Quarterly Report Q3 q3 2026 pr mda fs for website

St. John's, NL - November 3, 2026

This news release constitutes a "Designated News Release" incorporated by reference in the prospectus supplement dated December 9, 2024 to Fortis' short form base shelf prospectus dated December 9, 2024.

Fortis Inc. ("Fortis" or the "Corporation") (TSX/NYSE: FTS), a diversified leader in the North American regulated electric and gas utility industry, released its third quarter results and 2027-2031 outlook.1

Highlights

• Third quarter net earnings of $474 million or $0.92 per common share, up from $0.81 per common share in 2025

• Adjusted net earnings per common share2 of $0.92, up from $0.87 per common share in the third quarter of 2025

• Capital expenditures2 of $4.2 billion through September; capital investment of $6.0 billion expected for 2026

• Released 2027-2031 capital plan of $32.2 billion, $3.4 billion higher than prior plan and supporting 7.5% rate base growth3

• Competitive project in Iowa totalling US$1.0 billion awarded to ITC, with US$0.5 billion reflected in the new five-year plan

• Environmental approval received for both the Tilbury LNG Storage Tank and Phase 2 LNG Expansion projects in British Columbia

• Recommended Opinion and Order issued with respect to TEP's rate application

• Increased fourth quarter common share dividend by 4% and extended annual dividend growth guidance of 4-6% through 2031

"During the third quarter, our utilities executed key capital investments while advancing strategic growth initiatives across our portfolio, including a competitive transmission project at ITC and the Tilbury 1B and Phase 2 LNG expansion projects at FortisBC," said David Hutchens, President and Chief Executive Officer, Fortis. "Today, we are introducing our new $32.2 billion five-year capital plan, the largest in Fortis history, which reflects the critical investments required to deliver safe, reliable and resilient energy service to our customers. With a strong pipeline of regulated investment opportunities and a proven track record of execution, we are well positioned to deliver sustained rate base growth and 4-6% annual dividend growth through 2031."

Net Earnings

The Corporation reported net earnings attributable to common equity shareholders ("Net Earnings") of $474 million for the third quarter of 2026, or $0.92 per common share, an increase of $65 million, or $0.11 per common share compared to the third quarter of 2025. The disposition of FortisTCI in September 2025 resulted in the recognition of income taxes and closing costs of $32 million, or

$0.06 per common share, in the third quarter of 2025. Excluding this impact, Net Earnings increased by $33 million quarter-over-quarter primarily due to rate base growth across our utilities. The increase was also due to higher earnings at UNS Energy, reflecting growth in retail electricity sales and the timing of operating costs, partially offset by costs associated with rate base growth not yet reflected in customer rates. The 2025 dispositions of FortisTCI and Fortis Belize and higher holding company finance costs also unfavourably impacted earnings growth for the quarter.

On a year-to-date basis, excluding the impact of income taxes and closing costs related to the 2025 disposition of FortisTCI discussed above, Net Earnings increased by $47 million, or $0.06 per common share. The increase was primarily driven by rate base growth across our utilities, as well as the timing of costs at Central Hudson. These impacts were partially offset by lower earnings at UNS Energy due to lower margin on wholesale sales and costs associated with rate base growth not yet reflected in customer rates, partially offset by higher retail electricity sales. The dispositions of FortisTCI and Fortis Belize in 2025, higher holding company finance costs, and a lower foreign exchange rate also moderated year-to-date earnings growth.

The change in earnings per common share for both the third quarter and year-to-date periods also reflected an increase in the weighted average number of common shares outstanding associated with the Corporation's dividend reinvestment and at-the-market ("ATM") equity plans.

On an adjusted earnings per common share basis, the 2025 dispositions had a $0.02 and $0.05 dilutive impact on third quarter and year-to-date results, respectively.

1 Financial information is presented in Canadian dollars unless otherwise specified.

2 Fortis uses financial measures that do not have a standardized meaning under generally accepted accounting principles in the United States of America ("U.S. GAAP") and may not be comparable to similar measures presented by other entities. Fortis presents these non-U.S. GAAP measures because management and external stakeholders use them in evaluating the Corporation's financial performance. Refer to the Non-U.S. GAAP Reconciliation provided herein.

3 Reflects the five-year compound annual growth rate calculated using a constant U.S. dollar-to-Canadian dollar exchange rate.

Adjusted Net Earnings2

Adjusted net earnings attributable to common equity shareholders ("Adjusted Net Earnings") reflects the removal of items that management excludes in its key decision-making processes and evaluation of operating results. There were no adjustments to Net Earnings for the three and nine months ended September 30, 2026. For the three and nine months ended September 30, 2025, Net Earnings were favourably adjusted by $32 million related to the disposition of FortisTCI, as previously discussed.

2026 Capital Expenditures and New Five-Year Capital Plan

Capital expenditures for 2026 are expected to be approximately $6.0 billion, up from $5.6 billion previously anticipated for the year. The increase is largely driven by the acceleration of major capital projects, including tranche 1 Midcontinent Independent System Operator ("MISO") long-range transmission plan ("LRTP") investments at ITC, and the Tilbury Phase 1B project at FortisBC Energy.

The Corporation's new 2027-2031 capital plan totals $32.2 billion, $3.4 billion higher than the previous five-year plan. The increase is primarily driven by FERC-regulated transmission investments at ITC related to the MISO LRTP tranche 2.1 portfolio of projects, including a competitive project in Iowa awarded to ITC in October 2026, as well as ongoing investment in system reliability and interconnections. The increase also reflects continued development of the Tilbury site, including the Phase 1B expansion and the Liquefied Natural Gas ("LNG") Storage Tank projects at FortisBC Energy, as well as customer growth and reliability-related investments across the Corporation's utilities. The plan is low-risk and highly executable.

The five-year capital plan is expected to be funded primarily by cash from operations and regulated utility debt. Common equity is expected to be predominantly supported by the Corporation's dividend reinvestment plan. The Corporation advanced a portion of its equity funding requirements through the issuance of US$1.0 billion of junior subordinated notes and approximately $260 million of common shares through the ATM equity program in the third quarter of 2026. The Corporation intends to file a new short-form base shelf prospectus and re-establish the ATM equity program in early 2027 to provide funding flexibility.

Significant opportunities remain beyond the five-year plan, including incremental investments associated with MISO LRTP tranche 2.1 projects. ITC estimates a range of US$2.9 billion to US$3.4 billion in capital expenditures beyond the new five-year capital plan for MISO tranche 2.1 projects located in Michigan and Minnesota, where rights of first refusal are in effect, and for projects requiring system upgrades in Iowa which are not subject to a competitive bidding process. In addition, a competitive project in Iowa of US$1.0 billion was recently awarded to ITC, of which US$0.5 billion is included in the five-year plan.

In September 2026, FortisBC Energy received an Environmental Assessment Certificate from the Province of British Columbia and the Government of Canada for the Tilbury Phase 2 LNG Expansion which would provide up to 2.5 million tonnes per annum to serve emerging LNG markets, including marine fuelling. No capital has been included in our new five-year plan associated with the Phase 2 liquefaction expansion project, but investment opportunity of $2 billion to $4 billion exists, depending on market use and a final investment decision. The majority of this investment is expected beyond 2031.

UNS Energy is experiencing strong interest from new and existing customers associated with economic development activity, including opportunities related to data centers, mining, industrial development, electrification, and broader commercial and residential growth. These opportunities could drive additional investment in generation, transmission, and distribution infrastructure over time. Tucson Electric Power ("TEP") and UNS Electric filed new Integrated Resource Plans ("IRPs") in October 2026 that support customers' projected energy needs over the next 15 years while maintaining reliability and affordability. The base case IRPs reflect opportunity above the five-year plan of up to US$1.6 billion through 2031, subject to request for proposal processes. To evaluate the potential growth above the base case IRP, TEP included a high-load factor scenario in its IRP that assumes approximately 800 MW of additional generation and could require up to US$1.5 billion of incremental investment. These opportunities are not currently reflected in the Corporation's five-year capital plan but represent meaningful long-term growth potential for the business.

Regulatory Update

In October 2026, an Arizona Corporation Commission ("ACC") Administrative Law Judge issued a Recommended Opinion and Order with respect to TEP's general rate application, recommending an allowed rate of return on common equity of 9.65% and a 55.5% common equity component of capital structure. The order also included an annual formulaic rate adjustment mechanism with a range of +/- 50 basis points around the allowed ROE, the inclusion of post-test year adjustments, and the deferral of certain costs associated with owning and operating the Roadrunner Reserve II battery storage project for future recovery. The Recommended Opinion and Order proposes implementation of new rates by December 1, 2026. The rate application remains subject to ACC approval which is anticipated later this month.

The Board of Directors of Fortis has declared the following dividends payable on December 1, 2026 to the Shareholders of Record of the following Shares of the Corporation at the close of business on November 17, 2026:

• $0.3063 per share on the First Preference Shares, Series "F";

• $0.3826875 per share on the First Preference Shares, Series "G";

• $0.26144 per share on the First Preference Shares, Series "H";

• $0.23311 per share on the First Preference Shares, Series "I";

• $0.2969 per share on the First Preference Shares, Series "J";

• $0.3418125 per share on the First Preference Shares, Series "K";

• $0.3433125 per share on the First Preference Shares, Series "M"; and,

• $0.665 per share on the Common Shares.

The Corporation has designated the common share dividend and preference share dividends as eligible dividends for federal and provincial dividend tax credit purposes.

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

$32.2 billion five-year capital plan is expected to increase midyear rate base from $45.3 billion in 2026 to $55.8 billion by 2029 and

$63.9 billion by 2031, translating into three- and five-year compound annual growth rates of 7.7% and 7.5%, respectively. Fortis expects its long-term growth in rate base will drive earnings that support dividend growth guidance of 4-6% annually through 2031.

Above and beyond the five-year capital plan, growth opportunities include: further expansion of the electric transmission grid in the

U.S. to support load growth and facilitate the interconnection of new energy resources, including transmission investments associated with the MISO LRTP and MISO transmission expansion plan; 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.

Non-U.S. GAAP Reconciliation

Periods ended September 30 Quarter Year-to-Date

About Fortis

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 $82 billion as at September 30, 2026. The Corporation's 9,900 employees serve utility customers in five Canadian provinces, ten U.S. states and the Cayman Islands.

4 Reflects income taxes and closing costs associated with the disposition of FortisTCI.

5 Represents contributions in aid of construction received for the Eagle Mountain Pipeline project.

Fortis includes forward-looking information in this media release within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance, 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 and 2027-2031; forecast midyear rate base for 2026, 2029 and 2031, and forecast three- and five-year compound annual growth rates; annual dividend growth guidance through 2031; expected nature, timing, benefits and costs of certain major capital projects, including investments at ITC related to MISO LRTP tranche 2.1 projects and ongoing investment in system reliability and interconnections, continued development of the Tilbury 1B and Tilbury LNG Storage Tank Expansion projects at FortisBC Energy, and customer growth and reliability-related investments across the Corporation's utilities; expected sources of funding for the five-year capital plan, including the source of common equity proceeds; the Corporation's intention to re-establish its ATM Program in early 2027; expected nature, timing, benefits, and costs of additional investment opportunities, including further investments by ITC associated with MISO LRTP tranche 2.1 projects, investments at FortisBC Energy associated with the Tilbury Phase 2 LNG Expansion, investments at UNS Energy associated with additional energy demands, and investments associated with IRPs filed by TEP and UNS Electric; the Corporation's goal of achieving net zero direct greenhouse gas emissions by 2050; expected timing, outcome and impact of legal and regulatory proceedings and decisions; the expectation that long-term growth in rate base will drive earnings that support dividend growth guidance; and the expected nature, timing and benefits of growth opportunities above and beyond the five-year 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, including transmission investments associated with the MISO LRTP and MISO transmission expansion plan, 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.

