028
UNS Energy	US	375	2028
Central Hudson	US	250	2029
FortisBC Energy	900		2030
FortisAlberta	300		2030
FortisBC Electric	200		2030
Other Electric	285		(2)
Other Electric	US	83	2030
Corporate and Other	1,350		(3)
Other facilities
Regulated utilities
Central Hudson - uncommitted credit facility	US	60	n/a
FortisBC Energy - uncommitted credit facility	55		2026
FortisBC Electric - unsecured demand overdraft facility	10		n/a
Other Electric - unsecured demand facilities	20		n/a
Corporate and Other
Unsecured revolving facility	US	150	2027
Unsecured non-revolving facility	22		n/a

(1) ITC also has a US$400 million commercial paper program, under which US$237 million was outstanding as at December 31, 2025 (2024 - $nil)

(2) $90 million in 2027, $65 million in 2028, and $130 million in 2030

(3) $50 million in 2027 and $1.3 billion in 2030

FORTIS INC.	DECEMBER 31, 2025	27
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

15. LEASES

The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 25 years, with optional renewal terms. Certain lease agreements include rental payments adjusted periodically for inflation or require the payment of real estate taxes, insurance, maintenance, or other operating expenses associated with the leased premises.

The Corporation's subsidiaries also have finance leases related to generating facilities with remaining terms of up to 30 years.

Leases were presented on the consolidated balance sheets as follows.

($ millions)	2025	2024
Operating leases
Other assets	60	64
Accounts payable and other current liabilities	(16)	(17)
Other liabilities	(44)	(47)
Finance leases (1)
Regulatory assets	145	142
PPE, net	208	205
Accounts payable and other current liabilities	(5)	(4)
Finance leases	(348)	(343)

(1) FortisBC Electric has a finance lease for the BPPA (Note 8), which relates to the sale of the output of the Brilliant hydroelectric plant, and for the Brilliant Terminal Station ("BTS"), which relates to the use of the station. Both agreements expire in 2056. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, which includes the original and ongoing capital cost, and related variable power purchase costs. The BTS requires semi-annual payments based on a charge related to the recovery of the capital cost of the BTS, and related variable operating costs.

The components of lease expense were as follows.

($ millions)	2025	2024
Operating lease cost	20	19
Finance lease cost:
Amortization	3	2
Interest	34	33
Variable lease cost	25	21
Total lease cost	82	75

As at December 31, 2025, the present value of minimum lease payments was as follows.

($ millions)	Operating<br>Leases	Finance<br>Leases	Total
2026	19	38	57
2027	13	37	50
2028	7	38	45
2029	6	38	44
2030	5	38	43
Thereafter	21	936	957
	71	1,125	1,196
Less: Imputed interest	(11)	(772)	(783)
Total lease obligations	60	353	413
Less: Current installments	(16)	(5)	(21)
	44	348	392	FORTIS INC.	DECEMBER 31, 2025	28
---	---	---
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

15. LEASES (cont'd)

Supplemental lease information follows.
($ millions, except as indicated)	2025	2024
Weighted average remaining lease term (years)
Operating leases	7	7
Finance leases	30	31
Weighted average discount rate (%)
Operating leases	4.8	4.6
Finance leases	5.1	5.0

16. OTHER LIABILITIES

($ millions)	2025	2024
Employee future benefits (Note 24)	429	446
AROs (Note 3)	260	249
Stock-based compensation plans (Note 20)	145	113
Customer and other deposits	118	128
Manufactured gas plant site remediation (1)	98	101
Deferred compensation plan (Note 9)	67	63
Operating leases (Note 15)	44	47
Derivatives (Note 26)	31	66
Mine reclamation obligations (2)	25	40
Retail energy contract (3)	14	20
Other	44	41
	1,275	1,314

(1) Environmental regulations require Central Hudson to investigate sites at which it or its predecessors once owned and/or operated manufactured gas plants and, if necessary, remediate those sites. Costs are accrued based on the amounts that can be reasonably estimated. Central Hudson has notified its insurers that it intends to seek reimbursement where insurance coverage exists. Differences between actual costs and the associated rate allowances are deferred as a regulatory asset for future recovery (Note 8).

(2) TEP pays ongoing reclamation costs related to two coal mines that supply generating facilities in which it has an ownership interest but does not operate. Costs are deferred as a regulatory asset and recovered from customers as permitted by the regulator.

(3) FortisAlberta has an agreement with a retail energy provider to act as its default retailer to eligible customers. As part of this agreement FortisAlberta received an upfront payment which is being amortized to revenue over the eight year agreement.

17. EARNINGS PER COMMON SHARE

Diluted earnings per share ("EPS") was calculated using the treasury stock method for stock options.

	2025			2024
	Net Earnings	Weighted		Net Earnings	Weighted
	to Common	Average		to Common	Average
	Shareholders	Shares	EPS	Shareholders	Shares	EPS
	($ millions)	(# millions)	($)	($ millions)	(# millions)	($)
Basic EPS	1,714	503.5	3.40	1,606	495.0	3.24
Potential dilutive effect of stock-based compensation	—	0.2	—	—	0.2	—
Diluted EPS	1,714	503.7	3.40	1,606	495.2	3.24
FORTIS INC.	DECEMBER 31, 2025	29
---	---	---
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

18. PREFERENCE SHARES

Authorized

An unlimited number of first preference shares and second preference shares, without nominal or par value.

Issued and Outstanding		2025			2024
First Preference Shares		Number			Number
	of Shares		Amount	of Shares		Amount
	(thousands)		( millions)	(thousands)		( millions)
Series F		5,000			5,000
Series G		9,200			9,200
Series H		7,903			7,665
Series I		2,097			2,335
Series J		8,000			8,000
Series K		10,000			10,000
Series M		24,000			24,000
		66,200			66,200

All values are in US Dollars.

Characteristics of the first preference shares are as follows:

			Reset			Right to
	Dividend	Annual	Dividend	Redemption	Redemption	Convert on
	Rate	Dividend	Yield	and/or Conversion	Value	a One-For-
First Preference Shares (1) (2)	(%)	($)	(%)	Option Date	($)	One Basis
Perpetual fixed rate
Series F	4.90	1.2250	—	Currently Redeemable	25.00	—
Series J	4.75	1.1875	—	Currently Redeemable	25.00	—
Fixed rate reset (3) (4)
Series G	6.12	1.5308	2.13	September 1, 2028	25.00	—
Series H	4.18	1.0458	1.45	June 1, 2030	25.00	Series I
Series K	5.47	1.3673	2.05	March 1, 2029	25.00	Series L
Series M	5.49	1.3733	2.48	December 1, 2029	25.00	Series N
Floating rate reset (4) (5)
Series I	(5)	—	1.45	June 1, 2030	25.00	Series H
Series L	—	—	—	—	—	Series K
Series N	—	—	—	—	—	Series M

(1) Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal installments on the first day of each quarter.

(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding first preference shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the first preference shares that reset, on every fifth anniversary date thereafter.

(3) On the redemption and/or conversion option date, and on each five-year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield.

(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their shares into an equal number of Cumulative Redeemable first preference shares of a specified series.

(5) The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.

On the liquidation, dissolution or winding-up of Fortis, holders of common shares are entitled to participate ratably in any distribution of assets of Fortis, subject to the rights of holders of first and second preference shares, and any other class of shares of the Corporation entitled to receive the assets of the Corporation on such a distribution, in priority to or ratably with the holders of the common shares.

FORTIS INC.	DECEMBER 31, 2025	30
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

19. ACCUMULATED OTHER COMPREHENSIVE INCOME

($ millions)	Opening Balance	Net Change		Ending Balance
2025
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations	2,712	(990)		1,722
Hedges of net investments in foreign operations	(714)	54	(1)	(660)
Income tax recovery (expense)	18	(7)		11
	2,016	(943)		1,073
Other
Interest rate hedges (Note 26)	72	(37)		35
Unrealized employee future benefits (losses) gains (Note 24)	(7)	5		(2)
Income tax (expense) recovery	(14)	9		(5)
	51	(23)		28
Accumulated other comprehensive income	2,067	(966)		1,101
2024
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations	1,059	1,653		2,712
Hedges of net investments in foreign operations	(452)	(262)		(714)
Income tax recovery	4	14		18
	611	1,405		2,016
Other
Interest rate hedges (Note 26)	62	10		72
Unrealized employee future benefits (losses) gains (Note 24)	(9)	2		(7)
Income tax expense	(11)	(3)		(14)
	42	9		51
Accumulated other comprehensive income	653	1,414		2,067

(1) Includes the derecognition of $86 million in foreign currency translation gains associated with dispositions in 2025 (Note 21)

20. STOCK-BASED COMPENSATION PLANS

Stock Options

Beginning January 1, 2022, the Corporation no longer grants stock options. Existing options to purchase common shares of the Corporation are exercisable for a period of 10 years from the grant date, expire no later than three years after the death or retirement of the optionee, and vest evenly over a four year period on each anniversary of the grant date. Compensation expense related to stock options was measured at the grant date using the Black-Scholes fair value option-pricing model with each grant amortized to compensation expense evenly over the four year vesting period, with the offsetting entry to additional paid-in capital. Fortis satisfies stock option exercises by issuing common shares from treasury. Upon exercise, proceeds are credited to capital stock at the option prices and the fair value of the options, as previously recognized, is reclassified from additional paid-in capital to capital stock.

As at December 31, 2025, the Corporation had 0.9 million stock options outstanding (2024 - 1.5 million) with a weighted average exercise price of $50.96 (2024 - $48.96). All stock options were vested as of December 31, 2025 (2024 – 1.4 million vested).

In 2025, 0.6 million stock options were exercised (2024 - 0.4 million) for cash proceeds of $28 million (2024 - $15 million) and an intrinsic value realized by option holders of $13 million (2024 - $5 million).

DSUs

Directors of the Corporation who are not officers are eligible for grants of DSUs representing the equity portion of their annual compensation. Directors can also elect to receive credit for their quarterly cash retainer in a notional account of DSUs in lieu of cash. The Corporation may also determine that special circumstances justify the grant of additional DSUs to a director.

Beginning in 2024, in any year in which a director satisfies their share ownership target, the director may elect to receive a portion of their equity compensation in cash or common shares, with the remaining portion to be granted as DSUs. Common share elections are satisfied quarterly through purchases on the Toronto Stock Exchange or the New York Stock Exchange.

Each DSU vests at the grant date, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash.

FORTIS INC.	DECEMBER 31, 2025	31
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

STOCK-BASED COMPENSATION PLANS (cont'd)

DSUs (cont'd)

The following table summarizes information related to DSUs.

	2025	2024
Number of units (thousands)
Beginning of year	241	241
Granted	20	29
Notional dividends reinvested	9	10
Paid out	(7)	(39)
End of year	263	241

The accrued liability has been recognized at the respective December 31st VWAP and included in other liabilities (Note 16). The accrued liability, compensation expense and cash payout were not material for 2025 or 2024.

PSUs

Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of PSUs representing a component of their long-term compensation.

Each PSU vests over a three-year period, has an underlying value equivalent to that of one common share of the Corporation, and is entitled to commensurate notional common share dividends. PSUs are generally settled in cash with cash payouts calculated at the end of the three year vesting period as the product of: (i) the number of units vested; (ii) the VWAP of the Corporation's common shares for the five trading days prior to the vesting date; and (iii) a payout percentage that may range from 0% to 200%. Effective with the 2024 grant, PSUs granted under the Corporation's Omnibus Equity Plan can be settled in cash or common shares of the Corporation. PSUs settled through common shares will be satisfied by issuing common shares from treasury.

The payout percentage is based on the Corporation's performance over the three-year vesting period, mainly determined by: (i) the Corporation's total shareholder return as compared to a predefined peer group of companies; (ii) the Corporation's cumulative EPS, or for subsidiaries the company's cumulative net income, as compared to the target established at the time of the grant; and (iii) a carbon reduction or climate-related performance measure.

The following table summarizes information related to PSUs.

	2024
Number of units (thousands)
Beginning of year	1,942
Granted	788
Notional dividends reinvested	78
Paid out	(609)
Cancelled/forfeited	(28)
End of year	2,171
Additional information ( millions)
Compensation expense recognized	53
Compensation expense unrecognized (1)	34
Cash payout	44
Accrued liability as at December 31 (2)	105
Aggregate intrinsic value as at December 31 (3)	139

All values are in US Dollars.

(1) Relates to unvested PSUs and is expected to be recognized over a weighted average period of two years

(2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in other liabilities (Notes 13 and 16)

(3) Relates to outstanding PSUs and reflects a weighted average contractual life of one year

FORTIS INC.	DECEMBER 31, 2025	32
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

STOCK-BASED COMPENSATION PLANS (cont'd)

RSUs

Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of RSUs representing a component of their long-term compensation.

Each RSU vests over a three-year period, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash or common shares of the Corporation. Effective with the 2024 grant, RSUs granted under the Corporation's Omnibus Equity Plan can be settled through common shares of the Corporation. RSUs settled through common shares will be satisfied by issuing common shares from treasury.

The following table summarizes information related to RSUs.

	2024
Number of units (thousands)
Beginning of year	1,079
Granted	464
Notional dividends reinvested	38
Paid out	(357)
Cancelled/forfeited	(23)
End of year	1,201
Additional information ( millions)
Compensation expense recognized	29
Compensation expense unrecognized (1)	21
Cash payout	19
Accrued liability as at December 31 (2)	54
Aggregate intrinsic value as at December 31 (3)	75

All values are in US Dollars.

(1) Relates to unvested RSUs and is expected to be recognized over a weighted average period of two years

(2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16)

(3) Relates to outstanding RSUs and reflects a weighted average contractual life of one year

Share-settlements were not material for 2025 and 2024.

21. DISPOSITIONS

On September 2, 2025, Fortis sold its 100% ownership interest in FortisTCI. As s 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.

On October 31, 2025, Fortis sold its 100% ownership in Fortis Belize and its 33% ownership in Belize Electricity. Fortis recognized a loss on sale of $31 million, which has been reflected in the Corporate and Other segment.

22. OTHER INCOME, NET

($ millions)	2025	2024
Equity component of AFUDC	174	139
Non-service component of net periodic benefit cost	80	73
Gain on derivatives, net	46	1
Interest income (1)	43	64
Equity income	15	14
Net foreign exchange gain (loss)	13	(10)
Pre-tax loss on dispositions (Note 21)	(32)	—
Other	1	7
	340	288

(1) Includes interest on short-term deposits, as well as interest on regulatory deferrals, including the PPFAC at TEP and UNS Electric

FORTIS INC.	DECEMBER 31, 2025	33
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

23. INCOME TAXES

Deferred Income Tax Assets and Liabilities

($ millions)	2025	2024
Gross deferred income tax assets
Regulatory liabilities	701	659
Tax loss and credit carryforwards	677	629
Employee future benefits	111	123
Other	185	216
	1,674	1,627
Valuation allowance	(25)	(50)
Net deferred income tax asset	1,649	1,577
Gross deferred income tax liabilities
PPE	(6,208)	(5,993)
Regulatory assets	(556)	(432)
Intangible assets	(177)	(172)
	(6,941)	(6,597)
Net deferred income tax liability	(5,292)	(5,020)

Income Tax Expense

($ millions)	2025		2024
Canadian
Earnings before income tax expense	565		518
Current income tax	102		154
Deferred income tax	(23)		(87)
Total Canadian	79	(1)	67
Foreign
Earnings before income tax expense	1,789		1,656
Current income tax	39		38
Deferred income tax	275		241
Total Foreign	314		279
Income tax expense	393		346

(1) Includes $31 million of income tax expense associated with the repatriation of proceeds on the dispositions of FortisTCI, Fortis Belize and Belize Electricity

Rate Reconciliation of Income Tax Expense

($ millions, except as indicated)	2025			2024
Earnings before income tax expense	2,354			2,174
Canadian federal statutory tax rate	353	15.0	%	326	15.0	%
Provincial income tax effect (1)	50	2.1	%	24	1.1	%
Effects of rate-regulated accounting	(47)	(2.0)	%	(29)	(1.3)	%
Other adjustments	(9)	(0.4)	%	(6)	(0.3)	%
Foreign tax rate effects
United States
Statutory tax rate difference between United States and Canada	150	6.4	%	132	6.1	%
Effects of rate-regulated accounting	(61)	(2.6)	%	(50)	(2.3)	%
Tax credits	(28)	(1.2)	%	(34)	(1.6)	%
Other foreign jurisdictions	(15)	(0.6)	%	(17)	(0.8)	%
Income tax expense and effective tax rate	393	16.7	%	346	15.9	%

(1) Provincial taxes in British Columbia and Alberta contributed the majority of the tax effect in this category.

