HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the three and six months ended June 30, 2026 and 2025


The following Management’s Discussion and Analysis (MD&A) of the financial condition and results of operations should be read together with the unaudited condensed interim consolidated financial statements and accompanying notes thereto (Consolidated Financial Statements) of Hydro One Inc. (Hydro One or the Company) for the three and six months ended June 30, 2026, as well as the Company’s audited consolidated financial statements and MD&A for the year ended December 31, 2025. The Consolidated Financial Statements have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP). All financial information in this MD&A is presented in Canadian dollars, unless otherwise indicated.
The Company has prepared this MD&A in accordance with National Instrument 51-102 - Continuous Disclosure Obligations of the Canadian Securities Administrators. Under the U.S./ Canada Multijurisdictional Disclosure System, the Company is permitted to prepare this MD&A in accordance with the disclosure requirements of Canadian securities laws and regulations, which can vary from those of the U.S. This MD&A provides information as at and for the three and six months ended June 30, 2026, based on information available to management as of August 11, 2026.
Included in this MD&A are certain specified financial measures and financial ratios that are not recognized by U.S. GAAP but that are used by management to evaluate the performance of the Company and its businesses. Since these specified financial measures and financial ratios may not have a standardized meaning within U.S. GAAP, results may not be comparable to similar financial measures and financial ratios presented by other entities. These measures and ratios should not be considered in isolation nor as a substitute for analysis of the Company’s financial information reported under U.S. GAAP. See "Non-GAAP Financial Measures" for a discussion of these non-GAAP financial measures and a reconciliation of such measures to the most directly comparable U.S. GAAP measure.
CONSOLIDATED FINANCIAL HIGHLIGHTS AND STATISTICS
Three months ended June 30Six months ended June 30
(millions of dollars, except as otherwise noted)
20262025Change20262025Change
Revenues2,2872,05611.2%4,9214,45310.5%
Purchased power1,07189919.1%2,4952,11917.7%
Revenues, net of purchased power1
1,2161,1575.1%2,4262,3343.9%
Operation, maintenance and administration (OM&A) costs3173073.3%6346271.1%
Depreciation, amortization and asset removal costs277285(2.8%)5475460.2%
Financing charges1801659.1%3553278.6%
Income tax expense 69647.8%111133(16.5%)
Net income attributable to the common shareholder of Hydro One37233411.4%7656969.9%
Basic and diluted earnings per common share (EPS)$2,615$2,34811.4%$5,378$4,8939.9%
Net cash from operating activities67261110.0%1,0601,114(4.8%)
Funds from operations (FFO)1
69762012.4%1,4001,2997.8%
Annualized FFO to Net Debt1
14.4%13.9%0.5%14.4%13.9%0.5%
Capital investments808910(11.2%)1,5211,641(7.3%)
Assets placed in-service6415869.4%1,1211,00311.8%
Transmission: Average monthly Ontario 60-minute peak demand (MW)
20,93620,8360.5%21,14121,0080.6%
Distribution: Electricity distributed to Hydro One customers (GWh)
7,5507,2314.4%17,23516,5554.1%

As at		June 30,
2026		December 31,
2025
Net Debt to capitalization ratio1
58.8 %58.4 %
1     See section “Non-GAAP Financial Measures”.
OVERVIEW
The Company's transmission business consists of the electricity transmission system operated by its subsidiaries, which include Hydro One Networks Inc. (Hydro One Networks), Hydro One Sault Ste. Marie LP (HOSSM), an approximate 66% interest in B2M Limited Partnership (B2M LP), an approximate 55% interest in Niagara Reinforcement Limited Partnership (NRLP), and an approximate 50% interest in Chatham x Lakeshore Limited Partnership (CLLP). The Transmission segment also includes Hydro One Networks’ approximate 40% (2025 - 48%) minority interest in the East-West Tie Limited Partnership (EWT LP) (see section “Other Developments - EWT LP”).
Hydro One’s distribution business consists of the electricity distribution system operated by its subsidiaries, Hydro One Networks and Hydro One Remote Communities Inc. (Hydro One Remotes).
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
The other segment consists of certain corporate activities and is not rate-regulated.
For the six months ended June 30, 2026 and 2025, Hydro One's segments accounted for the Company's total revenues, as follows:
Six months ended June 3020262025
Transmission27 %28 %
Distribution73 %72 %
When adjusted for the recovery of purchased power costs, Hydro One’s segments accounted for the Company’s total revenues, net of purchased power,1 for the six months ended June 30, 2026 and 2025 as follows:
Six months ended June 3020262025
Transmission55 %54 %
Distribution45 %46 %
As at June 30, 2026 and December 31, 2025, Hydro One’s segments accounted for the Company’s total assets as follows:
As atJune 30,
2026		December 31,
2025
Transmission60 %60 %
Distribution38 %38 %
Other2 %2 %
RESULTS OF OPERATIONS
Net Income
Net income attributable to the common shareholder for the quarter ended June 30, 2026 of $372 million is an increase of $38 million, or 11.4%, compared to the same period in 2025. Significant influences on the change in net income attributable to the common shareholder include:
•higher revenues, net of purchased power,1 primarily resulting from an increase in transmission and distribution revenues due to Ontario Energy Board (OEB)-approved 2026 rates, and higher average monthly peak demand.
•higher OM&A as a result of higher work program expenditures, including emergency power restoration and lines maintenance work.
•lower depreciation, amortization and asset removal costs primarily due to lower asset removal costs resulting from lower volume of storm restoration activities, partially offset by higher depreciation due to growth in capital assets.
•higher financing charges primarily due to an increase in outstanding long-term debt, partially offset by higher capitalized interest.
•higher income tax expense primarily resulting from higher pre-tax earnings, partially offset by higher deductible timing differences.
Net income attributable to the common shareholder for the six months ended June 30, 2026 of $765 million is $69 million, or 9.9%, higher than the same period in 2025. Year-to-date results were impacted by similar factors as noted above, with the following exceptions:
•Depreciation, amortization and asset removal costs on a year-to-date basis were in-line with prior year; and
•Income tax expense on a year-to-date basis was lower than the prior year, primarily resulting from higher deductible timing differences than the prior year, partially offset by higher pre-tax earnings. Income tax expense on a year-to-date basis was higher than the prior year when adjusted for additional tax deductions from the re-introduction of accelerated capital cost allowance, that are offset by a corresponding reduction in revenue, and therefore net income neutral.
1 See section “Non-GAAP Financial Measures”.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Revenues
Three months ended June 30Six months ended June 30
(millions of dollars, except as otherwise noted)
20262025Change20262025Change
Transmission668 622 7.4%1,332 1,258 5.9%
Distribution1,619 1,434 12.9%3,589 3,195 12.3%
Total revenues2,287 2,056 11.2%4,921 4,453 10.5%
Transmission668 622 7.4%1,332 1,258 5.9%
Distribution revenues, net of purchased power1
548 535 2.4%1,094 1,076 1.7%
Total revenues, net of purchased power1
1,216 1,157 5.1%2,426 2,334 3.9%
Transmission: Average monthly Ontario 60-minute peak demand (MW)
20,936 20,836 0.5%21,141 21,008 0.6%
Distribution: Electricity distributed to Hydro One customers (GWh)
7,550 7,231 4.4%17,235 16,555 4.1%
1 See section “Non-GAAP Financial Measures”.
Transmission Revenues
Transmission revenues increased by 7.4% compared to the quarter ended June 30, 2025, primarily due to:
•higher revenues resulting from OEB-approved 2026 rates; and
•higher average monthly peak demand; partially offset by
•net income neutral items, mainly attributable to lower revenues associated with a regulatory tax adjustment related to re-introduction of accelerated capital cost allowance, which is offset in income tax expense.
Transmission revenues increased by 5.9% compared to the six months ended June 30, 2025, primarily due to similar factors noted above.
Distribution Revenues
Distribution revenues increased by 12.9% compared to the quarter ended June 30, 2025, primarily due to:
•higher purchased power costs, which are fully recovered from ratepayers and thus net income neutral;
•higher revenues resulting from OEB-approved 2026 rates; and
•higher energy consumption; partially offset by
•net income neutral items, mainly related to lower revenue from the recovery of 2025 storm-related costs incurred on behalf of third parties, and the OEB-approved recovery of regulatory assets in the prior period, which are offset in OM&A.