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 and 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; reasonable outcomes for legal and regulatory proceedings and the expectation of regulatory stability; and the Board of Directors of the Corporation exercising its discretion to declare dividends, taking into account the business performance and financial condition of the Corporation. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. For additional information with respect to certain risk factors, reference should be made to the continuous disclosure materials filed from time to time by the Corporation with Canadian securities regulatory authorities and the Securities and Exchange Commission. All forward-looking information herein is given as of the date of this media release. Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.

Teleconference and Webcast

A teleconference and webcast will be held on November 3, 2026 at 8:30 a.m. (Eastern) during which David Hutchens, President and Chief Executive Officer and Jocelyn Perry, Executive Vice President and Chief Financial Officer will discuss the Corporation's third quarter financial results and new five-year outlook.

Shareholders, analysts, members of the media and other interested parties are invited to listen to the teleconference via the live webcast on the Corporation's website, https://www.fortisinc.com/investors/events-and-presentations.

Those members of the financial community in Canada and the United States wishing to ask questions during the call are invited to participate toll free by calling 1.833.821.0229. Individuals in other international locations can participate by calling 1.647.846.2371. Please dial in 10 minutes prior to the start of the call. No access code is required.

An archived audio webcast of the teleconference will be available on the Corporation's website two hours after the conclusion of the call until December 3, 2026. Please call 1.855.669.9658 or 1.412.317.0088 and enter access code 6446629#.

Additional Information

This news release should be read in conjunction with the Corporation's September 30, 2026 Interim Management Discussion and Analysis and Condensed Consolidated Financial Statements. This and additional information can be accessed at www.fortisinc.com, www.sedarplus.ca, or www.sec.gov.

For more information, please contact:

Investor Enquiries Media Enquiries

Ms. Stephanie Amaimo Ms. Karen McCarthy

Vice President, Investor Relations Vice President, Communications & Government Relations Fortis Inc. Fortis Inc.

248.946.3572 709.737.5323

[email protected] [email protected]

Dated November 2, 2026

This Interim MD&A has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. It should be read in conjunction with the Interim Financial Statements, the 2025 Annual Financial Statements and the 2025 Annual MD&A and is subject to the cautionary statement and disclaimer provided under "Forward-Looking Information" on page 19. 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 the 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 1.38 for the quarters ended September 30, 2026 and 2025, respectively; (ii) average of 1.38 and 1.40 year-to-date September 30, 2026 and 2025, respectively; (iii) 1.42 and 1.39 as at September 30, 2026 and 2025, respectively; (iv) 1.37 as at December 31, 2025; (v) 1.38 for the 2026 annual forecast; and (vi) 1.35 for all other forecast periods. Certain terms used in this Interim MD&A are defined in the "Glossary" on page 21.

ABOUT FORTIS

Fortis (TSX/NYSE: FTS) is a diversified leader in the North American regulated electric and gas utility industry, with 2025 revenue of $12 billion and total assets of $82 billion as at September 30, 2026. The Corporation's 9,900 employees serve 3.5 million utility customers in five Canadian provinces, ten U.S. states and the Cayman Islands.

For additional information on the Corporation's operations, reportable segments and strategy, refer to the "About Fortis" section of the 2025 Annual MD&A and Note 1 of the Interim Financial Statements.

Key Financial Metrics

Periods ended September 30 Quarter Year-to-Date

(1) See "Non-U.S. GAAP Financial Measures" on page 8

Revenue

The increase in revenue for the quarter was due to overall higher flow-through and recoverable costs in customer rates, as well as Rate Base growth, higher electricity sales, and a higher U.S. dollar-to-Canadian dollar exchange rate. The increase was partially offset by the 2025 dispositions of FortisTCI and Fortis Belize.

The increase in revenue for the year-to-date period was due to the same factors discussed for the quarter, partially offset by lower pricing on wholesale sales at UNS Energy due to market conditions. A lower U.S. dollar-to-Canadian dollar exchange rate also unfavourably impacted revenue on a year-to-date basis.

Earnings and EPS

Common Equity Earnings for the quarter increased by $65 million compared to the prior year. The disposition of FortisTCI in September 2025 resulted in $32 million of income taxes and closing costs being recognized in the third quarter of 2025. Excluding this impact, Common Equity Earnings increased by $33 million quarter-over-quarter, primarily due to Rate Base growth across our utilities. The increase was also due to higher earnings at UNS Energy, reflecting growth in retail electricity sales and the timing of operating costs, partially offset by costs associated with Rate Base growth not yet reflected in customer rates. The higher U.S. dollar-to-Canadian dollar exchange rate also contributed to the increase in earnings. These factors were partially offset by the 2025 dispositions of FortisTCI and Fortis Belize, and higher holding company finance costs.

On a year-to-date basis, excluding the impact of income taxes and closing costs related to the 2025 disposition of FortisTCI discussed above, Common Equity Earnings increased by $47 million compared to the prior year. The increase was primarily driven by Rate Base growth across our utilities, as well as the timing of costs at Central Hudson. These impacts were partially offset by lower earnings at UNS Energy due to lower margin on wholesale sales and costs associated with Rate Base growth not yet reflected in customer rates, partially offset by higher retail electricity sales. The dispositions of FortisTCI and Fortis Belize in 2025, higher holding company finance costs, and a lower U.S. dollar-to-Canadian dollar exchange rate also moderated year-to-date earnings growth.

In addition to the factors impacting Common Equity Earnings, the changes in basic EPS for the quarter and year-to-date periods reflected an increase in the weighted average number of common shares outstanding associated with the Corporation's DRIP and ATM Program.

For the quarter and year-to-date periods: (i) Adjusted Common Equity Earnings increased by $33 million and $47 million, respectively, as discussed above; and (ii) Adjusted Basic EPS increased by $0.05 and $0.06, respectively. Refer to "Non-U.S. GAAP Financial Measures" on page 8 for a reconciliation of these measures. The changes in Adjusted Basic EPS for the quarter and year-to-date periods are illustrated in the following charts. On an adjusted EPS basis, the 2025 dispositions had a $0.02 and $0.05 dilutive impact on third quarter and year-to-date results, respectively, with impacts included in the Other Electric and Corporate and Other segments.

THIRD QUARTER CHANGE IN ADJUSTED BASIC EPS

$0.02

$0.02

$0.01

$0.92

$0.87

$0.03

$(0.01)

$(0.01)

$(0.01)

(1) Reflects Rate Base growth and lower non-recoverable stock-based compensation costs, partially offset by higher holding company finance costs

(2) Includes UNS Energy and Central Hudson. Reflects higher earnings at UNS Energy due to: (i) higher retail electricity sales, including higher average consumption by industrial and residential customers and customer growth; (ii) the timing of operating costs; and (iii) lower income tax expense associated with investment tax credits, partially offset by costs associated with Rate Base growth not yet reflected in customer rates. Also includes higher earnings at Central Hudson due to Rate Base growth, the timing of costs, and a contribution to a customer benefit fund in the third quarter of 2025, partially offset by a favourable adjustment to the regulatory deferral for uncollectible accounts in the third quarter of 2025

(3) Includes FortisBC Energy, FortisAlberta and FortisBC Electric. Primarily reflects Rate Base growth, as well as lower income tax expense at FortisAlberta

(4) Reflects average foreign exchange of 1.40 in 2026 compared to 1.38 in 2025

(5) Reflects the September 2025 disposition of FortisTCI, partially offset by higher electricity sales and Rate Base growth

(6) Reflects net unrealized losses on derivative contracts, the October 2025 disposition of Fortis Belize, and the timing of income tax recoveries, partially offset by a gain on a cost-accounted investment

(7) Weighted average shares of 513.1 million in 2026 compared to 504.5 million in 2025

YEAR-TO-DATE CHANGE IN ADJUSTED BASIC EPS

$0.07

$0.03

$0.07

$(0.03)

$2.69

$2.63

$(0.01)

$(0.04)

$(0.03)

(1) Reflects Rate Base growth partially offset by higher holding company finance costs

(2) Includes FortisBC Energy, FortisAlberta and FortisBC Electric. Reflects Rate Base growth and the timing of operating costs, as well as lower income tax expense at FortisAlberta

(3) Includes UNS Energy and Central Hudson. Reflects higher earnings at Central Hudson due to Rate Base growth, the timing of costs, and a contribution to a customer benefit fund in the third quarter of 2025, partially offset by a favourable adjustment to the regulatory deferral for uncollectible accounts in the third quarter of 2025. Also includes lower earnings at UNS Energy due to lower margin on wholesale sales, higher operating costs, and costs associated with Rate Base growth not yet reflected in customer rates, partially offset by: (i) higher retail electricity sales, including higher average consumption by industrial and residential customers and customer growth,

(ii) lower income tax expense, and (iii) higher transmission revenue

(4) Reflects net unrealized losses on derivative contracts, higher finance costs, and the October 2025 disposition of Fortis Belize, partially offset by gains on cost-accounted investments and the timing of income tax recoveries

(5) Reflects the September 2025 disposition of FortisTCI, partially offset by higher electricity sales and Rate Base growth

(6) Weighted average shares of 510.4 million in 2026 compared to 502.5 million in 2025

(7) Reflects average foreign exchange of 1.38 in 2026 compared to 1.40 in 2025, and foreign exchange gains recorded in 2025 associated with the revaluation of U.S. dollar denominated short-term liabilities

Dividends and TSR

Fortis paid a dividend of $0.64 per common share in the third quarter of 2026, up from $0.615 paid in the third quarter of 2025.

On November 2, 2026, Fortis declared a fourth quarter common share dividend of $0.665, up approximately 4% from its third quarter 2026 common share dividend. Fortis has increased its common share dividends for 53 consecutive years and is targeting annual dividend growth of 4-6% through 2031. See "Outlook" on page 19.

Growth in dividends and changes in the market price of the Corporation's common shares have yielded the following TSRs.

(1) Annualized TSR per Bloomberg as at September 30, 2026

Operating Cash Flow

Operating Cash Flow increased by $274 million and $489 million for the quarter and year-to-date periods, respectively. The increase was due to higher cash earnings, largely reflecting Rate Base growth as well as the sale of investment tax credits at UNS Energy. The timing of flow-through costs in customer rates, as well as higher deposits received at FortisBC Energy associated with construction costs to be incurred for the Eagle Mountain Pipeline project also contributed to the increase. The timing of collections and payments associated with the consumer carbon tax, which was effectively repealed in British Columbia in 2025, also resulted in an increase in Operating Cash Flow for the year-to-date period.

Capital Expenditures

Capital Expenditures for 2026 are expected to be $6.0 billion, up from $5.6 billion disclosed in the 2025 Annual MD&A. The increase is largely due to the acceleration of Major Capital Projects, including the MISO LRTP tranche 1 investments at ITC and the Tilbury 1B project at FortisBC Energy. The higher forecast U.S. dollar-to-Canadian dollar exchange rate is also contributing to the increase in Capital Expenditures in 2026. The Corporation is now using an assumed foreign exchange rate of 1.38 for 2026, as compared to 1.35 assumed previously.