FORTIS INC.	DECEMBER 31, 2025	34
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

23. INCOME TAXES (cont'd)

Income Tax Carryforwards(1)
($ millions)	Expiring Year	2025
Canadian
Non-capital loss	2028-2045	172
Other tax credits and restricted interest and financing expenses(2)	2033-2045	89
		261
Foreign
Federal and state net operating loss(3)	2026-2045	143
Other tax credits	2031-2045	273
		416
Total income tax carryforwards recognized		677

(1) Income tax carryforwards presented on an after-tax basis

(2) Indefinite carryforward for restricted interest and financing expenses

(3) Indefinite carryforward for Federal net operating losses, and for states that have adopted the Federal provisions, effective for tax years beginning after December 31, 2017

The Corporation and certain of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which the Corporation is subject to potential income tax compliance examinations include the United States (Federal, Arizona, Kansas, Iowa, Michigan, Minnesota and New York) and Canada (Federal, British Columbia and Alberta). The Corporation's 2020 to 2025 taxation years are still open for audit in Canadian jurisdictions, and its 2021 to 2025 taxation years are still open for audit in United States jurisdictions.

24. EMPLOYEE FUTURE BENEFITS

For DBP and OPEB plans, the benefit obligation and fair value of plan assets are measured as at December 31.

For the Corporation's Canadian and Caribbean subsidiaries, actuarial valuations to determine funding contributions for pension plans are required at least every three years. The most recent valuations were as of December 31, 2022 for Newfoundland Power, certain FortisBC Energy and FortisBC Electric plans, FortisAlberta and FortisOntario; December 31, 2023 for the Corporation; December 31, 2024 for the remaining FortisBC Energy and FortisBC Electric plans; and December 31, 2025 for Caribbean Utilities.

ITC, UNS Energy and Central Hudson perform annual actuarial valuations as their funding requirements are based on maintaining minimum annual targets, all of which have been met.

The Corporation's investment policy is to ensure that the DBP and OPEB plan assets, together with expected contributions, are invested in a prudent and cost-effective manner to optimally meet the liabilities of the plans. The investment objective is to maximize returns in order to manage the funded status of the plans and minimize the Corporation's cost over the long term, as measured by both cash contributions and recognized expense.

Allocation of Plan Assets	2025 Target Allocation
(weighted average %)		2025		2024
Equities	46		45		47
Fixed income	46		47		45
Real estate	7		7		7
Cash and other	1		1		1
	100		100		100
FORTIS INC.	DECEMBER 31, 2025	35
---	---	---
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

24. EMPLOYEE FUTURE BENEFITS (cont'd)

Fair Value of Plan Assets

($ millions)	Level 1 (1)	Level 2 (1)	Level 3 (1)	Total
2025
Equities	821	1,077	—	1,898
Fixed income	291	1,736	—	2,027
Real estate	—	—	309	309
Cash and other	16	25	—	41
	1,128	2,838	309	4,275
2024
Equities	773	1,168	—	1,941
Fixed income	268	1,561	—	1,829
Real estate	—	—	300	300
Cash and other	23	26	—	49
	1,064	2,755	300	4,119

(1) See Note 26 for a description of the fair value hierarchy.

The following table reconciles the changes in the fair value of plan assets that have been measured using Level 3 inputs.

($ millions)	2025	2024
Balance, beginning of year	300	291
Return on plan assets	7	5
Foreign currency translation	(2)	3
Purchases, sales and settlements	4	1
Balance, end of year	309	300
Funded Status	DBP Plans		OPEB Plans
---	---	---	---	---
($ millions)	2025	2024	2025	2024
Change in benefit obligation (1)
Balance, beginning of year	3,440	3,347	603	596
Service costs	71	74	23	25
Employee contributions	19	17	4	4
Interest costs	171	161	30	29
Benefits paid	(189)	(181)	(34)	(35)
Actuarial losses (gains)	27	(115)	(18)	(49)
Plan amendments/past service credits	40	(3)	—	—
Foreign currency translation	(84)	140	(19)	33
Balance, end of year (2)	3,495	3,440	589	603
Change in value of plan assets
Balance, beginning of year	3,613	3,313	506	430
Actual return on plan assets	331	249	66	50
Benefits paid	(180)	(174)	(28)	(31)
Employee contributions	19	17	4	4
Employer contributions	54	57	7	14
Foreign currency translation	(93)	151	(24)	39
Balance, end of year	3,744	3,613	531	506
Funded (unfunded) status	249	173	(58)	(97)
Balance sheet presentation
Other assets (Note 9)	474	395	174	156
Other current liabilities (Note 13)	(15)	(16)	(13)	(13)
Other liabilities (Note 16)	(210)	(206)	(219)	(240)
	249	173	(58)	(97)

(1)Amounts reflect projected benefit obligation for DBP plans and accumulated benefit obligation for OPEB plans.

(2)The accumulated benefit obligation, which excludes assumptions about future salary levels, for DBP plans was $3,184 million as at December 31, 2025 (2024 - $3,144 million).

FORTIS INC.	DECEMBER 31, 2025	36
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

24. EMPLOYEE FUTURE BENEFITS (cont'd)

For those DBP plans for which the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2025, the obligation was $1,020 million compared to plan assets of $840 million (2024 - $1,668 million and $1,460 million, respectively).

For those DBP plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2025, the obligation was $170 million compared to plan assets of $41 million (2024 - $195 million and $62 million, respectively).

For those OPEB plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2025, the obligation was $268 million compared to plan assets of $46 million (2024 - $296 million and $44 million, respectively).

Net Benefit Cost (1)	DBP Plans		OPEB Plans
($ millions)	2025	2024	2025	2024
Service costs	71	74	23	25
Interest costs	171	161	30	29
Expected return on plan assets	(214)	(221)	(28)	(26)
Amortization of actuarial gains	(15)	(1)	(33)	(17)
Amortization of past service credits/plan amendments	—	(1)	(1)	(1)
Regulatory adjustments	(2)	(1)	8	2
	11	11	(1)	12

(1) The non-service benefit cost components of net periodic benefit cost are included in other income, net in the consolidated statements of earnings.

The following table summarizes the accumulated amounts of net benefit cost that have not yet been recognized in earnings or comprehensive income and shows their classification on the consolidated balance sheets.

	DBP Plans		OPEB Plans
($ millions)	2025	2024	2025	2024
Unamortized net actuarial losses (gains)	6	11	(10)	(11)
Unamortized past service costs	2	1	4	6
Income tax (recovery) expense	(2)	(3)	1	1
Accumulated other comprehensive income	6	9	(5)	(4)
Net actuarial (gains) losses	(25)	46	(296)	(283)
Plan amendments/past service credits	39	(1)	(1)	(2)
Other regulatory deferrals	9	12	(1)	4
	23	57	(298)	(281)
Regulatory assets (Note 8)	192	235	—	—
Regulatory liabilities (Note 8)	(169)	(178)	(298)	(281)
Net regulatory assets (liabilities)	23	57	(298)	(281)
FORTIS INC.	DECEMBER 31, 2025	37
---	---	---
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

24. EMPLOYEE FUTURE BENEFITS (cont'd)

The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory liabilities.

	DBP Plans		OPEB Plans
($ millions)	2025	2024	2025	2024
Net actuarial (gains) losses	(5)	(1)	1	(1)
Past service costs (credits)/plan amendments	1	—	(2)	—
Income tax expense	1	—	—	—
Total recognized in comprehensive income	(3)	(1)	(1)	(1)
Net actuarial gains	(90)	(142)	(45)	(72)
Plan amendments	39	—	—	—
Amortization of actuarial gains	16	1	23	16
Amortization of past service credits	1	1	1	1
Foreign currency translation	3	(2)	9	(12)
Regulatory adjustments	(3)	23	(5)	2
Total recognized in regulatory liabilities	(34)	(119)	(17)	(65)
Significant Assumptions	DBP Plans		OPEB Plans
---	---	---	---	---
(weighted average %)	2025	2024	2025	2024
Discount rate as at December 31 (1)	5.24	5.25	5.36	5.43
Expected long-term rate of return on plan assets (2)	6.29	6.51	5.80	6.05
Rate of compensation increase	3.39	3.52	—	—
Health care cost trend increase as at December 31 (3)	—	—	4.40	4.53

(1)The discount rate used during the year was 5.25% for DBP plans (2024 - 4.84%) and 5.43% for OPEB plans (2024 - 4.96%). ITC and UNS Energy use the split discount rate methodology for determining current service and interest costs. All other subsidiaries use the single discount rate approach.

(2)Developed by management using best estimates of expected returns, volatilities and correlations for each class of asset. Best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.

(3)The projected 2026 health care cost trend rate is 6.60% and is assumed to decrease over the next 10 years to the ultimate health care cost trend rate of 4.40% in 2035 and thereafter.

Expected Benefit Payments
($ millions)	DBP Plans		OPEB Plans
2026	$	202	$	32
2027	205		32
2028	209		33
2029	216		34
2030	222		35
2031-2035	1,152		194

During 2026, the Corporation expects to contribute $52 million for DBP plans and $10 million for OPEB plans.

In 2025, the Corporation expensed $63 million (2024 - $58 million) related to defined contribution pension plans.

FORTIS INC.	DECEMBER 31, 2025	38
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

25. SUPPLEMENTARY CASH FLOW INFORMATION

($ millions)	2025	2024
Years ended December 31
Cash paid (received) for
Interest	1,469	1,361
Income taxes
Canadian	63	(34)
Foreign	(33)	17
	30	(17)
Change in working capital
Accounts receivable and other current assets	(52)	(2)
Prepaid expenses	(12)	(21)
Inventories	(45)	(73)
Regulatory assets - current portion	(94)	93
Accounts payable and other current liabilities	195	115
Regulatory liabilities - current portion	(110)	56
	(118)	168
Non-cash financing activity
Common share dividends reinvested	461	434
As at December 31
Non-cash investing and financing activities
Accrued capital expenditures	725	722
Contributions in aid of construction	11	14

26. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Derivatives

The Corporation generally limits 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 reliable 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 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 December 31, 2025, unrealized losses of $135 million (2024 - $175 million) were recognized as regulatory assets and unrealized gains of $37 million (2024 - $41 million) were recognized as regulatory liabilities.

FORTIS INC.	DECEMBER 31, 2025	39
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

26. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)

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. In 2025, gains of $39 million (2024 - $48 million) were recognized in revenue.

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. In 2025, unrealized gains of $24 million (2024 - $12 million) were recognized in other income, net.

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$448 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. In 2025, unrealized gains of $17 million (2024 - unrealized losses of $17 million) were recognized in other income, net.

Interest Rate Contracts

ITC has entered into five-year interest rate swap contracts with a combined notional value of US$755 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. In 2025, unrealized losses of US$5 million (2024 - unrealized gains of US$4 million) were recorded in other comprehensive income.

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. In 2025, unrealized gains of $9 million (2024 - unrealized losses of $29 million) were recorded in other comprehensive income.

FORTIS INC.	DECEMBER 31, 2025	40
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

26. 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 December 31, 2025
Assets
Energy contracts subject to regulatory deferral (2) (3)	—	51	—	51
Energy contracts not subject to regulatory deferral (2)	—	4	—	4
Total return swaps and foreign exchange contracts (2)	—	37	—	37
Other investments (4)	190	—	—	190
	190	92	—	282
Liabilities
Energy contracts subject to regulatory deferral (3) (5)	—	(149)	—	(149)
Energy contracts not subject to regulatory deferral (5)	—	(2)	—	(2)
Interest rate contracts and cross-currency interest rate swaps (5)	—	(23)	—	(23)
	—	(174)	—	(174)	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 long-term 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.

($ millions)	Gross Amount<br>Recognized In<br>Balance Sheet	Counterparty<br>Netting of<br>Energy Contracts	Cash Collateral<br>Posted/(Received)	Net Amount
As at December 31, 2025
Derivative assets	55	(29)	15	41
Derivative liabilities	(151)	29	—	(122)	As at December 31, 2024
---	---	---	---	---
Derivative assets	70	(30)	15	55
Derivative liabilities	(199)	30	—	(169)
FORTIS INC.	DECEMBER 31, 2025	41
---	---	---
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

26. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)

Volume of Derivative Activity

As at December 31, 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.

	2025	2024
Energy contracts subject to regulatory deferral (1)
Electricity swap contracts (GWh)	890	774
Electricity power purchase contracts (GWh)	395	430
Gas swap contracts (PJ)	183	236
Gas supply contracts (PJ)	147	105
Energy contracts not subject to regulatory deferral (1)
Wholesale trading contracts (GWh)	1,430	1,499
Gas swap contracts (PJ)	2	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 70% of its revenue is derived from three customers. These customers have investment-grade credit ratings and credit risk is further managed by the Midcontinent Independent System Operator 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 work with 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.

ITC, UNS Energy, Central Hudson, FortisBC Energy, and Fortis may be exposed to credit risk from 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 $99 million as at December 31, 2025 (2024 - $117 million).

Hedge of Foreign Net Investments

The reporting currency of ITC, UNS Energy, Central Hudson, and Caribbean Utilities is 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 December 31, 2025, US$1.9 billion (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$13.2 billion (2024 - US$12.6 billion) unhedged. Exchange rate fluctuations associated with the hedged 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 December 31, 2025, the carrying value of long-term debt, including the current portion, was $34.1 billion (2024 - $33.4 billion) compared to an estimated fair value of $32.3 billion (2024 - $31.3 billion).

FORTIS INC.	DECEMBER 31, 2025	42
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

27. COMMITMENTS AND CONTINGENCIES

As at December 31, 2025, unconditional minimum purchase obligations were as follows.

($ millions)	Total	Year 1	Year 2	Year 3	Year 4	Year 5	Thereafter
Gas and fuel purchase obligations (1)	6,592	908	689	586	491	416	3,502
Renewable PPAs (2)	2,374	158	174	173	165	173	1,531
Waneta Expansion capacity agreement (3)	2,307	58	59	60	61	63	2,006
Power purchase obligations (4)	1,135	251	156	129	127	124	348
ITC easement agreement (5)	342	14	14	14	14	14	272
UNS Energy EPC agreement (6)	269	110	143	16	—	—	—
Debt collection agreement (7)	96	3	3	3	3	3	81
Renewable energy credit purchase agreements (8)	50	18	6	6	5	5	10
Other (9)	122	27	12	9	9	2	63
	13,287	1,547	1,256	996	875	800	7,813

(1) FortisBC Energy ($5,295 million): includes contracts of $2,737 million for the purchase of renewable natural gas expiring in 2047 and contracts of $2,558 million for the purchase of gas, renewable gas, gas transportation and storage services, expiring in 2062. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2025. The renewable gas supply obligations disclosed reflect the contracted price per gigajoule between the Corporation and the suppliers.

UNS Energy ($1,190 million): includes long-term contracts for the purchase and delivery of coal to fuel generating facilities, the purchase of gas transportation services to meet load requirements, the purchase of transmission services for purchased power, as well as natural gas commodity agreements based on projected market prices as of December 31, 2025. Amounts paid for coal depend on actual quantities purchased and delivered. Certain contracts have price adjustment clauses that will affect future costs. These contracts have various expiry dates through 2048.

(2) TEP and UNS Electric are party to renewable power purchase agreements ("PPAs"), with expiry dates from 2027 through 2051, that require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities and RECs associated with the output delivered once commercial operation is achieved. The agreements include purchase commitments that are contingent upon the developers achieving commercial operation of the generating facilities, which are expected to be placed in service in 2026 and 2027. Amounts are the estimated future payments.

(3) FortisBC Electric is a party to an agreement to purchase capacity from the Waneta Expansion hydroelectric generating facility for forty-years, beginning April 2015.

(4) Maritime Electric ($496 million): includes an energy purchase agreement and transmission capacity contract for 30 MW of capacity to PEI with New Brunswick Power, expiring December 2026 and November 2032, respectively. The agreements entitle Maritime Electric to approximately 4.55% of the output of New Brunswick Power's Point Lepreau nuclear generating station and require Maritime Electric to pay its share of the station's capital and operating costs for the life of the unit.

FortisOntario ($314 million): an agreement with Hydro-Québec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated energy annually through December 2030.

FortisBC Electric ($271 million): an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term beginning October 1, 2013.

(5) ITC is party to an agreement with Consumers Energy, the primary customer of METC, which provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licenses associated with the land over which its transmission lines cross. The agreement runs through December 2050, subject to 10 automatic 50-year renewals thereafter unless METC gives notice of non-renewal at least one year in advance.

(6) UNS Electric has an engineering, procurement and construction ("EPC") agreement for the development of four gas engine turbines at the Black Mountain Generation Station, which are expected to be placed in service in 2028.

(7) Maritime Electric is party to a debt collection agreement with PEI Energy Corporation for the initial capital cost of the submarine cables and associated parts of the New Brunswick transmission system interconnection. Payments under the agreement, which expires in February 2056, are collected in customer rates.

(8) UNS Energy and Central Hudson are party to REC purchase agreements, mainly for the purchase of environmental attributions from retail customers with solar installations or other renewable generation. Payments are primarily made at contractually agreed-upon intervals based on metered energy production.