Distribution revenues increased by 12.3% compared to the six months ended June 30, 2025, primarily due to similar factors as noted above, as well as lower revenues associated with a regulatory tax adjustment related to re-introduction of accelerated capital cost allowance, which is offset in income tax expense and therefore net income neutral.
Distribution revenues, net of purchased power,2 increased by 2.4% and 1.7% compared to the three and six months ended June 30, 2025, respectively, primarily due to the reasons noted above.
OM&A Costs
Three months ended June 30Six months ended June 30
(millions of dollars, except as otherwise noted)
20262025Change20262025Change
Transmission140 134 4.5%277 267 3.7%
Distribution170 164 3.7%343 346 (0.9%)
Other7 9 (22.2%)14 14 —%
317 307 3.3%634 627 1.1%
Transmission OM&A Costs
Transmission OM&A costs were 4.5% higher than the quarter ended June 30, 2025, primarily due to:
•higher corporate support costs; and
•higher spend on vegetation management; partially offset by
•a one-time reduction to the property tax provision.
Transmission OM&A costs were 3.7% higher than the six months ended June 30, 2025, primarily due to similar factors to those noted above.
2 See section “Non-GAAP Financial Measures”.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Distribution OM&A Costs
Distribution OM&A costs were 3.7% higher than the quarter ended June 30, 2025, primarily due to:
•higher work program expenditures, including emergency power restoration and lines maintenance work; and
•higher corporate support costs; partially offset by
•net income neutral items including costs related to a storm in the prior year that were recovered from third parties and OM&A associated with the OEB-approved recovery of cost deferrals in the prior year, both of which are offset in revenue.
Distribution OM&A costs were 0.9% lower than the six months ended June 30, 2025, primarily due to:
•net income neutral items including OM&A associated with the OEB-approved recovery of cost deferrals in the prior year, and costs related to a storm in the prior year that were recovered from third parties, both of which were offset in revenue; partially offset by
•higher work program expenditures, including emergency power restoration and lines maintenance work; and
•higher corporate support costs.
Depreciation, Amortization and Asset Removal Costs
Depreciation, amortization and asset removal costs decreased by $8 million for the three months ended June 30, 2026, compared to the same period in 2025, primarily due to lower asset removal costs resulting from lower volume of storm restoration activities compared to the prior year, partially offset by higher depreciation expense attributed to the growth in capital assets as the Company continues to place new assets in-service.
Depreciation, amortization and asset removal costs of $547 million for the six months ended June 30, 2026, were in-line with the prior year.
Financing Charges
Financing charges increased by $15 million and $28 million for the three and six months ended June 30, 2026, respectively, primarily due to an increase in outstanding long-term debt, partially offset by higher capitalized interest.
Income Tax Expense
Income tax expense of $69 million for the three months ended June 30, 2026, compares to $64 million for the same period in 2025. The $5 million year-over-year increase was primarily due to:
•higher pre-tax earnings; partially offset by
•higher deductible timing differences than the prior year, including additional tax deductions from the re-introduction of accelerated capital cost allowance, that are offset by a corresponding reduction in revenue, and therefore net income neutral.
Income tax expense of $111 million for the six months ended June 30, 2026, compares to $133 million for the same period in 2025. The $22 million year-over-year decrease was primarily due to:
•higher deductible timing differences than the prior year, including additional tax deductions from the re-introduction of accelerated capital cost allowance, that are offset by a corresponding reduction in revenue, and therefore net income neutral; partially offset by
•higher pre-tax earnings.
The Company realized an effective tax rate (ETR) of approximately 15.5% and 12.6% for the three and six months ended June 30, 2026, respectively, compared to approximately 16.0% and 15.9% in the same periods of 2025. The decrease of 0.5% and 3.3% in the respective periods was primarily attributable to the factors discussed above.
SHARE CAPITAL
Hydro One is authorized to issue an unlimited number of common shares. The amount and timing of any dividends payable by Hydro One is at the discretion of Hydro One's Board of Directors (Board) and is established on the basis of Hydro One’s results of operations, maintenance of its deemed regulatory capital structure, the Company’s financial condition and forecast cash requirements, the satisfaction of solvency tests imposed by corporate laws for the declaration and payment of dividends, and other factors that the Board may consider relevant. As at August 11, 2026, Hydro One had 142,239 issued and outstanding common shares.
The Company is authorized to issue an unlimited number of preferred shares, issuable in series. As at August 11, 2026, the Company had no preferred shares issued and outstanding.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
QUARTERLY RESULTS OF OPERATIONS
Quarter ended (millions of dollars, except EPS and ratio)
Jun 30, 2026Mar 31, 2026Dec 31, 2025Sep 30, 2025Jun 30, 2025Mar 31, 2025Dec 31, 2024Sep 30, 2024
Revenues2,287 2,634 2,254 2,286 2,056 2,397 2,089 2,181 
Purchased power1,071 1,424 1,287 1,080 899 1,220 1,060 1,047 
Revenues, net of purchased power1
1,216 1,210 967 1,206 1,157 1,177 1,029 1,134 
Net income attributable to the common shareholder372 393 234 424 334 362 207 374 
Basic and diluted EPS$2,615 $2,763 $1,645 $2,981 $2,348 $2,545 $1,455 $2,629 
Earnings coverage ratio1
2.8 2.8 2.9 2.9 2.9 2.9 2.8 2.8 
1    See section “Non-GAAP Financial Measures”.

Variations in revenues and net income attributable to the common shareholder over the quarters are primarily due to the impact of seasonal weather conditions on customer demand and market pricing, as well as timing of regulatory decisions.
CAPITAL INVESTMENTS
Capital investments represent additions to property, plant and equipment and intangible assets, including capitalized interest and overhead costs incurred during construction. Assets placed in-service represent completed capital assets that have been transferred into service and are available for their intended use during the period, and as applicable, included in the Company’s rate-regulated asset base. The Company makes capital investments to maintain the safety, reliability and integrity of its transmission and distribution system assets and to provide for the ongoing growth and modernization required to meet the expanding and evolving needs of its customers and the electricity market. This is achieved through a combination of sustaining capital investments, which are required to support the continued operation of Hydro One’s existing assets, and development capital investments, which involve additions to both existing assets and large-scale projects such as new transmission lines and transmission stations.
Assets Placed In-Service
The following table presents Hydro One’s assets placed in-service during the three and six months ended June 30, 2026 and 2025:
Three months ended June 30Six months ended June 30
(millions of dollars)
20262025Change20262025Change
Transmission364 147 147.6%624 334 86.8%
Distribution277 439 (36.9%)497 669 (25.7%)
Total assets placed in-service641 586 9.4%1,121 1,003 11.8%
Transmission Assets Placed In-Service
Transmission assets placed in-service increased by $217 million, or 147.6%, for the quarter ended June 30, 2026, compared to the same period in 2025, primarily due to:
•timing of assets placed in-service for station refurbishments and replacements; partially offset by
•investments placed in-service for the Orillia Distribution Warehouse in the prior year.
Transmission assets placed in-service increased by $290 million, or 86.8%, for the six months ended June 30, 2026, compared to the same period in 2025, primarily due to similar factors noted above as well as investments placed in-service for high-voltage underground cable replacements; partially offset by the in-service of a customer connection project at the South Middle Road Transmission Station in the prior year.
Distribution Assets Placed In-Service
Distribution assets placed in-service decreased by $162 million, or 36.9%, for the quarter ended June 30, 2026, compared to the same period in 2025, primarily due to:
•lower volume of storm-related asset replacements;
•investments placed in-service for the Orillia Distribution Warehouse in the prior year; and
•timing of investments placed in-service for system capability reinforcement projects; partially offset by
•investments placed in-service for Ontario’s broadband initiative; and
•assets placed in-service for the Advanced Metering Infrastructure (AMI) 2.0 system.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Distribution assets placed in-service decreased by $172 million, or 25.7%, for the six months ended June 30, 2026, compared to the same period in 2025, primarily due to similar factors noted above, as well as investments placed in-service for the Orillia Operation Centre in the prior year and, lower volume of wood pole replacements.