Year-to-date Capital Expenditures of $4.2 billion represent 70% of the annual forecast, and are largely consistent with the same period in 2025.

Capital Expenditures is a Non-U.S. GAAP Financial Measure. Refer to "Non-U.S. GAAP Financial Measures" on page 8 and in the "Glossary" on page 21.

New Five-Year Capital Plan

The Corporation's new 2027-2031 Capital Plan totals $32.2 billion, $3.4 billion higher than the previous five-year plan. The increase is primarily driven by FERC-regulated transmission investments at ITC related to the MISO LRTP tranche 2.1 portfolio of projects, including those associated with ROFRs in Michigan and Minnesota and a competitive project in Iowa awarded to ITC in October 2026, as well as ongoing investment in system reliability and interconnections. The increase also reflects continued development of the Tilbury site, including the Phase 1B expansion and the LNG Storage Tank projects at FortisBC Energy, as well as customer growth and reliability-related investments across the Corporation's utilities. See "Capital Plan" on page 14 for additional information.

Common Equity Earnings Quarter Year-to-Date

Periods ended September 30 Variance Variance

(1) The reporting currency of ITC, UNS Energy, Central Hudson, and Caribbean Utilities is the U.S. dollar. The reporting currency of the Corporation's businesses in Turks and Caicos and Belize, which were sold in 2025, was the U.S. dollar or was 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 Cayman Islands: Newfoundland Power; Maritime Electric; FortisOntario; Wataynikaneyap Power; and Caribbean Utilities. Also included 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. Also included earnings from Fortis Belize up to the October 31, 2025 date of disposition

ITC Quarter Year-to-Date

Periods ended September 30 Variance Variance

2025 FX Other

(1) Revenue represents 100% of ITC. Earnings represent the Corporation's 80.1% controlling ownership interest in ITC

Revenue

The increase in revenue, net of foreign exchange, for the quarter and year-to-date periods was primarily due to Rate Base growth and higher recoverable costs in customer rates.

Earnings

The increase in earnings, net of foreign exchange, for the quarter and year-to-date periods was primarily due to Rate Base growth, partially offset by higher holding company finance costs. Lower non-recoverable stock-based compensation costs also contributed to the increase in earnings for the quarter.

UNS Energy Quarter Year-to-Date

Periods ended September 30 Variance Variance

2025 FX Other

(1) Primarily short-term wholesale sales

Sales

The increase in retail electricity sales for the quarter and year-to-date periods was due to higher average consumption by industrial and residential customers, as well as customer growth. For the quarter, the increase was partially offset by the impact of milder weather in TEP's service territory in southeastern Arizona resulting in lower air conditioning load.

The increase in wholesale electricity sales for the quarter and year-to-date periods was primarily due to higher short-term wholesale sales associated with an increase in generation capacity available under power purchase agreements and battery resources, partially offset by lower long-term wholesale sales due to unfavourable market conditions resulting in lower demand from certain customers. Revenue from short-term wholesale sales, which relate to contracts that are less than one year in duration, is primarily credited to customers through the PPFAC mechanism and, therefore, does not materially impact earnings.

Gas sales for the quarter were consistent with the same period in 2025. The decrease in gas sales for the year-to-date period was primarily due to lower average use associated with milder temperatures in UNS Gas' service territory in northern Arizona.

Revenue

The increase in revenue, net of foreign exchange, for the quarter was primarily due to higher retail and wholesale electricity sales, discussed above, partially offset by the recovery of overall lower fuel and non-fuel costs through the normal operation of regulatory mechanisms.

The decrease in revenue, net of foreign exchange, for the year-to-date period was primarily due to: (i) the recovery of overall lower fuel and non-fuel costs through the normal operation of regulatory mechanisms; and (ii) lower pricing on wholesale sales due to market conditions. The decrease was partially offset by higher retail and wholesale electricity sales.

Earnings

The increase in earnings, net of foreign exchange, for the quarter was primarily due to: (i) higher retail electricity sales, including higher average consumption and customer growth, as discussed above; (ii) the timing of operating costs; and (iii) lower income tax expense associated with the amortization of investment tax credits generated by the Roadrunner Reserve II battery storage project. The increase was partially offset by costs associated with Rate Base growth not yet reflected in customer rates. TEP has filed a general rate application with the ACC which is expected to be finalized in November 2026 (see "Regulatory Matters" on page 9).

The decrease in earnings, net of foreign exchange, for the year-to-date period was primarily due to: (i) lower margin on wholesale sales due to market conditions; (ii) higher operating costs, including planned generation maintenance costs; and (iii) costs associated with Rate Base growth not yet reflected in customer rates. The decrease was partially offset by higher retail electricity sales and lower income tax expense, as discussed above, as well as higher transmission revenue.

Central Hudson Quarter Year-to-Date

Periods ended September 30 Variance Variance

2025 FX Other

Sales

The decrease in electricity sales for the quarter was primarily due to lower average consumption by residential customers associated with lower air conditioning load due to milder weather.

The increase in electricity sales for the year-to-date period was due to higher average consumption by residential and commercial customers, partially offset by lower average consumption by industrial customers. Higher average consumption by residential customers was primarily due to higher heating load associated with colder weather in the first quarter of 2026.

The decrease in gas sales for the quarter and year-to-date periods was primarily due to lower average consumption by industrial customers.

Changes in electricity and gas sales at Central Hudson are subject to regulatory revenue decoupling mechanisms and, therefore, do not materially impact earnings.

Revenue

The increase in revenue, net of foreign exchange, for the quarter and year-to-date periods was primarily due to: (i) the flow-through of higher energy supply costs driven by commodity prices; and (ii) an increase in delivery rates, including Rate Base growth, as approved by the PSC.

Earnings

The increase in earnings, net of foreign exchange, for the quarter and year-to-date periods was due to Rate Base growth, the timing of incurring costs in comparison to related revenue recovery, and a contribution to a customer benefit fund in the third quarter of 2025. The increase was partially offset by a favourable non-recurring adjustment to the regulatory deferral for uncollectible accounts in the third quarter of 2025.

Periods ended September 30 Quarter Year-to-Date

Sales

The increase in gas sales for the quarter was primarily due to higher average consumption by industrial, residential, and commercial customers, partially offset by lower average consumption by transportation customers. Higher average consumption by residential and commercial customers was primarily due to cooler weather resulting in additional gas being used for space-heating requirements.

The decrease in gas sales for the year-to-date period was due to lower average consumption by transportation, residential, and commercial customers, partially offset by higher average consumption by industrial customers. Lower average consumption by residential and commercial customers was primarily due to milder weather in the first half of 2026.

Revenue

The increase in revenue for the quarter was primarily due to an increase in delivery rates, including the impact of Rate Base growth, as approved by the BCUC effective January 1, 2026, partially offset by the normal operation of regulatory mechanisms.

The increase in revenue for the year-to-date period was primarily due to the increase in delivery rates, including the impact of Rate Base growth, and the normal operation of regulatory mechanisms, partially offset by a lower cost of natural gas recovered from customers.

Earnings

The increase in earnings for the quarter and year-to-date periods was primarily due to Rate Base growth. The timing of operating costs also contributed to the increase in year-to-date earnings.

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.

Periods ended September 30 Quarter Year-to-Date

Deliveries

The increase in electricity deliveries for the quarter and year-to-date periods was primarily due to customer growth, largely related to industrial customers, and higher average consumption by residential customers due to warmer weather in the third quarter of 2026.

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 for the quarter and year-to-date periods was due to Rate Base and customer growth, partially offset by lower third-party service revenue. Lower income tax expense associated with the enactment of an accelerated capital cost allowance deduction on certain capital additions, and for the year-to-date period, the timing of operating costs, also contributed to the increase in earnings.

Periods ended September 30 Quarter Year-to-Date

Sales

The decrease in electricity sales for the quarter and year-to-date periods was primarily due to lower average consumption by industrial, commercial and residential customers. Lower average residential consumption for the quarter and year-to-date periods was primarily a result of lower air conditioning load in the third quarter of 2026 due to cooler weather, as well as lower heating load in the first quarter of 2026 due to milder weather.

Revenue

The decrease in revenue for the quarter and year-to-date periods was primarily due to lower electricity sales and the normal operation of regulatory mechanisms, partially offset by Rate Base growth and higher energy supply costs recovered from customers.

Earnings

Earnings for the quarter were consistent with the same period in 2025. The increase in earnings associated with Rate Base growth was offset by the timing of operating costs.

The increase in earnings for the year-to-date period was primarily due to Rate Base growth.

Due to regulatory deferral mechanisms, changes in consumption levels do not materially impact earnings.

Other Electric Quarter Year-to-Date

Periods ended September 30 Variance Variance

2025 FX Other

Sales

The decrease in electricity sales for the quarter and year-to-date periods was due to the September 2025 disposition of FortisTCI, partially offset by customer growth and higher average consumption associated with residential and commercial customers. Higher average consumption was largely due to the continued conversion of home heating systems from oil to electric in eastern Canada.

Revenue

The increase in revenue, net of foreign exchange, for the quarter and year-to-date periods was primarily due to the flow-through of higher energy supply costs recovered from customers, as well as higher sales and Rate Base growth. The increase was partially offset by the disposition of FortisTCI.

Earnings

The decrease in earnings for the quarter and year-to-date periods was primarily due to the disposition of FortisTCI, partially offset by higher electricity sales and Rate Base growth, as discussed above.

Corporate and Other Quarter Year-to-Date

Periods ended September 30 Variance Variance

2025 FX Other

(1) Reflects Fortis Belize up to the October 31, 2025 date of disposition

(2) Includes non-regulated holding company expenses and earnings for Fortis Belize up to the October 31, 2025 date of disposition

Sales and Revenue

The decrease in electricity sales and revenue for the quarter and year-to-date periods was due to the October 2025 disposition of Fortis Belize.

Net Loss

The decrease in net loss, excluding foreign exchange, for the quarter and year-to-date periods was primarily due to income taxes and closing costs of $32 million recognized in the third quarter of 2025 associated with the September 2025 disposition of FortisTCI.

Excluding this impact, the net loss increased by $7 million and $17 million for the quarter and year-to-date periods, respectively. The increase for the quarter was largely due to net unrealized losses on derivative contracts, as compared to unrealized gains recorded in 2025. The timing of income tax recoveries and the October 2025 disposition of Fortis Belize also contributed to the increase, partially offset by a gain on a cost-accounted investment.

The increase for the year-to-date period was largely due to net unrealized losses on derivative contracts, higher finance costs and the October 2025 disposition of Fortis Belize. These factors were partially offset by gains on cost-accounted investments and the timing of income tax recoveries.

In addition, the unfavourable foreign exchange impact for the year-to-date period was largely due to foreign exchange gains recorded in 2025 on the revaluation of U.S. dollar denominated short-term liabilities.

Adjusted Common Equity Earnings, Adjusted Basic EPS and Capital Expenditures are Non-U.S. GAAP Financial Measures and may not be comparable to similar measures used by other entities. They are presented because management and external stakeholders use them in evaluating the Corporation's financial performance.