(9) Includes AROs and joint-use asset and shared service agreements.

FORTIS INC.	DECEMBER 31, 2025	43
Notes to Consolidated Financial Statements
---
For the years ended December 31, 2025 and 2024
---

27. COMMITMENTS AND CONTINGENCIES (cont'd)

Other Commitments

Under a funding framework with the Governments of Ontario and Canada, Fortis has met the minimum equity capital contribution requirement of approximately $165 million to Wataynikaneyap Power, based on Fortis' proportionate 39% ownership interest and the final regulatory-approved capital cost of the related project. Wataynikaneyap Power has construction financing loan agreements in place and it is expected that long-term operating financing will replace the construction financing. In the event a lender under the loan agreements realizes security on the loans, Fortis may be required to make additional equity capital contributions, which may be in excess of the amount otherwise required of Fortis under the funding framework, to a maximum total funding of $235 million.

UNS Energy has joint generation performance guarantees with participants at Four Corners and Luna, with agreements expiring in 2041 and 2046 respectively, and at San Juan and Navajo through decommissioning. The participants have guaranteed that in the event of payment default, each non-defaulting participant will bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. In the case of San Juan and Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of $343 million for Four Corners. As at December 31, 2025, there was no obligation under these guarantees.

TEP and UNS Electric have entered into long-term gas transportation precedent agreements to secure reliable access to natural gas. The agreements support the development of a new pipeline to be owned and operated by a third-party. Subject to the receipt of required regulatory approvals and other conditions, the pipeline is expected to be in service in 2029. Once the pipeline enters commercial operation, TEP and UNS Electric will enter into gas transportation service agreements with estimated purchase commitments of US$1.9 billion over 25 years.

Contingency

In November 2023, an explosion and fire occurred at a residence located in Wappingers Falls, New York, while a contractor was performing work on Central Hudson’s natural gas infrastructure adjacent to the residence. Civil actions seeking damages for bodily injuries, property damage and punitive damages remain pending. While these matters collectively could involve substantial amounts, based on the facts currently known, management is not able to estimate the potential loss, but believes their ultimate resolution will not have a material adverse effect on the financial position, results of operations, or cash flows of the Corporation.

FORTIS INC.	DECEMBER 31, 2025	44

Document

Exhibit 99.3

Management Discussion and Analysis
Contents
---	---	---	---
About Fortis	1	Cash Flow Summary	15
Performance at a Glance	2	Contractual Obligations	16
The Industry	5	Capital Structure and Credit Ratings	17
Operating Results	5	Capital Plan	18
Business Unit Performance	6	Business Risks	21
ITC	7	Accounting Matters	29
UNS Energy	7	Financial Instruments	32
Central Hudson	8	Long-Term Debt and Other	32
FortisBC Energy	8	Derivatives	32
FortisAlberta	8	Selected Annual Financial Information	34
FortisBC Electric	9	Fourth Quarter Results	35
Other Electric	9	Summary of Quarterly Results	37
Corporate and Other	10	Related-Party and Inter-Company Transactions	38
Non-U.S. GAAP Financial Measures	10	Management's Evaluation of Controls and Procedures	38
Regulatory Highlights	11	Outlook	38
Financial Position	13	Forward-Looking Information	39
Liquidity and Capital Resources	13	Glossary	40
Cash Flow Requirements	13	Annual Consolidated Financial Statements	F-1

Dated February 11, 2026

This MD&A has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. It should be read in conjunction with the 2025 Annual Financial Statements and is subject to the cautionary statement and disclaimer provided under "Forward-Looking Information" on page 39. 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 1.40 and 1.37 for the years ended December 31, 2025 and 2024, respectively; (ii) 1.37 and 1.44 as at December 31, 2025 and 2024, respectively; (iii) average of 1.39 and 1.40 for the quarters ended December 31, 2025 and 2024, respectively; and (iv) 1.35 for all forecast periods. Certain terms used in this MD&A are defined in the "Glossary" on page 40.

ABOUT FORTIS

Fortis (TSX/NYSE: FTS) is a diversified leader in the North American regulated electric and gas utility industry, with revenue of $12 billion in 2025 and total assets of $75 billion as at December 31, 2025. The Corporation's 9,900 employees serve 3.5 million utility customers in five Canadian provinces, ten U.S. states and the Caribbean. As at December 31, 2025, 65% of the Corporation's assets were located in the U.S., 33% in Canada and the remaining 2% in the Caribbean. Operations in the U.S. accounted for 58% of the Corporation's 2025 revenue, with the remaining 38% in Canada, and 4% in the Caribbean.

FORTIS INC.	DECEMBER 31, 2025	1
Management Discussion and Analysis
---

Fortis' regulated utility businesses are: ITC (electric transmission - Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas, Oklahoma and Wisconsin); UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas distribution - New York State); FortisBC Energy (natural gas transmission and distribution - British Columbia); FortisAlberta (electric distribution - Alberta); FortisBC Electric (integrated electric - British Columbia); Newfoundland Power (integrated electric - Newfoundland and Labrador); Maritime Electric (integrated electric - Prince Edward Island); FortisOntario (integrated electric - Ontario); and Caribbean Utilities (integrated electric - Grand Cayman). The Corporation also owns a 39% equity investment in Wataynikaneyap Power (electric transmission - Ontario). Fortis sold FortisTCI (integrated electric - Turks and Caicos Islands) on September 2, 2025 and its 33% equity investment in Belize Electricity (integrated electric - Belize) on October 31, 2025.

The Corporation's only non-regulated business was Fortis Belize (three hydroelectric generation facilities - Belize), which was also sold on October 31, 2025.

Additional information about the Corporation's business and reporting units is provided in Note 1 in the 2025 Annual Financial Statements.

PERFORMANCE AT A GLANCE
Key Financial Metrics
( millions, except as indicated)	2024	Variance
Common Equity Earnings
Actual	1,606	108
Adjusted (1)	1,626	151
Basic EPS ()
Actual	3.24	0.16
Adjusted (1)	3.28	0.25
Dividends
Paid per common share ()	2.39	0.10
Actual Payout Ratio (%)	73.6	(0.5)
Adjusted Payout Ratio (%) (1)	72.7	(2.3)
Weighted average number of common shares outstanding (# millions)	495.0	8.5
Operating Cash Flow	3,882	180
Capital Expenditures (1)	5,247	367

All values are in US Dollars.

(1)See "Non-U.S. GAAP Financial Measures" on page 10

Earnings and EPS

Common Equity Earnings increased by $108 million, or $0.16 per common share, compared to 2024. Earnings growth in 2025 was impacted by $63 million of losses associated with the dispositions of FortisTCI, Fortis Belize and Belize Electricity, approximately half of which related to income taxes. In addition, results for 2024 were unfavourably impacted by $20 million associated with the retroactive impact of a reduction in the MISO base ROE at ITC as approved by FERC.

FORTIS INC.	DECEMBER 31, 2025	2
Management Discussion and Analysis
---

Adjusted Common Equity Earnings and Adjusted Basic EPS, which exclude the losses associated with dispositions in 2025 and the retroactive ROE adjustment at ITC in 2024, as discussed previously, increased by $151 million and $0.25, respectively. Refer to "Non-U.S. GAAP Financial Measures" on page 10 for a reconciliation of these measures. The change in Adjusted Basic EPS is illustrated in the following chart.

(1) Includes FortisBC Energy, FortisAlberta and FortisBC Electric. Reflects Rate Base growth, including AFUDC 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 at FortisAlberta.

(2) Includes UNS Energy and Central Hudson. Reflects higher earnings at Central Hudson primarily due to Rate Base growth, the rebasing of costs effective July 1, 2024, 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 higher costs associated with Rate Base growth not yet reflected in customer rates, lower retail electricity sales due to milder weather, and lower margin on wholesale sales, partially offset by higher transmission revenue and AFUDC

(3) Reflects Rate Base growth, partially offset by higher non-recoverable stock-based compensation and holding company finance costs

(4) Reflects unrealized gains on foreign exchange contracts and total return swaps, partially offset by higher holding company finance and stock-based compensation costs

(5) Reflects average foreign exchange rate of 1.40 in 2025 compared to 1.37 in 2024, and the revaluation of U.S. dollar denominated short-term liabilities

(6) Weighted average shares of 503.5 million in 2025 compared to 495.0 million in 2024

Dividends

Fortis paid a dividend of $0.64 per common share in the fourth quarter of 2025, up 4.1% from 0.615 paid in each of the previous four quarters. This marked the Corporation's 52nd consecutive year of increases in dividends paid. The Adjusted Payout Ratio was 70% in 2025 and the Actual Payout Ratio averaged 73% over the three-year period of 2023 through 2025.

Fortis is targeting annual dividend growth of approximately 4-6% through 2030. See "Outlook" on page 38.

Growth in dividends and changes in 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	23.9	10.7	10.8	9.5

(1)Annualized TSR per Bloomberg, as at December 31, 2025

FORTIS INC.	DECEMBER 31, 2025	3
Management Discussion and Analysis
---

Operating Cash Flow

The $180 million increase in Operating Cash Flow was due to higher cash earnings, reflecting Rate Base growth, new customer delivery rates at Central Hudson as approved by the PSC, and the sale of investment tax credits at UNS Energy. The timing of transmission charges at FortisAlberta and the higher U.S. dollar-to-Canadian dollar exchange rate also contributed to growth in Operating Cash Flow. The increase was partially offset by: (i) the timing of flow-through costs at UNS Energy associated with higher PPFAC collections in 2024, and at FortisBC Energy related to the consumer carbon tax which was effectively repealed in 2025; (ii) the receipt of a tax refund at FortisBC Energy in 2024; and (iii) higher interest payments.

Capital Expenditures

Capital Expenditures is a Non-U.S. GAAP Financial Measure. Refer to "Non-U.S. GAAP Financial Measures" on page 10 and in the "Glossary" on page 40.

New Five-Year Capital Plan

The Corporation's 2026-2030 Capital Plan of $28.8 billion is the largest in the Corporation's history and 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 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. For a detailed discussion of the Corporation's capital expenditure program, see "Capital Plan" on page 18.

The five-year Capital Plan is expected to increase midyear Rate Base from $42.4 billion in 2025 to $57.9 billion by 2030, translating into a five-year CAGR of 7.0%.

PROJECTED RATE BASE (1)

FORTIS INC.	DECEMBER 31, 2025	4
Management Discussion and Analysis
---

THE INDUSTRY

The North American utility industry is undergoing significant transformation, driven by energy security and climate adaptation priorities, as well as projected growth in load driven by data centers, manufacturing and electrification. Together, these factors are creating substantial investment opportunities across the sector.

Policy makers and regulators at the federal, state, and provincial levels are increasingly prioritizing matters of energy security. The convergence of policy directives and forecasted load growth has resulted in opportunities to invest in renewable and natural gas generation, energy storage systems and transmission infrastructure. Continued electrification of heating and transportation represents another opportunity to expand the output and efficiency of the grid.

Grid resilience remains a focus with increased frequency and intensity of weather events such as extreme temperatures, hurricanes, wildfires, floods and storms. With electricity expected to represent a larger portion of society's energy mix, investments in resiliency are necessary to improve the grid's ability to withstand and recover from weather events.

Diversity of energy supply and enhanced integration of energy systems are vital to deliver the resilience, energy, and capacity needed to support economic growth and energy demand. Electric transmission is a critical enabler of load growth, interconnecting large-scale generation while improving system resilience. Natural gas generation provides a reliable source of energy and capacity necessary to meet growing energy needs. Natural gas investments, as well as energy storage solutions, will enable the adoption of additional renewable energy.

Fortis' culture of innovation underlies a continuous drive to find better ways to safely, reliably and affordably deliver the energy and services that customers need. Energy delivery systems are becoming more intelligent, with advanced meters, remote sensing, and grid automation. Energy management capabilities are expanding through emerging storage, demand response, and distributed energy management systems. More capable operational technology provides utilities with detailed usage data, advanced system control, enhanced inspection techniques, and predictive capabilities. In addition, investments in AI look to unlock potential in the data collected by the Corporation's utilities. With increased digitization and an ever-changing threat landscape, investments in cyber and physical security continue to be high priorities. These technological advancements and challenges offer strategic investment opportunities for Fortis' utilities.

A focus on customer experience is important for utilities as customer expectations evolve. Customers want to make informed energy choices and become active participants in the delivery of their energy. They also expect personalized service, customized self-service offerings, and real‑time, digital communication. At the same time, customer affordability is critical and remains a priority across Fortis' utilities. In response, our utilities are enhancing customer information systems, adopting digital technologies including AI, and advancing new and modern approaches to customer experience.

The Corporation's culture and decentralized structure support our utilities' efforts to meet changing customer expectations, address customer affordability, and work constructively with regulators and other stakeholders on policy, energy and service solutions. Fortis is well-positioned to support energy security, climate adaptation, and load growth across the Corporation's footprint.

OPERATING RESULTS
			Variance
($ millions)	2025	2024	FX	Other
Revenue	12,170	11,508	142	520
Energy supply costs	3,371	3,249	36	86
Operating expenses	3,250	3,040	40	170
Depreciation and amortization	2,057	1,927	21	109
Other income, net	340	288	13	39
Finance charges	1,478	1,406	17	55
Income tax expense	393	346	2	45
Net earnings	1,961	1,828	39	94
Net earnings attributable to:
Non-controlling interests	162	148	2	12
Preference equity shareholders	85	74	—	11
Common equity shareholders	1,714	1,606	37	71
Net earnings	1,961	1,828	39	94
FORTIS INC.	DECEMBER 31, 2025	5
---	---	---
Management Discussion and Analysis
---

Revenue

The increase in revenue, net of foreign exchange, was due to: (i) Rate Base growth; (ii) higher flow-through costs in customer rates; and (iii) the implementation of new customer delivery rates at Central Hudson as approved by the PSC. The increase was also due to the retroactive impact of a reduction in the MISO base ROE at ITC in 2024 as approved by FERC. The increase was partially offset by lower retail electricity sales due to milder weather, and lower wholesale sales revenue due to a reduction in short-term wholesale sales and lower pricing driven by market conditions at UNS Energy.

Energy Supply Costs

The increase in energy supply costs, net of foreign exchange, was primarily due to the flow through of higher commodity costs at FortisBC Energy and Central Hudson, partially offset by lower sales and the flow through of lower commodity costs at UNS Energy.

Operating Expenses

The increase in operating expenses, net of foreign exchange, was primarily due to general inflationary and employee-related cost increases and higher stock-based compensation costs.

Depreciation and Amortization

The increase in depreciation and amortization, net of foreign exchange, was due to continued investment in energy infrastructure at the Corporation's regulated utilities.

Other Income, Net

The increase in other income, net of foreign exchange, was due to higher AFUDC at UNS Energy and FortisBC Energy as well as unrealized gains on foreign exchange contracts and total return swaps. The increase was partially offset by the pre-tax loss on the disposition of Fortis Belize and Belize Electricity, as well as a reduction in interest income due to lower interest on short-term deposits and regulatory deferrals.

Finance Charges

The increase in finance charges, net of foreign exchange, was primarily due to higher debt levels to support the Corporation's Capital Plan.

Income Tax Expense

The increase in income tax expense, net of foreign exchange, was driven by income tax associated with the repatriation of proceeds on the dispositions of FortisTCI, Fortis Belize, and Belize Electricity, as well as higher earnings before income taxes.

Net Earnings

See "Performance at a Glance - Earnings and EPS" on page 2.

BUSINESS UNIT PERFORMANCE
Common Equity Earnings			Variance
($ millions)	2025	2024	FX (1)	Other
Regulated Utilities
ITC	592	542	11	39
UNS Energy	437	448	8	(19)
Central Hudson	191	128	3	60
FortisBC Energy	336	293	—	43
FortisAlberta	182	181	—	1
FortisBC Electric	75	72	—	3
Other Electric (2)	167	163	1	3
	1,980	1,827	23	130
Non-Regulated
Corporate and Other (3)	(266)	(221)	14	(59)
Common Equity Earnings	1,714	1,606	37	71

(1)The reporting currency 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; and Caribbean Utilities. Also includes FortisTCI up to the September 2, 2025 date of disposition and Belize Electricity up to the October 31, 2025 date of disposition

(3)Consists of non-regulated holding company expenses, earnings from non-regulated long-term contracted generation assets in Belize up to the October 31, 2025 date of disposition, and losses on the dispositions of FortisTCI, Fortis Belize and Belize Electricity in 2025

FORTIS INC.	DECEMBER 31, 2025	6
Management Discussion and Analysis
---
ITC			Variance
---	---	---	---	---
($ millions)	2025	2024	FX	Other
Revenue (1)	2,495	2,229	44	222
Earnings (1)	592	542	11	39

(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, was primarily due to Rate Base growth and higher flow-through costs in customer rates. The increase was also due to the recognition of a refund liability in 2024 associated with a decrease in the MISO base ROE from 10.02% to 9.98%, as approved by FERC in October 2024, for the 15-month period from November 2013 through February 2015 and prospectively from September 2016.