Capital Investments
The following table presents Hydro One’s capital investments during the three and six months ended June 30, 2026 and 2025:
Three months ended June 30Six months ended June 30
(millions of dollars)
20262025Change20262025Change
Transmission
    Sustaining224 277 (19.1%)443 549 (19.3%)
    Development241 192 25.5%404 370 9.2%
    Other(18)21 (185.7%)31 30 3.3%
447 490 (8.8%)878 949 (7.5%)
Distribution
    Sustaining188 297 (36.7%)307 440 (30.2%)
    Development160 101 58.4%286 196 45.9%
    Other13 22 (40.9%)50 56 (10.7%)
361 420 (14.0%)643 692 (7.1%)
Total capital investments808 910 (11.2%)1,521 1,641 (7.3%)
Transmission Capital Investments
Transmission capital investments decreased by $43 million, or 8.8%, in the second quarter of 2026 compared to the second quarter of 2025, primarily due to:
•lower volume of station refurbishments and equipment replacements; and
•investments in the Waasigan Transmission Line, the St. Clair Transmission Line, and the Northeast Power Line Projects; partially offset by
•higher spend on other major development projects.
Transmission capital investments decreased by $71 million, or 7.5%, in the six months ended June 30, 2026, compared to the same period in 2025, primarily due to similar factors noted above.
Distribution Capital Investments
Distribution capital investments decreased by $59 million, or 14.0%, in the second quarter of 2026 compared to the second quarter of 2025, primarily due to:
•lower spend on storm-related asset replacements; partially offset by
•investments in Ontario’s broadband initiative; and
•investments in the AMI 2.0 system.
Distribution capital investments decreased by $49 million, or 7.1%, in the six months ended June 30, 2026, compared to the same period in 2025, primarily due to similar factors noted above as well as lower volume of wood pole replacements.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Major Transmission Capital Investment Projects
The following tables summarize the status of significant transmission projects as at June 30, 2026:
Development Projects

Project Name
Location
Type		Anticipated
In-Service Date
Estimated
Cost1
Capital Cost
To Date
(year)               (millions of dollars)
   Waasigan Transmission Line2
Thunder Bay-Atikokan-Dryden
  Northwestern Ontario		New transmission line and
  station expansion		20271,140661
   St. Clair Transmission LineSouthwestern OntarioNew transmission line and
  station expansion		2027435288
   Centennial Transmission Station3
Southwestern OntarioNew transmission station and
  connection; and new transmission line
2027
403244
   Holt Transmission StationBowmanville Central OntarioNew transmission station and
  connection		202713747
   Keith Intertie UpgradeWindsor
   Southwestern Ontario		Transmission station upgrade202810911
   Northeast Power LineNortheastern OntarioNew transmission line and
  station expansion		20291,85544
   Durham Kawartha Power LineEastern OntarioNew transmission line and
  station expansion		202943345
   Welland Thorold Power LineNiagara
   Southern Ontario		New transmission line and
  station expansion		202931134
   Orléans Area Reinforcement
Ottawa
   Eastern Ontario		Transmission line upgrade202910111
   Longwood to Lakeshore
Transmission Line
Southwestern OntarioNew transmission line and
  station expansion		20301,16675
   North Shore Link4
Northeastern OntarioNew transmission line and
  station expansion		TBDTBD31
   Wawa Timmins Power Line4
Northeastern OntarioNew transmission line and
  station expansion		TBDTBD16
   Windsor Lakeshore
     Transmission Line5
Southwestern OntarioNew transmission line and
  station expansion		TBDTBD6
   Sudbury Barrie
    Transmission Line6
Northern-Central OntarioNew transmission line and
  station expansion		TBDTBD5 
   Second Longwood to Lakeshore
Transmission Line5
Southwestern OntarioNew transmission line and
  station expansion		TBDTBD3
   Bowmanville to East Greater
   Toronto Area Power Line7
Southern OntarioNew transmission line and
  station expansion		TBDTBD2 
   Greenstone Transmission LineNorthwestern OntarioNew transmission line and
  station expansion		TBDTBD2 
   Waterloo Wellington Power Line8
Southwestern OntarioNew transmission line and new transmission stationTBDTBD1 
    Red Lake Transmission Line9
Northwestern OntarioNew transmission line and station expansionTBDTBD1 
1 Estimated costs are presented gross of any potential contribution from external parties.
2 The Waasigan Transmission Line Project includes construction of new transmission lines as well as station enhancements to support energization of the new lines. The estimated cost relates to the development and construction phases of the project and the anticipated in-service date reflects anticipated completion in 2027. The first phase of the project is anticipated to be in-serviced in 2026.
3 This Project consists of two phases, which includes the construction of a transmission station and a transmission line to meet the needs of, and is anticipated to be largely funded by, an industrial customer. Phase 1 of the Centennial Transmission Station Project includes a new transmission station in St. Thomas and an approximately 2 km, 230 kV double-circuit transmission line between the new transmission station and an existing transmission station in the city. Phase 1 of the project is anticipated to be in service by the end of 2026. The second phase, an approximately 20 km, 230 kV double-circuit transmission line from London to St. Thomas, is anticipated to be in service by the end of 2027.
4 The capital cost to date relates to costs incurred in the development phase of the project. The scope and timing of these Northeastern transmission reinforcements are currently under review. The Independent Electricity System Operator (IESO) has recommended a target in-service date of 2030 for the Wawa Timmins Power Line, and of 2029 for the North Shore Link transmission project.
5 The capital cost to date relates to costs incurred in the development phase of the projects. The scope and timing of these Southwestern Ontario transmission reinforcement projects are currently under review. The IESO has recommended a target in-service date by 2032 for the Windsor Lakeshore Transmission Line.
6 Pertains to the First Sudbury Barrie Transmission Line. The scope and timing of the line is currently under review. The IESO has recommended a target in-service date by 2032.
7 The Bowmanville to East Greater Toronto Area Power Line was previously referred to as the Bowmanville to Parkway Transmission Line.
8 The IESO has recommended a target in-service date of 2031 for the Waterloo Wellington Power Line and the Wellington Transmission Station in the Township of Puslinch. The Waterloo Wellington Power Line was previously referred to as the Wellington to Preston Transmission Line.
9 The project comprises a double-circuit 230 kV transmission line that runs from Dryden Transformer Station to Ear Falls, continuing to Red Lake Switching Station, with associated station work at Dryden Transformer Station and Ear Falls Transformer Station.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Sustainment Projects
Project NameLocationTypeAnticipated
In-Service Date
Estimated
Cost1
Capital Cost
To Date
(year)(millions of dollars)
   Middleport Transmission Station
     Circuit Breaker Replacement2
Middleport
  Southwestern Ontario		Station sustainment2026184173
   Lennox Transmission Station
     Circuit Breaker Replacement2
Napanee
  Southeastern Ontario		Station sustainment2026160155
   Esplanade x Terauley
     Underground Cable Replacement		Toronto
  Southern Ontario		Line sustainment2026117103
   Bridgman Transmission Station
     Refurbishment		Toronto
  Southern Ontario		Station sustainment202610896
   Bruce A Transmission Station
     Switchyard Replacement		Tiverton
  Southwestern Ontario		Station sustainment2027555447
   Otto Holden Transmission Station
     Refurbishment		Mattawa
  Northeast Ontario		Station sustainment202812891
   Merivale Transmission Station
     Replacement and Upgrades3
Ottawa
  Eastern Ontario		Station sustainment and
  upgrade		2029271216
   Synchronous Optical Network
     Telecommunication Replacement		OntarioTelecommunication sustainment202913721
    Essa Transmission Station Circuit
      Breaker Replacement		Barrie
  Central Ontario		Station sustainment203011619
1 Estimated costs are presented gross of any potential contribution from external parties.
2 The Middleport Transmission Station Circuit Breaker Replacement and the Lennox Transmission Station Circuit Breaker Replacement Projects were completed in Q2 2026.
3 The coordinated project includes both an asset replacement and station expansion. The anticipated in-service dates are between 2026 to 2029.
























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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Future Capital Investments
The Company estimates future capital investments based on management’s expectations of the amount of capital expenditures that will be required to provide transmission and distribution services that are efficient, reliable, and provide value for customers, consistent with the OEB’s Renewed Regulatory Framework. The Company includes projects when there is a high degree of confidence that the project will go forward and when there is a thorough estimate of the expected expenditures.