Net earnings attributable to common equity shareholders (i.e. Common Equity Earnings) and basic EPS are the most directly comparable

U.S. GAAP measures to Adjusted Common Equity Earnings and Adjusted Basic EPS, respectively. These adjusted measures reflect the removal of items that management excludes in its key decision-making processes and evaluation of operating results.

Capital Expenditures include additions to property, plant and equipment and additions to intangible assets, as shown on the condensed consolidated interim statements of cash flows, less CIACs received by FortisBC Energy associated with the Eagle Mountain Pipeline project. The CIACs received for this Major Capital Project are significant and presentation of Capital Expenditures net of CIACs better aligns with the Rate Base growth associated with this project.

Non-U.S. GAAP Reconciliation

Periods ended September 30 Quarter Year-to-Date

(1) Reflects income taxes and closing costs associated with the disposition of FortisTCI, included in the Corporate and Other segment

(2) Represents CIACs received for the Eagle Mountain Pipeline project, included in the FortisBC Energy segment

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 $0.015.

UNS Energy

TEP General Rate Application: In October 2026, an ACC Administrative Law Judge issued a Recommended Opinion and Order with respect to TEP's rate application, recommending an allowed ROE of 9.65% and a 55.5% common equity component of capital structure. The order also included an annual formulaic rate adjustment mechanism with a range of +/- 50 basis points around the allowed ROE, the inclusion of post-test year adjustments, the elimination of certain adjustor mechanisms, and the deferral of certain costs associated with owning and operating the Roadrunner Reserve II battery storage project for future recovery. The Recommended Opinion and Order proposes implementation of new rates by December 1, 2026. The rate application remains subject to ACC approval which is anticipated in November 2026.

The ACC approved 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. The ACC has previously approved adjustor mechanisms, including formula-based mechanisms, in rate cases.

UNS Gas General Rate Application: In February 2026, the ACC issued an order approving an allowed ROE of 9.61% and a 56% common equity component of capital structure. The order also approved an annual formulaic rate adjustment mechanism with a range of +/- 50 basis points around the allowed ROE and the inclusion of post-test year adjustments. New rates became effective March 1, 2026.

FortisAlberta

Third PBR Term Decision: FortisAlberta filed an appeal with respect to the AUC decision establishing the parameters for the third PBR term for the period of 2024 through 2028. The appeal was largely focused on the AUC's use of historical capital additions rather than forecast capital investments approved in the 2023 cost of service proceeding. In the third quarter of 2026, the Court of Appeal of Alberta dismissed the appeal.

Depreciation Study: In May 2026, the AUC approved the negotiated settlement agreement that had been reached with respect to FortisAlberta's depreciation study. The corresponding reduction in FortisAlberta's depreciation rates has resulted in a true-up of approximately $130 million. FortisAlberta has proposed that the true-up be returned to customers over multiple years in order to moderate future increases in the distribution component of customer rates. A decision from the AUC is expected in the fourth quarter of 2026. No impact to earnings is anticipated as the related updates to revenue and depreciation expense are expected to be neutral.

Significant Changes between September 30, 2026 and December 31, 2025

Cash Flow Requirements

At the subsidiary level, it is expected that operating expenses and interest costs will be paid from Operating Cash Flow, with varying levels of residual cash flow available for capital expenditures and/or dividend payments to Fortis. Remaining capital expenditures are expected to be financed primarily from borrowings under credit facilities, long-term debt offerings and equity injections from Fortis. Borrowings under credit facilities may be required periodically to support seasonal working capital requirements.

Cash required of Fortis to support subsidiary growth is generally derived from borrowings under the Corporation's credit facilities, the operation of the DRIP, as well as issuances of long-term debt, preference equity, and common shares including any issued through the ATM Program. The subsidiaries pay dividends to Fortis and receive equity injections from Fortis when required. Both Fortis and its subsidiaries initially borrow through their credit facilities and periodically replace these borrowings with long-term financing. Financing needs also arise to refinance maturing debt.

Credit facilities are syndicated primarily with large banks in Canada and the U.S., with no one bank holding more than approximately 20% of the Corporation's total revolving credit facilities. Approximately $5.5 billion of the total credit facilities are committed with maturities ranging from 2027 through 2031. Available credit facilities are summarized in the following table.

Credit Facilities

(1) See Note 14 in the 2025 Annual Financial Statements for a description of the credit facilities as at December 31, 2025

In May 2026, the Corporation amended its $1.3 billion revolving term committed credit facility to extend the maturity to July 2031, and in October 2026, UNS Energy increased its operating credit facilities from US$375 million to US$500 million with maturities extended to October 2031.

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 September 30, 2026, consolidated fixed-term debt maturities/repayments are expected to average $1.9 billion annually over the next five years, with a maximum of $3.3 billion due in any one year. Approximately 75% 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 re-established the ATM Program pursuant to the short-form base shelf prospectus, which allows the Corporation to issue up to $500 million of common shares from treasury to the public from time to time, at the Corporation's discretion, effective until January 10, 2027. During the third quarter of 2026, 3.4 million common shares were issued under the ATM Program at an average price of $77.17 per share for proceeds of approximately $260 million. The net proceeds were used to repay credit facility borrowings and for general corporate purposes. In addition, the Corporation issued US$1.0 billion of junior subordinated notes in September 2026 under the short-form base shelf prospectus (see "Debt Financing" on page 12). As at September 30, 2026,

$237 million remained available under the ATM Program and $98 million remained available under the short-form base shelf prospectus. Fortis intends to file a new short-form base shelf prospectus, including an ATM Program in early 2027.

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 expect to continue to have reasonable access to long-term capital.

Fortis and its subsidiaries were in compliance with debt covenants as at September 30, 2026 and are expected to remain compliant.

Summary of Cash Flows

Periods ended September 30 Quarter Year-to-Date

Operating Activities

See "Performance at a Glance - Operating Cash Flow" on page 4.

Investing Activities

Cash used in investing activities for the third quarter of 2026 was $227 million higher than the same period in 2025 due to the proceeds received on the disposition of FortisTCI in 2025, partially offset by lower demand side management expenditures at FortisBC Energy. An increase in capital expenditures in the third quarter of 2026 was largely offset by higher CIACs associated with the Eagle Mountain Pipeline project.

On a year-to-date basis, cash used in investing activities was comparable with the same period in 2025. The impact of proceeds received on the disposition of FortisTCI in 2025 was largely offset by: (i) the timing of capital expenditures, net of CIACs; (ii) lower demand side management expenditures at FortisBC Energy; (iii) an equity contribution to Wataynikaneyap Power in 2025; and (iv) the lower 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 10.

The increase in cash provided by financing activities for the quarter and year-to-date periods reflects a net increase in borrowings as well as equity proceeds received upon the issuance of common shares under the ATM Program in the third quarter of 2026. The increase in borrowings was in support of the Corporation's Capital Plan, and also reflects the issuance of US$1 billion of junior subordinated notes at Fortis in September 2026 which was used to repay maturing debt in October 2026.

Debt Financing

(1) Repay short-term and/or credit facility borrowings

(2) Fund capital expenditures

(3) General corporate purposes

(4) Repay maturing long-term debt

(5) Comprised of US$25 million at 5.51% due in 2036, US$35 million at 5.86% due in 2041 and US$10 million at 6.01% due in 2046

(6) Comprised of US$70 million at 6.09% due in 2041 and US$30 million at 6.34% due in 2051

As shown in the table above, Fortis issued two tranches of fixed-to-fixed rate junior subordinated notes in September 2026. The interest rate on the first tranche will reset on March 30, 2032, and every five years thereafter, equal to the then five-year U.S. treasury bond yield plus 2.02% provided that the interest rate will not be below the initial interest rate of 6.63%. The interest rate on the second tranche will reset on March 30, 2037, and every five years thereafter, equal to the then five-year U.S. treasury bond yield plus 2.04% provided that the interest rate will not be below the initial interest rate of 6.88%. The subordinated notes receive 50% equity treatment from credit rating agencies.

In August 2026, Caribbean Utilities issued US$60 million of 16-year, 6.24% unsecured senior notes. Proceeds will be drawn in May 2027 and will be used to repay credit facility borrowings, fund capital expenditures, and for general corporate purposes.

In March 2026, Fortis redeemed US$115 million of its U.S. dollar-denominated unsecured senior notes with original maturities ranging from 2029 to 2044, and in August 2026, Fortis redeemed US$75 million of its U.S. dollar-denominated unsecured senior notes with an original maturity in 2040.

Common Equity Financing

Common Equity Issuances and Dividends Paid

Periods ended September 30 Quarter Year-to-Date

(1) Includes common shares issued under the ATM Program, as well as 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 February 11, 2026 and July 29, 2026, Fortis declared a dividend of $0.64 per common share which was paid on June 1, 2026 and September 1, 2026, respectively. On November 2, 2026, Fortis declared a dividend of $0.665 per common share payable on December 1, 2026. The payment of dividends is at the discretion of the Board and depends on the Corporation's financial condition and other factors.

There were no material changes to the contractual obligations disclosed in the 2025 Annual MD&A, other than issuances of long-term debt and credit facility utilization (see "Cash Flow Summary" on page 11), and new agreements at TEP, UNS Electric and FortisBC Electric as disclosed in Note 15 of the Interim Financial Statements.

Off-Balance Sheet Arrangements

There were no material changes to off-balance sheet arrangements from those disclosed in the 2025 Annual MD&A.

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.

(1) Includes long-term debt and finance leases, including current portion, and short-term borrowings, less cash and junior subordinated notes

(2) Includes shareholders' equity, excluding preference shares, and non-controlling interests. Non-controlling interests represented 3.4% as at September 30, 2026 (December 31, 2025 - 3.4%)

Outstanding Share Data

As at November 2, 2026, the Corporation had issued and outstanding 515.8 million common shares and the following first preference shares:

5.0 million Series F; 9.2 million Series G; 7.9 million Series H; 2.1 million Series I; 8.0 million Series J; 10.0 million Series K; and 24.0 million Series M.

The common shares of the Corporation have voting rights. The Corporation's first preference shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive or declared.

If all outstanding stock options were converted as at November 2, 2026, an additional 0.7 million common shares would be issued and outstanding.

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.

In May 2026, S&P, Fitch and Morningstar DBRS confirmed the Corporation's issuer and debt credit ratings and stable outlooks, as shown above.

Capital Expenditures for 2026 are expected to be $6.0 billion, up from $5.6 billion disclosed in the 2025 Annual MD&A. The increase is largely due to the acceleration of Major Capital Projects, including the MISO LRTP tranche 1 investments at ITC and the Tilbury 1B project at FortisBC Energy. The higher forecast U.S. dollar-to-Canadian dollar exchange rate is also contributing to the increase in Capital Expenditures in 2026. The Corporation is now using an assumed foreign exchange rate of 1.38 for 2026, as compared to 1.35 assumed previously.

Year-to-date Capital Expenditures of $4.2 billion were consistent with expectations and represent 70% of the annual forecast.

Capital Expenditures (1)

(1) See "Non-U.S. GAAP Financial Measures" on page 8

New Five-Year Capital Plan

The Corporation's five-year 2027-2031 Capital Plan is targeted at $32.2 billion.