Earnings

The increase in earnings, net of foreign exchange, was primarily due to Rate Base growth. Growth in earnings was also due to FERC's approval of a reduction in the MISO base ROE in 2024, as discussed above, which resulted in a $20 million unfavourable impact to earnings in that year associated with the retroactive impact to prior periods. The increase in earnings was partially offset by higher non-recoverable stock-based compensation and holding company finance costs.

UNS Energy			Variance
($ millions, except as indicated)	2025	2024	FX	Other
Retail electricity sales (GWh)	10,734	10,870	—	(136)
Wholesale electricity sales (GWh) (1)	5,034	5,810	—	(776)
Gas sales (PJ)	16	17	—	(1)
Revenue	2,913	3,007	58	(152)
Earnings	437	448	8	(19)

(1) Primarily short-term wholesale sales

Sales

The decrease in retail electricity sales was primarily due to lower average use associated with milder temperatures in comparison to 2024.

The decrease in wholesale electricity sales 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 were relatively consistent with 2024.

Revenue

The decrease in revenue, net of foreign exchange, was primarily due to: (i) the recovery of overall lower fuel and non-fuel costs through the normal operation of regulatory mechanisms; (ii) lower electricity sales, discussed above; and (iii) lower pricing on wholesale sales. The decrease was partially offset by higher transmission revenue.

Earnings

The decrease in earnings, net of foreign exchange, was primarily due to: (i) higher costs associated with Rate Base growth not yet reflected in customer rates; (ii) lower retail electricity sales due to milder weather; and (iii) lower margin on wholesale sales, reflecting less favourable market conditions. The decrease was partially offset by higher transmission revenue and AFUDC.

FORTIS INC.	DECEMBER 31, 2025	7
Management Discussion and Analysis
---
Central Hudson			Variance
---	---	---	---	---
($ millions, except as indicated)	2025	2024	FX	Other
Electricity sales (GWh)	5,092	5,060	—	32
Gas sales (PJ)	30	25	—	5
Revenue	1,620	1,372	29	219
Earnings	191	128	3	60

Sales

The increase in electricity sales was due to higher average consumption by residential customers due to colder weather.

The increase in gas sales 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, was due to the flow-through of higher energy supply costs, Rate Base growth, and higher customer delivery rates as approved by the PSC.

Earnings

The increase in earnings, net of foreign exchange, was primarily due 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; and (iii) 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. This increase was partially offset by higher contributions made to a customer benefit fund in 2025.

FortisBC Energy
($ millions, except as indicated)	2025	2024	Variance
Gas sales (PJ)	217	220	(3)
Revenue	1,874	1,665	209
Earnings	336	293	43

Sales

The decrease in gas sales 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 fourth quarter of 2025.

Revenue

The increase in revenue was primarily due 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 was primarily due to Rate Base growth, including higher AFUDC associated with 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
($ millions, except as indicated)	2025	2024	Variance
Electricity deliveries (GWh)	17,561	17,324	237
Revenue	829	817	12
Earnings	182	181	1
FORTIS INC.	DECEMBER 31, 2025	8
---	---	---
Management Discussion and Analysis
---

Deliveries

The increase in electricity deliveries was primarily due to higher average consumption by industrial customers, largely reflecting 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.

Revenue and Earnings

The increase in revenue and earnings 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.

FortisBC Electric
($ millions, except as indicated)	2025	2024	Variance
Electricity sales (GWh)	3,619	3,513	106
Revenue	557	545	12
Earnings	75	72	3

Sales

The increase in electricity sales was due to higher average consumption by industrial and commercial customers, partially offset by lower average consumption by residential customers due to milder weather in the second half of 2025.

Revenue

The increase in revenue was primarily due to higher electricity sales, higher energy supply costs recovered from customers and Rate Base growth.

Earnings

The increase in earnings was primarily due to Rate Base growth.

Due to regulatory deferral mechanisms, changes in consumption levels do not materially impact earnings.

Other Electric			Variance
($ millions, except as indicated)	2025	2024	FX	Other
Electricity sales (GWh)	9,918	9,879	—	39
Revenue	1,851	1,838	10	3
Earnings	167	163	1	3

Sales

The increase in electricity sales was due to higher average consumption by residential and commercial customers, as well as customer additions. Higher average consumption by 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 impact of the September 2025 disposition of FortisTCI.

Revenue

The increase in revenue, net of foreign exchange, was primarily due to Rate Base growth and higher electricity sales, as well as the July 1, 2025 electricity rate change at Newfoundland Power. The increase was partially offset by the disposition of FortisTCI, the flow-through of lower energy supply costs recovered from customers and the operation of regulatory deferral mechanisms at Newfoundland Power.

Earnings

The increase in earnings, net of foreign exchange, was primarily due to Rate Base growth and higher electricity sales, partially offset by the September 2025 disposition of FortisTCI.

FORTIS INC.	DECEMBER 31, 2025	9
Management Discussion and Analysis
---
Corporate and Other			Variance
---	---	---	---	---
($ millions)	2025	2024	FX	Other
Electricity sales (GWh) (1)	167	215	—	(48)
Revenue (1)	31	35	1	(5)
Net loss (2)	(266)	(221)	14	(59)

(1) Reflects Fortis Belize up to the October 31, 2025 date of disposition

(2) Includes non-regulated holding company expenses, earnings for Fortis Belize up to the October 31, 2025 date of disposition, and losses on the dispositions of FortisTCI, Fortis Belize and Belize Electricity in 2025

Sales and Revenue

The decrease in electricity sales and revenue was due to the impact of the October 2025 disposition of Fortis Belize.

Net Loss

The increase in net loss was driven by $63 million of losses associated with the dispositions of FortisTCI, Fortis Belize and Belize Electricity, approximately half of which related to income taxes.

Excluding the impact of the dispositions, the net loss decreased by $4 million due to unrealized gains on foreign exchange contracts in 2025, as compared to unrealized losses in 2024, as well as higher unrealized gains on total return swaps, partially offset by higher finance and stock-based compensation costs. Lower earnings contribution from Fortis Belize due to the October 2025 disposition also unfavourably impacted the net loss.

The favourable foreign exchange impact was primarily due to foreign exchange gains in 2025, as compared to losses in 2024, associated with the revaluation of U.S. dollar denominated short-term liabilities.

NON-U.S. GAAP FINANCIAL MEASURES

Adjusted Common Equity Earnings, Adjusted Basic EPS, Adjusted Payout Ratio and Capital Expenditures are Non-U.S. GAAP Financial Measures and may not be comparable with 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. The Actual Payout Ratio calculated using Common Equity Earnings is the most comparable U.S. GAAP measure to the Adjusted Payout Ratio. 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 consolidated 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.

FORTIS INC.	DECEMBER 31, 2025	10
Management Discussion and Analysis
---
Non-U.S. GAAP Reconciliation
---	---	---	---
($ millions, except as indicated)	2025	2024	Variance
Adjusted Common Equity Earnings, Adjusted Basic EPS<br><br>and Adjusted Payout Ratio
Common Equity Earnings	1,714	1,606	108
Adjusting items:
Dispositions (1)	63	—	63
October 2024 MISO base ROE decision (2)	—	20	(20)
Adjusted Common Equity Earnings	1,777	1,626	151
Adjusted Basic EPS (3) ($)	3.53	3.28	0.25
Adjusted Payout Ratio (4) (%)	70.4	72.7	(2.3)
Capital Expenditures
Additions to property, plant and equipment	5,942	5,012	930
Additions to intangible assets	292	206	86
Adjusting items:
Eagle Mountain Pipeline Project (5)	(620)	—	(620)
Wataynikaneyap Transmission Power Project (6)	—	29	(29)
Capital Expenditures	5,614	5,247	367

(1) Represents losses on the dispositions of FortisTCI, Fortis Belize and the Corporation's 33% ownership in Belize Electricity, inclusive of income tax expense of $31 million, included in the Corporate and Other segment

(2) Represents the prior period impact of FERC's October 2024 MISO base ROE decision, net of income tax recovery of $7 million, included in the ITC segment

(3) Calculated using Adjusted Common Equity Earnings divided by weighted average common shares of 503.5 million in 2025 (2024 - 495.0 million)

(4) Calculated using dividends paid per common share of $2.49 in 2025 (2024 - $2.39) divided by Adjusted Basic EPS

(5) Represents CIACs received for the Eagle Mountain Pipeline project, included in the FortisBC Energy segment

(6) Represents Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power project, included in the Other Electric segment. Construction was completed in the second quarter of 2024

REGULATORY HIGHLIGHTS

General

The earnings of the Corporation's regulated utilities are determined under COS regulation, with some using PBR mechanisms.

Under COS regulation, the regulator sets customer rates to permit a reasonable opportunity for the timely recovery of the estimated costs of providing service, including a fair rate of return on a deemed or targeted capital structure applied to an approved Rate Base. PBR mechanisms generally apply a formula that incorporates inflation and assumed productivity improvements for a set term.

The ability to recover prudently incurred costs of providing service and earn the regulator‑approved ROE or ROA may depend on achieving the forecasts established in the rate-setting process. There can be varying degrees of regulatory lag between when costs are incurred and when they are recovered in customer rates. As well, the Corporation's regulated utilities, where applicable, are permitted by their respective regulators to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms.

Transmission operations in the U.S. are regulated federally by FERC. Remaining utility operations in the U.S. and Canada are regulated by state or provincial regulators. Utility operations in the Cayman Islands are regulated by the country's regulatory authority.

Additional information about regulation and the regulatory matters discussed below is provided in Note 2 in the 2025 Annual Financial Statements. Also refer to "Business Risks - Utility Regulation" on page 22.

FORTIS INC.	DECEMBER 31, 2025	11
Management Discussion and Analysis
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Significant Regulatory Matters

ITC

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

FortisAlberta

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 COS revenue requirement as approved by the AUC. In March 2025, the Court of Appeal granted FortisAlberta permission to appeal, which was heard in January 2026. A decision is expected in the third quarter of 2026.

FORTIS INC.	DECEMBER 31, 2025	12
Management Discussion and Analysis
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FINANCIAL POSITION

Significant Changes between December 31, 2025 and 2024
Balance Sheet Account	Variance
($ millions)	FX	Other	Explanation
Cash and cash equivalents	(19)	166	Primarily due to the timing of capital and operating requirements at UNS Energy, and unused proceeds from the disposition of Fortis Belize and Belize Electricity. Balances on hand have been invested in interest-bearing accounts and will be utilized in 2026.
Accounts receivable and other current assets	(53)	(138)	Primarily reflects a decrease in accounts receivable associated with collection efforts at Central Hudson, as well as a shift in long-term receivables associated with deferred payment agreements to other assets.
Other assets	(60)	189	Primarily due to an increase in employee future benefits assets, driven by investment returns on DBP and OPEB plans, and an increase in long-term receivables associated with deferred payment agreements at Central Hudson.
Regulatory assets (current and long-term)	(62)	453	Due to changes associated with various regulatory mechanisms including an increase in deferred income taxes, deferred energy management costs, and the normal operation of rate stabilization accounts.
Property, plant and equipment, net	(1,516)	2,946	Due to capital expenditures, partially offset by depreciation expense and CIACs, as well as the dispositions of FortisTCI and Fortis Belize.
Intangible assets, net	(56)	118	Largely reflects investments in computer software across the utilities.
Short-term borrowings	(4)	318	Reflects the issuance of commercial paper at ITC to finance working capital requirements.
Accounts payable & other current liabilities	(73)	223	Primarily due to an increase in deposits associated with the construction of the Eagle Mountain Pipeline project at FortisBC Energy.
Deferred income taxes	(152)	424	Primarily due to higher temporary differences associated with ongoing capital investments.
Long-term debt (including current portion)	(985)	1,640	Due to debt issuances in support of the Corporation's Capital Plan, partially offset by debt and credit facility repayments and the disposition of FortisTCI.
Shareholders' equity	(943)	945	Due primarily to: (i) Common Equity Earnings for 2025, less dividends declared on common shares; and (ii) the issuance of common shares, largely under the DRIP.

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.

FORTIS INC.	DECEMBER 31, 2025	13
Management Discussion and Analysis
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Credit Facilities
As at December 31	Regulated	Corporate
($ millions)	Utilities	and Other	2025	2024
Total credit facilities (1)	4,196	1,577	5,773	6,342
Credit facilities utilized:
Short-term borrowings	(412)	—	(412)	(98)
Long-term debt (including current portion)	(1,515)	—	(1,515)	(2,216)
Letters of credit outstanding	(83)	(22)	(105)	(102)
Credit facilities unutilized	2,186	1,555	3,741	3,926

(1)Additional information about the Corporation's credit facilities is provided in Note 14 in the 2025 Annual Financial Statements

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.

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 such capital structures will impact its ability to pay dividends in the foreseeable future.

As at December 31, 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.

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 also reestablished 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 December 31, 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. This 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 reasonable access to long-term capital.

Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2025 and are expected to remain compliant.

FORTIS INC.	DECEMBER 31, 2025	14
Management Discussion and Analysis
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Cash Flow Summary
---	---	---	---
Summary of Cash Flows
Years ended December 31
($ millions)	2025	2024	Variance
Cash and cash equivalents, beginning of year	220	625	(405)
Cash from (used in):
Operating activities	4,062	3,882	180
Investing activities	(5,357)	(5,395)	38
Financing activities	1,461	1,064	397
Effect of exchange rate changes on cash and cash equivalents	(19)	44	(63)
Cash and cash equivalents, end of year	367	220	147

Operating Activities

See "Performance at a Glance - Operating Cash Flow" on page 4.

Investing Activities

Cash used in investing activities was $38 million lower than 2024 primarily due to proceeds received on the dispositions of FortisTCI, Fortis Belize and Belize Electricity, partially offset by: (i) higher Capital Expenditures, net of CIACs; (ii) higher demand side management expenditures at FortisBC; and (iii) the higher U.S. dollar-to-Canadian dollar exchange rate.

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 13. The increase in cash from financing activities in 2025 primarily reflected an increase in borrowings to support capital investments.

Debt Financing	Month<br>Issued	Interest Rate<br><br>(%)	Maturity	Amount<br><br>($ millions)	Use of Proceeds
Significant Long-Term Debt Issuances
Year ended December 31, 2025
UNS Energy
Unsecured senior notes	February	5.90	2055	US $300	(1) (2) 3)
Unsecured senior notes	October	5.38	2035	US $50	(1) (3)
Central Hudson
Unsecured senior notes	April	(4)	(4)	US $70	(1) (3)
Unsecured senior notes	November	(5)	(5)	US $80	(3)
FortisBC Energy
Unsecured debentures	October	3.38	2030	200	(1)
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)
Unsecured subordinated notes	September	5.10	2055	750	(1) (3)

(1) Repay credit facility borrowings

(2) Fund capital expenditures

(3) General corporate purposes

(4) Comprised of US$20 million at 5.61% due in 2035, US$30 million at 5.81% due in 2040 and US$20 million at 6.01% due in 2045

(5) Comprised of US$15 million at 5.25% due in 2035 and US$65 million at 5.90% due in 2045

FORTIS INC.	DECEMBER 31, 2025	15
Management Discussion and Analysis
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Common Equity Financing
Common Equity Issuances and Dividends Paid
Years ended December 31
($ millions, except as indicated)	2025	2024	Variance
Common shares issued:
Cash (1)	60	46	14
Non-cash (2)	463	435	28
Total common shares issued	523	481	42
Number of common shares issued (# millions)	8.0	8.7	(0.7)
Common share dividends paid:
Cash	(788)	(744)	(44)
Non-cash (3)	(461)	(434)	(27)
Total common share dividends paid	(1,249)	(1,178)	(71)
Dividends paid per common share ($)	2.49	2.39	0.10

(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

On December 4, 2025 and February 11, 2026, Fortis declared a dividend of $0.64 per common share payable on March 1, 2026 and June 1, 2026, respectively. 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
As at December 31, 2025
($ millions)	Total	Year 1	Year 2	Year 3	Year 4	Year 5	Thereafter
Long-term debt:
Principal (1)	34,057	3,146	2,389	1,880	943	1,714	23,985
Interest	20,627	1,423	1,338	1,253	1,213	1,168	14,232
Finance leases (2)	1,125	38	37	38	38	38	936
Other obligations (3)	562	188	123	128	23	23	77
Other commitments: (4)
Gas and fuel purchase obligations	6,592	908	689	586	491	416	3,502
Renewable power purchase agreements	2,374	158	174	173	165	173	1,531
Waneta Expansion capacity agreement	2,307	58	59	60	61	63	2,006
Power purchase obligations	1,135	251	156	129	127	124	348
ITC easement agreement	342	14	14	14	14	14	272
UNS Energy EPC agreement	269	110	143	16	—	—	—
Debt collection agreement	96	3	3	3	3	3	81
Renewable energy credit purchase agreements	50	18	6	6	5	5	10
Other	122	27	12	9	9	2	63
	69,658	6,342	5,143	4,295	3,092	3,743	47,043

(1)Amounts not reduced by unamortized deferred financing and discount costs of $188 million. Additional information is provided in Note 14 of the 2025 Annual Financial Statements

(2)Additional information is provided in Note 15 of the 2025 Annual Financial Statements

(3)Primarily includes commitments with respect to long-term compensation and employee future benefit arrangements

(4)Represents unrecorded commitments. Additional information is provided in Note 27 of the 2025 Annual Financial Statements

FORTIS INC.	DECEMBER 31, 2025	16
Management Discussion and Analysis
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Other Commitments

The Corporation's utilities are obligated to provide service to customers within their respective service territories. Capital Expenditures are forecast to be approximately $5.6 billion for 2026 and approximately $28.8 billion for the five-year 2026-2030 Capital Plan. See "Capital Plan" on page 18.