On August 28, 2025, the Company submitted a Z-Factor application which sought recovery of the incremental revenue requirement associated with $223 million of storm-related costs, including capital and asset removal costs, incurred for a severe storm that began on March 28, 2025. On April 7, 2026, the OEB issued its Decision and Order for the Z-Factor application, denying the recovery of $69 million in incremental revenue requirement.
The 2026 and 2027 capital estimates have been updated during the three months ended June 30, 2026 to reflect the estimated costs of the Northeast Power Line and the Longwood to Lakeshore Transmission Line projects filed with the OEB on May 19, 2026 through leave-to-construct applications, as well as the Durham Kawartha Power Line project filed with the OEB on June 12, 2026 through a leave-to-construct application (see section “Other Developments” for further details).
The Company had updated its plan in the first quarter, for required Broadband investments, consistent with the detailed construction schedule submitted to the Province.
The following tables summarize Hydro One’s annual projected capital investments for 2026 and 2027 by business segment and by category:
By business segment: (millions of dollars)
20262027
Transmission1
2,432 3,333 
Distribution1,383 1,377 
Total capital investments2
3,815 4,710 
By category: (millions of dollars)
20262027
Sustainment1,426 1,064 
Development1
2,244 3,514 
Other3
145 132 
Total capital investments2
3,815 4,710 
1 Figures include investments in certain development projects of Hydro One Networks not included in the investment plan approved by the OEB in the Joint Rate Application (JRAP) decision in 2022.
2 Since the first quarter of 2022, the Minister of Energy and Mines (formerly the Minister of Energy) (Minister) has directed the OEB to amend Hydro One Networks’ transmission licence to require it to develop and seek approvals for twelve priority transmission lines in Ontario. The future capital investments presented do not include capital expenditures, nor development costs, associated with the following two priority Southwestern Ontario transmission line projects: Second Longwood to Lakeshore Transmission Line and Windsor Lakeshore Transmission Line; nor the following two priority Northeastern and Eastern Ontario transmission line projects: North Shore Link and Wawa Timmins Power Line; nor the Bowmanville to East Greater Toronto Area Power Line, Greenstone, Sudbury Barrie, and the Red Lake Transmission Lines. Hydro One is currently evaluating the scope and timing of these eight lines.
3 “Other” capital expenditures include investments in fleet, real estate, IT, and operations technology and related functions.
SUMMARY OF SOURCES AND USES OF CASH
Hydro One’s primary sources of cash flows are funds generated from operations, capital market debt issuances and bank credit facilities that are used to satisfy Hydro One’s capital resource requirements, including the Company’s capital expenditures, servicing and repayment of debt, and dividend payments.
Three months ended June 30Six months ended June 30
(millions of dollars)
2026202520262025
Net cash from operating activities672 611 1,060 1,114 
Net cash from financing activities 649 163 471 31 
Net cash used in investing activities(724)(833)(1,450)(1,787)
Net change in cash and cash equivalents 597 (59)81 (642)
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Net cash from operating activities
Net cash from operating activities increased by $61 million for the three months ended June 30, 2026, compared to the same period in 2025. The increase was mainly attributable to:
•higher pre-tax earnings; and
•changes in regulatory account balances; partially offset by
•changes in net working capital primarily attributable to timing differences in the settlement of receivables and payables, and lower cost of power payable to the IESO driven by lower purchased volumes, partially offset by higher accrued liabilities, and higher unearned revenue related to capital contributions.
Net cash from operating activities decreased by $54 million for the six months ended June 30, 2026, compared to the same period in 2025. The decrease was mainly attributable to:
•changes in net working capital primarily attributable to lower accrued liabilities, lower cost of power payable to the IESO driven by lower purchased volumes, and timing differences in the settlement of payables, partially offset by timing differences in the settlement of receivables, and higher unearned revenue related to capital contributions; and
•changes in regulatory account balances; partially offset by
•higher pre-tax earnings.
Net cash from financing activities
Net cash from financing activities increased by $486 million and $440 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025. This was impacted by various factors, including the following:
Sources of cash
•the Company issued $1,373 million of long-term debt in the three and six months ended June 30, 2026, compared to $nil issued in the same periods last year.
•the Company received proceeds of $925 million and $1,725 million from the issuance of short-term notes in the three and six month periods ended June 30, 2026, respectively, compared to $2,065 million and $3,140 million received in the same periods last year.
Uses of cash
•the Company repaid $1,425 million and $1,725 million of short-term notes in the three and six month periods ended June 30, 2026, respectively, compared to $1,350 million and $1,965 million repaid in the same periods last year.
•the Company repaid $nil and $500 million of long-term debt in the three and six month periods ended June 30, 2026, respectively, compared to $350 million and $750 million paid in the same periods last year.
•common share dividends paid in the three and six month periods ended June 30, 2026 were $211 million and $410 million, respectively, compared to dividends of $207 million and $394 million paid in the same periods last year.
Net cash used in investing activities
Net cash used in investing activities decreased by $109 million and $337 million for the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025. The decrease in the second quarter was primarily due to lower capital expenditures, partially offset by higher additions to future use assets. The year-to-date decrease was primarily due to similar factors noted above as well as the investment in EWT LP (see section “Other Developments - EWT LP”) in the prior year.
LIQUIDITY AND FINANCING STRATEGY
Short-term liquidity is provided through FFO,3 Hydro One’s commercial paper program, and the Company’s consolidated bank credit facilities. Under the commercial paper program, Hydro One is authorized to issue up to $2,300 million in short-term notes with a term to maturity of up to 365 days.
As at June 30, 2026, Hydro One had $100 million in commercial paper borrowings outstanding, compared to $100 million outstanding at December 31, 2025. The Company also has committed, unsecured, and revolving credit facilities (Operating Credit Facilities) with a total available balance of $3,650 million as at June 30, 2026. The Operating Credit Facilities include a pricing adjustment which can increase or decrease Hydro One’s cost of borrowing based on its performance on certain sustainability performance measures, which are related to Hydro One's sustainability goals. On June 1, 2026, Hydro One increased the committed amount under the Operating Credit Facilities by $600 million and extended the maturity date of the Operating Credit Facilities from 2030 to 2031. No amounts were drawn on the Operating Credit Facilities as at June 30, 2026 or December 31, 2025. The Company may use the Operating Credit Facilities for working capital and general corporate purposes. The short-term liquidity under the commercial paper program, the Operating Credit Facilities, available cash on hand and anticipated levels of FFO3 are expected to be sufficient to fund the Company’s operating requirements.
3 See section “Non-GAAP Financial Measures”.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
As at June 30, 2026, the Company had long-term debt outstanding in the principal amount of $19,540 million. The majority of long-term debt issued by Hydro One has been issued under its Medium-Term Note (MTN) Program. The Company's total long-term debt consists of notes and debentures that mature between 2026 and 2064, and as at June 30, 2026, had a weighted-average term to maturity of approximately 13.2 years (December 31, 2025 - 13.9 years) and a weighted-average coupon rate of 4.3% (December 31, 2025 - 4.3%).
In March 2026, Hydro One filed a short form base shelf prospectus in connection with its MTN Program, which expires in April 2029.
On August 18, 2025, Hydro One filed a short form base shelf prospectus (HOI U.S. Debt Shelf Prospectus) with securities regulatory authorities in Ontario and the U.S. The HOI U.S. Debt Shelf Prospectus allows Hydro One to offer, from time to time in one or more public offerings, U.S. debt securities, during the 25-month period ending on September 18, 2027. As at June 30, 2026, US$1,000 million senior notes have been issued under the HOI U.S. Debt Shelf Prospectus (2025 - US$nil). To mitigate the foreign currency risk due to exchange rate fluctuations between the U.S. dollar and the Canadian dollar, the Company entered into a series of cross-currency swap agreements, to convert U.S. dollar-denominated principal and interest cash flows into fixed Canadian dollar-denominated cash flows.
Compliance
As at June 30, 2026, the Company was in compliance with all financial covenants and limitations associated with the outstanding borrowings and credit facilities.