(1) Reflects an assumed U.S. dollar-to-Canadian dollar exchange rate of 1.35. On average, a five-cent increase or decrease in the U.S. dollar relative to the Canadian dollar would increase or decrease the new Capital Plan by approximately $0.8 billion over the five-year planning period

The Corporation's new 2027-2031 Capital Plan totals $32.2 billion, $3.4 billion higher than the previous five-year plan. The increase is primarily driven by FERC-regulated transmission investments at ITC related to the MISO LRTP tranche 2.1 portfolio of projects, including those associated with ROFRs in Michigan and Minnesota and a competitive project in Iowa awarded to ITC in October 2026, as well as ongoing investment in system reliability and interconnections. The increase also reflects continued development of the Tilbury site, including the Phase 1B expansion and the LNG Storage Tank projects at FortisBC Energy, as well as customer growth and reliability-related investments across the Corporation's utilities.

Investments in the 2027-2031 Capital Plan are categorized as: (i) 47% transmission; (ii) 29% distribution; (iii) 7% renewable gas and LNG; (iv) 6% generation; and (v) 11% other, largely related to information technology and facility investments. The five-year Capital Plan is low risk and highly executable. Geographically, 62% of planned expenditures are expected in the U.S., including 36% at ITC, with 36% in Canada and the remaining 2% in the Cayman Islands.

The Capital Plan is expected to be funded primarily through cash from operations and regulated utility debt. Common equity is expected to be predominantly supported by the Corporation's DRIP. As noted in "Cash Flow Requirements" on page 10, the Corporation advanced a portion of its equity funding requirements through the issuance of US$1.0 billion of junior subordinated notes and $263 million of common shares through the ATM Program in the third quarter of 2026. The Corporation intends to re-establish its short-form base shelf prospectus and ATM Program in early 2027 to provide funding flexibility.

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. It is not possible to predict the impact on the supply chain, business operations or the five-year Capital Plan, and these factors could change and cause actual expenditures to differ from forecast.

Major Capital Projects

(2) Reflects ROFRs in Michigan and Minnesota. Also includes projects requiring system upgrades in Iowa which are not subject to a competitive bidding process

(3) Anticipated in-service dates ranging from 2029 to post-2031

(4) Net of customer contributions

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. These projects are expected to be completed in 2030.

ITC has reflected investments of approximately $1.1 billion (US$0.8 billion) in the Corporation's 2027-2031 Capital Plan associated with the MISO LRTP tranche 2.1 portfolio of 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.

In October 2026, MISO announced that ITC was selected as the developer for a competitive project in Iowa, designated by MISO as the "MARS" project. The rate of return associated with MARS is defined by the bid parameters and reflects the competitive nature of this process. The five-year plan reflects an investment of $0.6 billion (US$0.5 billion) associated with this project.

Significant additional investment opportunities remain for tranche 2.1 (see "Additional Investment Opportunities" on page 16).

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 2029.

TEP Transmission Project

Reflects a transmission project with expected completion in 2030 to serve load demand growth, increase reliability, and provide a path for connecting future generation investments.

UNS Electric Gas Generation Project

Reflects the expansion of available generation capacity within the UNS Electric service territory to support rising capacity demands. 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 2030, subject to transmission interconnection requirements and regulatory approvals.

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. In March 2026, the ACC approved an amendment to the Springerville Generating Station's Certificate of Environmental Compatibility to permit the conversion. This regulatory approval advances TEP's plans to extend the operational life of the facility and supports long-term customer affordability and system reliability.

Tilbury 1B Project

On July 24, 2026, the Province of British Columbia issued an OIC approving the Phase 1B expansion of FortisBC Energy's Tilbury LNG Facility. The OIC provides approvals required to implement the Musqueam Indian Band's minority equity partnership in the project, and includes regulatory mechanisms to protect customers from rate impacts associated with the investment.

The project adds liquefaction and dispensing capacity, as well as a marine jetty and associated onshore infrastructure to support marine bunkering. It positions the Port of Vancouver as a leading LNG marine fuelling hub and supports the transition to lower-emission marine fuels. The project remains subject to certain regulatory approvals and permitting before construction can begin. Construction is expected to start in 2027 and could be in service as early as 2031

Approximately $1.1 billion for the project is reflected in the Corporation's 2027-2031 Capital Plan, and additional investment opportunities remain. See "Additional Investment Opportunities" below.

Tilbury LNG Storage Tank Expansion

This project replaces the original LNG storage tank at the Tilbury site with a three billion cubic foot LNG storage tank, and increases the available regasification capacity to provide backup gas supply for lower mainland customers. In 2025, the BCUC approved the project and in September 2026, the Province of British Columbia and the Government of Canada provided environmental approval. The total project cost is estimated at approximately $1.1 billion, including amounts expected beyond 2031.

AMI Project

The project includes replacement of residential, commercial and industrial meters with advanced gas meters to support the safety, resiliency, and efficient operation of FortisBC Energy's gas distribution system. The project will enable remote meter reading and remote shutoff of gas. The CPCN application was approved by the BCUC in 2023. The installation of the advanced meters commenced in 2025 and is expected to continue through 2029.

Eagle Mountain Pipeline Project

The project consists of a 50 kilometre pipeline expansion to a small-scale LNG facility owned by Woodfibre LNG near Squamish, British Columbia. FortisBC Energy commenced construction of the project in 2023 and it is scheduled for completion in 2027.

Additional Investment Opportunities

Fortis is pursuing investment opportunities that are not yet included in the five-year Capital Plan.

ITC

ITC estimates a range of US$2.9 billion to US$3.4 billion in capital expenditures beyond the five-year Capital Plan 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. In addition, the MARS competitive project in Iowa was recently awarded to ITC for a total investment of US$1.0 billion, of which US$0.5 billion is included in the five-year plan.

In April 2026, ITC, along with a coalition of other transmission owners, filed a complaint at FERC related to the competitive bidding process for electric transmission projects in the MISO and SPP regions. The complaint seeks to either exempt transmission projects in the MISO and SPP regions that facilitate generation or load additions from the competitive bidding process or suspend competitive solicitations for certain categories of projects in these regions for the next five years. Although there is no stipulated timeline for FERC to act, it has been requested that the proposed change apply prospectively from the date of the complaint.

UNS Energy

In 2025, TEP entered into an energy supply agreement to serve a customer expected to be located in TEP's service territory. The agreement, requiring potential power demand of approximately 300 MW, was approved by the ACC in December 2025. The energy supply agreement provides additional consumer protections such as establishing minimum monthly payment obligations that apply irrespective of customer energy use, authorizing termination fees supported by financial assurance mechanisms, and imposing credit standards designed to mitigate the risk of default. In April 2026, the parties waived certain contractual provisions under the energy supply agreement and established a US$40 million termination payment if the agreement is terminated prior to the commencement of electric service, which was secured by a letter of credit. Load associated with the initial phase of the data center campus is expected to ramp up beginning in 2027, and TEP expects to serve the customer from its existing and planned capacity, including solar and battery storage projects currently in development.

In addition to the energy supply agreement signed in 2025, 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.

UNS Energy is experiencing strong interest from new and existing customers associated with economic development activity, including opportunities related to data centers, mining, industrial development, electrification, and broader commercial and residential growth. These opportunities could drive additional investment in generation, transmission, and distribution infrastructure over time. TEP and UNS Electric filed new IRPs with the ACC in October 2026 that support customers' projected energy needs over the next 15 years while maintaining reliability and affordability. The base case IRPs reflect opportunity above the five-year plan of up to US$1.6 billion through 2031, subject to request for proposal processes. To evaluate the potential growth above the base case IRP, TEP included a high-load factor scenario in its IRP that assumes approximately 800 MW of additional generation and could require up to US$1.5 billion of incremental investment. These opportunities are not currently reflected in the Corporation's five-year capital plan but represent meaningful long-term growth potential for the business.

FortisBC Energy

Tilbury Phase 2 LNG Expansion Project

In September 2026, the Province of British Columbia and the Government of Canada provided environmental approval for the Tilbury Phase 2 LNG Expansion project which includes up to 2.5 million tonnes per annum of additional liquefaction capacity, as well as infrastructure to support domestic marine fuelling and/or bulk LNG export markets. Development of the project could occur in stages, and remains subject to market demand, permitting approvals and the final investment decision. FortisBC Energy estimates investment opportunity of $2 billion to $4 billion for the project, depending on market use. The majority of this investment is expected beyond 2031.

Tilbury 1B Project

As discussed above, a total of $1.1 billion is reflected in the Corporation's 2027-2031 Capital Plan for the Tilbury 1B project. Management estimates that additional investments of approximately $0.4 billion may be required for the project depending on the finalization of planning and cost estimates, which would bring the project to a total of approximately $1.8 billion including amounts incurred through 2026 and AFUDC. These additional investments may be beyond 2031.

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.

The Corporation's business risks remain substantially unchanged from those disclosed in its 2025 Annual MD&A.

Accounting Policies

The Interim Financial Statements have been prepared following the same accounting policies and methods as those used to prepare the 2025 Annual Financial Statements.

Future Accounting Pronouncements

Expense Disaggregation: ASU No. 2024-03, Disaggregation of Income Statement Expenses, is effective for Fortis on January 1, 2027 for annual periods and on January 1, 2028 for interim periods, on a prospective basis, with retrospective application and early adoption permitted. The ASU requires detailed disclosure of certain expense categories included on the consolidated statements of earnings, including energy supply costs, operating expenses, and depreciation and amortization expense. Fortis is assessing the impact on its disclosures.

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.

Critical Accounting Estimates

General

The preparation of the Interim Financial Statements required management to make estimates and judgments, including those related to regulatory decisions, that affect the reported amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. Actual results could differ materially from estimates.

There were no material changes to the nature of the Corporation's critical accounting estimates or contingencies from those disclosed in the 2025 Annual MD&A, except as disclosed in Note 15 of the Interim Financial Statements.

Income Tax Update

On September 15, 2026, the Government of Canada released draft legislative proposals introducing the Productivity Mega Deduction which would provide immediate expensing for a broad range of depreciable property acquired on or after that date. The proposals had not been enacted as at September 30, 2026 and, accordingly, no impact was recognized in the Interim Financial Statements.

The Productivity Mega Deduction is expected to increase tax losses across its Canadian regulated utilities and the ability to utilize these deductions or losses may vary depending on each utility's tax position and applicable regulatory framework. The Corporation is continuing to assess the potential impact of the proposals on its Canadian operations, but does not expect the Productivity Mega Deduction to materially impact the Corporation's financial position.

As at September 30, 2026, the carrying value of long-term debt, including current portion, was $37.8 billion (December 31, 2025 - $34.1 billion) compared to an estimated fair value of $34.2 billion (December 31, 2025 - $32.3 billion).

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 are recorded at fair value with certain exceptions, including those derivatives that qualify for the normal purchase and normal sale exception.

There were no material changes with respect to the nature and purpose, methodologies for fair value determination, and portfolio of the Corporation's derivatives from those disclosed in the 2025 Annual MD&A. See Note 14 of the Interim Financial Statements for additional information.

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.

September 2026/September 2025

See "Performance at a Glance" on page 2.