TEP has 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, was approved by the ACC in December 2025 but remains subject to other contractual contingencies. The energy supply agreement provides additional consumer protections such as establishing minimum monthly payment obligations that apply irrespective of customer energy use, termination fees supported by financial assurance mechanisms, and imposing credit standards designed to mitigate the risk of default. The initial phase of the data center campus is expected to be operational as early as 2027, with a ramp schedule through 2029. TEP currently expects to serve the customer from its existing and planned capacity, including solar and battery storage projects currently in development.

Off-Balance Sheet Arrangements

With the exception of letters of credit outstanding of $105 million as at December 31, 2025, the unrecorded commitments in the table above and the "Other Commitments" discussed above, the Corporation had no off-balance sheet arrangements.

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	2025		2024
As at December 31	($ millions)	(%)	($ millions)	(%)
Debt (1)	34,262	57.0	33,435	56.4
Preference shares	1,623	2.7	1,623	2.7
Common shareholders' equity and non-controlling interests (2)	24,246	40.3	24,230	40.9
	60,131	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 December 31, 2025 (December 31, 2024 - 3.4%)

Outstanding Share Data

As at February 11, 2026, the Corporation had issued and outstanding 507.4 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 February 11, 2026, an additional 0.9 million common shares would be issued and outstanding.

FORTIS INC.	DECEMBER 31, 2025	17
Management Discussion and Analysis
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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 December 31, 2025	Rating	Type	Outlook
S&P	A-	Issuer	Stable
	BBB+	Unsecured debt
Fitch	BBB+	Issuer	Stable
	BBB+	Unsecured debt
Morningstar DBRS	A (low)	Issuer	Stable
	A (low)	Unsecured debt	Stable

In May 2025, Fitch assigned first time issuer and senior unsecured debt ratings of BBB+ to the Corporation with a stable outlook.

In January 2026, Moody’s Investor Services, Inc. withdrew its ratings for Fortis at the Corporation's request. The withdrawal does not impact the subsidiary credit ratings.

Capital Plan

Capital investment in energy infrastructure is required to ensure the continued and enhanced performance, reliability and safety of the electricity and gas systems, to meet customer growth, and to facilitate the interconnection of new energy resources.

2025 Capital Expenditures (1)(2)
	Regulated Utilities							Total<br>Regulated<br>Utilities	Non-Regulated Corporate and Other	Total
($ millions, except as indicated)	ITC	UNS<br>Energy	Central<br>Hudson	FortisBC<br>Energy	Fortis<br>Alberta	FortisBC<br>Electric	Other Electric
Total	1,840	1,365	481	650	598	186	491	5,611	3	5,614
Forecast 2026 Capital Expenditures (2)(3)
---	---	---	---	---	---	---	---	---	---	---
	Regulated Utilities							Total<br>Regulated<br>Utilities	Non-Regulated Corporate and Other	Total
($ millions, except as indicated)	ITC	UNS<br><br>Energy	Central<br><br>Hudson	FortisBC<br><br>Energy	Fortis<br><br>Alberta	FortisBC<br><br>Electric	Other Electric
Total	1,874	1,281	466	712	614	207	462	5,616	—	5,616
2026-2030 Capital Plan (2)(3)
---	---	---	---	---	---	---
($ billions)	2026	2027	2028	2029	2030	Total
Five-year Capital Plan	5.6	5.9	5.6	6.2	5.5	28.8

(1)See "Non-U.S. GAAP Financial Measures" on page 10. Reflects a U.S. dollar-to-Canadian dollar exchange rate of 1.40 for 2025

(2)Excludes the non-cash equity component of AFUDC

(3)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 2026-2030 Capital Plan by approximately $0.7 billion over the five-year planning period

FORTIS INC.	DECEMBER 31, 2025	18
Management Discussion and Analysis
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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 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.

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, new or revised tariffs and other 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. These factors could change and cause actual expenditures to differ from forecast.

Midyear Rate Base (1)
($ billions)	2025(2)	2026(2)	2030(2)
ITC	13.9	14.6	19.8
UNS Energy	8.4	8.9	11.5
Central Hudson	3.7	4.0	5.0
FortisBC Energy	6.5	6.8	8.8
FortisAlberta	4.7	4.8	5.9
FortisBC Electric	1.8	1.9	2.3
Other Electric	3.4	3.7	4.6
Total	42.4	44.7	57.9

(1) Simple average of Rate Base at beginning and end of the year

(2) Reflects a U.S. dollar-to-Canadian dollar average exchange rate of 1.40 for 2025. 2026 and 2030 reflect an assumed U.S. dollar-to-Canadian dollar exchange rate of 1.35 consistent with the Corporation's 2026-2030 Capital Plan. On average, Fortis estimates that a five-cent increase or decrease in the U.S. dollar relative to the Canadian dollar would increase or decrease Rate Base by approximately $1.4 billion over the five-year planning period

Total midyear Rate Base is forecast to grow to $57.9 billion by 2030 underpinned by the five-year Capital Plan, translating to a CAGR of 7.0%.

Major Capital Projects			Plan	Expected
($ millions)	Pre-2025	Actual 2025	2026-2030	Completion
ITC
MISO LRTP Tranche 1	89	173	1,812	2030
MISO LRTP Tranche 2.1	—	8	529	Post-2030
Big Cedar Load Expansion	5	172	394	2028
UNS Energy
TEP Transmission Project	—	—	608	2029
Springerville Natural Gas Conversion	—	—	238	2030
Black Mountain Gas Generation	1	58	339	2028
Vail-to-Tortolita Transmission Project	199	144	147	2027
Roadrunner Reserve Battery Storage Project	116	345	3	2026
FortisBC Energy
Tilbury LNG Storage Expansion	35	5	627	Post-2030
AMI Project	37	136	570	2028
Tilbury 1B Project	49	12	342	2030
Eagle Mountain Pipeline Project (1)	436	14	274	2027
Total		1,067	5,883

(1)Net of customer contributions

FORTIS INC.	DECEMBER 31, 2025	19
Management Discussion and Analysis
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MISO LRTP - Tranches 1 and 2.1

Six projects included in the first tranche of the MISO LRTP portfolio run through ITC's MISO operating companies' service territories. A majority of ITC's planned investment associated with these projects has been 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 21).

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 will support customer affordability, local communities, and reliability, and satisfies the need for replacement capacity included in TEP's 2023 IRP.

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 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 facilities, 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 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.

FORTIS INC.	DECEMBER 31, 2025	20
Management Discussion and Analysis
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Additional Investment Opportunities

Fortis is pursuing additional investment opportunities within existing service territories that are not yet included in the five-year Capital Plan.

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 16), 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.

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 energy infrastructure investments to support the acceleration of load growth across our jurisdictions.

GHG Emissions Reduction Targets

Fortis is primarily an energy delivery company with approximately 95% 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. The Corporation has made consistent progress to decarbonize its energy mix and deliver cleaner energy to customers, achieving an approximate 38% reduction in scope 1 GHG emissions through 2025 compared to 2019 levels. The decrease in emissions in 2025 was primarily driven by outages at certain TEP fossil fuel generating units during the year.

In 2026, Fortis will be reviewing its decarbonization strategy, including potentially establishing new interim emission targets to replace its former targets. This work will be informed by resource planning across the Corporation's utilities, including the new IRPs to be filed in 2026 by TEP and UNS Electric, as discussed above. Fortis remains committed to having a coal-free generation mix in 2032 and advancing toward net-zero emissions by 2050.

BUSINESS RISKS

Fortis has an ERM program that identifies and evaluates the severity and probability of risks to its business. The Fortis Board, through its audit committee, oversees Fortis' ERM program ensuring that management has an effective risk management system to support strategic planning. The ERM program at the subsidiary level is overseen by each subsidiary's board of directors and any material risks identified form part of Fortis' ERM program. Materiality thresholds are reviewed annually. Systems of internal controls are used by management to monitor and manage identified risks. A summary of the Corporation's significant business risks follows.

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Management Discussion and Analysis
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Utility Regulation

Regulated utility assets represented virtually all of the Corporation's assets as at December 31, 2025. Regulatory jurisdictions include five Canadian provinces, ten U.S. states and the Cayman Islands, as well as FERC regulation for transmission assets in the U.S.

Regulators administer legislation covering material aspects of the utilities' business including: customer rates, allowed ROEs and deemed capital structures; capital expenditures; the terms and conditions for the provision of energy and capacity, ancillary services and affiliate services; securities issuances; and certain accounting matters. Regulatory or legislative changes and decisions, and delays in the recovery of costs in rates due to regulatory lag, could have a Material Adverse Effect. The risk of regulatory lag may be significant for UNS Energy given the past practice of its regulator to use historical test years in setting customer rates.

The ability to recover the actual cost of service and earn the approved ROE or ROA typically depends upon achieving the forecasts established in the rate-setting process. For those utilities subject to PBR mechanisms, rates reflect assumed inflation rates and productivity improvement factors, and variances therefrom could adversely affect rates of return. Failure to recover costs and/or earn a return could have a Material Adverse Effect.

For transmission operations, the underlying elements of FERC-established formula rates can be challenged by third parties which could result in rate reductions and customer refunds. These underlying elements include the ROE, ROE adders and deemed capital structure, as well as operating and capital expenditures.

In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to FERC, modify provisions of the U.S. Federal Power Act or the Natural Gas Act, or provide FERC or another entity with increased authority to regulate U.S. federal energy matters.

While Fortis is well-positioned to maintain constructive regulatory relationships through local management teams and subsidiary boards of directors comprised mostly of independent local members, it cannot predict future legislative or regulatory changes, or changes in the interpretation or application of laws and regulations, whether caused by economic, political (see "Political Environment" on page 24) or other factors. The Corporation and its utilities may experience challenges and compliance costs in responding to such regulatory changes in an effective and timely manner. Any such regulatory changes or operational impacts could have a Material Adverse Effect.

Physical Risks

The provision of electric and gas service is subject to physical risks, including impacts from severe weather and natural disasters, wars, terrorism, vandalism, critical equipment failure and other catastrophic events, including wildfires, within and outside the Corporation's service territories.

Electric utilities face risk of loss or damage from wildfires, floods, hurricanes, storm surges, washouts, landslides, earthquakes, avalanches, snow or ice storms, and other acts of nature. Further, certain utilities operate in remote or mountainous terrain that can be difficult to access for timely repairs and maintenance.

Gas utilities are exposed to operational risks associated with natural gas, including fires, explosions, pipeline corrosion and leaks, accidental damage to mains and service lines, equipment failure, damage and destruction from earthquakes, fires, floods and other natural disasters. Accidents or natural disasters affecting any of the Corporation's electricity or gas utilities can lead to service disruption, spills and commensurate environmental or other liability.

In addition, the operation of electric and gas systems has the potential to cause fires, including wildfires as a result of equipment failure, falling trees, lightning strikes to lines or equipment, or otherwise. The risks associated with fire damage vary depending on weather, forestation, the proximity of habitation and third-party facilities to utility facilities, and other factors. Failure to adequately address the risk of fire and wildfires could result in civil actions and government enforcement proceedings and utilities may become liable for fire-suppression costs, regeneration and timber value costs, and third-party losses if their facilities are determined to have been responsible for, or contributed to, a fire or wildfire.

Generating equipment and facilities are subject to physical risks, including equipment breakdown or damage from fire, floods or other natural disasters, that may result in the uncontrolled release of water, interruption of fuel supply, lower-than-expected operational efficiency or performance, and service disruption.

Electricity and gas systems require ongoing maintenance, improvement and replacement. The utilities are responsible for operating and maintaining their assets in a safe manner, including the development and application of appropriate standards, system processes and/or procedures to ensure the safety of employees, contractors and the general public.

If service disruption, or damage arising from, or caused by, the failure to properly implement or complete approved maintenance and capital expenditures, severe weather or other physical risks, is not mitigated through insurance policies or the recovery of such costs in customer rates, such service disruption or damage could result in loss.

Any of the foregoing potential impacts of physical risk could have a Material Adverse Effect.

The foregoing physical risks can be exacerbated by the "Climate Change" risks discussed below.

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Management Discussion and Analysis
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Growth

Fortis has a history of both growth through acquisitions and organic growth from capital investment in existing service territories. The Corporation's dividend growth guidance is significantly dependent upon achieving the Rate Base growth expected from the execution of the five-year Capital Plan as described under "Capital Plan" on page 18. Capital investments, including Major Capital Projects and opportunities to expand and extend the Capital Plan, are subject to risks of delay and cost overruns during construction caused by commodity price fluctuations, supply and labour costs, new or revised tariffs, supply chain constraints, supplier non-performance, weather, geologic conditions or other factors beyond the Corporation's control. There is no assurance that regulators will approve: (i) all of the planned projects or their amounts or timing; (ii) permits in a timely manner, or with reasonable terms and conditions; or (iii) the recovery of cost overruns in customer rates, which may have a Material Adverse Effect.

Cybersecurity and Information and Operations Technology

As operators of critical energy infrastructure, the Corporation's utilities are at risk of cybercrime, including cyberattacks, data breaches, cyber extortion, and similar compromises. As with other businesses, our information systems and the information systems of our third-party vendors are targeted by malware, phishing efforts, and other cyberattacks. Certain of the information systems of the Corporation's utilities have been subjected to direct and/or third-party cybersecurity breaches, including unauthorized access, none of which have been material. We expect to be targeted by similar attacks in the future. The ability of the Corporation's utilities to operate effectively is dependent upon using and maintaining complex information systems and infrastructure that: (i) support the operation of generation, transmission and distribution facilities, including electric and gas facilities; (ii) provide customers with billing, consumption and load settlement information, where applicable; and (iii) support financial and general operations.

Information and operations technology systems, including those of the Corporation's third-party service providers, may be vulnerable to unauthorized access or disruption due to cyber and other attacks, including hacking, malware, acts of war or terrorism, and acts of vandalism, among others. Further, geopolitical conflicts and the advancement of AI and generative AI may further increase the scale, sophistication or frequency of cyberattacks from malicious actors, some of which actions may even be initiated by or connected with nation-state actors.

Any cyberattack or breach event could result in the disruption of energy service and other business operations, including safety disruptions, disruption of internal control processes, property damage, reputational damage, corruption or unavailability of critical data, loss of assets, and the theft, loss, misappropriation and/or disclosure of sensitive, confidential and proprietary business information, intellectual property, or personal information of customers and/or employees. The Corporation's exposure to these risks increases as the Corporation continues to partner with third-party providers (see "Reliance on Supply Chain and Third Parties" on page 27).

A material cybersecurity breach of the Corporation's information security systems or those of a third-party service provider, or any delay or failure in assessing the materiality of such breach and related reporting/disclosure, could expose the Corporation to significant remediation costs and/or adversely affect the operations and financial performance of the Corporation, its reputation and standing with customers, regulators and financial markets, and expose it to claims for third-party damages or regulatory penalties. The resultant financial impacts may not be fully covered by insurance policies or, in the case of utilities, through regulatory cost recovery, and could have a Material Adverse Effect.

Climate Change

Climate-Related Physical Risk

Climate change may negatively impact the ability to provide reliable and safe electric and gas service. A changing climate that leads to more frequent and severe weather events may impact or disrupt the reliability of electric or gas systems. The physical risks associated with a changing climate requires the Corporation's utilities to adapt and respond to continue delivering reliable service to customers.

The Corporation has identified strong winds, extreme heat, wildfire risk and flooding as its most significant climate hazards. The Corporation's service territories may also experience other severe weather and events such as thunderstorms, drought, hurricanes, storm surges and snow or ice storms. Increased frequency of such events could increase the cost of providing service through increased repairs and use of contingency plans. Extreme weather conditions and changes in air temperature require system backup and can result in system stress, including service disruptions, and decreased efficiency of operating facilities over time.

Longer-term climate change impacts could result in service disruption, shortened asset life, increased repair and replacement costs, and costs associated with strengthened design standards and systems. The impacts of climate change can intensify the "Physical Risks" (see "Physical Risks" on page 22). Failure to appropriately respond to climate change may disrupt the ability of the utilities to provide safe and cost-effective service, which could cause reputational harm and other impacts.