OTHER OBLIGATIONS
Off-Balance Sheet Arrangements
There are no off-balance sheet arrangements that have, or are reasonably likely to have, a material current or future effect on the Company’s financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Summary of Contractual Obligations and Other Commercial Commitments
The following table presents a summary of Hydro One’s debt and other major contractual obligations and commercial commitments:

As at June 30, 2026 (millions of dollars)

Total
Less than
1 year

   1-3 years
   
3-5 years
More than
5 years
Contractual obligations (due by year)
Long-term debt - principal repayments19,540 425 1,300 3,170 14,645 
Long-term debt - interest payments11,298 826 1,607 1,466 7,399 
Short-term notes payable100 100 — — — 
Pension contributions1
559 75 160 179 145 
Outsourcing and other agreements111 51 44 — 16 
Environmental and asset retirement obligations101 12 5 4 80 
Lease obligations74 14 21 10 29 
Total contractual obligations31,783 1,503 3,137 4,829 22,314 
Other commercial commitments (by year of expiry)
Operating Credit Facilities3,650 — — 3,650 — 
Letters of credit2
175 175 — — — 
Guarantees3
475 475 — — — 
Total other commercial commitments4,300 650 — 3,650 — 
1 Contributions to the Hydro One Pension Plan are based on actuarial reports, including valuations performed at least every three years, and actual or projected levels of pensionable earnings, as applicable. The most recent actuarial valuation was performed effective December 31, 2024 and filed on September 23, 2025.
2 Letters of credit consist of $166 million letters of credit related to retirement compensation arrangements, a $2 million letter of credit provided to the IESO for prudential support, and $7 million in letters of credit for various operating purposes.
3 Guarantees consist of $475 million prudential support provided to the IESO by Hydro One on behalf of its subsidiaries.
REGULATION
Ontario Integrated Energy Plan
On June 12, 2025, the Ontario government released its first integrated energy plan (IEP), Energy for Generations, which aims to leverage electricity, natural gas, hydrogen, storage and other energy sources to provide Ontario with affordable, secure, reliable and clean energy to power growth and jobs across the province. The IEP establishes a planning horizon out to 2050, including the acceleration of the development of transmission infrastructure and the modernization of the distribution grid. As part of the IEP, the government announced the advancement of several transmission projects, including those aimed to enhance
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
transmission capacity between Northern and Southern Ontario, east of Toronto, in Southwestern Ontario and in Northern Ontario.
The IEP also addressed the need for additional transmission capacity in the Red Lake Area in Northwestern Ontario. In August 2025, the IESO released the Northwest Region Integrated Regional Resource Plan Addendum (Addendum). The Addendum recommends the urgent development of the Red Lake Transmission Line, a double-circuit 230 kV transmission line that will run from Dryden Transformer Station to Ear Falls Transformer Station, and another double-circuit 230 kV transmission line that will run from Ear Falls Transformer Station to Red Lake Switching Station, along with associated station facilities, to meet growing capacity needs after 2028. The project is expected to be in service by the early 2030s. On October 29, 2025, the Ministry of Energy and Mines (Ministry) announced a proposal to bring forward an Order in Council (to be recommended by the Minister) to declare the projects as priority and a companion directive, that would, if approved, direct the OEB to amend Hydro One Networks’ transmitter licence to require it to undertake development work and seek all necessary approvals to construct the projects. The consultation period for the proposal closed on December 13, 2025.
On April 23, 2026 the Minister notified the OEB that the two lines were declared priority projects, and issued a directive to the OEB to amend Hydro One Networks’ transmission license, to require it to develop and seek approvals for the projects. On April 28, 2026, further to the Minister’s Directive, the OEB amended Hydro One Networks’ electricity transmission license to allow it to develop and seek approvals for the projects in accordance with the recommendations of the IESO.
IESO’s Transmitter Selection Framework
On July 31, 2025, the IESO announced the launch of the Transmitter Selection Framework (TSF) Registry. Registration enables transmitters to participate in future competitive IESO transmission procurements. Hydro One Limited submitted an application to be included in the TSF Registry. On May 20, 2026, Hydro One was approved as a TSF Registrant by the IESO.
Next Generation Rate Framework Consultation
On January 8, 2026, the OEB announced a new policy consultation to develop an updated rate-setting framework for electricity distributors. The consultation will bring together existing OEB consultations under a new comprehensive policy consultation known as the Next Generation Rate Framework (Framework) consultation. The OEB plans to build on the Renewed Regulatory Framework that was established in 2012, given the significant changes in the energy and policy landscape. The OEB consulted on the scope of the review in January and February 2026, including reviewing all aspects of its current ratemaking policies to ensure that they continue to facilitate the cost-effective and efficient implementation of the government's policy objectives.
Building Broadband Faster Act, 2021
A regulation regarding electricity infrastructure and designated broadband projects under the Ontario Energy Board Act, 1998 (OEBA) (O.Reg. 410/22) came into force on April 21, 2022, and on March 28, 2023, the Province amended the OEBA (O.Reg. 410/22) with respect to performance timelines associated with designated broadband projects.
On October 31, 2024, the Ministry of Infrastructure (MOI) announced that it has developed a program to deliver up to $400 million in subsidies to internet service providers (ISPs) for work associated with designated broadband projects. The program is intended to enable ISPs to successfully and safely attach their material and equipment to the Company’s poles to bring connectivity to rural communities as part of a designated broadband project. A portion of the subsidies will be used to reimburse Hydro One Networks on behalf of ISPs for their share of enablement costs incurred to facilitate the program to date (see section “Related Party Transactions”). On April 27, 2026, the Ministry increased the maximum subsidies to $482 million.
OTHER DEVELOPMENTS
EWT LP
On March 4, 2025, Hydro One Networks completed the acquisition of an approximate 48% interest in the EWT LP for approximately $261 million in cash, including closing adjustments. The partnership owns the East-West Tie Line, a 450-kilometre, 230-kV double-circuit transmission line spanning between Wawa and Thunder Bay, along the north shore of Lake Superior. In February 2026, Bamkushwada Limited Partnership, a group of First Nation Partners, exercised its right to acquire additional interest in EWT LP. Following the transaction, Hydro One’s ownership in EWT LP was diluted to 40%.
Supporting Critical Transmission Infrastructure in Southwestern Ontario
On March 31, 2022, the Minister (formerly the Minister of Energy) directed the OEB to amend Hydro One Networks' licence to require it to develop and seek approvals for four priority transmission line projects to meet growing electricity demand in Southwestern Ontario, including the Longwood to Lakeshore Transmission Line. On April 7, 2022, further to the Minister’s Directive, the OEB amended Hydro One Networks’ electricity transmission licence to require it to develop and seek approvals for the projects in accordance with the recommendations of the IESO.
On May 19, 2026, Hydro One Networks filed a leave-to-construct application seeking OEB approval for the Longwood to Lakeshore Transmission Line, a single-circuit 500 kV transmission line between the Longwood Transformer Station in the Municipality of Strathroy-Caradoc and the Lakeshore Transformer Station in the Municipality of Lakeshore.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Supporting Critical Transmission Infrastructure in Northwestern Ontario
On April 16, 2024, the OEB issued its Decision and Order granting Hydro One Networks leave to construct the Waasigan Transmission Line Project, with standard conditions of approval.
On March 20, 2026, Waasigan Transmission Limited Partnership (WTLP) was formed to own and operate the transmission line, and Waasigan Transmission GP Inc. (WTGP) was formed as the General Partner of WTLP. On July 20, 2026, Hydro One Networks, on behalf of WTGP, requested certain approvals from the OEB, including obtaining an electricity transmission licence for WTGP, as a general partner on behalf of WTLP, and approval for Hydro One Networks to sell assets related to the Waasigan Transmission Line Project to WTGP, as a general partner on behalf of WTLP.
Supporting Critical Transmission Infrastructure in Northeastern and Eastern Ontario
On July 10, 2023, the Ministry announced a proposal to take certain actions to facilitate the timely development of three priority transmission line projects across Northeastern and Eastern Ontario, including the Northeast Power Line and the Durham Kawartha Power Line. On October 23, 2023, the Minister (formerly the Minister of Energy) directed the OEB to amend Hydro One Networks’ licence to require it to develop and seek approvals for the three projects. On November 14, 2023, further to the Minister’s Directive, the OEB amended Hydro One Networks’ electricity transmission licence to require it to develop and seek approvals for the projects in accordance with the recommendations of the IESO.