June 2026/June 2025

Common Equity Earnings increased by $12 million and basic EPS increased by $0.02 compared to the second quarter of 2025. The growth in earnings was due to Rate Base growth across our utilities and higher retail electricity sales, including the impact of warmer weather, at UNS Energy. The increase was partially offset by: (i) higher costs associated with Rate Base growth not yet reflected in customer rates as well as the timing of operating costs at UNS Energy; (ii) a shift in the timing of quarterly revenue associated with delivery rates effective July 1, 2025 at Central Hudson; and (iii) higher holding company finance costs. The 2025 dispositions of FortisTCI and Fortis Belize, as well as the impact of foreign exchange, also unfavourably impacted earnings growth. 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 2026/March 2025

Common Equity Earnings were comparable with the first quarter of 2025. Rate Base growth across our utilities, along with higher earnings at Central Hudson driven by the timing of operating expenses and a shift in quarterly revenue, contributed to earnings growth in the first quarter of 2026. This growth was offset by lower earnings at UNS Energy due to wholesale market conditions, the timing of planned generation maintenance costs, milder weather conditions, and higher costs associated with Rate Base growth not yet reflected in customer rates. The lower

U.S. dollar-to-Canadian dollar exchange rate and the 2025 dispositions of FortisTCI and Fortis Belize also unfavourably impacted earnings growth. Basic EPS decreased by $0.01 compared to the first quarter of 2025, reflecting the factors impacting Common Equity Earnings, as well as an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

December 2025/December 2024

Common Equity Earnings increased by $26 million and basic EPS increased by $0.04 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. Excluding these items, Common Equity Earnings increased by $37 million compared to the fourth quarter of 2024 primarily due to Rate Base growth across the utilities. Growth was also due to: (i) unrealized gains on derivative contracts; (ii) the timing of operating costs at FortisAlberta; and (iii) a favourable impact of foreign exchange. 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 in 2025. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions for the three and nine months ended September 30, 2026 and 2025.

Fortis periodically provides short-term financing to subsidiaries to support capital expenditures and seasonal working capital requirements, the impacts of which are eliminated on consolidation. As at September 30, 2026 and December 31, 2025, there were no material inter-segment loans outstanding. Interest charged on inter-segment loans was not material for the three and nine months ended September 30, 2026 and 2025.

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 $32.2 billion five-year Capital Plan is expected to increase midyear Rate Base from $45.3 billion in 2026 to $55.8 billion by 2029 and $63.9 billion by 2031, translating into three- and five-year CAGRs of 7.7% and 7.5%, respectively. Fortis expects its long-term growth in Rate Base will drive earnings that support dividend growth guidance of 4-6% annually through 2031.

Above and beyond the five-year Capital Plan, growth opportunities include: further expansion of the electric transmission grid in the U.S. to support load growth and facilitate the interconnection of new energy resources, including transmission investments associated with the MISO LRTP and MISO transmission expansion plan; 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.

Fortis includes forward-looking information in this MD&A within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance, business prospects, and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates, expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would, and the negative of these terms, and other similar terminology or expressions, have been used to identify the forward-looking information, which includes, without limitation: annual dividend growth guidance through 2031; forecast Capital Expenditures for 2026 and 2027 through 2031; expected timing, outcome and impact of legal and regulatory proceedings and decisions; expected and potential funding sources for operating expenses, interest costs, and capital expenditures; the expectation that maintaining the targeted capital structures of the regulated operating subsidiaries will not have an impact on the Corporation's ability to pay dividends in the foreseeable future; expected consolidated fixed-term debt maturities and repayments over the next five years; the Corporation's intention to re-establish its short-form base shelf prospectus and ATM Program in early 2027; 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; estimated impact of variations in the U.S. dollar-to-Canadian dollar exchange rate on the Capital Plan; expected sources of funding for the five-year Capital Plan, including the source of common equity; the potential impact of changes in government policy on foreign trade, including the imposition of tariffs and the potential impacts on the supply chain, commodity prices, the cost of energy, general economic conditions, business operations and the five-year Capital Plan; expected nature, timing, benefits and costs of certain Major Capital Projects, including investments associated with MISO LRTP tranches 1 and 2.1, the Big Cedar Load Expansion, the TEP Transmission project, the UNS Electric Gas Generation project, the Springerville Natural Gas Conversion, the Tilbury 1B project, the Tilbury LNG Storage Tank Expansion, the AMI project and the Eagle Mountain Pipeline project; expected nature, timing, benefits and costs of additional investment opportunities, including further investments by ITC associated with MISO LRTP tranche 2.1 projects, investments at UNS Energy associated with additional energy demands, including the energy supply agreement to serve a data center customer in TEP's service territory, further negotiations for additional capacity at that site and a potential second site, and investments associated with IRPs filed by TEP and UNS Electric, and investments at FortisBC Energy associated with the Tilbury Phase 2 LNG Expansion project and additional investments associated with Tilbury 1B project; the potential and expected impacts of future accounting pronouncements on the Corporations' disclosures; potential and expected impacts of the draft Canadian Productivity Mega Deduction on the Corporation's credit metrics and its Canadian regulated utilities' tax losses and their ability to utilize these deductions or losses; forecast Rate Base for 2026, 2029 and 2031 and the related three- and five-year CAGRs; the expectation that long-term growth in Rate Base will drive earnings that support dividend growth guidance; and the expected nature, timing and benefits of growth opportunities above and beyond the five-year 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, including transmission investments associated with the MISO LRTP and MISO transmission expansion plan, 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.

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; the 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 the 2025 Annual 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 and gas distribution volumes; 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 November 2, 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.

2025 Annual Financial Statements: the Corporation's audited consolidated financial statements and notes thereto for the year ended December 31, 2025

2025 Annual MD&A: the Corporation's management discussion and analysis for the year ended December 31, 2025

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 8

ACC: Arizona Corporation Commission

AFUDC: allowance for funds used during construction

AMI: advanced metering infrastructure

ASU: accounting standards update

ATM Program: at-the-market equity program

AUC: Alberta Utilities Commission

BCUC: British Columbia Utilities Commission

Belize Electricity: Belize Electricity Limited, in which Fortis indirectly 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 Interim Financial Statements, less CIACs received by FortisBC Energy associated with the Eagle Mountain Pipeline project. See "Non-U.S. GAAP Financial Measures" on page 8

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

CIACs: contributions in aid of construction

Common Equity Earnings: net earnings attributable to common equity shareholders

Corporation: Fortis Inc.

DRIP: dividend reinvestment plan

EPS: earnings per common share

FERC: Federal Energy Regulatory Commission

Fitch: Fitch Ratings, Inc.

Fortis: Fortis Inc.

FortisAlberta: FortisAlberta Inc., an indirect wholly-owned subsidiary of Fortis

FortisBC 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

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

GWh: gigawatt hour(s)

Interim Financial Statements: the Corporation's unaudited condensed consolidated interim financial statements and notes thereto for the three and nine months ended September 30, 2026

Interim MD&A: the Corporation's management discussion and analysis for the three and nine months ended September 30, 2026

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

LNG: liquefied natural gas

LRTP: long-range transmission plan

MARS: Marshalltown - Lehigh - Sub T - Montezuma - East Adair 345/765 kV competitive transmission project

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

MISO: Midcontinent Independent System Operator, Inc.

Morningstar DBRS: DBRS Limited

MW: megawatts

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

OIC: Order in Council

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

ROE: rate of return on common equity

ROFR: right of first refusal

RTO: regional transmission organization S&P: Standard & Poor's Financial Services LLC SPP: Southwest Power Pool

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 Energy: UNS Energy Corporation, an indirect wholly owned subsidiary of Fortis, together with its subsidiaries, including TEP, UNS Electric and UNS Gas

UNS Electric: UNS Electric, Inc.

UNS Gas: UNS Gas, Inc.

U.S.: United States of America

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

Wataynikaneyap Power: Wataynikaneyap Power Limited Partnership, in which Fortis indirectly holds a 39% equity interest

FORTIS INC.

For the three and nine months ended September 30, 2026 and 2025 (Unaudited)

FORTIS INC.

(1) No par value. Unlimited authorized shares. 515.8 million and 507.3 million issued and outstanding as at September 30, 2026 and December 31, 2025, respectively.

See accompanying Notes to Condensed Consolidated Interim Financial Statements

FORTIS INC.

Quarter Year-to-Date

See accompanying Notes to Condensed Consolidated Interim Financial Statements

Quarter Year-to-Date

(1) Net of hedging activities and income tax (expense) recovery of $(3) million and $8 million for the three and nine months ended September 30, 2026, respectively (three and nine months ended September 30, 2025 - income tax recovery (expense) of $2 million and $(6) million, respectively).

(2) Net of income tax expense of $1 million and $2 million for the three and nine months ended September 30, 2026, respectively (three and nine months ended September 30, 2025 - income tax recovery of $4 million and $10 million, respectively).

See accompanying Notes to Condensed Consolidated Interim Financial Statements

FORTIS INC.

Quarter Year-to-Date

Supplementary Cash Flow Information (Note 13)

See accompanying Notes to Condensed Consolidated Interim Financial Statements

FORTIS INC.

See accompanying Notes to Condensed Consolidated Interim Financial Statements

FORTIS INC.

See accompanying Notes to Condensed Consolidated Interim Financial Statements

For the three and nine months ended September 30, 2026 and 2025

1. DESCRIPTION OF BUSINESS

   Nature of Operations

   Fortis Inc. ("Fortis" or the "Corporation") is a diversified North American regulated electric and gas utility holding company.

   Earnings for interim periods may not be indicative of annual results due to: (i) the impact of seasonal weather conditions on customer demand; (ii) the impact of market conditions, particularly with respect to long-term wholesale sales at UNS Energy; (iii) the timing and significance of any regulatory decisions; and (iv) changes in the U.S. dollar-to-Canadian dollar exchange rate. 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.

   Entities within the reporting segments that follow operate with substantial autonomy.

   Regulated Utilities

   ITC: ITC Investment Holdings Inc., ITC Holdings Corp. and the electric transmission operations of its regulated operating subsidiaries, which include International Transmission Company, Michigan Electric Transmission Company, LLC, ITC Midwest LLC and ITC Great Plains, LLC. Fortis owns 80.1% of ITC and an affiliate of GIC Private Limited owns a 19.9% minority interest.

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

   Central Hudson: CH Energy Group, Inc., which primarily includes Central Hudson Gas & Electric Corporation.

   FortisBC Energy: FortisBC Energy Inc.

   FortisAlberta: FortisAlberta Inc.

   FortisBC Electric: FortisBC Inc.

   Other Electric: Eastern Canadian and Caribbean utilities, as follows: Newfoundland Power Inc.; Maritime Electric Company, Limited; FortisOntario Inc.; a 39% equity investment in Wataynikaneyap Power Limited Partnership; and an approximate 60% controlling interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities"). Also included 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 11).

   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, and included non-regulated long-term contracted generation assets in Belize until the October 31, 2025 date of disposition (Note 11).

2. REGULATORY MATTERS

   Regulation of the Corporation's utilities is generally consistent with that disclosed in Note 2 of the Corporation's annual audited consolidated financial statements ("2025 Annual Financial Statements"). A summary of significant outstanding regulatory matters follows.