The physical risks posed by the potential impacts of climate change and resultant damage to assets, service disruption repair and replacement costs, and liability for third party damages could have a Material Adverse Effect if not resolved in a timely and effective manner and/or mitigated through insurance policies or regulatory cost recovery. An increase in business risk associated with climate change can also impact credit ratings, which could affect credit risk spreads on new long-term debt and credit facilities, as well as their availability (see "Access to Capital" on page 27).

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Management Discussion and Analysis
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Climate-Related Transition Risk

A transition towards decarbonization will require the Corporation's utilities to effectively manage, among other things, evolving regulatory and legislative requirements, new resiliency standards, the integration of new technologies and impacts on customer demand and rates. Risks associated with policy, legal, technological and market changes may have capital and financial implications for the Corporation and its utilities.

Fortis expects changes to government policy and regulation to continue in the coming years (see "Environmental Regulation" below). Changes in policies and technologies, as well as the ability of the Corporation's utilities to pass related costs on to customers remain uncertain. Regulatory lag in relation to the adoption of climate change initiatives and/or the availability of regulatory recovery mechanisms in certain jurisdictions could contribute to financial harm to Fortis and its utilities (see "Utility Regulation" on page 22).

Technological advancements will be required in order for the Corporation to achieve net-zero emissions while preserving system reliability and customer affordability. In addition to the development and implementation of relevant energy technologies, the Corporation's ability to achieve net-zero emissions, and any GHG targets adopted by the Corporation, depends upon many factors including significant load growth, federal, state and provincial energy policies, the size of the Corporation's service territory, or the adoption of alternative energy products by the public, any of which could cause actual results and the ability to achieve such targets to materially differ from expectations. The ultimate impact of achieving or failing to achieve any such targets could cause reputational damage which could result in a Material Adverse Effect.

Health and Safety

The operations of the Corporation's utilities inherently involve risk to the health and safety of both employees and the public. Personal injury or loss of life could result from failure to implement or observe appropriate health and safety procedures and gives rise to operational, reputational or financial impacts, any of which could have a Material Adverse Effect. In addition, failure to comply with health and safety regulations could result in fines, penalties, reputational damage, litigation, increased capital and operating costs or adverse regulatory outcomes.

Political Environment

The political environment, at the local, national or global level, may impact energy laws, governmental energy policies, regulatory independence or regulatory decisions. For example, political pressure or intervention to address energy prices and customer affordability concerns may impact regulatory decisions, as well as the period over which the Corporation's utilities recover allowed costs. In addition, the Corporation could be adversely affected if certain of its utilities become subject to municipalization or other related government actions.

The business is further exposed to risks associated with geopolitical uncertainty. Global fragmentation, and political and economic uncertainty, including changing trade and energy policy, could lead to an increase in commodity prices, impact the availability and cost of energy, or generally affect global economic conditions, any of which could have a Material Adverse Effect (see "Environmental Regulation" below and "General Economic Conditions" on page 26).

Technology Developments and AI

New technology developments in distributed generation, particularly solar, and energy efficiency products and services, as well as the implementation of renewable energy and energy efficiency standards, will continue to impact retail sales. Heightened awareness of energy costs and environmental concerns have increased demand for products that reduce energy consumption. The Corporation's utilities are also promoting demand-side management programs. New technologies available to customers include energy derived from renewable sources, customer-owned generation, energy-efficient appliances, battery storage and control systems. Advances in these or other technologies could have a significant impact on retail sales with a potential Material Adverse Effect. Additionally, advances in AI or generative AI could cause disruption to our business and, if we are unable to acquire, develop, implement or adopt new technology, we may suffer a competitive disadvantage, which could also have an adverse effect on our results of operations, financial condition and/or liquidity.

Further, the implementation of new information technology systems and emerging technologies, such as cloud computing, AI and generative AI into the business, including those impacting utility operations, customer billing systems and cybersecurity threat monitoring, carries risk that any such technology or system will not operate as expected. Failure to maintain, upgrade, replace or properly implement such new technology or systems could result in increased risk of a cybersecurity incident and have an adverse effect on operational efficiency, revenue or reputation (see "Cybersecurity and Information and Operations Technology" on page 23).

Environmental Regulation

The Corporation's businesses are subject to environmental laws and regulations, including those which concern emissions into the air, discharges into water or soil, use of water, hazardous waste disposal and containment, and the investigation and remediation of contamination, among others.

The risk of contamination of air, soil and water associated with electricity operations primarily relates to: (i) the transportation, handling, storage and combustion of fuel; (ii) the use of petroleum-based products, mainly transformer and lubricating oil; (iii) the management and disposal of coal combustion residuals and other wastes; and (iv) accidents resulting in hazardous release at or from coal mines that supply generating facilities. Contamination risks at gas operations primarily relate to leaks and other accidents involving gas systems. The key environmental risks for hydroelectric generation operations include dam failures and the creation of artificial water flows that may disrupt natural habitats.

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Management Discussion and Analysis
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Failure to comply with environmental laws and regulations, or to obtain or comply with any necessary environmental permits pursuant to such laws and regulations, could result in injunctions, fines or other penalties. Further, liabilities relating to contamination investigation and remediation, and related claims for personal injury or property damage, may arise at many locations, including formerly and currently owned/operated properties and waste treatment or disposal sites, regardless of whether such contamination was caused by the business at the time it owned the property, whether it resulted from non-compliance with applicable environmental laws and regulations, or whether it resulted from any act or omission of the business. These liabilities could result in substantial monetary judgments for clean-up costs, damages, fines and/or penalties. To the extent not fully covered by insurance or through regulatory mechanisms, these foregoing costs could have a Material Adverse Effect.

Environmental laws and regulations continue to develop and may result in significant additional expense. In particular, the management of GHG emissions and related decarbonization requirements is a concern due to changing federal, state and provincial GHG laws, regulations and guidelines. Regulation and the pace of regulatory change to address reliability, resiliency, resource planning and safety is expected to increase. Future legislation could impact generation assets, operations, energy supply, operational costs, reporting obligations and other material aspects of the Corporation's business. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a Material Adverse Effect (see "Climate Change" at page 23).

Natural Gas Competitiveness

Approximately 20% of the Corporation's revenue is derived from the delivery of natural gas. In British Columbia, which accounts for approximately 80% of the Corporation's natural gas revenue, natural gas primarily competes with electricity for space and hot water heating load. Upfront capital costs for gas service continue to present competitive challenges for natural gas compared to electricity service. If gas becomes less competitive due to price or other factors, such as government policy or public perception of natural gas or its carbon intensity relative to other energy sources, the ability to add new customers could be impaired. Existing customers could also reduce their consumption or switch to electricity, placing further pressure on rates and, in the extreme, could ultimately lead to an inability to recover the utility's cost of service through customer rates.

Additionally, there are other competitive challenges that are impacting the penetration of natural gas into new housing stock such as the carbon intensity of the energy source and the type of housing stock being built. As part of their own climate change policy plans, local governments may use various tools at their disposal such as franchise agreements, permits, building codes and zoning bylaws to impose limitations on energy sources permitted in new and existing developments. Municipalities can also provide incentives, such as higher density allowance, to builders to adopt carbon free energy options for their developments. These actions and policies may hinder the Corporation's ability to attract new natural gas customers or retain existing customers.

A decrease in the competitiveness of natural gas due to pricing, government policy or other factors could have a Material Adverse Effect.

Weather Variability and Seasonality

Electricity consumption varies significantly in response to seasonal weather changes which have been and may continue to be impacted by climate change (see "Climate Change" on page 23). Cool summers may reduce the use of air conditioning and other cooling equipment, while warmer and less severe winters may reduce heating load. Alternatively, severe weather can increase heating and cooling loads, negatively impacting system reliability.

Weather and seasonality also have a significant impact on gas distribution volumes as a major portion of natural gas is used for space heating by residential customers. Regulatory deferral and revenue decoupling mechanisms are in place at certain of the Corporation's utilities to minimize the volatility in earnings that would otherwise be caused by variations in weather conditions. The absence or the discontinuance of key regulatory mechanisms could result in significant and prolonged weather variations from seasonal norms having a Material Adverse Effect.

Required Approvals

The acquisition, ownership and operation of electric and gas businesses require numerous licences, permits, agreements, orders, certificates, consultations, and other approvals from various levels of government, regulators, government agencies and/or other third parties. There is no assurance that: (i) such approvals will be obtained, continuously maintained or renewed without delay; and (ii) the terms and conditions thereof will be fully complied with at all times and will not change in a material adverse manner. Significant failures in these regards could prevent the operation of the businesses and have a Material Adverse Effect.

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Management Discussion and Analysis
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Reliability Standards

The Energy Policy Act of 2005 provides for a regulatory framework which requires owners, operators and users of the bulk electric system in the U.S. to meet mandatory reliability standards developed by the North American Electric Reliability Corporation and its regional entities, which are approved and enforced by FERC. Many of these, or similar, standards have been adopted in certain Canadian provinces including British Columbia and Alberta. The failure to develop, implement and maintain appropriate operating practices/systems and capital plans to address reliability obligations could lead to compliance violations and a Material Adverse Effect, including as a result of the exclusion of related costs from customer rates and other potentially significant penalties.

Indigenous Peoples' Land Claims

In British Columbia, the Corporation's utilities provide service to customers on Indigenous Peoples' lands and certain utility assets are located on Indigenous lands and other lands pursuant to rights of way or other land tenure agreements or rights. Various treaty negotiation processes and court proceedings involving Indigenous Peoples and related land tenure are underway, but the potential basis for settlement and final decisions are unclear and not all Indigenous Peoples are participating in such processes or proceedings. The inability to maintain land agreements or rights, to renew such land rights, or to obtain replacement land rights, could have a Material Adverse Effect.

Certain of FortisAlberta's distribution assets are located on Indigenous Peoples' lands. The locating of these assets on such land is subject to a permitting process and requires approvals from the applicable Indigenous Peoples' band council and Indigenous Service Canada. The inability to obtain such approvals or access permits could have a Material Adverse Effect.

Certain jointly owned facilities and portions of TEP's transmission lines are located on tribal lands pursuant to leases, land easements and other rights-of-way that are effective for specified time periods. The inability to receive future approvals for continued access to the facilities and land could have a Material Adverse Effect.

Joint-Ownership Interests and Third-Party Operators

Certain generating facilities from which TEP receives power are jointly owned with, or are operated by, third parties. TEP may not have sole discretion or any ability to affect the management or operations of such facilities, including how to best address changing economic conditions or environmental requirements. A divergence in the interests of TEP and those of the joint owners or operators could have a Material Adverse Effect.

General Economic Conditions

Fluctuations in general economic conditions, inflation, energy prices, employment levels, personal disposable incomes, housing starts, industrial activity and other factors, including new or revised tariffs, may lower energy demand and sales and reduce capital spending, particularly to the extent that related customer and Rate Base growth are impacted. A severe and prolonged economic downturn could also impair customers' ability to pay their bills in a timely manner. Each of these factors could lead to the impairment of goodwill or other long-term assets, and could have a Material Adverse Effect. Further, the impact of macroeconomic factors or social disruptions could restrict or disrupt business operations, cause weaker economic conditions or increase the volatility of the equity capital markets, which could impact the business and financial condition of the Corporation or adversely impact the Corporation's share price. Such factors may include, but are not limited to, international relations and geopolitical uncertainty and conflicts or the emergence of a pandemic or other health crisis.

Commodity Price Volatility

Purchased power and gas, and generation fuel costs are subject to commodity price volatility, which is managed through regulator-approved: (i) mechanisms that permit the flow through in customer rates of commodity price changes and/or that provide for rate-stabilization and other deferral accounts; and (ii) price-risk management strategies such as the use of derivative contracts that effectively fix costs (see "Financial Instruments - Derivatives" on page 32).

There is no assurance that current regulator-approved mechanisms or strategies will continue to exist in the future. Additionally, despite these mechanisms and strategies, severe and prolonged commodity price increases could result in rates that customers are unable to pay and/or could affect consumption and sales growth, which could have a Material Adverse Effect.

Purchased Power Supply

A significant portion of electricity and gas sold by the Corporation's utilities is purchased through the wholesale energy markets or pursuant to contracts with energy suppliers and is not being produced by the Corporation's utilities. A disruption in the wholesale energy markets, or a failure on the part of energy or fuel suppliers or operators of energy delivery systems that connect to the Corporation's utilities, could result in a loss and/or increase in the cost of purchased power and gas, which could have a Material Adverse Effect. The cost and availability of purchased power and gas may be adversely impacted by factors discussed under "Climate Change" on page 23, "Environmental Regulation" on page 24 and "Commodity Price Volatility" above.

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Management Discussion and Analysis
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Counterparty Credit Risk

ITC has a concentration of credit risk as approximately 70% of its revenue is derived from three customers. These 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.

There is no assurance that credit risk management strategies will continue to be effective. Significant counterparty defaults could have a Material Adverse Effect.

Reliance on Supply Chain and Third Parties

Domestic and global supply chain disruptions, as a result of either physical or cyberattacks or geopolitical issues, may delay the delivery or result in shortages of certain materials, equipment and other resources that are critical to the operation of the Corporation's utilities, or impact the services and performance of the operation of the Corporation's utilities. Failure to eliminate or manage constraints in, or performance of, the supply chain may impact the availability of items or service that are necessary to support operations as well as materials that are required for continued infrastructure growth and could have a Material Adverse Effect. Further, cybersecurity incidents in the Corporation's supply chain or cyberattacks originating from the Corporation's supply chain may further result in disruption of energy service and other business operations which could have a Material Adverse Effect.

Interest Rates

Generally, the market price of the Corporation's common shares is inversely correlated to interest rate changes. Additionally, allowed ROEs are exposed to changes in long-term interest rates, such that a decreasing interest rate environment can result in lower allowed ROEs over time. While a rising interest rate environment could result in higher allowed ROEs, such ROE changes tend to lag as a result of regulatory timelines. Borrowings under variable-rate credit facilities and long-term debt, as well as new debt issuances, are also exposed to interest rate changes. Although interest costs at the regulated utilities are generally recovered through customer rates, the discontinuance of regulatory mechanisms that permit the flow-through of actual interest costs, the impact of regulatory lag at UNS Energy, and higher finance costs on holding company debt could have a Material Adverse Effect.

Foreign Exchange Exposure

As at December 31, 2025, 67% of the Corporation's assets were located outside Canada and 62% of 2025 revenue was derived from foreign operations. The reporting currency of ITC, UNS Energy, Central Hudson, and Caribbean Utilities is 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's $28.8 billion five-year Capital Plan for 2026 through 2030 also includes exposure to foreign exchange.

Fortis has reduced its U.S. dollar currency exposure through hedging. The Corporation has issued and designated U.S. dollar-denominated long-term debt as an effective hedge of foreign net investments. Fortis has also entered into foreign exchange contracts and cross-currency swaps to manage a portion of its exposure to foreign currency risk.

Given only partial hedging, earnings and cash flow continue to be impacted by exchange rate fluctuations. In addition, there is no assurance that existing hedging strategies will continue to be effective, and therefore a significant, prolonged decrease in the U.S dollar-to-Canadian dollar exchange rate could have a Material Adverse Effect.

Access to Capital

The Corporation and certain of its subsidiaries have incurred material amounts of indebtedness. Ongoing access to cost-effective capital is required to fund, among other things, Capital Expenditures and the repayment of maturing debt.

Operating Cash Flow may not be sufficient to fund the repayment of all outstanding liabilities when due or fund anticipated Capital Expenditures.

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Management Discussion and Analysis
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The ability to meet long-term debt repayments is dependent upon obtaining sufficient and cost-effective financing to replace maturing indebtedness. The ability to arrange financing is subject to numerous factors, including the results of operations, financial condition and credit ratings of Fortis and its subsidiaries, the regulatory environments including decisions regarding capital structure and allowed ROEs, capital market conditions and general economic conditions. Changes in credit ratings could affect credit risk spreads on new long-term debt and credit facilities, as well as their availability.

Fortis is a holding company and, as such, has no revenue-generating operations of its own. The Corporation's subsidiaries are separate legal entities and have no independent obligation to pay dividends to Fortis. Prior to paying dividends to the Corporation, the subsidiaries have financial obligations that must be satisfied, including, among others, their operating expenses and obligations to creditors. Furthermore, the Corporation's utilities are required by regulation to maintain a minimum equity-to-total capital ratio that may restrict their ability to pay dividends to the Corporation or may require the Corporation to contribute capital to such subsidiaries. The future enactment of laws or regulations may prohibit or further restrict the ability of the Corporation's subsidiaries to pay dividends or to repay intercorporate indebtedness. In addition, in the event of a subsidiary's liquidation or reorganization, the Corporation's right to participate in a distribution of assets is subject to the prior claims of the subsidiary's creditors. As a result, the Corporation's ability to generate cash flow to service its debt obligations and pay dividends is reliant on the ability of its subsidiaries to generate sustained earnings and cash flows and to pay dividends and repay loans.