On May 19, 2026, Hydro One Networks filed a leave-to-construct application seeking the OEB’s approval for the Northeast Power Line, a single-circuit 500 kV transmission line between Hanmer Transformer Station in the Greater Sudbury Area, and the Mississagi Transformer Station, near Wharncliffe. On June 12, 2026, Hydro One Networks filed a leave-to-construct application seeking the OEB’s approval for the Durham Kawartha Power Line, a new double-circuit, 230 kV transmission line between Clarington Transformer Station in the Municipality of Clarington, and Dobbin Transformer Station in Peterborough County.
Orléans Area Reinforcement Project
The IESO-led regional planning process for the Greater Ottawa Region identified growing electricity demand in the Orléans area. In 2022, the Greater Ottawa Regional Planning Technical Working Group recommended that additional electricity supply be provided to meet forecast load growth, including a new 230 kV supply from Hawthorne Transformer Station to Orléans Transformer Station. On May 29, 2026, Hydro One Networks Inc. filed a leave-to-construct application seeking the OEB’s approval for the Orléans Area Reinforcement Project consistent with the regional planning recommendations. The Project includes the construction of a new 115 kV transmission line within an existing transmission corridor between Hawthorne Transformer Station and Orléans Transformer Station, located in the Greater Ottawa Area. The project also includes converting an existing 115 kV transmission line between the two stations to a standard 230 kV transmission line. See section "Major Transmission Capital Investment Projects” for additional information.
Collective Agreements
On March 23, 2026, Hydro One and the Canadian Union of Skilled Workers (CUSW) commenced collective bargaining. The prior Hydro One - CUSW collective agreement expired on April 30, 2026. On April 24, 2026, Hydro One and CUSW reached a tentative agreement for a renewal collective agreement. On June 11, 2026, the agreement was ratified by the CUSW-represented employees for a term from May 1, 2026, to April 30, 2030.
Bill C-15, Budget 2025 Implementation Act, No.1
On March 26, 2026, Bill C‑15, An Act to implement certain provisions of the budget tabled in Parliament on November 4, 2025, received Royal Assent.
Impact
Federal budget measures enacted as part of Bill C-15 included time-limited investment incentives permitting Hydro One to claim enhanced capital cost allowance of up to three times the first-year rate for eligible capital investments acquired after 2024 and placed in-service before 2034. The re-introduction of accelerated capital cost allowance temporarily reduces the Company’s ETR and results in the recognition of a tax regulatory liability for the amounts that have not been reflected in OEB‑approved rates.
Estimated ETR Change
The re‑introduction of accelerated capital cost allowance is expected to lower the Company’s ETR to a range of approximately 11% to 15% during the current rate period (until 2027).
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
HYDRO ONE BOARD OF DIRECTORS AND EXECUTIVE OFFICERS
Board of Directors
Effective February 19, 2026, Debbie (Deb) Hutton was appointed to the Board.
Effective June 9, 2026, Perrin Beatty was elected to the Board.
Directors Helga Reidel and Mitch Panciuk did not stand for re-election at the Annual Meeting of Shareholders on June 9, 2026.
Executive Officers
Effective June 9, 2026, David Lebeter retired from his role as President and Chief Executive Officer (CEO). Effective the same day, Megan Telford was appointed as President and CEO. David Lebeter will remain with Hydro One as a Special Advisor until October 10, 2026.
NON-GAAP FINANCIAL MEASURES
Hydro One uses a number of non-GAAP financial measures to assess its performance. The Company presents FFO or “funds from operations” to reflect a measure of the Company’s cash flow; revenues, net of purchased power, to reflect the impact of revenue on net income; and net debt to reflect a measure of the Company’s financial leverage.
Hydro One also uses financial ratios that are non-GAAP ratios such as the net debt to capitalization ratio and annualized FFO to net debt ratio to reflect a measure of the Company’s financial leverage, and the earnings coverage ratio to reflect a measure of liquidity.
FFO
FFO is defined as net cash from operating activities, adjusted for changes in non-cash balances related to operations and distributions to noncontrolling interest. Management believes that FFO is helpful as a supplemental measure of the Company’s operating cash flows as it excludes timing-related fluctuations in non-cash operating working capital and cash flows not attributable to the common shareholder. As such, management believes that FFO provides a consistent measure of the cash generating performance of the Company’s assets.
The following table provides a reconciliation of reported GAAP results to non-GAAP results on a consolidated basis.
Three months ended June 30Six months ended June 30
(millions of dollars)
2026202520262025
Net cash from operating activities672 611 1,060 1,114 
Changes in non-cash balances related to operations28 11 346 192 
Distributions to noncontrolling interest(3)(2)(6)(7)
FFO697 620 1,400 1,299 
Revenues, Net of Purchased Power
Revenues, net of purchased power, is defined as revenues less the cost of purchased power; distribution revenues, net of purchased power, is defined as distribution revenues less the cost of purchased power. These measures are used internally by management to assess the impacts of revenue on net income and are considered useful because they exclude the cost of power that is fully recovered through revenues and therefore net income neutral.
The following tables provide a reconciliation of reported GAAP revenues to non-GAAP revenues, net of purchased power, on a consolidated basis.
Quarter ended (millions of dollars)
Jun 30, 2026Mar 31, 2026Dec 31, 2025Sep 30, 2025Jun 30, 2025Mar 31, 2025Dec 31, 2024Sep 30, 2024
Revenues2,287 2,634 2,254 2,286 2,056 2,397 2,089 2,181 
Less: Purchased power1,071 1,424 1,287 1,080 899 1,220 1,060 1,047 
Revenues, net of purchased power1,216 1,210 967 1,206 1,157 1,177 1,029 1,134 
Quarter ended (millions of dollars)
Jun 30, 2026Mar 31, 2026Dec 31, 2025Sep 30, 2025Jun 30, 2025Mar 31, 2025Dec 31, 2024Sep 30, 2024
Distribution revenues1,619 1,970 1,757 1,605 1,434 1,761 1,583 1,551 
Less: Purchased power1,071 1,424 1,287 1,080 899 1,220 1,060 1,047 
Distribution revenues, net of purchased power548 546 470 525 535 541 523 504 
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Net Debt
The Company uses net debt as an alternative measure of outstanding debt. Management considers net debt as an important measure in assessing the financial leverage of the Company. Net debt is used by management to assess the Company’s overall debt position and financial leverage.
The following table provides a reconciliation of net debt as reported in the Company’s Consolidated Financial Statements.
As at (millions of dollars)
Jun 30, 2026Dec 31, 2025
Short-term notes payable100 100 
Less: cash and cash equivalents(602)(521)
Long-term debt (current portion)425 925 
Long-term debt (long-term portion)19,079 17,668 
Net Debt19,002 18,172 
Net Debt to Capitalization Ratio
The Company believes that the net debt to capitalization ratio is an important non-GAAP ratio as a measure of the Company’s financial leverage. Net debt to capitalization ratio has been calculated as net debt, as described above, divided by net debt plus total shareholders’ equity, but excluding any amounts related to noncontrolling interest. Management believes that the net debt to capitalization ratio is helpful as a measure of the proportion of debt in the Company's capital structure.
As at (millions of dollars)
Jun 30, 2026Dec 31, 2025
Net debt (A)19,002 18,172 
Shareholder’s equity (excluding noncontrolling interest)13,307 12,958 
Net debt plus shareholder’s equity (B)32,309 31,130 
Net Debt to capitalization ratio (A/B)58.8 %58.4 %
Annualized FFO to Net Debt
Management believes that the annualized FFO to net debt ratio is helpful as a measure of the Company’s financial leverage. Annualized FFO to net debt ratio has been calculated as FFO (see section “Non-GAAP Financial Measures - FFO”) on a rolling twelve-month period divided by net debt at the period end date (see section “Non-GAAP Financial Measures – Net Debt”). Management believes the annualized FFO to net debt ratio is helpful as a measure of the company’s ability to pay off its debt using the Company’s net operating income.
The following table provides a reconciliation of reported GAAP results to non-GAAP results on a consolidated basis.