   ITC

   Transmission Incentives: In 2021, the Federal Energy Regulatory Commission ("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") return on common equity ("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 October 2026, an Arizona Corporation Commission ("ACC") Administrative Law Judge issued a Recommended Opinion and Order with respect to TEP's rate application, recommending an allowed ROE of 9.65% and a 55.5% common equity component of capital structure. The order also included an annual formulaic rate adjustment mechanism with a range of +/- 50 basis points around the allowed ROE, the inclusion of post-test year adjustments, the elimination of certain adjustor mechanisms, and the deferral of certain costs associated with owning and operating the Roadrunner Reserve II battery storage project for future recovery. The Recommended Opinion and Order proposes implementation of new rates by December 1, 2026. The rate application remains subject to ACC approval which is anticipated in November 2026.

   The ACC approved 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. The ACC has previously approved adjustor mechanisms, including formula-based mechanisms, in rate cases.

   For the three and nine months ended September 30, 2026 and 2025

   2. REGULATORY MATTERS (cont'd)

   UNS Gas General Rate Application: In February 2026, the ACC issued an order approving an allowed ROE of 9.61% and a 56% common equity component of capital structure. The order also approved an annual formulaic rate adjustment mechanism with a range of +/- 50 basis points around the allowed ROE and the inclusion of post-test year adjustments. New rates became effective March 1, 2026.

   FortisAlberta

   Third Performance-based Rate-setting ("PBR") Term Decision: FortisAlberta filed an appeal with respect to the Alberta Utilities Commission ("AUC") decision establishing the parameters for the third PBR term for the period of 2024 through 2028. The appeal was largely focused on the AUC's use of historical capital additions rather than forecast capital investments approved in the 2023 cost of service proceeding. In the third quarter of 2026, the Court of Appeal of Alberta dismissed the appeal.

   Depreciation Study: In May 2026, the AUC approved the negotiated settlement agreement that had been reached with respect to FortisAlberta's depreciation study. The corresponding reduction in FortisAlberta's depreciation rates has resulted in a true-up of approximately $130 million. FortisAlberta has proposed that the true-up be returned to customers over multiple years in order to moderate future increases in the distribution component of customer rates. A decision from the AUC is expected in the fourth quarter of 2026. No impact to earnings is anticipated as the related updates to revenue and depreciation expense are expected to be neutral.

3. ACCOUNTING POLICIES

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

   The Interim Financial Statements include the accounts of the Corporation and its subsidiaries and reflect the equity method of accounting for entities in which Fortis has significant influence, but not control, and proportionate consolidation for assets that are jointly owned with non-affiliated entities.

   These Interim Financial Statements do not include all of the disclosures required in the annual financial statements and should be read in conjunction with the Corporation's 2025 Annual Financial Statements. In management's opinion, these Interim Financial Statements include all adjustments that are of a normal recurring nature, necessary for fair presentation.

   The preparation of the Interim Financial Statements required management to make estimates and judgments, including those related to regulatory decisions, that affect the reported amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. Actual results could differ materially from estimates.

   The Corporation considers the applicability and impact of all Accounting Standards Updates ("ASUs") issued by the Financial Accounting Standards Board. Any ASUs not included in these Interim Financial Statements were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the Interim Financial Statements.

   The accounting policies applied herein are consistent with those outlined in the Corporation's 2025 Annual Financial Statements.

   Future Accounting Pronouncements

   Expense Disaggregation: ASU No. 2024-03, Disaggregation of Income Statement Expenses, is effective for Fortis on January 1, 2027 for annual periods and on January 1, 2028 for interim periods, on a prospective basis, with retrospective application and early adoption permitted. The ASU requires detailed disclosure of certain expense categories included on the consolidated statements of earnings, including energy supply costs, operating expenses, and depreciation and amortization expense. Fortis is assessing the impact on its disclosures.

   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.

   For the three and nine months ended September 30, 2026 and 2025

4. SEGMENTED INFORMATION

   Fortis' President and Chief Executive Officer is considered the chief operating decision maker ("CODM") for purposes of reviewing segment performance. Fortis segments its business based on regulatory jurisdiction and service territory, as well as the information used by the CODM in deciding how to allocate resources. Segment performance is evaluated principally on net earnings attributable to common equity shareholders, and this measure is used consistently in the evaluation of actual segment performance as well as in the Corporation's business plan and forecasting processes.

   Related-Party and Inter-Company Transactions

   Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions for the three and nine months ended September 30, 2026 and 2025. Fortis periodically provides short-term financing to subsidiaries to support capital expenditures and seasonal working capital requirements, the impacts of which are eliminated on consolidation. As at September 30, 2026 and December 31, 2025, there were no material inter-segment loans outstanding. Interest charged on inter-segment loans was not material for the three and nine months ended September 30, 2026 and 2025.

   ($ millions)	ITC	UNS Energy	Central Hudson	FortisBC Energy	Fortis Alberta	FortisBC Electric	Other Electric	Sub Total	Corporate and Other	Inter-segment eliminations	Total
   Quarter ended September 30, 2026
   Revenue	666	919	449	308	221	132	420	3,115	-	-	3,115
   Energy supply costs	-	(310)	(161)	(64)	-	(38)	(248)	(821)	-	-	(821)
   Operating expenses	(152)	(208)	(191)	(110)	(48)	(36)	(57)	(802)	(2)	-	(804)
   Depreciation and amortization	(131)	(122)	(43)	(103)	(79)	(21)	(53)	(552)	(1)	-	(553)
   Operating income	383	279	54	31	94	37	62	940	(3)	-	937
   Other income, net	30	15	15	16	2	1	9	88	7	-	95
   Finance charges	(145)	(44)	(25)	(38)	(37)	(21)	(20)	(330)	(65)	-	(395)
   Income tax expense	(62)	(25)	(11)	(3)	(1)	(2)	(5)	(109)	17	-	(92)
   Net earnings	206	225	33	6	58	15	46	589	(44)	-	545
   Non-controlling interests	(39)	-	-	-	-	-	(10)	(49)	-	-	(49)
   Preference share dividends	-	-	-	-	-	-	-	-	(22)	-	(22)
   Net earnings attributable to common
   equity shareholders	167	225	33	6	58	15	36	540	(66)	-	474
   Additions to property, plant and
   equipment and intangible assets	573	257	136	512	162	54	99	1,793	-	-	1,793
   As at September 30, 2026
   Goodwill	8,734	1,966	642	913	231	235	216	12,937	-	-	12,937
   Total assets	30,006	16,194	7,204	11,296	6,829	3,086	5,441	80,056	1,676	(10)	81,722

   Quarter ended September 30, 2025
   Revenue	625	893	388	281	213	133	393	2,926	12	-	2,938
   Energy supply costs	-	(311)	(138)	(59)	-	(42)	(209)	(759)	-	-	(759)
   Operating expenses	(160)	(209)	(166)	(103)	(46)	(33)	(58)	(775)	(15)	-	(790)
   Depreciation and amortization	(121)	(106)	(39)	(95)	(75)	(23)	(57)	(516)	(2)	-	(518)
   Operating income	344	267	45	24	92	35	69	876	(5)	-	871
   Other income, net	21	16	16	13	2	2	5	75	3	-	78
   Finance charges	(129)	(42)	(21)	(39)	(34)	(20)	(22)	(307)	(63)	-	(370)
   Income tax expense	(53)	(32)	(9)	2	(6)	(2)	(2)	(102)	(3)	-	(105)
   Net earnings	183	209	31	-	54	15	50	542	(68)	-	474
   Non-controlling interests	(34)	-	-	-	-	-	(9)	(43)	-	-	(43)
   Preference share dividends Net earnings attributable to common	-	-	-	-	-	-	-	-	(22)	-	(22)
   equity shareholders	149	209	31	-	54	15	41	499	(90)	-	409
   Additions to property, plant and
   equipment and intangible assets	435	385	121	215	136	50	110	1,452	1	-	1,453
   As at September 30, 2025
   Goodwill	8,543	1,923	628	913	231	235	213	12,686	-	-	12,686
   Total assets	27,455	15,136	6,337	10,515	6,385	2,907	5,251	73,986	530	(13)	74,503

   For the three and nine months ended September 30, 2026 and 2025

   4. SEGMENTED INFORMATION (cont'd)

   ($ millions)	ITC	UNS Energy	Central Hudson	FortisBC Energy	Fortis Alberta	FortisBC Electric	Other Electric	Sub Total	Corporate and Other	Inter-segment eliminations	Total
   Year-to-date September 30, 2026
   Revenue	1,973	2,221	1,416	1,396	642	410	1,391	9,449	-	-	9,449
   Energy supply costs	-	(733)	(528)	(392)	-	(107)	(851)	(2,611)	-	-	(2,611)
   Operating expenses	(502)	(642)	(562)	(333)	(150)	(113)	(181)	(2,483)	(32)	-	(2,515)
   Depreciation and amortization	(385)	(343)	(128)	(309)	(239)	(64)	(157)	(1,625)	(2)	-	(1,627)
   Operating income	1,086	503	198	362	253	126	202	2,730	(34)	-	2,696
   Other income, net	83	58	58	43	5	4	27	278	27	-	305
   Finance charges	(420)	(126)	(75)	(113)	(108)	(62)	(61)	(965)	(189)	-	(1,154)
   Income tax expense	(169)	(45)	(44)	(65)	(8)	(7)	(24)	(362)	82	-	(280)
   Net earnings	580	390	137	227	142	61	144	1,681	(114)	-	1,567
   Non-controlling interests	(108)	-	-	(1)	-	-	(22)	(131)	-	-	(131)
   Preference share dividends	-	-	-	-	-	-	-	-	(65)	-	(65)
   Net earnings attributable to common
   equity shareholders	472	390	137	226	142	61	122	1,550	(179)	-	1,371
   Additions to property, plant and
   equipment and intangible assets	1,591	774	346	1,368	490	152	284	5,005	-	-	5,005
   As at September 30, 2026
   Goodwill	8,734	1,966	642	913	231	235	216	12,937	-	-	12,937
   Total assets	30,006	16,194	7,204	11,296	6,829	3,086	5,441	80,056	1,676	(10)	81,722

   Year-to-date September 30, 2025
   Revenue	1,870	2,267	1,208	1,298	621	412	1,386	9,062	29	-	9,091
   Energy supply costs	-	(816)	(399)	(378)	-	(120)	(800)	(2,513)	-	-	(2,513)
   Operating expenses	(477)	(606)	(518)	(314)	(148)	(105)	(190)	(2,358)	(51)	-	(2,409)
   Depreciation and amortization	(361)	(319)	(117)	(274)	(228)	(63)	(177)	(1,539)	(6)	-	(1,545)
   Operating income	1,032	526	174	332	245	124	219	2,652	(28)	-	2,624
   Other income, net	60	55	53	37	5	4	17	231	43	-	274
   Finance charges	(387)	(127)	(69)	(115)	(101)	(60)	(68)	(927)	(182)	-	(1,109)
   Income tax expense	(163)	(60)	(37)	(51)	(17)	(11)	(19)	(358)	45	-	(313)
   Net earnings	542	394	121	203	132	57	149	1,598	(122)	-	1,476
   Non-controlling interests	(100)	-	-	(1)	-	-	(20)	(121)	-	-	(121)
   Preference share dividends Net earnings attributable to common	-	-	-	-	-	-	-	-	(63)	-	(63)
   equity shareholders	442	394	121	202	132	57	129	1,477	(185)	-	1,292
   Additions to property, plant and
   equipment and intangible assets	1,363	1,128	330	792	424	127	373	4,537	3	-	4,540
   As at September 30, 2025
   Goodwill	8,543	1,923	628	913	231	235	213	12,686	-	-	12,686
   Total assets	27,455	15,136	6,337	10,515	6,385	2,907	5,251	73,986	530	(13)	74,503

   For the three and nine months ended September 30, 2026 and 2025

5. ALLOWANCE FOR CREDIT LOSSES

   The allowance for credit losses, which is recorded in accounts receivable and other current assets, changed as follows.