There is no assurance that sufficient capital will continue to be available on acceptable terms, and the inability to access cost-effective capital could have a Material Adverse Effect. For further information see "Liquidity and Capital Resources" on page 13.

Taxation

Earnings at Fortis and its subsidiaries could be impacted by changes in income tax rates and other tax legislation in Canada, the U.S. and other international jurisdictions. The nature, timing or impact of changes in tax laws cannot be predicted and could have a Material Adverse Effect. At the holding company level, changes in income tax rates and other tax legislation could materially affect the after-tax cost of existing and future debt. Although income taxes at the regulated utilities are generally recovered in customer rates, tax-related regulatory lag can result in recovery delays or non-recovery for certain periods.

Insurance

Insurance is maintained with reputable industry insurers for property damage, potential liabilities and business interruption for coverage considered appropriate and in accordance with industry practice.

A significant portion of transmission and distribution assets is uninsured, as is customary in North America, as the cost to insure such assets is prohibitive. Insurance is subject to coverage limits and deductibles, as well as time-sensitive claims discovery and reporting provisions. There is no assurance that: (i) the amounts and types of losses from actual damage, liabilities or business interruption will be fully covered by insurance; (ii) regulatory relief would be obtained for coverage shortfalls; (iii) adequate insurance at reasonable rates will continue to be available; or (iv) insurers will fulfill their obligations. Significant actual shortfalls in insurance coverage or claims payment could have a Material Adverse Effect. The availability and cost of certain types of insurance may be adversely impacted by the risks described under "Climate Change" on page 23.

Talent Management

The delivery of safe, reliable and cost-effective service depends on the attraction, development and retention of a skilled workforce as well as filling strategic positions. Like its peers, Fortis faces demographic challenges and competitive markets relating to trades, technical and professional staff, particularly considering its significant capital plan. ITC relies heavily on agreements with third parties to provide services for the construction, maintenance and operation of certain aspects of its business. Significant failures in attracting or retaining a skilled workforce or filling strategic positions within the Corporation or its utilities could have a Material Adverse Effect.

Labour Relations

Most of the Corporation's utilities employ members of labour unions or associations under collective bargaining agreements. Fortis considers its labour relationships to be satisfactory, but there is no assurance that this will continue or that existing collective bargaining agreements will be renewed on reasonable terms without work disruption or other job action. Significant failures in these regards could cause service interruptions and/or labour cost increases for which regulators may not allow full recovery in customer rates, and could have a Material Adverse Effect.

Post-Retirement Obligations

Fortis and most of its subsidiaries maintain a combination of DBP and/or OPEB plans for certain employees and retirees. The most significant cost drivers for these plans are investment performance and interest rates, which are affected by global financial markets. Regulatory deferral mechanisms are in place at many of the Corporation’s utilities that permit the flow through in customer rates of certain impacts associated with market fluctuations. Severe and prolonged market disruptions, significant declines in the market values of investments held to meet plan obligations, discount rate changes, participant demographics, changes in laws and regulations, as well as changes in existing regulatory treatment of post-retirement benefit costs, may increase plan expenses or require additional plan funding and could have a Material Adverse Effect.

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Management Discussion and Analysis
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Reputation, Relationships and Stakeholder Activism

There can be no assurance that internal processes, controls or audits, including those related to the preparation and presentation of financial statements, will ensure compliance with the Corporation's internal policies, including its Code of Conduct, or anti-bribery and anti-corruption laws. Employees, affiliates, independent contractors or agents may violate such policies and laws, which may potentially lead to reputational damage, in addition to potential fines, penalties or litigation, any of which could have a Material Adverse Effect.

The Corporation's operations and growth prospects require strong relationships with key stakeholders, including regulators, governments and agencies, Indigenous communities, landowners, and environmental organizations. Inadequately managing expectations and issues important to stakeholders, including those arising during construction of Major Capital Projects, could affect the Corporation's reputation as well as have a significant impact on its operations and infrastructure development. See "Required Approvals" on page 25 and "Indigenous Peoples' Land Claims" on page 26.

External stakeholders have been challenging companies regarding strategy, governance, climate change, sustainability, diversity, returns (including ROEs and ROAs), executive compensation, and other matters. Public opposition to larger infrastructure projects is becoming increasingly common, which can challenge capital plans and resultant organic growth. While the Corporation actively monitors such activism and is committed to developing stronger relationships with its external stakeholders, failure to effectively manage or respond to stakeholder activism could have a Material Adverse Effect.

Legal, Administrative and Other Proceedings

Legal, administrative and other proceedings arise in the ordinary course of business and may include environmental claims, employment-related claims, securities-based litigation, contractual disputes, personal injury or property damage claims, actions by regulatory or tax authorities, and other matters. Unfavourable outcomes such as judgments or settlements for monetary or other damages, injunctions, denial or revocation of permits, reputational harm, and other results could have a Material Adverse Effect.

ACCOUNTING MATTERS

New Accounting Policies

Income Taxes: The Corporation adopted ASU No. 2023-09, Improvements to Income Tax Disclosures, effective January 1, 2025. This update 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 ASU has been applied retrospectively and the updated disclosure is included in the 2025 Annual Financial Statements.

Future Accounting Pronouncements

Critical Accounting Estimates

General

The preparation of the 2025 Annual Financial Statements required management to make estimates and judgments that affect the reported amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. Management evaluates these estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable at the time they are made, with any adjustments recognized in the period they become known. Actual results may differ significantly from these estimates.

Regulatory Assets and Liabilities

As at December 31, 2025, Fortis recognized regulatory assets of $5.0 billion (2024 - $4.6 billion) and regulatory liabilities of $4.3 billion (2024 - $4.3 billion).

FORTIS INC.	DECEMBER 31, 2025	29
Management Discussion and Analysis
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Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent: (i) future reductions or limitations of increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process; or (ii) obligations to provide future service that customers have paid for in advance.

The recognition of regulatory assets and liabilities and the period(s) of settlement are often estimates based on past, existing or expected regulatory orders in relation to the nature of the underlying amounts, and are subject to regulatory approval. There is no assurance that actual settlement amounts and the related settlement periods will not be materially different from those estimated. Differences arising from the regulator's orders would be recognized in accordance with those orders, whereby any amounts disallowed would be immediately recognized in earnings with the remainder recognized in earnings in accordance with their inclusion in customer rates.

Employee Future Benefits
Key Estimates and Assumptions	DBP Plans		OPEB Plans
Years ended December 31
($ millions, except as indicated)	2025	2024	2025	2024
Funded status: (1)
Benefit obligation (2)	(3,495)	(3,440)	(589)	(603)
Plan assets	3,744	3,613	531	506
	249	173	(58)	(97)
Net benefit cost (2)	11	11	(1)	12
Key assumptions: (weighted average %)
Discount rate as at December 31 (3)	5.24	5.25	5.36	5.43
Expected long-term rate of return on plan assets (4)	6.29	6.51	5.80	6.05
Rate of compensation increase	3.39	3.52	—	—
Health care cost trend increase rate (5)	—	—	4.40	4.53

(1)Periodic actuarial valuations determine funding contributions for the DBP plans and U.S. OPEB plans, while Canadian OPEB plans are unfunded

(2)Actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, average remaining service life of employees, mortality rates and, for OPEB plans, expected health care costs

(3)Reflects market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension payments. The discount rate used during the year for DBP plans is 5.25% (2024 - 4.84%) and 5.43% (2024 - 4.96%) for OPEB plans

(4)Developed using best estimates of expected returns, volatilities and correlations for each class of asset. Estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes

(5)Actuarially determined, the projected 2026 rate is 6.60% and is assumed to decrease over the next 10 years to the ultimate rate of 4.40% in 2035 and thereafter

Sensitivity Analysis	Rate of Return		Discount Rate		Health Care Costs<br>Trend Rate
Year ended December 31, 2025	1% change		1% change		1% change
($ millions)	Increase	Decrease	Increase	Decrease	Increase	Decrease
DBP plans:
Net benefit cost	(35)	29	(26)	45	n/a	n/a
Projected benefit obligation	4	(77)	(378)	468	n/a	n/a
OPEB plans:
Net benefit cost	(5)	5	(7)	9	13	(11)
Accumulated benefit obligation	—	—	(67)	83	62	(51)

At the regulated utilities, changes in net benefit cost are generally expected to be reflected in customer rates, subject to regulatory lag and forecast risk at certain utilities.

ITC, Central Hudson, FortisBC Energy, FortisBC Electric and Newfoundland Power have regulator‑approved mechanisms to defer variations between actual net pension cost and that forecast and reflected in customer rates. There is no assurance that these deferral mechanisms will continue in the future.

Depreciation and Amortization

As at December 31, 2025, Fortis recognized property, plant and equipment and intangible assets of $52.6 billion (2024 - $51.1 billion) representing 70% of total assets (2024 - 70%). Depreciation and amortization of these assets totalled $2.0 billion for 2025 (2024 - $1.8 billion).

Depreciation and amortization reflect the estimated useful lives of the underlying assets, which considers historical experience, manufacturers' ratings and specifications, the past and expected future pattern and nature of usage, and other factors.

FORTIS INC.	DECEMBER 31, 2025	30
Management Discussion and Analysis
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At the regulated utilities, depreciation rates require regulatory approval and include a provision for estimated future removal costs, not identified as a legal obligation. Estimates primarily reflect historical experience and expected cost trends. The provision is recognized as a long-term regulatory liability against which actual removal costs are netted when incurred. As at December 31, 2025, this regulatory liability was $1.9 billion (2024 - $1.7 billion).

Depreciation rates at the regulated utilities are typically determined through periodic depreciation studies performed by external experts. Where actual experience differs from previous estimates, resultant differences are generally reflected in future depreciation rates and thereby recovered or refunded through customer rates in the manner prescribed by the regulator.

Goodwill Impairment

As at December 31, 2025, Fortis recognized goodwill of $12.5 billion (2024 - $13.1 billion), representing 17% of total assets (2024 - 18%). The decrease in goodwill was due to a lower U.S. dollar-to-Canadian dollar exchange rate at December 31, 2025 in comparison to December 31, 2024, and the associated impact on the translation of U.S. dollar-denominated goodwill. Goodwill was also reduced by $50 million in 2025 due to the disposition of FortisTCI.

The recognition of impairment losses could have a Material Adverse Effect. Such losses are not recoverable in regulated utility rates. To the extent impairment losses trigger non-compliance with debt covenants, or lower expected future cash flows to support interest payments on unregulated holding company debt and dividends on common shares, they could adversely affect the future cost of such capital.

Income Taxes

As at December 31, 2025, deferred income tax liabilities, deferred income taxes included in regulatory assets, income tax payable, and deferred income taxes included in regulatory liabilities totalled $5.3 billion, $2.4 billion, $24 million and $1.3 billion, respectively (2024 - $5.0 billion, $2.2 billion, $33 million, and $1.3 billion, respectively). Income tax expense was $393 million in 2025 (2024 - $346 million).

Current income taxes reflect the estimated taxes payable/receivable in the current year based on enacted tax rates and laws, and the estimated proportion of taxable earnings/loss attributable to various jurisdictions.

Deferred income tax assets and liabilities are recognized for temporary differences between the tax and accounting basis of assets and liabilities. A deferred income tax asset or liability is determined for each temporary difference based on enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. A valuation allowance is recognized in earnings to the extent that future tax recovery is not assessed as "more likely than not".

At the regulated utilities, differences between the income tax expense or recovery recognized under U.S. GAAP and that reflected in current customer rates, which is expected to be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities. These are subsequently amortized to earnings in accordance with their inclusion in customer rates pursuant to the regulator's orders. Otherwise, changes in expectations and resultant estimates arising from changes in tax rates, tax laws, jurisdictional earnings allocations and other factors are recognized in earnings upon occurrence.

Derivatives

The fair values of derivatives are based on estimates that cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be reliable in predicting future earnings or cash flows.

Contingencies

The Corporation and its subsidiaries are subject to various legal proceedings and claims that arise in the normal course of business, including those generally described under "Business Risks - Legal, Administrative and Other Proceedings" on page 29, for which no amounts have been accrued because the outcomes currently cannot be reasonably determined.

FORTIS INC.	DECEMBER 31, 2025	31
Management Discussion and Analysis
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FINANCIAL INSTRUMENTS

Long-Term Debt and Other

The consolidated carrying value of the remaining financial instruments approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature.

Derivatives

The Corporation generally limits 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.

Energy contracts subject to regulatory deferral

Energy contracts not subject to regulatory deferral

Total return swaps

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$448 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. In 2025, unrealized gains of $17 million (2024 - unrealized losses of $17 million) were recognized in other income, net.

Interest rate contracts

ITC has entered into five-year interest rate swap contracts with a combined notional value of US$755 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 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. In 2025, unrealized losses of US$5 million (2024 - unrealized gains of US$4 million) were recorded in other comprehensive income.

FORTIS INC.	DECEMBER 31, 2025	32
Management Discussion and Analysis
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Cross-Currency interest rate swaps

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 December 31, 2025
Assets (2)
Energy contracts subject to regulatory deferral	—	51	—	51
Energy contracts not subject to regulatory deferral	—	4	—	4
Total return swaps and foreign exchange contracts	—	37	—	37
Other investments	190	—	—	190
	190	92	—	282
Liabilities (3)
Energy contracts subject to regulatory deferral	—	(149)	—	(149)
Energy contracts not subject to regulatory deferral	—	(2)	—	(2)
Interest rate contracts and cross-currency interest rate swaps	—	(23)	—	(23)
	—	(174)	—	(174)
As at December 31, 2024
Assets (2)
Energy contracts subject to regulatory deferral	—	63	—	63
Energy contracts not subject to regulatory deferral	—	7	—	7
Total return swaps and interest rate contracts	—	16	—	16
Other investments	150	—	—	150
	150	86	—	236
Liabilities (3)
Energy contracts subject to regulatory deferral	—	(197)	—	(197)
Energy contracts not subject to regulatory deferral	—	(2)	—	(2)
Foreign exchange contracts and cross-currency interest rate swaps	—	(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 cash and cash equivalents, accounts receivable and other current assets, or other assets

(3)Included in accounts payable and other current liabilities or other liabilities

Derivative Volumes
As at December 31	2025	2024
Energy contracts subject to regulatory deferral (1)
Electricity swap contracts (GWh)	890	774
Electricity power purchase contracts (GWh)	395	430
Gas swap contracts (PJ)	183	236
Gas supply contracts (PJ)	147	105
Energy contracts not subject to regulatory deferral (1)
Wholesale trading contracts (GWh)	1,430	1,499
Gas swap contracts (PJ)	2	3

(1)Energy contracts settle on various dates through 2030

FORTIS INC.	DECEMBER 31, 2025	33
Management Discussion and Analysis
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SELECTED ANNUAL FINANCIAL INFORMATION

Years ended December 31
( millions, except as indicated)	2024	2023
Revenue	11,508	11,517
Net earnings	1,828	1,710
Common Equity Earnings	1,606	1,506
EPS: ()
Basic	3.24	3.10
Diluted	3.24	3.10
Total assets	73,486	65,920
Long-term debt (excluding current portion)	31,224	27,235
Dividends declared: ()
Per common share	2.41	2.31
Per first preference share:
Series F	1.2250	1.2250
Series G (1)	1.5308	1.3145
Series H (2)	0.4588	0.4588
Series I (3)	1.4902	1.5619
Series J	1.1875	1.1875
Series K (4)	1.3673	0.9823
Series M (5)	1.0770	0.9783

All values are in US Dollars.

(1)The annual dividend per share was reset to $1.5308 for the five-year period from September 1, 2023 up to but excluding September 1, 2028

(2)The annual dividend per share was reset to $1.0458 for the five-year period from June 1, 2025 up to but excluding June 1, 2030

(3)Floating quarterly dividend rate is reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus the applicable reset dividend yield

(4)The annual dividend per share was reset from $0.9823 to $1.3673 for the five-year period from March 1, 2024 up to but excluding March 1, 2029

(5)The annual dividend per share was reset from $0.9783 to $1.3733 for the five-year period from December 1, 2024 up to but excluding December 1, 2029

2025/2024

For a discussion of the changes in revenue, Common Equity Earnings, EPS, total assets and long-term debt see "Performance at a Glance" on page 2, "Operating Results" on page 5, and "Financial Position" on page 13.

2024/2023

The decrease in revenue was due to lower flow-through commodity costs in customer rates at FortisBC Energy and Central Hudson. The decrease was also due to a reduction in the MISO base ROE at ITC, approved by FERC in October 2024, including retroactive application to prior periods, and lower short-term wholesale sales revenue at UNS Energy. The decrease was partially offset by Rate Base growth and new customer rates at TEP and Central Hudson, effective September 1, 2023 and July 1, 2024, respectively, as well as a higher U.S. dollar-to-Canadian dollar exchange rate.