Twelve months and period ended (millions of dollars)
Jun 30, 2026Mar 31, 2026Dec 31, 2025Sep 30, 2025Jun 30, 2025Mar 31, 2025Dec 31, 2024Sep 30, 2024
Annualized FFO (A)2,728 2,651 2,627 2,494 2,457 2,354 2,280 2,234 
Net Debt (B)19,002 18,688 18,172 17,951 17,628 17,207 16,565 16,286 
Annualized FFO to Net Debt (A/B)14.4 %14.2 %14.5 %13.9 %13.9 %13.7 %13.8 %13.7 %
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
Earnings Coverage Ratio
Earnings coverage ratio is defined as earnings before income taxes, financing charges and equity income (loss) attributable to the shareholder, divided by the sum of financing charges and capitalized interest, and is calculated on a rolling twelve-month basis. The Company believes that the earnings coverage ratio is an important non-GAAP measure in the management of its liquidity.
Quarter ended (millions of dollars)
Jun 30, 2026Mar 31, 2026Dec 31, 2025Sep 30, 2025Jun 30, 2025Mar 31, 2025Dec 31, 2024Sep 30, 2024
Net income attributable to the common shareholder372 393 234 424 334 362 207 374 
Income tax expense69 42 29 61 64 69 19 59 
Financing charges180 175 173 171 165 162 161 154 
Equity income (loss) 3 (10)3 7 — — — — 
Earnings before income taxes, financing charges and equity income (loss) attributable to the common shareholder618 620 433 649 563 593 387 587 
Twelve months ended (millions of dollars)
Jun 30, 2026Dec 31, 2025
Earnings before income taxes, financing charges and equity income (loss) attributable to the common shareholder (A)2,320 2,238 
Quarter ended (millions of dollars)
Jun 30, 2026Mar 31, 2026Dec 31, 2025Sep 30, 2025Jun 30, 2025Mar 31, 2025Dec 31, 2024Sep 30, 2024
Financing charges180 175 173 171 165 162 161 154 
Capitalized interest 31 29 30 29 27 24 24 24 
Financing charges and capitalized interest 211 204 203 200 192 186 185 178 
Twelve months ended (millions of dollars)
Jun 30, 2026Dec 31, 2025
Financing charges and capitalized interest (B)818 781 
Earnings coverage ratio = A/B2.8 2.9 
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
RELATED PARTY TRANSACTIONS
Hydro One is owned by Hydro One Limited. The Province is a shareholder of Hydro One Limited with approximately 47.1% ownership as at June 30, 2026. The Ministry and MOI are related parties to Hydro One because they are controlled by the Province. The IESO, Ontario Power Generation Inc. (OPG), Ontario Electricity Financial Corporation (OEFC), the OEB and Acronym Solutions Inc. (Acronym) are related parties to Hydro One because they are controlled or significantly influenced by the Ministry or by Hydro One Limited. Hydro One also has transactions in the normal course of business with various government ministries and organizations in Ontario that fall under the purview of the Province. The following is a summary of the Company’s related party transactions during the three and six months ended June 30, 2026 and 2025:
(millions of dollars)
Three months ended June 30Six months ended June 30
Related PartyTransaction2026202520262025
Ministry
Broadband subsidy1, 2
17 — 27 — 
MOI
Broadband subsidy1, 2
— 6 — 19 
IESOPower purchased625 456 1,754 1,374 
Revenues for transmission services660 613 1,319 1,234 
Amounts related to electricity rebates376 233 826 508 
Distribution revenues related to rural rate protection64 64 127 127 
Distribution revenues related to Wataynikaneyap Power LP25 33 50 66 
Distribution revenues related to supply of electricity to remote northern communities13 13 26 25 
Funding received related to Conservation and Demand Management programs— — 1 — 
OPGPower purchased3 3 20 14 
Transmission revenues related to provision of services and supply of electricity1 — 1 1 
Distribution revenues related to provision of services and supply of electricity1 1 4 4 
Capital contribution received from OPG5 6 7 16 
Costs related to the purchase of services— 1 — 1 
OEFCPower purchased from power contracts administered by the OEFC— — 2 1 
OEBOEB fees4 3 8 6 
Hydro One LimitedDividends paid211 207 410 394 
Cost recovery for services provided3 3 6 6 
Stock-based compensation costs1 2 3 3 
AcronymServices received – costs incurred8 7 15 14 
Revenues for services provided1 1 1 1 
1 During 2025, Ministry replaced MOI in making broadband subsidy payments to Hydro One.
2 On October 31, 2024, the MOI announced that it has developed a program to deliver up to $400 million in subsidies to ISPs for work associated with designated broadband projects. Effective April 2026, this was increased by the Ministry to up to $482 million.
RISK MANAGEMENT AND RISK FACTORS
Hydro One is subject to numerous risks and uncertainties. Critical to Hydro One’s success is the identification, management, and to the extent possible, mitigation of these risks. Hydro One’s Enterprise Risk Management program assists decision-makers throughout the organization with the management of key business risks, including new and emerging risks and opportunities.
A discussion of the material risks relating to Hydro One and its business that the Company believes would be the most likely to influence an investor’s decision to purchase Hydro One’s securities can be found under the heading “Risk Management and Risk Factors” in the 2025 MD&A.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate disclosure controls and procedures and internal control over financial reporting as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. Internal control, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and due to its inherent limitations, may not prevent or detect all misrepresentations.
There were no changes in the Company’s internal control over financial reporting during the three months ended June 30, 2026 that materially affected, or are reasonably likely to materially affect, the Company’s disclosure controls and procedures and internal control over financial reporting.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
NEW ACCOUNTING PRONOUNCEMENTS
The following table presents Accounting Standards Updates (ASUs) issued by the Financial Accounting Standards Board (FASB) that are applicable to Hydro One:
Recently Adopted Accounting Guidance
GuidanceDate issued
Description
ASU Effective DateImpact on Hydro One
ASU 2025-05July 2025The amendments allow all entities to use a practical expedient when estimating expected credit losses for current accounts receivable and contract assets under Topic 606, by assuming that current conditions as of the balance sheet date remain unchanged over the asset’s life. Additionally, entities other than public business entities that elect this expedient may adopt an accounting policy to consider post–balance sheet date collection activity in their credit loss estimates.Annual and interim periods beginning after December 15, 2025.No impact upon adoption
Recently Issued Accounting Guidance Not Yet Adopted
GuidanceDate issuedDescriptionASU Effective DateImpact on Hydro One
ASU 2023-06October 2023The amendments represent changes to clarify or improve disclosure or presentation requirements of a variety of subtopics in the FASB Codification. Many of the amendments allow users to more easily compare entities subject to the U.S. Securities and Exchange’s (SEC) existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.