   Quarter Year-to-Date

   ($ millions)	2026	2025	2026	2025
   Periods ended September 30
   Balance, beginning of period	(77)	(74)	(80)	(78)
   Credit loss expense	(10)	(11)	(34)	(25)
   Credit loss deferral	(13)	(19)	(20)	(36)
   Write-offs, net of recoveries	24	19	60	51
   Disposition (Note 11)	-	6	-	6
   Foreign exchange	-	(1)	(2)	2
   Balance, end of period	(76)	(80)	(76)	(80)

   See Note 14 for disclosure on the Corporation's credit risk.

6. REGULATORY ASSETS AND LIABILITIES

   Detailed information about the Corporation's regulatory assets and liabilities is provided in Note 8 to the 2025 Annual Financial Statements. A summary follows.

   As at

   ($ millions)	September 30, 2026	December 31, 2025
   Regulatory assets
   Deferred income taxes	2,596	2,424
   Deferred energy management costs	702	701
   Rate stabilization and related accounts	590	552
   Employee future benefits	193	192
   Deferred lease costs	177	145
   Deferred restoration costs	113	109
   Derivatives	112	135
   Manufactured gas plant site remediation deferral	91	84
   Roadrunner Reserve 1 cost deferral	62	23
   Renewable natural gas account	61	28
   Generation early retirement costs	49	49
   Business development deposit tax	41	58
   Meter cost recovery	32	37
   Other regulatory assets	475	485
   Total regulatory assets	5,294	5,022
   Less: Current portion	(914)	(915)
   Long-term regulatory assets	4,380	4,107
   Regulatory liabilities
   Future cost of removal	1,994	1,853
   Deferred income taxes	1,521	1,349
   Employee future benefits	444	467
   Rate stabilization and related accounts	329	183
   Renewable energy surcharge	190	164
   Energy efficiency liability	77	68
   Other regulatory liabilities	214	178
   Total regulatory liabilities	4,769	4,262
   Less: Current portion	(510)	(452)
   Long-term regulatory liabilities	4,259	3,810

   For the three and nine months ended September 30, 2026 and 2025

7. LONG-TERM DEBT

   As at

   ($ millions)	September 30, 2026	December 31, 2025
   Long-term debt Credit facility borrowings	36,893 861	32,542 1,515
   Total long-term debt Less: Deferred financing costs and debt discounts Less: Current installments of long-term debt	37,754 (219) (3,967)	34,057 (188) (3,146)
   	33,568	30,723

   Significant Long-Term Debt Issuances Year-to-date September 30, 2026 ($ millions, except as noted)	Month Issued	Interest Rate (%)	Maturity	Amount ($ millions)	Use of Proceeds
   ITC
   Secured senior notes	January	5.08	2036	US $125	(1) (2) (3)
   Secured senior notes	January	5.71	2046	US $125	(1) (2) (3)
   First mortgage bonds	March	4.78	2034	US $175	(1) (2) (3)
   First mortgage bonds	March	4.86	2035	US $175	(1) (2) (3)
   Unsecured senior notes	April	4.88	2031	US $500	(1) (3) (4)
   Unsecured senior notes	April	5.50	2036	US $400	(1) (3) (4)
   First mortgage bonds	July	5.41	2044	US $50	(1) (2) (3)
   First mortgage bonds	July	5.53	2047	US $100	(1) (2) (3)
   UNS Energy
   Unsecured senior notes	August	5.74	2038	US $60	(1) (3) (4)
   Central Hudson
   Unsecured senior notes	April	(5)	(5)	US $70	(1) (3)
   FortisBC Energy
   Unsecured debentures	August	5.17	2056	300	(1) (3)
   FortisAlberta
   Unsecured senior debentures	July	4.92	2056	200	(1) (2) (3)
   FortisBC Electric
   Unsecured debentures	August	5.37	2056	150	(1) (3)
   Caribbean Utilities
   Unsecured senior notes	August	(6)	(6)	US $100	(1) (2) (3)
   Fortis
   Unsecured junior subordinated notes	September	6.63	2057	US $500	(3) (4)
   Unsecured junior subordinated notes	September	6.88	2057	US $500	(3) (4)

   1. Repay short-term and/or credit facility borrowings

   2. Fund capital expenditures

   3. General corporate purposes

   4. Repay maturing long-term debt

   5. Comprised of US$25 million at 5.51% due in 2036, US$35 million at 5.86% due in 2041 and US$10 million at 6.01% due in 2046

   6. Comprised of US$70 million at 6.09% due in 2041 and US$30 million at 6.34% due in 2051

      As shown in the table above, Fortis issued two tranches of fixed-to-fixed rate junior subordinated notes in 2026. The interest rate on the first tranche will reset on March 30, 2032, and every five years thereafter, equal to the then five-year U.S. treasury bond yield plus 2.02% provided that the interest rate will not be below the initial interest rate of 6.63%. The interest rate on the second tranche will reset on March 30, 2037, and every five years thereafter, equal to the then five-year U.S. treasury bond yield plus 2.04% provided that the interest rate will not be below the initial interest rate of 6.88%. The subordinated notes receive 50% equity treatment from credit rating agencies.

      In August 2026, Caribbean Utilities issued US$60 million of 16-year, 6.24% unsecured senior notes. Proceeds will be drawn in May 2027 and will be used to repay credit facility borrowings, fund capital expenditures, and for general corporate purposes.

      In March 2026, Fortis redeemed US$115 million of its U.S. dollar-denominated unsecured senior notes with original maturities ranging from 2029 to 2044, and in August 2026, Fortis redeemed US$75 million of its U.S. dollar-denominated unsecured senior notes with an original maturity in 2040.

      For the three and nine months ended September 30, 2026 and 2025

      7. LONG-TERM DEBT (cont'd)

      In December 2024, Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts, or debt securities in an aggregate principal amount of up to $2.0 billion. Fortis re-established the at-the-market equity program ("ATM Program") pursuant to the short-form base shelf prospectus, which allows the Corporation to issue up to $500 million of common shares from treasury to the public from time to time, at the Corporation's discretion, effective until January 10, 2027. As at September 30, 2026, $237 million remained available under the ATM Program and $98 million remained available under the short-form base shelf prospectus. Fortis intends to file a new short-form base shelf prospectus, including an ATM Program in early 2027.

      As at

      Credit facilities ($ millions)	Regulated Utilities	Corporate and Other	September 30, 2026	December 31, 2025
      Total credit facilities	4,313	1,586	5,899	5,773
      Credit facilities utilized:
      Short-term borrowings (1)	(27)	-	(27)	(412)
      Long-term debt (including current portion) (2)	(654)	(207)	(861)	(1,515)
      Letters of credit outstanding	(76)	(22)	(98)	(105)
      Credit facilities unutilized	3,556	1,357	4,913	3,741

      (1) The weighted average interest rate was 4.5% (December 31, 2025 - 4.2%).

      (2) The weighted average interest rate was 3.5% (December 31, 2025 - 3.8%). The current portion was $674 million (December 31, 2025 - $707 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 $5.5 billion of the total credit facilities are committed with maturities ranging from 2027 through 2031.

      See Note 14 in the 2025 Annual Financial Statements for a description of the credit facilities as at December 31, 2025. In May 2026, the Corporation amended its $1.3 billion revolving term committed credit facility to extend the maturity to July 2031, and in October 2026, UNS Energy increased its operating credit facilities from US$375 million to US$500 million with maturities extended to October 2031.

8. COMMON SHARES

   During the third quarter of 2026, the Corporation issued approximately 3.4 million common shares under its ATM Program at an average price of $77.17 per share for gross proceeds of $263 million ($260 million net of commissions). The proceeds were used to repay credit facility borrowings and for general corporate purposes.

9. EMPLOYEE FUTURE BENEFITS

   Fortis and each subsidiary maintain one or a combination of defined benefit pension plans and defined contribution pension plans, as well as other post-employment benefit ("OPEB") plans, including health and dental coverage and life insurance benefits, for qualifying members. The net benefit cost is detailed below.

   Defined Benefit

   Pension Plans OPEB Plans

   ($ millions)	2026	2025	2026	2025
   Quarter ended September 30
   Service costs	18	17	5	6
   Interest costs	44	42	7	8
   Expected return on plan assets	(58)	(53)	(8)	(7)
   Amortization of actuarial gains	(7)	(4)	(6)	(6)
   Amortization of past service credits/plan amendments	1	(1)	-	(1)
   Regulatory adjustments	-	-	-	2
   Net benefit cost	(2)	1	(2)	2
   Year-to-date September 30
   Service costs	54	53	16	17
   Interest costs	132	128	22	23
   Expected return on plan assets	(172)	(160)	(23)	(21)
   Amortization of actuarial gains	(20)	(12)	(19)	(18)
   Amortization of past service credits/plan amendments	4	(1)	-	(1)
   Regulatory adjustments	(1)	(1)	-	6
   Net benefit cost	(3)	7	(4)	6

   Defined contribution pension plan expense for the three and nine months ended September 30, 2026 was $16 million and $53 million (three and nine months ended September 30, 2025 - $15 million and $50 million, respectively).

   For the three and nine months ended September 30, 2026 and 2025

10. OTHER INCOME, NET

    Quarter Year-to-Date

    ($ millions)	2026	2025	2026	2025
    Periods ended September 30
    Equity component, allowance for funds used during construction	53	42	148	123
    Non-service component of net periodic benefit cost	19	19	70	58
    Interest income	16	9	46	31
    Equity income	5	3	14	10
    (Loss) gain on derivatives, net	(10)	7	(4)	39
    Other	12	(2)	31	13
    	95	78	305	274

11. DISPOSITIONS

    In September 2025, Fortis sold FortisTCI which contributed net earnings of $7 million in the third quarter of 2025 and $19 million for the eight-month period through the September 2, 2025 disposition date.

    In October 2025, Fortis sold Fortis Belize and its 33% ownership in Belize Electricity which combined to contribute net earnings of $8 million and

    $16 million for the three and nine months ended September 30, 2025, respectively, and $17 million for the ten-month period through the October 31, 2025 disposition date.

12. EARNINGS PER COMMON SHARE

    	2026			2025
    	Net Earnings to Common Shareholders ($ millions)	Weighted Average Shares (# millions)	EPS ($)	Net Earnings to Common Shareholders ($ millions)	Weighted Average Shares (# millions)	EPS ($)
    Quarter ended September 30
    Basic EPS	474	513.1	0.92	409	504.5	0.81
    Potential dilutive effect of stock-based compensation	-	0.2		-	0.3
    Diluted EPS	474	513.3	0.92	409	504.8	0.81
    Year-to-date September 30
    Basic EPS	1,371	510.4	2.69	1,292	502.5	2.57
    Potential dilutive effect of stock-based compensation	-	0.2		-	0.3
    Diluted EPS	1,371	510.6	2.69	1,292	502.8	2.57

13. SUPPLEMENTARY CASH FLOW INFORMATION