Common Equity Earnings increased by $100 million in comparison to 2023. The increase was due to: (i) Rate Base growth; (ii) higher earnings in Arizona, largely reflecting new customer rates at TEP effective September 1, 2023 and higher production tax credits; (iii) new customer rates including a higher allowed ROE at Central Hudson effective July 1, 2024; and (iv) an unfavourable deferred income tax adjustment recognized by ITC in 2023. The increase was partially offset by higher holding company finance costs, unrealized losses on derivative contracts, and a $10 million gain realized upon the disposition of Aitken Creek in 2023. The recognition of a refund liability at ITC in 2024, due to the reduction in the MISO base ROE as approved by FERC and largely reflecting the retroactive impact to prior periods, also unfavourably impacted earnings.

In addition to the above-noted items impacting earnings, the change in EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

The increase in total assets was primarily due to: (i) Capital Expenditures in 2024; (ii) the translation of U.S. dollar-denominated assets at a higher U.S. dollar-to-Canadian dollar exchange rate; and (iii) an increase in other assets, largely due to increase in employee future benefit assets, driven by higher discount rates on plan liabilities as well as investment returns on DBP and OPEB plans. The increase was partially offset by a reduction in cash and cash equivalents associated with the timing of a debt issuance at ITC in 2023.

FORTIS INC.	DECEMBER 31, 2025	34
Management Discussion and Analysis
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FOURTH QUARTER RESULTS

Sales
(GWh, except as indicated)	2025	2024	Variance
Regulated Utilities
UNS Energy
Retail Electricity	2,278	2,348	(70)
Wholesale Electricity	1,521	1,295	226
Gas (PJ)	4	5	(1)
Central Hudson
Electricity	1,218	1,187	31
Gas (PJ)	9	6	3
FortisBC Energy (PJ)	65	67	(2)
FortisAlberta	4,507	4,428	79
FortisBC Electric	914	916	(2)
Other Electric	2,515	2,533	(18)
Non-Regulated
Corporate and Other	13	80	(67)

Utilities with notable increases in fourth quarter electricity sales include: (i) UNS Energy, due to higher short-term wholesale sales reflecting favourable market conditions, partially offset by lower retail electricity sales due to milder weather; (ii) FortisAlberta, reflecting higher average consumption by industrial customers due to increased activity in the energy sector; and (iii) Central Hudson, due to higher average consumption by residential customers due to colder weather. Lower sales in the Other Electric and Corporate and Other segments reflect the impacts of the dispositions of FortisTCI and Fortis Belize.

Gas sales by utility for the fourth quarter were largely consistent with the fourth quarter of 2024.

Revenue and Common Equity Earnings			Earnings
( millions, except as indicated)	2024	Variance	2025	2024	Variance
Regulated Utilities
ITC	567	58	150	127	23
UNS Energy	659	(13)	43	52	(9)
Central Hudson	356	56	70	66	4
FortisBC Energy	522	54	134	120	14
FortisAlberta	207	1	50	42	8
FortisBC Electric	149	(4)	18	18	—
Other Electric	479	(14)	38	52	(14)
Non-regulated
Corporate and Other	10	(8)	(81)	(81)	—
Total	2,949	130	422	396	26
Weighted average number of common shares outstanding (# millions)			506.4	498.2	8.2
Basic EPS ()			0.83	0.79	0.04

All values are in US Dollars.

The increase in revenue was primarily due to: (i) Rate Base growth, (ii) higher flow-through costs in customer rates; and (iii) the retroactive impact of a reduction in the MISO base ROE at ITC as approved by FERC in 2024, as discussed below. The increase was partially offset by the dispositions of FortisTCI and Fortis Belize.

Common Equity Earnings increased by $26 million compared to the fourth quarter of 2024. Common Equity Earnings in the fourth quarter of 2025 were unfavourably impacted by a $31 million loss on the disposition of Fortis Belize and Belize Electricity in October 2025. In addition, Common Equity Earnings in the fourth quarter of 2024 were unfavourably impacted by $20 million at ITC associated with the retroactive impact of a reduction in the MISO base ROE as approved by FERC.

FORTIS INC.	DECEMBER 31, 2025	35
Management Discussion and Analysis
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Excluding the above-noted items, Common Equity Earnings increased by $37 million compared to the fourth quarter of 2024. The increase in Common Equity Earnings was primarily due to Rate Base growth across the utilities, including AFUDC associated with Major Capital Projects. Growth in earnings was also due to: (i) unrealized gains on derivative contracts; (ii) the timing of operating costs at FortisAlberta; and (iii) the favourable impact of foreign exchange, as discussed below. The increase was partially offset by higher costs associated with Rate Base growth not yet reflected in customer rates and lower retail electricity sales due to milder weather at UNS Energy, as well as higher stock-based compensation and holding company finance costs. Lower earnings contribution from FortisTCI and Belize due to the dispositions, net of finance cost savings associated with proceeds, also unfavourably impacted fourth quarter results.

The favourable change in earnings associated with foreign exchange largely reflected foreign exchange losses recorded in the fourth quarter of 2024 due to the significant appreciation of the U.S. dollar relative to the Canadian dollar during that quarter and the associated revaluation of U.S. dollar denominated short-term liabilities.

The increase in basic EPS reflects higher Common Equity Earnings, as discussed above, partially offset by an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

Cash Flows
($ millions)	2025	2024	Variance
Cash and cash equivalents, beginning of period	389	896	(507)
Cash from (used in):
Operating activities	1,018	962	56
Investing activities	(1,341)	(1,796)	455
Financing activities	305	125	180
Effect of exchange rate changes on cash and cash equivalents	(4)	33	(37)
Cash and cash equivalents, end of period	367	220	147

Operating Activities

The increase in Operating Cash Flow was due to higher cash earnings, reflecting Rate Base growth as well as the sale of investment tax credits at UNS Energy. The timing of transmission charges at FortisAlberta also contributed to growth in Operating Cash Flow. The increase was partially offset by: (i) the timing of flow-through costs at UNS Energy associated with higher PPFAC collections in 2024, and at FortisBC Energy related to the collection of consumer carbon tax in 2024; and (ii) lower deposits received, net of expenditures incurred, associated with the Eagle Mountain Pipeline project at FortisBC Energy.

Investing Activities

Cash used in investing activities for the fourth quarter of 2025 was $455 million lower than the same period in 2024 due to proceeds received on the disposition of Fortis Belize and Belize Electricity in October 2025 and higher CIACs largely associated with the Eagle Mountain Pipeline project.

Financing Activities

Cash provided by financing activities for the fourth quarter of 2025 increased by $180 million as compared to the fourth quarter of 2024. The increase primarily reflected an increase in borrowings to support capital investments.

FORTIS INC.	DECEMBER 31, 2025	36
Management Discussion and Analysis
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SUMMARY OF QUARTERLY RESULTS

		Common Equity
	Revenue	Earnings	Basic EPS	Diluted EPS
Quarter ended	($ millions)	($ millions)	($)	($)
December 31, 2025	3,079	422	0.83	0.83
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

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 the 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 long-term 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.

December 2025/December 2024

See "Fourth Quarter Results" on page 35.

September 2025/September 2024

Common Equity Earnings decreased by $11 million and basic EPS decreased by $0.04 in comparison 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 impact of the disposition, 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. 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.

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 AFUDC 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.

FORTIS INC.	DECEMBER 31, 2025	37
Management Discussion and Analysis
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RELATED-PARTY AND INTER-COMPANY TRANSACTIONS

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 December 31, 2025 and 2024, there were no inter-segment loans outstanding. Interest charged on inter-segment loans was not material in 2025 and 2024.

MANAGEMENT'S EVALUATION OF CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

DCP are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws. As of December 31, 2025, an evaluation was carried out under the supervision of, and with the participation of, the Corporation's management, including the CEO and CFO, of the effectiveness of the Corporation's DCP, as defined in the applicable Canadian and U.S. securities laws. Based on that evaluation, the CEO and CFO concluded that such DCP are effective as of December 31, 2025.

Internal Control over Financial Reporting

ICFR is designed by, or under the supervision of, the Corporation's CEO and CFO and effected by the Corporation's Board, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Corporation's management, including the Corporation's CEO and CFO, assessed the effectiveness of the Corporation's ICFR as of December 31, 2025, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that, as of December 31, 2025, the Corporation's ICFR was effective.

During the year ended December 31, 2025, there have been no changes in the Corporation's ICFR that have materially affected, or are reasonably likely to materially affect, the Corporation's ICFR.

OUTLOOK

FORTIS INC.	DECEMBER 31, 2025	38
Management Discussion and Analysis
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FORWARD-LOOKING INFORMATION

Fortis includes forward-looking information in the 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: the expectation that Fortis is well-positioned for future investment opportunities; annual dividend growth guidance through 2030; forecast Capital Expenditures for 2026 through 2030; expected sources of funding for the Capital Plan, including sources of common equity; forecast midyear Rate Base for 2030 and forecast five-year Rate Base CAGR through 2030; expected implications of industry trends on the utility sector and on the Corporation's capital investments; the expectation that Fortis is well-positioned to support energy security, climate adaptation, and load growth across the Corporation's footprint; expected timing, outcome and impact of legal and regulatory proceedings and decisions; expected or potential funding sources for operating expenses, interest costs and capital expenditures; the expectation that maintaining the targeted capital structure of the regulated operating subsidiaries will not have an impact on the Corporation's ability to pay dividends in the foreseeable future; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will continue to have reasonable access to long-term capital and will remain compliant with debt covenants; expected use of proceeds from debt financings; the potential requirement to accelerate equity capital contributions to Wataynikaneyap Power; expectations related to UNS Energy's joint generation performance guarantees, potential obligations arising from participant defaults, and associated recovery mechanisms; expected nature, timing, benefits and costs associated with TEP's energy supply agreement with a customer to support a planned data center in TEP's service territory; expected in-service date for a new pipeline in UNS Energy's service territory and the expectation that TEP and UNS Electric will enter into gas transportation service agreements and estimated purchase commitments associated therewith; the potential impact of new or revised tariffs on forecasted capital expenditures; forecast midyear Rate Base for 2026 and 2030 by business segment; the nature, timing, benefits and costs of certain Major Capital Projects, including the MISO LRTP, Big Cedar Load Expansion, TEP Transmission Project, Springerville Natural Gas Conversion, Black Mountain Gas Generation, Vail-to-Tortolita Transmission Project, Roadrunner Reserve Battery Storage Project, 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 ITC's investments associated with MISO LRTP tranche 2.1, TEP's investments associated with additional energy demands from new large retail customers, and FortisBC Energy's investments associated with the Tilbury LNG Storage Expansion project and Tilbury Marine Jetty project; expected nature, timing and benefits of additional opportunities to expand and extend growth beyond the Capital Plan, including 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 energy infrastructure investments to support the acceleration of load growth; the expectation that the Corporation will be reviewing its decarbonization strategy in 2026; the potential establishment of new interim emissions targets; expected timing and contents of TEP's and UNS Electric's new IRPs; the expectation that the Corporation will have a coal-free generation mix in 2032; the Corporation's 2050 net-zero GHG emissions target; the potential and expected impacts of new accounting policies and future accounting pronouncements on the Corporation's disclosures; the potential impact of the recognition of goodwill impairment losses; the potential and expected impacts of income tax compliance examinations and legislation with respect to interest deductibility limitations and global minimum tax; and the expectation that long-term growth in Rate Base will drive earnings that support dividend growth guidance.

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 2026 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 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 related to environmental laws and regulation; 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 February 11, 2026. 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.

FORTIS INC.	DECEMBER 31, 2025	39
Management Discussion and Analysis
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GLOSSARY

2025 Annual Financial Statements: the Corporation's audited consolidated financial statements and notes thereto for the year ended December 31, 2025

Actual Payout Ratio: dividends paid per common share divided by basic EPS

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 10

Adjusted Payout Ratio: dividends paid per common share divided by Adjusted Basic EPS as shown under "Non-U.S. GAAP Financial Measures" on page 10

AFUDC: allowance for funds used during construction

AI: artificial intelligence

Aitken Creek: Aitken Creek Gas Storage ULC, a 93.8%-owned subsidiary of FortisBC Holdings Inc., sold on November 1, 2023

AMI: advanced metering infrastructure

ATM Program: at-the-market equity program

ACC: Arizona Corporation Commission

ASU: accounting standards update

AUC: Alberta Utilities Commission

BCUC: British Columbia Utilities Commission

Belize Electricity: Belize Electricity Limited, in which Fortis indirectly held a 33% equity interest which was sold on October 31, 2025

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 Annual 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 10

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, 2025) 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

CEO: Chief Executive Officer of Fortis

CFO: Chief Financial Officer of Fortis

CIACs: contributions in aid of construction

Common Equity Earnings: net earnings attributable to common equity shareholders

Corporation: Fortis Inc.

COS: cost of service

Court of Appeal: Court of Appeal of Alberta

CPCN: Certificate of Public Convenience and Necessity

DBP: defined benefit pension

DCP: disclosure controls and procedures

DRIP: dividend reinvestment plan

EPC: engineering, procurement and construction

EPS: earnings per common share

ERM: enterprise risk management

FERC: Federal Energy Regulatory Commission

FFO: funds from operations

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, sold on October 31, 2025

Four Corners: Four Corners Generating Station, Units 4 and 5

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

FORTIS INC.	DECEMBER 31, 2025	40
Management Discussion and Analysis
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GHG: greenhouse gas

GWh: gigawatt hour(s)

ICFR: internal control over financial reporting

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

Luna: Luna Energy Facility

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

Material Adverse Effect: a material adverse effect on the Corporation's business, results of operations, financial position or liquidity, on a consolidated basis

MD&A: the Corporation's management discussion and analysis for the year ended December 31, 2025

MISO: Midcontinent Independent System Operator, Inc.

Morningstar DBRS: DBRS Limited

MW: megawatt(s)

Navajo: Navajo Generating Station

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

OPEB: other post-employment benefits

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

RNG: renewable natural gas

ROA: rate of return on Rate Base

ROE: rate of return on common equity

ROFR: right of first refusal

RTO: regional transmission organization

S&P: Standard & Poor's Financial Services LLC

San Juan: San Juan Generating Station Unit 1

SOFR: secured overnight financing rates

TEP: Tucson Electric Power Company

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 Electric: UNS Electric, Inc.

UNS Energy: UNS Energy Corporation, an indirect wholly-owned subsidiary of Fortis, together with its subsidiaries, including TEP, UNS Electric and UNS Gas

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

FORTIS INC.	DECEMBER 31, 2025	41

Document

Exhibit 99.4

Rule 13a-14(a) or Rule 15d-14(a) Certification - Chief Executive Officer

I, David G. Hutchens, certify that:

1. I have reviewed this annual report on Form 40-F of Fortis Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

/s/ David G. Hutchens

David G. Hutchens

President and Chief Executive Officer

St. John’s, Canada

February 12, 2026

Document

Exhibit 99.5

Rule 13a-14(a) or Rule 15d-14(a) Certification - Chief Financial Officer

I, Jocelyn H. Perry, certify that:

1. I have reviewed this annual report on Form 40-F of Fortis Inc.;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

/s/ Jocelyn H. Perry

Jocelyn H. Perry

Executive Vice President, Chief Financial Officer

St. John’s, Canada

February 12, 2026

Document

Exhibit 99.6

Rule 13a-14(b) Certification - Chief Executive Officer

In connection with the annual report of Fortis Inc. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2025 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David G. Hutchens, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ David G. Hutchens

David G. Hutchens

President and Chief Executive Officer

St. John’s, Canada

February 12, 2026

Document

Exhibit 99.7

Rule 13a-14(b) Certification - Chief Financial Officer

In connection with the annual report of Fortis Inc. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2025 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jocelyn H. Perry, Executive Vice President, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Jocelyn H. Perry

Jocelyn H. Perry

Executive Vice President, Chief Financial Officer

St. John’s, Canada

February 12, 2026

Document

Exhibit 99.8

Consent of Report of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in Registration Statement Nos. 333-264838, 333-276111, and 333-276112 on Form S-8, Registration Statement No. 333-281205 and its Post-Effective Amendment No. 1 on Form S-8, Registration Statement No. 333-236213 and its Post-Effective Amendment No. 2 on Form S-8, Registration Statement No. 333-226663 and its Post-Effective Amendment No. 3 on Form S-8, Registration Statement No. 333-283687 on Form F-10EF, and Registration Statement No. 333-279253 on Form F-3D and to the use of our reports dated February 11, 2026 relating to the consolidated financial statements of Fortis Inc. and the effectiveness of Fortis Inc.'s internal control over financial reporting appearing in this Annual Report on Form 40-F for the year ended December 31, 2025.

/s/ Deloitte LLP

Chartered Professional Accountants

St. John’s, Canada

February 12, 2026

Document

Exhibit 99.9