Applicable to all entities, if by June 30, 2027 the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K, the pending content of the related amendment will be removed from the Codification and will not become effective for any entity.		Two years subsequent to the date on which the SEC’s removal of that related disclosure becomes effective.Under assessment
ASU
2024-03		November 2024The amendments require public business entities to disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods, which are not generally presented in the current financial statements.Annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027. Under assessment
ASU 2025-03May 2025The amendments require entities to apply the guidance for identifying the accounting acquirer in transactions where a business that qualifies as a Variable Interest Entity is acquired through the exchange of equity interests.Annual and interim periods beginning after December 15, 2026.No impact upon adoption
ASU 2025-06September 2025The amendments modernize accounting for internal-use software by removing outdated development stage references and introducing a capitalization threshold based on management authorization and project completion probability. Annual and interim periods beginning after December 15, 2027.Under assessment
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
GuidanceDate issued
Description
ASU Effective DateImpact on Hydro One
ASU 2025-09November 2025The amendments expand hedge-accounting eligibility and better align the guidance with common risk‑management practices. Key updates allow grouping forecasted transactions with similar exposure, simplify hedging of choose‑your‑rate variable‑rate debt, and broaden eligibility for hedging nonfinancial components. The guidance modernizes treatment of certain option‑based derivatives and resolves mismatches in dual hedge relationships. Annual and interim periods beginning after December 15, 2026.Under assessment
ASU 2025-10December 2025The amendments establish authoritative GAAP for government grants, setting recognition, measurement, presentation, and disclosure requirements. Annual and interim periods beginning after December 15, 2028.Under assessment
ASU 2025-11December 2025The amendments clarify interim reporting by establishing a complete list of required GAAP interim disclosures. They introduce a disclosure principle requiring entities to report material events occurring after the annual reporting period. The Update also clarifies types of interim reports and the form and content of interim financial statements. Overall, the changes enhance clarity and consistency without altering existing disclosure requirements.Interim reporting periods within annual reporting periods beginning after December 15, 2027.Under assessment
ASU 2025-12December 2025The amendments clarify existing guidance, correct errors, and introduce minor improvements to numerous Codification Topics, thereby making the requirements easier for entities to understand and apply.Annual and interim periods beginning after December 15, 2026.Under assessment
ASU 2026-02May 2026The amendments establish authoritative guidance on the accounting and disclosure of environmental credits and environmental credit obligations. The guidance establishes a consistent framework for recognizing, measuring, presenting, and disclosing environmental credits and related compliance obligations arising from regulatory compliance programs. Overall, the changes improve comparability, transparency, and consistency in financial reporting.Annual and interim periods beginning after December 15, 2027.Under assessment
FORWARD-LOOKING STATEMENTS AND INFORMATION
The Company’s oral and written public communications, including this document, often contain “forward-looking information” within the meaning of applicable Canadian securities laws and “forward-looking statements” within the meaning of applicable U.S. securities laws (collectively, “forward-looking information”). Statements containing forward-looking information are made pursuant to the “safe harbour” provisions of applicable Canadian and U.S. securities laws. Forward-looking information in this document is based on current expectations, estimates, forecasts and projections about the Company’s business, the industry, regulatory and economic environments in which it operates, and includes beliefs and assumptions made by the management of the Company. Such statements include, but are not limited to, statements regarding: the Company’s corporate strategy; the Company’s transmission and distribution rate and revenue requirement applications including the JRAP and its proposed investment plan, resulting and related decisions as well as resulting rates, recovery and expected impacts and timing; expectations about the Company’s liquidity and capital resources and operational requirements; sustainability goals; the Operating Credit Facilities; expectations regarding the Company’s financing activities, expectations that the re-introduction of an accelerated capital cost allowance will lower the Company’s ETR to 11% to 15% during the current rate period (to 2027); the Company’s maturing debt; expectations and impact of the Company’s credit ratings; the Company’s ongoing and planned projects (including construction of transmission stations and lines) and expected capital investments and plans, including expected scope, approvals, results, costs, funding sources, increased transfer capacities, potential job creation and in-service and completion dates; cross-currency swap agreements; contractual obligations and other commercial commitments; future pension plan contributions, including estimates of total Company pension contributions; the expected advancement and construction of various transmission stations and transmission lines in connection with the Province’s integrated energy plan and the target in-service dates; collective agreements and bargaining; non-GAAP financial measures; internal controls over financial reporting and disclosure; the MTN Program; and accounting-related guidance and expected impacts. Words such as “expect,” “anticipate,” “intend,” “attempt,” “may,” “plan,” “will,” “would,” “believe,” “seek,” “estimate,” “goal,” “aim,” “target,” and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve assumptions and risks and uncertainties that are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed, implied or forecasted in such forward-looking statements. Hydro One does not intend, and it disclaims any obligation, to update any forward-looking statements, except as required by law.
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
These forward-looking statements are based on a variety of factors and assumptions including, but not limited to, the following: no unforeseen changes in the legislative and operating framework for Ontario’s electricity market or for Hydro One specifically; favourable decisions from the OEB and other regulatory bodies concerning outstanding and future rate and other applications; no unexpected delays in obtaining required regulatory approvals; no unforeseen changes in rate orders or rate setting methodologies for the Company’s distribution and transmission businesses; no unfavourable changes in environmental regulation; continued use of U.S. GAAP; a stable regulatory environment; no significant changes to the Company's current credit ratings; no unforeseen impacts of new accounting pronouncements; no changes to expectations regarding electricity consumption; no unforeseen changes to economic and market conditions; completion of operating and capital projects that have been deferred; and no significant event occurring outside the ordinary course of business. These assumptions are based on information currently available to the Company, including information obtained from third-party sources. Actual results may differ materially from those predicted by such forward-looking statements. While Hydro One does not know what impact any of these differences may have, the Company’s business, results of operations, financial condition and credit stability may be materially adversely affected if any such differences occur. Factors that could cause actual results or outcomes to differ materially from the results expressed or implied by forward-looking statements include, among other things:
•regulatory risks and risks relating to Hydro One’s revenues, including risks relating to actual performance against forecasts, competition with other transmitters and other applications to the OEB, the rate-setting models for transmission and distribution, the recoverability of capital expenditures, obtaining rate orders or recoverability of total compensation costs;
•risks associated with the Province’s share ownership of Hydro One Limited and other relationships with the Province, including potential conflicts of interest that may arise between Hydro One, the Province and related parties, risks associated with the Province’s exercise of further legislative and regulatory powers, risks relating to the ability of the Company to attract and retain qualified executive talent or the risk of a credit rating downgrade for the Company and its impact on the Company’s funding and liquidity;
•risks relating to the location of the Company’s assets on Reserve lands, that the Company’s operations and activities may give rise to the Crown’s duty to consult and potentially accommodate Indigenous communities, and the risk that Hydro One may incur significant costs associated with transferring assets located on Reserves;
•the risk that the Company may be unable to comply with regulatory and legislative requirements or that the Company may incur additional costs for compliance that are not recoverable through rates;
•the risk of exposure of the Company’s facilities to the effects of severe weather conditions, natural disasters, man-made events or other unexpected occurrences for which the Company is uninsured or for which the Company could be subject to claims for damage;
•risks associated with information system security and maintaining complex information technology and OT system infrastructure, including system failures or risks of cyber-attacks or unauthorized access to corporate information technology and OT systems;
•the risk of non-compliance with environmental regulations and inability to recover environmental expenditures in rate applications and the risk that assumptions that form the basis of the Company’s recorded environmental liabilities and related regulatory assets may change;
•the risk of labour disputes and inability to negotiate or renew appropriate collective agreements on acceptable terms consistent with the Company’s rate decisions;
•the risk that the Company may not be able to execute plans for capital projects necessary to maintain the performance of the Company’s assets or to carry out projects in a timely manner or the risk of increased competition for the development of large transmission projects or legislative changes affecting the selection of transmitters;
•risks associated with asset condition, capital projects and innovation, including public opposition to or delays or denials of the requisite approvals and accommodations for the Company’s planned projects;
•risks related to the Company’s work force demographic and its potential inability to attract and retain qualified personnel;
•the risk that the Company is not able to arrange sufficient cost-effective financing to repay maturing debt and to fund capital expenditures, the risk of a downgrade in the Company’s credit ratings or risks associated with investor interest in ESG performance and reporting;
•risks associated with fluctuations in interest rates and failure to manage exposure to credit and financial instrument risk;
•risks associated with economic uncertainty and financial market volatility;
•the risk of failure to mitigate significant health and safety risks;
•the risk of not being able to recover the Company’s pension expenditures in future rates and uncertainty regarding the future regulatory treatment of pension, other post-employment benefits and post-retirement benefits costs;
•the impact of the ownership by the Province of lands underlying the Company’s transmission system;
•the risk associated with legal proceedings that could be costly, time-consuming or divert the attention of management and key personnel from the Company’s business operations;
•the impact if the Company does not have valid occupational rights on third-party owned or controlled lands and the risks associated with occupational rights of the Company that may be subject to expiry;
•risks relating to adverse reputational events or political actions relating to Hydro One and the electricity industry;
•the potential that Hydro One may incur significant expenses to replace functions currently outsourced if agreements are terminated or expire before a new service provider is selected;
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HYDRO ONE INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
For the three and six months ended June 30, 2026 and 2025
•risks relating to acquisitions, including the failure to realize the anticipated benefits of such transactions at all, or within the time periods anticipated, and unexpected costs incurred in relation thereto;
•risks relating to an outbreak of infectious disease;
•the inability to continue to prepare financial statements using U.S. GAAP; and
•the risk related to the impact of any new accounting pronouncements.
Hydro One cautions the reader that the above list of factors is not exhaustive. Some of these and other factors are discussed in more detail in the section entitled “Risk Management and Risk Factors” in this MD&A.
In addition, Hydro One cautions the reader that information provided in this MD&A regarding the Company’s outlook on certain matters, including potential future investments, is provided in order to give context to the nature of some of the Company’s future plans and may not be appropriate for other purposes.
Additional information about Hydro One, including the Company’s Annual Information Form, is available on SEDAR+ at www.sedarplus.com, the U.S. Securities and Exchange Commission’s EDGAR website at www.sec.gov/edgar.shtml, and the Company’s website at www.HydroOne.com/Investors.
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